The Market Implementation Committee will be asked next month to choose between a PJM proposal and one from the Independent Market Monitor to resolve pricing and dispatch misalignment issues in the RTO’s fast-start pricing plan.
At the MIC meeting Wednesday, PJM’s Tim Horger outlined the RTO’s plan, which calls for three “work streams”: short-term market changes to address pricing alignment; LMP verification “enhancements and clarifications”; intermediate operational changes to implement more “regimented” real-time security-constrained economic dispatch (RT SCED) case approvals; and long-term operational changes to investigate changing SCED timing and consider previous dispatch instructions.
PJM’s proposed short-term fixes align the locational price calculator (LPC) to use the reference RT SCED case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
“PJM is committed to both the short-term changes and the intermediate changes,” Horger said. “We will be moving forward with these.”
Proposed short-term implementation | PJM
Rebecca Carroll provided a timeline for the PJM intermediate solution that calls for conducting operator training and making software changes to limit automatic execution of RT SCED cases to once for every five minutes. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.
Carroll said PJM already switched from a three-minute interval to four minutes for operators in February, moving closer to the desired five-minute dispatch interval. Carroll said no adverse impacts to pricing were discovered with the time change, but she said closing the gap gives less flexibility for operators to make changes in real time and urged being “cautious” before taking the next step.
The “more regimented five-minute case approval [is] very different from what PJM’s operators see today and have done [as long as] they’ve worked for PJM,” Carroll said. “It’s definitely going to be a philosophy shift in the control room.”
Catherine Tyler of Monitoring Analytics presented the Monitor’s proposal, which was originally the joint package between it and PJM. The RTO withdrew from the proposal at the April 15 MIC meeting.
Tyler said the proposal includes changes to dispatch SCED calculations and settlements, while the PJM proposal only includes making the settlement changes.
“The difference is not in the timing of implementation so much as commitment to making all of the changes that need to be made,” Tyler said.
Carroll and Adam Keech, vice president of market services, insisted the RTO is committed to making the changes, although it can’t say when. “PJM is planning to move forward to a five-minute periodic dispatch,” Keech said. “We need to take operational precautions … we need to learn along the way.”
Stability Limits in Markets and Operations
PJM’s Joe Ciabattoni told the MIC that the RTO could support the Monitor’s proposal to use capacity constraints to curtail generating output when needed to maintain stability during maintenance outages or continue using thermal surrogates.
Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units.
After stakeholder discussion and feedback at April’s MIC meeting, “PJM can still jointly sponsor the existing package with the IMM but can also support the status quo,” Ciabattoni said. (See “Work Continues on Stability-limited Generators,” PJM MIC Briefs: April 15, 2020.)
Ciabattoni said some of the feedback received from stakeholders was that the stability constraint or generator output constraint doesn’t fully resolve the issue that the LMP would not be aligned with the dispatch signal. Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
Tyler reviewed the Monitor’s proposal. It says surrogate constraints are not modeled consistently in the day-ahead and real-time markets, resulting in differences that traders can take advantage of.
PJM’s Thomas DeVita provided an update on the RTO’s response to a complaint filed with FERC last month over its forfeiture rules for financial transmission rights.
XO Energy asked FERC to order PJM to change its FTR forfeiture rule or abandon it and adopt “a structured market monitoring approach” like the one used by Trader Challenges PJM FTR Forfeiture Rules.)
DeVita said he couldn’t give specifics as to how PJM is going to respond to the complaint, but he said the RTO’s answer will focus primarily on compliance with FERC’s January 2017 order (EL14-37). In that order, FERC instructed PJM to change how it implements the forfeiture rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
PJM filed Tariff revisions in April and June 2017 describing its new approach (ER17-1433). In September 2017, the RTO began billing forfeitures based on its new approach, XO said in its complaint, even though the commission has never acted on it.
“It’s been pending at FERC for three years, which is a significant amount of time, even by FERC standards,” DeVita said.
Comments on the XO complaint are due June 1.
PJM Seeking Consultant on ARR FTR Task Force
PJM is seeking a consultant to aid the ARR FTR Market Task Force in a review of the FTR and other markets.
PJM’s Dave Anders said the consultant is being hired in response to a recommendation of the Report of the Independent Consultants on the GreenHat Default, which called for expert help “to conduct a general review of the FTR market and other PJM markets in order to evaluate risks and rewards of structural reforms.”
After focusing primarily on the education portion of the key work activities, Anders said the task force has reached the point of needing to engage expert help in the review process.
The scope and timing of the review is currently being developed, Anders said, with PJM looking at the task force’s remaining key work activities to determine what can be accomplished and what should be put on hiatus during the external consultant review. The scope and timing plan will be discussed at the next task force meeting on May 27, Anders said, which has been cut back to a half-day of discussion.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked if PJM has a sense of what the external consultant’s mission will be. He said it would be important to have an idea of the scope of the work ahead of time in order to pick the right consultant.
Anders said PJM is currently working on the scope and welcomed ideas from stakeholders on what they would like to see included in the work.
“We want to share the scope with stakeholders, but we’re not really ready yet because it’s still in development,” Anders said. “The selection is going to be interesting because there certainly are a number of experts out there that have deep knowledge of the products and the market.”
‘Quick Fix’ for NITS Rule
The MIC approved an issue charge and a “quick fix” Tariff revision to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). PJM requires load-serving entities to sign NITS agreements and post collateral based on their peak market activity. The expected duration for Tariff revisions is two to three months. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)
If another television commercial or online public service announcement intones this lazy, probably insincere attempt to offer comfort during our collective pandemic experience, I might throw my laptop or television out a window. I might — except, because I’m largely confined these days to a single-story building, it wouldn’t result in the effect or satisfaction that is supposed to accompany this fit of pique. Cranky? Yes, I am! Along with many of my fellow pandemic inmates in cell block H. But while out in the exercise yard walking the dog recently, it struck me that another addition to our virus vernacular, “flatten the curve,” might offer a useful way to think about emerging challenges facing electric grid operators.
As we now unfortunately have all come to understand, in pandemic terms, “flattening the curve” refers to slowing the otherwise exponential spread of a virus to avoid overwhelming limited health care infrastructure and human resources. The analog in our industry is “flattening or shifting the peak,” and it’s not something we’ve historically done well.
Years ago, I likened grid planning and resource adequacy to a church designed to ensure every congregant, visitor, curious heathen, adherent to family tradition and the like was guaranteed a seat for Easter services, with 15% more pews added over the forecast attendance for good measure. As times changed, I shifted toward a more secular illustration: the example of a fictitious ordinance by the city of New Orleans requiring construction of hotels to cater to every person who might want to attend Mardi Gras, plus a prudent reserve. That’s a lot of excess capacity to expect the local hospitality industry to carry over the many sweltering, hurricane-threatened months when most sane tourists would opt for Maine or Yosemite over Bourbon Street.
The point was not to suggest that electricity should be planned and provided like church pews or hotel rooms. Society values continuous, on-demand electricity differently and for many good reasons. But still, the laws of economics aren’t suspended when it comes to our industry. Carrying large, fixed costs associated with infrastructure lying fallow for months on end is either quickly unsustainable or results in high tariffs that over time shift the supply-and-demand equilibrium, resulting in a suboptimal allocation of consumer and producer surpluses and reduced total economic well-being. In other words, in most industries, while shortage may not be a good thing, it is at least a necessary evil.
For grid operators and planners, demand is still largely unexposed or is inelastic to price. Shortage isn’t an option. And the price of electricity, despite being delivered like a guaranteed hotel room during Mardi Gras, is still a good deal as a “value proposition” for most consumers. But from the perspective of those interested in designing organized wholesale electricity markets, the economic inefficiency of our industry’s infrastructure profile keeps people working on demand response, advanced metering and regulatory reform to expose more customers to actual real-time prices for electricity in the wholesale market. Here, the hope is that prices can be harnessed to change consumption behavior to flatten peaks through a curtailment or temporal shift of consumption. As mentioned, despite huge theoretical promise, as an industry we have had modest success at best in identifying and controlling discretionary consumption through either price or programs.
Today, new fronts have opened to tackle this problem. The motivation here isn’t the economic inefficiency associated with transmission and generation infrastructure in waiting. Rather, the concern is operational. Public tolerance to ever-expanding infrastructure, particularly transmission, is limited. Let’s face it: Electric infrastructure has less aesthetic appeal than a cathedral and arguably even less than a Trump Tower hotel. More salient, is the changing generation resource mix and, in particular — through policy mandate, customer preference or otherwise — the increasing penetration of intermittent, renewable wind and solar generation. We’ve all heard of CAISO’s “duck curve” and seen ramp rates become steeper year after year. In a carbon-constrained world, the role of flexible natural gas generation to “back up” and follow load is viewed as a temporary solution at best. So, we redouble efforts to conform an uncooperative supply curve populated by intermittent generation to an inviolate load curve.[efn_note]Admittedly one can find isolated, but significant, efforts by certain large customers to change consumption patterns to better align to the limits of the supply curve. For example, Google, which has a goal of real-time, 24/7 zero-carbon operations, has begun shifting the timing of computing functions that are electricity intensive at data centers “to when low-carbon power sources, like wind and solar, are most plentiful.” https://blog.google/inside-google/infrastructure/data-centers-work-harder-sun-shines-wind-blows/We can hope this kind of participation by large data center customers will eventually involve a more complex optimization of business needs, the availability of renewable electrons, electricity price and communication costs across multiple data centers located in different geographies and in different electricity markets. These actions will change load shape to better conform to a changing supply shape.[/efn_note] We ruminate over ideas such as building more transmission to move solar power from Arizona at the speed of light to meet the 8 a.m. morning pick-up in Los Angeles when the sun is still low in the sky over coastal California, and then push overabundant California solar back to Phoenix as the sun begins to set out there. What about batteries and the promise of other advanced clean technologies to add to our supply mix? It’s old news to note that increasing reliance on renewable resources is creating new challenges for system operators responsible for reliably ramping a system up and down to meeting its peaks.
Timing of March/April weekday peaks in PJM | PJM
Fine. But what has the pandemic got to do with any of this? The answer is what today’s grand and involuntary social experiment shows about grid performance and the attendant price outcomes associated with new and different load curves. And while quarantines and shutdowns may persist, they are finite. So, the more interesting point to consider is how more permanent social distancing, work from home and staggered industrial production scheduling could change the load shape, and the grid operation, carbon and economic implications that in turn would follow from this change.
Recently, PJM published data illustrating aggregate impacts of the pandemic situation on its operations over the past six weeks. Of course, it showed overall energy consumption had declined across the region, in a range of about 6 to 8%. It also showed that the peaks had declined by a greater amount — more like 10 to 12%. But things get more interesting looking at the ramp or load shape. Yes, the morning pick-up started later, but it also appears less concentrated in the 7 to 9 a.m. hours and spread out over a longer time period[efn_note]The graph on page 9 of the following document, in particular, illustrates changes to peaks: https://pjm.com/~/media/committees-groups/subcommittees/las/2020/20200505/20200505-item-03-covid-19-impact-update.ashx[/efn_note] — a “flattening of the curve,” if you will. Other operators are also showing evidence of a more gradual and delayed morning peak just like PJM; implications to the evening peak are less conclusive.[efn_note]NYISO spokesperson Zach Hutchins reported: “We continue to observe a more gradual morning ramping period.” (April 2, 2020 9:45 a.m.) https://www.nyiso.com/covid[/efn_note]
I’m not one to characterize anything associated with our current human health and economic catastrophe as a “silver lining.” But very early observations suggest that certain “new normal” post-COVID scenarios affecting how society lives and works may change load behaviors in a way that decades of price incentives and regulatory programs have largely failed to do[efn_note]The data we have after just six weeks of a shutdown that has occurred during the industry’s shoulder season serves as only a glimpse of what we might expect by way of more permanent changes in load profiles.[/efn_note] — behavioral changes that cause a temporal shift in electricity consumption, flatten the peak and, thus, reduce the strain on a supply side increasingly challenged to meet peaks as it transitions toward cleaner, carbon-free resources.[efn_note]It’s also sometimes easy to forget that in order to meet decarbonization goals, the electric sector is going to have to do more. The electrification of transportation, industrial processes and heating in buildings will increase total consumption and also affect consumption patterns.[/efn_note]
To further burden the analogy, a monthlong Mardi Gras allowing access to more people on less costly terms may be less intense, less fun and have a less obvious crescendo, but it’s probably healthier. More gradual load curves that reduce reliance on fossil-fueled, load-following generation promise beneficial carbon reductions while buying additional time for the development of clean supply side and storage technologies.
It remains to be seen — in fact, I have heard these are “uncertain times” — whether we will return to the “good old days” or instead a “new normal” of social distancing with different patterns of work and life. I hope it’s Door No. 1. But the thought nagging me is that we might be better positioned to address our other evolving global crisis, the climate, if we are forced for health reasons to change how we live and work and, as a consequence, we flatten the curve; that is to say, the load curve.
Vincent Duane is presently consulting through his firm Copper Monarch, LLC. He was previously the Senior Vice President: Law, Compliance & External Relations at PJM Interconnection, LLC.
Texas regulators last week adopted rules establishing a cybersecurity monitor and coordination program for investor-owned, municipal and cooperative utilities that count on their voluntary participation (49819).
The amendments to the Texas Public Utility Regulatory Act (PURA) don’t require utilities to participate or to submit documents to the monitor. Utilities have made the rules’ voluntary nature a key issue in the proceeding.
But that left members of the Public Utility Commission nonplussed over comments made in the docket. Chair DeAnn Walker said during the commission’s open meeting Thursday that she was “taken aback” and “floored” by some of the stakeholders’ comments “and some of the people making those comments.”
The amendments are the result of two bills approved last year by the state legislature. Senate Bill 64 established the cybersecurity coordination program to share guidance on best practices, while SB 936 set up the cybersecurity monitor.
“Over the years, we have had input from the legislators that they clearly wanted something like this,” Walker said.
Commissioner Arthur D’Andrea said that he too was “taken aback” by the utilities’ comments, noting that the PUC has stood “shoulder-to-shoulder” with its stakeholders during the recent legislative session.
Commissioner Arthur D’Andrea
“While [the program is] voluntary, this is not an audit,” he said. “We want to protect their data, but we do expect participation and cooperation.”
When several utilities asked that “voluntary” be added to the rule, the PUC responded by saying the “voluntary nature of participation … is made clear throughout the rule.”
Monitored utilities will contribute to the program through their administrative fee to ERCOT. Those outside the ERCOT footprint will pay for the monitoring under a separate fee.
Any Texas utility “may” participate in the cybersecurity coordination program at no cost.
Commissioners Defend PUC Staff
Walker and D’Andrea both defended commission staff after they felt staff’s comments on an ERCOT Nodal Protocol revision request were devalued in a grid operator stakeholder meeting last week (NPRR1020).
PUC staff filed joint comments with ERCOT staff on NPRR1020, which clarifies that emerging battery storage technologies can be interconnected and operated as a resource. The change proposes to add a definition for “integrated battery storage system” (IBSS) and modifies the definition of “wholesale storage load” (WSL) to include IBSS.
PUC staff did not sign their individual names to their comments, while ERCOT staff did. During the Protocol Revision Subcommittee’s (PRS) meeting Wednesday, at least one stakeholder questioned why PUC staff didn’t sign their names, according to another stakeholder who requested anonymity.
“They wanted a name of a particular staff member. I find that offensive,” said Walker, who relayed her understanding of the PRS meeting based on a phone call she had received from staff.
PUC Chair DeAnn Walker makes a point during the commission’s May 14 open meeting.
PUC staff said PURA rules already allow for storage system loads integrated into a single container to be eligible to receive WSL treatment. They said the current IBSS definition “may arbitrarily exclude some integrated battery systems that do not meet all of the criteria specified in the proposed definition.”
“Therefore, [PUC] staff and ERCOT suggest revisions … in an effort to provide clearer guidance and minimize arbitrary treatment in extending WSL treatment to integrated battery systems,” agency representatives wrote. “The definition should focus on the characteristics that support extending WSL treatment to [storage systems] integrated into a single container instead of adding a new technology category to the WSL definition, which already includes the term ‘batteries.’”
“Technology is going to change. We have to be nimble to be able to change and do things with it,” Walker said. “If staff believes [NPRR1020] falls under our current rule, I find it offensive that people at ERCOT are challenging and saying that staff has no rights and has to [identify themselves].”
“Staff’s position is an institutional voice, and that should be good enough,” D’Andrea said. “This [NPRR] is already two-and-a-half years in the making. I’m already embarrassed by how long it’s taken us to nimbly account for this technology. This is the kind of thing Texas should be able to adapt to and that the markets should be able to handle well.”
The Wholesale Market Subcommittee agreed to take up NPRR1020, and ERCOT staff said it would schedule a workshop on the issue. Like the PRS, the WMS reports up to ERCOT’s Technical Advisory Committee.
ERCOT and PRS Chair Martha Henson, with Oncor, both declined to comment.
Customer Protections Extended to June 17
The commission added another month to its pandemic-related provision that suspends customer disconnections for non-payments, from May 15 until June 17, acknowledging concerns that extensions of the emergency order are being issued open meeting by open meeting (50664).
“I was really hoping at this point we would be further along in our reopening of the state,” Walker said, pointing to the Texas Panhandle and the rising numbers of COVID-19 cases related to meatpacking plants. The state reported more than 700 cases on Saturday alone.
“Those customer bills will continue to rack up,” she said. “At some point, they’re going to get a bill they have to pay.”
“I’m concerned we’re just starting to see the effects of economic disruption,” Commissioner Shelly Botkin said.
The order applies to low-income customers of vertically integrated electric utilities that operate outside of ERCOT: Entergy, El Paso Electric, Southwestern Public Service and Southwestern Electric Power Co.
In other actions, the PUC approved an amendment to the PURA that adds retail brokers or aggregators to those governed by customer protection rules for retail service (50406).
PJM will pay an Illinois wind farm at least $10 million under a FERC-ordered resettlement of incremental capacity transfer rights (ICTRs) to the Commonwealth Edison locational deliverability area (LDA), the RTO said Thursday.
On April 16, FERC ordered PJM to recalculate the ICTRs for Radford’s Run Wind Farm, agreeing with facility owner E.ON Climate & Renewables N.A. that the analysis should have used the base case for the 2015 Base Residual Auction, entitling it to 279 MW of ICTRs (EL18-183). (See PJM Ordered to Recalculate Wind Farm’s Capacity Rights.)
ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into an LDA. The rights are good for up to 30 years.
In 2018, the commission ordered a paper hearing after granting a complaint by Radford’s Run, which said PJM unfairly denied ICTRs for funding an upgrade identified in its system impact study to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line. The 306-MW wind farm in Macon County, Ill., began operations in 2018. The commission ordered the hearing to determine whether the upgrade increased the capacity emergency transfer limit of the ComEd LDA, entitling it to ICTRs.
| E.ON
The commission’s April 16 order entitled Radford’s to receive payments for the capacity auctions held in 2016-2018 for delivery years 2019/20, 2020/21 and 2021/22. It also required PJM to resettle payments for the ICTRs and to rebill affected load-serving entities for the nearly complete 2019/20 delivery year.
On Wednesday, PJM canceled a presentation on the resettlement that was scheduled for the Market Implementation Committee. The presentation said the annual economic value of the 279-MW ComEd LDA ICTR was almost $10 million for 2019/20, $1.04 million for the upcoming 2020/21 delivery year and $5.6 million for 2021/22, as of the first Incremental Auction, which is subject to change based on results of the second and third IAs.
The $10 million payment for the nearly completed 2019/20 delivery year will be clawed back from other LSEs in the ComEd LDA. PJM said the final zonal credit rate for the ComEd zone was reduced to $2.34/MW-day from the initial rate of $3.43/MW-day per megawatt of unforced capacity obligation, a 32% cut. The resettlement will be included in the May invoices PJM expects to issue on June 5.
For the 2020/21 delivery year, the rate was reduced to $0/MW-day from 12 cents/MW-day. ICTR holders only receive revenues if the LDA in question is constrained in subsequent capacity auctions.
More than two dozen companies and coalitions filed responses to PJM’s March minimum offer price rule (MOPR) compliance filing last week, taking issue with the RTO on auction timing, floor prices, unit-specific rules and self-supply exemptions (EL16-49).
Below is a summary of the issues raised in the comments and protests filed last week.
Auction Timing
Commenters weighed in on both sides of PJM’s proposal to hold the Base Residual Auction for delivery year 2022/23, six and a half months after a final compliance order but no later than March 31, 2021.
The Electric Power Supply Association, PJM Power Providers (P3) Group, NRG Power Marketing and Calpine — whose complaint led to the December order — all called for an earlier auction.
“For its part, EPSA is deliberately refraining from wading into the details of the compliance filing in order to focus on the importance of conducting the 2022/23 BRA as soon as possible,” it said.
PJM proposed delaying the auction to as late as March 2021 if it is requested by regulators in a state that approves legislation before June 1 opting out of the capacity market for a fixed resource requirement (FRR).
PJM would seek to eliminate the first and second Incremental Auctions for delivery year 2022/23 if the Base Residual Auction is not held until December 2020. | PJM
EPSA noted that FERC’s April order rejecting rehearing of the December ruling requires PJM to make a second compliance filing June 1. “Realistically, even assuming a shortened comment period for the second compliance filing and a lightning quick turnaround on the commission’s part, it is hard to see the commission issuing an order earlier than July 1, 2020, which, under PJM’s schedule, would have the 2022/2023 BRA being conducted in mid-January 2021,” EPSA said. That would leave a forward period for the BRA of only 14 to 16 months, versus the three years under the Reliability Pricing Model’s (RPM) normal schedule.
“EPSA recognizes that PJM’s request may be moot if no state enacts FRR-enabling legislation by the end of this month, but the commission will undoubtedly be asked to extend the June 1, 2020, deadline or to deem it satisfied by something less than legislation ‘enacted’ by that date,” Calpine added. (Indeed, New Jersey regulators said the extension should also accommodate state regulatory processes. See below.)
P3 said the yearlong delay in the 2022/23 auction has already “thwarted” decisions on investments and maintenance; “projects have not been financed or refinanced” because of the lack of forward price signals.
“The delay … is well beyond the pale of acceptable. For the sake of suppliers, consumers and the sanctity of the PJM wholesale market, resumption of these auctions must become a priority for the commission and PJM,” it said. “PJM and the commission continue to look to each other to ‘make the call’ on the timing of the next auction. P3 urges the commission to end this back-and-forth and provide specific direction to PJM so these auctions can resume.”
P3 and NRG questioned whether PJM needs more than six months to prepare for the next auction, noting it proposed a 4.5-month time preparation period the subsequent BRAs.
P3 urged the commission to “settle the issue of the definition of a state subsidy” and finalize net cost of new entry (CONE) and avoidable-cost rate (ACR) values in its order on the compliance filing and give capacity resources 21 days to determine whether they are subject to the MOPR. “For those units that are considered subsidized and not eligible for an exemption, PJM and the [Independent Market Monitor] could immediately commence the unit-specific review process for those units that elect that process.
“PJM should not be idly waiting for the commission’s second order on compliance. Instead, the commission should direct PJM to commence its auction preparation following its approval in this compliance proceeding and then direct PJM, as part of the second compliance process, to derive a timeline shorter than six and a half months,” P3 said.
“Suspension of market milestones in deference to states embroiled in special interest lobbying does not simultaneously freeze all other factors that contribute to the economics of supply and demand of a 180,000-MW market, which serves 65 million customers,” NRG said.
MOPR eligibility flow chart | PJM
The company said it has spent more than $500 million over the last six years to modernize and add environmental controls to its Illinois fleet “based on a market structure that was regularly generating price signals while at the same time enhancements such as Capacity Performance were being incorporated into PJM’s capacity construct.”
“Absent RPM price signals, NRG will blindly face investment decisions for commitment years that are rapidly approaching. Environmental regulators, both state and federal, will press on with deadlines that could require near-term capital spending for compliance with regulations such as the Effluent Limitations Guidelines for Steam Electric Generating Facilities and Coal Combustion Residuals.”
NRG and P3 also noted that utilities have had to adjust their default procurement programs because of the delay.
New Jersey electric distribution companies told the state Board of Public Utilities that bidders in the state’s Basic Generation Service default procurement program were likely to include risk premiums in their bids and that some potential bidders may not participate, “which could result in higher prices in the auction,” NRG said.
State regulators, consumer advocates and environmental groups argued in favor of the Organization of PJM States Inc.’s (OPSI) call to delay the auction until as late as May 2021, several of them noting that the coronavirus pandemic caused the suspension of state legislative sessions. The Maryland General Assembly adjourned March 18, failing to complete its full session for the first time since the Civil War.
“With the commission’s recent determination that capacity resources indirectly benefiting from state default service auction process are also subject to the MOPR, the impact of the MOPR on state policies has become only more disruptive, further supporting OPSI’s request,” the Natural Resources Defense Council, the Sierra Club and the Sustainable FERC Project said.
“The FRR alternative is not the only step that states might need to take to protect consumers and state policies from the harm of the MOPR,” the environmental groups said. “States may also need to revisit the structure of their default service auctions, the manner in which state objectives relating to generation are pursued or budgets for bill payment assistance.”
Exelon — which is supporting legislation to create an FRR in its Commonwealth Edison territory in Northern Illinois — also endorsed the May date. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)
Proposed capacity auction schedule | PJM
In a joint filing, consumer advocates for New Jersey, D.C., Maryland, Delaware, Illinois and Pennsylvania said the auction schedule should allow for a “complete load forecast similar in scope and depth” to those used in prior auctions.
“The ongoing COVID-19 pandemic and attendant reduction in economic activity only highlight the need for regular updates over the coming BRAs,” the advocates said, noting that PJM’s load has dropped by an average of almost 8%, with peak impacts as high as 15%. “These significant reductions in demand will be all the more impactful because the time between the next four BRAs and the actual delivery year will be reduced from three years to as little as one year. In other words, updated load forecasts will reflect not just the long-term outlook but short- and medium-term operating conditions.”
The New Jersey BPU said PJM’s proposed extension should not be triggered only by FRR legislation. “Implementation of the FRR alternative could also involve efforts by state regulators and state regulatory processes — even where no change in legislation is required,” it said. “The [BPU], for example, has initiated an investigation into resource adequacy alternatives, which includes exploration of its own statutory authority to implement these changes without additional legislation.”
Demand Response
The PJM Industrial Customer Coalition called for Tariff changes to clarify that neither year-to-year fluctuations in customer consumption nor changes in state subsidy levels should cause an existing DR resource to lose its MOPR exemption.
The ICC said its proposed changes would “clearly distinguish between capability fluctuations that occur as a result of year-to-year modifications in consumption and the ‘step-jumps’ associated with uprates to physical capacity. The former is MOPR-exempt, the latter is not.”
Default Floor Prices
Members of the Maryland House Economic Matters and Senate Finance committees, which oversee state energy policy, complained that the default floors proposed by PJM will likely prevent many renewable resources, especially offshore wind and storage, from clearing the auction.
“The mere possibility that renewable energy and storage projects will be able to obtain resource-specific offer price floors allowing them to clear the auction does not allay states’ concerns,” they said. “The outcomes of such an idiosyncratic and opaque resource-specific offer floor process are unpredictable and therefore cannot be relied upon by state lawmakers that need to understand the costs and benefits of different legislative proposals.”
The Pennsylvania Public Utility Commission took issue with PJM’s use of “speculative” cost adders, saying MOPR floor prices “should not be ‘maximum offer prices’ but prices that reflect actual costs of competitive entry.”
Default net CONE ($/ICAP MW-day) | Maryland legislators
It said PJM’s traditional price escalation factors are at odds with the declining costs of solar, batteries and onshore wind, noting new crystalline solar PV resources’ nominal levelized cost of energy have declined from $359/MWh to $41/MWh since 2009.
For onshore wind, PJM proposed using the Energy Information Administration’s 2019 value of $1,677/kW, which the PUC said is 14% higher than any alternative published value and outside Lazard’s range of values ($1,100 to $1,500/kW).
PJM’s gross CONE value for onshore wind assumes a 17-by-2.8-MW configuration (about 50 MW). “However, PJM’s current interconnect queue as of May 6, 2020, for onshore wind projects shows an average project size of 205 MW over 80 projects,” the PUC said.
“For newer declining cost technologies, annual price adjustments should be adopted to reflect current and projected nominal costs at the time of development,” it said.
Unit-specific Rules
PJM’s proposal for unit-specific exemption requests also drew criticism, with some calling for more flexibility and Calpine calling for rigorous vetting.
“The unit-specific review process must be carefully conducted in order to ensure that it does not defeat the purpose of offer-floor mitigation,” Calpine said. “PJM and the IMM should vigorously review any such submissions to ensure that the seller has adequately demonstrated that it is reasonable to assume an asset life of more than 20 years for the specific resource at issue. As another example, to the extent that a seller relies on ‘long-term power supply contracts, tolling agreements or tariffs on file with state regulatory agencies’ in order to support its projected energy and ancillary services markets revenues, PJM and the IMM should take pains to ensure that such contracts, agreements or tariffs are not disguised state subsidies.”
In the last decade, the levelized cost of energy (LCOE) for utility-scale solar has dropped by 89% and the LCOE for onshore wind has declined by 70%. | Lazard
OPSI and the Pennsylvania PUC complained that although PJM said it would allow evidence of a longer than 20-year asset life, it proposed standardizing the other five financial modeling assumptions used to calculate resource-specific offers: nominal levelization of gross costs; no residual value; all project costs included with no sunk costs excluded; use of first year revenues; and weighted average cost.
“While each of the assumptions may have a material impact on the calculation of the offer floor, PJM only proposes flexibility with respect to the 20-year unit life element,” OPSI said. “If a resource owner maintains its financial records using real levelized costs rather than nominal, or can document residual value for its unit, or uses a different protocol for sunk costs, the resource-specific cost review process for the purpose of calculating MOPR floor prices should permit that flexibility to be reflected.”
State Procurements
Calpine also called for tightening PJM’s proposal for exempting state default service procurements.
It said the state subsidy definition should only exempt “nondiscriminatory, competitive, and fuel- and emissions-neutral state-directed default service procurement programs.”
“Without this modification, the proposed definition could allow a state to evade the MOPR by requiring a procurement process that is nominally competitive and neutral with respect to fuel type but that is structured in a way that will exclude potential competitors for the benefit of favored resources,” Calpine said.
Self-supply
Dominion Energy called for broadening the competitive exemption to include self-supply entities.
“Self-supply entities that are vertically integrated utilities, such as Dominion Energy Virginia, currently own and are developing new solar resources [that] are not part of its rate base and whose costs are ‘ring fenced’ and not recovered from ratepayers,” it said. “As a result, these resources are not receiving a ‘state subsidy’ as defined by the Dec. 19 order even though they are owned by a ‘self-supply entity.’”
OPSI called for exempting all existing bilateral contracts, saying PJM’s proposal discriminates against load-serving entities in restructured states.
The organization said it supports PJM’s proposal to exempt bilateral contracts where the buyer is a self-supply entity but said the RTO’s “justification for the exemption applies equally to other, bilateral contracts of non-self-supply entities.”
“This exemption should be extended further to include enforceable supply purchase contracts entered into by non-self-supply entities entered into prior to Dec. 19, 2019, in reliance upon then-existing commission guidance. Load-serving entities in restructured states should not be precluded from using the business arrangement provided for self-supply entities in PJM’s compliance filing.”
Voluntary RECs
The Advanced Energy Buyers Group, a coalition of large energy users, said FERC should order PJM to create “an additional pathway” for capacity resources that sell a portion of their output to a voluntary purchaser and a portion to a compliance purchaser to avoid applying the expanded MOPR to the voluntary transaction.
“PJM’s compliance filing would subject such projects to the MOPR in their entirety. That result could also limit the market for voluntary purchases of renewable energy by forcing buyers to purchase the entire output of a project to avoid the MOPR, which many buyers may not be in a position to do,” the group said.
Subsidy Determinations
The American Wind Energy Association, the Solar Energy Industries Association, Advanced Energy Economy and the Solar Council, filing jointly as “Clean Energy Associations,” asked the commission for assurances that capacity market sellers “will be allowed to rely upon guidance from PJM and the IMM” in determining which state and local programs constitute state subsidies. They urged FERC to “direct PJM to create an ongoing process for market participants to timely obtain such determinations.”
The NRDC, Sierra Club and Sustainable FERC Project called for a transparent process, including a public list of which policies have been determined to be subject to MOPR; a process for parties to submit a policy for consideration with timelines for the decision-making process; and a process for determinations to be clarified or challenged at FERC.
“Absent clear reporting requirements, expanded discovery powers for PJM and/or the Market Monitor, and possibly some form of safe harbor for resource owners, uncertainty regarding the ultimate purchaser of power is likely to result in over mitigation of resources that do not receive a subsidy but are unable to verify they do not,” the groups said.
“This kind of uncertainty, case-by-case analysis and lack of transparency or oversight is likely to result in inconsistent application of the MOPR in a manner that introduces discriminatory treatment of resources.”
American Electric Power complained that PJM’s proposed MOPR exemption for voluntary bilateral transactions was unduly restrictive. FERC said voluntary bilateral transactions were not state subsidies but “permissible out-of-market revenue.”
“PJM appeared to limit the applicability of the commission’s holding in its March compliance filing by only addressing its treatment of bilateral transactions in which one party is a self-supply entity,” AEP said.
Accounting for Federal Tax Credits
AWEA and SEIA also said that while PJM properly proposed accounting for the federal investment tax credit in default gross CONE calculations for wind and solar resources, it “does not expressly provide comparable treatment for other types of federal subsidies,” such as the federal production tax credit.
MISO staff last week floated initial ideas on how the RTO could better synchronize the separate studies supporting its annual transmission planning and generator interconnection queue processes.
The RTO took up the issue after multiple renewable developers complained that their generation projects were unfairly being required to finance multimillion-dollar network interconnection upgrades that should rightly be handled in the transmission planning process. They argued MISO was relying on network upgrades to plan the system. (See MISO Begins Bid to Merge Tx, Queue Planning.)
During a Planning Advisory Committee conference call Wednesday, MISO North Region Economic Planning Manager Neil Shah said one idea would adjust the Transmission Expansion Plan (MTEP) model development timeline to allow for more coordination, analysis and stakeholder input.
Shah said MISO could reserve a window of time in the MTEP cycle to review transmission needs found across multiple planning processes, including reliability and economic benefits, and in interconnection queue studies. From there, the RTO could identify “focus areas with common issues” or transmission needs in “electrical proximity for further investigation and cost-effective solution development,” he said.
MISO would have to decide how to select project needs unearthed in interconnection studies for testing for wider economic benefits under MTEP, Shah said. The RTO might settle on testing all new 230- or 345-kV upgrades that emerge from the first phase of the queue’s three-part definitive planning phase, he said.
Shah added that MISO may need to instate a timing cutoff for upgrades identified in the interconnection queue to be evaluated as potential market efficiency projects. An early December cutoff makes sense, he said, because that falls close to the time that MISO opens the window for economic project submissions for the next year’s MTEP cycle. He said a cutoff would ensure that interconnection upgrades are evaluated on a “fresh set of models and assumptions” from the latest MTEP cycle. He said MISO would accept other stakeholder ideas through May 28.
“These are some initial ideas. Definitely we’d like to hear from stakeholders for more ideas to explore,” he said.
Stakeholders on a Planning Subcommittee conference call Thursday asked MISO to provide a spreadsheet of its modeling and assumptions across all planning processes so they could more easily detect inconsistencies that contribute to apparent discrepancies in transmission needs. MISO has also been asking stakeholders what changes it could make to methodologies and assumptions across separate planning studies to achieve more comparable treatment of transmission projects.
MISO Senior Manager of Expansion Planning Edin Habibovic said such a list runs the risk of being too long and confusing. Director of Planning Jeff Webb said the RTO “might try to hone in on the salient points.”
Clean Grid Alliance’s Rhonda Peters said MISO has been seeing more 345-kV upgrades found in generator interconnection studies assigned to interconnection customers. She said the problem may lie in dramatically different contingency mitigation requirements in local planning criteria between different transmission owners. She asked for a review of TOs’ local planning criteria.
Webb said MISO would likely arrive at “negotiated reasons” as to why the different planning processes can’t be treated exactly the same.
MISO said all of its study processes — reliability and economic planning, transmission service requests, generation interconnection, generation deliverability and generation retirements — have “a uniquely defined purpose.”
FERC last week partly accepted NYISO’s March 12 compliance filing on buyer-side market power mitigation (BSM) rules, denying a waiver as unnecessary and rejecting the ISO’s arguments on Tariff language.
The commission ordered the ISO to submit a compliance filing within 45 days of the May 12 order on the rules for special-case resources (SCRs), a type of demand response resource (EL16-92-002, ER17-996). (See FERC Narrows NYISO Mitigation Exemptions.)
The commission in February narrowed the resources exempt from NYISO’s BSM rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market.
FERC ruled in February that new special-case resources in southeastern New York are subject to NYISO’s buyer-side mitigation rules. | NYISO
On April 1, NYISO’s Market Monitoring Unit and the Independent Power Producers of New York (IPPNY) filed protests. The MMU asserted that the “State Program Language” exempting certain resources administered under New York programs should not be considered part of the currently effective Services Tariff, while IPPNY contended that the commission “fully addressed and expressly rejected” said language in a March 2015 order and reaffirmed that decision in its February order.
“Despite NYISO’s claims to the contrary, the commission never accepted, and indeed expressly rejected, the State Program Language at issue,” FERC said.
NYISO also requested in its filing a conditional waiver to authorize the ISO’s past implementation of the February 2017 order from the period between that order — which established a blanket exemption for SCRs — and the February order that in part granted rehearing of the 2017 order.
“That waiver is unnecessary because in the February 2017 order, the commission directed NYISO to exempt SCRs from NYISO’s buyer-side market power mitigation rules effective as of the date of that order,” the commission ruled.
PJM’s transmission owners gave their long-awaited response to the push to open end-of-life (EOL) projects to competition and regional planning Friday, saying they support the RTO’s proposal to increase its oversight of the process.
The TOs made their case during a fractious special meeting of the Markets and Reliability Committee in which both sides of the debate accused RTO staff of treating them unfairly.
For months, stakeholders seeking to make PJM responsible for EOL planning have bemoaned the TOs’ refusal to engage in negotiations. On May 7, however, the TOs gave notice that they are supporting the PJM proposal and considering a Federal Power Act Section 205 filing to revise the Tariff to reflect it.
While conceding to load-side stakeholders in agreeing to increased PJM oversight of the EOL process, the TOs are trying to retain as much control as possible over the billion-dollar business of planning and building EOL projects.
With the TOs lined up behind PJM’s proposal, LS Power announced Friday that it was withdrawing its proposal and joining with the “joint stakeholder” package by a group including American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC), state consumer advocates, the Public Power Association of New Jersey and the PJM Industrial Customer Coalition.
The maneuvers by the TOs and LS Power mean that only two proposals will be brought to sector-weighted votes at the May 28 MRC meeting.
Project status as of Dec. 31, 2019 | PJM
PJM officials said at the April 30 MRC meeting that the package with the most support that meets the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support would become the main motion for a vote of the Members Committee on June 18.
On Friday, however, PJM Director of Stakeholder Affairs Dave Anders said it was unclear the May 28 vote on the joint stakeholder proposal would include their proposed Operating Agreement language. He said the procedure would be clarified in the agenda for the meeting.
Under the Consolidated Transmission Owners Agreement (CTOA), the TOs are required to provide stakeholders 30 days to comment before filing proposed Tariff changes. (Comments may be submitted to Comments_for_Transmission_Owners@pjm.com.)
The June 8 comment deadline gives the TOs more than a week to file their proposal with FERC before the MC votes.
“This [Section] 205 notification changes the game fairly significantly relating to the timing of voting on OA changes,” said Sharon Segner of LS Power. “Time is of the essence.”
Both the stakeholder and PJM proposals would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP).
The joint stakeholder proposal would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.
LS Power’s proposal was identical except for requiring at least eight years’ notice for facilities of 230 kV and above. Segner said Friday that her company decided to address the issue in future manual changes because the joint stakeholders’ OA changes referred to “at least six years’” notice.
PJM’s package requires TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions.
The RTO said it would implement its plan through changes to Manual 14B: PJM Region Transmission Planning Process. The stakeholders questioned whether it would have authority to enforce the new rules if they were in the manual alone and have proposed changes to the OA, which they outlined during the nearly three-and-a-half-hour meeting Friday.
The TOs’ representative, Chad Heitmeyer, director of RTO policy for American Electric Power, said their proposed changes to Tariff Attachment M-3 go beyond FERC requirements to provide increased transparency on “certain asset management projects, including EOL projects.” The TOs said the revision would continue to “honor [TOs’] responsibility over end-of-useful-life replacement projects.”
He said the only significant difference between the TOs’ proposal and PJM’s is the TOs’ belief that the new rules require changes to Tariff Attachment M-3. “The Tariff is the most appropriate governing document to effectuate the delineation of responsibilities between PJM and the PJM TOs,” Heitmeyer said.
However, the TOs also said that under their proposal, the nonbinding five-year forecast of EOL candidates would be confidential and shared with PJM only. The stakeholders want the list to be made public. Dave Souder, senior director of system planning, said at the April 30 MRC meeting that PJM hadn’t decided whether the list would be made public or not.
On Friday, Souder said PJM would determine which EOL projects “overlap” with RTEP violations and would be included in a competitive window seeking regional solutions. EOL projects for which PJM did not find overlaps would not be disclosed, Souder said.
ODEC’s Mark Ringhausen said PJM’s approach represented a “complete lack of transparency.”
The TOs have been under increasing pressure from both stakeholders and FERC as spending on EOL and other supplemental projects controlled by the TOs has overtaken baseline upgrades planned by PJM. FERC opened Section 206 investigations of PJM, RTOs, TOs Defend Competition Exemptions.)
Baseline and supplemental projects since 2005 (adjusted by peak load) | PJM
Last week, the joint stakeholders sent a letter to the PJM Board of Managers highlighting the “the mounting evidence that the majority of transmission planning in the PJM footprint is not occurring on a regional basis.” The letter came as PJM reported that TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It marked the fifth year out of the last six in which supplemental projects exceeded baseline projects. (See related story, Stakeholders Urge PJM: Plan ‘Grid of the Future’.)
Segner said she was concerned by the potential Section 205 filing because it “essentially moved a number of [FERC] Form 715 projects potentially into the supplemental bucket” exempt from competition. Last August, FERC ordered PJM to open Form 715 transmission projects to competitive bidding, with regional cost-sharing for those projects involving high-voltage lines. (See FERC Opens Local Tx Projects to Competition, Cost Sharing.)
“I don’t think PJM can file this because it violates the Operating Agreement,” she said.
Attorney Don Kaplan, representing the TOs, said the Tariff changes were not intended to have any impact on handling of Form 715 projects.
Process Dispute
Friday’s meeting opened with both load-side stakeholders and TO representatives criticizing PJM staff for mismanaging the agenda.
Load-side stakeholders accused staff of ignoring their requests to post the proposed OA language changes with meeting materials and include discussion of them on the agenda.
The OA language had been public since April 23, when it was posted for the April 30 MRC meeting. But it wasn’t until Thursday — after emails from multiple stakeholders — that it was posted with the materials for Friday’s meeting, said ODEC’s Adrien Ford, a former PJM staffer.
PJM facilitator Jim Gluck, who chaired the meeting, said the failure to post the language earlier was an “administrative oversight.”
Ford wasn’t so sure. “There were multiple emails. That’s a lot of flubs,” Ford said. “This really feels like we’re not being treated equitably.”
“The intent is to treat all stakeholders equitably,” Gluck said.
“The outcome is much different from the intent,” AMP’s Ed Tatum responded.
After about 30 minutes of arguments, Gluck agreed to amend the agenda to provide time for the stakeholders’ presentation.
That prompted a protest from PPL’s Amber Thomas, who said stakeholders were not given notice that the OA language would be discussed during the meeting.
“There’s a lot of confusion about how this agenda was developed,” she said. “This all feels very messy and very confusing. … Some of you talked about [how] the stakeholder process is broken. This is another example.”
“I want to acknowledge that this is getting very tense,” responded PJM’s Anders, who promised staff “will certainly do a debrief on this internally.”
OA Page-turn
AMP General Counsel Lisa McAlister, who presented a page-turn of the proposed OA changes, said the stakeholders’ goal is to “put end-of-life planning on a par with reliability planning.”
Responding to questions about proposed revisions to the definition of supplemental projects, attorney Mike Engleman, representing LS Power, said, “To be frank, the intent was to not allow supplemental projects to be used to … prematurely replace facilities to avoid” the EOL notification requirement.
Supplemental projects by voltage (2015-2019) | PJM
AEP’s Heitmeyer presented the TOs’ proposal. “After reviewing PJM’s package, it was evident we were in alignment,” he said.
The PJM and stakeholder packages were developed in a series of lengthy meetings since December.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he was “frustrated” by the TOs’ late introduction of their proposal and their threat to file it unilaterally with FERC.
“I would say this kind of ends the CBIR [consensus-based issue resolution] process at the Planning Committee,” he said.
“I don’t think the TOs consider what we’ve done here to be counter to the CBIR process,” said Alex Stern of Public Service Electric and Gas. “All we’re doing is facilitating what PJM has laid out.”
Tatum pressed PJM officials for their reaction to the TOs’ proposal, but Souder refused to take a position, saying only that the RTO is “very supportive of the stakeholder process.”
The PJM Planning Committee last week approved an initiative to develop rules for “if and how” storage should be considered in the Regional Transmission Expansion Plan (RTEP) process.
The storage as a transmission asset (SATA) issue charge was approved May 12 by an acclamation vote with one objection and no abstentions after some stakeholders expressed misgivings about the potential that storage could be a transmission asset at times and a market participant at others.
PJM is looking to develop “transparent rules” by the end of the year for how it would evaluate storage’s performance and cost and whether it could be an alternative to traditional transmission reinforcements. Proponents say storage could be dispatched by the RTO to address thermal, voltage or stability violations or to relieve transmission constraints.
During a first read of the problem statement and issue charge April 14, some PC members raised issues with PJM’s proposal, questioning its scope and timing. (See Stakeholders not Sold on PJM SATA Plan.)
During last week’s second read, PJM’s Jeff Goldberg said staff made several changes to reflect stakeholder and internal feedback. “While PJM’s approach to SATA hasn’t changed, some sections were entirely rewritten to incorporate comments and give clarity to PJM’s goal,” Goldberg said.
To address stakeholders’ concerns that the concept of SATA is an unsettled issue, staff added a paragraph to the problem statement citing two FERC decisions regarding proposed SATA systems in CAISO. The first was a 2010 decision approving transmission incentives for a project by Western Grid Development (EL10-19); the second was a 2008 denial for a project proposed by Nevada Hydro (ER06-278).
Primus Power energy pods | Primus Power
Wording was also added to the problem statement to clarify that PJM has not decided “whether or not storage assets should be included” in the RTEP.
Goldberg said Phase 1 of the process will be focused on identifying gaps in existing transmission planning rules for evaluating storage. Because PJM is the NERC-registered transmission planner and must be comply with reliability standards, Phase 1 also will identify any operations impacts that need to be addressed in Phase 2.
Issues regarding SATA implementation, such as telemetry requirements, are out of scope for Phase 1.
The RTO acknowledged the potential for SATA’s dual use.
“PJM recognizes that the evaluation of the cost-effectiveness of a given storage solution to a transmission reliability or market efficiency need could be impacted by the question of whether and how the unit would participate in the market,” the issue charge says. “Nevertheless, this issue is derivative of the primary question, to be answered in this Phase I, as to the feasibility of evaluat[ing] energy storage purely as a transmission asset.”
“We’re taking a measured approach,” Goldberg said.
Carl Johnson of the PJM Public Power Coalition said he appreciated the “significant changes” the RTO put into the problem statement and issue charge to address stakeholder concerns.
“I’m not enthusiastic about having this conversation because I’m not enthusiastic about the possibility of looking at dual use,” Johnson said. “But I understand where PJM is, which you may see these things approved somewhere on the system through a process that isn’t the RTEP and you’ll have to figure out how to incorporate those.”
John Brodbeck of EDP Renewables also said he wasn’t enthusiastic about bringing up the issue of SATA. He said he would have liked more clarity on how projects would be paid for and who could bid on a project.
“I’d like to make sure that there’s an Order 1000 process; that if we’re going to do storage as a transmission asset, we make sure that in order to build this, things are made available to everyone in the marketplace,” Brodbeck said.
PC Chair Dave Souder said making sure projects were open to competition would be part of the interest identification in Phase 1, so it wouldn’t be out of scope.
The committee will hold monthly special sessions beginning around June to work on the initiative. Proposed changes to manuals or other governing documents are expected to be completed by the end of the year.
Indiana regulators are collecting information from both sides of the argument over whether Duke Energy is prudently handling the self-commitments of its coal units in the state.
The Indiana Utility Regulatory Commission opened a docket in March to investigate Duke’s self-scheduling practices after the company applied to increase its fuel adjustment charge, the amount billed to ratepayers based on fluctuating fuel prices. The IURC has scheduled a Sept. 21 hearing in the matter (38707).
The Sierra Club and Citizens Action Coalition of Indiana (CAC) have said there are “serious issues related to Duke’s commitment decisions,” pointing to the company’s coal-fired Cayuga Generating Facility, Gibson Generating Station and Edwardsport Integrated Gasification Combined Cycle plant.
In testimony to the commission, Sierra Club attorney Kathryn Watson said the organization isn’t sure if Duke is meeting its responsibility of providing electricity to retail customers at “the lowest fuel cost reasonably possible because those costs may include periods of unreasonable commitment for its Cayuga, Gibson and Edwardsport coal-burning plants into the MISO energy markets.”
Jennifer Washburn, an attorney with CAC, also said Duke may be purchasing and storing “excessive amounts of coal” for some units.
Devi Glick, a senior associate at Synapse Energy Economics who testified on behalf of Sierra Club, said Duke’s own analysis showed that Edwardsport could have earned $3 million if it ran on natural gas alone, compared with the $3.1 million in losses the company had projected based on the plant running on a synthetic gas-and-coal combination from Sept. 1 to Nov. 30, 2019.
Glick herself estimated that over the same three-month period, Duke’s operational losses totaled $3.3 million at Edwardsport and $3.56 million at Cayuga.
“Duke should be electing to operate its units on a forward-looking basis only if it expects to make money, and the company should keep the units offline if they are projected to operate at a loss,” Glick told the IURC. “While there are reasons why inflexible units with longer start-up and shutdown times, such as coal-fired units, may choose to self-commit, the company’s process for deciding how and when to self-commit should result in reasonable decisions that do not bring or keep units online when they are projected to lose money over a multiday, weeklong or longer time horizon.
“Based on my review of the company’s internal commitment-decision process … I see no indication that the company’s internal processes are aligned with, or guaranteed to serve, the best interest of ratepayers,” Glick added.
Shannon Fisk, managing attorney for the Earthjustice coal program who represents the CAC, said that while there potentially may be “a day here and there” where coal units operate uneconomically for other reasons, it shouldn’t be nearly as often as occurs with Duke.
“They’re incurring substantial losses running Edwardsport on coal, when the more logical approach is to shut the thing down, which would be cheaper for customers or, at worst, run it on gas,” he told RTO Insider.
Duke: Must-run Statuses Justified
Duke spokesperson Angeline Protogere said the utility’s goal is “always economic operation of our plants for customers.”
“Each business day, we do an economic review of a number of factors as we make a decision for each unit,” Protogere said in an email to RTO Insider.
In April 29 testimony, Duke Managing Director of Trading and Dispatch John Swez said the company commits its generating units “on an economic basis, except as required for unit testing, operational requirements or other infrequent reasons.”
“Units are dispatched on an economic basis between their minimum and maximum capability when not required to run at a specific output as would be necessary for unit testing, an operational requirement or other reasons. Utilizing a commitment status offer of must-run in the MISO energy markets does not necessarily mean that a generating unit was not economically committed,” Swez said.
He said must-run designations are sometimes necessary for facility testing, to ensure that a unit meets its minimum run-time to prevent wear or avoid damage from freezing temperatures. He also said the designation is needed because of the Indiana Municipal Power Agency’s nearly 25% ownership interest in the 625-MW Gibson Unit 5 and the Cayuga station’s arrangement that one unit remain at or above 300 MW to supply steam to nearby industrial customer International Paper.
“Used properly, as we do, the use of a must-run offer reduces the overall cost to supply energy to our customers by reducing the additional costs and risk associated with the unnecessary and uneconomic cycling of longer lead-time generating units,” Swez said.
But Fisk questioned “whether the proceeds from International Paper justify the costs to ratepayers” to keep the unit always switched on.
“The issue we’ve queued up in the commission is whether this is beneficial to customers. It’s clear that sometimes they’re dispatching the unit uneconomically,” Fisk said.
Swez said the minimum run-time of a unit at the Gibson station is 72 hours, and a restart of Edwardsport’s gasification systems can take up to 14 days. He also noted that MISO’s day-ahead market “was never designed to forecast economic commitments beyond the next day.”
Beyond that, Duke makes purchases of lower-cost energy from the MISO markets, Swez said, noting that the company last year purchased a little more than 30% of energy served to customers from the RTO. “The MISO energy markets are a resource that is used to the customers’ advantage when power prices are below the cost of the company’s generation cost,” he said.
Protogere also noted that a unit under must-run designation in MISO is only required to be online for its minimum load.
“It’s still MISO … that directs dispatch of a unit anywhere between a unit’s minimum and maximum capability,” she said. “If there is lower-cost power available, we make every attempt to turn down/off our units and purchase from the market. We manage our units as economically as possible for our customers. The ability to self-commit a generating unit is critical to avoid start-up expenses and operational risks incurred by cycling a unit offline and then back online during short periods.”
Duke Vice President of Midwest Generation Cecil Gurganus also defended his company’s practice of maintaining a coal pile at Edwardsport even though the plant can run on natural gas.
“We must acknowledge the reliability and resiliency value in fuel inventory maintained at coal plants, relative to natural gas. Even having contracted firm transportation agreements with natural gas suppliers is no guarantee of service when the commodity is curtailed,” he said.
Gurganus said Edwardsport’s fuel flexibility allows it to be available when other resources may not be. He also said the plant’s permitting dictates it run on coal as a primary fuel source and natural gas as a secondary fuel.
But Fisk said Edwardsport is approved to run on either fuel.
“Duke has substantial over-inventories of coal,” Fisk said, adding that utility-wide, it appears that Duke keeps about 60-plus days of inventory at units in addition to up to 1.4 million tons of coal in off-site storage. He said Duke should rethink coal-supply contracts and set aside any possible loyalties to keeping coal mines afloat. Duke officials pointed out in testimony that the plants use locally sourced Indiana coal.
“It should not be on Indiana ratepayers to keep a struggling coal mine is business,” he said. “A more prudent approach would be to ask: How can we stop buying more coal?”
While Fisk said his organization has yet to evaluate a MISO multiday market, he argued it wouldn’t change much about Duke’s commitment behavior.
“The argument here isn’t whether Duke on a daily basis is turning the unit on and off. The argument is: Duke has analysis over the coming weeks that the unit will be uneconomic, and it’s committing it anyways. If their own projection is showing the unit won’t make money, then it should be taken offline,” he said.
MISO’s Perspective
MISO itself continues to maintain that uneconomic coal must-run designations are uncommon.
The RTO said that from early 2017 to late 2019, self-committed coal units economically dispatched above their economic minimum level represented about 76% of its total coal-fired generation. MISO said it economically committed and dispatched another 12%.
“Added together, that means 88% of the region’s coal-fired energy in the last three years was economically dispatched in some manner,” MISO said.
But Fisk said that uneconomic commitments even 12% of the time represents “still quite a bit of money lost.”
“Commissions should be carefully evaluating how to shrink that number,” Fisk said.
MISO also points out that self-commitment is “used by all types of resources, not just coal.” During March, coal represented just 2 out of the 12 TWh in self-committed and uneconomically dispatched generation, the RTO said.
It also reported that coal self-commitments are on the decline. In 2009, 64% of its total energy was from self-committed coal resources. By 2019, that share fell to 36%.
Despite the drop, MISO states Minnesota and Missouri have also opened similar investigations into utilities’ coal plant self-scheduling.
Fisk acknowledged that coal self-commitments are on the decline even as they garner more attention. He said increasingly economic renewable resources have likely contributed to the emphasis on the issue.
“Certainly, the rise of renewables has contributed to lower-cost generation. The question is whether these utilities have properly adjusted to this new reality. It doesn’t appear that Duke has attempted this transition,” he said.
