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| 1 | AMEREN CORP | NOTE 2 - RATE AND REGULATORY MATTERS Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity. Missouri 2009 Electric Rate Order In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. In September 2009, the Circuit Court of Pemiscot County granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. The merits of the appeal will be briefed by the parties over the next several months, with a decision likely to be issued by the court in the first half of 2010. During the stay, Noranda will pay into the court registry the contested portion of its monthly billings, approximately $0.5 million per month based on current usage levels. If UE wins the appeal, it will receive those monthly payments plus interest. Pending Electric Rate Case UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The balance of the increase request is based primarily on investments made to continue system-wide reliability improvements for customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The electric rate increase request is based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. Following Ameren’s September 2009 common stock issuance, UE received a capital contribution from Ameren of $436 million in September 2009. UE expects to true-up its capital structure in the electric rate case to reflect this capital contribution, among other things. See Note 4 - Long-term Debt and Equity Financings for further information on the Ameren common stock issuance. UE’s filing included a request for interim rate relief, which would place into effect approximately $37 million of the requested increase prior to completion of the full rate case. The amount of this interim increase request reflected the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009. The MoPSC has scheduled a hearing in December 2009 to consider UE’s request for interim rate relief.
As part of its filing, UE also requested the MoPSC to approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. The environmental cost recovery mechanism, if approved, would allow UE to twice each year adjust electric rates outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state or local environmental laws, regulations or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews of the MoPSC. UE’s request is consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures. In addition, UE requested that the MoPSC approve the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order, and the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs that the MoPSC previously authorized in its May 2007 electric rate order. UE’s filing with the MoPSC also seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, such as the revenue losses resulting from the January 2009 storm-related power outage. The tariff change that UE is proposing would permit it to collect from Noranda the revenue authorized by the MoPSC in this rate case regardless of the level at which the Noranda plant is operating prospectively. If the plant is operating at levels less than the levels assumed in rates, Noranda would receive a credit reflecting any revenues received by UE from energy sales resulting from the decrease in actual energy sales to Noranda. The result would be that UE is able to recover its costs without impacting other customers regardless of Noranda’s actual energy use. The MoPSC proceeding relating to the proposed electric service rate changes (except for the request for interim rate relief as discussed above) will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010. Hearings are scheduled for March 2010. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change (interim or final) may go into effect, whether the cost recovery mechanisms and trackers requested will be approved or continued, or whether any rate change that may eventually be approved will be sufficient to enable UE to recover its costs and earn a reasonable return on its investments when the rate change goes into effect. Missouri Energy Efficiency Investment Act In July 2009, the Missouri governor signed a law that went into effect in August 2009, which, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. Recovery is only permitted if the program is approved by the MoPSC, results in energy savings, and is beneficial to all customers in the class for which the program is proposed. The new law would potentially, among other items, allow UE to earn a return on its energy efficiency programs, which the current model of cost recovery does not permit.
Illinois Pending Electric and Natural Gas Delivery Service Rate Cases In June 2009, CIPS, CILCO and IP filed requests with the ICC to increase their annual revenues for electric delivery service. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $136 million in the aggregate (CIPS - $41 million, CILCO - $22 million, and IP - $73 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.4 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. In addition, the Ameren Illinois Utilities have requested a rider mechanism that would permit all distribution-related costs incurred to implement reliability recommendations submitted by the Liberty Consulting Group, which are discussed below, to be reflected in electric rates outside of general rate proceedings. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million, and IP - $7 million) in 2010. CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $26 million in the aggregate (CIPS - $7 million, CILCO - $6 million, and IP - $13 million). The natural gas rate increase requests are based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. In September 2009, the ICC staff filed direct testimony in response to the Ameren Illinois Utilities electric and natural gas delivery service rate increase filings. The ICC staff recommended in their testimony a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $49 million in the aggregate (CIPS - $16 million increase, CILCO - $6 million increase, and IP - $27 million increase) and a net decrease in revenues for natural gas delivery service of $4 million in the aggregate (CIPS - $1 million increase, CILCO - $3 million decrease, and IP - $2 million decrease). The ICC staff position is based on a 10.2% to 10.4% return on equity for electric delivery service and a 9.4% to 9.8% return on equity for natural gas delivery service. Other parties also made recommendations through direct testimony filed in the electric and natural gas delivery service rate cases. The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010. Hearings are scheduled for December 2009. The Ameren Illinois Utilities cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the rate changes go into effect. Illinois Electric Settlement Agreement The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding under the Illinois electric settlement agreement in a manner corresponding with the timing of the funding. As a result, Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended September 30, 2009, of $6 million, $1 million, $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended September 30, 2008 - $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively) and during the nine months ended September 30, 2009, of $18 million, $3 million, $1 million, $4 million, $7 million, and $3 million, respectively (nine months ended September 30, 2008 - $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively).
Power Procurement Plan In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities in the second quarter of 2009. See Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies for further information about the results of the RFPs. In August 2009, the IPA submitted its plan for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The plan must be approved or modified by the ICC by December 29, 2009. The IPA is proposing to hold two procurement events in 2010: one in the spring for energy, capacity and renewable energy credits and a second in the fall for demand response resources. The exact dates of each procurement event have not been determined. Once the proposed 2010 procurement events are complete, the Ameren Illinois Utilities will have sufficient capacity and energy hedges in place for 100% of their expected supply obligation for the period June 2010 through May 2011, 70% of their expected supply obligation for the period June 2011 through May 2012, and 44% of their expected supply obligations for the period June 2012 through May 2013. Renewable energy credits will be procured for 2010 only. ICC Reliability Audit In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect to incur an estimated $20 million ($15 million for distribution and $5 million for transmission) of capital costs and an estimated $66 million ($50 million for distribution and $16 million for transmission) of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. In testimony filed with the ICC in October 2009 as part of the pending electric delivery service rate cases, the Ameren Illinois Utilities requested recovery of all distribution-related costs through the implementation of a rider mechanism that would permit the Ameren Illinois Utilities to reflect these costs in electric rates outside of general rate proceedings. Transmission-related costs will be recoverable through FERC’s ratemaking proceedings. Illinois 2009 Energy Legislation In July 2009, a new law became effective in Illinois that, among other things, establishes new energy efficiency targets for Illinois natural gas utilities, develops a percentage of income payment plan for low-income utility customers, and allows electric and gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. During 2008, the Ameren Illinois Utilities incurred approximately $25 million more of bad debt expense (CIPS - $5 million, CILCO - $4 million, and IP - $16 million) than they recovered through rates. In August 2009, the Ameren Illinois Utilities filed with the ICC electric and natural gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to make corresponding rate adjustments beginning in 2010. The ICC has until February 2010 to approve, or approve as modified, the filed tariffs.
Upon ICC approval of the rate adjustment clause tariffs filed in August 2009, the Ameren Illinois Utilities will be required to make a one-time $10 million donation (CIPS - $3 million, CILCO - $2 million, and IP - $5 million) for customer assistance programs. The amount of the required one-time donation and the impact of the recovery of 2008 bad debt expenses were reflected in earnings during the third quarter of 2009. Federal Nuclear Combined Construction and Operating License Application In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. UE had also signed contracts for COLA-related services and certain long lead-time nuclear-unit related equipment (heavy forgings). In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. These bills were designed to allow the MoPSC to authorize, among other things, utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant was being constructed. Recovery of actual construction costs still could not have begun until a plant was put into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit. In April 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed pursuing the legislation being considered in the Missouri Senate in its then proposed form would not give it the financial and regulatory certainty needed to complete the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due to file with the MoPSC in 2011. As of September 30, 2009, UE had capitalized approximately $68 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit, it is possible that a charge to earnings could be recognized in a future period. Prior to June 30, 2009, UE made contractual payments to the heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings procurement agreement, and $5 million of previously-made payments were retained by the manufacturer as a penalty for terminating the contract, which was charged to earnings in June 2009. See Note 9 - Commitments and Contingencies for further information about the contract termination.
FERC Order - MISO Charges In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC issued an order granting the request for clarification and directed MISO to reallocate certain MISO operational costs among MISO participants and provide refunds for the period April 2006 to August 2007 (“November 7, 2008 Clarification Order”). On November 10, 2008, FERC granted further relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward (“November 10, 2008 Complaint Order”). Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed effective on August 10, 2007. On May 6, 2009, FERC issued an order that upheld most of the conclusions of the November 10, 2008 Complaint Order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. In June 2009, UE, CIPS, CILCO and IP filed for rehearing of the May 2009 order regarding the change to the refund effective date. This rehearing request is pending. With respect to the November 7, 2008 Clarification Order, in June 2009 FERC issued an order dismissing rehearing requests of such clarification order and waiving refunds of amounts billed that were included in the MISO charge under the assumption that there was a rate mismatch for the period April 25, 2006, through November 4, 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending. With respect to the two rehearing requests discussed above, UE, CIPS, CILCO and IP do not believe that the ultimate resolution of either request will have a material effect on their results of operations, financial position, or liquidity. MISO and PJM Dispute Resolution During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the RTOs. The error originated in April 2005, corresponding with the initiation of the MISO Day Two Energy Market and was corrected prospectively in June 2009. Since discovering the error, MISO and PJM have worked jointly to estimate the financial impact to the respective markets. MISO and PJM are in agreement on the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement on the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement over the resettlement amount. To resolve this issue, MISO and PJM have agreed to participate in FERC’s dispute resolution and settlement process to determine a resettlement amount for the entire period from April 2005 to June 2009. In October 2009, an administrative law judge was appointed as mediator, and a settlement conference was held at FERC. A final settlement between MISO and PJM, if and when reached, will be subject to FERC approval. Ameren, and its subsidiaries, may receive a to-be-determined portion of the resettlement amount due from PJM to MISO. Until a settlement has been reached and approved by FERC, we cannot predict the ultimate impact of these proceedings on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity. |
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| 2 | AMERICAN ELECTRIC POWER CO INC |
As discussed in the 2008 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2008 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2009 and updates the 2008 Annual Report. Ohio Rate Matters Ohio Electric Security Plan Filings In March 2009, the PUCO issued an order, which was amended by a rehearing entry in July 2009, that modified and approved CSPCo’s and OPCo’s ESPs that established standard service offer rates. The ESPs will be in effect through 2011. The ESP order authorized revenue increases during the ESP period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. CSPCo and OPCo implemented rates for the April 2009 billing cycle. In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis. CSPCo and OPCo are collecting the 2009 annualized revenue increase over the last nine months of 2009. The order provides a FAC for the three-year period of the ESP. The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. The FAC deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and OPCo, respectively, inclusive of carrying charges at the weighted average cost of capital. In the July 2009 rehearing order, the PUCO once again rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins. As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales. The PUCO’s July 2009 rehearing entry among other things reversed the prior authorization to recover the cost of CSPCo’s recently acquired Waterford and Darby Plants. In July 2009, CSPCo filed an application for rehearing with the PUCO seeking authorization to sell or transfer the Waterford and Darby Plants. The PUCO also addressed several additional matters in the ESP order, which are described below:
In June 2009, intervenors filed a motion in the ESP proceeding with the PUCO requesting CSPCo and OPCo to refund deferrals allegedly collected by CSPCo and OPCo which were created by the PUCO’s approval of a temporary special arrangement between CSPCo, OPCo and Ormet, a large industrial customer. In addition, the intervenors requested that the PUCO prevent CSPCo and OPCo from collecting these revenues in the future. In June 2009, CSPCo and OPCo filed a response noting that the difference in the amount deferred between the PUCO-determined market price for 2008 and the rate paid by Ormet was not collected, but instead was deferred, with PUCO authorization, as a regulatory asset for future recovery. In the rehearing entry, the PUCO did not order an adjustment to rates based on this issue. See “Ormet” section below. In August 2009, an intervenor filed for rehearing requesting, among other things, that the PUCO order CSPCo and OPCo to cease and desist from charging ESP rates, to revert to the rate stabilization plan rates and to compel a refund, including interest, of the amounts collected by CSPCo and OPCo. CSPCo and OPCo filed a response stating the rates being charged by CSPCo and OPCo have been authorized by the PUCO and there was no basis for precluding CSPCo and OPCo from continuing to charge those rates. In September 2009, certain intervenors filed appeals of the March 2009 order and the July 2009 rehearing entry with the Supreme Court of Ohio. One of the intervenors, the Ohio Consumers’ Counsel, has asked the court to stay, pending the outcome of its appeal, a portion of the authorized ESP rates which the Ohio Consumers’ Counsel characterizes as being retroactive. In October 2009, the Supreme Court of Ohio denied the Ohio Consumers' Counsel's request for a stay and granted motions to dismiss both appeals. In September 2009, CSPCo and OPCo filed their initial quarterly FAC filing with the PUCO. An order approving the FAC 2009 filings will not be issued until a financial audit and prudency review is performed by independent third parties and reviewed by the PUCO. In October 2009, the PUCO convened a workshop to begin to determine the methodology for the Significantly Excessive Earnings Test (SEET). The SEET requires the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings. This will be determined by measuring whether the utility’s earned return on common equity is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, which have comparable business and financial risk. In the March 2009 ESP order, the PUCO determined that off-system sales margins and FAC deferral phase-in credits should be excluded from the SEET methodology. However, the July 2009 PUCO rehearing entry deferred those issues to the SEET workshop. If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers. The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the workshop is completed, the PUCO issues SEET guidelines, a SEET filing is made by CSPCo and OPCo in 2010 and the PUCO issues an order thereon. The SEET workshop will also determine whether CSPCo’s and OPCo’s earnings will be measured on an individual company basis or on a combined CSPCo/OPCo basis. In October 2009, an intervenor filed a complaint for writ of prohibition with the Supreme Court of Ohio requesting the Court to prohibit CSPCo and OPCo from billing and collecting any ESP rate increases that the PUCO authorized as the intervenor believes the PUCO's statutory jurisdiction over CSPCo's and OPCo's ESP application ended on December 28, 2008, which was 150 days after the filing of the ESP applications. CSPCo and OPCo plan on filing a response in opposition to the complaint for writ of prohibition. Management is unable to predict the outcome of the various ongoing proceedings and litigation discussed above including the SEET, the FAC filing review and the various appeals to the Supreme Court of Ohio relating to the ESP order. If these proceedings result in adverse rulings, it could have an adverse effect on future net income and cash flows. Ohio IGCC Plant In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. In June 2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to recover pre-construction costs over a period of no more than twelve months effective July 1, 2006. During that period, CSPCo and OPCo each collected $12 million in pre-construction costs and incurred $11 million in pre-construction costs. As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million. The June 2006 order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all pre-construction cost recoveries associated with items that may be utilized in projects at other jurisdictions must be refunded to Ohio ratepayers with interest. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest. In October 2008, CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent. In January 2009, a PUCO Attorney Examiner issued an order that required CSPCo and OPCo to file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant. In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and CSPCo and OPCo believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including the IGCC plant. The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time. In September 2009, an intervenor filed a motion with the PUCO requesting that CSPCo and OPCo be required to refund all pre-construction cost revenue to Ohio ratepayers with interest or show cause as to why the amount for the proposed IGCC plant should not be immediately refunded based upon the PUCO’s June 2006 order. The intervenor contends that the most recent integrated resource plan filed for the AEP East companies’ zone does not reflect the construction of an IGCC plant. In October 2009, CSPCo and OPCo filed a response opposing the intervenor’s request to refund revenues collected stating that an integrated resource plan is a planning tool and does not prevent CSPCo and OPCo from meeting the PUCO’s five-year time limit. Management continues to pursue the consideration of construction of an IGCC plant in Ohio although CSPCo and OPCo will not start construction of an IGCC plant until the statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists. Management cannot predict the outcome of the cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, the litigation will have on future net income and cash flows. However, if CSPCo and OPCo were required to refund the $24 million collected and those costs were not recoverable in another jurisdiction, it would have an adverse effect on future net income and cash flows. Ormet In December 2008, CSPCo, OPCo and Ormet, a large aluminum company currently operating at a reduced load of approximately 330 MW (Ormet operated at an approximate 500 MW load in 2008), filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. The interim arrangement was effective January 1, 2009 and expired in September 2009 upon the filing of a new PUCO-approved long-term power contract between Ormet and CSPCo/OPCo that was effective prospectively through 2018. Under the interim arrangement, Ormet would pay the then-current applicable generation tariff rates and riders and CSPCo and OPCo would defer as a regulatory asset, beginning in 2009, the difference between the PUCO-approved 2008 market price of $53.03 per MWH and the applicable generation tariff rates and riders. CSPCo and OPCo proposed to recover the deferral through the new FAC phased-in mechanism that they proposed in the ESP proceeding. In January 2009, the PUCO approved the application as an interim arrangement. In February 2009, an intervenor filed an application for rehearing of the PUCO’s interim arrangement approval. In March 2009, the PUCO granted that application for further consideration of the matters specified in the rehearing application. In the PUCO’s July 2009 order discussed below, CSPCo and OPCo were directed to file an application to recover the appropriate amounts of the deferrals under the interim agreement and for the remainder of 2009. In February 2009, as amended in April 2009, Ormet filed an application with the PUCO for approval of a proposed Ormet power contract for 2009 through 2018. Ormet proposed to pay varying amounts based on certain conditions, including the price of aluminum and the level of production. The difference between the amounts paid by Ormet and the otherwise applicable PUCO ESP tariff rate would be either collected from or refunded to CSPCo’s and OPCo’s retail customers. In March 2009, the PUCO issued an order in the ESP filings which included approval of a FAC for the ESP period. The approval of an ESP FAC, together with the January 2009 PUCO approval of the Ormet interim arrangement, provided the basis to record regulatory assets for the differential in the approved market price of $53.03 versus the rate paid by Ormet until the effective date of the 2009-2018 power contract. In May 2009, intervenors filed a motion with the PUCO that contends CSPCo and OPCo should be charging Ormet the new ESP rate and that no additional deferrals between the approved market price and the rate paid by Ormet should be calculated and recovered through the FAC since Ormet will be paying the new ESP rate. In May 2009, CSPCo and OPCo filed a Memorandum Contra recommending the PUCO deny the motion to cease additional Ormet FAC under-recovery deferrals. In June 2009, intervenors filed a motion with the PUCO related to Ormet in the ESP proceeding. See “Ohio Electric Security Plan Filings” section above. In July 2009, the PUCO approved Ormet’s application for a power contract through 2018 with several modifications. As modified by the PUCO, rates billed to Ormet by CSPCo and OPCo for the balance of 2009 would reflect an annual average rate using $38 per MWH for the periods Ormet was in full production and $35 and $34 per MWH at certain curtailed production levels. The $35 and $34 MWH rates are contingent upon Ormet maintaining its employment levels at 900 employees for 2009. The PUCO authorized CSPCo and OPCo to record under-recovery deferrals computed as revenue foregone (the difference between CSPCo’s and OPCo’s ESP tariff rates and the rate paid by Ormet) created by the blended rate for the remainder of 2009. For 2010 through 2018, the PUCO approved the linkage of Ormet’s rate to the price of aluminum but modified the agreement to include a maximum electric rate reduction for Ormet that declines over time to zero in 2018 and a maximum amount of under-recovery deferrals that ratepayers will be expected to pay via a rider in any given year. For 2010 and 2011, the PUCO set the maximum rate discount at $60 million and the maximum amount of the rate discount other ratepayers should pay at $54 million. To the extent the under-recovery deferrals exceed the amount collectible from ratepayers, the difference can be deferred, with a long-term debt carrying charge, for future recovery. In addition, this rate is based upon Ormet maintaining at least 650 employees. For every 50 employees below that level, Ormet’s maximum electric rate reduction will be lowered. The new long-term power contract became effective in September 2009 at which point CSPCo and OPCo began deferring as a regulatory asset the unrecovered amounts less Provider of Last Resort (POLR) charges. Rehearing applications filed by CSPCo, OPCo and intervenors were granted by the PUCO. In September 2009 on rehearing, the PUCO ordered that CSPCo and OPCo must credit all Ormet related POLR charges against the under-recovery amounts that CSPCo and OPCo would otherwise recover. As of September 30, 2009, CSPCo and OPCo had $32 million and $34 million, respectively, deferred as regulatory assets related to Ormet under-recovery, which is included in CSPCo’s and OPCo’s FAC phase-in deferral balance. Ormet indicated it will operate at reduced operations at least through the end of 2009. Management cannot predict Ormet’s on-going electric consumption levels, the resultant prices Ormet will pay and/or the amount that CSPCo and OPCo will defer for future recovery from other customers. If CSPCo and OPCo are not ultimately permitted to recover their under-recovery deferrals, it would have an adverse effect on future net income and cash flows. Hurricane Ike In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike. Under the RSP, which was effective in 2008, CSPCo and OPCo could seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts. In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the expected recovery of the storm restoration costs. In December 2008, the PUCO approved these regulatory assets along with a long-term debt only carrying cost on these regulatory assets. In its order approving the deferrals, the PUCO stated that the mechanism for recovery would be determined in CSPCo’s and OPCo’s next distribution rate filings. At September 30, 2009, CSPCo and OPCo have accrued for future recovery regulatory assets of $18 million and $10 million, respectively, including the approved long-term debt only carrying costs. If CSPCo and OPCo are not ultimately permitted to recover their storm damage deferrals, it would have an adverse effect on future net income and cash flows. Texas Rate Matters TEXAS RESTRUCTURING Texas Restructuring Appeals Pursuant to PUCT orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC refunded net other true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider. Although earnings were not affected by this CTC refund, cash flows were adversely impacted for 2008, 2007 and 2006 by $75 million, $238 million and $69 million, respectively. Municipal customers and other intervenors appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. TCC also appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items. The significant items appealed by TCC were:
In March 2007, the Texas District Court judge hearing the appeals of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions. The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration. This remand could potentially have an adverse effect on TCC’s future net income and cash flows if upheld on appeal. The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness which could have a favorable effect on TCC’s future net income and cash flows. TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals. In May 2008, the Texas Court of Appeals affirmed the District Court decision in all but two major respects. It reversed the District Court’s unfavorable decision which found that the PUCT erred by applying an invalid rule to determine the carrying cost rate. It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs. Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings based upon the reasons discussed in the “TCC Excess Earnings” section below. The favorable commercial unreasonableness judgment entered by the District Court was not reversed. In June 2008, the Texas Court of Appeals denied intervenors’ motions for rehearing. In August 2008, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court. Review is discretionary and the Texas Supreme Court has not determined if it will grant review. In January 2009, the Texas Supreme Court requested full briefing of the proceedings which concluded in June 2009. A decision is not expected from the Texas Supreme Court until 2010. TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed. TNC appealed its final true-up order, which remains pending in state court. Management cannot predict the outcome of these court proceedings and PUCT remand decisions. If TCC and/or TNC ultimately succeed in their appeals, it could have a material favorable effect on future net income, cash flows and possibly financial condition. If municipal customers and other intervenors succeed in their appeals, it could have a material adverse effect on future net income, cash flows and possibly financial condition. TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes TCC’s appeal remains outstanding related to the stranded costs true-up and related orders regarding whether the PUCT may require TCC to refund certain Accumulated Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT) tax benefits to customers. Subsequent to the PUCT’s ordered reduction to TCC’s securitized stranded costs for certain tax benefits, the PUCT, reacting to possible IRS normalization violations, allowed TCC to defer $103 million of ordered CTC refunds for other true-up items to negate the securitization reduction. Of the $103 million, $61 million relates to the present value of certain tax benefits applied to reduce the securitization stranded generating assets and $42 million was for subsequent carrying costs. The deferral of the CTC refunds is pending resolution on whether the PUCT’s securitization refund is an IRS normalization violation. Since the deferral through the CTC refund, the IRS issued a favorable final regulation in March 2008 addressing the normalization requirements for the treatment of ADITC and EDFIT in a stranded cost determination. Consistent with a Private Letter Ruling TCC received in 2006, the final regulations clearly state that TCC will sustain a normalization violation if the PUCT orders TCC in a final order after all appeals to flow these tax benefits to customers as part of the stranded cost true-up. TCC notified the PUCT that the final regulations were issued. The PUCT made a request to the Texas Court of Appeals for the matter to be remanded back to the PUCT for further action. In May 2008, as requested by the PUCT, the Texas Court of Appeals ordered a remand of the tax normalization issue for the consideration of this favorable additional evidence. TCC expects that the PUCT will allow TCC to retain the deferred amounts. This will have a favorable effect on future net income as TCC will be able to amortize the deferred ADITC and EDFIT tax benefits to income over the remaining securitization period. Since management expects that the PUCT will allow TCC to retain the deferred CTC refund amounts in order to avoid an IRS normalization violation, no related interest expense has been accrued related to refunds of these amounts. If accrued, management estimates interest expense would have been approximately $11 million higher for the period July 2008 through September 2009 based on a CTC interest rate of 7.5% with $4 million relating to 2008. If the PUCT orders TCC to return the tax benefits to customers, thereby causing a violation of the IRS normalization regulations, the violation could result in TCC’s repayment to the IRS, under the normalization rules, of ADITC on all property, including transmission and distribution property. This amount approximates $102 million as of September 30, 2009. It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. If TCC is required to repay to the IRS its ADITC and is also required to refund ADITC to customers, it would have an unfavorable effect on future net income and cash flows. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are actually returned to ratepayers under a nonappealable final order. Management intends to continue to work with the PUCT to favorably resolve this issue and avoid the adverse effects of a normalization violation on future net income, cash flows and financial condition. TCC Excess Earnings In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the REPs excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. From 2002 to 2005, TCC refunded $55 million of excess earnings, including interest, under the overturned PUCT order. On remand, the PUCT must determine how to implement the Court of Appeals decision given that the unauthorized refunds were made to the REPs in lieu of reducing stranded cost recoveries from REPs in the True-up Proceeding. It is possible that TCC’s stranded cost recovery, which is currently on appeal, may be affected by a PUCT remedy. In May 2008, the Texas Court of Appeals issued a decision in TCC’s True-up Proceeding determining that even though excess earnings had been previously refunded to REPs, TCC still must reduce stranded cost recoveries in its True-up Proceeding. In 2005, TCC reflected the obligation to refund excess earnings to customers through the true-up process and recorded a regulatory asset of $55 million representing a receivable from the REPs for prior excess earnings refunds made to them by TCC. However, certain parties have taken positions that, if adopted, could result in TCC being required to refund additional amounts of excess earnings or interest through the true-up process without receiving a refund from the REPs. If this were to occur, it would have an adverse effect on future net income and cash flows. AEP sold its affiliate REPs in December 2002. While AEP owned the affiliate REPs, TCC refunded $11 million of excess earnings to the affiliate REPs. Management cannot predict the outcome of the excess earnings remand and whether it would have an adverse effect on future net income and cash flows. Texas Restructuring – SPP In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011. In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes. Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction in the second quarter of 2009. Management believes that a switch to competition in the SPP area of Texas will not occur. The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss. In addition, effective April 2009, the generation portion of SWEPCo’s Texas retail jurisdiction began accruing AFUDC (debt and equity return) instead of capitalized interest on its eligible construction balances including the Stall Unit and the Turk Plant. The accrual of AFUDC increased September year to date 2009 net income by approximately $8 million using the last PUCT-approved return on equity rate. OTHER TEXAS RATE MATTERS Hurricanes Dolly and Ike In July and September 2008, TCC’s service territory in south Texas was hit by Hurricanes Dolly and Ike, respectively. TCC incurred $23 million and $2 million in incremental maintenance costs related to service restoration efforts for Hurricanes Dolly and Ike, respectively. TCC has a PUCT-approved catastrophe reserve which permits TCC to collect $1.3 million annually until the catastrophe reserve reaches $13 million. Any incremental storm-related maintenance costs can be charged against the catastrophe reserve if the total incremental maintenance costs for a storm exceed $500 thousand. In June 2008, prior to these hurricanes, TCC had a $2 million balance in its catastrophe reserve account. Therefore, TCC established a net regulatory asset for $23 million. The balance in the net catastrophe reserve regulatory asset account as of September 30, 2009 is approximately $22 million. Under Texas law and as previously approved by the PUCT in prior base rate cases, the regulatory asset will be included in rate base in the next base rate filing. In connection with the filing of the next base rate case, TCC will evaluate the existing catastrophe reserve ratepayer funding and review potential future events to determine the appropriate increase in the funding level to request both recovery of the then existing regulatory asset balance and to adequately fund a reserve for future storms in a reasonable time period. 2008 Interim Transmission Rates In March 2008, TCC and TNC filed applications with the PUCT for an annual interim update of wholesale-transmission rates. The proposed new interim transmission rates are estimated to increase annual transmission revenues by $9 million and $4 million for TCC and TNC, respectively. In May 2008, the PUCT and the FERC approved the new interim transmission rates as filed. TCC and TNC implemented the new rates effective May 2008, subject to review during the next TCC and TNC base rate case. This review could result in a refund if the PUCT finds that TCC and TNC have not prudently incurred the requested transmission investment. TCC and TNC have not recorded any provision for refund regarding the interim transmission rates because management believes these new rates are reasonable and necessary to recover costs associated with prudently incurred new transmission investment. A refund of the interim transmission rates would have an adverse impact on net income and cash flows. 2009 Interim Transmission Rates In February 2009, TCC and TNC filed applications with the PUCT for an annual interim update of wholesale-transmission rates. The proposed new interim transmission rates are estimated to increase annual transmission revenues by $8 million and $9 million for TCC and TNC, respectively. In May 2009, the PUCT and the FERC approved the new interim transmission rates as filed. TCC and TNC implemented the new rates effective May 2009, subject to review during the next TCC and TNC base rate case. This review could result in a refund if the PUCT finds that TCC and TNC have not prudently incurred the requested transmission investment. TCC and TNC have not recorded any provision for refund regarding the interim transmission rates because management believes these new rates are reasonable and necessary to recover costs associated with prudently incurred new transmission investment. A refund of the interim transmission rates would have an adverse impact on net income and cash flows. 2007 Texas Base Rate Increase Appeal In November 2006, TCC filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rates in Texas. TCC’s revised requested increase in annual base rates was $70 million based on a requested return on common equity of 10.75%. TCC implemented the rate change in June 2007, subject to refund. In March 2008, the PUCT issued an order approving a $20 million base rate increase based on a return on common equity of 9.96% and an additional $20 million increase in revenues related to the expiration of TCC’s merger credits. In addition, depreciation expense was decreased by $7 million and discretionary fee revenues were increased by $3 million. The order increased TCC’s annual pretax income by approximately $50 million. Various parties appealed the PUCT decision. In February 2009, the Texas District Court affirmed the PUCT in most respects. However, it also ruled that the PUCT improperly denied TCC an AFUDC return on the prepaid pension asset that the PUCT ruled to be CWIP. In March 2009, various intervenors appealed the Texas District Court decision to the Texas Court of Appeals. Management is unable to predict the outcome of these proceedings. If the appeals are successful, it could have an adverse effect on future net income and cash flows. 2009 Texas Base Rate Filing In August 2009, SWEPCo filed a base rate case with the PUCT to increase non-fuel base rates by approximately $75 million annually based on a requested return on common equity of 11.5%. The filing includes a base rate increase of $27 million, a vegetation management rider for $16 million and financing cost riders of $32 million related to the construction of the Stall Unit and Turk Plant. In addition, the net merger savings credit of $7 million will be removed from rates and depreciation expense is proposed to decrease by $17 million. The proposed filing would increase SWEPCo’s annual pretax income by approximately $51 million. The proposed Stall Unit rider would recover a return on the Stall Unit investment while the Stall Unit is under construction and continuing after it is placed in service plus recovery of depreciation when it is placed in service in 2010. The proposed Turk Plant rider would recover a return on the Turk Plant investment and will continue until such time that the Turk Plant is included in base rates. Both riders would terminate when base rates are increased to include recovery of the Turk Plant’s and the Stall Unit’s respective plant investments, plus a return thereon, and a recovery of their related operating expenses. Management is unable to predict the outcome of this filing. ETT In December 2007, TCC contributed $70 million of transmission facilities to ETT, an AEP joint venture accounted for using the equity method. The PUCT approved ETT's initial rates, a request for a transfer of facilities and a certificate of convenience and necessity (CCN) to operate as a stand alone transmission utility in the ERCOT region. ETT was allowed a 9.96% after tax return on equity rate in those approvals. In 2008, intervenors filed a notice of appeal to the Travis County District Court. In October 2008, the court ruled that the PUCT exceeded its authority by approving ETT’s application as a stand alone transmission utility without a service area under the wrong section of the statute. Management believes that ruling is incorrect. Moreover, ETT provided evidence in its application that ETT complied with what the court determined was the proper section of the statute. In January 2009, ETT and the PUCT filed appeals to the Texas Court of Appeals. In June 2009, the Texas governor signed a new law that clarifies the PUCT’s authority to grant CCNs to transmission-only utilities such as ETT. In September 2009, ETT filed an application with the PUCT for a CCN under the new law for the purpose of confirming its authority to operate as a transmission-only utility regardless of the outcome of the pending litigation. The parties to the litigation pending at the Texas Court of Appeals have stipulated agreement or indicated they are not opposed to ETT’s request. During 2009, TCC and TNC sold $93 million and $1 million, respectively, of additional transmission facilities to ETT. As of September 30, 2009, AEP’s net investment in ETT was $47 million. Depending upon ETT’s filing under the new law, the ultimate outcome of the appeals and any resulting remands, TCC and TNC may be required to reacquire transferred assets and projects under construction by ETT if ETT cannot obtain the appropriate approvals. As of September 30, 2009, ETT’s net investment in property, plant and equipment was $236 million, of which $100 million was under construction. In September 2008, ETT and a group of other Texas transmission providers filed a comprehensive plan with the PUCT for completion of the Competitive Renewable Energy Zone (CREZ) initiative. The CREZ initiative is the development of 2,400 miles of new transmission lines to transport electricity from 18,000 MWs of planned wind farm capacity in west Texas to rapidly growing cities in eastern Texas. In March 2009, the PUCT issued an order pursuant to a January 2009 decision that authorized ETT to pursue the construction of $841 million of new CREZ transmission assets and also initiated a proceeding to develop a sequence of regulatory filings for routing the CREZ transmission lines. In June 2009, ETT and other parties entered into a settlement agreement establishing dates for these filings. Pursuant to the settlement agreement, which is pending PUCT approval, ETT would make regulatory filings in 2010 and initiate construction upon receipt of PUCT approval. ETT, TCC and TNC are involved in transactions relating to the transfer to ETT of other transmission assets, which are in various stages of review and approval. In October 2009, ETT, TCC and TNC filed joint applications with the PUCT for approval to transfer from TCC and TNC to ETT approximately $69 million and $72 million, respectively, of transmission assets and CWIP. The transfers are planned to be completed by the end of the first quarter of 2010. A decision from the PUCT is pending. Stall Unit See “Stall Unit” section within “Louisiana Rate Matters” for disclosure. Turk Plant See “Turk Plant” section within “Arkansas Rate Matters” for disclosure. Virginia Rate Matters Virginia E&R Costs Recovery Filing Due to the recovery provisions in Virginia law, APCo has been deferring incremental E&R costs as incurred, excluding the equity return on in-service E&R capital investments, pending future recovery. In October 2008, the Virginia SCC approved a stipulation agreement to recover $61 million of incremental E&R costs incurred from October 2006 to December 2007 through a surcharge in 2009 which will have a favorable effect on cash flows of $61 million and on net income for the previously unrecognized equity portion of the carrying costs of approximately $11 million. The Virginia E&R cost recovery mechanism under Virginia law ceased effective with costs incurred through December 2008. However, the 2007 amendments to Virginia’s electric utility restructuring law provide for a rate adjustment clause to be requested in 2009 to recover incremental E&R costs incurred through December 2008. Under this amendment, APCo filed an application, in May 2009, to recover $102 million of unrecovered 2008 incremental deferred E&R costs plus its 2008 equity costs based on a 12.5% return on equity on its E&R capital investments. However, APCo deferred and recognized income under the E&R legislation based on a return on equity of 10.1%, which was the Virginia SCC staff’s recommendation in the prior E&R case. In October 2009, a stipulation agreement was reached between the parties and filed with the Virginia SCC addressing all matters other than rate design and customer class allocation issues. The stipulation agreement allows APCo to recover Virginia incremental E&R costs of $90 million, representing costs deferred during 2008 plus unrecognized 2008 equity costs, using a 10.6% return on equity for collection in 2010. This will result in an immaterial adjustment which will be recorded in the fourth quarter of 2009. The Virginia SCC is expected to approve the stipulation agreement in the fourth quarter of 2009. As of September 30, 2009, APCo had $88 million of deferred Virginia incremental E&R costs excluding $17 million of unrecognized equity carrying costs. The $88 million consists of $6 million of over-recovered costs collected under the 2008 surcharge, $14 million approved by the Virginia SCC related to the 2009 surcharge and $80 million, representing costs deferred during 2008, which were included in the May 2009 E&R filing for collection in 2010. Mountaineer Carbon Capture and Storage Project In January 2008, APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility. APCo and Alstom will each own part of the CO2 capture facility. APCo will also construct and own the necessary facilities to store the CO2. RWE AG, a German electric power and natural gas public utility, and the Electric Power Research Institute are participating in the project and providing some funding to offset APCo's costs. APCo’s estimated cost for its share of the constructed facilities is $74 million. In May 2009, the West Virginia Department of Environmental Protection issued a permit to inject CO2 that requires, among other items, that APCo monitor the wells for at least 20 years following the cessation of CO2 injection. In September 2009, the capture portion of the project was placed into service and in October 2009, APCo started injecting CO2 in underground storage. The injection of CO2 required the recordation of an asset retirement obligation and an offsetting regulatory asset at its estimated net present value of $36 million in October 2009. Through September 30, 2009, APCo incurred $71 million in capitalized project costs which are included in Regulatory Assets. APCo currently earns a return on the Virginia portion of the capitalized project costs incurred through June 30, 2008, as a result of a base rate case settlement approved by the Virginia SCC in November 2008. In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on the estimated increased Virginia jurisdictional share of its CO2 capture and storage project costs including the related asset retirement obligation expenses. See the “Virginia Base Rate Filing” section below. Based on the favorable treatment related to the CO2 capture demonstration facility in APCo’s last Virginia base rate case, APCo is deferring its carbon capture expense as a regulatory asset for future recovery. APCo plans to seek recovery of the West Virginia jurisdictional costs in its next West Virginia base rate filing which is expected to be filed in the first quarter of 2010. If the deferred project costs are disallowed in future Virginia or West Virginia rate proceedings, it could have an adverse effect on future net income and cash flows. Virginia Base Rate Filing The 2007 amendments to Virginia’s electric utility restructuring law required that each investor-owned utility, such as APCo, file a base rate case with the Virginia SCC in 2009 in which the Virginia SCC will determine fair rates of return on common equity (ROE) for the generation and distribution services of the utility. As a result, in July 2009, APCo filed a base rate case with the Virginia SCC requesting an increase in the generation and distribution portions of its base rates of $169 million annually based on a 2008 test year, as adjusted, and a 13.35% ROE inclusive of a requested 0.85% ROE performance incentive increase as permitted by law. The recovery of APCo’s transmission service costs in Virginia was requested in a separate and simultaneous transmission rate adjustment clause filing. See the “Rate Adjustment Clauses” section below. In August 2009, APCo filed supplemental schedules and testimony that decreased the requested annual revenue increase to $154 million which reflected a recent Virginia SCC order in an unaffiliated utility’s base rate case concerning the appropriate capital structure to be used in the determination of the revenue requirement. The new generation and distribution base rates will become effective, subject to refund, in December 2009. Rate Adjustment Clauses In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RAC) beginning in January 2009 for the timely and current recovery of costs of (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities including major unit modifications. In July 2009, APCo filed for approval of a transmission RAC simultaneous with the 2009 base rate case filing in which the Virginia jurisdictional share of transmission costs was requested for recovery through the RAC instead of through base rates. The transmission RAC filing requested an initial $94 million annual revenue requirement representing an annual increase of $24 million above the current level embedded in APCo’s Virginia base rates. APCo requested to implement the transmission RAC concurrently with the new base rates in December 2009. See the “Virginia Base Rate Filing” section above. In October 2009, the Virginia SCC approved the stipulation agreement providing for an annual incremental revenue increase in transmission rates of $22 million excluding $2 million of reasonable and prudent PJM administrative costs that may be recovered in base rates. APCo plans to file for approval of an environmental RAC no later than the first quarter of 2010 to recover any unrecovered environmental costs incurred after December 2008. APCo also plans to file for approval of a renewable energy RAC before the end of the first quarter of 2010 to recover costs associated with APCo’s wind power purchase agreements. In accordance with Virginia law, APCo is deferring any incremental transmission and environmental costs incurred after December 2008 and any renewable energy costs incurred after August 2009 which are not being recovered in current revenues. As of September 30, 2009, APCo has deferred for future recovery $17 million of environmental costs (excluding $3 million of unrecognized equity carrying costs), $14 million of transmission costs and $1 million of renewable energy costs. Management is evaluating whether to make other RAC filings at this time. If the Virginia SCC were to disallow a portion of APCo’s deferred RAC costs, it would have an adverse effect on future net income and cash flows. Virginia Fuel Factor Proceeding In May 2009, APCo filed an application with the Virginia SCC to increase its fuel adjustment charge by approximately $227 million from July 2009 through August 2010. The $227 million proposed increase related to a $104 million projected under-recovery balance of fuel costs as of June 2009 and $123 million of projected fuel costs for the period July 2009 through August 2010. APCo’s actual under-recovered fuel balance at June 2009 was $93 million. Due to the significance of the estimated required increase in fuel rates, APCo’s application proposed an alternative method of collection of actual incurred fuel costs. The proposed alternative would allow APCo to recover 100% of the $104 million prior period under-recovery deferral and 50% of the $123 million increase from July 2009 through August 2010 with recovery of any remaining actual under-recovered fuel costs in APCo’s next fuel factor proceeding from September 2010 through August 2011. In May 2009, the Virginia SCC ordered that neither of APCo’s proposed fuel factors shall become effective, pending further review by the Virginia SCC. In August 2009, the Virginia SCC issued an order which provided for a $130 million fuel revenue increase, effective August 2009. The reduction in revenues from the requested amount recognizes a lower than projected under-recovery balance and a lower level of projected fuel costs to be recovered through the approved fuel factor. Any fuel under-recovery due to the lower level of projected fuel costs should be deferred as a regulatory asset for future recovery under the FAC true-up mechanism and recoverable, if necessary, either in APCo’s next fuel factor proceeding for the period September 2010 through August 2011 or through other statutory mechanisms. APCo’s Filings for an IGCC Plant See “APCo’s Filings for an IGCC Plant” section within “West Virginia Rate Matters” for disclosure. West Virginia Rate Matters APCo’s and WPCo’s 2009 Expanded Net Energy Cost (ENEC) Filing In March 2009, APCo and WPCo filed an annual ENEC filing with the WVPSC to increase the ENEC rates by approximately $442 million for incremental fuel, purchased power, other energy related costs and environmental compliance project costs to become effective July 2009. Within the filing, APCo and WPCo requested the WVPSC to allow APCo and WPCo to temporarily adopt a modified ENEC mechanism due to the distressed economy and the significance of the projected required increase. The proposed modified ENEC mechanism provides that the ENEC rate increase be phased in with unrecovered amounts deferred for future recovery over a five-year period beginning in July 2009, extends cost projections out for a period of three years through June 30, 2012 and provides for three annual increases to recover projected future ENEC cost increases as well as the phase-in deferrals. The proposed modified ENEC mechanism also provides that to the extent the phase-in deferrals exceed the deferred amounts that would have otherwise existed under the traditional ENEC mechanism, the phase-in deferrals are subject to a carrying charge based upon APCo’s and WPCo’s weighted average cost of capital. As proposed, the modified ENEC mechanism would produce three annual increases, based upon projected fuel costs and including carrying charges, of $189 million, $166 million and $172 million, effective July 2009, 2010 and 2011, respectively. In May 2009, various intervenors submitted testimony supporting adjustments to APCo’s and WPCo’s actual and projected ENEC costs. The intervenors also proposed alternative rate phase-in plans ranging from three to five years. Specifically, the WVPSC staff and the West Virginia Consumer Advocate recommended an increase of $376 million and $327 million, respectively, with $132 million and $130 million, respectively, being collected during the first year and suggested that the remaining rate increases for future years be determined in subsequent ENEC filings. In June 2009, APCo and WPCo filed rebuttal testimony. In the rebuttal testimony, APCo and WPCo accepted certain intervenor adjustments to the forecasted ENEC costs and reduced the requested increase to $398 million with a proposed first-year increase of $160 million. The intervenors’ forecast adjustments would not impact earnings since the ENEC mechanism would continue to true-up to actual costs. The primary difference between the intervenors’ $130 million first-year increase and APCo’s and WPCo’s $160 million first-year increase is the intervenors’ proposed disallowance of up to $36 million of actual and projected coal costs. In September 2009, the WVPSC issued an order granting a $355 million increase to be phased in over the next four years with a first-year increase of $124 million. As of September 30, 2009, APCo’s ENEC under-recovery balance was $255 million which is included in Regulatory Assets. The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 1, 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan. The order disallowed an immaterial amount of deferred ENEC costs which was recognized in September 2009. It also lowered annual coal cost projections by $27 million and deferred recovery of unrecovered ENEC deferrals related to price increases on certain renegotiated coal contracts. The WVPSC indicated that it would review the prudency of these additional costs in the next ENEC proceeding. As of September 30, 2009, APCo has deferred $13 million of unrecovered coal costs on the renegotiated coal contracts which is included in APCo’s $255 million ENEC under-recovery regulatory asset and has an additional $5 million in purchased fuel costs on the renegotiated coal contracts which is recorded in Fuel on the Condensed Consolidated Balance Sheets. Although management believes the portion of its deferred ENEC under-recovery balance attributable to renegotiated coal contracts is probable of recovery, if the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs including any costs incurred in the future related to the renegotiated coal contracts, it could have an adverse effect on future net income and cash flows. APCo’s Filings for an IGCC Plant In January 2006, APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia. In June 2007, APCo sought pre-approval from the WVPSC for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing finance costs of the project during the construction period, as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. In March 2008, the WVPSC granted APCo the CPCN to build the plant and approved the requested cost recovery. In March 2008, various intervenors filed petitions with the WVPSC to reconsider the order. No action has been taken on the requests for rehearing. In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with the proposed IGCC plant. The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009. The $45 million included a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009. APCo also requested authorization to defer a carrying cost on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered. The Virginia SCC issued an order in April 2008 denying APCo’s requests, in part, upon its finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities. In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. Various parties, including APCo, filed comments with the WVPSC. In September 2009, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant. In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant contingent upon the commencement of construction, qualifying expenses being incurred and certification of the IGCC plant prior to July 2010. Through September 30, 2009, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction. Although management continues to pursue consideration of the construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs, which if not recoverable, would have an adverse effect on future net income and cash flows. Mountaineer Carbon Capture and Storage Project See “Mountaineer Carbon Capture and Storage Project” section within “Virginia Rate Matters” for disclosure. Kentucky Rate Matters Kentucky Storm Restoration Expenses During 2009, KPCo experienced severe storms causing significant customer outages. In August 2009, KPCo filed a petition with the Kentucky Public Service Commission (KPSC) for an order seeking authorization to defer approximately $10 million of incremental storm restoration expense for review and recovery in KPCo’s next base rate proceeding. The requested deferral of the previously expensed $10 million is in addition to the annual $2 million of storm-related operation and maintenance expense included in KPCo’s current base rates. Management is unable to predict the outcome of this petition. A decision is expected from the KPSC during the fourth quarter of 2009. Indiana Rate Matters Indiana Base Rate Filing In a January 2008 filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million based on a return on equity of 11.5%. The base rate increase included a $69 million annual reduction in rates due to an approved reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007. In addition, I&M proposed to share with customers, through a proposed tracker, 50% of its off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million. In December 2008, I&M and all of the intervenors jointly filed a settlement agreement with the IURC proposing to resolve all of the issues in the case. The settlement agreement incorporated the $69 million annual reduction in revenues from the depreciation rate reduction in the development of an agreed to revenue increase of $44 million, which included a $22 million increase in base rates based on an authorized return on equity of 10.5% and a $22 million initial increase in tracker rates for incremental PJM, net emission allowance and demand side management (DSM) costs. The agreement also establishes an off-system sales sharing mechanism and other provisions which include continued funding for the eventual decommissioning of the Cook Plant. In March 2009, the IURC modified and approved the settlement agreement that provides for an annual increase in revenues of $42 million. The $42 million increase included a $19 million increase in base rates, net of the depreciation rate reduction and a $23 million increase in tracker revenue. The IURC order modified the settlement agreement by removing from base rates the recovery of DSM costs, establishing a tracker with an initial zero amount for DSM costs, requiring I&M to collaborate with other affected parties regarding the design and recovery of future I&M DSM programs, adjusting the sharing of off-system sales margins to 50% above $37.5 million which it included in base rates and approving the recovery of $7 million of previously expensed NSR and OPEB costs which favorably affected 2009 net income. In addition, the IURC order requires I&M to review and file a final report by December 2009 on the effectiveness of the Interconnection Agreement including I&M’s relationship with PJM. The new rates were implemented in March 2009. Rockport and Tanners Creek Plants Environmental Facilities In January 2009, I&M filed a petition with the IURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from its existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants. In addition, the petition requested approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport Plant. The petition requested to depreciate the ACI systems over an accelerated 10-year period and the SNCR systems over the 11-year remaining useful life of the Tanners Creek generating units. I&M’s petition also requested the IURC to approve a rate adjustment mechanism for unrecovered carrying costs during the remaining construction period of these environmental facilities and a return on investment, depreciation expense and operation and maintenance costs, including consumables and new emission allowance costs, once the facilities are placed in service. I&M also requested the IURC to authorize the deferral of the remaining construction period carrying costs and any in-service cost of service for these facilities until such costs can be recovered in the requested rate adjustment mechanism. Through September 30, 2009, I&M incurred $12 million and $12 million in capitalized facilities cost related to the Rockport and Tanners Creek Plants, respectively, which are included in CWIP. Subsequent to the filing of this petition, the Indiana base rate order included recovery of emission allowance costs. Therefore, that portion of the emission allowances cost for the subject facilities will not be recovered in this requested rate adjustment mechanism. In May 2009, a settlement agreement (settlement) was filed with the IURC recommending approval of a CPCN and a rider to recover a weighted average cost of capital on I&M’s investment in the SNCR system and the ACI system at December 31, 2008, plus future depreciation and operation and maintenance costs. The settlement will allow I&M to file subsequent requests in six month intervals to update the rider for additional investments in the SNCR systems and the ACI systems and for true-ups of the rider revenues to actual costs. In June 2009, the IURC approved the settlement which will result in an annualized increase in rates of $8 million effective August 1, 2009. Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown) In January 2009, I&M filed with the IURC an application to increase its fuel adjustment charge by approximately $53 million for the period of April through September 2009. The filing included an under-recovery for the period ended November 2008, mainly as a result of deferred under-recovered fuel costs, the shutdown of the Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire and a projection for the future period of fuel costs increases including Unit 1 shutdown replacement power costs. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. The filing also included an adjustment, beginning coincident with the receipt of accidental outage insurance proceeds in mid-December 2008, to eliminate the incremental fuel cost of replacement power post mid-December 2008 with a portion of the insurance proceeds from the accidental outage policy. I&M reached an agreement in February 2009 with intervenors, which was approved by the IURC in March 2009, to collect the prior period under-recovery deferral balance over twelve months instead of over six months as proposed. Under the agreement, the fuel factor was placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown, the use of the insurance proceeds and I&M’s fuel procurement practices. The order also provided for the shutdown issues to be resolved subsequent to the date Unit 1 returns to service, which if temporary repairs are successful, could occur as early as the fourth quarter of 2009. Consistent with the March 2009 IURC order, I&M made its semi-annual fuel filing in July 2009 requesting an increase of approximately $4 million for the period October 2009 through March 2010. The projected fuel costs for the period included the second half of the under-recovered deferral balance approved in the March 2009 order plus recovery of an additional $12 million under-recovered deferral balance from the reconciliation period of December 2008 through May 2009. In August 2009, an intervenor filed testimony proposing that I&M should refund approximately $11 million through the fuel adjustment clause, which is the intervenor’s estimate of the Indiana retail jurisdictional portion of the additional fuel cost during the accidental outage insurance policy deductible period, which is the period from the date of the incident in September 2008 to when the insurance proceeds began in December 2008. In August 2009, I&M and intervenors filed a settlement agreement with the IURC that included the recovery of the $12 million under-recovered deferral balance, subject to refund, over twelve months instead of over six months as originally proposed and an agreement to delay all Unit 1 outage issues in this filing until after the unit is returned to service. Management cannot predict the outcome of the pending proceedings, including the treatment of the outage insurance proceeds, and whether any fuel clause revenues or insurance proceeds will have to be refunded which could adversely affect future net income and cash flows. Michigan Rate Matters 2008 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown) In March 2009, I&M filed with the Michigan Public Service Commission (MPSC) its 2008 PSCR reconciliation. The filing also included an adjustment to reduce the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage with a portion of the accidental insurance proceeds from the Cook Plant Unit 1 outage policy, which began in mid-December 2008. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. In May 2009, the MPSC set a procedural schedule for testimony and hearings to be held in the fourth quarter of 2009. A final order is anticipated in the first quarter of 2010. Management is unable to predict the outcome of this proceeding and whether it will have an adverse effect on future net income and cash flows. Oklahoma Rate Matters PSO Fuel and Purchased Power 2006 and Prior Fuel and Purchased Power Proceedings addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the OCC due to two issues. The first issue relates to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement. In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed the ALJ recommendations that concluded the FERC and not the OCC had jurisdiction over this matter. In August 2008, the OCC filed a complaint with the FERC concerning this allocation of OSS issue. In December 2008, under an adverse FERC ruling, PSO recorded a regulatory liability to return the reallocated OSS to customers. Effective with the March 2009 billing cycle, PSO began refunding the additional reallocated OSS to its customers. See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.” The second issue concerns a 2002 under-recovery of $42 million of PSO fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to 2002. PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. In the June 2008 appeal by the OIEC of the ALJ recommendations, the OIEC contended that PSO should not have collected the $42 million without specific OCC approval nor collected the $42 million before the OSS allocation issue was resolved. As such, the OIEC contends that the OCC could and should require PSO to refund the $42 million it collected through its fuel clause. In August 2008, the OCC heard the OIEC appeal and a decision is pending. Although the OSS allocation issue has been resolved at the FERC, if the OCC were to order PSO to make an additional refund for all or a part of the $42 million, it would have an adverse effect on future net income and cash flows. 2007 Fuel and Purchased Power In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007. In August 2009, a joint stipulation and settlement agreement (settlement) was filed with the OCC requesting the OCC to issue an order accepting the fuel adjustment clause for 2007 and find that PSO’s fuel procurement practices, policies and decisions were prudent. In September 2009, the OCC issued a final order approving the settlement. 2008 Oklahoma Base Rate Filing Appeal In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million (later adjusted to $127 million) on an annual basis. At the time of the filing, PSO was recovering $16 million a year for costs related to new peaking units recently placed into service through a Generation Cost Recovery Rider (GCRR). Subsequent to implementation of the new base rates, the GCRR terminates and PSO recovers these costs through the new base rates. Therefore, PSO’s net annual requested increase in total revenues was actually $117 million (later adjusted to $111 million). The proposed revenue requirement reflected a return on equity of 11.25%. In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on equity. The rate increase includes a $59 million increase in base rates and a $22 million increase for costs to be recovered through riders outside of base rates. The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service. The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures. The final order approved lower depreciation rates and also provided for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period. The deferral was recorded in the first quarter of 2009. PSO was given authority to record additional under/over recovery deferrals for future distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses. The new rates reflecting the final order were implemented with the first billing cycle of February 2009. During 2009, PSO accrued a regulatory liability of approximately $1 million related to a delay in installing gridSMART technologies as the OCC final order had included $2 million of additional revenues for this purpose. PSO filed an appeal with the Oklahoma Supreme Court challenging an adjustment contained within the OCC final order to remove prepaid pension fund contributions from rate base. In February 2009, the Oklahoma Attorney General and several intervenors also filed appeals with the Oklahoma Supreme Court raising several rate case issues. In July 2009, the Oklahoma Supreme Court assigned the case to the Court of Civil Appeals. If the Oklahoma Attorney General or the intervenors’ appeals are successful, it could have an adverse effect on future net income and cash flows. Oklahoma Capital Reliability Rider Filing In August 2009, PSO filed an application with the OCC requesting a Capital Reliability Rider (CRR) to recover depreciation, taxes and return on PSO’s net capital investments for generation, transmission and distribution assets that have been placed into service from September 1, 2008 to June 30, 2009. If approved, PSO would increase billings to customers during the first six months of 2010 by $11 million related to the increase in revenue requirement and $9 million related to the lag between the investment cut-off of June 30, 2009 and the date of the rider implementation of January 1, 2010. In October 2009, all but two of the parties to the CRR filing agreed to a stipulation that was filed with the OCC to collect no more than $30 million of revenues under the CRR on an annual basis beginning January 2010 until PSO’s next base rate order. The CRR revenues are subject to refund with interest pending the OCC’s audit. The stipulation also provides for an offsetting fuel revenue reduction via a modification to the fuel adjustment factor of Oklahoma jurisdictional customers on an annual basis by $30 million beginning January 2010 and refunds of certain over-recovered fuel balances during the first quarter of 2010. Finally, the stipulation requires that PSO shall file a base rate case no later than July 2010. Management is unable to predict the outcome of this application. PSO Purchase Power Agreement As a result of the 2008 Request for Proposals following a December 2007 OCC order that found PSO had a need for new base load generation by 2012, PSO and Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term purchase power agreement (PPA). The PPA is for the annual purchase of approximately 520 MW of electric generation from the 795 MW natural gas-fired generating plant in Jenks, Oklahoma for a term of approximately ten years beginning in June 2012. In May 2009, an application seeking approval was filed with the OCC. In July 2009, OCC staff, the Independent Evaluator and the Oklahoma Industrial Energy Consumers filed responsive testimony in support of PSO’s proposed PPA with Exelon. In August 2009, a settlement agreement was filed with the OCC. In September 2009, the OCC approved the settlement agreement including the recovery of these purchased power costs through a separate base load purchased power rider. Louisiana Rate Matters 2008 Formula Rate Filing In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (FRP). SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%. In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund. During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors. SWEPCo is currently working with the settlement parties to prepare a written agreement to be filed with the LPSC. 2009 Formula Rate Filing In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009 pursuant to the approved FRP. SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund. In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation. The consultants also recommended refunding the SIA through SWEPCo’s FRP. See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters.” SWEPCo will continue to work with the LPSC regarding the issues raised in their objection. SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC. If the LPSC disagrees with SWEPCo, it could result in material refunds. Stall Unit In May 2006, SWEPCo announced plans to build an intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit at its existing Arsenal Hill Plant location in Shreveport, Louisiana to be named the Stall Unit. SWEPCo submitted the appropriate filings to the LPSC, the PUCT, the APSC and the Louisiana Department of Environmental Quality to seek approvals to construct the Stall Unit. The Stall Unit is currently estimated to cost $435 million, including $49 million of AFUDC, and is expected to be in service in mid-2010. The Louisiana Department of Environmental Quality issued an air permit for the Stall Unit in March 2008. In July 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, own and operate the Stall Unit and recommended that costs be capped at $445 million including AFUDC and excluding related transmission costs. In October 2008, the LPSC issued a final order effectively approving the ALJ recommendation. In March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the facility based on a prior cost estimate. In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the unit. The APSC staff filed testimony in March 2009 supporting the approval of the plant. In June 2009, the APSC approved the construction of the unit with a series of conditions consistent with those designated by the LPSC, including a requirement for an independent monitor and a $445 million cost cap including AFUDC and excluding related transmission costs. As of September 30, 2009, SWEPCo has capitalized construction costs of $364 million, including AFUDC, and has contractual construction commitments of an additional $31 million with the total estimated cost to complete the unit at $435 million. If the final cost of the Stall Unit exceeds the $445 million cost cap, it could have an adverse effect on net income and cash flows. If for any other reason SWEPCo cannot recover its capitalized costs, it would have an adverse effect on future net income, cash flows and possibly financial condition. Temporary Funding of Financing Costs during Construction In October 2009, SWEPCo made a filing with the LPSC requesting temporary recovery of financing costs related to the Louisiana jurisdiction portion of the Turk Plant. In the filing, SWEPCo would recover over three years of an estimated $105 million of construction financing costs related to SWEPCo’s ongoing Turk generation construction program through its existing Fuel Adjustment Rider. If approved as requested, recovery would start in January 2010 and continue through 2012 when the Turk Plant is scheduled to be placed in service. According to the filing, the amount of financing costs collected during construction would be refunded to customers, including interest at SWEPCo’s long-term debt rate, after the Turk Plant is in service. As filed, the refund would occur over a period not to exceed five years. Finally, SWEPCo requested that both the Turk Plant and the Stall Unit be placed in rates via the formula rate plan without regulatory lag. Management cannot predict the outcome of this filing. Turk Plant See “Turk Plant” section within “Arkansas Rate Matters” for disclosure. Arkansas Rate Matters Turk Plant In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. In 2007, the Oklahoma Municipal Power Authority (OMPA) acquired an approximate 7% ownership interest in the Turk Plant, paid SWEPCo $13.5 million for its share of the accrued construction costs and began paying its proportional share of ongoing costs. During the first quarter of 2009, the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) acquired ownership interests in the Turk Plant representing approximately 12% and 8%, respectively, paid SWEPCo $104 million in the aggregate for their shares of accrued construction costs and began paying their proportional shares of ongoing construction costs. The joint owners are billed monthly for their share of the on-going construction costs exclusive of AFUDC. Through September 30, 2009, the joint owners paid SWEPCo $196 million for their share of the Turk Plant construction expenditures. SWEPCo owns 73% of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.6 billion, excluding AFUDC, with SWEPCo’s share estimated to cost $1.2 billion, excluding AFUDC. In addition, SWEPCo will own 100% of the related transmission facilities which are currently estimated to cost $131 million, excluding AFUDC. In November 2007, the APSC granted approval for SWEPCo to build the Turk Plant in Arkansas by issuing a Certificate of Environmental Compatibility and Public Need (CECPN). Certain intervenors appealed the APSC’s decision to grant the CECPN to the Arkansas Court of Appeals. In January 2009, the APSC granted additional CECPNs allowing SWEPCo to construct Turk-related transmission facilities. Intervenors also appealed these CECPN orders to the Arkansas Court of Appeals. In June 2009, the Arkansas Court of Appeals issued a unanimous decision that, if upheld by the Arkansas Supreme Court, would reverse the APSC’s grant of the CECPN permitting construction of the Turk Plant to serve Arkansas retail customers. The decision was based upon the Arkansas Court of Appeals’ interpretation of the statute that governs the certification process and its conclusion that the APSC did not fully comply with that process. The Arkansas Court of Appeals concluded that SWEPCo’s need for base load capacity, the construction and financing of the Turk generating plant and the proposed transmission facilities’ construction and location should all have been considered by the APSC in a single docket instead of separate dockets. In October 2009, the Arkansas Supreme Court granted the petitions filed by SWEPCo and the APSC to review the Arkansas Court of Appeals decision. While the appeal is pending, SWEPCo is continuing construction of the Turk Plant. If the decision of the Court of Appeals is not reversed by the Supreme Court of Arkansas, SWEPCo and the other joint owners of the Turk Plant will evaluate their options. Depending on the time taken by the Arkansas Supreme Court to consider the case and the reasoning of the Arkansas Supreme Court when it acts on SWEPCo’s and the APSC’s petitions, the construction schedule and/or the cost could be adversely affected. Should the appeals by the APSC and SWEPCo be unsuccessful, additional proceedings or alternative contractual ownership and operational responsibilities could be required. In March 2008, the LPSC approved the application to construct the Turk Plant. In August 2008, the PUCT issued an order approving the Turk Plant with the following four conditions: (a) the capping of capital costs for the Turk Plant at the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders. In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions as being unlawful. In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers. If the cost cap restrictions are upheld and construction or CO2 emission costs exceed the restrictions or if the intervenor appeal is successful, it could have an adverse effect on net income, cash flows and possibly financial condition. A request to stop pre-construction activities at the site was filed in Federal District Court by certain Arkansas landowners. In July 2008, the federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals. In January 2009, SWEPCo filed a motion to dismiss the appeal, which was granted in March 2009. In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. In December 2008, certain parties filed an appeal of the air permit approval with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while the appeal of the Turk Plant’s air permit is heard. In June 2009, hearings on the air permit appeal were held at the APCEC. A decision is still pending and not expected until 2010. These same parties have filed a petition with the Federal EPA to review the air permit. The petition will be acted on by December 2009, according to the terms of a recent settlement between the petitioners and the Federal EPA. The Turk Plant cannot be placed into service without an air permit. In August 2009, these same parties filed a petition with the APCEC to halt construction of the Turk Plant. In September 2009, the APCEC voted to allow construction of the Turk Plant to continue and rejected the request for a stay. If the air permit were to be remanded or ultimately revoked, construction of the Turk Plant would be suspended or cancelled. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers an inadvertent impact on approximately 2.5 acres of wetlands at the Turk Plant construction site prior to the receipt of the permit. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas outside of the proposed Army Corps of Engineers permitted areas of the Turk Plant pending the Army Corps of Engineers review. SWEPCo has entered into a Consent Agreement and Final Order with the Federal EPA to resolve liability for the inadvertent impact and agreed to pay a civil penalty of approximately $29 thousand. The Arkansas Governor’s Commission on Global Warming issued its final report to the governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. To date, the report’s effect is only advisory, but if legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s ability to complete construction on schedule in 2012 and on budget. If the Turk Plant cannot be completed and placed in service, SWEPCo would seek approval to recover its prudently incurred capitalized construction costs including any cancellation fees and a return on unrecovered balances through rates in all of its jurisdictions. As of September 30, 2009, and excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $646 million of expenditures (including AFUDC and capitalized interest, and related transmission costs of $24 million). As of September 30, 2009, the joint owners and SWEPCo have contractual construction commitments of approximately $515 million (including related transmission costs of $1 million) and, if the plant had been cancelled, would have incurred cancellation fees of $136 million (including related transmission cancellation fees of $1 million). Management believes that SWEPCo’s planning, certification and construction of the Turk Plant to date have been in material compliance with all applicable laws and regulations, except for the inadvertent wetlands intrusion discussed above. Further, management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if for any reason SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service, it would adversely impact net income, cash flows and possibly financial condition unless the resultant losses can be fully recovered, with a return on unrecovered balances, through rates in all of its jurisdictions. Arkansas Base Rate Filing In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall Unit and Turk Plant. In September 2009, SWEPCo, the APSC staff and the Arkansas Attorney General entered into a settlement agreement in which the settling parties agreed to an $18 million increase based on a return on equity of 10.25%. In addition, the settlement agreement will decrease depreciation expense by $10 million. The settlement agreement would increase SWEPCo’s annual pretax income by approximately $28 million. The settlement agreement also includes a separate rider of approximately $11 million annually that will allow SWEPCo to recover carrying costs, depreciation and operation and maintenance expenses on the Stall Unit once it is placed into service. Until then, SWEPCo will continue to accrue AFUDC on the Stall Unit. The other parties to the case do not oppose the settlement agreement. If the settlement agreement is approved by the APSC, new base rates will become effective for all bills rendered on or after November 25, 2009. In January 2009, an ice storm struck in northern Arkansas affecting SWEPCo’s customers. SWEPCo incurred incremental operation and maintenance expenses above the estimated amount of storm restoration costs included in existing base rates. In May 2009, SWEPCo filed an application with the APSC seeking authority to defer $4 million (later adjusted to $3 million) of expensed incremental operation and maintenance costs and to address the recovery of these deferred expenses in the pending base rate case. In July 2009, the APSC issued an order approving the deferral request subject to investigation, analysis and audit of the costs. In August 2009, the APSC staff filed testimony that recommended recovery of approximately $1 million per year through amortization of the deferred ice storm costs over three years in base rates. This amount was included in the $18 million base rate increase agreed upon in the settlement agreement. In September 2009, based upon the APSC audit and recommendation, management established a regulatory asset of $3 million for the recovery of the ice storm restoration costs. Stall Unit See “Stall Unit” section within “Louisiana Rate Matters” for disclosure. FERC Rate Matters Regional Transmission Rate Proceedings at the FERC SECA Revenue Subject to Refund Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006. Intervenors objected to the temporary SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues. In August 2006, a FERC ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount. In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes, based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. AEP and SECA ratepayers are engaged in settlement discussions in an effort to settle the SECA issue. However, if the ALJ’s initial decision is upheld in its entirety, it could result in a refund of a portion or all of the unsettled SECA revenues. Based on anticipated settlements, the AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $39 million and $5 million in 2006 and 2007, respectively, applicable to a total of $220 million of SECA revenues. In February 2009, a settlement agreement was approved by the FERC resulting in the completion of a $1 million settlement applicable to $20 million of SECA revenue. Including this most recent settlement, AEP has completed settlements totaling $10 million applicable to $112 million of SECA revenues. The balance in the reserve for future settlements as of September 30, 2009 was $34 million. As of September 30, 2009, there were no in-process settlements. Management cannot predict the ultimate outcome of future settlement discussions or future FERC proceedings or court appeals, if any. However, if the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refund, it will have an adverse effect on future net income and cash flows. Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the available reserve of $34 million is adequate to settle the remaining $108 million of contested SECA revenues. If the remaining unsettled SECA claims are settled for considerably more than the to-date settlements or if the remaining unsettled claims cannot be settled and are awarded a refund by the FERC greater than the remaining reserve balance, it could have an adverse effect on net income. Cash flows will be adversely impacted by any additional settlements or ordered refunds. The FERC PJM Regional Transmission Rate Proceeding With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM. As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities even though other non-affiliated entities transmit power over AEP’s lines. However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region. It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone. The AEP East companies will need to obtain state regulatory approvals for recovery of any costs of new facilities that are assigned to them by PJM. In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals. In August 2009, the United States Court of Appeals issued an opinion affirming FERC’s refusal to implement a regional rate design in PJM. The AEP East companies filed for and in 2006 obtained increases in their wholesale transmission rates to recover lost revenues previously applied to reduce those rates. The AEP East companies sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky. In January and March 2009, the AEP East companies received retail rate increases in Tennessee and Indiana, respectively, which recognized the higher retail transmission costs resulting from the loss of wholesale transmission revenues from T&O transactions. As a result, the AEP East companies are now recovering approximately 98% of the lost T&O transmission revenues from their retail customers. The remaining 2% is being incurred by I&M until it can revise its rates in Michigan to recover the lost revenues. The FERC PJM and MISO Regional Transmission Rate Proceeding In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008. All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs. In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system. AEP argued the use of other PJM and MISO facilities by AEP is not as large as the use of the AEP East companies’ transmission by others in PJM and MISO and as a result the use of zonal rates would be unfair and discriminatory to AEP’s East zone retail customers. Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates. In January 2008, the FERC denied AEP’s complaint. AEP filed a rehearing request with the FERC in March 2008. In December 2008, the FERC denied AEP’s request for rehearing. In February 2009, AEP filed an appeal in the U.S. Court of Appeals. If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings to reflect the resultant additional wholesale transmission T&O revenues reduction of transmission cost to retail customers. This case is pending before the U.S. Court of Appeals which in August 2009 ruled against AEP in a similar case. See “The FERC PJM Regional Transmission Rate Proceeding” section above. Allocation of Off-system Sales Margins In August 2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies. The PUCT, the APSC and the Oklahoma Industrial Energy Consumers intervened in this filing. In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the SIA and the CSW Operating Agreement for the period June 2000 through March 2006. The FERC ordered AEP to recalculate and reallocate the off-system sales margins in compliance with the SIA and to have the AEP East companies issue refunds to the AEP West companies. Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology was reasonable. The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006. In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006. The motion for rehearing is still pending. In January 2009, AEP filed a compliance filing with the FERC and refunded approximately $250 million from the AEP East companies to the AEP West companies. Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006. In December 2008, the AEP West companies recorded a provision for refund reflecting the sharing. In January 2009, SWEPCo refunded approximately $13 million to FERC wholesale customers. In February 2009, SWEPCo filed a settlement agreement with the PUCT that provides for the Texas retail jurisdiction amount to be included in the March 2009 fuel cost report submitted to the PUCT. PSO began refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle. In April 2009, TCC and TNC filed their Advanced Metering System (AMS) with the PUCT proposing to invest in AMS to be recovered through customer surcharges beginning in October 2009. In the filing, TCC and TNC proposed to apply the SIA recorded customer refunds including interest to reduce the AMS investment and the resultant associated customer surcharge. In July 2009, consultants for the LPSC issued an audit report of SWEPCo’s Louisiana retail fuel adjustment clause. Within this report, the consultants for the LPSC recommended that SWEPCo refund the SIA, including interest, through the fuel adjustment clause. In October 2009, other consultants for the LPSC recommended refunding the SIA through SWEPCo’s formula rate plan. See “2009 Formula Rate Filing” section within “Louisiana Rate Matters.” SWEPCo is working with the APSC and the LPSC to determine the effect the FERC order will have on retail rates. Management cannot predict the outcome of the requested FERC rehearing proceeding or any future state regulatory proceedings but believes the AEP West companies’ provision for refund regarding related future state regulatory proceedings is adequate. Modification of the Transmission Agreement (TA) APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA entered into in 1984, as amended, that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations operated at 345kV and above. In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA. Under the proposed amendments, WPCo and KGPCo will be added as parties to the TA. In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse the majority of PJM transmission revenues based on individual cost of service instead of the MLR method used in the present TA. AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order. The delayed effective date was approved by the FERC in August 2009 when the FERC accepted the new TA for filing. Settlement discussions are in process. Management is unable to predict the effect, if any, it will have on future net income and cash flows due to timing of the implementation by various state regulators of the FERC’s new approved TA. |
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| 3 | CENTERPOINT ENERGY INC |
(a) Hurricane Ike CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast in September 2008. As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole mounted equipment that comprise CenterPoint Houston’s transmission and distribution system are not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $28 million. CenterPoint Houston deferred the uninsured system restoration costs as management believed it was probable that such costs would be recovered through the regulatory process. As a result, system restoration costs did not affect CenterPoint Energy’s or CenterPoint Houston’s reported operating income for 2008 or the first nine months of 2009. In April 2009, CenterPoint Houston filed with the Public Utility Commission of Texas (Texas Utility Commission) an application for review and approval for recovery of approximately $608 million in system restoration costs identified as of the end of February 2009, plus $2 million in regulatory expenses, $13 million in certain debt issuance costs and $55 million in incurred and projected carrying costs, pursuant to the legislation described below. In April 2009, the Texas Legislature enacted legislation that authorized the Texas Utility Commission to conduct proceedings to determine the amount of system restoration costs and related costs associated with hurricanes or other major storms that utilities are entitled to recover, and to issue financing orders that would permit a utility like CenterPoint Houston to recover the distribution portion of those costs and related carrying costs through the issuance of non-recourse system restoration bonds similar to the securitization bonds issued previously. The legislation also allowed such a utility to recover, or defer for future recovery, the transmission portion of its system restoration costs through the existing mechanisms established to recover transmission level costs. The legislation required the Texas Utility Commission to make its determination of recoverable system restoration costs within 150 days of the filing of a utility’s application and to rule on a utility’s application for a financing order for the issuance of system restoration bonds within 90 days of the filing of that application. Alternatively, if securitization is not the least-cost option for rate payers, the legislation authorized the Texas Utility Commission to allow a utility to recover those costs through a customer surcharge mechanism. In its application filed in April 2009, CenterPoint Houston sought approval for recovery of a total of approximately $678 million, including the $608 million in system restoration costs described above plus related regulatory expenses, certain debt issuance costs and carrying costs calculated through August 2009. In July 2009, CenterPoint Houston announced that it had reached a settlement agreement with the parties to the proceeding. Under the terms of that settlement agreement, CenterPoint Houston would be entitled to recover a total of $663 million in costs relating to Hurricane Ike, along with carrying costs from September 1, 2009 until system restoration bonds were issued. The Texas Utility Commission issued an order in August 2009 approving CenterPoint Houston’s application and the settlement agreement and authorizing recovery of a total of $663 million, of which $643 million is attributable to distribution service and eligible for securitization and the remaining $20 million is attributable to transmission service and eligible for recovery through the existing mechanisms established to recover transmission costs. In July 2009, CenterPoint Houston filed with the Texas Utility Commission its application for a financing order to recover the portion of approved costs related to distribution service through the issuance of system restoration bonds. As discussed above, in August 2009, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize $643 million in distribution service costs plus carrying charges from September 1, 2009 through the date the system restoration bonds are issued, as well as certain up-front qualified costs capped at approximately $6 million. In accordance with the financing order, CenterPoint Houston is to place into effect a separate customer credit related to accumulated deferred federal income taxes (ADFIT) associated with the storm restoration costs to be recovered. This separate credit (ADFIT Credit) is to be applied to customers’ bills to reflect the benefit of those deferred taxes at a carrying charge of 11.075%. The beginning balance of the ADFIT related to storm costs is approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit will become effective on the same date as the tariff for the system restoration charges and will reduce operating income in 2010 by approximately $24 million. CenterPoint Houston expects to issue the system restoration bonds in the fourth quarter of 2009. Assuming system restoration bonds are issued, CenterPoint Houston will recover the distribution portion of approved system restoration costs out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. CenterPoint Houston expects to recover the remaining approximately $20 million of Hurricane Ike costs related to transmission service through the existing mechanisms established to recover transmission costs. In accordance with the orders discussed above, as of September 30, 2009, CenterPoint Houston has recorded a net regulatory asset of $642 million associated with distribution-related storm restoration costs and $20 million associated with transmission-related storm restoration costs. These amounts reflect carrying costs of $50 million related to distribution and $2 million related to transmission through September 30, 2009, based on the 11.075% cost of capital approved by the Texas Utility Commission. The carrying costs have been bifurcated into two components: (i) return of borrowing costs and (ii) an allowance for earnings on shareholders’ investment. During the three months and nine months ended September 30, 2009, the component representing a return of borrowing costs of $6 million and $20 million, respectively, has been recognized and is included in other income in CenterPoint Energy’s Condensed Statements of Consolidated Income. That component will continue to be recognized as earned until the associated system restoration costs are recovered. The component representing an allowance for earnings on shareholders’ investment of $32 million is being deferred and will be recognized as it is collected through rates. (b) Recovery of True-Up Balance In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and certain other adjustments. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:
The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request. CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:
In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007. In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true up award. In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision. Oral argument before the court was held in October 2009. Although CenterPoint Energy and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, CenterPoint Energy can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below. To reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in CenterPoint Energy’s consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, CenterPoint Energy anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008. In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. CenterPoint Energy believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT. If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require CenterPoint Energy to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on CenterPoint Energy’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. CenterPoint Energy and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand. The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued. In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on REPs to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008. Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two of the appellants have requested further review from the Texas Supreme Court. In June 2009, the Texas Supreme Court agreed to hear those appeals and oral argument before the court was held in October 2009. The ultimate outcome of this matter cannot be predicted at this time. However, CenterPoint Energy does not expect the disposition of this matter to have a material adverse effect on CenterPoint Energy’s or CenterPoint Houston’s financial condition, results of operations or cash flows. During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented. During the nine months ended September 30, 2008, CenterPoint Houston recognized approximately $5 million in operating income from the CTC. As of September 30, 2009, CenterPoint Energy had not recognized an allowed equity return of $196 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. During the three months ended September 30, 2008 and 2009, CenterPoint Houston recognized approximately $4 million and $5 million, respectively, of the allowed equity return not previously recognized. During the nine months ended September 30, 2008 and 2009, CenterPoint Houston recognized approximately $10 million and $11 million, respectively, of the allowed equity return not previously recognized. (c) Rate Proceedings Texas. In March 2008, the natural gas distribution businesses of CERC (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, Gas Operations implemented rates that are expected to increase annual revenues by approximately $3.5 million. The implemented rates have been contested by 9 cities. CenterPoint Energy and CERC do not expect the outcome of this matter to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC. In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain energy efficiency program costs, an energy efficiency performance bonus for 2008 programs and carrying costs totaling approximately $10 million. The application seeks to begin recovery of these costs through a surcharge effective July 1, 2010. CenterPoint Houston expects an order from the Texas Utility Commission in the fourth quarter of 2009. In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. If approved by the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $25.4 million. The proposed increase would allow Gas Operations to recover increased operating costs, which include higher pension expense. It would also provide a return on the additional capital invested to serve its customers. In addition, Gas Operations is seeking an adjustment mechanism similar to that obtained in the Texas Coast rate proceeding discussed above that would annually adjust rates to reflect changes in capital, expenses and usage. CERC and CenterPoint Energy do not expect an order from the Railroad Commission and the cities until the first quarter of 2010. Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision. In July 2009, the Minnesota Supreme Court issued its decision in which it reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on CenterPoint Energy’s or CERC’s financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed. In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service. If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of $59.8 million. The proposed increase would allow Gas Operations to recover increased operating costs, including higher bad debt and collection expenses, higher pension expenses, the cost of improved customer service and inflationary increases in other expenses. It also would allow recovery of increased costs related to conservation improvement programs and provide a return on the additional capital invested to serve its customers. In addition, Gas Operations is seeking an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. CERC and CenterPoint Energy do not expect an order from the MPUC until early 2010. Mississippi. In July 2009, Gas Operations filed a request to increase its rates for utility distribution service with the Mississippi Public Service Commission (MPSC). If approved by the MPSC, the proposed new rates would result in an overall increase in annual revenue of $6.2 million. The proposed increase would allow Gas Operations to recover increased operating costs, including higher pension and benefit expenses, and provide a return on the additional capital invested to serve its customers. The MPSC is expected to issue an order in mid-November 2009. (d) Regulatory Accounting CenterPoint Energy has a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas pipeline. In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CenterPoint recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the quarters ended March 31, 2009 and September 30, 2009 of $5 million and $11 million, respectively. These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Condensed Statements of Consolidated Income. The related tax benefits of $2 million and $4 million, respectively, are reflected in the income tax expense line of the Condensed Statements of Consolidated Income. |
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| 4 | ENTERGY CORP /DE/ | NOTE 2. RATE AND REGULATORY MATTERS Regulatory Assets See Note 2 to the financial statements in the Form 10-K for information regarding regulatory assets in the Utility business presented on the balance sheets of Entergy and the Registrant Subsidiaries. Following are updates to that discussion. Fuel and purchased power cost recovery See Note 2 to the financial statements in the Form 10-K for information regarding fuel proceedings involving the Utility operating companies. Following are updates to that information. Entergy Arkansas Energy Cost Recovery Rider In March 2009, Entergy Arkansas filed with the APSC its annual energy cost rate for the period April 2009 through March 2010. The filed energy cost rate decreased from $0.02456/kWh to $0.01552/kWh. The decrease was caused by the following: 1) all three of the nuclear power plants from which Entergy Arkansas obtains power, ANO 1 and 2 and Grand Gulf, had refueling outages in 2008, and the previous energy cost rate had been adjusted to account for the replacement power costs that would be incurred while these units were down; 2) Entergy Arkansas has a deferred fuel cost liability from over-recovered fuel costs at December 31, 2008, as compared to a deferred fuel cost asset from under-recovered fuel costs at December 31, 2007; offset by 3) an increase in the fuel and purchased power prices included in the calculation. In August 2009, as provided for by its energy cost recovery rider, Entergy Arkansas filed with the APSC an interim revision to its energy cost rate. The revised energy cost rate is a decrease from $0.01552/kWh to $0.01206/kWh. The decrease was caused by a decrease in natural gas and purchased power prices from the levels used in setting the rate in March 2009. The interim revised energy cost rate went into effect for the first billing cycle of September 2009. In its order approving the new rate, the APSC ordered Entergy Arkansas to show cause why the rate should not be further reduced. In its September 14, 2009 response, Entergy Arkansas explained that it used the same methodology it had used in previous interim revisions, which is based on estimating what the rate would be in the next annual update based on the information known at the time. There has been no further activity in this proceeding. Entergy Mississippi In August 2009 the MPSC retained an independent audit firm to audit Entergy Mississippi's fuel adjustment clause submittals for the period October 2007 through September 2009. The audit report is due to the MPSC by December 15, 2009. Entergy Texas In January 2008, Entergy Texas made a compliance filing with the PUCT describing how its 2007 Rough Production Cost Equalization receipts under the System Agreement were allocated between Entergy Gulf States, Inc.'s Texas and Louisiana jurisdictions. A hearing was held at the end of July 2008, and in October 2008 the ALJ issued a proposal for decision recommending an additional $18.6 million allocation to Texas retail customers. The PUCT adopted the ALJ's proposal for decision in December 2008. Because the PUCT allocation to Texas retail customers is inconsistent with the LPSC allocation to Louisiana retail customers, the PUCT's decision would result in trapped costs between the Texas and Louisiana jurisdictions with no mechanism for recovery. The PUCT denied Entergy Texas' motion for rehearing and Entergy Texas commenced proceedings in both state and federal district courts seeking to reverse the PUCT's decision. On May 12, 2009, certain defendants, in their official capacities as Commissioners of the PUCT, filed a motion to dismiss Entergy Texas' pending complaint before the U.S. District Court for the Western District of Texas. The federal proceeding, including a ruling on the motion to dismiss, has been abated pending further action by the FERC in the proceeding discussed below. 36 Entergy Corporation and Subsidiaries Notes to Financial Statements Entergy Texas also filed with the FERC a proposed amendment to the System Agreement bandwidth formula to specifically calculate the payments to Entergy Gulf States Louisiana and Entergy Texas of Entergy Gulf States, Inc.'s rough production cost equalization receipts for 2007. On May 8, 2009, the FERC issued an order rejecting the proposed amendment, stating, among other things, that the FERC does not have jurisdiction over the allocation of an individual utility's receipts/payments among or between its retail jurisdictions and that this was a matter for the courts to review in the pending proceedings noted above. Because of the FERC's order, Entergy Texas recorded the effects of the PUCT's allocation of the additional $18.6 million to retail customers in the second quarter 2009. On an after-tax basis, the charge to earnings was approximately $13.0 million (including interest). Entergy requested rehearing of the FERC's order, and on July 8, 2009, the FERC granted the request for rehearing for the limited purpose of affording more time for consideration of Entergy's request. In May 2009, Entergy Texas filed with the PUCT a request to refund $46.1 million, including interest, of fuel cost recovery over-collections through February 2009. Entergy Texas requested that the proposed refund be made over a four-month period beginning June 2009. Pursuant to a stipulation among the various parties, in June 2009 the PUCT issued an order approving a refund of $59.2 million, including interest, of fuel cost recovery overcollections through March 2009. The refund was made over a three-month period beginning July 2009. In September 2009, Entergy Texas filed with the PUCT a request for a good cause exception to implement a power cost recovery factor to collect approximately $26 million annually associated with a new purchased power contract with Entergy Arkansas that takes effect January 1, 2010. Entergy Texas proposes that the power cost recovery factor be approved beginning January 2010 and remain in place until the contract expires or new rates that include the cost of the contract are set after a general rate case, whichever is earlier. This matter is pending before the PUCT, and a procedural schedule has not been set. The ALJ suspended the effective date of the factor until March 22, 2010. In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Entergy Texas requested that the proposed refund be made over a six-month period beginning January 2010. The matter is pending before the PUCT, and a procedural schedule has not been set. Storm Cost Recovery Filings Entergy Arkansas Storm Reserve Accounting The APSC's June 2007 order in Entergy Arkansas' base rate proceeding, which is discussed in the Form 10-K, eliminated storm reserve accounting for Entergy Arkansas. In March 2009 a law was enacted in Arkansas that requires the APSC to permit storm reserve accounting for utilities that request it. Entergy Arkansas filed its request with the APSC, and has reinstated storm reserve accounting effective January 1, 2009. Entergy Arkansas January 2009 Ice Storm In January 2009 a severe ice storm caused significant damage to Entergy Arkansas' transmission and distribution lines, equipment, poles, and other facilities. The current cost estimate for the damage caused by the ice storm is in the lower end of the range of approximately $120 million to $140 million, of which approximately $65 million to $80 million is estimated to be operating and maintenance type costs and the remainder is estimated to be capital investment. On January 30, 2009, the APSC issued an order inviting and encouraging electric public utilities to file specific proposals for the recovery of extraordinary storm restoration expenses associated with the ice storm. On February 16, 2009, Entergy Arkansas filed a request with the APSC for an accounting order authorizing deferral of the operating and maintenance cost portion of Entergy Arkansas' ice storm restoration costs pending their recovery. The APSC issued such an order in March 2009 subject to certain conditions, including that if Entergy Arkansas seeks to recover the deferred costs, those costs will be subject to investigation for whether they are incremental, prudent, and reasonable. Entergy Arkansas is still analyzing its options for the method of recovery of the ice storm restoration costs. One option is securitization, and in April 2009 a law was enacted in Arkansas that authorizes securitization of storm damage restoration costs. Entergy Arkansas' September 2009 general rate filing requests recovery of the 2009 ice storm costs over 10 years if it is expected that securitization would not produce lower costs for customers. 37 Entergy Corporation and Subsidiaries Notes to Financial Statements Entergy Gulf States Louisiana and Entergy Louisiana Hurricane Gustav and Hurricane Ike Filing See the Form 10-K for a discussion of Hurricane Gustav and Hurricane Ike, which caused catastrophic damage to portions of Entergy's service territories in Louisiana in September 2008. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. Entergy Gulf States Louisiana seeks a determination that $152.6 million of storm restoration costs are recoverable and seeks to replenish its storm reserve in the amount of $90 million. Entergy Louisiana seeks a determination that $267.4 million of storm restoration costs are recoverable and seeks to replenish its storm reserve in the amount of $200 million. The storm restoration costs are net of costs that have already been paid from previously funded storm reserves. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana made a supplemental filing to, among other things, recommend recovery of the costs and replenishment of the storm reserves by Louisiana Act 55 (passed in 2007) financing. Entergy Gulf States Louisiana and Entergy Louisiana recovered their costs from Hurricane Katrina and Hurricane Rita primarily by Act 55 financing. The parties have agreed to a procedural schedule that includes March 2010 hearing dates for both the recoverability and the method of recovery proceedings. Entergy Texas Hurricane Ike and Hurricane Gustav Filing See the Form 10-K for a discussion of Hurricane Gustav and Hurricane Ike, which caused catastrophic damage to portions of Entergy's service territory in Texas in September 2008. In April 2009 a law was enacted in Texas that authorizes recovery of these types of costs by securitization. Entergy Texas filed its storm cost recovery case in April 2009 seeking a determination that $577.5 million of Hurricane Ike and Hurricane Gustav restoration costs are recoverable, including estimated costs for work to be completed. On August 5, 2009, Entergy Texas submitted to the ALJ an unopposed settlement agreement intended to resolve all issues in the storm cost recovery case. Under the terms of the agreement $566.4 million, plus carrying costs, are eligible for recovery. Insurance proceeds will be credited as an offset to the securitized amount. Of the $11.1 million difference between Entergy Texas' request and the amount agreed to, which is part of the black box agreement and not directly attributable to any specific individual issues raised, $6.8 million is operation and maintenance expense for which Entergy Texas recorded a charge in the second quarter 2009. The remaining $4.3 million was recorded as utility plant. The PUCT approved the settlement in August 2009, and in September 2009 the PUCT approved recovery of the costs, plus carrying costs, by securitization. See Note 4 to the financial statements for a discussion of the issuance of the securitization bonds. Retail Rate Proceedings See Note 2 to the financial statements in the Form 10-K for information regarding retail rate proceedings involving the Utility operating companies. The following are updates to the Form 10-K. Filings with the APSC Retail Rates See the Form 10-K for a discussion of the rate filing made by Entergy Arkansas and the proceedings regarding that filing. On April 23, 2009, the Arkansas Supreme Court denied Entergy Arkansas' petition for review of the Court of Appeals decision. 38 Entergy Corporation and Subsidiaries Notes to Financial Statements On September 4, 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. Entergy Arkansas requested a $223.2 million base rate increase that would become effective in July 2010. The filing reflects an 11.5% return on equity using a projected capital structure, and proposes a formula rate plan mechanism. Proposed formula rate plan provisions include a +/- 25 basis point bandwidth, with earnings outside the bandwidth reset to the 11.5% return on common equity midpoint and rates changing on a prospective basis depending on whether Entergy Arkansas is over or under-earning. The proposed formula rate plan also includes a recovery mechanism for APSC-approved costs for additional capacity purchases or construction/acquisition of new transmission or generating facilities. The filing also requests recovery of 2009 ice storm costs over 10 years if it is expected that securitization will not produce lower costs for customers. Entergy Arkansas is also seeking an increase in its annual storm damage accrual from $14.4 million to $22.3 million. The APSC scheduled hearings in the proceeding beginning in May 2010. Filings with the LPSC (Entergy Louisiana) See the Form 10-K for a discussion of Entergy Louisiana's formula rate plan filings with the LPSC for the 2007 and 2006 test years. The LPSC staff and intervenors issued their reports on Entergy Louisiana's 2007 test year filing in July 2008 and, with minor exceptions, primarily raised proposed disallowance issues that were previously raised with regard to Entergy Louisiana's 2006 test year filing and remained at issue in that proceeding. The 2006 test year included Entergy Louisiana's request to recover unrecovered fixed costs associated with the loss of customers that resulted from Hurricane Katrina. In October 2009 the LPSC approved a settlement that resolves the 2007 and 2006 test year filings. The settlement provides for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. 10.25% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%). The rate reset, a $20.5 million increase, was implemented for the November 2009 billing cycle, and the rate reset will be subject to refund pending review of the 2008 test year filing that was made on October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlement Entergy Louisiana will refund to its customers $12.9 million, which includes interest, in the November 2009 billing cycle. (Entergy Gulf States Louisiana) See the Form 10-K for a discussion of Entergy Gulf States Louisiana's formula rate plan filing with the LPSC for the 2007 test year. In October 2009 the LPSC approved a settlement that resolves the 2007 test year filing. The settlement provides for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Gulf States Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.65% return on equity for the 2008 test year. 10.6510.65% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). The rate reset, a $36.7 million increase, was implemented for the November 2009 billing cycle, and the rate reset will be subject to refund pending review of the 2008 test year filing that was made on October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Gulf States Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlement Entergy Gulf States Louisiana will refund to its customers $3.7 million, which includes interest, in the November 2009 billing cycle. Retail Rates - Gas (Entergy Gulf States Louisiana) In January 2009, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2008. The filing showed a revenue deficiency of $529 thousand based on a return on common equity mid-point of 10.5%. In April 2009, Entergy Gulf States Louisiana implemented a $255 thousand rate increase pursuant to an uncontested settlement with the LPSC staff. 39 Entergy Corporation and Subsidiaries Notes to Financial Statements Filings with the MPSC On September 18, 2009, Entergy Mississippi filed proposed modifications to its formula rate plan rider. The proposed modifications include: (1) resetting Entergy Mississippi's return on common equity to the middle of the formula rate plan bandwidth each year and eliminating the 50/50 sharing in the current plan, (2) replacing the current rate change limit of two percent of revenues subject to a $14.5 million revenue adjustment cap with a proposed limit of four percent of revenues, (3) implementing a projected test year for the annual filing and subsequent look-back for the prior year, and (4) modifying the performance measurement process. In March 2009, Entergy Mississippi made with the MPSC its annual scheduled formula rate plan filing for the 2008 test year. The filing reported a $27.0 million revenue deficiency and an earned return on common equity of 7.41%. Entergy Mississippi requested a $14.5 million increase in annual electric revenues, which is the maximum increase allowed under the terms of the formula rate plan. The MPSC issued an order on June 30, 2009, finding that Entergy Mississippi's earned return was sufficiently below the lower bandwidth limit set by the formula rate plan to require a $14.5 million increase in annual revenues, effective for bills rendered on or after June 30, 2009. In March 2008, Entergy Mississippi made its annual scheduled formula rate plan filing for the 2007 test year with the MPSC. The filing showed that a $10.1 million increase in annual electric revenues is warranted. In June 2008, Entergy Mississippi reached a settlement with the Mississippi Public Utilities Staff that would result in a $3.8 million rate increase. In January 2009 the MPSC rejected the settlement and left the current rates in effect. Entergy Mississippi appealed the MPSC's decision to the Mississippi Supreme Court. After the decision of the MPSC regarding the formula rate plan filing for the 2008 test year, Entergy Mississippi filed a motion to dismiss its appeal to the Mississippi Supreme Court. Filings with the City Council Retail Rates As discussed in the Form 10-K, on July 31, 2008, Entergy New Orleans filed an electric and gas base rate case with the City Council. On April 2, 2009, the City Council approved a comprehensive settlement. The settlement provides for a net $35.3 million reduction in combined fuel and non-fuel electric revenue requirement, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and complete realignment of Grand Gulf cost recovery from fuel to electric base rates, and a $4.95 million gas rate increase, both effective June 1, 2009. A new three-year formula rate plan was also adopted, with terms including an 11.1% electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans is over- or under-earning. The formula rate plan also includes a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events. The rate case settlement also included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. On September 17, 2009, the City Council approved the programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. The programs are expected to begin in 2010. Fuel Adjustment Clause Litigation See the Form 10-K for a discussion of the lawsuit filed by a group of ratepayers in April 1999 against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers, which currently remains pending, and the corresponding complaint filed with the City Council. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through 40 Entergy Corporation and Subsidiaries Notes to Financial Statements September 2004. In May 2005 the Civil District Court for the Parish of Orleans affirmed the City Council resolution, finding no support for the plaintiffs' claim that the refund amount should be higher. In June 2005, the plaintiffs appealed the Civil District Court decision to the Louisiana Fourth Circuit Court of Appeal. On February 25, 2008, the Fourth Circuit Court of Appeal issued a decision affirming in part, and reversing in part, the Civil District Court's decision. Although the Fourth Circuit Court of Appeal did not reverse any of the substantive findings and conclusions of the City Council or the Civil District Court, the Fourth Circuit found that the amount of the refund was arbitrary and capricious and increased the amount of the refund to $34.3 million. In April 2009 the Louisiana Supreme Court reversed the decision of the Louisiana Fourth Circuit Court of Appeal and reinstated the decision of the Civil District Court. On April 17, 2009, the plaintiffs requested rehearing by the Louisiana Supreme Court. On May 29, 2009, the Louisiana Supreme Court denied the request for rehearing. Filings with the PUCT and Texas Cities (Entergy Texas) Retail Rates As discussed in the Form 10-K, Entergy Texas made a rate filing in September 2007 with the PUCT requesting an annual rate increase totaling $107.5 million, including a base rate increase of $64.3 million and riders totaling $43.2 million. On December 16, 2008, Entergy Texas filed a term sheet that reflected a settlement agreement that included the PUCT Staff and the other active participants in the rate case. On December 19, 2008, the ALJs approved Entergy Texas' request to implement interim rates reflecting the agreement. The agreement includes a $46.7 million base rate increase, among other provisions. Under the ALJs' interim order, Entergy Texas implemented interim rates, subject to refund and surcharge, reflecting the rates established through the settlement. These rates became effective with bills rendered on and after January 28, 2009, for usage on and after December 19, 2008. In addition, the existing recovery mechanism for incremental purchased power capacity costs ceased as of January 28, 2009, with purchased power capacity costs then subsumed within the base rates set in this proceeding. Certain Texas municipalities exercised their original jurisdiction and took final action to approve rates consistent with the interim rates approved by the ALJs. In March 2009, the PUCT approved the settlement, which made the interim rates final, and this PUCT decision is now final and non-appealable. Arkansas Attorney General and AEEC appeals As discussed in the Form 10-K, the Arkansas attorney general and the AEEC appealed a December 2007 APSC order that addressed Entergy Arkansas' production cost allocation, energy cost recovery, and capacity costs riders. Pursuant to a motion of the Arkansas attorney general and the AEEC, in September 2009 the Arkansas Court of Appeals dismissed the appeal. Electric Industry Restructuring in Texas See Note 2 to the financial statements in the Form 10-K for a discussion of electric restructuring activity that involves Entergy Texas. In June 2009, a law was enacted in Texas that requires Entergy Texas to cease all activities relating to Entergy Texas' transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining the Southwest Power Pool. The law provides that any further proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the new law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT's certification of Entergy Texas' power region. In response to the new law, Entergy Texas in June 2009 gave notice to the PUCT of the withdrawal of its transition to competition plan, and requested that its transition to competition proceeding be dismissed. In July 2009 the ALJ dismissed the proceeding. The new law also contains provisions that allow Entergy Texas to be included in a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas. 41 Entergy Corporation and Subsidiaries Notes to Financial Statements The new law further amends already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the new law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall "purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer"; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The new law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. Entergy Texas has thus far not made a filing with the PUCT in response to the newly adopted law addressing the tariff. The new law provides that the PUCT shall approve, reject, or modify the proposed tariff not later than September 1, 2010. |
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| 5 | FirstEnergy Corp. | 10. REGULATORY MATTERS (A) RELIABILITY INITIATIVES In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy's facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards. FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows. In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy's bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. On December 9, 2008, a transformer at JCP&L's Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L's contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC's request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results. On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L's and Penelec's transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy's mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation. (B ) OHIO On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies' application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing. SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies' application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies' collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO's December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per KWH. The power supply obtained through this process provided generation service to the Ohio Companies' retail customers who chose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies' request for a new fuel rider to recover increased costs resulting from the CBP but denied OE's and TE's request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery. On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009. On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers. The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs. SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance will be recoverable from customers. On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised. On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a "to be re-filed" status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission's failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission's recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011. On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP (C) PENNSYLVANIA Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various interveners filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed's TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed's and Penelec's TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The Companies are now awaiting a PPUC decision. On May 28, 2009, the PPUC approved Met-Ed's and Penelec's annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC's January 2007 rate order. For Penelec's customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed's customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed's proposal to continue to recover the prior period deferrals allowed in the PPUC's May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed's customers would increase approximately 9.4% for the period June 2009 through May 2010. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Major provisions of the legislation include: o power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases; o the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; o utilities must provide for the installation of smart meter technology within 15 years; o utilities must reduce peak demand by a minimum of 4.5% by May 31, 2013; o utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and o the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities. Act 129 requires utilities to file with the PPUC, an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities' energy efficiency and peak load reduction plans. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC's June 23, 2009 Order. Following an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved, in part, and rejected, in part, the Pennsylvania Companies' filing. The Companies must file revised EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies. Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year. Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain. On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies' plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec anticipate PPUC approval of their plan in November 2009. On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012. On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies' Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec's compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether "the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists." In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies filed reply comments on October 26, 2009, and await the decision of the PPUC. (D) NEW JERSEY JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2009, the accumulated deferred cost balance totaled approximately $102 million. In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU. New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor's Office and the Governor's Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals: o maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; o reduce peak demand for electricity by 5,700 MW by 2020; o meet 30% of the state's electricity needs with renewable energy by 2020; o examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state's greenhouse gas targets; and o invest in innovative clean energy technologies and businesses to stimulate the industry's growth in New Jersey. On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. Such utility specific plans are due to be filed with the BPU by July 1, 2010. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations. In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the BPU on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal. (E) FERC MATTERS Transmission Service between MISO and PJM On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC's intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, FirstEnergy and Exelon filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case. PJM Transmission Rate On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order ("Opinion 494") finding that the PJM transmission owners' existing "license plate" or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a "beneficiary pays" basis. The FERC found that PJM's current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM's tariff. On May 18, 2007, certain parties filed for rehearing of the FERC's April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC's April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral arguments were held on April 13, 2009. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied AEP's appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion Electric Cooperative was denied by the Seventh Circuit on October 20, 2009. On October 28, 2009, the Seventh Circuit closed its case dockets and returned the case to FERC for further action on the remand order. The FERC's orders on PJM rate design prevented the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC's decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the "beneficiary pays" methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC's Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM's Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008. Post Transition Period Rate Design The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC's approval, the rates charged to FirstEnergy's load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be retained. On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM "Super Region" that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC's January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Opinion 494 appeal discussed above. Now that the Seventh Circuit has ruled on the Opinion 494 case, AEP and FERC have until November 11, 2009, to advise the Seventh Circuit of any changes to their litigation positions that result from or reflect the Seventh Circuit's decision in the Opinion 494 case. RTO Consolidation On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy's transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy's transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy's integration into PJM. FirstEnergy has requested that FERC rule on its application and the related complaint by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies. On September 4, 2009, the PUCO opened a case to take comments from Ohio's stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation. Changes ordered for PJM Reliability Pricing Model (RPM) Auction On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers' complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM's proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply. On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order. PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes were approved by the FERC in an order issued on October 30, 2009, and are effective November 1, 2009. The CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009. MISO Resource Adequacy Proposal MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn and FES. This requirement was proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO's Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC's March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO's compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO's Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO's proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC's April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO's compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO's and Independent Market Monitor's proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation. FES Sales to Affiliates FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies' power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies' power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC. On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly's energy requirements in 2010. Under the new agreement, Met-Ed, Penelec, and Waverly (Buyers) assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers' power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010. | |||||||||||||||||||||||
| 6 | KINDER MORGAN ENERGY PARTNERS L P | 11. Regulatory Matters The following updates the disclosure in Note 17 to our audited financial statements that were filed with our 2008 Form 10-K, with respect to developments that occurred during the nine months ended September 30, 2009. Order on Rehearing and Clarification - Standards of Conduct for Transmission Providers – Docket No. RM07-1-001 On October 15, 2009, the FERC issued Order No. 717-A, an order on rehearing and clarification regarding FERC’s Affiliate Rule - Standards of Conduct. The FERC clarified a lengthy list of issues relating to: the applicability, the definition of transmission function and transmission function employees, the definition of marketing function and marketing function employees, the definition of transmission function information, independent functioning, transparency, training, and North American Energy Standards Board business practice standards. The FERC generally reaffirmed its determinations in Order No. 717, but granted rehearing on and clarified certain provisions. Order No. 717-A aims to make the Standards of Conduct clearer and to refocus the rules on the areas where there is the greatest potential for abuse. The Order addresses requests for rehearing and clarification of the following issues: (i) applicability of the Standards of Conduct to transmission owners with no marketing affiliate transactions; (ii) whether the Independent Functioning Rule applies to balancing authority employees; (iii) which activities of transmission function employees or marketing function employees are subject to the Independent Functioning Rule; (iv) whether local distribution companies making off-system sales on nonaffiliated pipelines are subject to the Standards of Conduct; (v) whether the Standards of Conduct apply to a pipeline’s sale of its own production; (vi) applicability of the Standards of Conduct to asset management agreements; (vii) whether incidental purchases to remain in balance or sales of unneeded gas supply subject the company to the Standards of Conduct; (viii) applicability of the No Conduit Rule to certain situations; and (ix) applicability of the Transparency Rule to certain situations. The rehearing and clarification granted are not anticipated to have a material impact on the operation of our interstate pipelines. Notice of Proposed Rulemaking – Natural Gas Price Transparency- Docket No. RM08-2-000 On November 20, 2008, the FERC issued Order 720 establishing new reporting requirements for interstate and major non-interstate natural gas pipelines. Interstate pipelines are required to post no-notice activity at each receipt and delivery point three days after the day of gas flow. Major non-interstate pipelines are required to daily post design capacity, scheduled volumes and available capacity at each receipt or delivery point with a design capacity of 15,000 MMBtus of natural gas per day or greater. The final rule became effective January 27, 2009 for interstate pipelines. On January 15, 2009, the FERC issued an order granting an extension of time for major non-interstate pipelines to comply until 150 days following the issuance of an order addressing the pending requests for rehearing. On January 16, 2009, the FERC granted rehearing of Order 720. On July 16, 2009, the FERC issued a request for supplemental comments on revisions to the posting requirements. Our intrastate pipeline group filed comments on August 31, 2009. We do not expect this Order to have a material impact on our consolidated financial statements. Notice of Proposed Rulemaking - Contract Reporting Requirements of Intrastate Natural Gas Companies, Docket No. RM09-2-000. On July 16, 2009, the FERC issued a Notice of Proposed Rulemaking proposing revisions to the existing transactional reporting requirements for intrastate and Hinshaw pipelines performing services in interstate commerce. The proposed revisions would require filings to be filed on a quarterly basis and to include more information than previously required. Comments are due on November 2, 2009. Natural Gas Pipeline Expansion Filings Rockies Express Meeker to Cheyenne Expansion Project Pursuant to certain rights exercised by EnCana Gas Marketing USA as a result of its foundation shipper status on the former Entrega Gas Pipeline LLC facilities (now part of the Rockies Express Pipeline), Rockies Express Pipeline LLC requested authorization to construct and operate certain facilities that will comprise its Meeker, Colorado to Cheyenne Hub Rockies Express Pipeline expansion project. The proposed expansion will add natural gas compression at its Big Hole compressor station located in Moffat County, Colorado, and its Arlington compressor station located in Carbon County, Wyoming. Upon completion, the additional compression will permit the transportation of an additional 200 million cubic feet per day of natural gas from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion is fully contracted and is expected to be operational in the second quarter of 2010. The total FERC authorized cost for the proposed project is approximately $78 million; however, Rockies Express is currently projecting that the final actual cost will be less. By FERC order issued July 16, 2009, Rockies Express was granted authorization to construct and operate this project. Construction on this project commenced August 4, 2009. Rockies Express Pipeline-East Project Construction continued during the third quarter of 2009 on the previously announced Rockies Express Pipeline-East Pipeline project. The Rockies Express-East project includes the construction of an additional natural gas pipeline segment, comprising approximately 639 miles of 42-inch diameter pipeline commencing from the terminus of the Rockies Express-West pipeline to a terminus near the town of Clarington in Monroe County, Ohio. Current market conditions for consumables, labor and construction equipment along with certain provisions in the final regulatory orders have resulted in increased costs for the project and have impacted certain projected completion dates. Including expansions, our current estimate of total construction costs on the entire Rockies Express Pipeline is between $6.7 billion and $6.8 billion (consistent with our October 21, 2009 third quarter earnings press release). On June 29, 2009, Rockies Express-East commenced service on the portion of the pipeline from Audrain County, Missouri to the Lebanon Hub in Warren County, Ohio. Currently, this section of the line provides capacity of approximately 1.8 billion cubic feet per day of natural gas, and includes interconnects to Natural Gas Pipeline Company of America LLC, Ameren, Trunkline, Midwestern Gas Transmission, Panhandle Eastern, Texas Eastern, Dominion Transmission and Columbia Gas, with future interconnects to Texas Gas Transmission, ANR, Citizens and Vectren. The remainder of Rockies Express-East, consisting of approximately 195 miles of 42-inch diameter pipe extending to Clarington, Ohio, is expected to be in service in November 2009 provided the horizontal directional drill across Deer Creek is successfully completed. When completed, the entire 1,679-mile Rockies Express Pipeline will have a capacity of approximately 1.8 billion cubic feet per day of natural gas, virtually all of which has been contracted under long-term firm commitments from creditworthy shippers. Kinder Morgan Interstate Gas Transmission Pipeline - Huntsman 2009 Expansion Project Kinder Morgan Interstate Gas Transmission LLC, referred to as KMIGT, has filed an application with the FERC for authorization to construct and operate certain storage facilities necessary to increase the storage capability of the existing Huntsman Storage Facility, located near Sidney, Nebraska. KMIGT also requested approval of new incremental rates for the project facilities under its currently effective Cheyenne Market Center Service Rate Schedule CMC-2. When fully constructed, the proposed facilities will create incremental firm storage capacity for up to one million dekatherms of natural gas, with an associated injection capability of approximately 6,400 dekatherms per day and an associated deliverability of approximately 10,400 dekatherms per day. As a result of an open season, KMIGT and one shipper executed a firm precedent agreement for 100% of the capacity to be created by the project facilities for a five-year term. By FERC order issued September 30, 2009, KMIGT was granted authorization to construct and operate the project. Construction of the project commenced on October 12, 2009. Kinder Morgan Louisiana Pipeline LLC (KMLP) – Docket No. CP06-449-000 On April 16, 2009, KMLP received authorization from the FERC to begin service on Leg 2 of the approximately 133-mile, 42-inch diameter pipeline, and service on Leg 2 commenced April 18, 2009. On June 21, 2009, KMLP completed pipeline construction and placed the remaining portion of the pipeline system into service. The Kinder Morgan Louisiana Pipeline project cost approximately $1 billion to complete (consistent with our July 15, 2009 second quarter earnings press release). The Kinder Morgan Louisiana Pipeline provides approximately 3.2 billion cubic feet per day of take-away natural gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal, located in Cameron Parish, Louisiana, to various delivery points in Louisiana. The pipeline interconnects with multiple third-party pipelines and all of the capacity on the pipeline system has been fully subscribed by Chevron and Total under 20-year firm transportation contracts. Total’s contract became effective on June 21, 2009, and Chevron’s contract became effective on October 1, 2009. Midcontinent Express Pipeline LLC – Docket Nos. CP08-6-000 and CP09-56-000 On April 10, 2009, Midcontinent Express placed Zone 1 of the Midcontinent Express natural gas pipeline system into interim service. Zone 1 extends from Bennington, Oklahoma to the interconnect with Columbia Gulf Transmission Company in Madison Parish, Louisiana. It has a design capacity of approximately 1.5 billion cubic feet per day. On August 1, 2009, construction of the pipeline was completed, and Zone 2 was placed into service. Zone 2 extends from the Columbia Gulf interconnect to the terminus of the system in Choctaw County, Alabama. It has a design capacity of approximately 1.2 billion cubic feet per day. In an order issued September 17, 2009, the FERC approved Midcontinent Express’ (i) amendment to move one compressor station in Mississippi and modify the facilities at another station in Texas (both stations were among the facilities certificated in the July 2008 Order authorizing the system’s construction); and (ii) application to expand the capacity in Zone 1 by 0.3 billion cubic feet per day (this expansion is expected to be completed in December 2010). The Midcontinent Express Pipeline is owned by Midcontinent Express Pipeline LLC, a 50/50 joint venture between us and Energy Transfer Partners, L.P. The pipeline originates near Bennington, Oklahoma and extends from southeast Oklahoma, across northeast Texas, northern Louisiana and central Mississippi, and terminates at an interconnection with the Transco Pipeline near Butler, Alabama. The approximate 500-mile natural gas pipeline system connects the Barnett Shale, Bossier Sands and other natural gas producing regions to markets in the eastern United States, and substantially all of the pipeline’s capacity is fully subscribed with long-term binding commitments from creditworthy shippers. The entire Midcontinent Express project cost approximately $2.3 billion to complete (consistent with our October 21, 2009 third quarter earnings press release). Fayetteville Express Pipeline LLC – Docket No.CP09-433-000 Pipeline system development work continued during the third quarter of 2009 on the previously announced Fayetteville Express Pipeline project. The Fayetteville Express Pipeline is owned by Fayetteville Express Pipeline LLC, another 50/50 joint venture between us and Energy Transfer Partners, L.P. The Fayetteville Express Pipeline is a 187-mile, 42-inch diameter natural gas pipeline that will begin in Conway County, Arkansas, and end in Panola County, Mississippi. The pipeline will have an initial capacity of two billion cubic feet per day, and has currently secured binding commitments for at least ten years totaling 1.85 billion cubic feet per day of capacity. On June 15, 2009, Fayetteville Express filed its certificate application with the FERC. On October 15, 2009, the FERC issued its Environmental Assessment finding that, subject to compliance with certain conditions, the environmental impact of Fayetteville Express could be adequately mitigated. Pending regulatory approvals, the pipeline is expected to be in service by late 2010 or early 2011. Our estimate of the total costs of this pipeline project is approximately $1.2 billion (consistent with our October 21, 2009 third quarter earnings press release). |
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| 7 | MDU RESOURCES GROUP INC | 18. Regulatory matters and revenues subject to refund
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| 8 | PROGRESS ENERGY INC |
FUEL COST RECOVERY On May 7, 2009, PEC filed with the SCPSC for a decrease in the fuel rate charged to its South Carolina ratepayers. On May 28, 2009, PEC jointly filed a settlement agreement with the South Carolina Office of Regulatory Staff (ORS) and Nucor Steel. Under the terms of the settlement agreement, the parties agreed to PEC’s proposed rate reduction of approximately $13 million. On June 19, 2009, the SCPSC approved the settlement agreement. The decrease was effective July 1, 2009, and decreased residential electric bills by $2.08 per 1,000 kilowatt-hours (kWh), or 2.0 percent, for fuel cost recovery. On June 4, 2009, PEC filed with the NCUC for a decrease in the fuel rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $14 million decrease in the fuel rates driven by declining fuel prices. If approved, the decrease would take effect December 1, 2009, and would decrease residential electric bills by $0.45 per 1,000 kWh, or 0.4 percent, for fuel cost recovery. A hearing on the matter was held on September 15, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter. DEMAND-SIDE MANAGEMENT AND ENERGY-EFFICIENCY COST RECOVERY See Note 7B in the 2008 Form 10-K for discussion of North Carolina’s comprehensive energy legislation, which became law on August 20, 2007. As a result of the legislation, PEC has implemented a series of demand-side management (DSM) and energy-efficiency programs and will continue to pursue additional programs. These programs must be approved by the NCUC, and we cannot predict the outcome of the DSM and energy-efficiency filings currently pending approval by the NCUC or whether the implemented programs will produce the expected operational and economic results. 24 On June 6, 2008, and as subsequently amended, PEC filed an application with the NCUC for approval of a DSM and energy-efficiency rider to recover all program costs, including the recovery of appropriate incentives for investing in such programs. On November 14, 2008, the NCUC issued an order allowing PEC to implement the rates requested in PEC’s November 14, 2008 revision to its initial application. The new rates, subject to true-up to the final order, were implemented on December 1, 2008, increasing residential electrical bills by $0.74 per 1,000 kWh, or 0.8 percent. On December 9, 2008, the North Carolina Public Staff filed an Agreement and Stipulation of Partial Settlement with PEC and some of the other parties to the proceedings. The NCUC held a hearing on the matter on January 7, 2009. On June 15, 2009, the NCUC issued an order approving the Agreement and Stipulation of Partial Settlement, subject to certain modifications. PEC estimates the year-to-date impact of these modifications to be immaterial. On July 13, 2009, PEC filed a motion asking the NCUC to reconsider certain provisions of the June 15, 2009 order and stay the requirements for PEC to revise its cost-recovery filings in accordance with the decisions approved in the order. On July 20, 2009, the NCUC issued an order requesting comments on the motion and allowed the motion for stay, pending a ruling on the motion for reconsideration, on a portion of PEC’s request. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter. On June 4, 2009, PEC filed with the NCUC for an adjustment in the DSM and energy-efficiency rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $1 million increase in the DSM and energy-efficiency rates. However, because of changes in how the costs are allocated among customer classes, the request results in a decrease to the residential rate, while increasing rates for other customer classes. If approved, the rate changes would take effect December 1, 2009, and would decrease residential electric bills by $0.18 per 1,000 kWh, or 0.2 percent, for DSM and energy-efficiency cost recovery. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter. On June 27, 2008, PEC filed an application with the SCPSC to establish procedures that encourage investment in cost-effective energy-efficient technologies and energy conservation programs and approve the establishment of an annual rider to allow recovery for all costs associated with such programs, as well as the recovery of appropriate incentives for investing in such programs. On January 23, 2009, PEC filed a Stipulation Agreement between PEC and some of the other parties to the proceeding. On May 6, 2009, the SCPSC approved the Stipulation Agreement and issued a directive requiring PEC to file for approval of all proposed DSM and energy-efficiency programs. On May 11, 2009, in accordance with the SCPSC directive, PEC filed its programs for approval and an application for a cost-recovery rider for PEC’s DSM and energy-efficiency programs. On June 10, 2009, SCPSC approved the proposed DSM and energy-efficiency programs and the cost-recovery rider application, on a provisional basis pending a review of the cost-recovery rider by the ORS. The rate increase was effective July 1, 2009, and increased residential electric bills by $0.79 per 1,000 kWh, or 0.8 percent, for DSM and energy-efficiency cost recovery. We cannot predict the outcome of this matter. RENEWABLE ENERGY AND ENERGY EFFICIENCY PORTFOLIO STANDARD COST RECOVERY On June 4, 2009, PEC filed with the NCUC for an increase in the Renewable Energy and Energy Efficiency Portfolio standard (NC REPS) rate charged to its North Carolina ratepayers. The filing was updated on August 17, 2009. PEC is asking the NCUC to approve a $7 million increase in the NC REPS rates. If approved, the increase would take effect December 1, 2009, and would increase residential electric bills by $0.29 per month, or 0.3 percent, for REPS cost recovery. A hearing on the matter was held on September 16, 2009, and an order is expected in November 2009. We cannot predict the outcome of this matter. OTHER MATTERS North Carolina enacted a law in July 2009 that abbreviates the certification process for a public utility to construct a new natural gas plant as long as the public utility permanently retires the existing coal units at that specific site. On August 18, 2009, PEC filed with the NCUC an application for a certificate of public convenience and necessity to construct a 950-MW combined cycle natural gas-fueled electric generating facility at a site in Wayne County, N.C. PEC projects that the generating facility would be in service by January 2013. PEC proposed that upon completion of the generating facility, it will permanently cease operation of the three coal-fired generating units, with a combined generating capacity of approximately 400 MW, that are currently in operation at the site. This will result in approximately 550 MW of incremental capacity. On September 21, 2009, the Public Staff recommended that the NCUC issue the certificate subject to additional conditions as follows: the facility be constructed and operated in 25 accordance with all applicable laws and regulations, PEC file with the NCUC a progress report and any revisions in the cost estimates on an annual basis, PEC permanently cease operation of the three coal-fired units immediately upon completion and placement into service of the facility and that the NCUC clarify that the issuance of the certificate does not constitute approval of the final costs associated with construction of the facility. On October 1, 2009, the NCUC issued a notice of decision stating it found good cause to issue an order granting PEC the certificate of public convenience and necessity subject to the four conditions proposed by the Public Staff as well as adding a condition that PEC submit for NCUC approval a plan to retire additional coal-fired capacity reasonably proportionate to the 550 MW of incremental capacity. On October 22, 2009, the NCUC issued its order granting PEC a certificate of public convenience and necessity to construct the 950-MW facility. PEC is currently evaluating its options concerning the additional retirements.
BASE RATE FILING As a result of a base rate proceeding in 2005, PEF is party to a base rate settlement agreement that was effective with the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009. On March 20, 2009, in anticipation of the expiration of its current base rate settlement agreement, PEF filed with the FPSC a proposal for an increase in base rates effective January 1, 2010. In its filing, PEF requested the FPSC to approve calendar year 2010 as the projected test period for setting new base rates and approve annual rate relief for PEF of $499 million, which includes PEF’s petition for a combined $76 million of new base rates in 2009 as discussed below. The request for increased base rates is based, in part, on investments PEF is making in its generating fleet and in its transmission and distribution systems. Included within the base rate proposal is a request for an interim base rate increase of $13 million. Additionally, on March 20, 2009, PEF petitioned the FPSC for a limited proceeding to include in base rates revenue requirements of $63 million for the repowered Bartow Plant, which began commercial operations in June 2009. On May 19, 2009, the FPSC approved both the annualized interim base rate increase and the cost recovery for the repowered Bartow Plant subject to refund with interest effective July 1, 2009. The interim and limited base rate relief increased revenues by $47 million during the nine months ended September 30, 2009, and are expected to result in total increases to revenues of approximately $70 million for 2009. The changes increased residential bills by approximately $4.52 per 1,000 kWh, or 3.7 percent. On July 2, 2009, Florida’s Office of Public Counsel (OPC), the Florida Industrial Power Users Group, the Attorney General, the Florida Retail Federation and PCS Phosphate filed a petition protesting portions of the FPSC approval. On August 31, 2009, the FPSC issued an order to consolidate the interim and limited base rate relief increase and the base rate proposal. We cannot predict the outcome of this matter. If PEF’s remaining rate request is approved by the FPSC as filed by PEF, the new base rates would increase residential bills by approximately $9.66 per 1,000 kWh, or 7.6 percent, effective January 1, 2010. A hearing was held on this matter September 21, 2009 – October 1, 2009. On October 27, 2009, the FPSC held a hearing to determine if the voting of pending rate cases should be delayed until new FPSC appointees take office in January 2010. During the hearing, the FPSC voted to delay the rulings on the appropriate level of revenue requirements until January 11, 2010, and on the appropriate customer rates until January 28, 2010. In response to this delay and in lieu of implementing PEF's proposed base rates subject to refund, PEF filed a motion with the FPSC on November 2, 2009, to establish a regulatory asset (or liability) for the incremental rate relief not recovered between January 1, 2010, and when new rates become effective, expected to be March 1, 2010. If PEF's petition is approved, the regulatory asset (or liability) would be recovered, plus interest at the commercial paper rate, through a rate adjustment commencing March 1, 2010, through the remainder of the calendar year. We cannot predict the outcome of this matter. FUEL COST RECOVERY On March 17, 2009, PEF received approval from the FPSC to reduce its 2009 fuel cost-recovery factors by an amount sufficient to achieve a $206 million reduction in fuel charges to retail customers as a result of effective fuel purchasing strategies and lower fuel prices. The approval reduced residential customers’ fuel charges by $6.90 per 1,000 kWh, or 5.0 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers. 26 See Note 7C in the 2008 Form 10-K for discussion of the OPC petition filed with the FPSC in 2006 requesting PEF to refund to ratepayers $135 million, plus interest, related to fuel recovery charges during the period 2003 to 2005 for Crystal River Unit 4 and Crystal River Unit 5 (CR4 and CR5). On October 10, 2007, in response to the OPC petition, the FPSC ordered PEF to refund its ratepayers $14 million for disallowed fuel and sulfur dioxide (SO2) costs, inclusive of interest, over a 12-month period beginning January 1, 2008. In addition, the FPSC also ordered PEF to address whether it was prudent in its 2006 and 2007 coal purchases for CR4 and CR5. On February 2, 2009, the OPC filed direct testimony alleging that during 2006 and 2007, PEF collected excessive fuel costs and SO2 allowance costs of $61 million before interest. During the hearing on the matter, the OPC reduced the alleged excessive fuel costs to $33 million before interest. On June 30, 2009, the FPSC approved a refund of $8 million to PEF’s ratepayers to be paid over a 12-month period beginning January 1, 2010, and ordered PEF to file a report by September 2009 regarding the prospective application of PEF’s coal procurement plan and the prudence of PEF’s coal procurement actions. In compliance with the FPSC order, PEF filed the coal procurement status report on September 14, 2009. For the nine months ended September 30, 2009, PEF recorded a pre-tax other operating expense of $8 million plus an immaterial amount of interest and an associated regulatory liability for the disallowed fuel costs and interest. PEF chose not to appeal the FPSC’s order. On September 14, 2009, PEF filed a request with the FPSC to seek approval of a cost adjustment to reduce fuel costs, thereby decreasing residential electric bills by $3.34 per 1,000 kWh, or 2.6 percent, effective January 1, 2010. This decrease is due to a decrease of $9.89 per 1,000 kWh for the projected recovery of fuel costs, partially offset by an increase of $6.55 per 1,000 kWh for the projected recovery through the capacity cost-recovery clause (CCRC). The decrease in projected fuel costs is due primarily to a decrease in the price of natural gas and a change in the expected average fuel costs. An extended biennial nuclear outage at Crystal River Unit No. 3 Nuclear Plant (CR3) for an uprate project in 2009 contributed to higher projected fuel costs for 2009; however, anticipated changes in the generation mix for 2010 are expected to result in lower average fuel costs and contributed to the projected decrease in 2010 fuel costs. The increase in the CCRC is primarily the result of projected costs to be incurred in 2010 under the nuclear cost-recovery rule discussed below for the proposed nuclear plant in Levy County, Fla. (Levy) and an under-recovery of purchased power costs in 2009. On October 23, 2009, as a result of the October 16, 2009 FPSC vote in the nuclear cost recovery matter discussed more fully below, PEF filed a cost adjustment with the FPSC which reduced the CCRC rate by $0.08 per 1,000 kWh from the original September 14, 2009 cost-adjustment filing. The FPSC approved PEF's fuel and capacity clause filings on November 2, 2009. On August 28, 2009, PEF filed a request to increase the Environmental Cost Recovery Clause (ECRC) residential rate and the filing was updated on October 27, 2009. PEF is asking the FPSC to increase residential rates by $2.25 per 1,000 kWh, or 1.8 percent. This increase is primarily due to the return on assets expected to be placed in service at the end of 2009. On September 14, 2009, PEF filed a request to increase the Energy Conservation Cost Recovery Clause (ECCR) residential rate by $0.47 per 1,000 kWh, or 0.4 percent. This increase is due mainly to an increase in conservation program costs. If approved, the ECRC and ECCR changes would be effective January 1, 2010. The FPSC approved PEF’s ECRC and ECCR clause filings on November 2, 2009. NUCLEAR COST RECOVERY On March 17, 2009, PEF received approval from the FPSC to defer until 2010 the recovery of $198 million of nuclear pre-construction costs for Levy, which the FPSC had authorized to be collected in 2009. The approval reduced residential customers’ nuclear cost-recovery charge by $7.80 per 1,000 kWh, or 5.7 percent, starting with the first billing cycle of April 2009, with similar reductions for commercial and industrial customers. On May 1, 2009, pursuant to the FPSC nuclear cost-recovery rule, PEF filed a petition to recover $446 million through the CCRC, which primarily consists of pre-construction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy and CR3 uprate projects. In an effort to help mitigate the initial price impact on its customers, as part of its filing, PEF proposed collecting certain costs over a five-year period, with associated carrying costs on the unrecovered balance. This alternate proposal reduced the 2010 revenue requirement to $236 million. On September 14, 2009, consistent with FPSC rules, PEF included both proposed revenue requirements in its CCRC filing, which would result in a nuclear cost-recovery charge of either $7.98 per 1,000 kWh for residential customers under PEF’s alternate proposal, or $15.07 per 1,000 kWh if the FPSC did not approve PEF’s alternate proposal. At a special agenda hearing by the FPSC on October 16, 2009, the FPSC approved the alternate proposal allowing PEF to recover $207 million of revenue requirements associated with the nuclear cost-recovery clause through the CCRC beginning with the first billing cycle of January 2010. The remainder, with minor adjustments, will also be recovered through the CCRC. This revenue level results in a nuclear 27 cost-recovery charge of $6.99 per 1,000 kWh, which represents a $2.68 increase per 1,000 kWh for residential customer bills. In adopting PEF’s proposed rate plan for 2010, the FPSC permitted PEF to annually reconsider changes to the recovery of deferred amounts to afford greater flexibility to manage future rate impacts. On October 16, 2009, the FPSC clarified certain implemenation policies related to the recognition of deferrals and the application of carrying charges under the nuclear cost-recovery rule. Specifically, the FPSC clarified that (1) nuclear costs are deemed to be recovered up to the amount of FPSC-approved projections and (2) the deferral of unrecovered nuclear costs would accrue a carrying charge at PEF’s approved allowance for funds used during construction (AFUDC) rate consistent with the requirements of FPSC’s nuclear cost-recovery rule, which is fixed at the pre-tax AFUDC rate in effect as of June 12, 2007. Accordingly, PEF retrospectively assigned capacity revenues to match the FPSC-approved projected level of nuclear cost recovery as of September 30, 2009. Nuclear costs incurred in excess of original projections earn a carrying charge equal to the AFUDC rate. Prior to the FPSC clarification, PEF assigned capacity revenues to nuclear cost recovery based on actual costs incurred; any over- or under-recoveries of actual costs were deferred and earned a carrying charge equal to a commercial paper rate. See Note 7C in the 2008 Form 10-K for discussion of PEF’s filing with the FPSC for Determination of Need to uprate CR3 and bid rule exemption, and for recovery of the revenue requirements of the uprate. On August 28, 2009, PEF filed a petition with the FPSC to approve a $17 million base rate increase for the phase II costs associated with the uprate of CR3. PEF’s 2009 revenue requirements for recovery of the phase II costs were included in the CCRC. As permitted under the nuclear cost-recovery rule, PEF’s phase III costs associated with the CR3 uprate are currently being recovered through the CCRC discussed above. On October 29, 2009, the FPSC Staff recommended that the FPSC approve PEF's request with minor modifications and that the new rates be implemented at the same time as PEF implements new base rates from its rate case proceeding. On October 30, 2009, PEF filed an amended petition requesting this rate change be implemented effective January 1, 2010. If approved, the base rates for residential customers will increase by $0.57 per 1,000 kWh, or 0.4 percent. A decision by the FPSC is expected on December 1, 2009. We cannot predict the outcome of this matter. OTHER MATTERS On March 20, 2009, PEF filed a petition with the FPSC for expedited approval of the deferral of $53 million in 2009 pension expense and the authorization to charge $33 million in estimated 2009 storm hardening expenses to its storm damage reserve. PEF requested that the deferral of pension expense continue until the recovery of these costs is provided for in FPSC-approved base rates. On June 16, 2009, the FPSC denied PEF’s request related to the storm hardening expenses, but approved the deferral of the retail portion of actual 2009 pension expense. As a result of the order, PEF deferred pension expense of $10 million and $26 million for the three months and nine months ended September 30, 2009, respectively. PEF will not earn a carrying charge on the deferred pension regulatory asset. The retail portion of subsequent pension expense will be deferred as incurred during the remainder of 2009. The deferral of pension expense will not result in a change in PEF’s 2009 retail rates or prices. In accordance with the order, subsequent to 2009 PEF will amortize the deferred pension regulatory asset to the extent that annual pension expense is less than the allowance provided for in the base rates established in the 2010 base rate proceeding. In the event such amortization is insufficient to fully amortize the regulatory asset, PEF can seek recovery of the remaining unamortized amount in a base rate proceeding no earlier than 2015.
On May 15, 2009 and May 29, 2009, PEC and PEF filed updates to their Open Access Transmission Tariffs (OATT) with the FERC. For PEC, the updates increased the transmission rate charged to wholesale customers by 18 percent effective June 1, 2009, and by an additional 1 percent effective August 1, 2009. The impact to PEC’s 2009 revenue is expected to be an increase of $4 million. For PEF, the updates increased the transmission rate charged to wholesale customers by 11 percent, effective June 1. The impact to PEF’s 2009 revenue is expected to be an increase of $2 million. On October 9, 2009, PEC and PEF reached settlement agreements with their respective wholesale customers regarding these rate increases. Both settlement agreements resulted in a small decrease to the filed rates, but have no material impact on the expected increase to 2009 revenue. |
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| 10 | Sempra Energy | NOTE 9. SEMPRA UTILITIES' REGULATORY MATTERS POWER PROCUREMENT AND RESOURCE PLANNING Sunrise Powerlink Electric Transmission Line Renewable Energy
As previously noted, SDG&E expects the Sunrise Powerlink transmission line to be in operation in 2012. This would be too late to provide transmission capability to meet the RPS Program requirements for 2010 and 2011. However, SDG&E believes it will be able to comply with the RPS Program requirements based on its contracting activity and application of the flexible compliance mechanisms. SDG&E's failure to comply with the RPS Program requirements in 2010, or in any subsequent years, could subject it to CPUC-imposed penalties of 5 cents per kilowatt hour of renewable energy under-delivery up to a maximum penalty of $25 million per year. Miramar II Peaking Plant Solar Photovoltaic Program General Rate Case (GRC) In November 2009, SDG&E and SoCalGas, jointly with the Division of Ratepayer Advocates (DRA), a division of the CPUC representing the interests of customers, filed petitions with the CPUC to delay the filing of SDG&E's and SoCalGas' next GRC applications by one year. If approved by the CPUC, both SDG&E and SoCalGas would file their next GRC application in late 2011 for test year 2013. The petitions propose methodology to determine the 2012 revenue requirements for each company which would result in SDG&E and SoCalGas receiving an increase of no less than approximately $45 million and $55 million, respectively, in authorized margin, or three percent, above the 2011 authorized margin. The parties also agreed, among other things, to allow the Sempra Utilities to recover the increase, as deemed reasonable, in their annual excess liability insurance premiums in 2012, primarily due to the coverage for wildfire claims. Utility Incentive Mechanisms
Incentive awards are included in our earnings when we receive any required CPUC approval of the award. We would record penalties for results below the specified benchmarks in earnings when we believe it is more likely than not that the CPUC would assess a penalty. All award amounts discussed below are on a pretax basis. Cost of Capital SoCalGas SDG&E Advanced Metering Infrastructure In September 2008, SoCalGas filed an application with the CPUC for approval to upgrade approximately six million natural gas meters with an advanced metering infrastructure at an estimated cost of $1.1 billion (including approximately $900 million in capital investment). We expect a final CPUC decision in early 2010. If approved, installation of the meters is expected to begin in 2012 and continue through 2017. 2007 wildfires Cost Recovery INSURANCE COST RECOVERY FUTURE EXCESS claims COST RECOVERY |
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| 11 | SPECTRA ENERGY CORP. | 4. Regulatory Matters Union Gas. The OEB issued a decision under the incentive regulation framework in January 2009 providing for slight increases in rates for Union Gas’ small-volume customers and slight decreases for large-volume customers. Beginning April 1, 2009, the new rates were retroactively applied to January 1, 2009. In the second quarter of 2009, we recorded an $11 million charge to Operating Revenues—Distribution of Natural Gas on the Condensed Consolidated Statement of Operations as a result of a settlement with Union Gas’ stakeholders in June 2009 that was subsequently approved by the OEB. The settlement preserves the incentive regulation framework and replaces the provision for a review of the framework with a 90/10 sharing mechanism, in favor of customers, for any utility earnings of 300 basis points or more above the benchmark utility return on equity (ROE) for the year and is retroactive to 2008. The $11 million charge represents the adjustment to credit customers with 90% of Union Gas’ 2008 utility earnings that exceeded the 2008 benchmark utility ROE by 300 basis points. In September 2009, we filed an application with the OEB seeking approval of 2010 regulated distribution, storage and transmission rates, determined pursuant to the incentive regulation framework. The application proposes a delivery rate increase of less than 1% for a typical residential customer in our service territory. A decision by the OEB is expected before the end of the year. Maritimes & Northeast Pipeline Limited Partnership (M&N LP). During 2008, M&N LP operated under an NEB-approved toll settlement that expired December 31, 2008. M&N LP obtained approval to operate under interim rates, effective January 1, 2009, that were set to equal the 2008 rates. The final 2009 toll settlement rates were approved by the NEB in April 2009. M&N LP implemented the new rates on a prospective basis effective May 1, 2009 such that the total tolls charged during 2009 will result in revenues equal to those had the new 2009 rates been in effect for the entire year. Maritimes & Northeast Pipeline, L.L.C. (M&N LLC). On July 1, 2009, M&N LLC filed a rate case with the FERC. The rate case includes the impact of the Phase IV expansion facilities that went into service January 15, 2009 and results in lower recourse rates. The lower recourse rates did not impact the rates negotiated with customers for service, which are charged to customers for over 90% of M&N LLC’s capacity, including its Phase IV expansion facilities. |