Covid Impacts on PJM Demand

Like everyone else, PJM has had to react to the impacts of Covid-19 on their operations. Their Systems Operations Subcommittee has created an Operations Pandemic Coordination Team to discuss pandemic coordination operations. In addition, weekly on Fridays, PJM is providing status updates for each state and other members/stakeholders.

PJM Planning Committee has also been generating weekly updates on Covid-19 impacts to load. The graph above was taken from the most recent (April 14, 2020) presentation. Here are the findings:

• On weekdays last week (week of 4/6), peak came in on average 8-9% lower (~7500 MW) than anticipated.

• Largest impacts so far were around 10-11% (~9500 MW) on 3/26.

• Energy has been less affected, with average weekday reduction since mid-March being 7%.

• Weekends have been impacted less (~2-4%)

Take-aways: Obviously the change in work patterns via stay-at-home/shelter-in-place orders have impacted demand, but how so? What about the huge increase in unemployment? If the 8% reduction in peak is coincidental load, does that mean the energy footprint of our office employees while at work is higher than when working from home? What about the weekend load, is that all retail closures? Difficult to say at this point what the root cause is with so many variables.

What the PJM Generation Retirement Queue Currently Looks Like

Courtesy of PJM

Two weeks ago I was asked to assist with the startup of one of four converted coal-to-natural gas boilers in Virginia. At the plant, a 150 MWe, eight boiler coal fired cogen plant, half of the boiler burners were being converted to natural gas. What I was hearing for the reasoning behind the investment mirrored what you have read in the news - it was just too expensive to operate while burning coal.

So, like any engineer, it got me thinking about how ubiquitous these conversions or closings actually are. Fortunately, PJM maintains an awesome website with tons of downloadable data. Under the Planning section of their site you can find a list of power plants who have applied for deactivation. I was able to download this data and run some quick analysis. Note that these are planned deactivations and the applications can be withdrawn in the future (so no guarantee of retirement).

In PJM’s retirement queue, as of March 27, 2019, there are 62 plants representing about 12,722 MWs of capacity. Coal fueled plants represent about 40% of the number of plant retirements, and about 55% of the capacity. Note that while only 5 nuclear fueled plants are retiring, they represent another 37% of capacity (92% of capacity retirement is from coal and nuclear)!

Data courtesy of PJM

Data courtesy of pjm

And my next question was, “in what states are the coal and nuclear retirements from?”

Data courtesy of PJM

Data courtesy of pjm

As you can see, plant retirements in Ohio dominate all others. Total plant retirement capacity in Ohio is 5934 MW, or about 46% of all PJM retirements.

Fortunately for us, the Ohio Public Utilities Commission (PUCO) publishes a long-term energy forecast that details current and forecasted energy generation, consumption, and other great info. Turns out that as of December 2018, Ohio gets 45% of it’s electricity generation from coal fired sources, 38% from natural gas, and 15% from nuclear. And in 2016, the non-coincident summer peak load was 31,469 MW. Now, if we figure the PJM plant projected retirement date goes out to 2020/22, that means Ohio could lose 20% of it’s capacity in the next three years!

Graph courtesy of Ohio Public Utilities Commission

And so what is our take-away from this shallow dive? There is an obvious disproportionate amount of coal-fired assets that are currently planned to retire, but there is also a surprisingly large capacity of nuclear planned as well. Those who advocate coal plant retirement as an environmental goal will be pleased, but keep in mind how much emission free nuclear energy is going with it. Also keep in mind that along with these fuel types goes a stable base-load asset with fuel that is cheaply stored on-site.

Another interesting finding was PJM’s Learning Center that discusses (in plain English) what steps are taken when a generating plant retires. See the image/diagram below (from PJM). In short, generator retirements and any required system upgrades to keep the grid running smoothly are included in the PJM Regional Transmission Expansion Planning process.

Explaining Power Plant Retirements in PJM

Per PJM:

PJM Ensures that replacement generation is available to cover lost MWs from the retired plant - this replacement could come from newly built power plants, upgrades to existing plants, or from sources external to PJM. PJM’s capacity market helps secure power supply resources to meet future demand on the grid.

Since transmission lines and distribution lines are all interconnected, upgrades to the system allow electricity to flow on multiple paths and in turn increase the overall flow of electricity.

This means that these kinds of upgrades typically end up bringing more MW (in this example, 1000 MW) onto the system as a whole than the amount of MW lost (800 MW) at a single point, from the retired plant.

Distributed Energy Resource (DER) Siting

Interesting article in the new SolarPro about how states (California) are pushing utilities to use their capacity and capital planning information to optimize the siting of PV and storage projects.  As many of us know, the interconnection process for large commercial and utility projects can be a game of chance.  What the line capacity is (and therefore how big the system can be) and whether there are required upgrades is determined after a lengthy review.  The initial responses generally include hefty cost estimates to proceed with what amounts to a nameplate size significantly less than what was proposed.

The CPUC (California Public Utility Commission) created two working groups to address the issue: the Integration Capacity Analysis (ICA) and the Locational Net Benefits Analysis (LNBA).  Above is the heat map for the LNBA demo.  Per CPUC, "the goal is to ensure DERs are deployed at optimal locations, times, and quantities so that their benefits to the grid are maximized and utility customer costs are reduced."

Why is this important?  Consider the $2.6 billion planned transmission project upgrades in California that were recently revised down, accounting for higher forecasts of PV and energy efficiency projects.  And besides the avoided costs, don't forget all the grid upgrades DER developers are paying for that benefit all consumers.  This is a key factor in the debate over whether PV owners pay their fair share, or rather whether non-DER owners are subsidizing DER projects.  With the federal investment tax credit decreasing to 26% in 2020, 21% in 2021, and 10% in 2022, the models generated in the CPUC exercise can be used to reduce development costs, defer distribution and transmission capital improvements, and lay the groundwork for incentivizing grid-beneficial siting.