Here is my experience with a PJM generator retirement. Part I/II
FERC should mandate DLRs on existing Tx Lines.
Federal Energy Regulatory Commission (FERC) approved a $796 Million transmission plan over the objections of multiple parties, including the Maryland Public Service Commission, Maryland Consumers Advocate and the Organization of PJM States. These $ 796 Million transmission improvements are needed because Talen’s Brandon Shores generator is retiring, according to PJM.
Source - https://www.talenenergy.com/plant/brandon-shores/
While I don’t have experience with Brandon Shores specifically, I have recent experience with a generator retirement in PJM similar to Brandon Shores. I share my experience below for others to learn from my experience.
First, it is important to share that transmission lines are rated at 95 degrees Fahrenheit. But most locations hardly experience 95 degrees all around the year. Hence, the state and Federal commissions should mandate dynamic line ratings, which increase the ratings by 40% before approving transmission line rebuilds.
Second, to make the case for a battery to replace the retiring generator, PJM needs a generator replacement tariff like MISO. PJM also needs a Storage As a Transmission Only Asset tariff like MISO. Before building the regulatory case for a transmission line rebuild, utilities should rigorously explore all options. Consumers and advocates must know how to address these transmission lines rebuilt due to generator retirements.
Reliability Must Run (RMR) Payments set the bar.
When a generator announces its intention to retire, PJM runs a reliability study to decide whether it can retire as planned or needs to stay online. If PJM determines that the generator needs to stay online, PJM pays for that generator to stay online.
Reliability Must Run (RMR) payment is the cost of keeping the generator online. Before paying a retiring generator to stay online for reliability, MISO checks if a demand response or other non-transmission alternatives are possible. PJM does not have a process for that. MISO only pays for the variable O&M costs to keep the plant online, and the decision for RMR payments is not indefinite. Those RMR payments are only for one year; at the end of the year, MISO checks for non-transmission alternatives again.
Back to PJM, I found that this RMR payment was a big barrier to bringing alternatives to a transmission line (“Tx Line”) rebuild because the utility was comparing the cost of the Tx Line rebuild to the RMR payment and found that rebuilding the Tx Line was less expensive. Instead, the cost of the proposed Tx Line rebuild must be compared to the proposed alternatives, such as Battery Energy Storage System (BESS) and Dynamic Line Ratings (DLRs).
Which transmission lines are overloaded, and by how much?
When PJM ran the reliability study to determine whether the generator needed to stay online, it also identified the overloaded transmission lines under single and double contingencies, as required by NERC transmission planning standards.
I wish NERC standards explicitly stated that BESS and DLRs are viable options to address overloads.
Not all overloaded transmission lines needed to be rebuilt. But one particular one became the core issue in my experience. PJM showed that under at least 2 scenarios – generator deliverability and generator re-dispatch, the transmission lines were overloaded by x%. Since transmission line ratings are considered Critical Energy Infrastructure Information (CEII), I am not allowed to discuss the actual rating of the line, or which line, for that matter.
My training and experience in transmission system modeling came in handy when evaluating the percentage overloads. Typically, there are base case violations and contingency case violations. Base case violations show how much the line is overloaded when the system is intact, meaning as is. Contingency case violations occur under single contingencies (one transmission element – a Tx line or a substation is taken out) or double contingencies (two transmission elements are out simultaneously).
In the case of the PJM generator retirement, I found that x% overloaded this particular Tx line under the generator deliverability scenario and y% under the generator re-dispatch scenario.
What is the generator deliverability scenario?
When a generator retires, the PJM operator studies whether that single generator is needed and what happens if the retiring generator is removed from a cluster of generators that need to deliver their output. PJM runs this study for all new generators also – hence the name generator deliverability – can the generators deliver their combined output?
What is the generator re-dispatch scenario?
When an overload occurs on a transmission line in real-time due to another transmission line taken out of service (either due to a storm or planned maintenance), then there are options for the PJM operator to re-dispatch, meaning re-route the transmission flow by reducing the generators that are causing that flow or by increasing the generator's output elsewhere in the system. This action is called generator re-dispatch. Operators do this all the time; it is a Standard Operating Procedure.
Moving back to the results of the generator deliverability and generator re-dispatch scenarios that showed the Tx line overloaded at x% and y%, respectively, that set the goal to meet for any other alternatives. If I had proposed a battery, I needed to show that the battery met the overloaded x% and y%. If I had proposed DLRs, the new ratings must meet the new conductor minimum ratings.
Source - https://www.pjm.com/-/media/committees-groups/committees/oc/2021/20210330-special/20210330-item-01-dynamic-line-ratings-overview.ashx
Can transmission utilities relieve the overloads if transmission line ratings are dynamic instead of static?
It is important to understand that Tx line ratings are Rating A, Rating B and Rating C. Rating A is a normal or continuous rating. This rating A value shows how much power can flow on the Tx line continuously. Rating B is an emergency rating that shows how much power can flow on the Tx line under emergency conditions for less than 2 hours. If Rating A is 100 MVA, Rating B is typically 130 MVA. Rating C is an emergency rating for 15 minutes that shows how much power can flow on the Tx line under emergency conditions for 15 minutes. Typically, Rating C is 50% higher than Rating A. Hence, 150 MVA in our hypothetical scenario.
One way to argue whether a Tx line rebuild is needed is by making the case to move to a dynamic line rating instead of the static value. A static value does not consider wind speed, ambient temperature and other factors that influence the rating of a Tx line. But to be an effective solution to a Tx line rebuild, it is important to show that the dynamic rating of the existing Tx line meets the x%/y% overload scenarios mentioned earlier (generator deliverability and generator re-dispatch).
Source - https://www.pjm.com/-/media/committees-groups/committees/oc/2021/20210330-special/20210330-item-09-installation-considerations-education.ashx
Dynamic Line Ratings (DLRs) are most commonly known to increase the rating of a Tx line by 40% compared to a static rating. So, if the x and y% of the overloaded are less than 40%, the DLRs would be an effective solution. Rating C was 50% higher in my experience, but DLRs could only get me up to 40%. So, I fell flat.
Tx Line ratings' relationship with temperature is important to consider.
Tx Line ratings are rated at 95 degrees Fahrenheit. This fact means that in my hypothetical Rating A/B/C of 100 MVA/130 MVA/150 MVA, those ratings are valid for a temperature of 95 degrees Fahrenheit. It is common knowledge that when temperature increases, there is a greater chance of heating the transmission line. Hence, temperature-related overloads are called thermal overloads. Since DLRs take into account ambient temperature, they can address thermal overloads.
It is also common knowledge that not all locations experience 95 degrees all the time. Take the example below for Norfolk International Airport in Virginia, which is in the PJM region. Yes, the temp is greater than 95 degrees during some months for the 23 year historical data, and for some hours during those months - but not all around the year.
Source - https://nowdata.rcc-acis.org/akq/
You can research this issue and find if there is a location on Earth that has a constant 95-degree temperature all year round. Please drop me a note if you find that location.
My point is that temperatures are in the high 80s in summer when there is a peak demand on the transmission system. Yes, at some locations, temperatures reach greater than 95 degrees, but it doesn’t stay long because the wind picks up and cools down the Tx Line. As a result, the thermal overload is reduced.
That wind speed and temperature correlation brings me to tie the DLRs to the Ratings A, B and C. Recall that Rating B is for 2 hours generally, and Rating C is 15 mins. So, to prove DLRs are viable alternatives to a Tx line rebuilt, I need to prove that moving to DLRs can reduce the thermal overloads, AND the location's temperature hardly ever reaches 95 degrees Fahrenheit. Because even if the location has a temperature of 95 or greater than 95 for a single hour, the game is over.
But there is a bigger point here for the electric utility industry. Because the transmission line ratings are assuming 95 degrees, and any given location hardly stays at a constant 95 degrees, it makes a case for our transmission utilities to move to DLRs. If our utilities moved to DLRs, we could realize 40% of the existing Tx capacity. So, the FERC should mandate DLRs on existing Tx Lines.
The cost of DLRs is way lower than the cost of Tx Line rebuild.
DLRs are sensor utilities attached to Tx towers without seeking PJM’s permission to schedule an outage on the Tx Line. The cost of these sensors is much lower than that of a transmission line. But DLRs could only get me to 40% not 50% - Rating C, plus the RMR payments were an anchor. Both these points made the lower DLR cost a moot issue.
In the next installment, I will discuss BESS.