3. RATE MATTERS

As discussed in the 2010 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2010 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 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
				September 30,		December 31,
				2011		2010
				(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
		Capacity Auction True-Up - TCC		$	682	$	-
		Line Extension Carrying Costs - CSPCo, OPCo			64		55
		Customer Choice Deferrals - CSPCo, OPCo			60		59
		Storm Related Costs - CSPCo, OPCo			31		30
		Storm Related Costs - TCC			25		25
		Economic Development Rider - CSPCo, OPCo			12		6
		Acquisition of Monongahela Power - CSPCo			9		8
		Other Regulatory Assets Not Yet Being Recovered			1		1
	Regulatory Assets Currently Not Earning a Return
		Environmental Rate Adjustment Clause - APCo			73		56
		Deferred Wind Power Costs - APCo			40		29
		Storm Related Costs - APCo, KGPCo			27		28
		Mountaineer Carbon Capture and Storage Product Validation Facility - APCo			19		60
		Special Rate Mechanism for Century Aluminum - APCo			13		13
		Mountaineer Carbon Capture and Storage Commercial Scale Facility - APCo,
			I&M, KPCo, PSO, SWEPCo		12		-
		Litigation Settlement - I&M			11		-
		Acquisition of Monongahela Power - CSPCo			4		4
		Storm Related Costs - PSO			-		17
		Other Regulatory Assets Not Yet Being Recovered			6		4
	Total Regulatory Assets Not Yet Being Recovered			$	1,089	$	395

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo's and OPCo's ESPs which established rates at the start of the April 2009 billing cycle through 2011. The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. In November 2009, the PUCO's order was appealed to the Supreme Court of Ohio (the Court). In April 2011, the Court issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. The order required CSPCo and OPCo to refund Provider of Last Resort (POLR) charges which were collected subject to refund since June 2011. According to the order, CSPCo and OPCo are required to apply the refund first to the FAC deferral with any remaining balance to be credited to CSPCo's and OPCo's customers in November and December 2011. As a result, in the third quarter of 2011, CSPCo and OPCo recorded pretax refund provisions of $34 million and $9 million, respectively, on the condensed statements of income. The PUCO order also agreed with CSPCo's and OPCo's position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in CSPCo's and OPCo's base generation rates. In addition, the PUCO rejected the intervenors' proposed adjustments to the FAC deferral balance for POLR charges and environmental carrying charges for the period from April 2009 through May 2011. This decision is subject to rehearing and appeal.

In April 2010, the Industrial Energy Users-Ohio (IEU) filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. In June 2011, the Court affirmed the PUCO's decision and dismissed the IEU's appeal.

In January 2011, the PUCO issued an order on CSPCo's and OPCo's 2009 SEET filings and determined that OPCo's 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered CSPCo to refund $43 million of its pretax earnings to customers, which was recorded as a revenue provision on CSPCo's December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo's FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo's customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011. In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO's SEET decisions.

In July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo will have any significantly excessive earnings. In October 2011, the Ohio Consumers' Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings. Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings.

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

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation. The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.

In September 2011, a stipulation agreement was filed with the PUCO by CSPCo, OPCo, the PUCO staff and multiple other parties which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. The FAC deferral as of September 30, 2011 was $542 million for OPCo, excluding $40 million of unrecognized equity carrying costs. CSPCo did not have a FAC deferral as of September 30, 2011. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo's and OPCo's SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo's and OPCo's generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. See the “Possible Termination of the Interconnection Agreement” section of FERC rate matters. The current FAC mechanism would continue through May 2015. Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations.

Various intervenors who did not sign the stipulation agreement filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the market-rate offer and that the proposed capacity charges to competitive retail suppliers are anti-competitive. Hearings on the stipulation agreement are ongoing. A decision from the PUCO is expected in the fourth quarter of 2011. If OPCo is not ultimately permitted to fully recover its FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of September 30, 2011 was $102 million and $66 million for CSPCo and OPCo, respectively, excluding $64 million and $48 million, respectively, of unrecognized equity carrying costs.

In September 2011, the PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million based upon a return on common equity range of 8.58% to 9.6%. In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. In July 2011, the FERC issued an order approving the proposed merger. In September 2011, a stipulation agreement was filed with the PUCO which recommended CSPCo merge into OPCo by the end of 2011. A decision from the PUCO is expected in the fourth quarter of 2011. See “January 2012 – May 2016 ESP” section above.

Sporn Unit 5

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding. In April 2011, intervenors filed comments opposing OPCo's application. A PUCO decision is pending as to whether a hearing will be ordered.

In the third quarter of 2011, management decided to no longer offer Sporn Unit 5 into the PJM market. Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the AEP Power Pool. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the condensed statements of income.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for CSPCo and OPCo for the period of January 2009 through December 2009. In May 2010, the outside consultant provided its confidential audit report to the PUCO. The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo's FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010. Hearings were held in August 2010. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit for CSPCo and OPCo. The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes. As of September 30, 2011, the amount of OPCo's carrying costs that could potentially be at risk is estimated to be $12 million, excluding $14 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, 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 filings and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio's April 2011 decision referenced in the “2009-2011 ESPs” section above. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo's and OPCo's FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and 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 CSPCo's and OPCo's November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo's and OPCo's ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. In June 2011, the Supreme Court of Ohio affirmed the PUCO's decision and dismissed the IEU's appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above. In August 2011, the Supreme Court of Ohio affirmed the PUCO's decision on the remaining issues.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs. As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively. The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. As of June 2011, there were no active IGCC projects at other AEP sites. In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest. 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 any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would 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 expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $129 million for transmission, excluding AFUDC. SWEPCo's share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $129 million for transmission, excluding AFUDC. As of September 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.3 billion of expenditures (including AFUDC and capitalized interest of $197 million and related transmission costs of $88 million). As of September 30, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $163 million (including related transmission costs of $13 million). SWEPCo's share of the contractual construction commitments is $123 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2011, of approximately $101 million (including related transmission cancellation fees of $1 million). SWEPCo's share of the contractual construction cancellation fees would be approximately $74 million.

Discussed below are the significant outstanding uncertainties related to the Turk Plant:

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. The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN. However, the Arkansas Supreme Court approved the APSC's procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding. SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates. In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.

The PUCT issued an order approving 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 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. In February 2010, the Texas District Court affirmed the PUCT's order in all respects. In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals. Management is unable to predict the timing of the outcome related to this proceeding.

In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit. The parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas. In December 2010, the Circuit Court affirmed the APCEC. In January 2011, the same parties filed a notice of appeal with the Arkansas Court of Appeals.

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order. In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The plaintiffs' federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. The plaintiffs' state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims. In 2010, the motions for preliminary injunction were partially granted by the Federal District Court for the Western District of Arkansas. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and portions of two transmission lines. SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction and remanded the case to the district court. Management is unable to predict the timing or the outcome related to this remand proceeding.

In August 2011, a joint stipulation of dismissal was approved by the Federal District Court for the Western District of Arkansas that resolved all pending matters between SWEPCo, the Hunting Club and several other parties. As a result, the Hunting Club's challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas was dismissed and the Hunting Club's appeal of the air permit was withdrawn. Additional judicial and administrative proceedings were terminated. The Sierra Club and the Audubon Society challenges to the wetlands and air permits remain pending.

In October 2011, the Sierra Club, the National Audubon Society and Audubon Arkansas filed a complaint with the APSC requesting that construction of the Turk Plant be halted until SWEPCo or the Arkansas Electric Cooperative Corporation obtain either a CECPN, or SWEPCo obtains a CCN and performs an Environmental Impact Statement on associated gas facilities. Management believes the complaint is without merit and intends to vigorously defend against the complaint.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Texas Turk Plant Rate Plan

In August 2011, SWEPCo requested approval of a three step plan from the PUCT for including the Turk Plant investment in Texas retail rates. If approved, step one would recover financing costs on 40% of the June 2011 Texas jurisdictional share of the Turk Plant construction work in progress balance from April 2012 through October 2012. In step two, which would be implemented in November 2012, additional financing costs would be recovered on 100% of the June 2011 Texas jurisdictional share of the Turk Plant CWIP balance and would continue until the Turk Plant costs are included in base rates. Once the Turk Plant goes into service, which is expected in the fourth quarter of 2012, SWEPCo proposes that it also be allowed to defer Turk Plant related depreciation expense, operating and maintenance expense and additional financing costs incurred for future recovery. The final step would be to file a complete base rate case which will include all of the Turk Plant investment and associated operating expenses. Based upon the Turk Plant being placed into service in the fourth quarter of 2012, SWEPCo expects to file a complete base rate case in the first half of 2013.

TCC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders. TCC and intervenors appealed the PUCT's true-up related orders. After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas. In July 2011, the Supreme Court of Texas granted review and issued its opinion. No parties filed for rehearing with the Supreme Court of Texas, and the case was remanded to the PUCT. The following issues were decided by the Supreme Court:

The PUCT's 2006 order denying recovery of capacity auction true-up amounts was reversed. Based upon the Supreme Court of Texas' opinion, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011. Further, in October 2011, the PUCT issued a preliminary order in the remand proceeding.

Also in the third quarter of 2011, TCC recorded $261 million in pretax Carrying Costs Income on the condensed statements of income related to the debt component of carrying costs for the period from January 2002 through September 2011. This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002. The total regulatory asset related to the capacity auction true-up as of September 30, 2011 was $682 million. In October 2011, TCC filed with the PUCT requesting a final determination of the amount to be securitized. In its filing, TCC presented three alternative carrying cost calculations through March 2012, the anticipated securitization date, where the debt and equity component of carrying costs ranged from $396 million to $756 million, including $280 million to $444 million for the debt component of carrying costs. As of September 30, 2011, the corresponding range of the debt and equity component of carrying costs was $368 million to $692 million, including $261 million to $410 million for the debt component of carrying costs. The final amount of carrying costs will be determined by the PUCT and could vary from the calculations presented by TCC. TCC plans to recognize debt carrying costs income prior to securitization and equity carrying costs income will be recognized as collected over the life of the securitization. A PUCT hearing is scheduled for November 2011.

The Supreme Court of Texas reversed the Texas Court of Appeal's decision and found that the PUCT could adjust the net book value for what it determined to be commercially unreasonable conduct. This portion of the decision is unfavorable, but was already reflected in our financial statements.
The Supreme Court of Texas affirmed the PUCT's finding that the sales price should be used to value TCC's nuclear generation. This portion of the decision is favorable, but this issue will have no impact on TCC's rate recovery as this was already reflected in our financial statements.
The Supreme Court of Texas reversed the Texas Court of Appeal's decision and found it was appropriate for the PUCT to take into account previously refunded excess mitigation credits to affiliate retail electricity providers. This portion of the decision upheld the PUCT's decision. However, resolution of related issues will be addressed on remand in the excess earnings proceeding. See the “TCC Excess Earnings” section below.
The PUCT decisions allowing recovery of construction work in progress balances and specifying the interest rate on stranded costs were upheld. These decisions are already reflected in our financial statements and were not addressed in the remand proceeding.

If TCC is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits including associated carrying costs related to TCC's generation assets. In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such a reduction was an IRS normalization violation. In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus additional interest through the CTC refund period pending resolution of the normalization issue. In 2008, the IRS issued final regulations, which supported the IRS's private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation. After the IRS issued its final regulations, the Texas Court of Appeals, at the request of the PUCT, remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations. The issue was not appealed to the Supreme Court of Texas but it was addressed in connection with the remand of the true-up proceeding. See the “Texas Restructuring Appeals” section above. In August 2011, the Supreme Court of Texas issued a mandate to return this proceeding and other true-up proceedings to the PUCT. The PUCT established a proceeding to address this issue along with other true-up remanded issues. TCC is not accruing interest on the $103 million because management believes it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code. If interest were accrued, management estimates interest expense would have been approximately $30 million higher for the period July 2008 through September 2011.

Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows. Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC's repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property. This amount approximates $101 million as of September 30, 2011. It could also lead to a loss of TCC's right to claim accelerated tax depreciation in future tax returns. If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it would reduce future net income and cash flows and impact financial condition.

TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the Texas Retail Electric Providers excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. From 2002 to 2005, TCC refunded $55 million of excess earnings, including interest, under the overturned PUCT order. In the true-up proceeding, the PUCT adjusted stranded costs for TCC's payment of excess earnings under the PUCT order. However, the PUCT did not properly recognize TCC's payment of interest under the prior order, causing TCC to refund interest twice. The Supreme Court of Texas approved the PUCT treatment of these matters in the true-up case, noting that TCC could pursue its additional interest claim in further proceedings related to the excess earnings order. TCC intends to assert its claims in a remand of this order to the PUCT.

APCo and WPCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo's net base rate increase would be $75 million.

In August 2011, the Virginia Attorney General filed testimony recommending no increase in annual base rates based on a return on common equity of 11.03%. Also in August 2011, the Virginia SCC staff filed testimony recommending an increase in annual base rates of $31 million based on a return on common equity of 10.83%. Hearings were held in September 2011. A decision from the Virginia SCC is pending.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications. In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after December 2007 which are not being recovered in current revenues. As of September 30, 2011, APCo has deferred $73 million of environmental costs (excluding $17 million of unrecognized equity carrying costs) and $40 million of renewable energy costs.

In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing. The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $77 million to be collected over two years beginning in February 2012. The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million. APCo plans to seek recovery of non-incremental deferred wind power costs ($34 million as of September 30, 2011) in future rate proceedings. The generation RAC is requesting recovery of the Dresden Plant, currently under construction. With Virginia SCC approval, APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million.

In August 2011, the Virginia SCC staff filed testimony in the environmental RAC proceeding recommending recovery, based upon the methodology used, of $37 million to $42 million of environmental compliance costs. In October 2011, a hearing examiner issued a report recommending recovery of $65 million of environmental compliance costs. An order is pending from the Virginia SCC. Also in August 2011, a stipulation agreement was filed with the Virginia SCC related to the generation RAC. The stipulation agreement allows recovery of the Dresden Plant costs totaling up to $27 million annually, effective March 2012. A decision from the Virginia SCC is pending. In September 2011, the Virginia SCC staff filed testimony in the renewable energy program RAC recommending incremental costs of $1 million to $6 million depending on whether 2008 and 2009 costs are includable. Hearings were held in October 2011. If the Virginia SCC were to disallow a portion of APCo's deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011. In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity. The approved settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In October 2009, APCo started injecting CO2 into the underground storage facilities. The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset. In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo's and WPCo's May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, in the first quarter of 2011, APCo recorded a pretax write-off of $41 million in Other Operation expense on the condensed statements of operations. See “2010 West Virginia Base Rate Case” section above. As of September 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF. If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. Management informed the DOE that it completed a Front-End Engineering and Design (FEED) study during the third quarter of 2011 and was postponing any further CCS project activities because of the uncertainty about the regulation of CO2. In June 2011, the FEED study costs were allocated among the AEP East companies, PSO and SWEPCo based on eligible plants that could potentially benefit from the carbon capture. Requests for recovery are in process in Indiana, Michigan and Virginia. In September 2011, a stipulation agreement was filed with the PUCO related to the ESP proceedings. The stipulation agreement withdrew a proposed rider to recover CSPCo's and OPCo's portion of the CCS facility costs. As a result, in September 2011, CSPCo and OPCo recorded pretax write-offs of $2 million and $7 million, respectively, in Other Operation expense on the condensed statements of income. A decision is pending from the PUCO. See the “Ohio Electric Security Plan Filings” section above. As of September 30, 2011, the project has incurred $34 million in total costs and has received $13 million of DOE eligible funding resulting in $21 million of net costs, of which $2 million and $7 million was written off by CSPCo and OPCo, respectively. The remaining net costs are recorded in Regulatory Assets on APCo's, I&M's, KPCo's, PSO's and SWEPCo's condensed balance sheets as follows:

Company	(in millions)
APCo	$	4
I&M		2
KPCo		1
PSO		1
SWEPCo		4

Total	$	12

If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

APCo's Filings for an IGCC Plant

In 2008, the Virginia SCC issued an order denying APCo's request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation. The order was based upon the Virginia SCC's finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of CCS facilities. During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional Certificate of Environmental Compatibility and Public Need granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.

Through September 30, 2011, 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.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. 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 September 2009, the WVPSC issued an order approving APCo's and WPCo's March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $96 million, including $10 million of construction surcharges related to APCo's and WPCo's second year ENEC increase. The settlement agreement allows APCo to accrue a weighted average cost of a capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving a $98 million annual increase including $8 million of construction surcharges and $8 million of carrying charges related to APCo's and WPCo's third year ENEC increase. The order also allows APCo to accrue a fixed annual carrying cost rate of 4%. The new rates became effective in July 2011. Additionally, the order approved APCo's request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery. APCo purchased the Dresden Plant at cost from AEGCo in August 2011 for $302 million. As of September 30, 2011, APCo's ENEC under-recovery balance was $380 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets. If the WVPSC were to disallow a portion of APCo's and WPCo's deferred ENEC costs, it could reduce 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 prudency 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. 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

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized accidental outage insurance proceeds. In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation. In March 2011, I&M filed its 2010 PSCR reconciliation with the MPSC. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

2011 Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on common equity of 11.15%. The request included an increase in depreciation rates that would result in a $6 million increase in annual depreciation expense.

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 request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC's direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006. Intervenors objected to the temporary SECA rates. 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 from 2004 through 2006 when the SECA rates terminated.

In 2006, a FERC Administrative Law Judge (ALJ) 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. The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

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 supports AEP's position and required a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC. In September 2011, the FERC issued orders that denied all parties' request for rehearing of the initial decision.

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 AEP East companies' 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 AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input. No filings have been made at the FERC. It is unknown at this time whether the AEP Power Pool 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.

In addition, in September 2011, a stipulation agreement was filed in the Ohio ESP proceeding which proposed to dissolve and/or modify the Interconnection Agreement. A decision from the PUCO regarding the stipulation agreement is expected in the fourth quarter of 2011. See “January 2012 - May 2016 ESP” section of the CSPCo and OPCo rate matters.

If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool 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.

PJM/MISO Market Flow Calculation Settlement Adjustments

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates. These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005. In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero. In June 2011, the FERC approved the settlement agreement.

Rate Matters [Abstract]

Rate Matters

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo's and OPCo's ESPs which established rates at the start of the April 2009 billing cycle through 2011. The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. In November 2009, the PUCO's order was appealed to the Supreme Court of Ohio (the Court). In April 2011, the Court issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. The order required CSPCo and OPCo to refund Provider of Last Resort (POLR) charges which were collected subject to refund since June 2011. According to the order, CSPCo and OPCo are required to apply the refund first to the FAC deferral with any remaining balance to be credited to CSPCo's and OPCo's customers in November and December 2011. As a result, in the third quarter of 2011, CSPCo and OPCo recorded pretax refund provisions of $34 million and $9 million, respectively, on the condensed statements of income. The PUCO order also agreed with CSPCo's and OPCo's position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in CSPCo's and OPCo's base generation rates. In addition, the PUCO rejected the intervenors' proposed adjustments to the FAC deferral balance for POLR charges and environmental carrying charges for the period from April 2009 through May 2011. This decision is subject to rehearing and appeal.

In April 2010, the Industrial Energy Users-Ohio (IEU) filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. In June 2011, the Court affirmed the PUCO's decision and dismissed the IEU's appeal.

In January 2011, the PUCO issued an order on CSPCo's and OPCo's 2009 SEET filings and determined that OPCo's 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered CSPCo to refund $43 million of its pretax earnings to customers, which was recorded as a revenue provision on CSPCo's December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo's FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo's customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011. In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO's SEET decisions.

In July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo will have any significantly excessive earnings. In October 2011, the Ohio Consumers' Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings. Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings.

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

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation. The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.

In September 2011, a stipulation agreement was filed with the PUCO by CSPCo, OPCo, the PUCO staff and multiple other parties which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. The FAC deferral as of September 30, 2011 was $542 million for OPCo, excluding $40 million of unrecognized equity carrying costs. CSPCo did not have a FAC deferral as of September 30, 2011. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo's and OPCo's SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo's and OPCo's generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. See the “Possible Termination of the Interconnection Agreement” section of FERC rate matters. The current FAC mechanism would continue through May 2015. Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations.

Various intervenors who did not sign the stipulation agreement filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the market-rate offer and that the proposed capacity charges to competitive retail suppliers are anti-competitive. Hearings on the stipulation agreement are ongoing. A decision from the PUCO is expected in the fourth quarter of 2011. If OPCo is not ultimately permitted to fully recover its FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of September 30, 2011 was $102 million and $66 million for CSPCo and OPCo, respectively, excluding $64 million and $48 million, respectively, of unrecognized equity carrying costs.

In September 2011, the PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million based upon a return on common equity range of 8.58% to 9.6%. In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. In July 2011, the FERC issued an order approving the proposed merger. In September 2011, a stipulation agreement was filed with the PUCO which recommended CSPCo merge into OPCo by the end of 2011. A decision from the PUCO is expected in the fourth quarter of 2011. See “January 2012 – May 2016 ESP” section above.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for CSPCo and OPCo for the period of January 2009 through December 2009. In May 2010, the outside consultant provided its confidential audit report to the PUCO. The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo's FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010. Hearings were held in August 2010. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit for CSPCo and OPCo. The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes. As of September 30, 2011, the amount of OPCo's carrying costs that could potentially be at risk is estimated to be $12 million, excluding $14 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, 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 filings and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio's April 2011 decision referenced in the “2009-2011 ESPs” section above. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo's and OPCo's FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and 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 CSPCo's and OPCo's November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo's and OPCo's ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. In June 2011, the Supreme Court of Ohio affirmed the PUCO's decision and dismissed the IEU's appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above. In August 2011, the Supreme Court of Ohio affirmed the PUCO's decision on the remaining issues.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs. As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively. The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. As of June 2011, there were no active IGCC projects at other AEP sites. In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest. 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 any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

3. RATE MATTERS

As discussed in the 2010 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 2010 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 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
				APCo				I&M
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
		Environmental Rate Adjustment Clause		$	73,335	$	55,724	$	-	$	-
		Deferred Wind Power Costs			39,882		28,584		-		-
		Storm Related Costs			25,225		25,225		-		-
		Mountaineer Carbon Capture and Storage
			Product Validation Facility		19,245		59,866		-		-
		Special Rate Mechanism for Century Aluminum			12,750		12,628		-		-
		Mountaineer Carbon Capture and Storage
			Commercial Scale Facility		3,681		-		2,440		-
		Litigation Settlement			-		-		10,732		-
		Other Regulatory Assets Not Yet Being Recovered			2,417		604		-		-
	Total Regulatory Assets Not Yet Being Recovered			$	176,535	$	182,631	$	13,172	$	-

				CSPCo				OPCo
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
	Regulatory assets not yet being recovered
		pending future proceedings to determine
		the recovery method and timing:
	Regulatory Assets Currently Earning a Return
		Line Extension Carrying Costs		$	39,034	$	33,709	$	24,962	$	21,246
		Customer Choice Deferrals			30,304		29,716		29,670		29,141
		Storm Related Costs			19,853		19,122		11,441		11,021
		Acquisition of Monongahela Power			8,955		7,929		-		-
		Economic Development Rider			6,201		3,057		6,200		3,057
		Other Regulatory Assets Not Yet Being Recovered			293		287		399		391
	Regulatory Assets Currently Not Earning a Return
		Acquisition of Monongahela Power			4,052		4,052		-		-
		Other Regulatory Assets Not Yet Being Recovered			51		43		68		58
	Total Regulatory Assets Not Yet Being Recovered			$	108,743	$	97,915	$	72,740	$	64,914

				PSO				SWEPCo
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
		Mountaineer Carbon Capture and Storage
			Commercial Scale Facility	$	1,117	$	-	$	3,456	$	-
		Storm Related Costs			-		17,256		-		1,239
		Other Regulatory Assets Not Yet Being Recovered			-		574		843		613
	Total Regulatory Assets Not Yet Being Recovered			$	1,117	$	17,830	$	4,299	$	1,852

Mountaineer Carbon Capture and Storage Project

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. Management informed the DOE that it completed a Front-End Engineering and Design (FEED) study during the third quarter of 2011 and was postponing any further CCS project activities because of the uncertainty about the regulation of CO2. In June 2011, the FEED study costs were allocated among the AEP East companies, PSO and SWEPCo based on eligible plants that could potentially benefit from the carbon capture. Requests for recovery are in process in Indiana, Michigan and Virginia. In September 2011, a stipulation agreement was filed with the PUCO related to the ESP proceedings. The stipulation agreement withdrew a proposed rider to recover CSPCo's and OPCo's portion of the CCS facility costs. As a result, in September 2011, CSPCo and OPCo recorded pretax write-offs of $2 million and $7 million, respectively, in Other Operation expense on the condensed statements of income. A decision is pending from the PUCO. See the “Ohio Electric Security Plan Filings” section above. As of September 30, 2011, the project has incurred $34 million in total costs and has received $13 million of DOE eligible funding resulting in $21 million of net costs, of which $2 million and $7 million was written off by CSPCo and OPCo, respectively. The remaining net costs are recorded in Regulatory Assets on APCo's, I&M's, KPCo's, PSO's and SWEPCo's condensed balance sheets. APCo's, I&M's, PSO's and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	3.7
I&M		2.4
PSO		1.1
SWEPCo		3.5

If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

FERC Rate Matters

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

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC's direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006. Intervenors objected to the temporary SECA rates. 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 from 2004 through 2006 when the SECA rates terminated. APCo's, CSPCo's, I&M's and OPCo's portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

In 2006, a FERC Administrative Law Judge (ALJ) 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. The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

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 supports AEP's position and required a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC. In September 2011, the FERC issued orders that denied all parties' request for rehearing of the initial decision.

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, CSPCo's, I&M's and OPCo's portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
CSPCo		7.8
I&M		8.3
OPCo		10.7

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 September 30, 2011 was $32 million. APCo's, CSPCo's, I&M's and OPCo's reserve balances as of September 30, 2011 were:

Company	September 30, 2011
	(in millions)
APCo	$	10.0
CSPCo		5.6
I&M		5.9
OPCo		7.6

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, CSPCo'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
CSPCo		3.5		1.8
I&M		3.7		1.9
OPCo		4.8		2.4

Based on the AEP East companies' 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, CSPCo, I&M and OPCo

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input. No filings have been made at the FERC. It is unknown at this time whether the AEP Power Pool 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.

In addition, in September 2011, a stipulation agreement was filed in the Ohio ESP proceeding which proposed to dissolve and/or modify the Interconnection Agreement. A decision from the PUCO regarding the stipulation agreement is expected in the fourth quarter of 2011. See “January 2012 - May 2016 ESP” section of CSPCo and OPCo rate matters.

If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool 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.

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates. These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005. In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero. In June 2011, the FERC approved the settlement agreement.

Rate Matters [Abstract]

Rate Matters

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo's and OPCo's ESPs which established rates at the start of the April 2009 billing cycle through 2011. The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. In November 2009, the PUCO's order was appealed to the Supreme Court of Ohio (the Court). In April 2011, the Court issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. The order required CSPCo and OPCo to refund Provider of Last Resort (POLR) charges which were collected subject to refund since June 2011. According to the order, CSPCo and OPCo are required to apply the refund first to the FAC deferral with any remaining balance to be credited to CSPCo's and OPCo's customers in November and December 2011. As a result, in the third quarter of 2011, CSPCo and OPCo recorded pretax refund provisions of $34 million and $9 million, respectively, on the condensed statements of income. The PUCO order also agreed with CSPCo's and OPCo's position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in CSPCo's and OPCo's base generation rates. In addition, the PUCO rejected the intervenors' proposed adjustments to the FAC deferral balance for POLR charges and environmental carrying charges for the period from April 2009 through May 2011. This decision is subject to rehearing and appeal.

In April 2010, the Industrial Energy Users-Ohio (IEU) filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. In June 2011, the Court affirmed the PUCO's decision and dismissed the IEU's appeal.

In January 2011, the PUCO issued an order on CSPCo's and OPCo's 2009 SEET filings and determined that OPCo's 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered CSPCo to refund $43 million of its pretax earnings to customers, which was recorded as a revenue provision on CSPCo's December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo's FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo's customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011. In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO's SEET decisions.

In July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo will have any significantly excessive earnings. In October 2011, the Ohio Consumers' Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings. Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings.

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

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation. The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.

In September 2011, a stipulation agreement was filed with the PUCO by CSPCo, OPCo, the PUCO staff and multiple other parties which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. The FAC deferral as of September 30, 2011 was $542 million for OPCo, excluding $40 million of unrecognized equity carrying costs. CSPCo did not have a FAC deferral as of September 30, 2011. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo's and OPCo's SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo's and OPCo's generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. See the “Possible Termination of the Interconnection Agreement” section of FERC rate matters. The current FAC mechanism would continue through May 2015. Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations.

Various intervenors who did not sign the stipulation agreement filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the market-rate offer and that the proposed capacity charges to competitive retail suppliers are anti-competitive. Hearings on the stipulation agreement are ongoing. A decision from the PUCO is expected in the fourth quarter of 2011. If OPCo is not ultimately permitted to fully recover its FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of September 30, 2011 was $102 million and $66 million for CSPCo and OPCo, respectively, excluding $64 million and $48 million, respectively, of unrecognized equity carrying costs.

In September 2011, the PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million based upon a return on common equity range of 8.58% to 9.6%. In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. In July 2011, the FERC issued an order approving the proposed merger. In September 2011, a stipulation agreement was filed with the PUCO which recommended CSPCo merge into OPCo by the end of 2011. A decision from the PUCO is expected in the fourth quarter of 2011. See “January 2012 – May 2016 ESP” section above.

Sporn Unit 5

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding. In April 2011, intervenors filed comments opposing OPCo's application. A PUCO decision is pending as to whether a hearing will be ordered.

In the third quarter of 2011, management decided to no longer offer Sporn Unit 5 into the PJM market. Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the AEP Power Pool. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the condensed statements of income.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for CSPCo and OPCo for the period of January 2009 through December 2009. In May 2010, the outside consultant provided its confidential audit report to the PUCO. The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo's FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010. Hearings were held in August 2010. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit for CSPCo and OPCo. The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes. As of September 30, 2011, the amount of OPCo's carrying costs that could potentially be at risk is estimated to be $12 million, excluding $14 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, 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 filings and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio's April 2011 decision referenced in the “2009-2011 ESPs” section above. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo's and OPCo's FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and 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 CSPCo's and OPCo's November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo's and OPCo's ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. In June 2011, the Supreme Court of Ohio affirmed the PUCO's decision and dismissed the IEU's appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above. In August 2011, the Supreme Court of Ohio affirmed the PUCO's decision on the remaining issues.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs. As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively. The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. As of June 2011, there were no active IGCC projects at other AEP sites. In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest. 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 any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

3. RATE MATTERS

As discussed in the 2010 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 2010 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 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
				APCo				I&M
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
		Environmental Rate Adjustment Clause		$	73,335	$	55,724	$	-	$	-
		Deferred Wind Power Costs			39,882		28,584		-		-
		Storm Related Costs			25,225		25,225		-		-
		Mountaineer Carbon Capture and Storage
			Product Validation Facility		19,245		59,866		-		-
		Special Rate Mechanism for Century Aluminum			12,750		12,628		-		-
		Mountaineer Carbon Capture and Storage
			Commercial Scale Facility		3,681		-		2,440		-
		Litigation Settlement			-		-		10,732		-
		Other Regulatory Assets Not Yet Being Recovered			2,417		604		-		-
	Total Regulatory Assets Not Yet Being Recovered			$	176,535	$	182,631	$	13,172	$	-

				CSPCo				OPCo
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
	Regulatory assets not yet being recovered
		pending future proceedings to determine
		the recovery method and timing:
	Regulatory Assets Currently Earning a Return
		Line Extension Carrying Costs		$	39,034	$	33,709	$	24,962	$	21,246
		Customer Choice Deferrals			30,304		29,716		29,670		29,141
		Storm Related Costs			19,853		19,122		11,441		11,021
		Acquisition of Monongahela Power			8,955		7,929		-		-
		Economic Development Rider			6,201		3,057		6,200		3,057
		Other Regulatory Assets Not Yet Being Recovered			293		287		399		391
	Regulatory Assets Currently Not Earning a Return
		Acquisition of Monongahela Power			4,052		4,052		-		-
		Other Regulatory Assets Not Yet Being Recovered			51		43		68		58
	Total Regulatory Assets Not Yet Being Recovered			$	108,743	$	97,915	$	72,740	$	64,914

				PSO				SWEPCo
				September 30,		December 31,		September 30,		December 31,
				2011		2010		2011		2010
	Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
		Mountaineer Carbon Capture and Storage
			Commercial Scale Facility	$	1,117	$	-	$	3,456	$	-
		Storm Related Costs			-		17,256		-		1,239
		Other Regulatory Assets Not Yet Being Recovered			-		574		843		613
	Total Regulatory Assets Not Yet Being Recovered			$	1,117	$	17,830	$	4,299	$	1,852

Mountaineer Carbon Capture and Storage Project

Carbon Capture and Sequestration Project with the Department of Energy (DOE) (Commercial Scale Project)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. Management informed the DOE that it completed a Front-End Engineering and Design (FEED) study during the third quarter of 2011 and was postponing any further CCS project activities because of the uncertainty about the regulation of CO2. In June 2011, the FEED study costs were allocated among the AEP East companies, PSO and SWEPCo based on eligible plants that could potentially benefit from the carbon capture. Requests for recovery are in process in Indiana, Michigan and Virginia. In September 2011, a stipulation agreement was filed with the PUCO related to the ESP proceedings. The stipulation agreement withdrew a proposed rider to recover CSPCo's and OPCo's portion of the CCS facility costs. As a result, in September 2011, CSPCo and OPCo recorded pretax write-offs of $2 million and $7 million, respectively, in Other Operation expense on the condensed statements of income. A decision is pending from the PUCO. See the “Ohio Electric Security Plan Filings” section above. As of September 30, 2011, the project has incurred $34 million in total costs and has received $13 million of DOE eligible funding resulting in $21 million of net costs, of which $2 million and $7 million was written off by CSPCo and OPCo, respectively. The remaining net costs are recorded in Regulatory Assets on APCo's, I&M's, KPCo's, PSO's and SWEPCo's condensed balance sheets. APCo's, I&M's, PSO's and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	3.7
I&M		2.4
PSO		1.1
SWEPCo		3.5

If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

FERC Rate Matters

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

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC's direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006. Intervenors objected to the temporary SECA rates. 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 from 2004 through 2006 when the SECA rates terminated. APCo's, CSPCo's, I&M's and OPCo's portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

In 2006, a FERC Administrative Law Judge (ALJ) 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. The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

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 supports AEP's position and required a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC. In September 2011, the FERC issued orders that denied all parties' request for rehearing of the initial decision.

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, CSPCo's, I&M's and OPCo's portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
CSPCo		7.8
I&M		8.3
OPCo		10.7

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 September 30, 2011 was $32 million. APCo's, CSPCo's, I&M's and OPCo's reserve balances as of September 30, 2011 were:

Company	September 30, 2011
	(in millions)
APCo	$	10.0
CSPCo		5.6
I&M		5.9
OPCo		7.6

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, CSPCo'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
CSPCo		3.5		1.8
I&M		3.7		1.9
OPCo		4.8		2.4