2. RATE MATTERS

As discussed in the 2011 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered
				June 30,		December 31,
				2012		2011
				(in millions)
	Noncurrent Regulatory Assets (excluding fuel)
	Regulatory assets not yet being recovered pending future proceedings
			to determine the recovery method and timing:
	Regulatory Assets Currently Earning a Return
		Storm Related Costs		$	24	$	24
		Economic Development Rider			13		13
	Regulatory Assets Currently Not Earning a Return
		Virginia Environmental Rate Adjustment Clause			22		18
		Mountaineer Carbon Capture and Storage Product Validation Facility			14		14
		Special Rate Mechanism for Century Aluminum			13		13
		Litigation Settlement			11		11
		Storm Related Costs			8		10
		Virginia Deferred Wind Power Costs			4		38
		Other Regulatory Assets Not Yet Being Recovered			26		14
	Total Regulatory Assets Not Yet Being Recovered			$	135	$	155

OPCo Rate Matters

Ohio Electric Security Plan Filing

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. See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below. 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 and the Industrial Energy Users-Ohio (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 total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO's SEET decision. The OEG's appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation. The IEU's appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount. Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals. If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. In the fourth quarter of 2011, OPCo provided a reserve based upon management's estimate of the probable amount for a PUCO ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo's request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above. If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation. Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation. In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP. Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order. See the “2009 – 2011 ESP” section above. In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding. OPCo implemented the new revised tariffs in March 2012. In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order. Also in March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be deferred into a separate PIRR docket. See the “Proposed June 2012 – May 2015 ESP” section below.

As a result of the PUCO's rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo's motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo's current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day through May 2012. The PUCO subsequently extended that order until August 8, 2012 or until an order is issued in OPCo's pending June 2012 – May 2015 ESP proceeding, whichever is sooner. See the “Proposed June 2012 – May 2015 ESP” section below.

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing. The SSO rates would be effective through May 2015. The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015. OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value. Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014. In addition, a competitive bidding process would determine the price of energy for OPCo's SSO load from January 2015 through May 2015. The ESP proposed a two-tiered capacity pricing structure for CRES providers. The first tier is priced at the Reliability Pricing Model (RPM) rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively. All other capacity provided to CRES providers would be offered at $255/MW day. In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the FERC and the PUCO. In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo's pending June 2012 – May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. If OPCo is ultimately not permitted to fully recover its capacity cost deferral, it would reduce future net income and cash flows and impact financial condition.

The ESP also proposed to collect the PIRR from June 2013 through December 2018. As of June 30, 2012, the net PIRR deferral was $538 million, excluding unrecognized equity carrying costs. If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period. The proposed RSR would be effective through May 2015. Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo's ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. Intervenors recommended a flash cut to the current RPM rate for capacity. In addition, the PUCO staff's testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012. A decision from the PUCO is expected in August 2012.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012. In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.

Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated. In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR. See the “Proposed June 2012 – May 2015 ESP” section above. A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012. In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case. If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo's FAC for 2009. The outside consultant provided its audit report to the PUCO. In January 2012, the PUCO ordered 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. OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 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. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants' review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In June 2012, OPCo filed a notice of appeal with the Supreme Court of Ohio challenging the PUCO's decision to have proceeds from the 2008 coal contract settlement applied to OPCo's under recovered fuel balance. The PUCO filed a motion to dismiss OPCo's notice of appeal at the Supreme Court of Ohio. A decision is pending from the Supreme Court of Ohio.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audits. The audit reports 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. As of June 30, 2012, the amount of OPCo's carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $34 million, including $18 million of unrecognized equity carrying costs. Decisions from the PUCO are pending. Management is unable to predict the outcome of these proceedings. If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet. 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. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The deferral amount is included in OPCo's FAC phase-in deferral balance. In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would 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. Through June 30, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would 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 is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC. SWEPCo's share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC. As of June 30, 2012, excluding costs attributable to its joint owners and a $49 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million. As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million). SWEPCo's share of the contractual construction obligations is $48 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers. In June 2010, in response to the Arkansas Supreme Court's decision, the APSC issued an order which reversed and set aside the previously granted CECPN. SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

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 construction cost, excluding AFUDC and 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. SWEPCo appealed the PUCT's order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT's grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT's order in all respects. In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially 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 based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs. It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

APCo and WPCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012. The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012. The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing. In June 2012, the Virginia SCC approved the application as filed.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo's environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs. As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010. In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding this decision. If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo's Filings for an IGCC Plant

Through June 30, 2012, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo's and WPCo's Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets. Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC related assets. The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates. APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation. Upon completion of the securitization, APCo and WPCo would offset the then current ENEC rates by an amount recovered through the securitization. If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates. As of June 30, 2012, APCo's ENEC under-recovery balance of $326 million was recorded in Regulatory Assets on the balance sheet, excluding $6 million of unrecognized equity carrying costs.

In June 2012, a settlement agreement was filed with the WVPSC which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates. The settlement agreement did not address an intervenor recommendation that the fuel cost recovery for the Mountaineer Plant be limited to the prudently incurred cost of high sulfur coal which, if approved by the WVPSC, could result in a disallowance of approximately $14 million. Approval of the settlement agreement is pending before the WVPSC. If the WVPSC were to disallow a portion of APCo's and WPCo's deferred ENEC costs, it could reduce APCo's future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO's fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder's portion of off-system sales margins decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed. The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts. Hearings were held in June 2011. In June 2012, an Administrative Law Judge issued a report that affirmed the margin sharing amount of 25% and found that the OCC does not have the jurisdiction to grant the relief sought by the OIEC regarding the comprehensive review of all affiliate fuel transactions and the ERCOT trading contracts. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders. Final hearings were held in June 2012. A decision from the IURC is expected in the fourth quarter of 2012.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M's base rates. As of June 30, 2012, I&M has incurred $92 million related to the LCM Project. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

KPCo Rate Matters

Big Sandy Unit 2 FGD System

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system. The motion was accepted by the KPSC in May 2012. KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs. KPCo has not determined its future plan. As of June 30, 2012, KPCo has incurred $29 million related to the project. Management intends to pursue recovery of all costs related to this project. If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC's direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million. In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supported AEP's position and required a compliance filing. In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million. A decision is pending from the FERC.

The FERC has approved settlements applicable to $112 million of SECA revenue. The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected. Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012. The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012. The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing. In June 2012, the Virginia SCC approved the application as filed.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo's environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs. As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010. In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding this decision. If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo's Filings for an IGCC Plant

Through June 30, 2012, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

APCo's and WPCo's Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets. Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC related assets. The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates. APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation. Upon completion of the securitization, APCo and WPCo would offset the then current ENEC rates by an amount recovered through the securitization. If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates. As of June 30, 2012, APCo's ENEC under-recovery balance of $326 million was recorded in Regulatory Assets on the balance sheet, excluding $6 million of unrecognized equity carrying costs.

In June 2012, a settlement agreement was filed with the WVPSC which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates. The settlement agreement did not address an intervenor recommendation that the fuel cost recovery for the Mountaineer Plant be limited to the prudently incurred cost of high sulfur coal which, if approved by the WVPSC, could result in a disallowance of approximately $14 million. Approval of the settlement agreement is pending before the WVPSC. If the WVPSC were to disallow a portion of APCo's and WPCo's deferred ENEC costs, it could reduce APCo's future net income and cash flows and impact financial condition.

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Virginia Environmental Rate Adjustment Clause		$	22,336	$	17,950
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		14,155		14,155
	Special Rate Mechanism for Century Aluminum			12,939		12,811
	Dresden Operating Costs			7,265		-
	Virginia Deferred Wind Power Costs			4,277		38,192
	Transmission Agreement Phase-In			2,510		1,925
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,289		1,335
	Other Regulatory Assets Not Yet Being Recovered			3,049		1,010
Total Regulatory Assets Not Yet Being Recovered			$	67,820	$	87,378

APCo Rate Matters

WPCo Merger with APCo

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division. The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources. Merger approvals from the WVPSC, the Virginia SCC and the FERC are required. In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively. In February 2012, APCo and WPCo withdrew their merger application with the FERC. Management intends to refile a merger application with the FERC and also file a merger application with the Virginia SCC in the future.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC's direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million. APCo's, I&M's and OPCo's portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supported AEP's position and required a compliance filing.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo's, I&M's and OPCo's portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
I&M		8.3
OPCo		18.5

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue. Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million. The balance in the reserve for future settlements as of June 30, 2012 was $32 million. APCo's, I&M's and OPCo's reserve balances as of June 30, 2012 were:

Company	June 30, 2012
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million. A decision is pending from the FERC. APCo's, I&M's and OPCo's portions of potential refund payments and potential payments to be received are as follows:

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
I&M		3.7		1.9
OPCo		8.3		4.2

Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement – Affecting APCo, I&M and OPCo

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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 September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders. Final hearings were held in June 2012. A decision from the IURC is expected in the fourth quarter of 2012.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M's base rates. As of June 30, 2012, I&M has incurred $92 million related to the LCM Project. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

			I&M
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Litigation Settlement		$	10,954	$	10,803
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,382		1,680
	Other Regulatory Asset Not Being Recovered			658		-
Total Regulatory Assets Not Yet Being Recovered			$	12,994	$	12,483

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC's direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million. APCo's, I&M's and OPCo's portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supported AEP's position and required a compliance filing.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo's, I&M's and OPCo's portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
I&M		8.3
OPCo		18.5

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue. Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million. The balance in the reserve for future settlements as of June 30, 2012 was $32 million. APCo's, I&M's and OPCo's reserve balances as of June 30, 2012 were:

Company	June 30, 2012
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million. A decision is pending from the FERC. APCo's, I&M's and OPCo's portions of potential refund payments and potential payments to be received are as follows:

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
I&M		3.7		1.9
OPCo		8.3		4.2

Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement – Affecting APCo, I&M and OPCo

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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

OPCo Rate Matters

Ohio Electric Security Plan Filing

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. See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below. 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 and the Industrial Energy Users-Ohio (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 total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO's SEET decision. The OEG's appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation. The IEU's appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount. Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals. If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. In the fourth quarter of 2011, OPCo provided a reserve based upon management's estimate of the probable amount for a PUCO ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo's request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above. If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation. Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation. In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP. Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order. See the “2009 – 2011 ESP” section above. In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding. OPCo implemented the new revised tariffs in March 2012. In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order. Also in March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be deferred into a separate PIRR docket. See the “Proposed June 2012 – May 2015 ESP” section below.

As a result of the PUCO's rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

In March 2012, in response to OPCo's motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo's current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day through May 2012. The PUCO subsequently extended that order until August 8, 2012 or until an order is issued in OPCo's pending June 2012 – May 2015 ESP proceeding, whichever is sooner. See the “Proposed June 2012 – May 2015 ESP” section below.

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing. The SSO rates would be effective through May 2015. The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015. OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value. Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014. In addition, a competitive bidding process would determine the price of energy for OPCo's SSO load from January 2015 through May 2015. The ESP proposed a two-tiered capacity pricing structure for CRES providers. The first tier is priced at the Reliability Pricing Model (RPM) rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively. All other capacity provided to CRES providers would be offered at $255/MW day. In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the FERC and the PUCO. In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo's pending June 2012 – May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. If OPCo is ultimately not permitted to fully recover its capacity cost deferral, it would reduce future net income and cash flows and impact financial condition.

The ESP also proposed to collect the PIRR from June 2013 through December 2018. As of June 30, 2012, the net PIRR deferral was $538 million, excluding unrecognized equity carrying costs. If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period. The proposed RSR would be effective through May 2015. Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo's ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. Intervenors recommended a flash cut to the current RPM rate for capacity. In addition, the PUCO staff's testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012. A decision from the PUCO is expected in August 2012.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012. In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.

Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated. In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR. See the “Proposed June 2012 – May 2015 ESP” section above. A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012. In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case. If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo's FAC for 2009. The outside consultant provided its audit report to the PUCO. In January 2012, the PUCO ordered 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. OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 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. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants' review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In June 2012, OPCo filed a notice of appeal with the Supreme Court of Ohio challenging the PUCO's decision to have proceeds from the 2008 coal contract settlement applied to OPCo's under recovered fuel balance. The PUCO filed a motion to dismiss OPCo's notice of appeal at the Supreme Court of Ohio. A decision is pending from the Supreme Court of Ohio.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audits. The audit reports 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. As of June 30, 2012, the amount of OPCo's carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $34 million, including $18 million of unrecognized equity carrying costs. Decisions from the PUCO are pending. Management is unable to predict the outcome of these proceedings. If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet. 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. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The deferral amount is included in OPCo's FAC phase-in deferral balance. In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would 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. Through June 30, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would 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.

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

		OPCo
		June 30,		December 31,
		2012		2011
Noncurrent Regulatory Assets (excluding fuel)		(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Economic Development Rider	$	12,892	$	12,572
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		-		8,375
Total Regulatory Assets Not Yet Being Recovered		$	12,892	$	20,947

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC's direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million. APCo's, I&M's and OPCo's portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supported AEP's position and required a compliance filing.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo's, I&M's and OPCo's portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
I&M		8.3
OPCo		18.5

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue. Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million. The balance in the reserve for future settlements as of June 30, 2012 was $32 million. APCo's, I&M's and OPCo's reserve balances as of June 30, 2012 were:

Company	June 30, 2012
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million. A decision is pending from the FERC. APCo's, I&M's and OPCo's portions of potential refund payments and potential payments to be received are as follows:

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
I&M		3.7		1.9
OPCo		8.3		4.2

Based on the analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Possible Termination of the Interconnection Agreement – Affecting APCo, I&M and OPCo

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers, or if each company will choose to operate independently. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement 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

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO's fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder's portion of off-system sales margins decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed. The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts. Hearings were held in June 2011. In June 2012, an Administrative Law Judge issued a report that affirmed the margin sharing amount of 25% and found that the OCC does not have the jurisdiction to grant the relief sought by the OIEC regarding the comprehensive review of all affiliate fuel transactions and the ERCOT trading contracts. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Rate Matters

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs. It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

			SWEPCo
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Rate Case Expenses		$	2,760	$	-
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		2,298		2,380
	Other Regulatory Assets Not Yet Being Recovered			2,006		1,699
Total Regulatory Assets Not Yet Being Recovered			$	7,064	$	4,079

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC. SWEPCo's share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC. As of June 30, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million. As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million). SWEPCo's share of the contractual construction obligations is $48 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers. In June 2010, in response to the Arkansas Supreme Court's decision, the APSC issued an order which reversed and set aside the previously granted CECPN. SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

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 construction cost, excluding AFUDC and 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. SWEPCo appealed the PUCT's order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT's grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT's order in all respects. In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its third formula rate plan (FRP) which decreased annual Louisiana retail rates by $3 million effective August 2010, subject to refund. In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo's FRP calculations. Hearings were scheduled for May 2012 but were postponed pending settlement negotiations. In the second quarter of 2012, SWEPCo recorded a reserve related to these settlement negotiations. Management believes that the reserve is adequate to pay any refunds. However, if the LPSC orders a refund greater than the booked reserve, it would reduce future net income and cash flows.