Fitch: AEP has hired advisors to explore sale of merchant generation business

American Electric Power (NYSE: AEP) is making a series of moves to help its credit profile, including retention of advisors to help it explore a sale of its merchant power generation business, said Fitch Ratings.

Fitch Ratings on March 26 affirmed the ratings of AEP and certain of its subsidiaries. The Issuer Default Rating (IDR) for AEP is ‘BBB’. The Rating Outlook is Stable. The rating affirmation for Ohio-based 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 capital expenditures (capex) and 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.

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.

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 the 2011-2014 period. Approximately 25% of annual capex spending through 2017 targets FERC-regulated transmission, providing a relatively high and predictable returns on investment.

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 power contracts for its in-state power plants. “Simultaneously, management has engaged advisors to explore a potential divestment of its merchant power business,” Fitch added. “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.”

Notable is that AEP, in one respect, is already divesting merchant generation. For example, the 1,600-MW Mitchell coal plant in northern West Virginia in the last couple of years moved from AEP’s now-deregulated Ohio Power subsidiary to the unregulated AEP Generation Resources, with half of it then sold to AEP’s regulated Wheeling Power unit and the other half sold to regulated subsidiary Kentucky Power.

Fitch says the utility commissions in the AEP states are generally supportive

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 general rate applications in certain jurisdictions (Kentucky, Louisiana, Oklahoma, Texas, and West Virginia) and rider mechanisms in other jurisdictions (Indiana, Ohio, Oklahoma, and West Virginia)

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.

The regulatory environment in Virginia, served by Appalachian Power (APCO), is in flux, Fitch noted, with new legislation signed into law by the governor in February 2015 that postponed the biennial review of Virginia utilities, including Applachian Power, 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.

With over 75% of APCO’s generating capacity derived from coal-fired generation, the company is exposed to pending carbon regulations. 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, Fitch added.

For AEP’s Indiana Michigan Power unit, 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.

Kentucky Power filed a general rate application seeking a $70 million rate increase related to the Mitchell 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. Note that Big Sandy Unit 2 will be retired outright, while Unit 1 will be switched to natural gas. Fitch expects capex to decline, relative to historical levels through 2017. Current capex plan includes conversion of Unit 1 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.

Highlights for other subsidiaries include:

  • For AEP Ohio, Fitch noted that it has a long-term power purchase agreement (PPA), as an off-taker, with Ohio Valley Electric Corp. (OVEC) that terminates in 2040. OVEC is owned by a consoritum of utilities and has two coal-fired power plants (Kyger Creek and Clifty Creek). Under the terms of the PPA, AEP Ohio 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 AEP Ohio’s regulated tariffs. AEP Ohio must sell the PPA capacity in the wholesale market and is subject to wholesale electricity market risks. To exit the PPA, AEP Ohio can only sell its share of the OVEC capacity to an investment grade off-taker. Currently, AEP Ohio is responsible for about 20% of OVEC’s installed capacity of about 2,400 MW.
  • For Public Service Co. of Oklahoma (PSO), the 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 years is expected to include $600 million for the replacement of distribution and transmission assets and about $140 million to comply with the environmental regulations. Fitch views Oklahoma’s regulatory environment as constructive.
  • Southwestern Electric Power Co. (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. Approximately 42% of SWEPCO’s generation capacity is coal- and lignite-fired, including the merchant portion of its Turk power plant. The company plans to spend about $460 million on environmental compliance related projects between 2015 and 2017.
  • For AEP Texas, 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. 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. The current management forecast shows about $1.5 billion of new investment between 2015 and 2017 for TCC and TNC combined.


About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.