The Department of Energy’s “Staff Report on Electricity Markets and Reliability,” released on Aug. 23, 2017, addressed Secretary Perry’s specific questions about the causes for recent power plant retirements and their implications for grid reliability. That study’s summary and recommendations didn’t take the longer view many stakeholders had hoped for, but it did answer the secretary’s immediate questions.

Between late May and early July 2017, I organized the research and drafted the bulk of the technical portions of the DOE “Staff Report.” DOE staff and management modified the technical study draft and prepared the summary of findings (Section 2) and recommendations (Sections 7 and 8). But that summary and recommendations missed some important points about reliability and resilience that are worth keeping in mind as stakeholders and policy-makers consider next steps.

Key DOE study findings

DOE’s staff summary of the technical study was narrowly focused to answer the Secretary’s specific questions.  That summary got many things right:

• Baseload generation is an operational mode, not a type of power plant.
• Low natural gas costs and low electric demand growth were principal causes of conventional power plant retirements.
• Many of the power plants that retired between 2002 and 2016 were used for baseload generation in the past, but they had moved to lower capacity factors and no longer served a baseload function by the time they retired.
• Wholesale markets are good at optimizing and delivering basic grid reliability at low cost, but they must evolve to address further reliability and resilience services as well as extra-market interventions and societally valued benefits such as air quality and jobs.
• The characteristics, metrics, benefits and compensation for essential resilience and reliability services are not yet fully understood.

But the DOE summary didn’t recognize a broader set of conclusions about why those power plants retired, and it offered too few constructive recommendations about how to address reliability and resilience going forward.

Rethinking the conclusions about power plant retirements

A broader look at the technical sections of the Staff Report offers some inescapable conclusions about why so many coal, nuclear and natural gas power plants retired between 2002 and 2016. It is necessary to understand these retirement causes in order to design effective policy, market and operational solutions for the future.

Many of the retirement stories differ by region, but here are some over-arching observations:

• While coal and nuclear generation were once the preferred choice for low-cost, round-the-clock generation, the drastic fall in natural gas prices has irrevocably changed the competitive economic balance between fuel types, with gas driving coal and nuclear farther out the supply curve.
• Continuing improvements in natural gas plant flexibility and fuel efficiency have exacerbated gas plants’ competitive advantage over coal and nuclear resources, particularly given the faster pace of grid operations driven by variable generation on both sides of the meter.
• Flat or falling electricity demand has removed the expected rising revenue and demand cushion that once helped high-cost plants.
• As a root cause of retirements, wholesale competition worked as intended, driving inefficient, high-cost generation out of the market. This is evident in the pattern of retirements, which occurred earlier in the highly competitive, easy entry and exit markets of ERCOT, California, and the Northeast, and much more slowly in the vertically integrated Midwest, West and Southeast.
• As another root cause, most of the plants that have retired were old, smaller, inefficient, and high-cost. These plants did not have the flexibility and cost profiles to compete in a fast-moving grid and were old enough to merit retirement.
• Renewable generation was an exacerbating factor, but in most cases not a causal factor behind power plant retirements. Many of these retirements occurred before significant quantities of renewable generation were added to the grid, or in regions with little or no renewable production. Negative prices occurred – often bid by nuclear plants behind transmission constraints — before the advent of deep renewables penetration.
• In many cases, the plants that retired were already less economically competitive and were being dispatched less before the time (2011-2016) when they would have to make new regulatory compliance investments.  Therefore, regulations forced many plant retirement decisions and set their retirement dates, exacerbating but not causing many retirements.

Policy recommendations

Many more coal and nuclear plants face borderline economic viability and are at risk of retirement over the next few years. Before all of those plants retire, we need to understand – based on valid reliability analyses, not just the desire to protect existing assets and jobs – whether those plants play a valid reliability role. 

If I had written DOE’s policy recommendations, they would include the following:

Wholesale markets – Today’s wholesale electric markets were designed to manage reliability and low costs, not to manage carbon, jobs or preferred resources. But as we patch and re-patch the current market system, what have we learned from the past 20 years of experience with competitive wholesale markets? FERC and stakeholders might explore the question, if we were to design wholesale electric markets fresh today, to address the conflicting cost, reliability and societal needs and goals in a consistent and integrated fashion, what would those markets look like?

Essential reliability and resilience services – NERC has given us a starting set of essential reliability services, but many of those services are not yet compensated adequately. We don’t yet have a comparable understanding of the key elements of resilience (including fuel security), nor how to measure, productize and compensate them. We do know that a wide variety of supply- and demand-side resources can provide many of these services – and the better we define and productize these services and specify their need and value, the more resources can step up to deliver them. 

We must figure out what all these essential services are and how to compensate providers appropriately for each, even if compensation is not determined based on market solutions. Such compensation may help meet some generators’ missing revenues problem.

Frequency response provision – Not all inertia is created equal. While rotating mass-based generation was the only source of frequency response decades back in the days of a slow grid, such sources are no longer the only way to get frequency response. DOE, NERC and others should conduct immediate research to determine the capabilities and limits of rotating mass-based inertia, inverter-based synthetic inertia, and a variety of storage and automated demand response sources to provide primary and secondary frequency response. 

If there is unique value to rotating mass-based inertia, we need to know the value of that resource relative to other frequency response sources, and how much and where (topologically) such rotating mass-based resources must be located for maximum effectiveness. Early studies suggest that inverter-based resources can be used to great advantage to manage frequency control and response and voltage, if we first identify the necessary performance expectations on a technology-neutral basis and build those into grid participation requirements.

Building portfolios to mitigate risk – We have a complex society and a complex grid with conflicting sets of goals and requirements.  Our electronically-based, electricity-dependent society needs a mix of fast, flexible, clean, resources that collectively deliver a low-cost, high-reliability, highly resilient energy system.  Diverse supply- and demand-side resources should be assembled in portfolios that have a solid probability of meeting societal and operational goals effectively under a wide variety of possible future paths, under a reasonable range of costs.  Market operators are trying to incorporate societal needs and state preferences into reliability and market rules, but they need help (as do state and federal regulators) to design cost-effective, risk-moderating portfolios of supply- and demand-side resources that will deliver lasting value under diverse, uncertain future paths.  DOE and NERC should work with stakeholders to conduct research and offer guidance on better portfolio design.

Subsidies – Every type of energy resource today receives some type of support or subsidy.  Oil and gas get depletion allowances, renewables get production tax credits, investment tax credits and R&D, nuclear generation gets insurance, R&D and construction work in progress, natural gas gets depletion allowances and R&D, and so on.  But new subsidies for coal and nuclear plants won’t level the playing field relative to renewables nor undo the impact of old subsidies – they’ll just make the playing field even bumpier. 

Any new subsidies – including direct state payments, out-of-market uplift payments, or potential cost-of-service payments for non-competitive resources -- should have a specific purpose and a limited duration.  As renewable PTCs end, Congress and regulators should consider also ending old subsidies of traditional resources insofar as they are based on outdated assumptions about the unique role and value of these resources.

Better information and modeling – Effective power system planning and operation requires a solid set of models and forecasts of supply resources and loads whose behavior is interdependent and hard to predict.  EIA, FERC, NERC and the reliability coordinators should be directed to collect more information to improve models and forecasts of the individual and compound interactions of rapidly changing loads, behind-the-meter resources, demand response and energy efficiency, and all supply-side resources.

Decision processes – Regulatory and administrative law processes can be painfully slow.  So are NERC and reliability coordinator stakeholder processes, which can produce decisions and outcomes that don’t always favor reliability and resilience over entrenched interests and precedent.  This is not news, but the grid and reliability challenges are moving faster than ever and formal decision processes aren’t keeping up.  It is worth taking another look at whether there are good reasons and effective methods to make critical time-sensitive, reliability-affecting decisions more quickly.

In closing

Secretary Perry’s April memo raised important and timely questions about power system reliability and resilience.  We designed the Staff Report’s technical analyses to explain why and how changes in the bulk power system economics, technology and markets caused coal, nuclear and natural gas plant retirement. There is much more work to be done to determine the evolving nature of reliability and resilience requirements, and to identify the additional changes in technology, economics and markets associated with a modern grid. This broad set of challenges will require far more than 60 days to study, understand and implement effective, forward-looking solutions.