The New York Public Service Commission on Thursday continued to tweak compensation and billing for distributed energy resources, adjusting the structure of existing standby and buyback service rates and extending standby rate exemptions for two years (Case 15-E-0751).
The PSC held its regular monthly session in Albany on May 16.
The PSC’s order modifies rates “to more accurately reflect costs and benefits and to ensure that those rates are available to all interested ratepayers.”
Ted Kelly
“Standby service rates generally apply to customers who have on-site generation that serves much of their load but still depend on the utility to provide partial or backup service,” said Ted Kelly, assistant counsel for the Department of Public Service. The buyback rates determine the price customers receive for selling excess energy back into the grid.
“With interval metering becoming much more widely available due to the rollout of advanced metering infrastructure (AMI) throughout New York state, mass market standby service rates no longer need to be limited to flat fees and volumetric energy usage,” the PSC said. “Rather, rates for mass-market standby service can be measured and billed on the basis of demand in the same manner as the standby service rates applicable to larger customers.”
The order requires that all customers be eligible to opt into a demand-based rate option, irrespective of whether they have on-site DERs. It also requires greater granularity by using off-peak, on-peak and super-peak charge components, and allows the load of multiple customers in multiple buildings to be offset by a common generator.
John Rhodes
“This is obviously a complex topic,” PSC Chair John Rhodes said. “Though a complicated subject, this is a very practical approach going forward.”
Commissioner Gregg Sayre said he was “comfortable establishing a rate design that more closely tracks the cost of service.”
Diane Burman
“Standby rates have been controversial and hotly debated,” said Commissioner Diane Burman, who concurred in the approval. “I do think we were overly ambitious in 2015 in thinking that it could happen overnight and that the signal was we were ready to go.”
The order also modifies the design and administration of buyback service tariffs to eliminate or reduce barriers to deployment of DERs, and clarifies the application of grid access demand charges for energy storage systems.
Gregg Sayre
The commission also voted unanimously to continue existing statewide exemptions from standby rates, and to extend the in-service date deadline for eligible DERs until May 31, 2021 (Case 19-E-0079).
These exemptions apply to certain DERs with a capacity of 1 MW or less, including fuel cells, wind, solar thermal, solar photovoltaic, biomass, tidal, geothermal, methane waste-powered resources, and efficient combined heat and power projects, the order said.
New York utilities must implement the rule changes effective July 1.
Grid Prepared for Summer
DPS staff presented the commission a report on summer electricity preparedness that forecasts a 1 to 3% decline in energy prices compared with last summer, depending on load zone and weather conditions.
“This is very comforting for New Yorkers,” Rhodes said.
The state bases its energy price forecasts on futures trading at the New York Mercantile Exchange, and the commission said that financial hedging by utilities will also reduce any price increases this summer.
Warren Myers
“The big driving factor of course is ICAP [installed capacity], which tends to be fairly stably high in the summer downstate and, year after year, quite low upstate,” said Warren Myers, DPS director of market and regulatory economics. “And with respect to delivery charges, those, by their design through rate cases, are very stable.”
New York has sufficient generating capacity resources to supply expected customer demands and all of the state’s electric utilities are prepared to serve those expected customer demands, the report said. Peak load this summer is forecast to be 32,382 MW, down slightly from last year.
FERC on Thursday granted LS Power Grid New York’s (LSPG-NY) request for an abandoned plant incentive for a transmission project approved by NYISO (EL19-30).
| LSPG-NY
LSPG-NY (formerly known as North American Transmission) had partnered with the New York Power Authority to jointly propose two 345-kV transmission projects to address capacity shortfalls at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (Segment B) interface.
NYISO’s Management Committee had backed both projects — part of the broader AC Public Policy Transmission Project — but the ISO’s Board of Directors in April selected only one of them, awarding Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)
“In particular, we find that LSPG-NY’s Segment A project is entitled to the rebuttable presumption that it meets [Federal Power Act] Section 219’s requirement that the project will ensure reliability and/or reduce congestion because it has been approved through a relevant regional transmission planning process,” the commission said.
LSPG-NY said in its petition that NYISO estimated that Segment A will cost $750 million (in 2018 dollars, including 30% contingency).
The commission rejected LSPG-NY’s request for the incentive for its Segment B project, as NYISO did not select it. The company filed its request in January.
Stressing the importance of being efficient and effective, the Texas Reliability Entity’s Derrick Davis last week shared with his Board of Directors a new process to help the regional entity devote more time to its ERO responsibilities.
“I’m going to say more efficient and more effective 1,000 times,” said Davis, director of enforcement, reliability standards and registration, during the board’s Wednesday meeting.
Davis told the board that the RE’s new mitigation verification sampling process will be, of course, “more efficient and more effective” in resolving smaller issues, freeing up staff to perform other tasks.
TRE staff will verify mitigation for compliance exceptions on a sample basis. Registered entities will be required to provide an affidavit identifying the details of mitigation activities and source documents. Entities will hold the mitigating evidence for 18 months after being notified of compliance exception treatment or upon completion of mitigation activities, whichever is later.
Staff have also begun using a new triage process to obtain disposition information faster. Davis said enforcement staff will ask for “pertinent disposition information” earlier in the process than before, leading to quicker validations.
“In the past, we haven’t had an answer for an entity that self-reports and waits for the enforcement group to get with them,” he said. “We’re going to get to you faster now, so that we can close these out.”
2020 Risk Elements Focus on Resource Adequacy
Staff have proposed three regional risk elements to focus on for 2020: data integrity and situational awareness; resource adequacy; and insufficient dynamic performance and loadability by transmission and generation providers.
Risk Assessment Manager Jeff Hargis told directors that risk elements are translated into audit scopes. These specific, defined risks are determined on an annual basis, he said.
“We live in the future,” Hargis said.
He said the resource adequacy risk is not a result of ERCOT’s slim summer reserve margins, but whether or not resources adequately support frequency and voltage and stay online during transient events. Multiple resource failures can lead to system instability or a significant loss of generation, Hargis said.
Texas Tops Other REs in Effectiveness Survey
COO Jim Albright told directors that TRE bested all other REs on NERC’s 2018 ERO effectiveness survey. The Texas RE registered an average score of 3.91, based on a 5-point scale; the Florida Reliability Coordinating Council came in second, with an average score of 3.88.
TRE received its highest score (4.23) for its business planning and budgeting process, which stakeholders found provide reasonable opportunities for input and offer sufficient information, Albright said. It was also rated highly for its audit reports and audit process (4.19 and 4.14, respectively) and for enforcement (4.13).
The organization fared poorest in enforcement and standards, with no score higher than 3.77. Still, it was rated highest among the regions for its regional reliability standards addressing risk in a cost-effective manner.
Respondents favorably commented on the “competent” compliance monitoring and enforcement staff and found the organization’s self-certification process to be an “effective engagement method.” However, they dinged TRE for a lack of transparency and consistency on the penalty and internal risk assessment processes.
“When you look at the number of penalties we actually had, it’s a small number,” Albright said, noting TRE has only assessed “six or seven” penalties in recent years. “The opportunities to be transparent are few and far between.”
The ERO effectiveness survey, composed of 76 questions across five topic areas, is conducted every two years. TRE received 92 responses in 2018, up from the 54 it received in 2016. It has 222 entities registered in its region.
“We’re reaching more people, which is a good thing,” Albright said.
He also said TRE’s certification process has received a clean report from NERC.
Board Approves 2018 Budget, Audit
The directors approved the RE’s 2020 business plan and budget of $13.8 million, a 5.8% increase over the current budget. The approval is subject to “no material changes,” as NERC has not completed its review of the budget.
The Member Representatives Committee approved the budget May 3.
The board also approved accounting and advisory firm BKD’s 2018 financial audit report, which had no reported findings, and accepted its financial statements for the same year.
FERC on Thursday rejected multiple requests to reconsider its landmark electric storage order, prompting a partial dissent from Commissioner Bernard McNamee over requests to allow states to opt out (RM16-23-001, AD16-20-001, Order No. 841-A).
The majority rejected requests that it allow relevant electric retail regulatory authorities (RERRAs) the ability to opt out of its storage provisions, as the commission did for demand response under Order 719. The commissioners also rebuffed questions about their authority to require that power sold by RTO markets to an electric storage resource (ESR) for resale be at the wholesale LMP.
| SDG&E
Dissent
McNamee’s 13-page dissent said the majority “fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”
“I believe Order Nos. 841 and 841-A are on solid footing when they deal with ESRs connected to the transmission system and how ESRs may participate in the wholesale market, and I concur in those aspects of today’s order. I am troubled, however, that the storage orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distributions systems and local retail customers,” McNamee wrote.
McNamee said he would have reconsidered the commission’s finding that it has jurisdiction over whether ESRs located behind the meter or on a local distribution system are permitted to participate in the RTO/ISO markets through the ESR participation model, and its refusal to provide states the opportunity to opt out of the participation model.
But the majority said the Federal Power Act gives FERC clear jurisdiction over storage.
It cited the Supreme Court’s 2016 EPSA ruling, which upheld FERC’s jurisdiction over the participation in RTO markets of DR resources, which are generally located on the distribution system. “The court did not find the commission’s authority to be lessened by the location of demand response resources behind the retail customer meter,” the commission said.
“We disagree with assertions by petitioners and the dissent that, unless the commission adopts an opt-out, the commission’s regulation of the RTO/ISO market participation of distribution-connected and behind-the-meter electric storage resources violates FPA Section 201. We find that the Supreme Court’s jurisdictional findings in EPSA regarding wholesale demand response apply with at least as much force to participation in RTO/ISO markets by electric storage resources engaged in wholesale sales in interstate commerce, even where those resources are interconnected on a distribution system or located behind a retail meter.”
The majority also rejected assertions that states can dictate whether resources can participate in the RTO markets through conditions on the receipt of retail service. “We acknowledge that states have the authority to include conditions in their own retail distributed energy resource or retail electric storage resource programs that prohibit any participating resources from also selling into the RTO/ISO markets. In that scenario, the owner of a resource has a choice between participating in the retail market or wholesale market. However, states may not take away that choice by broadly prohibiting all retail customers from participating in RTO/ISO markets.”
The commissioners said McNamee incorrectly suggested that the commission had required that storage “be permitted to use distribution facilities so that they may access the wholesale market.”
“Although Order No. 841 provides that states may not prohibit electric storage resources from participating in wholesale markets, that requirement does not amount to an effective right of access to the distribution system itself. As noted, Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access, provided that they do not ‘aim directly at the RTO/ISO markets.’”
Participation Model
FERC also rejected AES’ request for rehearing over the use of a single participation model for storage.
“While we agree … that the various technologies that qualify as an electric storage resource under the definition that the commission adopted in the final rule may have different operating characteristics and that new electric storage technologies will likely emerge, we continue to find that a single participation model can be designed to be flexible enough to accommodate any type of electric storage resource,” it said.
FERC said AES had mischaracterized Order 841 as requiring that storage resources seeking to participate in RTO markets be available to RTOs as dispatchable resources. But the commission said it would change its regulations to clarify that dispatchable storage must be permitted by RTOs to participate in that manner and be eligible to set clearing prices.
RTO Requests
The commission granted SPP’s request for clarification, saying RTOs without capacity markets do not have to create such a product to comply with Order 841. “However, to the extent that an RTO/ISO has a resource adequacy construct, the RTO/ISO must demonstrate on compliance that the existing market rules governing its resource adequacy construct provide a means for electric storage resources to participate in that construct if electric storage resources are technically capable of doing so,” it said.
It rejected a clarification request by MISO, reiterating that RTOs must allow storage resources the same ability to self-schedule as other market participants.
In response to another MISO request, FERC clarified that the RTO may propose in its compliance filing a requirement that a storage resource submit its forecasted state of charge at the beginning of any market interval in which it intends to participate. “With that said, we make no findings on the proposal that MISO outlines in its request for clarification,” it added.
Minimum Size Requirement
FERC rejected the Edison Electric Institute’s request for rehearing on Order 841’s directive that RTOs establish a minimum size requirement not to exceed 100 kW, saying the threshold “balances the benefits of increased competition with the potential need to update RTO/ISO market clearing software to effectively model and dispatch smaller resources.”
It also rejected MISO’s request to phase in the minimum size requirement. “We continue to believe that, given the record showing that all RTOs/ISOs are already accommodating the participation of smaller resources in their markets and the commission’s willingness to consider requests to increase the minimum size requirement in the future, we are providing the RTOs/ISOs with adequate time to develop the requisite tariff language and update their modeling and dispatch software to comply with Order No. 841,” it said.
Charging Energy
Pacific Gas and Electric asked the commission to acknowledge that states have jurisdiction to determine how power flowing from distribution lines into the storage located behind the customer meter is split between retail consumption and wholesale charging for later discharge into the wholesale markets.
“The sale of energy from the grid that is used to charge electric storage resources for later resale into the energy or ancillary service markets constitutes a sale for resale in interstate commerce,” the commission said. “As such, the just and reasonable rate for that wholesale sale of energy used to charge that electric storage resource is the RTO/ISO market’s wholesale LMP.”
It said CAISO’s request for clarification that storage resources participating as transmission resources should not incur transmission charges for charging demand is premature, noting the ISO “has not yet filed a proposal to allow electric storage resources to provide transmission or reliability services.”
In response to another issue raised by CAISO, the commission clarified that “the RTO/ISO itself does not need to be the entity that directly meters electric storage resources.”
“We also … clarify that an RTO/ISO could require verification from the host distribution utility that it is unable or unwilling to net wholesale demand from retail settlement before the RTO/ISO ceases to settle an electric storage resource’s wholesale demand at the wholesale LMP. While Order No. 841 stated that each RTO/ISO must prevent electric storage resources from paying twice for the same charging energy, it did not specify how each RTO/ISO must implement this requirement.”
FERC rejected requests to change the compliance deadlines it set in Order 841, insisting “the timeline for compliance and implementation is reasonable.” In April, FERC issued deficiency letters to all six jurisdictional RTOs and ISOs over their compliance filings, pressing for definitions, tariff citations and other details. (See FERC Asks RTOs for more Details on Storage Rules.)
Reaction
The National Rural Electric Cooperative Association said FERC “side-stepped” the FPA in its jurisdictional ruling.
“The commission has dealt a blow to consumers and dramatically expanded its authority by giving itself the discretion to decide which distributed and behind-the-meter energy storage resources can participate in wholesale electricity markets,” NRECA CEO Jim Matheson said in a statement. “In doing so, FERC has undermined the ability of local utilities and regulatory authorities to manage these resources for the benefit of consumers.”
Jeff Dennis, general counsel for Advanced Energy Economy, praised the ruling. “We applaud FERC for upholding Order No. 841, recognizing the benefits to consumers and the grid of giving all energy storage resources, including those located on the distribution grid or behind the meter, an opportunity to participate in wholesale markets,” he said.
“We also appreciate Chairman [Neil] Chatterjee’s focus on FERC’s continued efforts to remove the barriers that keep advanced energy technologies from participating in wholesale markets. Energy storage is just one of the technologies that face barriers to entry. We urge FERC to finalize a similar rule to permit aggregations of distributed energy resources to participate in wholesale markets, utilizing the same legally sound approach taken in today’s order.”
PJM utilities and independent power producers joined wind, solar and nuclear generators in support of the RTO’s controversial price formation proposal, with some commenters urging it to go further and one saying the plan should be an “off ramp” from the capacity market (ER19-1486, EL19-58).
But Maryland regulators and the Independent Market Monitor asked FERC to reject the proposal, saying it would add billions in costs for negligible benefit.
PJM filed its proposal unilaterally in March after a yearlong discussion with stakeholders produced no consensus. The RTO said its plan borrows concepts used by other RTOs to capture the real-time actions of grid operators, including a revised operating reserve demand curve (ORDC); improved utilization of existing capability for locational reserve needs; alignment of the day-ahead and real-time markets; and increased penalty factors. (See PJM Files Energy Price Formation Plan.)
PJM’s plan received backing in comments by Exelon; FirstEnergy; Duke Energy; the PJM Power Providers Group (including Calpine, NRG Energy and Talen Energy); the Nuclear Energy Institute; the American Wind Energy Association; the Solar Energy Industries Association, and eight energy trading firms.
PJM’s Independent Market Monitor said FERC should reject the RTO’s proposed operating reserve demand curve (ORDC) in favor of the Monitor’s plan (dotted blue line), which prices reserves beyond requirements at $0. | Monitoring Analytics
‘Pulling Back the Curtain’
Exelon cited an affidavit by PJM dispatch director Christopher Pilong, which it said “pulls back the curtain of the PJM control room and provides new, conclusive evidence” that operators are using out-of-market actions to commit reserve capability by inflating load forecasts. “These practices are so pervasive that, without them, PJM would have been in a reserve shortage in almost one-third of five-minute intervals in 2018,” Exelon said.
The company filed an affidavit by NorthBridge Group consultant Michael Schnitzer, who said PJM’s estimate of $556 million in additional annual payments by load is misleading, because it only measures the impact of the proposal on market prices and energy and reserve procurement volumes.
Schnitzer estimated PJM’s proposal “would create at least $200 million of net benefits by both increasing reliability through incremental reserve purchases and by reducing production costs,” Exelon continued. “PJM’s proposal is therefore the rare market reform that both creates incremental reliability benefits while simultaneously reducing total costs.”
Exelon consultant Michael Schnitzer said PJM operators’ “load biasing” — inflating load above the actual demand forecasts — depresses energy and reserve prices. | NorthBridge Group
NEI said PJM operators’ “load biasing” has contributed to the financial pressures facing nuclear plants.
“Over the course of the entire year, the average operator bias was 515 MW of out-of-market additions. PJM’s filing makes clear that this bias is a natural result of the asymmetric incentives facing operators. The consequence of failing to have sufficient reserves could be calamitous, whereas the downside of excess procurement can be rationalized as just a small instance of market price suppression,” NEI said. “Given the scale and frequency of these biases, however, the cumulative effect is quite large.”
AWEA and SEIA agreed with PJM that the lack of alignment between the RTO’s day-ahead and real-time markets is unjust and unreasonable and that reforms are needed to provide the flexibility needed to respond to the increase in variable generation. “As explained by PJM, ‘every other [RTO] has a methodology to procure the reserve products needed in real time in advance of the operating day except PJM.’”
More Action Sought
FirstEnergy said the RTO’s proposal was so “watered down” it will fail to create the “meaningful price impact that is needed to spur increased investor confidence in the PJM wholesale markets.”
In addition to approving PJM’s proposal, FirstEnergy said FERC should order the RTO “to conduct a holistic review of all of PJM’s wholesale markets to ensure that generation resources that provide key attributes, such as fuel security, fuel diversity and resilience, receive compensation for the attributes they provide to the electric grid.”
The eight energy trading firms, members of the Energy Trading Institute, backed PJM’s proposal but said it represents only “low hanging fruit” and that the RTO should take further action to fix its energy market.
“To be clear, ETI is not advocating for an energy-only construct, but both PJM staff and its stakeholders should focus on getting the prices right in the energy market and not on continual and Sisyphean revising of the capacity market constructs to meet newly arising needs,” the traders said. “The capacity markets were intended to be residual markets, not a panacea for all revenue needs.”
Former Montana regulator Travis Kavulla, director of energy policy for the R Street Institute, said the PJM proposal is “laudable” but may not be just and reasonable without also making changes to the capacity market. “It is not clear why consumers, having paid for capacity once through the forward capacity market, should be expected to pay again for a type of operational capacity in near real time,” Kavulla said. “The commission should make clear that a market design shaped around an increasingly robust ORDC is an off-ramp from, and an eventual substitute for, the forward capacity market, which is an inferior vehicle to pay resources for the capacity that customers actually require.”
Kavulla noted that PJM’s base case projects energy and capacity revenues will increase by $556 million annually while production costs rise only $30 million. “In other words, the vast majority of ORDC revenue is paying for resources’ fixed costs and not the costs associated with production under this new market design. At the same time, avoided uplift costs — one of the core reasons to adopt ORDC that PJM proffers, with which we agree — amount to little more than $3 million.
“An ORDC with high price caps remains administrative in nature, but at least its administrative elements seek to correct blunter and worse administrative interventions in the markets — namely operator commitments and lower price caps,” Kavulla continued. “Importantly, ORDC does not require the degree of speculative planning that forward capacity markets do. Either a resource has dispatchable headroom in near real time, or it does not.”
Insufficient Evidence
The Monitor and the Maryland Public Service Commission said PJM’s proposal is overly expensive and not supported by evidence that current rules are unjust and unreasonable.
“PJM’s proposal, if implemented, would cost ratepayers billions of dollars with no commensurate benefits,” the PSC said. “Furthermore, energy and operating reserve market revenues would increase without an appropriate offset in the capacity market, thereby resulting in billions of dollars in over-recovery.”
The PSC said the real problem is that PJM’s dispatchers lack appropriate tools and generator operating information.
“It is vexing that after seven years of market implementation and in this modern age of technology, communications and telemetry, PJM is unable to provide its dispatchers with actual, real-time resource operating data and performance capabilities from the generators it controls on its system,” the PSC said.
The IMM rejected PJM’s claims that prices during the January 2019 cold snap were too low, saying there was ample supply, generator outage rates were low and natural gas prices remained below the cost of fuel oil. | Monitoring Analytics
The PSC challenged PJM’s proposal to increase maximum prices — including compounding of multiple reserve products — to $12,000/MWh, saying the RTO’s current maximum of $3,700 is “on par” with the $3,725/MWh cap in NYISO and the $3,500/MWh maximum in MISO.
“While an overreliance on wind and solar resources during times of operational stress may merit additional review in the future, such resources currently contribute minimally to the PJM grid,” the PSC said. “For example, PJM indicates that when the system experienced its peak demand during the most severe recent cold weather event, wind and solar resources amounted to approximately 1.4% of the total generation output.”
Public Citizen also opposed the filing, saying it is “simply a regional version of U.S. Energy Secretary Rick Perry’s grid resilience bailout push.”
“PJM is run less as an independent transmission operator and more as a price-fixing cartel: PJM management is free to conspire with certain of its powerful members, promoting pricing changes designed to deliver bigger profits to said members,” the group said.
It said FERC should order an evidentiary hearing to investigate “the cabal involving PJM management and certain transmission owner-members that control generation assets.” It also said Commissioner Bernard McNamee, a former Department of Energy official, should recuse himself from the case.
Monitor: Prices Reflect Oversupply
The Monitor said PJM’s current energy and ancillary service markets are producing just and reasonable rates and that the RTO’s proposal would increase costs by more than $1.7 billion per year.
The proposal “shifts scarcity revenues from the capacity market to the energy market but does not propose that capacity market revenues reflect that shift,” the Monitor added.
It rejected complaints that energy and reserve prices are too low, saying they are a function of cheap fuel and excess capacity, noting the RTO’s reserve margin — 25.9% in June — is 62% above the required 16% margin.
“Frequent reserve pricing at zero is just and reasonable because it is an efficient, competitive outcome. This market design and market outcome is common among the RTOs. Finding it unjust and unreasonable in the PJM market would naturally extend to the other RTO markets.”
If the commission does rule PJM’s current rules unjust, the Monitor said FERC should reject the RTO’s plan in favor of its own proposal, which was the most popular of five voted on by the Markets and Reliability Committee in January — albeit at 52%, still below the two-thirds threshold needed for endorsement. (See PJM Stakeholders Deadlock on Energy Price Formation.)
VALLEY FORGE, Pa. — PJM staff agreed on Tuesday to delay approval of revisions to generation outage procedures after stakeholders raised concerns over potential market consequences.
Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, pressed the Operating Committee to defer a vote on changes to Manual 10, saying the proposed language would encourage resource owners to distort prices in their favor.
Vince Stefanowicz, PJM senior lead engineer, said the manual specifies that generators must submit outage requests corresponding to the time frame that they will be unavailable because of a transmission facility outage — and, under the proposed language, in the event of a PJM-identified stability limitation.
O’Connell said PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under PJM’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.
As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and it must be used in each of the markets. He also encouraged the RTO to publicize stability limits on OASIS prior to contacting the affected generator.
“I think Bob has raised a legitimate issue,” said Mike Bryson, PJM’s vice president of operations. “But we have an interim issue that this practice will be enforced until we come up with a solution. I don’t know how to resolve that outside a clarification in the manual.”
The committee agreed to delay the revisions — and remove stability-related changes from Manual 3 revisions that were approved earlier in the meeting — until the issue is resolved.
O’Connell said he will present a problem statement and issue charge at the June meeting of the Market Implementation Committee detailing his proposed solution.
BTM Solar Penetration Mimicking CAISO Duck Curve
Increasing penetration of behind-the-meter solar generation creates a dramatic load shape in certain PJM zones during spring and fall months, mimicking CAISO’s infamous “duck curve,” staff said Tuesday.
Joseph Mulhern, PJM senior engineer, told the OC that significant growth in both grid-connected and BTM solar units over the last decade have caused load forecasting challenges, particularly during shoulder seasons when reduced electricity demand results in overgeneration.
“Since the duck curve became a popular concept … do we see anything reminiscent of this?” Mulhern said. “If you look in the right places at the right times, we do.”
CAISO first introduced the idea of the duck curve in 2013 to illustrate how rapidly expanding solar generation was impacting the system. Solar energy often peaks midday when electricity usage, particularly in the spring, may be lower than usual. The resulting curve resembles a duck — hence the name — which has become common nomenclature when describing the challenges of harnessing the full potential of solar generation. (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)
Mulhern presented sample load shapes from 24-hour periods in March — the peak season for the duck curve in PJM —and said traditional forecasting methods failed to capture all of the 3,304 MW of BTM solar currently online. The RTO can’t access unit-specific data for BTM generation like it can for the more than 1,500 MW of grid-connected solar panels, so staff has implemented a “reconstituted load” calculation to fill in the gaps.
The reconstituted load “retrains” the existing model by adding historic measured load and estimated BTM generation together. Staff then subtract forecasted BTM generation to get a more accurate picture of how solar impacts load shape — but it’s not exact.
“All of this is evidence that our load forecasting process needs to have some changes made beyond our traditional approach,” Mulhern said.
Staff will continue educating the OC about existing BTM business rules over the course of several months before suggesting manual revisions to better account for the grid’s diversifying resource mix.
A decade of renewable energy growth in PJM | PJM
Quad Cities RAS Unnecessary
Exelon said recent analysis from PJM and Commonwealth Edison determined a remedial action scheme (RAS) in the Quad Cities region of Illinois and Iowa is no longer necessary to meet planning criteria.
The Quad Cities RAS prevents instability for a three-phase fault during line outages and thermal overloads during multiple line outages. Exelon said incremental grid reinforcements reduced the need for the scheme. The company will disable the RAS by the end of year with complete removal in 2020.
Manuals Endorsed
The committee unanimously endorsed the following manual changes:
Manual 1: Periodic cover-to-cover review to update terminology and guidelines for control center and data exchange requirements.
Manual 3: Biannual review to update transmission operating procedures, excluding references to stability.
Manuals 11 and 13: Clarifies the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
Manual 13: Periodic cover-to-cover review and changes to align with new Markets Gateway functionality for resource-limitation reporting to be implemented July 1.
Pacific Gas and Electric transmission and distribution lines caused the deadliest and most destructive fire in California history, state fire officials announced Wednesday.
The Camp Fire in rural Butte County flared the morning of Nov. 8 near the tiny community of Pulga. Within hours it killed at least 85 people, destroyed 18,804 structures and burned more than 153,000 acres. The fire destroyed the town of Paradise, population 27,000.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) said the fire’s main origin was beneath a PG&E transmission tower on the 100-year-old Caribou-Palermo line.
The department said in a statement that it made the determination “after a very meticulous and thorough investigation.”
National Guard soldiers search through rubble in November after the Camp Fire tore through Paradise, Calif., killing 85 and casting suspicion on PG&E. | California National Guard
A second ignition occurred nearby when vegetation contacted a PG&E distribution line, Cal Fire said. That second fire was consumed by the main blaze.
“The tinder dry vegetation and red flag conditions consisting of strong winds, low humidity and warm temperatures promoted this fire and caused extreme rates of spread, rapidly burning into Pulga to the east and west into Concow, Paradise, Magalia and the outskirts of east Chico.”
Cal Fire said it forwarded the results of the investigation to the Butte County district attorney for possible criminal investigation.
The announcement that PG&E started the fire was long awaited but not a surprise. The utility has already said its equipment most likely started the blaze.
“The act by Cal Fire of forwarding its report is strictly symbolic,” Butte County District Attorney Mike Ramsey’s office said in a statement Wednesday. “The fact the Camp Fire was started by a malfunction of equipment on a Pacific Gas & Electric Company transmission line has been known for months by investigators and had been, essentially, admitted by Pacific Gas & Electric in an early December 2018 report to the California Public Utility Commission.”
Ramsey said his office would provide no further comment on its investigation, “which is expected to last from weeks to months.”
The expected liability from the Camp Fire — currently estimated by PG&E to be about $14 billion — was a major reason the utility filed for bankruptcy in January. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Cal Fire has also blamed PG&E for 18 of 21 major wildfires in 2017 that burned through Northern California wine country and the Sierra Nevada foothills.
All told, PG&E said it is facing more than $30 billion in liability for the 2017 and 2018 blazes.
‘Wrong Message’
California Gov. Gavin Newsom last month released a report criticizing PG&E for its lax safety standards and accusing the utility of “taking advantage of the bankruptcy process to promote the interests of investors over fire victims and other stakeholders.” (See Calif. Must Limit Wildfire Liability, Governor Says.)
The report said the state should monitor and intervene in the bankruptcy to protect California residents and keep open the option of breaking up the utility.
Acting in that vein, Newsom’s office on Wednesday asked the judge overseeing PG&E’s bankruptcy to deny the utility’s request for a six-month extension of its “exclusivity period” for producing a reorganization plan, urging the court to instead grant a 75-day extension at the most.
Under U.S. bankruptcy law, debtors normally have 120 days from the date of a bankruptcy filing in which to file a reorganization plan. Parties wanting to file a competing plan during that time must convince the judge to terminate the exclusivity period.
In a brief submitted to the U.S. Bankruptcy Court in San Francisco, Newsom said PG&E’s request “reflects no sense of urgency in addressing the serious problems and issues confronting” the company.
“The requested six-month extension is of particular concern because it encompasses the entirety of the 2019 wildfire season, thereby exposing PG&E to the risk of unquantifiable post-petition claims arising from 2019 wildfires,” Newsom wrote. “Such a prolonged extension of exclusivity to file a plan of reorganization would send PG&E and all of its stakeholders the wrong message. Allowing PG&E to continue a business-as-usual approach without any accountability would only encourage PG&E’s distressed-investors to leverage the Chapter 11 cases to their benefit and to the detriment of existing and future wildfire victims.”
Newsom reminded bankruptcy Judge Dennis Montali that PG&E entered bankruptcy as a convicted felon over its culpability for and obstruction of justice related to the 2010 San Bruno natural gas pipeline explosion.
“Nor should we ignore the reality that victims of the catastrophic fires in 2017 and 2018 suffered unimaginable losses and are still struggling to rebuild their lives,” Newsom said. “Allowing PG&E to remain in Chapter 11 without accountability will only unfairly cast doubt and uncertainty over the recovery on victims’ claims and prepetition settlement obligations.”
CARMEL, Ind. — MISO will pull back on a plan to create a special lane in its interconnection queue to accelerate the process for projects that demonstrate readiness for development.
The move — announced Tuesday at the Interconnection Process Working Group (IPWG) — represents MISO’s second about-face on the issue. After last year resisting wind developers’ pleas to create, the RTO early this year said it would develop a fast-track option, with staff floating possible approaches in March. (See MISO Details Fast-track Queue Options.)
The effort would have created a separate, expedited definitive planning phase (DPP) designed to allow select projects with documented evidence they would be complete in about three to six months.
“We’ve decided to put this on hold until further notice,” Resource Interconnection Planning Manager Neil Shah told the IPWG.
MISO queue as of May | MISO
Shah said stakeholder reaction to the March presentation persuaded MISO to change course. He said a fast-track option does not have general support, with stakeholders instead urging the IPWG to improve the existing process rather than “developing a parallel path.”
“Basically, stakeholders want us to improve efficiency for the existing DPP. They think it’s not the right time for it.”
Shah said some stakeholders pointed out that an expedited DPP “may not help projects where state regulations mandate certificates of public convenience and need,” typically a two-year process.
But BayWa r.e. renewable energy’s Patrick Brown urged MISO to not “flush away” the proposal, but “flesh it out more.”
“If you have a [power purchase agreement], you’re clamoring for this,” Brown said, adding that there must be multiple developers in MISO’s interconnection queue that can demonstrate readiness.
MISO’s queue is once again at an all-time high, now at 640 projects totaling 100.7 GW, with 297 projects totaling nearly 44 GW having entered the queue this year before the April 29 window close. Solar accounts for about 210 of the new projects, at nearly 30 GW.
The total queue is now about 86% wind and solar projects, with proposed solar generation (59 GW) overtaking wind (27 GW). Proposed storage projects represent about 3 GW, while natural gas projects represent more than 9 GW.
MISO’s queue topped out at about 90 GW in 2018 but had fallen to about 70 GW by March because of withdrawing projects.
The RTO is only suspending the fast-track effort, not completely closing the door on the idea, Shah said, noting his staff will continue to monitor any shift in stakeholder opinions. He also pointed out there other there are “other avenues” stakeholders can pursue within the Tariff if they are simply looking to accelerate the construction of projects.
Additionally, MISO now plans to perform an intensive examination of how projects advance the queue, looking specifically at project modeling, the DPPs and agreement negotiation.
MISO Manager of Resource Interconnection Arash Ghodsian said interconnection staff will follow the April 2018 cycle of projects and collect data to examine how to reduce the length of time projects spend in the interconnection process.
“The goal is to come back in July and talk about the model development stage, talk about the process, the successes and challenges, and the opportunities for improvements,” Ghodosian said.
“There are no intentions at this point to file anything,” he added. He said any possible solutions will be arrived at “collaboratively” with stakeholders.
California’s oldest irrigation district has become the latest balancing authority to commit to the Western Energy Imbalance Market.
CAISO said Wednesday that Turlock Irrigation District (TID) signed an agreement to join the EIM in April 2021, putting it on track to begin trading alongside Los Angeles Department of Water and Power, NorthWestern Energy and Public Service Company of New Mexico.
TID’s decision comes just a week after Arizona-based Tucson Electric Power said it will link up with the real-time market in 2022. (See Tucson Electric Power Signs up for Western EIM.)
Turlock Irrigation District operates the 203-MW Don Pedro Dam in partnership with Modesto Irrigation District. | Turlock Irrigation District
Established in 1887 to provide water to farmers in California’s Central Valley, TID now serves more than 100,000 electricity accounts in addition to 5,800 irrigation customers. The district’s generation portfolio includes 137 MW of wind, 98 MW of natural gas, 54 MW of contracted solar, a small amount of geothermal and a 68% share of the output from the 203-MW Don Pedro hydroelectric dam.
TID also owns a share of the California-Oregon Intertie, the key link between the Pacific Northwest and Northern California. Its transmission network interconnects with neighboring systems operated by CAISO, the Western Area Power Administration, the California-Oregon Transmission Project and the Sacramento Municipal Utility District (SMUD), the last of which began transacting in the EIM last month.
“TID’s participation in the Energy Imbalance Market will lead to a greater utilization of our resource portfolio,” Brad Koehn, the district’s assistant general manager of power supply, said in a statement. “Additionally, gaining access to the resource diversity within the EIM footprint will help us maintain our core mission of providing reliable and affordable power.”
The sheer momentum of the EIM — combined with a parallel decline in regional bilateral markets — appears to have sealed the deal for TID.
“With the amount of utilities participating in the intra-hour market, TID expects the hourly markets it currently participates in will become much less liquid compared to previous years. Over time, this reduced liquidity would likely lead to increased purchased power and fuel costs, absent participation in the EIM,” TID said last month in announcing its plans.
TID estimates it will recoup its $5.5 million in EIM start-up costs in two to three years.
The EIM’s current members in addition to SMUD are Arizona Public Service, Idaho Power, NV Energy, PacifiCorp, Portland General Electric, Puget Sound Energy and Powerex. CAISO last month said the EIM has yielded $650.26 million in benefits for its members since being launched with PacifiCorp as its first member in November 2014.
WASHINGTON — By now, ERCOT’s low reserve margin heading into this summer has been a much-discussed topic.
The grid operator anticipates its reserve margin will be 8.5%, well below its 13.75% target, indicating a possibility it will need to issue an energy emergency alert at some point this summer. It’s forecasting a peak demand of 74.9 GW against 78.9 GW in available capacity. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)
But ERCOT’s margin sticks out even more when compared to those of most other regions in the U.S., where their reserves are well above their reference levels. The Western Electricity Coordinating Council region will have reserves of more than 30% against a reference level of slightly less than 15%. PJM comes in second with a margin of slightly less than 30%. Only MISO expects reserves to be only slightly more than its target level.
The reserve margins for this summer were presented to FERC commissioners at their monthly open meeting Thursday as part of staff’s annual summer reliability report, using data from NERC’s Summer Reliability Assessment, which will be released on May 30, and from the Energy Information Administration.
Three-month temperature outlook, as of May 16. This projection was coincidentally released the same day FERC staff presented their report, which used NOAA’s (mostly similar) projection from April 18. | NOAA
Last year, FERC was similarly concerned about ERCOT’s low reserve margin: 10.92% at the time. But staff noted in their report that the grid operator “maintained system reliability with no load curtailments,” and ERCOT has reassured stakeholders repeatedly that it will do so again. (See FERC Keeps Eye on ERCOT, CAISO as Hot Summer Approaches.)
FERC is also still concerned about natural gas constraints in California because of low inventories at the Aliso Canyon natural gas storage facility. But “various preliminary assessments have found that the power system is in a better position this summer than during the summer of 2018,” staff said. And unlike last year, which saw a decrease in winter precipitation — and therefore less available hydropower — this past winter saw heavy snowfall, with snowpack over 160% of the historical norm as of April 1. (See related story, CAISO Predicts Plentiful Hydro, Gas Constraints.)
“Preliminary estimates suggest that higher available hydropower plant production this summer will reduce the reliability risk of insufficient operating reserves occurring due to a gas curtailment in California,” commission staff said.
Based on EIA data, FERC staff expect net new generation capacity to be about 4.1 GW, with about 6.7 GW to come online against 2.6 GW of retirements. Most of the retirements consist of coal resources (0.8 GW in PJM) and two nuclear plants — one each in ISO-NE and PJM — worth 1.5 GW.
Reserve margins are more than adequate in all regions, except ERCOT. | NERC
Commissioner Richard Glick noted the high reserve margins in comments after the staff presentation. While he said it was good news that the U.S. doesn’t have a resource adequacy problem, the figures suggest that “it’s worth taking another look at” the way some regions are procuring capacity. “Because if we’re significantly over the targeted reserve margins, something’s wrong.”
He said he knew that some of the capacity was leftover and no longer receiving payments. “There’s also a lot receiving capacity payments; there’s not a lot of retirements going on,” he said. “We need to figure that out: how we can get closer to the targets.”
Asked about potential overcapacity and its costs to consumers, FERC Chairman Neil Chatterjee told reporters after the meeting, “It’s something that we’ll look at. My takeaway from the report is we’re in good shape for the coming summer, but we need to be vigilant regarding discrete issues,” particularly ERCOT and gas constraints in the West.
