Time to Stop Sticking Hoosiers with the Bill for Running Coal Plants at a Loss

Sarah Steinberg's picture
Policy Principal, Advanced Energy United

-Leads Advanced Energy United's Future of Gas and gas transition work; legislative and regulatory engagement in Nevada; and regulatory work in Indiana. Issues include long-term gas planning,...

  • Member since 2022
  • 8 items added with 4,429 views
  • Jan 13, 2021

IN Self-Scheduling proposed order-745

Over the past several months, our Indiana team has been intervening in a proceeding before the Indiana Utility Regulatory Commission (IURC) to examine Duke Energy Indiana’s coal self-commitment practices. Self-commitment refers to a process by which a utility instructs the regional market within which it operates – in this case, the Midcontinent Independent System Operator (MISO) – to dispatch the utility’s own resource unit regardless of whether or not it is the cheapest available at the time. Many vertically integrated utilities have been using this mechanism to run their expensive coal plants more frequently than economics would otherwise dictate. They do this because it is not their shareholders who suffer financial losses, but rather their captive ratepayers: When the cost to operate these units exceeds the market clearing price, utilities pass along the difference to customers, in part through fuel adjustment clause proceedings. AEE is working to curb this self-serving utility practice.

Throughout the fall of 2019, the time period covered by the IURC proceeding, this is exactly what Duke did with its Edwardsport, Cayuga, and Gibson coal-fired units. Analysis conducted by Berkeley Research Group (BRG) for AEE demonstrated that, in three months alone, Duke’s commitment practices cost ratepayers over $20 million more than if Duke had selected the least-cost option at all times. What’s more, Duke’s own Daily Profit and Loss Analyses predicted millions of dollars in losses – and Duke chose to run the units anyway. For rationale, it cited the “unique operating characteristics” of each plant and undocumented in-person daily decisions that consider “a number of factors.” 

This is unacceptable. At the very least, Duke should be transparent and consistent in its decision-making to fully justify its unit commitment practices. We also know that if the utility were motivated, it could operate its units differently. Merchant coal plants offer a useful comparison. They are independently owned and obey all of the same physical and economic constraints as utility-owned plants, but have a much lower level of uneconomic dispatch. This is because their investors shoulder financial losses from uneconomic operation, instead of ratepayers.

Indiana law requires that utilities make “every reasonable effort to acquire fuel for its own generation or to purchase power so as to provide electricity to its customers at the lowest fuel cost reasonably possible.” Duke has violated this standard by routinely and knowingly self-committing its coal generation units at a financial loss. 

In our rapidly evolving energy landscape, what formerly worked for Duke can no longer be assumed to be best practice. BRG’s modelling showed that Duke could save its ratepayers between $105.3 million and $423.7 million by 2025 if it transitioned its resource portfolio to one that includes greater levels of demand response, renewable energy generation, and energy storage. This finding is in line with what two other Indiana utilities, NIPSCO and Vectren, have found in their most recent Integrated Resource Plans (IRPs). Duke has just begun its 2021 IRP process, making this the perfect time for Duke to plan for a significant, near-term shift toward advanced energy resources instead of sticking its customers with the bill for running outmoded power plants. 

In the current proceeding, our proposed order and brief call for a number of specific remedies for Duke’s self-commitment practices:

  1. Duke must issue refunds to its customers for the actual incurred losses for all instances at each of its coal-fired units for which Duke’s own Daily Profit and Loss analysis predicted economic losses, but it still chose to commit the plant to MISO using a “must-run” designation. 
  2. In the future, Duke must provide the Commission with sufficient documentation to justify its commitment decisions, including its efforts to mitigate costs and written explanation of all of the factors that it uses to make each commitment decision, including their relative values and underlying assumptions. 
  3. With regard to its Edwardsport Integrated Gasification Combined Cycle plant, Duke must study the ratepayer impacts of retiring the coal-fired gasifiers that currently use coal to produce syngas, and switching to natural gas as the plant’s primary fuel.
  4. Duke must perform a cost-of-service study to determine the fuel costs associated with uneconomic operation of the Cayuga unit related to a steam contract that obligates them to run at least one Cayuga unit at 300 MW or greater at all times, regardless of MISO prices. 
  5. Duke must study the use of seasonal outages (also known as seasonal operations) at all of its coal plants as a strategy to mitigate customer risk. If the study shows ratepayer savings from turning off coal plants during the shoulder months when energy prices are low, Duke must file a plan with the Commission to implement seasonal outages. 

These seasonal shutdowns are becoming increasingly common for coal plants that remain in operation today, including those that participate in the MISO market and in circumstances substantially similar to that of Duke and its coal fleet. In late 2019, Xcel Energy filed a plan (approved in July, 2020) with the Minnesota Public Utilities Commission to begin seasonally and economically dispatching its Allen S. King and Sherco Unit 2 coal plants into the MISO market. Xcel estimates that it will save between $8.5 million and $28.5 million annually on fuel costs alone, $18.4 million in total operation and maintenance costs, and over $27 million in capital costs. In fact, in its 2020 Review of the Commitment and Dispatch of Coal Generators in MISO, the MISO Independent Market Monitor suggested seasonal outages would likely be beneficial for a number of MISO utilities to consider. 

Today, we are at a pivotal moment in the energy transition. Expensive, older coal assets were simply not designed to respond in real time to market price and demand signals, and are increasingly out of step with a newer, more dynamic system. The practice of allowing coal plants to operate at an economic loss and recovering those costs—even occasionally—raises electricity costs for Indiana ratepayers and deprives Hoosiers of the benefits of readily available lower-cost, highly reliable advanced energy resources. We hope the Commission agrees. 

Follow the IURC docket on Duke's self-scheduling and download AEE’s proposed order and brief on PowerSuite, AEE's online policy tracking tool. Sign up for a free trial by clicking below.


Read More


No discussions yet. Start a discussion below.

Sarah Steinberg's picture
Thank Sarah for the Post!
Energy Central contributors share their experience and insights for the benefit of other Members (like you). Please show them your appreciation by leaving a comment, 'liking' this post, or following this Member.
More posts from this member

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 »