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Rate Matters

12 Months Ended

Dec. 31, 2011

3. RATE MATTERS

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

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018 or until securitized. The net FAC deferral as of December 31, 2011 was $521 million, excluding unrecognized equity carrying costs. Collection of the FAC began in January 2012. 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. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. The order required OPCo to cease POLR billings and apply POLR collections since June 2011 first to the FAC deferral with any remaining balance to be credited to OPCo's customers in November and December 2011. As a result, OPCo recorded a pretax write-off of $47 million on the statement of income related to POLR for the period June 2011 through October 2011. OPCo ceased collection of POLR billings in November 2011. The PUCO order also agreed with OPCo's position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in 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. In February 2012, the Ohio Consumers' Counsel (OCC) and the Industrial Energy Users-Ohio (IEU) filed appeals with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 Significantly Excessive Earnings Test (SEET) filing and determined that 2009 earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered a $43 million refund of pretax earnings to customers, which was recorded in OPCo's 2010 statement of income. The PUCO ordered that the significantly excessive earnings be applied first to the FAC deferral, as of the date of the order, with any remaining balance to be credited to customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and continued through December 2011. In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO's SEET decision. The OEG's appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET, which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation. The IEU's appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount. Management is unable to predict the outcome of the appeals. If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. In the fourth quarter of 2011, OPCo provided a reserve based upon management's estimate of the probable amount for a PUCO ordered SEET refund.

OPCo is required to file its 2011 SEET filing with the PUCO in 2012. Management does not currently believe that there are significantly excessive earnings in 2011. 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, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. The filed ESP also included alternative energy resource requirements and addressed provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.

In December 2011, a modified stipulation was approved by the PUCO which involved various issues pending before the PUCO. Various parties, including OPCo, filed requests for rehearing with the PUCO. In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved. Under the February 2012 rehearing order, OPCo has 30 days to notify the PUCO whether it plans to modify or withdraw its original application as filed in January 2011. Management is currently evaluating its options and the potential financial and operational impacts on OPCo.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012. In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR). See the “January 2012 – May 2016 ESP” section above. The stipulation also approved recovery of certain distribution regulatory assets of $173 million as of December 31, 2011, excluding $154 million of unrecognized equity carrying costs. These assets and unrecognized carrying costs will be recovered in a distribution asset recovery rider over seven years with an additional long term debt carrying charge, effective January 2012.

Due to the February 2012 PUCO ESP entry on rehearing which rejected the modified stipulation for a new ESP, collection of the DIR terminated. OPCo has the right to withdraw from the stipulation in the distribution base rate case. Management is currently evaluating all its options. If OPCo is not ultimately permitted to fully recover its costs and deferrals, it would reduce future net income and cash flows and impact financial condition.

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 the third quarter of 2011, management decided to no longer offer the output of 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 statement of income. In January 2012, the PUCO issued an order which denied recovery of a new non-bypassable distribution rider and declined to exercise jurisdiction over the closure of Sporn Unit 5.

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 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, of which approximately $7 million was the retail jurisdictional share which reduced the FAC deferral in 2009 and 2010.

In January 2012, the PUCO ordered that the remaining $65 million in proceeds from the 2008 coal contract settlement be applied against OPCo's under-recovered fuel balance pending a PUCO decision in OPCo's February 2012 rehearing request. OPCo's rehearing request stated that no additional gain should be credited to the FAC or at most only the retail share of the $58 million gain be applied to the FAC, which approximated $30 million. Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of the consultant's recommendation. If the PUCO ultimately determines that additional amounts related to the coal reserve valuation should benefit ratepayers, it could 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 OPCo. The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes. As of December 31, 2011, the amount of OPCo's carrying costs that could potentially be at risk is estimated to be $15 million, excluding $17 million of unrecognized equity carrying costs. 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

OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferral is included in OPCo's FAC phase-in deferral balance. In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement and this issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

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. 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 in the 2009 EDR appeal. In addition, the IEU added a claim that 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 its 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, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through December 31, 2011, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order and has incurred pre-construction costs. 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 OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $122 million for transmission, excluding AFUDC. SWEPCo's share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $122 million for transmission, excluding AFUDC. As of December 31, 2011, excluding costs attributable to its joint owners and a provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.4 billion of expenditures (including AFUDC and capitalized interest of $220 million and related transmission costs of $104 million). As of December 31, 2011, the joint owners and SWEPCo have contractual construction obligations of approximately $125 million (including related transmission costs of $8 million). SWEPCo's share of the contractual construction obligations is $94 million.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. SWEPCo 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.

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. In November 2011, the Texas Court of Appeals affirmed the PUCT's order in all respects. As a result, in the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the estimated excess of the Texas jurisdictional portion of the Turk Plant above the Texas jurisdictional capital costs cap. In December 2011, SWEPCo and the Texas Industrial Energy Consumers filed motions for rehearing at the Texas Court of Appeals which were denied in January 2012. SWEPCo intends to seek review of the Texas Court of Appeals decision at the Supreme Court of Texas.

Several parties, including the Hempstead County Hunting Club, the Sierra Club and the National Audubon Society had challenged the air permit, the wastewater discharge permit and the wetlands permit that were issued for the Turk Plant. Those parties also sought a temporary restraining order and preliminary injunction to stop construction of the Turk Plant. The motion for preliminary injunction was partially granted in 2010. In 2011, SWEPCo entered into settlement agreements with these parties which resolved all outstanding issues related to the permits and the APSC's grant of a CECPN. The parties dismissed all pending permit and CECPN challenges at the APSC, other administrative agencies and the courts.

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 plan from the PUCT for including the Turk Plant investment in Texas retail rates. SWEPCo's application was dismissed in December 2011. The PUCT stated that, as a matter of policy, the PUCT would not order a return on CWIP outside of a full base rate case proceeding. SWEPCo intends to file a full base rate case in 2012 with a proposed rate increase closely aligned with the commercial operation date of the Turk Plant.

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 issued its opinion reversing the PUCT's 2006 order denying recovery of capacity auction true-up amounts and remanding for reconsideration the treatment of certain tax balances under normalization rules. In December 2011, the PUCT approved an unopposed stipulation allowing TCC to recover $800 million, including carrying charges, and retain contested tax balances in full satisfaction of its true-up proceeding. The following actions resulted from these decisions:

Based upon the Supreme Court of Texas' reversal of the PUCT's capacity auction true-up disallowance, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the third quarter of 2011.
In 2011, TCC recorded $271 million in pretax Carrying Costs Income on the statement of income related to the debt component of carrying costs for the period from January 2002 through December 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 December 31, 2011 was $692 million, excluding unrecognized equity carrying costs. TCC plans to continue to recognize debt carrying costs income until securitization occurs and plans to recognize equity carrying costs income as collected from customers over the life of the securitization.
The PUCT allowed TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges. TCC recorded the reversal of regulatory credits of $65 million ($42 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the fourth quarter of 2011. Also, in the fourth quarter of 2011, TCC recorded $52 million in pretax Carrying Costs Income on the statement of income. TCC also recorded the reversal of $89 million of accumulated deferred investment tax credits ($58 million, net of tax) in Extraordinary Items, Net of Tax on the statement of income in the fourth quarter of 2011. See the “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” section below.
The Supreme Court of Texas reversed the Texas Court of Appeals' 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 the 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 the financial statements.
The Supreme Court of Texas reversed the Texas Court of Appeals' 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.
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 the financial statements and were not addressed in the remand proceeding.

The approved stipulation resolved all remaining issues in these dockets. In December 2011, TCC filed an application with the PUCT for a financing order to recover the $800 million through the issuance of securitization bonds as permitted by Texas statutory provisions. In January 2012, the PUCT approved the request. TCC anticipates issuing the bonds in March 2012.

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 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 tax normalization issue was remanded to the PUCT for its consideration of additional evidence including the IRS regulations. In December 2011, the PUCT approved an unopposed stipulation allowing TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges, in final resolution of this issue. See the “Texas Restructuring Appeals” section above.

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 agreed to dismiss its claims as part of the stipulation approved by the PUCT in the true-up proceeding. See the “Texas Restructuring Appeals” section above. The dismissal did not have any impact on TCC's rate recovery as this was already reflected in the financial statements.

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. The return on common equity included a requested 0.5% renewable portfolio standards (RPS) incentive as allowed by law.

In November 2011, the Virginia SCC issued an order which approved a $55 million increase in generation and distribution base rates, effective February 2012, and a 10.9% return on common equity, which included a 0.5% RPS incentive. The $55 million increase included $39 million related to an increase in depreciation rates.

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 December 31, 2011, APCo has deferred $24 million of environmental costs, excluding $6 million of unrecognized equity carrying costs, incurred from January 2009 through December 2010, $18 million of environmental costs, excluding $4 million of unrecognized equity carrying costs, incurred in 2011 and $44 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. The environmental RAC requested recovery of $77 million of incremental environmental compliance costs incurred from January 2009 through December 2010. The renewable energy program RAC requested recovery of $6 million for the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects through December 2010. The generation RAC requested recovery of the Dresden Plant, which was placed into service in January 2012. With Virginia SCC approval, APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million.

In August 2011, a stipulation was filed with the Virginia SCC related to the generation RAC. The stipulation requested recovery of the Dresden Plant costs totaling up to $27 million annually, effective March 2012. In January 2012, the Virginia SCC issued an order which modified and approved the stipulation to allow APCo to recover $26 million annually, effective March 2012.

In November 2011, the Virginia SCC issued an order which approved recovery of $6 million for the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects, effective February 2012. In addition, the order found that APCo can recover the non-incremental deferred wind power costs of $27 million as of December 31, 2011 through the FAC.

Also in November 2011, the Virginia SCC issued an order which approved environmental RAC recovery of $30 million to be collected over one year beginning in February 2012. The Virginia SCC denied recovery of certain environmental costs. As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010. In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding the Virginia SCC's environmental RAC decision. If the Virginia SCC were to disallow a portion of APCo's deferred environmental compliance costs incurred since January 2011, 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 upon an 11.75% return on common equity. 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, effective April 2011. The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in March 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.

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. See “2010 West Virginia Base Rate Case” section above. In 2011, APCo recorded a net pretax write-off of $14 million in Other Operation expense on the statement of income related to the write-off of a portion of the West Virginia jurisdictional share of the PVF offset by an asset retirement obligation adjustment. As of December 31, 2011, APCo has recorded $14 million in Regulatory Assets on the balance sheet 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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, APCo has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheet. 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

Through December 31, 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 from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery. APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million. As of December 31, 2011, APCo's ENEC under-recovery balance of $359 million was recorded in Regulatory Assets on the balance sheet, excluding $7 million of unrecognized equity carrying costs. 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 prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the Oklahoma Industrial Energy Consumers (OIEC) recommended the fuel clause adjustment rider be amended so that the shareholder's portion of off-system sales margins decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate fuel transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed. The testimony included unquantified refund recommendations relating to re-pricing of those ERCOT trading contracts. Hearings were held in June 2011. 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) Reconciliation (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 Cook Plant Unit 1 (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 November 2011, the MPSC approved a settlement agreement for the 2010 PSCR reconciliation which resolved the Unit 1 outage issue by ordering no disallowances associated with the Unit 1 outage issue. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 5.

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. An interim rate increase of $16 million annually was implemented in January 2012, subject to refund.

In February 2012, the MPSC approved a settlement agreement which increased annual base rates by approximately $15 million, effective April 2012, based upon a return on common equity of 10.2% and included a $5 million annual increase in depreciation rates. The approved settlement agreement also excluded the Michigan jurisdictional share of the net costs of the Cook Plant Unit 1 (Unit 1) turbine replacement from rate base but provided for a return on and of the net cost as a regulatory asset, effective February 2012. As of December 31, 2011, the Michigan jurisdictional share of the net costs of the Unit 1 turbine replacement was $9 million. Future rate recovery of the regulatory asset will be reviewed in a future rate proceeding.

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

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

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

Possible Termination of the Interconnection Agreement

In December 2010, each of the 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. In February 2012, an application was filed with the FERC proposing to establish a new power cost sharing agreement between APCo, I&M and KPCo. 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. As a result of the February 2012 ESP rehearing order, management is in the process of withdrawing the PUCO and FERC applications. See “January 2012 – May 2016 ESP” section of the OPCo rate matters.

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.

Appalachian Power Co [Member]

Rate Matters [Abstract]

Rate Matters

2011 Virginia Biennial Base Rate Case

Rate Adjustment Clauses

APCo's Filings for an IGCC Plant

3. RATE MATTERS

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

APCo Rate Matters

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase APCo's annual base rates by $140 million based upon an 11.75% return on common equity. In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity, effective April 2011. The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in March 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 $14 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)

In APCo's May 2010 West Virginia base rate filing, APCo 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. See “2010 West Virginia Base Rate Case” section above. In 2011, APCo recorded a net pretax write-off of $14 million in Other Operation expense on the statements of income related to the write-off of a portion of the West Virginia jurisdictional share of the PVF offset by an asset retirement obligation adjustment. As of December 31, 2011, APCo has recorded $14 million in Regulatory Assets on the balance sheets 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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, the project has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheets. APCo's, I&M's, and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	1.3
I&M		1.7
SWEPCo		2.4

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

APCo's 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo'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 $320 million and a first-year increase of $112 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges related to APCo's second year ENEC increase. The settlement agreement allows APCo to accrue a weighted average cost of 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 an $88 million annual increase including $7 million of construction surcharges and $7 million of carrying charges related to APCo'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 from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery. APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million. As of December 31, 2011, APCo's ENEC under-recovery balance of $359 million was recorded in Regulatory Assets on the balance sheet, excluding $7 million of unrecognized equity carrying costs. If the WVPSC were to disallow a portion of APCo's deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

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

FERC Rate Matters

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

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

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

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

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

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

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue. Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million. The balance in the reserve for future settlements as of December 31, 2011 was $32 million. APCo's, I&M's and OPCo's reserve balances as of December 31, 2011 were:

Company	December 31, 2011
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

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

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

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

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

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

Indiana Michigan Power Co [Member]

Rate Matters [Abstract]

Rate Matters

I&M Rate Matters

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

2011 Michigan Base Rate Case

2011 Indiana Base Rate Case

3. RATE MATTERS

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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, the project has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheets. APCo's, I&M's, and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	1.3
I&M		1.7
SWEPCo		2.4

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, I&M and OPCo

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

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

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

Company	December 31, 2011
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

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

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

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

Ohio Power Co [Member]

Rate Matters [Abstract]

Rate Matters

2011 Ohio Distribution Base Rate Case

Sporn Unit 5

2009 Fuel Adjustment Clause Audit

2010 Fuel Adjustment Clause Audit

Ormet Interim Arrangement

Economic Development Rider

Ohio IGCC Plant

3. RATE MATTERS

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018 or until securitized. The net FAC deferral as of December 31, 2011 was $507 million, excluding unrecognized equity carrying costs. Collection of the FAC began in January 2012. 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. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

January 2012 – May 2016 ESP

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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, the project has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheets. APCo's, I&M's, and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	1.3
I&M		1.7
SWEPCo		2.4

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, I&M and OPCo

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

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

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

Company	December 31, 2011
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

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

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

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

Public Service Co Of Oklahoma [Member]

Rate Matters [Abstract]

Rate Matters

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

3. RATE MATTERS

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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, the project has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheets. APCo's, I&M's, and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	1.3
I&M		1.7
SWEPCo		2.4

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

FERC Rate Matters

Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo

PSO, SWEPCo and TNC are parties to the TCA, originally dated January 1, 1997, as amended. The TCA provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the Open Access Transmission Tariff (OATT).

In April 2011, the FERC accepted proposed revisions to the TCA. Under this amendment, TNC was removed from the TCA. In addition, the amended TCA provides for the allocation of SPP OATT revenues between PSO and SWEPCo based on the SPP formula rate revenue requirements for transmission investment and related expenses of each company. The amended TCA was effective May 1, 2011.

Southwestern Electric Power Co [Member]

Rate Matters [Abstract]

Rate Matters

Texas Turk Plant Rate Plan

3. RATE MATTERS

SWEPCo Rate Matters

Turk Plant

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. In November 2011, the Texas Court of Appeals affirmed the PUCT's order in all respects. As a result, in the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairment and Other Related Charges on the statement of income related to the estimated excess of the Texas jurisdictional portion of the Turk Plant above the Texas jurisdictional capital costs cap. In December 2011, SWEPCo and the Texas Industrial Energy Consumers filed motions for rehearing at the Texas Court of Appeals which were denied in January 2012. SWEPCo intends to seek review of the Texas Court of Appeals decision at the Supreme Court of Texas.

Several parties, including the Hempstead County Hunting Club (Hunting Club), the Sierra Club and the National Audubon Society had challenged the air permit, the wastewater discharge permit and the wetlands permit that were issued for the Turk Plant. Those parties also sought a temporary restraining order and preliminary injunction to stop construction of the Turk Plant. The motion for preliminary injunction was partially granted in 2010. In 2011, SWEPCo entered into settlement agreements with these parties which resolved all outstanding issues related to the permits and the APSC's grant of a CECPN. The parties dismissed all pending permit and CECPN challenges at the APSC, other administrative agencies and the courts.

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.

Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo's Louisiana retail FAC recommending that the LPSC discontinue SWEPCo's tiered sharing mechanism related to the off-system sales margins and reduce the FAC. In April 2011, a settlement agreement was filed with the LPSC which resulted in an immaterial impact for SWEPCo. The settlement agreement deferred the off-system sales issue to SWEPCo's formula rate plan (FRP) extension filing, which was filed in January 2012. In June 2011, the LPSC approved the settlement agreement.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year FRP. SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%. In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund. During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors. SWEPCo began refunding customers in August 2010. In March 2011, the LPSC approved the settlement stipulation.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009. SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund. Consultants for the LPSC objected to certain components of SWEPCo's FRP calculation. A settlement stipulation was reached by the parties and approved by the LPSC in March 2011. The settlement stipulation provided for a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's balance sheets. The refund to customers, with interest, began in August 2011.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund. In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo's FRP calculations. Hearings are scheduled for May 2012. SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC. If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows.

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. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study was completed during the third quarter of 2011. Management postponed 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. As of December 31, 2011, the project has incurred $34 million in total project costs and has received $20 million of DOE and other eligible funding resulting in $14 million of net costs, of which $8 million was written off. The remaining $6 million in net costs are recorded in Regulatory Assets on the balance sheets. APCo's, I&M's, and SWEPCo's portions of remaining net costs are as follows:

Company	(in millions)
APCo	$	1.3
I&M		1.7
SWEPCo		2.4

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

FERC Rate Matters

Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo