The Myriad Risks Underlying Duke Energy’s 4.4% Dividend Yield


Duke Energy (DUK) offers income-seeking investors an attractive cash dividend yield of 4.4%. Though the Charlotte, N.C-based utility has a reputation for delivering on promised operational and financial metrics, early retirement of the troubled Crystal River nuclear plant in Florida combined with added costs of complying with new environmental regulations could adversely affect future profitability and cash flows.

View gallery

DUK Dividend Yield Chart

Duke Energy’s regulated utility operations serve 7.2 million electric retail customers (i.e., meters) located in six states in the Southeast and Midwest, representing a population of about 22 million people. Of the 50-gigawatts in totally owned capacity, nuclear power provides approximately 34% of regulated U.S. Franchised Electric and Gas (U.S. FE&G) total generation. The importance of this fossil-fuel alternative as an earnings driver cannot be understated: In 2012, cost of delivered nuclear fuel per net Kilowatt-hour generated was 0.62 cents, compared with 3.55 cents and 4.06 cents for coal and oil & gas, respectively, according to recent regulatory filings.

In February 2013, the company announced plans to retire the single-unit, 860-megawatt Crystal River Nuclear Plant, which is located about 70 miles north of Tampa. The decision was reached after an engineering analysis (“worst case scenario”) estimated that construction and repair costs – $338 million through December 2012 – might ultimately total more than $3.4 billion (and take 8 years to complete!). The reactor, which the company acquired through its purchase of Progress Energy last year, has been offline since the fall of 2009 after the containment building’s concrete outer wall formed delamination (cracks) during maintenance for refueling and replacement of steam generators.

Given uncertainties with regulatory approval for restart and cost recoveries, Wall Street believes early retirement positions Duke Energy to better control costs going forward and affords investors clearer earnings visibility. Baring “acts of god” (natural disasters or adverse changes to weather models), management believes it can grow long-term earnings and cash dividends per share at compounded annual growth rates of 4% - 6% and 2%, respectively, from 2013 to 2015 – with a target payout ratio of 65% - 70%.

Investors have expressed confidence that Duke Energy’s seemingly low-risk, predominantly regulated (read predictable) business model will hit consensus estimates, on average, of $4.75 per share in 2015, up from adjusted share-net of $4.32 in 2012.

View gallery

DUK EPS Estimates for Current and Next 3 Fiscal Years Chart

Year-to-date, the share price of Duke Energy has outperformed the S&P 500 Index by 180 basis points, posting a total return of 8.31%. However, at current prices the stock looks fairly valued, based on PE ratio, trading at a premium to other large-cap, regulated utilities, such as The Southern Company (SO), American Electric Power (AEP), and Consolidated Edison (ED):

View gallery

DUK PE Ratio TTM Chart

What, therefore, could trigger an earnings miss and pressure Duke Energy’s stock price and targeted dividend payout ratio?

The unrecovered investment on the Crystal River Unit 3 asset is approximately $1.64 billion, which is equal to 70% of prevailing and agreed-upon ROE (calculated on the prevailing cost of equity), according to terms of a settlement with the Florida Public Service Commission (FPSC). In written correspondence, company spokesman David Scanzoni confirmed that the company cannot begin to recoup its embedded costs through future customer rate hikes until the billing cycle starting in January 2017 (with collection accreting over a 20 year span). Additionally, $20 million listed as an offset (liability) in removal costs could prove too conservative, as the approved SAFSTOR decommissioning strategy will take between 40 – 60 years to complete!

While the foregoing reflects current estimates with respect to the retirement of the Florida facility, there is significant risk and uncertainty, too, with respect to the cost and recoverability of replacement power. Through December 2012, Duke Energy had already spent $614 million for contracted third-party power purchases. Although the 2012 Settlement Agreement negotiated with the FPSC permits recovery of “prudently” incurred fuel and purchase costs (through December 2016), it seems likely that future rate-setting charges could prove less attractive than the 2012 Agreement which granted a regulated ROE up to 11.5%.

In the aggregate, each 100 basis point decline in 2013 ROE will result in a 37 cent hit to share-net earnings, according to chief financial officer Lynn Good.

Shifting the burden of construction costs and operating risks from investors to taxpayers and ratepayers could prove more difficult in coming years. Already, in some states, including Florida, legislators are looking to amend existing laws that permit recovery of nuclear construction costs and limit profits utilities can earn on customer prepayments. Another consumer bill is looking to reduce allowable interests utilities now earn on carrying costs on their projected construction costs – reducing the permissible rate from 8.5% to annual market rates.

The company hasn’t announced a definitive plan for replacement capacity. A proposed nuclear reactor facility in Levy County has stalled, and with estimated construction costs escalating from $19 billion to $24 billion, the project makes little economic sense – especially to customers already paying surcharges for Crystal River. Megawatt capacity needs are likely to be met by a natural gas fueled-generation plant. However, such a facility is unlikely to be completed and lit up before 2018.

Duke management has demonstrated an ability to control costs during rate-freeze periods. Credit metrics are reasonable for a capital-intensive company: Debt comprises about 50% of total capitalization; EBITDA is about five times interest payments; and, liquidity on the balance sheet runs at about $700 million in U.S. accounts plus $5.6 billion in available credit.

In a recent financial presentation, management disclosed that even with projected EBITDA of $6.8 billion, required funding of CAPEX projects (a budgeted $6.3 billion, consisting mostly of maintenance (57%), infrastructure growth (28%), nuclear fuel and environmental, debt maturities ($2.7 billion), dividend payments ($2.2 billion), and other miscellaneous costs will result in the company bleeding $4.7 billion in cash flow. Ergo, the quality of earnings and balance sheet could quickly deteriorate, should pending regulatory issues go against the company:

The company just lost out on a requested 11.2% base-rate hike in North Carolina to offset costs associated with ongoing construction of new natural gas combined-cycle generation at its Sutton Plant in Wilmington. The settlement included an ROE of just 10.2%. Still to be heard this year is a separate request for a 9.7% increase in the state (totaling $359 million) and a hearing in Ohio requesting a rate hike totaling $132 million (5.1%).

Of even greater concern than battling state utility commissions, Duke Energy could run into a buzz saw called the Environmental Protection Agency (EPA). To date, the company has spent approximately $7 billion on air emission control equipment; nonetheless, management estimates that to bring its fossil fuel burning plants in compliance with a plethora of new regulations – including clean air, soil and water acts -- will require an additional $5 billion to $6 billion in investments over the next 10 years. These monies do not include the $825 million in CAPEX planned over the next three years to meet Nuclear Regulatory Commission Fukushima-related requirements.

Environmental costs could rise dramatically in the next year, too, as the EPA is set to release a series of even tighter air quality regulations in coming months, especially governing the management of coal combustion by-products (such as fly ash) and greenhouse gas emissions.

Even a well-managed utility like Duke Energy could saddle investors with losses and declining dividend payouts if opportunities for recovery of generation costs and ROE allowances start to narrow.

David J. Phillips, a contributing editor at YCharts, is a former equity analyst. His journalism has appeared in Bloomberg BusinessWeek, Forbes, and Kiplinger's Personal Finance. From 2008 to 2011, David was a reporter for CBS News Interactive. He can be reached at

More From YCharts
View Comments (2)