SANTA FE, N.M. — SPP and its stakeholders have begun to grapple with the complex issue of how to use battery storage, but they must first determine who will guide the process moving forward.
Meeting Jan. 15, the Strategic Planning Committee heard from some members who wanted to create a task force and others who pushed for a steering committee.
Larry Altenbaumer, chair of both the Board of Directors and SPC, posited that SPP should take a strategic approach to the issue. He suggested the SPC again take up the subject at its April meeting in Little Rock, Ark.
“It sounds like a really good idea that we need to work out,” Altenbaumer said.
SPP Senior Vice President of Engineering Lanny Nickell agreed that the decision should be a strategic one. “What degree does SPP want to invest in the growth of batteries?” he asked. “Once we know that vision about storage, that will help guide what we know about batteries.”
“Someone has to take on a big-picture view of this thing, to get the discussion going and organize it,” Midwest Energy’s Bill Dowling said. “We have to do some of this up front in an organized fashion. We have to organize this herd of cats.”
FERC in October found that SPP’s first response “generally enable[s] electric storage resources to provide all services they are capable of providing.” However, it also required the RTO to adopt Tariff rules covering minimum run-time requirements for resource adequacy. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
“Energy storage has the potential to change the way this industry operates,” said Richard Dillon, SPP’s market policy technical director. “Until now, energy had to be generated immediately. Energy storage changes that paradigm.
“But Order 841 removes barriers to ESR participation. That can be too much of a good thing. It responds so fast that the rest of the system can’t keep up with it,” he said.
Dillon presented a white paper on energy storage to the Markets and Operations Policy Committee at its Jan. 15 meeting. He returned that afternoon to discuss the paper with the SPC.
The paper lists energy storage’s benefits as its flexibility and ability to inject or receive energy; its instantaneous response to grid events; its ability to balance supply and demand; and its potential as an economic market resource and an economic alternative to traditional transmission.
It says SPP should capitalize on ESRs’ flexibility, maximize their reliability and economic benefits, develop cost-recovery for ESRs, and resolve issues on whether they’re used as generation and/or transmission assets.
“We have a great asset coming into our region and we don’t want to limit it,” Dillon said.
Dillon said ESRs’ decreasing costs — an 87% drop in real terms from 2010 to $156/kWh last year, according to Bloomberg New Energy Finance — and recent tax law changes have significantly increased requests to interconnect the resources to the grid. SPP’s generator interconnection queue contained less than 1 GW of ESRs in 2016. By mid-2019, ESR requests had expanded to nearly 7 GW.
SPP’s accelerating energy storage growth | SPP
The white paper makes several recommendations that touch six different working groups and SPP’s Market Monitoring Unit.
Betsy Beck, with Enel Green Power NA, agreed with Hall. She said ERCOT felt things were moving too slowly and changed its approach.
“They put everything in. They’re moving really, really quickly to resolve these issues. It’s worked extremely well,” Beck said. “We need storage to come on and provide the maximum flexibility for ramping issues we’re seeing on the operational side.”
PJM industrial customers said Tuesday that voluntarily buying and selling renewable energy credits shouldn’t count as subsidies in the RTO’s capacity market, urging FERC to reconsider its broad definition of the word to exclude those transactions (EL16-49, EL18-178).
FERC, in its Dec. 19 ruling expanding PJM’s minimum offer price rule to all resources, said distinguishing between RECs mandated through state renewable portfolio standards and those bought as part of power purchase agreements is impossible. The new MOPR, meant to address price suppression from state subsidies, has drawn criticism from a broad section of stakeholders who say FERC went too far in attempting to control states’ generation choices. (See related story, PJM MOPR Rehearing Requests Pour into FERC.)
Both the RTO and the PJM Industrial Customer Coalition (ICC) note that if resources can certify that all the RECs it sold were voluntary — rather than within the confines of state-sponsored RPS programs — then those resources should be exempt from the MOPR. At the very least, PJM argued in its rehearing request, FERC should have adopted a “safe harbor” for voluntary REC transactions.
The ICC was joined in its rehearing request by the Illinois Industrial Energy Consumers, the Electricity Consumers Resource Council (ELCON), the Industrial Energy Consumers of America, the Pennsylvania Energy Consumer Alliance, the Industrial Energy Consumers of Pennsylvania and the American Forest and Paper Association.
Hershey’s original, now demolished chocolate factory in Hershey, Pa., in 1976. The company was one of many industrial market participants protesting FERC’s MOPR ruling.
In their filing, the groups said they share FERC’s goal “of ensuring just and reasonable prices in both the short-term and the long-term through proper and sustainable operation of the PJM capacity market” and appreciate that the “order conveys a clear signal that states’ efforts to subsidize capacity resources will not be permitted to interfere with the efficient functioning of the PJM capacity market.”
But the ruling, they said, does not “enable its practical implementation without unlawfully upsetting existing commercial arrangements and market dynamics.”
“In a voluntary REC transaction, the RECs are not needed or used by the retail customer or its load-serving entity for state RPS compliance,” the groups said. “Because there is no nexus between the customer’s load and any state RPS, the generating resource does not obtain any state subsidy from its sale of the RECs.”
Hershey, the famed chocolate company, also filed a motion to intervene in the proceedings Tuesday upon learning that its pending PPAs that include voluntary REC transactions would be subject to the MOPR. The agreements were designed to help Hershey meet its greenhouse gas emission-reductions goals in line with the Science-Based Targets Initiative. The company said in its filing that FERC’s decision has “effectively stalled Hershey’s project and impeded its ability to meet Hershey’s environmental goals and the expectations set by the company’s consumers and investors.”
ELCON, in a separate filing it made against the MOPR, reiterated that such contracts should not be subjected to the new price floors.
“In particular, private capital that pursues voluntary capacity contracts in bilateral markets should not face administrative corrections,” the group said. “For example, corporate consumers are increasingly deploying their own capital to voluntarily purchase power through the bilateral market or procure renewable energy credits, which do not constitute subsidies. Voluntary payments received outside of the capacity market should receive categorical exclusion.”
CARMEL, Ind. — MISO navigated December with just one severe weather alert in its South region.
The RTO’s load averaged 74.3 GW throughout the month, down slightly from the 75.5-GW average a year earlier. However, the 95.5-GW peak on Dec. 19 bested December 2018’s 94.2-GW peak.
“Temperatures in December were slightly higher than last year and above the 30-year average,” Executive Director of Energy Operations Rob Benbow explained during an Informational Forum on Tuesday.
Benbow said prices were down significantly because of “surging” U.S. natural gas production. Day-ahead prices averaged $21.92/MWh and real-time $21.05/MWh — both down more than 30% year over year.
| MISO
The RTO’s lone operational alert for the month occurred Dec. 16-17 in MISO South, when multiple tornadoes formed in Louisiana, Mississippi and southern Arkansas. The severe weather alert never escalated to conservative operations instructions.
CEO John Bear said the reasonably mild winter conditions are not indicative of what’s to come in the footprint, cautioning that MISO was in the “calm before the storm” in terms of resource evolution.
2019 “was a very successful year,” Bear said. “We have a whole lot of heavy lifting in front of us in the next 24 to 36 months. … We’ve got a lot of big, meaty things on our plate this year.” Bear cited MISO’s ongoing market platform replacement as well as the resource availability and need project, which may entail changes to the Planning Resource Auction and capacity accreditation.
“It’s going to give us a tremendous amount of flexibility and transparency … as resources change,” Bear said of the new cloud-based market platform.
Four former FERC chairs celebrated two decades of RTOs Tuesday with a call for federal action to increase interregional transmission and price carbon emissions into energy markets.
Former Chair Jon Wellinghoff (2009-13) said Congress, which gave FERC authority to enforce mandatory reliability standards in 2005, should now give the commission the power to create a national transmission policy to move renewable power to load centers.
“I think it’s now time for the Congress to give FERC direction about our climate crisis and how the transmission system is going to address that,” Wellinghoff said during a webinar by Americans for a Clean Energy Grid. The hour-long session celebrated the 20th anniversary of FERC Order 2000, the December 1999 order that pressed transmission operators to join regional transmission organizations.
Wellinghoff — who was joined by former Chairs James Hoecker, Pat Wood III and Cheryl LaFleur — said FERC needs congressional direction on transmission siting and cost allocation. “Without those specific things being addressed in some congressional authorizations, I think FERC will continue to be moving around the edges of things. We really need to move beyond that to address the climate crisis that we’ve got before us.”
Hoecker (1997-2001), former counsel to the trade group WIRES, said Order 2000 was needed to address anticompetitive practices that continued despite the open access requirements of 1996’s Order 888.
He lamented that Order 2000 was not mandatory. While the six FERC regulated RTOs and ISOs are “a lot more complicated and sophisticated than we anticipated,” he said, all the Southeast and much of the West remains without access to organized wholesale markets today.
Hoecker “was Moses; he got to see the promised land. I was Joshua [who] actually got to walk through the muck to get into it,” joked Wood (2001-2005), referring to the compliance filings that FERC received in 2001.
Wood said he would have preferred the original plan to have four RTOs, one each in the Northeast, north Midwest, Southeast and West. “That would have been the best [design] possibly. But after multilateral settlement talks, it became clear that it just wasn’t going to work out for a number of reasons, both political and interpersonal and operational.”
As a result, the commission approved filings by PJM and ISO-NE to become RTOs and later helped craft MISO and SPP “from the ground up,” he said.
Wood said Order 2000 reduced opportunities for gaming, reduced generators’ profit margins and facilitated state retail access programs. He acknowledged the changes were not popular with generators, particularly those operating inefficient coal- and gas-fired generators that were displaced by more efficient units and renewables. “That’s how a market is supposed to work,” he said, noting the importance of transmission and price signals. “We saw this on about the fourth hour that MISO was open. We saw redispatch happening in real-time. It was fascinating to look at the heat map.”
Wood said the big question for RTOs now is how to deal with the increasing penetration of zero variable cost renewables, saying he’s been “intrigued” by proposals for having a separate clean energy attribute market.
“From the beginning, the goal was simply an economic goal. But now we need to also consider these non-economic factors such as carbon intensity that are important to now — probably — the majority of the states.”
LaFleur, who served as chair or acting chair during parts of 2013-17, said RTOs’ regional planning and operations allowed a faster and more efficient transition away from coal and toward natural gas and renewables. It also helped regions deal with their own challenges, said LaFleur, who joined ISO-NE’s board of directors after leaving FERC last year.
“ISO-NE built several billions of transmission in the first decade of this century that essentially eliminated generation congestion that had been a problem there for decades. PJM was able to seamlessly adapt to MATS [the Mercury and Air Toxics Standards] that drove a tremendous amount of coal-to-gas switching in PJM … . Because you had a market, you never felt the blow.”
LaFleur and her colleagues agreed that some rulemakings since Order 2000, including Order 1000, which sought to open transmission development to competition, have not met their goals. Wood said he’d like to see Congress give FERC “backstop” transmission siting authority, which the commission could use as a “hammer to get people to the [negotiating] table” on interregional transmission needed to deliver renewable power.
But he said policymakers must find a way to pay for the new infrastructure that doesn’t encourage customers to leave the grid altogether in favor of distributed generation.
Moderator Rob Gramlich asked the panelists to predict whether RTOs will take root in the West and Southeast. The Western Energy Imbalance Market (EIM) has steadily increased since 2014. In the Southeast, lawmakers in North and South Carolina are considering legislation to study creation of an RTO for their states following the billions lost on the cancelled expansion of the V.C. Summer nuclear plant.
“It’s hard to think that, after all the economic carnage that happened in the Southeast, people don’t figure out that organized markets [are] a damn good way to get transparency on future investment,” said Wood. “We can’t repeat those mistakes again where you’ve got utility-driven investment that gets no market check at all. At a minimum, the energy imbalance market concept — or what we always called the day-one market — clearly makes sense across the country, even in the vertically regulated areas of the country like the Southeast.”
RTO/ISO transmission projects enabled half of the U.S.’s 100 GW of wind capacity, according to Americans for a Clean Energy Grid. | Americans for a Clean Energy Grid
But he acknowledged the “politics of this probably haven’t changed at the congressional level, so we’ve got to win their hearts.”
LaFleur noted that the growth of the EIM has been driven by individual states and utilities, not a federal mandate. “I’d love to see that happen in the Southeast as well,” she said, cautioning against a fight over a federal mandate.
But Wellinghoff said a federal mandate is needed to prevent transmission owners from using threats to quit an RTO to exercise control over RTO management. “I think it’s a fight worth picking,” he said.
SACRAMENTO, Calif. — The state’s new Wildfire Safety Advisory Board held its first meeting Tuesday, electing industry veterans as its chair and vice chair and getting briefed by California Public Utility Commission staff on its role and responsibilities.
Assembly Bill 1054, signed by Gov. Gavin Newsom in July, created the board and established a $21 billion wildfire recovery fund to shore up the state’s investor-owned utilities as they deal with the costs of massive, deadly wildfires sparked by electrical equipment. Pacific Gas and Electric is in bankruptcy following two years of catastrophic blazes.
The board, whose members are appointed by the governor and lawmakers, is meant to advise the CPUC’s new Wildfire Safety Division on fire-prevention measures, especially the wildfire-mitigation plans that IOUs must file with the CPUC under Senate Bill 901, approved in 2018.
The CPUC approved the first set of plans under SB 901 in May. (See California Regulators OK Utility Wildfire Plans.) This year’s measures are due in early February, and the CPUC plans to hold workshops to consider the measures later in the month. CPUC staff said the second-year plans likely would be far more detailed than last year’s measures.
“There’s a lot more coming this year, a lot more information,” Melissa Semcer, the commission’s wildfire mitigation branch manager, told the board.
At the outset of Tuesday’s meeting, the new board members elected as their chair Marcie Edwards, the former general manager of the Los Angeles Department of Water and Power (2014-17). Edwards was interim chief executive officer of CAISO in 2004.
As vice chair they picked Diane Fellman, the former vice president of regulatory and legislative affairs for the Western region at NRG Energy (2010-17). Fellman served as legal counsel to the CPUC in the 1980s and was most recently employed as a regulatory specialist at the CPUC.
Edwards and Fellman were appointed to the panel by Newsom, along with the following: Jessica Block, a senior wildfire researcher at the University of California, San Diego, who previously worked as a fire researcher in Australia; John Mader, an electrical distribution engineer at Pacific Gas and Electric since 1998; and Alexandra Syphard, a veteran research scientist now employed by Sage Insurance Holdings.
The state Senate named Ralph Armstrong Jr., a representative and business manager with the International Brotherhood of Electrical Workers (IBEW) and former journeyman lineman with the Western Area Power Administration. The state Assembly appointed Christopher Porter, also an IBEW representative and business manager.
The board scheduled monthly meetings through June, with its next meeting March 11 in Sacramento.
A broad range of stakeholders asked FERC on Tuesday to reconsider its Dec. 19 order requiring PJM to overhaul its capacity market, saying the commission’s directive is unnecessary and oversteps federal jurisdiction (EL16-49, EL18-178).
The commission said PJM must expand its minimum offer price rule (MOPR) to counter increasing state subsidies, primarily for renewables and financially struggling nuclear generation. (See FERC Extends MOPR to State Subsidies.)
The ruling builds on PJM’s “MOPR-Ex” proposal, filed in response to the commission’s June 2018 order finding the RTO’s capacity market rules unjust and unreasonable because they failed to address growing subsidies. The RTO’s existing MOPR covers only new gas-fired resources. (See FERC Orders PJM Capacity Market Revamp.)
But state regulators, utilities and load-serving entities alike argued in their rehearing requests that the order goes too far in attempting to control their generation choices and fails to prove state-subsidized resources suppress capacity market prices.
“The December order imposes an extraordinary cost on states that seek to exercise some control over their generation mix, effectively commandeering states into FERC’s preferred approach to resource planning,” wrote FirstEnergy Solutions, which last year became the chief beneficiary of an Ohio law subsidizing its nuclear and coal plants via ratepayer surcharges.
“The alternatives to submitting to FERC’s regime are grim,” FES wrote. “States will either have to incur significant duplicative costs for capacity — which will only increase as time goes on and emissions-reduction targets escalate — or exit the market altogether.”
State commissions in New Jersey, Ohio, Maryland, Pennsylvania and West Virginia complained that the order encroaches on their jurisdiction while inexplicably abandoning the resource-specific fixed resource requirement (FRR) alternative FERC itself suggested in June 2018 to address alleged price suppression from subsidies.
The result, they argue, means the expanded MOPR will distort price signals and force market participants to over-procure capacity and charge ratepayers twice for it.
“In the long run, the expansion of the MOPR to all new and existing resources under the repricing proposal advanced by the commission is likely to harm the energy and capacity markets administered by PJM,” the Pennsylvania Public Utility Commission said. “Imposing administratively adjusted offer prices at prices well above historical competitive market prices will only hasten the demise of truly competitive markets.”
The Maryland Public Service Commission said the order “forcefully treads” on state policies that value a resource’s environmental attributes by denying them capacity payments and “undoing the benefit of state support.”
“By raising barriers to state-sponsored renewable resources and effectively excluding them from participating in wholesale markets, the commission has acted ultra vires to shape generation mix and thwart states from exercising that function,” the Maryland PSC wrote. “The December 2019 order is particularly dangerous in that it severely curtails cooperative federalism in the regulation of generation by acting to stymie state efforts to value resource attributes.”
The New Jersey Board of Public Utilities said the “clunky” MOPR results in a “systemic and calculated” expulsion of new clean energy resources from the market, upsetting FERC’s “decades-long precedent” of leaving environmental regulation “largely to the states.”
“Nowhere does the order adequately explain this sudden antagonism to the cooperative federalism principles that underlie the” Federal Power Act, the BPU said. “Make no mistake: The alternative to granting rehearing is increased consumer harm in the form of higher prices and worse environmental outcomes. If the commission does not reverse course, state clean energy efforts will be frustrated and the PJM market will be at risk for dissolution.”
PJM itself urged the commission to rethink the order’s impact on states, saying that expanding the MOPR in pursuit of economic efficiency “may in fact unintentionally cause economic inefficiencies over the long term.”
“That new approach is over-broad and over-prescriptive and will dramatically curtail new resource options for integrated utilities, including those that meet the previously accepted net short and net long tests, whose offers have not previously been viewed as posing unacceptable risks to efficient price formation,” the RTO wrote. “The new approach also needlessly interferes with state resource policies well beyond what is needed to protect the market against inefficient price formation and achieve rates within a zone of reasonableness.”
[PJM also posted answers Tuesday to stakeholders’ questions on the MOPR ruling. The document will be updated each Friday afternoon, the RTO said.]
The Nuclear Energy Institute took issue with FERC’s refusal to allow a resource-specific FRR, which the commission had invited comment on in its June 2018 order, saying it may be just and reasonable. “However, in the December 2019 order, the commission reversed course and declined to adopt the resource-specific FRR with virtually no discussion of the issue, much less a reasoned justification,” NEI said.
NEI also criticized the commission for failing to address state preferences regarding capacity resources and the risk that an expanded MOPR without the resource-specific FRR option could leave ratepayers paying twice for capacity.
“The commission’s failure to conduct any such analyses [of a resource-specific FRR] and completely disregard legitimate state interests and goals, including failing to provide any kind of transition mechanism to accommodate such state interests and goals, is arbitrary and capricious and does not represent reasoned decision making,” the group said.
The Public Utilities Commission of Ohio asked FERC to consider ordering PJM to hold the delayed 2022/23 capacity auction without applying the expanded MOPR — similar to action taken during the implementation of Capacity Performance — to “get a forward capacity price signal in place, plug the three-year forward hole that currently exits and will likely grow, and provide for a transition period.”
“At a time when the commission has already significantly delayed the reveal of the three-year-forward capacity price, it is the PUCO’s fear that the forces set in motion by the order will promote long-lived uncertainty,” PUCO said. “This will, accordingly, strongly motivate states and market participants to take flight from the consequences attributed to the order.”
The Maryland attorney general’s office also questioned FERC’s decision to mitigate state subsidies while ignoring their federal counterparts and said the order “will have an outsized effect on existing business models for demand response, public power and voluntary renewable energy credits.”
Self-supply Exemption
Self-supply entities, like the Southern Maryland Electric Cooperative and Old Dominion Electric Cooperative, urged rehearing after describing PJM’s existing fixed resource requirement alternative (FRR-A) “unwieldy” and “unworkable” for planning new capacity.
FERC’s decision to abandon previously accepted exemptions for self-supply LSEs puts many resources at risk of being unable to clear the capacity auction, SMECO said. PJM’s existing and narrow FRR-A would require SMECO to carve out its entire load when using the option to accommodate a single new capacity resource subject to the MOPR, the cooperative said.
ODEC argued that eliminating the exemption would “indeed cause disruption of the industry” and fail to preserve existing investments. Further, the cooperative argues, the expanded MOPR will chill future ventures and disregards the entire business model of self-supply.
“As opposed to making investment decisions based on long-term economics and other benefits as ODEC historically has under its traditional business model, investments must now be made based at least in part on whether a resource is likely to clear the single-year, three-year forward capacity auction,” ODEC wrote.
The cooperative said neither the unit-specific exemption nor the FRR-A serve as legitimate substitutions for the self-supply exemption.
“ODEC and others have demonstrated in the past that the FRR may not be a workable alternative for smaller LSEs, given the requirements to opt out of the capacity construct for both purchases and sales, for a five-year period with onerous financial consequences if the ability to do so becomes untenable,” ODEC wrote.
Clean Energy Associations
Advanced Energy Economy, American Council on Renewable Energy, American Wind Energy Association and the Solar Energy Industries Association, filing as “Clean Energy Associations,” said FERC failed to prove PJM’s current market design is unjust and unreasonable, as required under Section 206 of the FPA, or to establish a new just and reasonable rate with its “drastic and unwarranted” expansion of MOPR.
The groups also said FERC overreached its authority under the FPA by effectively nullifying state renewable policies and seeking to mitigate state subsidies that don’t directly affect capacity prices, in violation of the Supreme Court’s 2016 ruling in FERC v. EPSA. (See Supreme Court Upholds FERC Jurisdiction over DR.)
“Based on the commission’s definition of state subsidy, if a town were to offer local permitting support to develop a specific new type of energy resource on a particular plot of land, and such program was not tied solely to ‘generic industrial development and local siting support,’ such program would also appear to be swept into the definition of state subsidy.”
The groups also said the commission failed to support its application of MOPR to state subsidies obtained through competitive processes and that its inclusion of voluntary renewable energy credits is arbitrary. “Further, the order presented no evidence or offered no analysis for subjecting carbon allowances, such as Regional Greenhouse Gas Initiative allowances, to the MOPR.”
EPSA
The Electric Power Supply Association (EPSA) and the PJM Power Providers Group (P3) asked the commission to reconsider its finding that no federal subsidies will be considered in determining whether a resource should be subject to the MOPR, saying the commission underestimated its authority under the FPA. It was EPSA member Calpine that led the complaint that resulted in the MOPR ruling.
“The commission’s refusal to extend the MOPR to offers from resources receiving federal subsidies of any kind was arbitrary and capricious as it cannot be reconciled with the commission recognition that ‘subsidies created by federal law distort competitive outcomes in the PJM capacity market in the same manner as do state subsidies,'” the groups said, quoting from the Dec. 19 order.
“EPSA and P3 do not argue that the commission must expand the MOPR to address all federal subsidies, only that the commission erred in declining to expand it to address any federal subsidies,” the groups said in a press release about their filing. “This request is consistent with EPSA’s past opposition to federal subsidies for uneconomic coal and nuclear resources.”
They also asked FERC to clarify that the definition of state subsidies would not include RGGI or voluntary, bilateral transactions for RECs. And they asked the commission to clarify that its references to the availability of the existing FRR rules “were merely factual statements as to the ongoing effectiveness of the FRR rules and cannot be construed as findings that the FRR rules are just, reasonable and not unduly discriminatory or preferential in light of changes required in the Dec. 19 order or other changes that have occurred since it went into effect.”
They also asked FERC to pressure PJM to hold the next two BRAs before the end of 2020, as the Independent Market Monitor has proposed.
Clarifications
Both PJM and the Monitor asked FERC to clarify that credits received through RGGI and default service procurement programs do not constitute subsidies.
Both Maryland and Delaware use RGGI as a means of reducing carbon emissions, with New Jersey, Virginia and Pennsylvania in line to join the program in the coming years.
“The RGGI cap-and-auction system is not a subsidy, any more than any other environmental limit on a particular plant is a subsidy for any plant that does not have the same emissions or discharges or the same limit,” PJM wrote.
AES likewise requested clarification on whether the MOPR applies to RGGI transactions.
PJM also asked confirmation on its interpretation on what triggers MOPR for resources that receive both state and federal subsidies, the latter of which FERC said aren’t impacted by the order.
The Monitor wants the commission to clarify treatment of the existing MOPR, noting that current rules subject capacity from landfill gas units, cogeneration units and fuel cells to an offer price floor, while exempting coal-fired steam units that are repowered as oil- and gas-fired steam units. Questions also remain about calculations for net revenues and rules for resources that seek must-offer exceptions, the Monitor said.
FirstEnergy Utilities expressed concerns about the unknown timeline for upcoming capacity auctions and worried that they wouldn’t have enough time to evaluate PJM’s FRR-A as an option. They requested clarification that PJM should provide flexible timelines to give utilities leeway in making a near-irreversible decision to use the FRR-A.
The utilities also said the commission should clarify that the self-supply exemption will apply when a self-supply entity purchases an existing generation asset that has previously cleared a capacity auction. Its rehearing request centered on FERC allegedly ignoring their arguments for a holistic market review.
SANTA FE, N.M. — SPP stakeholders last week delayed a decision over the weighting of futures and the use of economic must-run modeling in the RTO’s 2021 transmission planning assessment.
Staff and the Economic Studies Working Group committed to providing additional information to the Markets and Operations Policy Committee during its April meeting in Little Rock, Ark.
The ESWG last month agreed on a 60-40 weighting split between Future 1 — the “business-as-usual” case that reflects current trends — and Future 2, which is driven by assumptions that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates. The ratio passed both the ESWG and Transmission Working Group with a single abstention each.
Renewable interests favored a more aggressive forecast that incorporates additional energy growth. Others, wary of increasing transmission costs, favored a more conservative approach. Future 1 projects about 32 GW of wind installations by 2031, while Future 2 foresees about 37 GW.
Casey Cathey, SPP’s manager of reliability planning and seams, said that a similar 60-40 split in the 2019 Integrated Transmission Planning assessment would not have changed its final results for identifying transmission needs.
“Some people think there should have been more wind assumptions,” Cathey said. “In the end, after all that debate, it would not have budged our 2019 portfolio.” (See “MOPC Approves $336 ITP Portfolio,” SPP MOPC Briefs: Oct. 15-16, 2019.)
SPP Senior Vice President of Engineering Lanny Nickell suggested identifying reasonable outcomes and assigning them probabilities.
“Once you do that and you’re confident you considered the outcomes, you’re going to make the best quality decision at that time,” he said, noting no one had mentioned the implications of extended tax credits for wind energy.
“It feels like whether you want chocolate or vanilla ice cream. There’s no scientific basis,” SPP Board Chair Larry Altenbaumer said during the Strategic Planning Committee’s meeting Wednesday. “Some prefer one; some prefer the other. That feels lacking to me. It doesn’t seem a very good way to get to where we need to be.”
Must-run Review
Also drawing considerable stakeholder discussion was the ESWG’s plan to assign economic must-run designations to cogeneration, nuclear and hydro units. Exceptions would have to be requested during the generation review and approved by the working group.
However, a list shared with stakeholders included several coal-fired units previously granted exceptions, including Sunflower Electric Power’s 349-MW Holcomb 1. The 37-year-old unit in western Kansas has been often criticized for causing congestion in the area and creating the need for additional transmission investment.
Al Tamimi, Sunflower’s vice president of transmission planning and policy, told RTO Insider that the utility is contractually obligated to a coal delivery contract, executed in 2004 before it became an SPP member, that does not expire until 2034.
Tamimi said no studies completed through the planning-study processes confirm the assertion that congestion will be reduced by removing Holcomb from the list of economic must-run units. Energy exported from Sunflower’s transmission zone far outpaces Holcomb’s production during periods of high wind and also increases congestion, he said.
“As a must-run unit, [Holcomb] … will be dispatched down during high-wind periods … and dispatched up during periods when wind output is lower, which will help alleviate congestion on the byway lines around the unit,” Tamimi said. “Removing coal units like Holcomb from the economic must-run list will most likely drive new economic transmission capital projects to Sunflower’s [transmission] zone. If the new transmission is byway-funded, the Sunflower zone pays almost 70% of its cost and receives negative benefit from it.”
Greg McAuley, Oklahoma Gas & Electric’s director of RTO policy and development, said his concerns about including Holcomb on the economic must-run list centered around the potential effect of a unilateral decision to self-commit a unit out-of-merit on transmission planning.
“We simply want to ensure that we’re all being treated fairly, and that our customers are not being asked to pay for unilateral decisions made by other entities,” McAuley said.
Coincidentally, while the MOPC meeting was taking place, Sunflower announced it would let its air permit for a proposed second Holcomb unit expire in March. Colorado-based Tri-State Generation & Transmission’s decision to pull out of the $2.2 billion, 895-MW project was the final straw for a project first proposed in 2005 during former Kansas Gov. Kathleen Sebelius’ administration.
ESWG Chair Alan Myers, with ITC Holdings, was able to secure approval of leveraging existing processes to model member-submitted loads from the Bakken shale play in the upper Midwest area; to begin developing approaches that address winter-peaking and cold-weather-driven reliability issues for incorporation in SPP’s normal planning processes; and obtain a waiver of the ITP manual’s requirement to use resource planning software in the 2021 assessment.
Members also approved an ESWG revision request (RR395) that creates a hybrid methodology for gas price forecasts by averaging multiple sources.
The California Public Utilities Commission launched an examination Thursday of the state’s natural gas infrastructure and the rules governing it for the first time in 16 years, citing accidents and declining demand as threats to the system’s safety and reliability.
“California’s energy system is undergoing a period of profound change,” Commissioner Liane Randolph said. “We have committed to the goals of 100% clean energy, doubling of energy efficiency, widespread transportation electrification and a carbon neutral economy by 2045. Given these adopted objectives and policies we should anticipate and plan for the long-term changes in California’s gas distribution system as well.”
The dozen companies named as respondents by the CPUC include Pacific Gas and Electric, San Diego Gas & Electric and Southern California Gas.
“Since the commission’s last decision in [January 2004], several events, such as greenhouse gas legislation, operational issues and constraints, and gas pipeline and storage safety-related incidents, require the commission to re-evaluate the policies, processes and rules that govern gas utilities,” the commission said in its order instituting rulemaking (OIR).
The Aliso Canyon natural gas storage facility experienced a massive leak in 2015. | California Governor’s Office of Emergency Services
It noted that PG&E was found responsible for the explosion of a 30-inch gas pipeline in 2010 that killed eight people in San Bruno, south of San Francisco. Afterward, the commission adopted a safety plan requiring operators to outline how they would replace or pressure test all intrastate gas pipelines that hadn’t been tested recently at a cost of more than $2.3 billion.
Then in October 2015, SoCalGas identified a leak at its Aliso Canyon natural gas storage facility, which spilled 120,000 metric tons of methane before it was capped nearly four months later. Gov. Jerry Brown ordered a halt to gas injections at Aliso Canyon.
State regulators, including the CPUC, allowed limited injections to resume at Aliso Canyon in July 2017. The continuing limitations have constrained gas supply in Southern California, leading to higher wholesale electricity prices and reliability concerns. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
Problems with interstate pipelines have also impacted supply. About 30% of the state’s electric supply comes from gas-fired generators.
Meanwhile, the state has enacted stringent GHG emission laws and required decarbonization of the grid by midcentury. Cities, including Los Angeles and San Francisco, have introduced rules and incentives to eliminate gas heating and appliances from certain classes of buildings. (See West Coast Pushes for Building Electrification.)
Falling Demand, Rising Costs
The demand for natural gas is expected to decline significantly over the next 25 years, leaving those still dependent on gas to pay the costs, the commission said in its OIR.
“Ratepayers who remain on the system the longest will likely be customers who may not be able to afford to switch from gas to electric home heating and cooling systems; yet, these customers would be required to cover the revenue requirement of the remaining pipeline system at higher rates,” it said.
In an October 2019 report titled “Natural Gas Distribution in California’s Low-Carbon Future,” the California Energy Commission discussed the “feedback effect” of building electrification and declining gas use.
“If demand for natural gas in California falls dramatically because of some combination of policy and economically driven electrification, the fixed costs to maintain and operate the gas system will be spread over a smaller number of gas sales and, ultimately, will increase costs for remaining gas customers,” the commission said.
“This outcome raises the possibility of a feedback effect where rising gas rates caused by electrification spur additional electrification,” it said. “Such a feedback effect would threaten the financial viability of the gas system, as well as raise substantial equity concerns over the costs that remaining gas system customers would face.”
The CPUC said the goal of its OIR is to ensure reliable gas service to customers at just and reasonable rates going forward.
The “proceeding will examine how industry-related events that have occurred since the last OIR require the commission to change the rules, processes and regulations governing gas utilities, including, but not limited to, reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders,” the commission said.
The OIR outlines a three-phased approach, starting immediately.
The first phase will examine reliability standards for the gas transmission system to determine if design changes are needed to account for a changing climate and the service capacity of current and future gas system infrastructure.
The second will consider proposals for mitigating the negative effects that “operational issues with gas transmission systems have on wholesale and local gas prices, and gas system and electric grid reliability.”
Phase three will weigh regulatory solutions and strategies the commission should implement “to ensure that, as the demand for natural gas declines, gas utilities maintain safe and reliable gas systems at just and reasonable rates, and with minimal or no stranded costs,” the CPUC said.
The Texas Public Utility Commission last week approved modifications to proposed transmission lines necessary to integrate Lubbock Power & Light load into ERCOT (48909).
The approval came during the PUC’s open meeting Thursday, following a quick sidebar agreement between Oncor and the city of Lubbock over the project’s dividing point. The project will connect a 345-kV Oncor line with a 115-kV switchyard and line being built by LP&L.
Oncor counsel Jaren Taylor (left) and LP&L counsel Lambeth Townsend describe their companies’ agreement.
Oncor’s portion of the project could cost as much as $84 million and LP&L’s portion $61.5 million. The municipality is on the hook for $30.2 million in switchyard costs.
The project is one of several needed to move 470 MW of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)
In other actions, the PUC:
approved Entergy’s request to amend its transmission cost recovery factor and recover $19.4 million (49874).
was notified by Commissioner Arthur D’Andrea that he has directed outside counsel to intervene in a MISO docket at FERC related to the treatment of energy storage facilities as transmission assets (ER20-588). (See Despite Pushback, MISO Pursuing TO-only SATA.)
The effort to prevent utility equipment from causing disasters was a major reason the California Public Utilities Commission decided Thursday to extend the general rate case cycle for the state’s investor-owned utilities from three years to four.
After the 2010 San Bruno gas pipeline explosion and years of catastrophic wildfires starting in 2007, the commission opened its general rate case (GRC) rulemaking in 2013 “out of concern that the energy utilities were not explicitly or adequately addressing safety and reliability issues in their GRC funding requests.”
In December 2014, the commission added a Risk Assessment Mitigation Phase and the related Safety Model Assessment Proceeding to the IOUs’ rate cases. The protocols require IOUs to examine the risks they face and propose strategies to mitigate those risks, which the commissioners must then approve. (See CPUC Adds RAMP Costs to Rate Case for 1st Time.)
| California governor’s office
In its latest decision, the commission said moving to a four-year GRC cycle would bolster disaster-prevention efforts.
“The longer cycle will allow the utilities and stakeholders to dedicate more time to implementing the new risk-mitigation and accountability structures that this commission established earlier in this rulemaking, and less time litigating GRC applications,” it said.
The longer cycle also will let the commission monitor “utility spending in something closer to real time, especially when the utility decides to reprioritize authorized funding for another purpose.”
With circumstances changing quickly because of wildfires, utilities have had to redirect money to fire prevention efforts such as tree trimming, line inspections and repairs. (See California Regulators OK Utility Wildfire Plans.)
In addition, the commission said it hoped the four-year cycle would improve efficiency in the GRC process, which can be delay-prone, by providing more time to work through difficulties.
“General rate cases are the bread and butter of what we do,” Commissioner Clifford Rechtschaffen said at Thursday’s meeting. “They’re very complex, very time consuming,” and at least one rate case is always pending, he said.
In a GRC, the commission authorizes a utility to recover capital investments and annual operations and maintenance expenses through rates charged to customers. Fundamental principles include balancing the needs of investors and ratepayers and providing safe and reliable service at a reasonable cost.
The commission’s unanimous decision said the “task we face is how to adhere to these principles in a world where — as all stakeholders can surely agree — events are moving much more quickly than can be accommodated by the existing GRC process.”
“In such circumstances, the importance of commission oversight in the midst of a utility’s GRC cycle increases,” it said. “It is no longer sufficient for the commission to authorize a multiyear GRC revenue requirement for the utility and then sit back and wait for the utility and intervenors to report back three years later regarding whether the utility spent the authorized amounts, for specifically authorized purposes, or found it necessary to use the funds elsewhere.”
The move to a four-year cycle was supported by two of the state’s large IOUs, Pacific Gas and Electric and San Diego Gas & Electric, and by the commission’s Public Advocates Office.
PG&E said the four-year cycle would allow for adjustments to the revenue requirement to address unusual circumstances and give the commission more time to weigh “the extraordinary amount of evidence” in GRCs.
CPUC staff, Southern California Edison, the state’s second largest IOU, and The Utility Reform Network, a consumer advocacy group, objected to the move.
Staff expressed concerns about switching to a four-year cycle, citing potential problems such as increased uncertainty about forecasted expenditures in the additional fourth year.
SCE did not oppose a four-year cycle outright but said it worried the longer cycle would lead to shortfalls in authorized spending. It asked for “greater tolerance on the part of the commission and parties with respect to errors and variances in forecasting.”
The new four-year cycle and other provisions incorporated into the order take effect June 30. A series of workshops to deal with implementing the changes and increasing efficiency in the GRC process will take place over the next year, the commission said.
