Changes to PJM's Capacity Market: What is the Impact on Consumers?

PJM’s capacity market results in higher-than-necessary electric bills for consumers as a result of two problems: (1) high clearing prices, and (2) over-procurement of capacity. When high clearing prices appear in a capacity market, they are a reflection of overestimating customer demand and generator costs—which ultimately get passed on to utility customers. As discussed in our recent report on PJM’s capacity market, over-procurement occurs when the grid operator overestimates its peak demand and cost of new generation (or “net CONE”), resulting in avoidable spending on additional capacity payments and generator investments and, as a result, extra costs charged to customers.

In the past year, PJM capacity market rules have experienced significant changes affecting customer bills. For instance, the latest revision to the PJM’s Minimum Offer Price Rule (MOPR) in September 2021 changes how the floor price that generators receive for capacity is determined for various resource types, which also impacts the price of electricity on customer bills. The most recent change came on January 20, 2022 when the Federal Energy Regulatory Commission (FERC) ordered PJM to halt the use of an adder used to raise generators’ expected costs in its 2023/24 capacity auction. According to FERC Commissioner Richard Glick, methods to maximize prices in PJM’s capacity market conflict with FERC’s regulatory mission:

“Sometimes I felt like we were just making stuff up in order just to increase prices...It's important that we go back to basics and figure out what is truly just and reasonable and not focus extensively on bolstering uneconomic generation.”

FERC’s January 20th order targets the 10 percent adder used in calculating generators’ fuel cost risks; without the adder, capacity charges on customer bills should be lower. Estimated fuel cost risks are used in PJM’s methodology for calculating the cost of new generators (called “net CONE”) and impact the price generators receive in the capacity market. The 10 percent adder raises costs to consumers by: (1) increasing generator bids which, in turn, increases the clearing price, and (2) inflating the demand curve (due to a higher net CONE) which results in increases to both the clearing price and cleared amount—all of which gets passed on to consumers as higher electric bills.

What concerns remain after these substantial changes? For the issue of high costs to consumers, FERC’s order removing the adder should have the effect of lower capacity charges on customer bills, but it’s complicated. As long as PJM overestimates demand in constructing its capacity market, over-procurement of capacity will persist. “Fat market” conditions due to over-procurement allow power plants to remain online (as well as new ones to be built) despite being uneconomic and not needed to provide reliable electric service for meeting peak customer demand. The impacts of over-procurement could be resolved by PJM reconsidering its methodology for estimating future demand and by implementing changes in market design to address the concerns of communities in close proximity to power plants. Actions, such as FERC’s January 20th order, act to lower PJM customer bills, but there is still more that needs to be done to eliminate flaws in PJM’s capacity market design that have kept uneconomic, unnecessary generating capacity online across the PJM region.

Sagal Alisalad

Assistant Researcher

Joshua Castigliego

Researcher

This is a part of the AEC Blog series

Gas Utilities Explore Hydrogen as a Decarbonization Strategy

To meet state and local climate goals, gas utilities across the United States are looking towards alternative fuel sources such as hydrogen and biogas—also referred to as renewable natural gas (RNG)—to decarbonize their future gas supply. Along with maximizing energy efficiency and making further investments in gas infrastructure, recent planning documents from gas utilities like National Grid and Washington Gas highlight a shift towards low and zero-carbon fuels such as RNG and hydrogen.

Hydrogen is not an energy source itself; it is an energy carrier. There are several types, or “colors”, of hydrogen that are distinguished by the energy source and process used to produce it. “Green” hydrogen—which is produced through electrolysis of water using electricity from renewable sources such as wind or solar—releases zero greenhouse gas emissions when burned for energy. Green hydrogen itself is not a zero-emission fuel source: If leaked directly into the atmosphere green hydrogen is an indirect greenhouse gas and its combustion has been found to emit nitrogen oxides (NOx), which is a criteria air pollutant. Since it can be mixed with fossil-sourced gas, green hydrogen is attractive to gas utilities who want to continue to use their existing gas pipelines while attempting to comply with climate mandates.

Several economic, technical, and infrastructure barriers stand in the way of using green hydrogen in decarbonization:

Green hydrogen is more expensive than its dirtier counterparts (e.g., hydrogen made using fossil fuels), fossil fuels themselves, and grid electricity.
Hydrogen production is inefficient. The International Renewable Energy Agency estimates that 30 to 35 percent of its energy is lost during electrolysis.
Hydrogen poses a risk to public safety. Hydrogen molecules are more likely to leak through pipeline imperfections and escape existing gas pipelines; hydrogen can also degrade the materials used for pipelines.
Due to insufficient infrastructure, and regardless of demand, hydrogen could only be injected into existing gas pipelines to make up 5 to 15 percent of total gas volume.

Even if these barriers could be overcome, an important question remains: Is the production of green hydrogen the best use of renewable resources?

Electrification, or the replacement of fossil-fuel dependent technologies (like gas and oil heating systems or gasoline-powered motor vehicles) with those that rely on electricity, is an alternative decarbonization method gaining traction across the United States. When sourced from renewables, heating our homes with electricity rather than gas or gas mixed with hydrogen, can significantly reduce emissions without the safety concerns of piped gas and costly infrastructure upgrades needed to make hydrogen work.

As the United States works towards electrifying sectors throughout the economy, the demand for electricity, and subsequently the demand for renewables, will rise. The use of green hydrogen as energy storage in time periods when the supply of renewables exceeds electric demand may be a viable option worth comparing to other storage technologies, but maintaining and improving costly gas delivery infrastructure is far less likely to make sense economically or socially.

Tanya Stasio Researcher

Joshua Castigliego Researcher

This is a part of the AEC Blog series

The "Colors" of Hydrogen

The appropriate role of hydrogen in achieving global climate goals—especially in hard to decarbonize sectors—is an important area for consideration in today’s climate plans. Although hydrogen itself is a zero-emission fuel, it can result in substantial upstream greenhouse gas emissions depending on the method used to produce it.

Hydrogen is an energy carrier, not an energy source. Hydrogen is produced from an energy source through various processes such as electrolysis, steam methane reformation, or gasification using either fossil fuels directly or electricity produced from renewables, fossil fuels or nuclear. Not all methods of hydrogen production are equal when it comes to climate impacts. Several categorization systems exist to distinguish between hydrogens made from different fuel and electric sources. For example, the North American Council for Freight Efficiency (NACFE) categorizes hydrogen into different “colors” based on initial energy source and production process.

A 2018 policy briefing from the Royal Society reports that about 95 percent of global hydrogen production is sourced from fossil fuels including:

Grey hydrogen extracted from gas using steam methane reformation,
Brown/black hydrogen extracted from coal using gasification.

Other types of hydrogen are starting to gain traction as various industries work to decarbonize, such as:

Green hydrogen produced by electrolysis of water, using electricity from renewable sources such as wind or solar resulting in zero carbon emissions, and
Blue hydrogen produced from fossil fuels (i.e., grey, black, or brown hydrogen) where carbon dioxide is captured and either stored or repurposed.

The industry group that promotes hydrogen use produced a study suggests that a combination of green and blue hydrogen can meet the world’s hydrogen demand and be cost competitive compared to grey hydrogen (fossil gas derived hydrogen) by 2035.

Utilities across the United States (and around the world) claim that green hydrogen has an important role in decarbonizing their future gas supply and meet local and state climate goals. In theory, hydrogen could be injected into existing gas pipelines to make up a small percentage—5 to 15 percent—of the total gas volume.

The U.S. Congressional Research Service has found that major infrastructure upgrades will be needed before we see a higher share of hydrogen blended with conventional gas. Hydrogen molecules are smaller than methane and therefore more likely to leak through pipe imperfections and even permeate gas pipelines; hydrogen can also eat away at common materials used for gas pipelines.

Hydrogen may have a role in a decarbonized future, but there are substantial technological and infrastructure challenges to its use in heating and providing electricity. Hard to decarbonize processes or sectors (e.g., transportation, high-heat industrial equipment, etc.) may benefit the most from utilizing hydrogen to achieve greenhouse gas reductions.

Joshua Castigliego Researcher

Tanya Stasio Research Assistant

This is a part of the AEC Blog series