Fitch Affirms American Electric Power and Subs; Outlook Stable

NEW YORK--()--Fitch Ratings has affirmed the ratings of American Electric Power Company, Inc. (AEP) and certain subsidiaries. The Issuer Default Rating (IDR) for AEP is 'BBB'. The Rating Outlook is Stable. A complete list of rating actions is provided at the end of this release.

The rating affirmation for AEP reflects its diverse and low-risk business profile based on ownership of regulated utilities, growing investment in the regulated businesses, and predictable cash flow. Fitch's assumptions for the current rating affirmation exclude the sale of any non-core businesses.

The Rating Outlook for AEP and its Fitch-rated subsidiaries is Stable and reflects solid liquidity, manageable but growing capex, strong capital market access. The Stable Outlook also reflects Fitch's expectation that capex will be funded in a manner to preserve its regulatory capital structure commensurate with their current credit profiles. Fitch expects AEP's subsidiaries will continue to seek timely recovery of its invested capital and receive constructive regulatory outcomes.

KEY RATING DRIVERS

Diversified Business Profile: AEP's ownership of nine regulated electric utilities operating in 11 states and growing investments in FERC-regulated transmission projects provide regulatory, geographic and cash flow diversity and a low business-risk profile. Fitch considers management's strategic focus on growth through investment in regulated distribution and transmission businesses to be key rating drivers. Fitch forecasts that approximately 90% of AEP's consolidated EBITDA, through 2017, will be provided by its regulated businesses, including the FERC-regulated transmission networks.

Large Capex Spending: Fitch's rating model includes management's forecasted capex spending of about $4.4 billion in 2015, $3.8 billion in 2016, and $3.9 billion in 2017, significantly higher than average annual expenditures of about $2.3 billion during 2011 - 2014. Approximately 25% of annual capex spending through 2017 targets FERC-regulated transmission, providing a relatively high and predictable returns on investment.

Fitch expects AEP to fund capex with a combination of internal cash flow and parent and utility debt. Negative FCF at AEP's utility subsidiaries will likely be financed with a mix of debt and equity infusions by the parent to maintain the regulatory capital structure. Fitch estimates about 30-35% of new investment will receive relatively current recoveries, including investment in FERC regulated transmission and typical regulatory lag for the remainder of the capex.

Key Financial Metrics: Consolidated 2014 credit metrics of adjusted debt to FFO of 3.6x, adjusted debt to EBITDAR of 3.8x and FFO fixed charge coverage of 4.3x were in line with AEP's rating level. Consolidated FFO-based credit measures through 2017 are estimated by Fitch to decline in the absence of bonus depreciation related cash tax benefits but remain within Fitch's guidelines for the assigned IDR. Fitch forecasts consolidated FFO fixed coverage will range between 4.0x and 4.3x and consolidated adjusted debt to FFO will be around 4.8x through 2017. Debt/EBITDAR is expected to remain modestly higher compared to similarly rated peers at between 4.0x and 4.3x through 2017 driven by the large capex program and regulatory lag.

Challenging Merchant Business Environment: Low electricity demand and a weak pricing environment will persist over the forecast period (2015-2017), in Fitch's opinion, pressuring margins on AEP's merchant business. In addition, the cost to comply with stricter environmental regulations for the company's predominantly coal fired fleet will further increase merchant risk. To lower merchant risk, management is currently engaged with Ohio regulators to seek long-term contracts for its in-state power plants. Simultaneously, management has engaged advisors to explore a potential divestment of its merchant power business. These endeavors, if successful, would further strengthen AEP's credit profile. AEP is also evaluating sale of its barge business; divesture of this business would be a modest positive for AEP's consolidated business risk profile.

A Balanced Regulatory Construct: Fitch views the state regulatory construct as balanced within AEP's service territories. Returns on equity (ROE) tend to be close to the industry average and in each case include provisions to mitigate commodity and environmental regulation risks and in some instances current recovery of certain investments. Management expects the earned ROE for regulated operations to improve from 9% to 9.6% with the implementation of new retail rate increases based on approved GRC applications in certain jurisdictions (Kentucky, Louisiana, Oklahoma, Texas, and West Virginia) and rider mechanisms in other jurisdictions (Indiana, Ohio, Oklahoma, and West Virginia)

Ties with AEP: All operating subsidiaries have operational, financial and functional ties to AEP - the parent holding company. The utility subsidiaries rated one notch higher than AEP reflect their lower risk and stronger standalone profile than that of AEP and generally favorable service area economies. All subsidiaries remain dependent on AEP for short-term liquidity and they participate in the AEP money pool, adding a moderate degree of linkage.

Parental Liquidity Support: Financial and functional ties of AEP's regulated operating subsidiaries to AEP are supportive of their credit risk profile. These utilities participate in AEP's utility money pool and are a part of AEP's treasury function. The utility pool allows utilities to manage working capital needs and provides short-term financing to utilities within AEP's family of companies. The breadth of AEP's liquidity and its access to capital markets are key features of the parental liquidity support.

Appalachian Power Company (APCO)

Improving Credit Metrics: APCO's credit protection measures at the end of December 2014 were consistent with its rating level. As of Dec. 31, 2014, FFO fixed-charge coverage was about 4x. Debt/EBITDAR and FFO adjusted debt, was 3.8x and 4.3x, respectively. Fitch expects Debt/EBITDAR to remain around 3.9x between 2015 and 2017 and adjusted debt to FFO to modestly increase to about 4.5x for the same period, mainly reflecting absence of bonus depreciation. Fitch's financial assumptions include a constructive outcome of APCO's GRC in West Virginia, including recovery of deferred storm costs.

Regulatory Overview: Fitch considers the regulatory environment in West Virginia, which accounts for about 48% of rate base, to be somewhat restrictive. The West Virginia Public Service Commission (WVPSC) has not only authorized below average ROEs, but has utilized consolidated tax adjustments to reduce the rate base and earnings capacity.

In its GRC application filed in June 2014, APCO is requesting the WVPSC to approve $156 million increase in retail rates, based on 10.62% ROE, to recover new rate base investments and changes in the depreciable lives of certain assets. APCO is also requesting deferred storm costs of $77 million over five years and about $38 million in annual vegetation management. Fitch has included a conservative forecast for retail rate increases in West Virginia consistent with previous GRC outcomes. A final decision is expected by mid-2015.

Favorably, in December 2014, the WVPSC approved a base rate surcharge of $93 million for APCO to recover its investment in Mitchell coal power plant with the surcharge increasing by about $20 million in 2020. In approving the settlement, the WVPSC required APCO to share its energy margins proportionally with its affiliate Wheeling Power Company (not rated by Fitch). The regulatory environment in Virginia has been far more constructive; however, new legislation signed into law by the Governor in February 2015, has postponed the biennial review of Virginia utilities, including APCO, until 2020 and has frozen retail rates until the next review. The next rate case will be filed in 2020 with new retail rates effective 2021. Fitch does not expect the legislative changes to significantly affect APCO's financial performance through 2017 given the effectiveness of AEP's current cost reduction program and the economic stability/growth in APCO's service territory, in Fitch's opinion.

Large Capex: Fitch expects APCO's capex to remain high through 2017. Management's current capex forecast over 2015-2017 includes about $1 billion for distribution and transmission network reinforcement and an additional $300 million of environmental upgrades.

In addition, with over 75% of APCO's generating capacity derived from coal fired generation, the company is exposed to pending carbon regulations (excluded from the above capex). Even though, the current regulatory construct in APCO's service territory allows for recovery of these costs, timely recovery could be challenging given the substantial capital investment that will be required to upgrade or replace existing capacity.

Indiana Michigan Power Company (IMPCO):

Large Capex Cycle: A large $1.5 billion capex plan over next three years is expected by Fitch to pressure credit protection measures. The three-year capex plan includes approximately $640 million for the life extension of the Cook nuclear plant. About 65% of the life extension expenditures are attributable to Indiana and recoverable through a rider mechanism partly mitigating the adverse credit impact. The remainder is attributable to Michigan and is not recoverable until the life extension project is complete, which is currently estimated to be in 2018. The project has been approved by Michigan regulators but will require a general rate case filing to recover the estimated $500 million attributable to the Michigan jurisdiction. Current ratings assume a constructive outcome in Michigan.

Weakening Credit Metrics: Due to the large capex plan and external funding requirements Fitch expects debt/EBITDAR to increase to 4.5x by 2017 from 4.1x in 2014, which is somewhat weak for the current rating level. However, adjusted FFO leverage is expected to remain within Fitch's guidelines for IMPCO's current IDR, while weakening from 3.2x in 2014 to an estimated 4x at the end of 2017. The erosion to IMPCO's FFO leverage reflects the absence of bonus depreciation for tax purposes and higher interest expense mitigated by timely recovery of nuclear life extension investment in Indiana.

KPCO:

Improving Credit Metrics: KPCO's credit metrics expected by Fitch to improve due to the anticipated approval of KPCO's pending GRC application. Fitch expects KPCO's adjusted debt/FFO will remain around 4.1x and adjusted debt/EBITDAR to range between 3.5x and 4x for the 2015 - 2017 forecast period. As of Dec. 31, 2014, FFO adjusted debt and debt/EBITDAR, were 4.0x and 4.6x respectively. These ratios are in line with Fitch's guidelines for KPCO's current ratings. The FFO fixed-charge coverage ratio is estimated by Fitch to range between 4.1x - 4.4x over the 2015-2017 period.

Regulatory Activity: KPCO filed a GRC application seeking a $70 million rate increase related to the Mitchell Power plant acquisition and recovery of the unamortized costs of its Big Sandy coal plant, which will be retired later this year. New retail rates are expected to be effective in the latter part of 2015.

Manageable Capex: Fitch expects capex to decline, relative to historical levels through 2017. Current capex plan includes conversion of an existing coal plant to natural gas that already has received regulatory approval and reinforcement of its electricity distribution networks. Compliance with more stringent environmental rules is a concern for investors given that the company's generating capacity is 100% coal-fired.

Ohio Public Co. (OPCO)

Constructive Regulatory Settlement: The recently approved Electricity Security Plan (ESP) by the public utility commission of Ohio (PUCO) is supportive of OPCO's credit profile. Main provisions of the ESP include approval of a distribution investment rider (DIR) for investments in distribution infrastructure through May 2018. The ESP also approved OPCO's new capital structure with the debt to capital ratio increasing to about 52.5%. Along with the DIR, the ESP also includes riders to recover storm expenses. The approved ROE (10.2%) with 47.5% equity in the regulatory capital structure is reasonable in Fitch's opinion.

Moderating Capex Cycle: OPCO's capex cycle is expected to moderate over next three years. The current management forecast is for $1.2 billion to be spent though 2017, including about $565 million on distribution infrastructure with current recovery. In Fitch's view, the current capex cycle is manageable.

Merchant Risk: OPCO has a long-term power purchase agreement (PPA), as an off-taker, with Ohio Valley Electric Corporation (OVEC, 'BBB-', Stable Outlook) that terminates in 2040. Under the terms of the PPA, OPCO pays a demand charge to OVEC based on its fixed and variable costs. OVEC PPA costs are significantly higher than wholesale market prices and not recoverable in OPCO's regulated tariffs. OPCO must sell the PPA capacity in the wholesale market and is subject to wholesale electricity market risks. To exit the PPA, OPCO can only sell its share of the OVEC capacity to an investment grade off-taker. Currently, OPCO is responsible for about 20% of OVEC's installed capacity of about 2,400 MW.

Credit Metrics: Fitch expects OPCO's adjusted debt-to-EBITDAR to remain at the current levels of around 3.5x through 2017. FFO adjusted leverage, however, will increase to about 4.4x by 2017 from 3.0x at the end of 2014, mainly due to the absence of bonus tax depreciation benefits. Nevertheless, these leverage metrics will remain within Fitch's guidelines for the assigned IDR.

Supportive Regulatory Environment: The PUCO is the regulator for OPCO's distribution networks and the Federal Energy Regulatory Commission (FERC) has jurisdiction over the transmission segment of its networks. OPCO's tariff mechanisms are favorable and include a PUCO-authorized 10.2% ROE and 11.49% ROE by FERC.

Public Service Company of Oklahoma (PSO)

Rate Case Settlement: A recent rate case settlement at PSO will reduce general base rates by about $5 million a year. Concurrently, the Oklahoma Corporation Commission (OCC) also approved a new automated metering infrastructure (AMI) rider for PSO. AMI will increase PSO's cash flows by about $17 million in 2015 and about $27 million annually for the remainder of the forecast period. Fitch believes that the regulatory approval of the GRC application by OCC is supportive of PSO's credit profile.

Capex Cycle: Replacement of aging electricity distribution and transmission infrastructure, environmental compliance, and installation of smart meters are included in the current capex plan. Proposed capex over the next three year is expected to include $600 million for the replacement of distribution and transmission assets and about $140 million to comply with the environmental regulations. Timely recovery of its investment in smart meters is expected to modestly reduce the external financing needs over the forecast period (2015-2017) with Fitch estimating that PSO will be FCF neutral by 2017.

Pressure on Credit Metrics: Regulatory lag and high capex over the 2015 - 2017 forecast period will pressure PSO's credit metrics, in Fitch's opinion. FFO-based leverage is expected to weaken to 5x by 2017 and adjusted debt to EBITDAR to 4.5x. Fitch forecasts FFO fixed charge coverage will also weaken to around 4.2x, reflecting higher anticipated interest rates and the absence of bonus tax-depreciation benefits. Future regulatory outcomes that result in further deterioration in PSO's credit metrics could result in adverse credit rating actions.

Constructive Regulatory Environment: Fitch views Oklahoma's regulatory environment as constructive. Historically, OCC has authorized equity returns that were around the prevailing industry averages. Oklahoma state statutes authorizes the OCC to preapprove new construction projects, and allow the utilities to earn a cash return on construction-work-in-progress associated with plant improvements and environmental and transmission projects. Riders have also been allowed to facilitate recovery of new generation plants, transmission projects, a smart-grid expansion program, and storm restoration. In addition, the utilities' electric fuel and gas commodity cost recovery mechanisms allow for timely recovery of the related costs. These regulatory features are supportive of PSO's credit profile.

Revenue Risk: Slowing shale gas activity is a concern for the current IDR as reduced electricity demand will pressure PSO's cash flow measures in the absence of a corresponding retail rate adjustment by regulators. Fitch has used conservative volumetric growth rate estimates in its financial forecast. Any further decline in electricity demand without a corresponding increase in retail rates will constrain cash flow measures at PSO and could adversely affect the IDR.

Southwestern Electric Power Company (SWEPCO):

Regulatory and Cash Flow Diversity: SWEPCO operates in three utility jurisdictions -- Arkansas, Louisiana and Texas -- providing cash flow diversity. A supportive regulatory environment, which includes fuel cost adjustment clauses and cost riders to recover environmental regulation-related costs are key drivers of SWEPCO's credit profile.

Regulatory Activity: In 2014, the Public Utility Commission of Texas (PUCT) approved a $52 million increase in rates based on an authorized ROE of 9.65% as well as the transmission recovery factor for $14 million a year. In 2014, Louisiana Public Service Commission (LPSC) approved $15 million a year for the incremental power generation cost attributable to Louisiana customers. These regulatory outcomes are supportive of SWEPCO's cash flow profile and the IDR.

Improving Credit Protection Measures: With the implementation of regulator-approved increase in retail rates by SWEPCO, Debt/EBITDAR is expected to improve to 4.3x by the end of 2017 from 4.5x at the end of 2014. FFO adjusted leverage will, however, increase, in the absence of bonus tax depreciation benefit, but will remain within Fitch's expectations for the assigned IDR at around 4.6x. The FFO based leverage ratio at the end of 2014 was 3.4x. FFO based fixed charge coverage ratio will also remain around 4x between 2015 and 2017.

Rising Environmental Compliance Costs: Approximately 42% of SWEPCO's generation capacity is coal and lignite fired, including merchant portion of its Turk power plant. The company plans to spend about $460 million on environmental compliance related projects between 2015 and 2017. The company has a mix of recovery mechanisms with Louisiana regulations allowing a formula plan recovery while Arkansas and Texas regulations require SWEPCO to file a general rate case application to recover these costs, creating a regulatory lag for the investment.

AEP Texas:

Combined Credit Profile: Fitch considers operational and geographical ties between AEP Texas Central Co. (TCC) and AEP Texas North Co. (TNC) as fundamental factors in aligning the Issuer Default Ratings (IDRs) of both companies.

Declining Credit Metrics: Fitch expects TCC and TNC's credit metrics to decline between 2015-2017 reflecting slowing electricity demand, absence of bonus tax depreciation, anticipated increase in interest rates, and continued investment in the rate base with a regulatory lag. By the end of 2017, Fitch expects TCC's adjusted debt to EBITDAR and adjusted debt/FFO to be around 3.6x and 4.3x, respectively. TNC's adjusted debt to EBITDAR and adjusted debt/FFO will rise to about 4.5x and 4.9x by 2017 from 3.9x and 4.1x at the end of 2014. Fitch expects the FFO-based fixed-charge coverage ratios for the period ending 2017 to be around 4.5x for TCC and 4.7x for TNC. TCC has larger operations than TNC and its credit profile supports assigned IDR to TNC.

Offset to Slowing Electricity Demand: The Distribution Cost Recovery Factor (DCRF) available to Texas utilities allows recovery of newly- incurred distribution capital costs on an interim basis, for timely recovery of new investment. The DCRF rule allows a utility to change its rates between GRCs. However, DCRF limits the rate adjustment to once a year and not more than four times between the two GRC applications. TCC and TNC can recover their investments in a timely manner if electricity demand declines with the falling economic activity in shale gas segment of the economy. The current management forecast shows about $1.5 billion of new investment between 2015 and 2017 for TCC and TNC combined.

Low-Risk Business Profile: TCC and TNC own and operate regulated electricity distribution and transmission networks under a cost-of-service based regulatory framework in Texas. Neither company has any exposure to commodity prices. TNC's partial interest in a power plant co-owned with an affiliate is leased to a non-affiliated company through 2027.

LIQUIDITY

Strong Liquidity: At the end of 2014, AEP had approximately $3 billion of total liquidity available, including $163 million of cash and cash equivalents. $1.75 billion of consolidated revolving credit facilities will mature in June 2017 and the remainder of $1.75 billion will mature in July 2018.

Manageable Maturities: Consolidated debt maturities over the next three years are manageable and include $2.5 billion in 2015, $1.3 million in 2015, and $1.8 billion in 2016. Fitch expects AEP to fund the maturing debt with a combination of internally generated cash flows and debt.

RATING ASSUMPTIONS:

--Annual volumetric increase in sales at operating companies between 0.5% - 1% over next three years.

--For the concluded regulatory activities, Fitch's financial model includes implementation of recently settled ESP in Ohio, approval of general rate case applications in Oklahoma, Louisiana, and Texas (SWEPCO), and a reasonable return on invested capital for the inclusion of Mitchell Power plant in APCO's West Virginia rate base.

--For pending general rate case applications (GRCs), Fitch assumptions include:

In West Virginia, Fitch took into account historical ratios between requested and approved revenue increases and the upper end of intervener recommended increases in retail rates along with full recovery of deferred storm costs ($77 million) over five years.

In Kentucky, Fitch has assumed that the majority of increase will be allowed by the regulators as it pertains to the inclusion of the new power plant that was previously approved by the regulators and recovery of unamortized costs related to closing of its Big Sandy power plant.

In Virginia, Fitch has assumed that the utility achieves targeted financial metrics by maintaining cost savings programs and increased volumetric sales as the new law freezing retail rates until the next biennial review in 2020.

--Management's publically available forecasts for capex, dividends, and equity issuance.

--Fitch used independent consultant's (WoodMac) projections for power prices ($34-$37/MWh) and actual capacity prices in PJM to forecast EBITDA for AEP's competitive generation business.

--Interest rate assumption for AEP and its subsidiaries at 5%.

RATING SENSITIVITIES:

Positive: An upgrade of AEP or any of its subsidiaries is considered unlikely over the next 12-18 months. However, positive ratings actions may be considered if there is a material improvement in financial metrics as follows:

--For AEP and PSO: If adjusted debt/EBITDAR and adjusted debt/FFO ratios improve to 3.6x and approximates 4.5x or better on a sustainable basis.

--For OPCO, TCC, and TNN: If adjusted debt/EBITDAR and adjusted debt/FFO ratios improve to 3.4x and 4.0x or better on a sustainable basis.

--For other Fitch rated operating subsidiaries: If adjusted debt/EBITDAR and adjusted debt/FFO ratios improve to 3.75x and 5.0x or better on a sustainable basis.

--Better than expected regulatory outcome could result in a positive rating action for the utility operating companies.

Negative: Future developments that may, individually or collectively, lead to negative rating action include:

--For AEP and PSO: If adjusted debt/EBITDAR and adjusted debt/FFO ratios are higher than 4.0x and 5.5x on a sustainable basis.

--For OPCO, AEPTN and AEPTC: If adjusted debt/EBITDAR and adjusted debt/FFO ratios are higher than 3.75x and 5.0x on a sustainable basis.

--For all other rated operating subsidiaries: If adjusted debt/EBITDAR and adjusted debt/FFO ratios increase to 4.4x and 6.0x on a sustainable basis.

--The inability to recover environmental investments;

--Significantly adverse changes to the regulatory framework of the individual regulated operating company;

--A material increase in parent-level leverage to maintain a strong shareholder distribution policy.

Fitch affirms the following ratings with the Stable Outlook:

American Electric Power Company

--Long-term IDR at 'BBB';

--Senior unsecured at 'BBB';

--Short-term IDR and commercial paper 'F2'.

AEP Texas Central Company (TCC)

--Long-term IDR at 'BBB+';

--Senior unsecured and Pollution Control Revenue Bonds (PCRBs) at 'A-';

--Short-term IDR 'F2'.

AEP Texas North Company (TNC)

--Long-term IDR at 'BBB+';

--Senior unsecured at 'A-';

--Short-term IDR at 'F2'.

Appalachian Power Company (APCO)

--Long-term IDR at 'BBB-';

--Senior unsecured and PCRBs at 'BBB'.

Indiana Michigan Power Company (IMPCO)

--Long-term IDR at 'BBB-';

--Senior unsecured and PCRBs at 'BBB'.

Kentucky Power Company (KPCO)

--Long-term IDR 'BBB-';

--Senior unsecured at 'BBB';

Ohio Power Company (OPCO)

--Long-term IDR at 'BBB+';

--Senior unsecured and PCRBs at 'A-';

--Short-term IDR and commercial paper at 'F2'.

Public Service Company of Oklahoma (PSO)

--Long-term IDR at 'BBB';

--Senior unsecured at 'BBB+';

--Short-term IDR at 'F2'.

Southwestern Electric Power Company (SWEPCO)

--Long-term IDR at 'BBB-';

--Senior unsecured at 'BBB'.

The Rating Outlook is Stable

Additional information is available on www.fitchratings.com.

Applicable Criteria and Related Research:

--'Corporate Rating Methodology', dated May 28, 2014.

Applicable Criteria and Related Research:

Corporate Rating Methodology - Including Short-Term Ratings and Parent and Subsidiary Linkage

http://www.fitchratings.com/creditdesk/reports/report_frame.cfm?rpt_id=749393

Additional Disclosure

Solicitation Status

http://www.fitchratings.com/gws/en/disclosure/solicitation?pr_id=981963

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Contacts

Fitch Ratings
Primary Analyst
Roshan Bains, +1-212-908-0211
Director
Fitch Ratings, Inc.
33 Whitehall St.
New York, NY 10004
or
Secondary Analyst
Shalini Mahajan, CFA, +1-212-908-0351
Managing Director
or
Committee Chairperson
Philip Smyth, CFA, +1-212-908-0531
Senior Director
or
Media Relations
Alyssa Castelli, New York, +1-212-908-0540
alyssa.castelli@fitchratings.com
Elizabeth Fogerty, New York, +1-212-908-0526
elizabeth.fogerty@fitchratings.com

Contacts

Fitch Ratings
Primary Analyst
Roshan Bains, +1-212-908-0211
Director
Fitch Ratings, Inc.
33 Whitehall St.
New York, NY 10004
or
Secondary Analyst
Shalini Mahajan, CFA, +1-212-908-0351
Managing Director
or
Committee Chairperson
Philip Smyth, CFA, +1-212-908-0531
Senior Director
or
Media Relations
Alyssa Castelli, New York, +1-212-908-0540
alyssa.castelli@fitchratings.com
Elizabeth Fogerty, New York, +1-212-908-0526
elizabeth.fogerty@fitchratings.com