Senior decision-makers come together to connect around strategies and business trends affecting utilities.

Post

A Problematic S&P Study Predicts Stranded Assets Worth $68 Billion for Electric Utilities Due to the Energy Transition

image credit: Dreamstime.com
Rakesh  Sharma's picture
Journalist, Freelance Journalist

I am a New York-based freelance journalist interested in energy markets. I write about energy policy, trading markets, and energy management topics. You can see more of my writing...

  • Member since 2006
  • 1,019 items added with 704,943 views
  • Aug 12, 2021
  • 520 views

How will an accelerated energy transition affect fossil fuel assets at electric utilities?

 

An S&P Market Intelligence study has some dire predictions about the costs involved. But it seems half-baked and omits key information. The overall result is an oblique attempt to sway public opinion about natural gas as a baseload fuel and ensure its longevity as a money-making proposition for electric utilities.

 

Billions of Dollars in Stranded Assets

 

The study estimates that the Biden administration's current energy policies could result in $68 billion worth of stranded assets. Out of that amount, $34 billion could be stranded in prolonging the life of existing coal plants to comply with pollution control standards. Steve Piper, one of the report’s authors, called it an “overhang of investments in pollution control.” Retrofitting existing plants, the report states, is not a solution because it does not provide a “financially viable solution” to address carbon dioxide – the most harmful and prevalent of all emissions.

 

Another $34 billion could be stranded in spending on new natural gas assets for baseload generation. According to Piper, capacity utilization rates for these new assets will rapidly decline as renewable energy sources take over most of the grid’s power requirements.

 

As proof, the paper outlines the case of the La Paloma generation power plant, a combined cycle gas power plant in California. It ran 73% of the time in 2014. The plant’s owner declared bankruptcy in 2016, when its utilization rate fell to 47%, claiming that they could no longer compete against solar energy’s cheap prices and service debt at the same time. (The average capacity factor for natural gas plants was 56% in 2016). 

 

The study estimates that 13% of Combined Cycle Gas Turbine (CCGT) capacity, or 33,700 MW, is at risk in the US. ISO markets in the Northeast are especially vulnerable to retirements. 20,600 MW of combined cycle gas transmission capacity across three ISO markets – NYISO, PJM, and ISONE – may be retired by 2030, according to the study. That figure represents 20% of the overall fleet in these markets.

 

Piper told Utility Dive that if the Biden administration adopts a clean energy standard or if states and regulatory markets adopt even more aggressive targets for renewable energy in their grid, then the cost of these stranded assets will likely increase.

 

Stranded Assets: A Money-Making Opportunity for Electric Utilities

 

For all its hand-wringing about stranded natural gas assets, the study omits key information about them.

 

For starters, it does not include some of the biggest natural gas markets in its assessment. About 38% of U.S. natural gas-fired capacity was located in Texas, California, Florida, and New York in 2016. The fate of natural gas plants in Texas and California – the top two states for natural gas end use consumption – are not discussed.

 

It also cherry-picks case studies. La Paloma, in fact, emerged from bankruptcy and was embroiled in a case against CAISO in 2018. The utility wanted a mandatory capacity market in California because of “an increasing number of reliability must-run contracts for gas-fired power plants.” (An argument that is similar to the one made by the study’s authors – albeit obliquely). CAISO argued against it because “the resources needed for reliability also receive revenues from bilateral RA (Resource Adequacy) contracts (besides spot market revenues).

 

The ISO’s argument holds true for baseload generators in other markets. These generators are compensated with a higher sales price per unit of power under baseload PPAs because of the increased risk and tight schedules for baseload power. And spot market revenues can be substantial.   

 

Besides, natural gas plants can still make bank during period of high demand and compensate for their diminishing energy margins. The February Texas fiasco, when natural gas companies made away with an estimated $26 billion, is an example of the strategic profits available to natural gas companies.

 

That might be the reason why electric utilities continue to invest in natural gas assets, despite its diminishing future prospects. Regulatory commissions, even in renewable energy – forward states like California, are also happy to oblige by prolonging the life of such assets due for retirement.

 

Recovery costs for stranded assets also represent additional money-making opportunities for electric utilities. Energy stranded costs are generally recovered through a mix of securitization and increase in ratepayer bills. The former involves selling bonds in securities markets to finance an energy transition and the latter is an opportunity to stiff ratepayer bills with additional amounts to retire depreciating assets. In recent times, thanks to the pandemic shutdown, electric utilities have become adept at doing both. They lose no opportunity to complain about the costs of energy transition while mopping up funds at low coupon rates from bond markets.

 

An example is Duke Energy. In its 2019 IRP, the North Carolina-based utility committed to spending roughly $1 trillion on 15 new natural gas plants, of between 6.1 GW and 9.6 GW, by 2030. Meanwhile, Duke Energy Indiana modified its depreciation schedules to reflect shorter estimated lives for three coal plants located at Gallagher, Cayuga, and Gibson and recover the increased expense, amounting to $212 million, from ratepayers. Even as it recovers stranded costs from ratepayers, the utility is financing its move towards green energy with bond offerings that run into millions and billions of dollars.

 

I have also detailed the case of NextEra Energy, which derives almost all of its profits from fossil fuel sources and has committed to more capital spend on natural gas plants as a “bridge” to becoming a renewable energy company. It issued new green bonds last year to finance energy transition at Florida Power & Light (FPL), a NextEra energy company that generates a majority of its electricity from fossil fuels. The cost of these to the utility is minimal. FPL issued bonds with coupon rates of 2.85%, significantly less than their earlier rate range of between 5.85% to 9.8%.     

The study’s authors state that a clean energy standard would likely increase the stranded costs for natural gas assets. But inclusion of natural gas in that standard, as some argue, could also make it cheaper for electric utilities to justify their slate of recent investments and make money hand-over-fist in the process.

There is an argument to be made for natural gas and fossil fuel to remain a part of the grid during the energy transition. This study definitely is not one. 

Discussions

No discussions yet. Start a discussion below.

Get Published - Build a Following

The Energy Central Power Industry Network is based on one core idea - power industry professionals helping each other and advancing the industry by sharing and learning from each other.

If you have an experience or insight to share or have learned something from a conference or seminar, your peers and colleagues on Energy Central want to hear about it. It's also easy to share a link to an article you've liked or an industry resource that you think would be helpful.

                 Learn more about posting on Energy Central »