Comments on DOE Staff Report on Electricity Markets and Reliability

By Doug Houseman

In August 2017, the DOE released their staff report on Electricity Markets and Reliability. This report was written at the request of Secretary Perry to look at issues in the energy markets and how policy was driving those markets.

There were three areas that Sec. Perry asked to be investigated:

  • The evolution of the wholesale electricity markets, including the extent to which Federal policy interventions and the changing nature of the electricity fuel mix are challenging the original policy assumptions that shaped the creation of those markets;
  • Whether wholesale energy and capacity markets are adequately compensating attributes such as on-site fuel supply and other factors that strengthen grid reliance and, if not, the extent to which this could affect grid reliability and resilience in the future and;
  • The extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.

While everyone can argue that both the request and the report are political, the reality is all three questions should be asked and answered. The report lays out the current conditions and events in great detail. All driven from data that is readily available to anyone who wants to verify the facts in the report.

Market Changes

PJM – the first real Independent System Operator (ISO) in the US was founded in 1927, but became an official ISO in 1997. One of the things the report does not do well is to review the changes in the generation markets since 1997. Some of the major changes were:

  • In 1992, Energy Policy Act (EPACT) created a $15 per Mega-Watt-Hour (MWH) production tax credit for renewables, plus a $15 per MWH renewable energy production incentive. Wind and solar increased from less than 300 Mega-Watts (MW) in 1997 to more than 85 Giga-Watts (GW) in 2017 . In 2017 subsidies to renewables exceeded $10 billion dollars .
  • In 1997, natural gas prices varied between $2.5 and 4 a Million BTU (MMBTU), in 2017 they are at roughly the same price . Natural gas power plants (combined cycle) have improved from 45% efficient to more than 60% efficient – effectively reducing the price of natural gas for electricity by 33% . The end points do not tell the whole story, because natural gas climbed to over $10 an MMBTU during that 20-year period and then fell back to the lower prices.
  • In 2000, the EPA started tightening the regulations on NOx, SOx, Ozone, and other pollutants for all power plants. The tightening continued through 2016. In 2011, rules were added for Mercury, heavy metals, and acidic gases. Finally, cooling water regulations impacted both nuclear and coal fired power plants. See table 3-4 in the DOE report for a complete list of regulations.
  • By 2017, more than half the states had renewable portfolio standards in place, which required a certain percentage of power to come from renewable sources without regard to economics.
  • Technology continued to advance on batteries, wind turbines, solar cells, gas turbines, and other generation technologies.
  • Industrial demand response increased by more than an order of magnitude and now exceeds 2GW of available DR.

While the DOE report touches on most of these, there is no single point in the report that analyzes the combined impact of these changes. Which is too bad. The conclusions in the report, tend to focus on two or three of these items – regulations and cheap natural gas, but lack focus on the changing technology base. Figure 3.2 in the report “Net Generation Capacity Additions and Retirements” is the telling figure in the report, showing the massive shift in technology for generation.


DOE in the report gives very little credence to storage. Table 4-1 summarizes DOE’s thinking on storage, and the table probably needs a revision, because issues such as seasonal shifting and storage life cycles are not accounted for. Figure 4-13 has a single line in it to deal with all types of storage – leading to conclusions in the table that, if examined in more detail, would change. They acknowledge that more than 20 GW of storage exists in the report, almost all of it pumped hydro. There are no recommendations in the report on the use cases for storage to manage variable renewables, ancillary services, or other aspects of the power generation system.

Part of this may be the sheer magnitude of the storage required. If the US were to shift to a full renewable electric system, using existing renewable technologies (wind, solar, hydro, biomass/gas, etc.) then utilizing energy storage to shift power would require an estimated 800 GW of capacity and roughly 10 TWH of energy to get through a winter peak. For seasonal mismatches, while the capacity is lower the energy stored is much higher. Based on analysis of the major RTO/ISO over a two-year time-period more than 630 TWh of storage may be required for seasonal shifting . At the currently projected 2020 price of $150 per kilowatt-hour for batteries – the cost of battery storage is a staggering $94,500,000,000,000 or roughly 5 times the national debt or 5 years of the GDP of the US.

Only doing day/night shifting using storage is a much more manageable $1.5 trillion. Now, this is an unrealistic estimate because hydro and nuclear power provide enough energy for many nights that storage may not be needed (e.g. very nice spring days). Additionally, energy efficiency and demand response have not been factored into this analysis either. There is a possibility that the day/night requirements may be as much as 50% high, and the annual storage similarly high. Even so, $750 billion for storage is a number that cannot be supported by the current economics of the electricity system. Not only is there not room in the current regulated tariff structure, but the retail price of electricity would have to rise significantly to support this size of investment – potentially pricing low income customers out of the market.

On site fuel

When talking about on-site fuel in the report, for some reason DOE neglected to think about the water behind many of the hydroelectric dams. This is a major oversight on their part, because it neglects the one renewable resource that is fully schedulable.

Demand Response and Energy Efficiency

While DOE mentions demand response, then drops the topic completely in the report, which is interesting given DOE’s backing of Transactive Energy. Energy efficiency also gets a passing mention. The fact that the report spends a good deal of time on the disconnect between retail and wholesale markets and offers little in the way of recommendations on how to fix this disconnect is an issue. Not only is that an issue, but the use of demand response does not play in the discussion of the disconnect at all.

Polar Vortex

In the winter of 2014, the US suffered through a polar vortex, where over 200 million people from the Rocky Mountains all the way to the Atlantic Ocean experienced winter conditions that most of the US had never faced before. Many generation sources did not, or could not run. In fact, there were worries that brownouts and blackouts may occur. Because of the still air in many areas, wind turbines did not make power – of the over 9 Gigawatts (GW) of wind generation in MISO, less than 1 GW of power was produced from wind during most of the polar vortex. It was not just wind that did not run; coal piles froze and gas plants found their supply was diverted to home heating. Only Nuclear power plants and hydro-electric plants ran with close to their normal capacity according to the public records from MISO, NYISO, PJM, ISO-NE and other control areas that were subject to the worst of the vortex. As we have seen with the return of the Polar Vortex in 2018 and its impact on the grid, this cold weather scenario is probably one of the best to study. On January 3, 2018 – the NE-ISO had more than 30% of its power being produced using on-site stored petroleum, because other sources of energy were not available. On a normal day, petroleum accounts for less than 1% of the total power produced in NE-ISO. In much of the DOE report, cold weather seems to be a concern and the reason for many of the conclusions and recommendations.


The DOE report leaves more questions than answers. While they have a section in the report that asks some very good questions, it does not touch on many of the strategy and policy questions that should be dealt with, including but not limited to:

  1. How much variable renewable generation can the system absorb without storage?
  2. What is the long-term forecast for market prices if the system reaches renewable saturation?
  3. What generation cycle will be viable for non-renewable plants if renewables reach saturation?
  4. What is the role, size and cost of storage at an ISO/RTO/National level?
  5. How does storage get paid for?
  6. What is the role of demand response at the ISO/RTO/National level?
  7. How does demand response get paid for?
  8. How does Transactive energy, and IoT fit into the future of the wholesale market?
  9. What is the demarcation for storage, demand response, and energy efficiency between transmission (bulk power) and distribution?
  10. How do we assure the power will be there during extreme events at the wholesale level?
  11. What steps need to be taken for resiliency? What are the best assets to provide this resiliency?
  12. What new technologies are going to impact the wholesale market and generation mix?

Even bigger questions exist around things like should there be a wholesale market in the future? Should restructuring continue to exist or should the industry return to its roots or even disappear?

While DOE did a great job with providing a platform of information in this report, it unfortunately falls short on the analysis of the data with respect to many areas. A version 2.0 of the report would be welcome.

This article was edited by Frances Bell

For a downloadable copy of the January 2018 eNewsletterwhich includes this article, please visit the IEEE Smart Grid Resource Center




Doug Houseman is the utility modernization lead for Burns & McDonnell and chairman of the IEEE PES Intelligent Grid Coordinating Committee. Previously, he was VP of Technical Innovation at Enernex. Doug has a broad background in Utilities and Energy. He worked for Capgemini in the Energy Practice for more than 15 years. During that time he rose to the position of CTO of the 12,000 person practice. During that same time Capgemini grew from less than $10 million dollars in Energy related revenue to more than $2.4 billion. Doug was part of the Global leadership team and worked all over the world in a thought leadership and delivery role. During that time Doug founded the Smart Energy Alliance, lead the Distribution Roadmap 2025, and developed the smart metering and smart grid practices. Doug and his sons are makers and tinkers who have built everything from a 3D printer to a greenhouse. Doug started using photovoltaics in the 1970s and geothermal in the 1980s.

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