Rate Matters	12 Months Ended
Dec. 31, 2013
Rate Matters	4. RATE MATTERS Our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. Our recent significant rate orders and pending rate filings are addressed in this note. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO. In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of December 31, 2013, OPCo's net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision. In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2013, could reduce carrying costs by $31 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In July 2011, OPCo filed its 2010 SEET filing with the PUCO. In October 2013, the PUCO issued an order on the 2010 SEET filing that determined there were excessive earnings of $7 million, which were primarily offset against deferred fuel, as ordered. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In November 2013, OPCo filed its 2011 and 2012 SEET filings with the PUCO. In February 2014, the PUCO staff filed testimony asserting that no significantly excessive earnings had occurred in 2011 for CSPCo or OPCo and that no significantly excessive earnings had occurred in 2012 for OPCo. In February 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. A hearing at the PUCO related to the 2011 SEET filing is scheduled for February 2014. Management does not believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in either 2012 or 2013 for OPCo. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of December 31, 2013, OPCo's incurred deferred capacity costs balance of $288 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR. In November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its fixed fuel and deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. Proposed June 2015 – May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the first quarter of 2014. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets and associated generation liabilities at net book value to AGR. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, the PUCO approved OPCo's application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC. The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. Storm Damage Recovery Rider (SDRR) In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation included a $6 million reduction in the amount of 2012 storm expenses to be recovered and for recovery of those expenses to take place over a 12-month period. The agreement also states that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In December 2013, the OCC filed testimony opposing the stipulation. The testimony recommended the disallowance of approximately $18 million of the 2012 storm expenses and that the remaining 2012 storm expenses be offset by an additional $20 million that OPCo was ordered to spend on a solar project in OPCo's 2009 SEET filing. See the “2009-2011 ESP” section above. Hearings were held at the PUCO in January 2014 related to the settlement agreement and to address issues presented in the OCC's testimony. As of December 31, 2013, OPCo has deferred $56 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo's 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition. 2010 and 2011 Fuel Adjustment Clause Audits The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider (EDR). In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of December 31, 2013, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. Ohio IGCC Plant In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of December 31, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters Turk Plant SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of December 31, 2013, SWEPCo's share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion. As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion. The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market. The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. The PUCT decision was upheld on appeal. See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition. 2012 Texas Base Rate Case In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016 and (b) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determining that the Turk Plant Texas capital cost cap established in the Certificate of Convenience and Necessity (CCN) case discussed above (the Texas capital cost cap) also limited SWEPCo's recovery of AFUDC in addition to its recovery of cash construction costs. As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax regulatory disallowance of $111 million. The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%, including an unfavorable consolidated income tax adjustment of $5 million. As a result of this approval, SWEPCo retroactively applied the rate increase to the end of January 2013. The order also provided that there would be no disallowance to the existing book investment in the Stall Unit and that the Turk Plant related transmission line investment that was not in service at the end of the test year would be excluded from rate base. SWEPCo has since sought approval to recover this transmission investment through a Transmission Cost Recovery Rider in a filing made in December 2013. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of December 31, 2013, the net book value of Welsh Plant, Unit 2 was $87 million, before cost of removal, including materials and supplies inventory and CWIP. In October 2013, SWEPCo filed a motion for rehearing with the PUCT. In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo's annual revenues by $5 million. In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. These rulings also increased SWEPCo's previously approved annual base rates by a total of $13 million, which was also retroactively applied to the end of January 2013. The resulting annual base rate increase is approximately $52 million. If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Welsh Plant, Unit 2 and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition. 2013 Texas Transmission Costs Recovery Factor Filing In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In January and February 2014, intervenors filed motions with the PUCT opposing SWEPCo's filing. In February 2014, an Administrative Law Judge issued an order requesting additional information from SWEPCo related to this filing. If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. Flint Creek Plant Environmental Controls In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. APCo and WPCo Rate Matters Plant Transfers In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity. In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price. The Virginia jurisdictional share of the disallowance was approximately $39 million. The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia's jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo's next West Virginia base rate case which APCo has agreed to file no later than June 2014. The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax. Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo. The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue. In December 2013, the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo was completed. As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income. Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR. If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition. APCo IGCC Plant As of December 31, 2013, 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 $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period. The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015. As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs. 2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant. In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million. Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue. As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs. 2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC) In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually. The increase in the transmission RAC is expected to be effective May 2014. In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $49 million annually, subject to true-up. The stipulation included the Virginia SCC staff's commitment to fully audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC filing in 2015. As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs. If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows. 2013 West Virginia Expanded Net Energy Charge (ENEC) Filing In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance. In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031. APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues. As of December 31, 2013, APCo's ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet. Virginia Storm Costs In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings. The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo's biennial Virginia base rate filing. PSO Rate Matters 2014 Oklahoma Base Rate Case In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years. Oklahoma Environmental Compliance Plan In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026. As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP. In August 2013, the OCC dismissed PSO's environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding. PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan. If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. I&M Rate Matters 2011 Indiana Base Rate Case In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. Cook Plant Life Cycle Management Project (LCM Project) In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC. In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014. In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. Rockport Plant Clean Coal Technology Project (CCT Project) In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system. The estimated cost in the application was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. I&M's Indiana jurisdictional allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. As of December 31, 2013, we have incurred costs of $109 million related to the CCT Project, including AFUDC. Tanners Creek Plant, Units 1 - 4 In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases. In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition. KPCo Rate Matters Plant Transfer In October 2012, the AEP East Companies submitted several filings with the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of December 31, 2013, the net book value of Big Sandy Plant, Unit 2 was $249 million, before cost of removal, including materials and supplies inventory and CWIP. In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace a portion of the capacity from Big Sandy Plant, Unit 1. In June 2013, KPCo filed the results of its RFP with the KPSC. In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo's request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income. In November 2013, the KPSC denied the Attorney General's petition for rehearing. In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal. A hearing on the motions to dismiss was held in January 2014. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. 2013 Kentucky Base Rate Case In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase included cost recovery of the proposed transfer of the one-half interest in the Mitchell Plant (780 MW). In October 2013, the KPSC issued an order in the plant transfer case which modified and approved a settlement agreement that included the approval of the proposed transfer of the one-half interest in the Mitchell Plant to KPCo. The modified and approved settlement agreement also included KPCo's agreement to withdraw this base rate case request and file a base case proceeding no later than December 2014 with its current base rates to remain in effect until at least May 2015. In November 2013, KPCo withdrew this base rate request and the withdrawal was approved by the KPSC. FERC Rate Matters Corporate Separation and Termination of Interconnection Agreement In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the KPSC, the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters. In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015. Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC. In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders. If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.
Appalachian Power Co [Member]
Rate Matters	Plant Transfers In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity. In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price. The Virginia jurisdictional share of the disallowance was approximately $39 million. The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia's jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo's next West Virginia base rate case which APCo has agreed to file no later than June 2014. The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax. Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo. The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue. In December 2013, the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo was completed. As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income. Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR. If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition. APCo IGCC Plant As of December 31, 2013, 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 $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period. The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015. As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs. 2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant. In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million. Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue. As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs. 2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC) In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually. The increase in the transmission RAC is expected to be effective May 2014. In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $49 million annually, subject to true-up. The stipulation included the Virginia SCC staff's commitment to fully audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC filing in 2015. As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs. If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows. 2013 West Virginia Expanded Net Energy Charge (ENEC) Filing In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance. In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031. APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues. As of December 31, 2013, APCo's ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet. Virginia Storm Costs In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings. The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo's biennial Virginia base rate filing. 3. RATE MATTERS The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note. APCo Rate Matters WPCo Merger with APCo In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant. In June 2013, the WVPSC issued an order consolidating the merger case with APCo's plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer will result in insufficient generation to serve the merged company. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. Management continues to review its options and the feasibility related to the merger, the respective companies' needs for generation and the remaining one-half interest in the Mitchell Plant currently owned by AGR. See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. FERC Rate Matters Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo Rate Matters. In accordance with management's December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015. Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC. In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.
Indiana Michigan Power Co [Member]
Rate Matters	I&M Rate Matters 2011 Indiana Base Rate Case In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. Cook Plant Life Cycle Management Project (LCM Project) In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC. In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014. In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. Tanners Creek Plant, Units 1 - 4 In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases. In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition. 3. RATE MATTERS The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note. Rockport Plant Clean Coal Technology Project (CCT Project) In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system. The estimated cost of the CCT Project was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share of $129 million. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. I&M's Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. As of December 31, 2013, I&M has incurred costs of $56 million related to the CCT Project, including AFUDC. FERC Rate Matters Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo Rate Matters. In accordance with management's December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015. Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC. In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.
Ohio Power Co [Member]
Rate Matters	OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO. In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of December 31, 2013, OPCo's net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision. In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2013, could reduce carrying costs by $31 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In July 2011, OPCo filed its 2010 SEET filing with the PUCO. In October 2013, the PUCO issued an order on the 2010 SEET filing that determined there were excessive earnings of $7 million, which were primarily offset against deferred fuel, as ordered. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In November 2013, OPCo filed its 2011 and 2012 SEET filings with the PUCO. In February 2014, the PUCO staff filed testimony asserting that no significantly excessive earnings had occurred in 2011 for CSPCo or OPCo and that no significantly excessive earnings had occurred in 2012 for OPCo. In February 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. A hearing at the PUCO related to the 2011 SEET filing is scheduled for February 2014. Management does not believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in either 2012 or 2013 for OPCo. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of December 31, 2013, OPCo's incurred deferred capacity costs balance of $288 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR. In November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its fixed fuel and deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. Proposed June 2015 – May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the first quarter of 2014. Storm Damage Recovery Rider (SDRR) In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation included a $6 million reduction in the amount of 2012 storm expenses to be recovered and for recovery of those expenses to take place over a 12-month period. The agreement also states that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In December 2013, the OCC filed testimony opposing the stipulation. The testimony recommended the disallowance of approximately $18 million of the 2012 storm expenses and that the remaining 2012 storm expenses be offset by an additional $20 million that OPCo was ordered to spend on a solar project in OPCo's 2009 SEET filing. See the “2009-2011 ESP” section above. Hearings were held at the PUCO in January 2014 related to the settlement agreement and to address issues presented in the OCC's testimony. As of December 31, 2013, OPCo has deferred $56 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo's 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition. 2010 and 2011 Fuel Adjustment Clause Audits The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider (EDR). In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of December 31, 2013, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. Ohio IGCC Plant In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of December 31, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition. 3. RATE MATTERS The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, the PUCO approved OPCo's application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC. The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. In December 2013, corporate separation of OPCo's generation assets was completed. Also in October 2012, filings at the FERC were submitted related to corporate separation. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. FERC Rate Matters Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo Rate Matters. In accordance with management's December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015. Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC. In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.
Public Service Co of Oklahoma [Member]
Rate Matters	PSO Rate Matters 2014 Oklahoma Base Rate Case In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years. Oklahoma Environmental Compliance Plan In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026. As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP. In August 2013, the OCC dismissed PSO's environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding. PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan. If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. 3. RATE MATTERS The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note.
Southwestern Electric Power Co [Member]
Rate Matters	SWEPCo Rate Matters Turk Plant SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of December 31, 2013, SWEPCo's share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion. As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion. The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market. The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. The PUCT decision was upheld on appeal. See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap. If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition. 2012 Texas Base Rate Case In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016 and (b) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determining that the Turk Plant Texas capital cost cap established in the Certificate of Convenience and Necessity (CCN) case discussed above (the Texas capital cost cap) also limited SWEPCo's recovery of AFUDC in addition to its recovery of cash construction costs. As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax regulatory disallowance of $111 million. The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%, including an unfavorable consolidated income tax adjustment of $5 million. As a result of this approval, SWEPCo retroactively applied the rate increase to the end of January 2013. The order also provided that there would be no disallowance to the existing book investment in the Stall Unit and that the Turk Plant related transmission line investment that was not in service at the end of the test year would be excluded from rate base. SWEPCo has since sought approval to recover this transmission investment through a Transmission Cost Recovery Rider in a filing made in December 2013. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of December 31, 2013, the net book value of Welsh Plant, Unit 2 was $87 million, before cost of removal, including materials and supplies inventory and CWIP. In October 2013, SWEPCo filed a motion for rehearing with the PUCT. In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo's annual revenues by $5 million. In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. These rulings also increased SWEPCo's previously approved annual base rates by a total of $13 million, which was also retroactively applied to the end of January 2013. The resulting annual base rate increase is approximately $52 million. If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Welsh Plant, Unit 2 and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition. 2013 Texas Transmission Costs Recovery Factor Filing In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In January and February 2014, intervenors filed motions with the PUCT opposing SWEPCo's filing. In February 2014, an Administrative Law Judge issued an order requesting additional information from SWEPCo related to this filing. If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. Flint Creek Plant Environmental Controls In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. 3. RATE MATTERS The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note.

4. RATE MATTERS

Our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. Our recent significant rate orders and pending rate filings are addressed in this note.

OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of December 31, 2013, OPCo's net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2013, could reduce carrying costs by $31 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO. In October 2013, the PUCO issued an order on the 2010 SEET filing that determined there were excessive earnings of $7 million, which were primarily offset against deferred fuel, as ordered. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In November 2013, OPCo filed its 2011 and 2012 SEET filings with the PUCO. In February 2014, the PUCO staff filed testimony asserting that no significantly excessive earnings had occurred in 2011 for CSPCo or OPCo and that no significantly excessive earnings had occurred in 2012 for OPCo. In February 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. A hearing at the PUCO related to the 2011 SEET filing is scheduled for February 2014. Management does not believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in either 2012 or 2013 for OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of December 31, 2013, OPCo's incurred deferred capacity costs balance of $288 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR.

In November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its fixed fuel and deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the first quarter of 2014.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets and associated generation liabilities at net book value to AGR. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, the PUCO approved OPCo's application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC. The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation included a $6 million reduction in the amount of 2012 storm expenses to be recovered and for recovery of those expenses to take place over a 12-month period. The agreement also states that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In December 2013, the OCC filed testimony opposing the stipulation. The testimony recommended the disallowance of approximately $18 million of the 2012 storm expenses and that the remaining 2012 storm expenses be offset by an additional $20 million that OPCo was ordered to spend on a solar project in OPCo's 2009 SEET filing. See the “2009-2011 ESP” section above. Hearings were held at the PUCO in January 2014 related to the settlement agreement and to address issues presented in the OCC's testimony. As of December 31, 2013, OPCo has deferred $56 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo's 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider (EDR). In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of December 31, 2013, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues.

In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of December 31, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of December 31, 2013, SWEPCo's share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion. As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. The PUCT decision was upheld on appeal. See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016 and (b) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determining that the Turk Plant Texas capital cost cap established in the Certificate of Convenience and Necessity (CCN) case discussed above (the Texas capital cost cap) also limited SWEPCo's recovery of AFUDC in addition to its recovery of cash construction costs. As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax regulatory disallowance of $111 million. The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%, including an unfavorable consolidated income tax adjustment of $5 million. As a result of this approval, SWEPCo retroactively applied the rate increase to the end of January 2013. The order also provided that there would be no disallowance to the existing book investment in the Stall Unit and that the Turk Plant related transmission line investment that was not in service at the end of the test year would be excluded from rate base. SWEPCo has since sought approval to recover this transmission investment through a Transmission Cost Recovery Rider in a filing made in December 2013. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of December 31, 2013, the net book value of Welsh Plant, Unit 2 was $87 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, SWEPCo filed a motion for rehearing with the PUCT. In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo's annual revenues by $5 million. In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. These rulings also increased SWEPCo's previously approved annual base rates by a total of $13 million, which was also retroactively applied to the end of January 2013. The resulting annual base rate increase is approximately $52 million.

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Welsh Plant, Unit 2 and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

2013 Texas Transmission Costs Recovery Factor Filing

In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In January and February 2014, intervenors filed motions with the PUCT opposing SWEPCo's filing. In February 2014, an Administrative Law Judge issued an order requesting additional information from SWEPCo related to this filing. If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo and WPCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity. In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price. The Virginia jurisdictional share of the disallowance was approximately $39 million. The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.

In December 2013, the WVPSC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia's jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo's next West Virginia base rate case which APCo has agreed to file no later than June 2014. The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax. Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo. The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue.

In December 2013, the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo was completed. As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income. Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR. If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of December 31, 2013, 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 $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period. The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015. As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing

In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant. In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million. Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue. As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs.

2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually. The increase in the transmission RAC is expected to be effective May 2014. In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $49 million annually, subject to true-up. The stipulation included the Virginia SCC staff's commitment to fully audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC filing in 2015. As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs. If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows.

2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance. In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031. APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.

As of December 31, 2013, APCo's ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings. The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo's biennial Virginia base rate filing.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026. As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP. In August 2013, the OCC dismissed PSO's environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding. PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan. If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014. In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system. The estimated cost in the application was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. I&M's Indiana jurisdictional allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. As of December 31, 2013, we have incurred costs of $109 million related to the CCT Project, including AFUDC.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.

As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of December 31, 2013, the net book value of Big Sandy Plant, Unit 2 was $249 million, before cost of removal, including materials and supplies inventory and CWIP. In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace a portion of the capacity from Big Sandy Plant, Unit 1. In June 2013, KPCo filed the results of its RFP with the KPSC.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo's request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income. In November 2013, the KPSC denied the Attorney General's petition for rehearing. In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal. A hearing on the motions to dismiss was held in January 2014. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase included cost recovery of the proposed transfer of the one-half interest in the Mitchell Plant (780 MW). In October 2013, the KPSC issued an order in the plant transfer case which modified and approved a settlement agreement that included the approval of the proposed transfer of the one-half interest in the Mitchell Plant to KPCo. The modified and approved settlement agreement also included KPCo's agreement to withdraw this base rate case request and file a base case proceeding no later than December 2014 with its current base rates to remain in effect until at least May 2015. In November 2013, KPCo withdrew this base rate request and the withdrawal was approved by the KPSC.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the KPSC, the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters.

In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015.

Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders.

If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.

Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity. In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price. The Virginia jurisdictional share of the disallowance was approximately $39 million. The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.

In December 2013, the WVPSC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia's jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo's next West Virginia base rate case which APCo has agreed to file no later than June 2014. The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax. Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo. The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue.

In December 2013, the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo was completed. As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income. Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR. If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of December 31, 2013, 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 $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period. The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015. As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing

In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant. In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million. Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue. As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs.

2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually. The increase in the transmission RAC is expected to be effective May 2014. In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $49 million annually, subject to true-up. The stipulation included the Virginia SCC staff's commitment to fully audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC filing in 2015. As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs. If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows.

2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance. In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031. APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.

As of December 31, 2013, APCo's ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings. The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo's biennial Virginia base rate filing.

3. RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note.

APCo Rate Matters

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant. In June 2013, the WVPSC issued an order consolidating the merger case with APCo's plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer will result in insufficient generation to serve the merged company. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. Management continues to review its options and the feasibility related to the merger, the respective companies' needs for generation and the remaining one-half interest in the Mitchell Plant currently owned by AGR. See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR. The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo. In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR. Similar asset transfer filings were made at the Virginia SCC and the WVPSC. In December 2013, corporate separation of OPCo's generation assets was completed. See the “Plant Transfers” section of APCo Rate Matters.

In accordance with management's December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014. The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015.

Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo. This agreement provides for AGR to supply capacity for OPCo's switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. In December 2013, the FERC issued an order approving the PSA. The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO's current and future underlying rates and rate structure. In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. In December 2013, the FERC issued an order approving these additional filings. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order.

If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Rate Matters

I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014. In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.

As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

3. RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries' recent significant rate orders and pending rate filings are addressed in this note.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system. The estimated cost of the CCT Project was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share of $129 million. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. I&M's Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. As of December 31, 2013, I&M has incurred costs of $56 million related to the CCT Project, including AFUDC.