FERC last week dismissed a second round of complaints over overlapping pseudo-tie congestion charges between MISO and PJM, rejecting a call that the Midwestern RTO rework its solution and denying rehearing requests over its refund decision.
No MISO Solution Rejection
American Municipal Power had called for a retroactive rejection of the second phase of MISO’s solution to address overlapping congestion charges on pseudo-tied generation, arguing that the RTO failed to prove that all overlapping congestion charges had been resolved (ER19-34-003). The utility also said FERC’s acceptance of PJM’s second-phase solution was conditioned on an expectation that MISO would also develop a voluntary schedule-cutting mechanism like its eastern neighbor.
The RTOs in 2018 agreed to first make limited software changes to account for pseudo-tie transactions in their respective day-ahead markets, then filed separate second-phase solutions to eliminate double-charging. While PJM now provides rebates for deviations from day-ahead commitments and created a new transaction type to hedge exposure to financial risk, MISO added pseudo-tie transaction interchange schedules so pseudo-tied resources can use the day-ahead market to hedge against real-time congestion. (See FERC Approves MISO Pseudo-tie Proposal.)
Contrary to AMP’s claims, pseudo-tie double-charging has been wiped out, FERC said in its order Thursday.
The commission’s decision relied on reports from the RTOs. It said AMP failed to point out any specific Tariff changes in MISO’s second-phase solution that it believed was unreasonable. FERC also said it would not require MISO to restyle its hedging mechanism after PJM’s, noting that several types of hedging mechanisms could be just and reasonable.
The commission also pushed back on AMP’s contention that MISO promised to address any leftover overlap “through rebates or other means” even after the full solution was in place. FERC said neither RTO ever committed in filings to additional rebate mechanisms as part of their second-phase solutions.
FERC also expressed confusion about why AMP was calling for rebates at this point given that PJM now charges or credits congestion where pseudo-tie paths overlap between the RTOs.
The commission in October also rejected a trio of complaints from AMP over how the RTOs eliminated their overlapping congestion charges. The commission said their phased-in pseudo-tie solution did not constitute prohibited “piecemeal” ratemaking. (See MISO-PJM Pseudo-tie Fix Challenges Rejected.)
PJM and MISO footprints | MISO, PJM
No Rehearing of Refund Decision
FERC also batted away several requests to rehear its May decision that ordered settlement proceedings to determine how much the RTOs must remit to address redundant congestion costs incurred from 2016 onward. (See Refund Hearing Ordered in Pseudo-Tie Complaint.)
The complainants — including Tilton Energy, AMP, Northern Illinois Municipal Power Agency and Dynegy — relied on a variety of arguments to seek rehearing.
FERC held firm that MISO didn’t violate its Tariff when it began using its financial schedules for pseudo-tied customers without prior approval. The commission said the RTO had the authority to assess congestion charges “in the absence of an explicit Tariff section that applied to the situation” (EL16-108-001).
The commission additionally found that PJM was not in violation of its Tariff for calculating congestion charges from nodal points inside the MISO footprint. The companies had argued that PJM overstepped its authority by reaching into MISO territory to calculate congestion.
“The fact remains that the PJM Tariff explicitly gives PJM the authority to utilize either the source nodal point or the MISO-PJM interface,” FERC said.
The commission also affirmed that only named complainants are entitled to whatever amount of congestion charge refunds stem from settlement. The Illinois Municipal Electric Agency interceded to argue that refunds should extend to everyone affected by the unjust and unreasonable charge — including itself.
“The commission has held that ‘allowing a third party to join in a complaint by filing comments would circumvent our public notice requirements and deprive the respondent of the opportunity to address the assertions of that third party,’” FERC said.
It also declined to extend its usual 15-month refund period as the companies had requested, saying they did not show that the RTOs were slow to act on complex solutions to the duplicative charges.
The commission repeated its stance that the separate administrative charges MISO and PJM assessed on pseudo-tied generation cannot be considered duplicative.
“By taking transmission service in both RTOs, complainants were causing administrative costs to be incurred by both RTOs,” the commission wrote.
Finally, the commission again denied AMP’s previously failed argument that MISO couldn’t guarantee that its phase two solution fully eliminated the double charging.
NERC has certified SPP’s reliability coordination offering in the Western Interconnection, allowing the RTO to offer those services effective Dec. 3.
| SPP
SPP said the certification, which it received Nov. 15, confirms it has the necessary tools, processes, training, procedures and personnel to operate as a RC in the West. (See “Staff Prepping for 2nd Certification Visit, Shadow Ops,” SPP Western Reliability Briefs: Week of Sept. 16, 2019.)
The RTO has agreements with 13 customers, representing about 12% of the Western Interconnection, which has been managed by Peak Reliability. Peak announced last year it would be going out of business by the end of 2019, opening the door to SPP and CAISO to provide RC services to its previous customers.
SPP has been a NERC-certified RC in the Eastern Interconnection since 1997, managing about 40 GW of load. Its RC service territory now extends from the Canadian border to the Texas Panhandle.
The RTO also plans to open a Western real-time market in 2021 as an alternative to CAISO’s Western Energy Imbalance Market. Five regional organizations are helping fund the market’s development. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
Regulators in Ohio last week denied American Electric Power’s request to recover costs from ratepayers for proposed wind and solar projects totaling 900 MW, saying that PJM’s diverse resource mix already provides enough access to renewable generation.
The Public Utilities Commission of Ohio said in a ruling Thursday that “we are not persuaded that the energy or capacity markets have, in fact, failed, as AEP Ohio asserts” and instead suggested the utility seek state subsidies or solicit competitive bids for the projects.
“Today’s decision is not about any particular generating technology,” PUCO Chairman Sam Randazzo said. “Rather, it is about what must be demonstrated by an electric distribution utility before Ohio law might allow the PUCO to approve the proposed charge. Indeed, Ohio’s ‘customer choice’ framework provides AEP Ohio customers with the individual right to do directly what the proposal would have compelled all such customers to do regardless of their individual preferences.”
AEP last year asked for cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and 400 MW of solar, arguing that the projects would fulfill a growing desire for clean energy, offset the price volatility in PJM associated with fossil fuels and enhance the state’s economy.
Exelon’s Antelope Valley Solar Ranch in the desert near Los Angeles | U.S. Department of Energy
The proceeding was split into two parts, with PUCO first determining the need for the projects before settling on a cost-recovery mechanism. AEP stalled the ruling in September in order to update its arguments to reflect the impacts of the recently passed House Bill 6, which curtails the state’s current renewable portfolio standard and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including AEP’s proposals, in rural areas of the state. (See Ohio Approves Nuke Subsidy.)
Protesters — including the Ohio Consumers’ Counsel, Kroger, Ohio Coal Association, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” The companies further alleged that AEP didn’t need a second revenue stream on top of the money afforded to the projects via HB 6. (See PUCO Delays Ruling on AEP Solar Projects.)
“We note that our conclusion on the question of need is not intended to address the merits of the Willowbrook or Highland [solar] projects, which may provide significant benefits to the region,” the commission wrote. “Nothing in our decision today precludes AEP Ohio (or its affiliates) from investing in the Willowbrook or Highland projects and pursuing the projects’ claimed social and economic benefits through means other than a nonbypassable surcharge.”
FERC on Thursday rejected a pair of complaints from the Louisiana Public Service Commission related to a longtime dispute over how Entergy previously allocated production costs among its operating companies and arranged for pooled use of generation and transmission assets.
In EL01-88-019, FERC cited D.C. Circuit Court of Appeals precedent when it affirmed a previous ruling that declined to compel Entergy to issue refunds in an 18-year old complaint from the PSC over how Entergy handled its rough production cost equalization on its system from 2001 to 2003.
The commission said a refund mechanism would be more trouble than it’s worth to design and not appropriate given how much time has passed. It also noted that its “‘default’ position is to deny refunds in cases in which there is no net over-recovery by the utility.”
Both Entergy and the PSC asked FERC to revisit unresolved issues in the proceeding given the commission’s decision last year that the Federal Power Act prohibits refunds among electric companies of a registered holding company “to the extent that one or more of the electric companies making refunds cannot surcharge its customers or otherwise obtain retroactive cost recovery.”
Grand Gulf Nuclear Station | Entergy
The two-year refund period covered a time when Entergy’s System Agreement required that production costs among its half-dozen operating companies be “roughly equal,” but before implementation of its “bandwidth” solution, which ensured no operating company had production costs more than 11% above or below the system average.
In Thursday’s decision not to compel refunds, FERC cited the same three equity factors that guided the D.C. Circuit’s 2018 affirmation of the commission’s earlier decision not to issue refunds over Entergy’s inclusion of interruptible service in its rate design, including:
a principle that “past decisions made in reliance on the prior cost allocation cannot be revisited”;
the possibility of a disconnect between those who would pay surcharges and those who benefited from the previous cost allocation; and
a “non-trivial risk” that a utility might under-recover refund costs because state regulators might block the utility from collecting surcharges from retail customers under rules against retroactive ratemaking.
“The commission has previously noted that refunds may not be appropriate because system operating decisions cannot be revisited and redone,” FERC said.
FERC provided an example: From 2001 to 2003, Entergy Arkansas had 11 wholesale customers that made up about 14% of its peak load. Today, the utility has just one wholesale customer — which was not a customer 18 years ago — that requires less than 0.001% of its peak load. The commission also said Entergy Arkansas “experienced significant changes to its retail customers since the refund effective period.”
Finally, FERC refused to hear new reasoning for refunds from the PSC, which cited the recent D.C. Circuit decision that found that Entergy’s System Agreement itself — not the Federal Power Act, as the PSC originally thought — was the basis for the “rough equalization” requirement. The state commission said the court’s distinction was another reason to revisit the refund question.
FERC was unpersuaded.
“We find that it is too late in this 17-year-old proceeding for the Louisiana commission to change its theory of the case and raise for the first time a new refund claim,” FERC said. “Because the Louisiana commission has had previous opportunities to raise this claim and has failed to do so until now, the Louisiana commission’s claim is untimely.”
No Opening of Entergy Settlement
In EL19-50, FERC also declined to rehear the PSC’s claim that Entergy Arkansas acted against the 1982 System Agreement when it had Entergy Services make off-system sales to third-party power marketers on its behalf from 2000 to 2005.
The PSC first claimed in 2009 that the sales violated the generation-sharing outlined in the System Agreement, denied customers the benefits of surplus power and was in violation of the “rough equalization of production costs” provision.
In that proceeding, the PSC focused its argument on Entergy Arkansas’ sales of output from the Grand Gulf Nuclear Station from January through September 2000, saying the sales violated the System Agreement’s reimbursement rules for off-system sales and harmed the other Entergy operating companies.
But FERC said Entergy’s 2015 settlement that terminated the System Agreement and resolved all disputes barred the PSC from raising its claims again. The commission pointed out that the PSC was a party to the settlement’s waiver and release provision, which covered Entergy Arkansas.
“We are not persuaded by the Louisiana commission’s repetition of this argument in the instant proceeding and find that, by entering into the 2015 settlement agreement, the Louisiana commission has waived its right to now raise the … claims in the complaint,” FERC said.
LS Power is urging Virginia officials to intervene in Dominion Energy’s solicitation for a new 1,500-MW peaking plant, saying in a letter Thursday that the process stifles competition and profits shareholders at the expense of customers.
“Dominion’s ratepayers should get the benefit of a competitive auction and not have to be burdened with higher costs to benefit Dominion shareholders,” Nathan Hanson, senior vice president at LS Power, said in a statement.
The company urged William F. Stephens, the State Corporation Commission’s director of public utility regulation, and state Attorney General Mark Herring “to suspend the solicitation as it is currently structured, review the requirements and implement changes that will make the process competitive, for the benefit of Virginia consumers.”
Hanson sent the letter on behalf an LS Power limited partnership, which began operation of two 170-MW natural gas peaking plants at the Doswell Energy Center in Hanover County, Va., in May 2018. Dominion published the request for proposals Nov. 6 to help close a projected 4,044-MW capacity gap identified through the company’s integrated resource plan. Dominion said it is committed to building a 485-MW combustion turbine facility in 2022 as part of the solution but now seeks third-party proposals to identify “the most favorable supply-side options for its customers.”
Combined cycle generator at Doswell Energy Center | Fluor
In the RFP, Dominion limits proposals to new resources only with an in-service date that’s no later than June 1, 2024. The company specified units must use fossil fuel generation and would prefer a facility with a minimum runtime of 10 hours to maximize capacity value in PJM’s wholesale market. The company said it will compare all proposals to self-build options before selecting a project — a process Hanson said “all but guarantees” the latter will win out.
“Typically, an RFP is utilized to assure a competitive process that will achieve the lowest cost for the consumer,” he said in the letter. “However, Dominion’s RFP is structured in such a way that it limits competition and will not provide the competitive results that will ensure the consumers in Virginia and not the shareholders of Dominion are the beneficiaries of the process.”
Hanson said the SCC could act as an independent third party to review the RFPs and Dominion’s self-build options. Further, he said, the RFP should include existing resources in PJM’s “oversupplied” market — with some peaking generation coming online in Dominion’s zone just last year — that “are very capable of providing ratepayers with competitive supply into the future.”
Bidders should also be privy to the costs and risk associated with Dominion’s self-build options, as well as reserve the right to pass the risk of environmental law changes onto customers, Hanson said.
“Without the changes described above, it is likely that this uncompetitive process will not provide the results that will ensure the ratepayers of Dominion are receiving the benefits in the form of low rates that a truly competitive process can provide,” Hanson concluded in the letter. “Left in its current form, the supposedly ‘competitive’ process will only ensure that the ratepayers are not receiving the most competitive rates achievable.”
Dominion spokesperson Jeremy Slayton told RTO Insider in an email Monday that the company “is reviewing the letter from LS Power.”
Renewable proponents are calling on MISO to revamp a transmission planning process that they say inhibits the development of renewable generation in the RTO’s western region.
“We have been hearing from our developer members that MISO West is ‘closed for business’ due to the high cost of transmission upgrades needed, and the cliff interconnection customers experienced recently has been foreshadowed in the last two interconnection planning study cycles,” Natalie McIntire, Clean Grid Alliance (CGA) policy consultant, said in an interview with RTO Insider.
The alliance this month issued a “clarion call” for MISO to build more transmission capacity in the area consisting of the Dakotas, Minnesota and Iowa, pointing to the demise of 3,500 MW of proposed wind and solar projects that entered the RTO’s interconnection queue in February 2017.
Development of nearly all of those 27 projects — some of which had power purchase agreements in place — was hindered by transmission upgrades necessary to accommodate interconnection at the cost of tens to hundreds of millions of dollars per project. As of this month, only a 175-MW wind farm and a 45-MW solar facility remain, though McIntire said their fates may be uncertain as well.
“It was a shock to have a whole study cycle of projects in the MISO West region just fall out of the queue,” McIntire said.
A single wind or solar farm cannot be expected to fund transmission lines alone, and the lack of renewable development because of scarce transmission capacity in MISO West will mean communities that were expecting development might not see it, CGA argues.
For example, “the loss of 5,000 MW of renewable energy means losing an estimated $15 million, annually, in landowner payments,” CGA said, calling the situation “a really loud wake-up call.”
CGA also said the failed projects left more than $1 billion worth of production tax credits on the table.
“Without an immediate commitment to addressing the exorbitant cost of interconnecting new projects to the electric grid and a plan to strategically build new transmission lines, wind and solar development will be stalled for the foreseeable future,” CGA said.
‘Perfect Storm’ Thwarted
CGA argues the western MISO footprint should be prepping for a boom.
“The low cost and high demand should be the ingredients for a perfect storm of development, fueling terrific job growth and economic development for rural communities that are all too often struggling to maintain basic services without draining the pocketbooks of its citizens,” the group said.
Instead, CGA contends, a shortage of transmission capacity means millions in lost land leases, community tax revenue and jobs. The group points out that the National Renewable Energy Laboratory estimates that a 100-MW wind project supports 60 to 80 construction jobs and five to seven operations and maintenance jobs.
McIntire said a disconnect exists between MISO interconnection queue studies and those performed under the RTO’s annual Transmission Expansion Plan (MTEP).
“What are the differences between these two study processes that show such different results?” McIntire asked, noting that interconnection studies show the need for high-cost upgrades when MTEP studies do not. She said the MTEP planning process “should at least be modeling” future generation resulting from customer demand and state and utility commitments.
McIntire also questioned why MISO’s reliability and economic planning studies under the annual transmission plan are conducted separately, with needs examined in isolation.
“Planning processes divided into silos driven by economic, reliability and interconnection needs result in smaller projects and abandon big-picture transmission planning that can solve multiple needs more efficiently,” she said, adding that the isolated studies often make for smaller, “piecemeal” transmission solutions.
MISO declined to comment for this story. However, RTO executives on a call of the Board of Directors’ System Planning Committee on Friday said it would take a Tariff filing to close the gap between identifying upgrades for its generation interconnection queue and transmission planning for the purposes of MTEP.
McIntire said CGA supports the direction MISO has taken on its new proposed futures, though they may not be enough.
MISO plans to hold another workshop to discuss its new, renewable-heavy futures proposal on Dec. 5. Last month the RTO released a trio of new planning future scenarios that include Industry-Announced Plans, Advanced Fleet Change 2.0 and Fleet Electrification. (See MISO Sets Course for New Futures.)
“The futures provide much more realistic bookends, which we support, but it’s hard to say whether those set of futures will result in the most efficient plan for all the needs on the system,” McIntire said, calling for more comprehensive transmission planning.
| Madison Gas and Electric
CGA said MISO could benefit from another transmission package akin to its 2011 multi-value portfolio (MVP), which produced 17 projects, and CapX2020’s five-project, 800-mile grid expansion in the Upper Midwest. The 10 Minnesota utilities behind CapX2020 have recently reunited for a CapX2050 study to identify transmission needs in Minnesota, eastern North Dakota and South Dakota, and western Wisconsin. (See Minnesota Utilities Reunite for CapX2050 Study.)
CGA argues that the MVP and CapX2020 have already “reached maximum capacity,” although the lines have been “enormously successful at enabling development and delivery” of renewable energy.
McIntire said a future transmission buildout doesn’t necessarily have to take the form of another MVP, but that MISO needs a “comprehensive long-term transmission process.”
“This whole process takes such a long time, and they’re behind. They really needed to start this three to five years ago,” she said.
According to McIntire, a 10-year lead time before anticipated in-service dates is ideal. “The planning process requires a few years; then it takes at least a few years for permitting and siting and construction,” she said.
She foresees a stalled MISO West with little renewable development over the next decade unless something changes.
“This is possibly just the beginning as similar situations to the recent interconnection request fallout may start to happen in other areas across the footprint. The region must start planning for what needs to be built next,” she said.
Don’t Wait on Load
McIntire acknowledges there isn’t much load growth in the region but said electric vehicle adoption may change the demand picture.
But growth predictions aren’t a justification for inaction, she said.
“It’s a question of the resource choices that consumers, states and utilities want to make.”
She said new, renewable generation can come online — not only to meet load growth — but to replace retiring thermal generation. These new resources can be the lower-cost option, even considering the costs of transmission construction to customers.
“When you’re building transmission to new generation, it can still be beneficial to consumers. If the overall cost of the generation is going down, there can still be a net benefit.”
McIntire also pointed out that there are costs associated with maintaining the lines and poles of increasingly aging infrastructure.
“We don’t just want to build transmission for transmission’s sake. We want to work with MISO and its transmission owners to help plan efficient transmission upgrades to meet a variety of needs,” she said.
SAN ANTONIO — The National Association of Regulatory Utility Commissioners held its 131st Annual Meeting and Education Conference last week, bringing state and national utility regulators, federal and state policymakers, industry representatives, consumer advocates and other stakeholders to south-central Texas.
Here is some of what we heard during the four-day event.
A ‘Fabulous’ Leftover
Texas Public Utility Commission Chair DeAnn Walker moderated the leadoff panel, which discussed the changes facing competitive markets and the cost and potential benefits of restructuring.
Independent consultant Alison Silverstein said markets have become more complicated since they were created to balance supply and demand through competition. So much so, she said, that she lamented being unable to find clip art for her presentation to illustrate her point: that of an elephant standing on a stool and juggling a chainsaw, flaming batons and a flowerpot.
“A lot of things have changed: falling prices; older baseload generation retiring; little demand growth,” Silverstein said. “All of these things are incredibly complicated. Competition works, but the current market design is not working well. We need market changes for the next 20-plus years to deal with high decarbonization, variability and uncertainty.”
Silverstein listed the four factors of market design:
What competes in the market?
What are the market rules for ancillary service, dispatch and price calculations?
Who buys — and how much — in the spot market vs. self-supply or bilateral contracts?
What is the missing money mechanism (i.e., capacity payments or an operating reserve demand curve)?
Asked by Walker what regulators should focus on, Silverstein pointed to the markets’ ease of entry and exit.
“You don’t want old, expensive resources cluttering up your market,” she said. “Focus on energy efficiency, because your customers need as much energy efficiency as possible. Changes in technology and economics have changed completely what resources are available, and changes in society have changed what customers are willing to put up with.
“We need a lot of market changes to deal with uncertainty and variability,” Silverstein said. “Just because you’re in charge of market prices, don’t think those are the only dials that matter. There’s an awful lot of stuff going on that can screw up the best markets.”
Mason Emnett, Exelon’s vice president of competitive markets, said capacity markets “are not working out” in some portions of the country and suggested the answer could be regional resource adequacy.
“I think there’s a possibility, a hope, that the regions with capacity markets could evolve into something that is optimized over a larger footprint,” Emnett said. “We have hope that regional adequacy markets can evolve, but we’re not holding our breath. Those types of changes take years to develop.”
“When he talks about resource adequacy, that’s a fabulous leftover from the generation-centric days,” Silverstein said.
“You don’t have to have a sky-high resource margin or a resource adequacy construct in order to keep the lights on. That proves the fact that markets do work,” Silverstein said.
“Don’t let anyone say a 7.4% reserve margin doesn’t make you sit on the edge of your seat every day. It does,” Walker said in agreeing with Silverstein. “Generators have to come to the table to be on and produce during those [low-resource] days, but we had a huge impact from demand response. When prices hit $9,000, [industrial] loads come off. That’s something we’re learning.”
Glick Concerned with FERC Nominating Process
FERC Commissioner Richard Glick, the only federal commissioner to show up at NARUC and the only Democrat on the soon-to-be-four-person panel, shared his concerns over the agency’s nomination process during a “Nick & Glick” Q&A session with outgoing NARUC President Nick Wagner.
Glick said he has issues with the process, in large part because the tradition of pairing nominees for two or more vacancies was ignored with the recent nomination of General Counsel James Danly to fill one of two vacancies on the commission. (See FERC General Counsel Tapped for Commission.)
He said changes to the Senate’s filibuster rules have made it difficult for Democrats to have any say in the matter. Former Commissioner Cheryl LaFleur’s Democratic seat has been vacant since she left in August. Republicans will enjoy a 3-1 majority when Danly joins the commission.
“What does it say the next time a Democratic president and a Democratic Senate don’t pick any Republican nominees?” Glick said. “That was not the way the process was designed. I hope we can go back to a more normal process.”
Glick also hopes for a return to the days when FERC operated in a more bipartisan manner. He said a couple of protesters of FERC’s recent pipeline approvals showed up at his house on Halloween, unnerving his 10-year-old son.
“We have our share of protesters … but going to someone’s house? That’s beyond the pale,” Glick said.
Asked by Wagner about the relationship between state regulators and FERC, Glick said that low gas prices have resulted in additional zero-marginal-cost resources beyond renewables and “more contentious” markets.
“No doubt, state policies impact the wholesale markets, and that was true the day they invented energy policy in general,” he said. “The more traditional generators are essentially insisting those continued subsidies are depressing the markets. But [fossil fuel] technologies have been subsidized for a long time. If we only recognize the more recent subsidies, particularly renewables and nuclear, we are being short-sighted. Over the long term, these other subsidies have a long-term effect over the markets.”
Glick also recounted how he became a FERC commissioner. At the time, he was a staff member for U.S. Sen. Maria Cantwell (D-Wash.), and he recalled telling her that if a FERC position came open, “sure,” he would be interested.
“Sometimes we’re in the wrong place at the wrong time,” Wagner cracked.
New President: Remember the Customer
Newly installed NARUC President Brandon Presley — yes, he’s related to Elvis, a fellow Mississippian — showed off his public speaking chops with a stem-winder of an acceptance speech that highlighted his theme for the upcoming year: “Bridging the Divide.”
“At the end of the day, you serve the people of this country in all 50 states and [the] territories,” Presley said, encouraging his fellow commissioners and regulatory staff to avoid the use of the term “ratepayer.”
“They’re a customer. A person. We’ve got to keep that in the forefront of our minds,” he said. “Many challenges exist for the least; the last; the left out; those people who are marginalized in our society. We have the biggest impact on their lives because we affect the cost of living for those people and those businesses. We have to keep this organization focused like a laser on the customer.”
To that end, Presley said he plans to appoint a task force to look at how best to bring broadband service to rural communities, such as those in the northeastern portion of Mississippi that he represents. He said his goals include identifying and closing other gaps that impede regulators and industry from better representing the public interest.
“We know that gulf exists. We know the brain drain in rural America is real,” Presley said. “We’ve got to find a way as a national association to solve this problem. I hope in the next year, we can be progressive; we can be alert and on the lookout for opportunities to make real, impacting decisions and policies that translate back to the people.
“There’s no greater satisfaction in life than knowing that you left something better than you found it,” he said.
Presley was first elected to the Mississippi Public Service Commission in 2007, winning re-election in 2011, 2015 and 2019. He served as mayor of his hometown of Nettleton from 2001 to 2007, being elected at the age of 23. Presley is a member of MISO’s Advisory Committee.
Joining Presley as NARUC officers are First Vice President Paul Kjellander, with the Idaho Public Utilities Commission, and Second Vice President Judith Jagdmann, chair of the Virginia State Corporation Commission.
On Friday, Presley added to the Executive Committee by naming North Carolina Utilities Commissioner ToNola Brown-Bland as treasurer and Arkansas Public Service Commissioner Kim O’Guinn as one of two appointed members.
Brown-Bland was appointed to the NCUC in 2009 and reappointed in 2017. O’Guinn was appointed to the PSC in 2016.
State Commissioners Evaluate PURPA NOPR
“At long last, it is finally here — the PURPA NOPR!”
That invitation to a panel discussion on FERC’s Notice of Proposed Rulemaking for changes to the 41-year-old Public Utility Regulatory Policies Act did the trick. An overflow audience overwhelmed the seating, grabbing empty spaces on the floor to listen to regulators and consumer advocates discuss the potential changes to rate-setting and which markets qualify for an exemption from PURPA’s “mandatory purchase obligation.” (See FERC to Reshape PURPA Rules.)
FERC’s proposed top-to-bottom changes include the elimination of a fundamental principle of the rules: fixed-price contracts at an “avoided-cost” rate for qualifying facilities. Utilities and state commissions have been among those complaining about PURPA, though most ISO/RTO members are exempt from the rule.
“PURPA has given me more grey hairs per policy than most I’ve worked on,” said Megan Decker, chair of the Oregon Public Utility Commission. Noting FERC declined to extend a deadline for comments on the NOPR, Decker said, “I hope that denial does not reflect FERC’s intention to not engage with a number of compromise solutions put forward. We don’t want continued uncertainty.”
“Idaho has a pretty tormented history with PURPA,” PUC Commissioner Kristine Raper said. “The NOPR was very responsive to the technical hearing. They clearly discounted cogeneration in the NOPR, and they looked at things like cost. These are all the things Idaho has tried to bring to the attention of FERC. FERC has narrowed the way states can interpret those rules.”
“The PURPA NOPR does a terrible job of distinguishing between competitive markets and those regions that don’t have wholesale competition,” said Katherine Gensler, vice president for the Solar Energy Industries Association. “PURPA’s structure is basically a balancing act between telling utilities to purchase a product and sellers that have to accept the price. Utilities have to buy a product they often claim they don’t want, and the seller has to accept the price published by the utility commissioners. This NOPR shifts that balance … moving away from the developers’ rights to give greater authority and power to the utility state commissions.”
Former FERC Commissioner Philip Moeller, now executive vice president of regulatory affairs for the Edison Electric Institute, argued that the NOPR would give states additional flexibility in approving QFs.
“This is about cost. Who’s paying? Are your constituents, your customers, overpaying for the projects? Most people think that’s a bad thing, unless you’re the one getting overpaid.”
FERC Commissioner Glick, who dissented against the NOPR, said what “perturbed” him the most was that the first 50 pages describe PURPA as no longer being a necessary statute.
“You can make a reasonable argument that that’s the case … but it’s our duty to administer [PURPA] and carry it out,” Glick said. “Congress has told us we need to facilitate small power production. To the extent a utility has a procurement practice or a market setup that allows all entrants to fully participate, you can get out of the PURPA requirements. If everyone has access to the procurement process, that seems to be best for users and consistent with Congress’ intent.”
Gold Still Sees Place for Renewables
Wall Street Journal reporter Russell Gold, whose “Superpower: One Man’s Quest to Transform American Energy” details Mike Skelly’s failed attempt to use HVDC lines to ship renewable energy across the country, called for changes to the current regulatory system “because of what’s coming.” (See Book on Tx Developer Transmits Climate Hope.)
He noted ERCOT has 22 GW of wind energy and 2 GW of solar — “[Solar] used to be fine if you wanted to warm water,” Gold said, referring to the efficiency advances for solar resources — and that the numbers will only increase as technology continues to improve and renewable energy prices stay low.
“There’s no blackouts and no one’s panicking,” Gold said. “Coal and nuclear are having trouble competing. Natural gas is soon going to have problems competing. The question for utilities and utility regulators is how long do you want to hold on to a coal plant that is above market prices? You have the potential for lots of inexpensive renewable electricity.”
But to bring that energy to market, he said, “you need to stitch this country together with HVDC transmission lines.”
In the end, not even the determined Skelly could do that.
“The biggest problem was that it was hard to get [landowners] to accept the sacrifice for the greater good of less carbon and clean power,” Gold said.
Speaking before a friendly audience, Gold couldn’t resist putting in a plug for his book.
“I’ve been told my book does the impossible,” he said. “It turns the regulatory process into a page-turner.”
Reality ‘Sinks in’ for Undoing Mexican Reforms
A two-person panel on the slowing energy reforms in Mexico said reality is “beginning to sink in” for President Andrés Manuel López Obrador’s administration as it marks its first year in power on Dec. 1.
José María Lujambio Irazábal, a partner with Cacheaux Cavazos & Newton in Austin and a former general counsel for Mexican Energy Regulatory Commission, and Peter Nance, managing director for Que Advisors, said AMLO, as he is more commonly known, has made it clear that he will neither expand nor fully implement the energy reforms begun before his 2018 election and may even reverse some of the measures. (See Overheard at GCPA Mexico Power Market Conference.)
“If [Enrique] Peña Nieto proposed something,” Nance said, referring to AMLO’s predecessor, “we’re against it because of those guys.”
Some of the pushback has come from the Federal Electricity Commission (CFE), the state-run monopoly. The latest market reforms, begun in 2015, split up its generation into six different companies in an effort to break up its hold on the market.
“The work was not finished. It was really a matter of resistance from CFE,” Lujambio Irazábal said.
“Some people have long memories and believe in the state and the role of the state in these entities,” Nance said.
CFE’s aging fossil plants have increased operating costs. Faced with an operating reserve margin reportedly as low as 0.7% and a succession of blackouts in the Yucatan Peninsula, the government earlier this year announced plans to build five combined cycle gas-fired plants with an aggregate capacity of 2.76 GW and has made overtures to public-private partnerships.
“In special situations, it might be possible to have private partnerships,” Nance said of the new reality. “You just can’t put five power plants on the balance sheet.”
FERC on Thursday found that CAISO, ISO-NE and MISO had largely complied with Order 841, but it ordered changes to some of the grid operators’ proposed tariff revisions.
With CAISO, FERC found its compliance filing, with “certain modifications,” met the requirements of Order 841, intended to remove barriers to the participation of electric storage resources in organized electric markets (ER19-468). But the commission determined the ISO had not fully complied with the requirement that it prevent electric storage resources from paying both wholesale and retail rates for the same charging energy.
“In other words, we find that CAISO has not proposed a participation model for electric storage resources that fully eliminates the potential for duplicative retail and wholesale billing for charging by electric storage resources that later resell that charging energy back to the wholesale markets,” FERC wrote. “We are requiring CAISO on compliance to modify its Tariff so that it does not charge an electric storage resource wholesale rates for charging energy for which the electric storage resource is already paying retail rates.”
Invenergy’s Grand Ridge Battery Storage Facility in Illinois | BYD
In the case of ISO-NE, FERC determined the RTO’s Tariff revisions hadn’t adequately dealt with “the application of transmission charges to electric storage resources” (ER19-470).
“ISO-NE proposes to exempt electric storage resources from all applicable transmission service charges (i.e., charges for regional network service and local service) when they are dispatched to charge,” the commission said. Order 841, however, required “any electric storage resource that is charging for the purpose of participating in an RTO/ISO market … should be assessed charges consistent with how the RTO/ISO assesses transmission charges to wholesale load under its existing rate structure.”
“ISO-NE does not meet these requirements because its proposal exempts all electric storage resources that are charging for later resale from transmission charges that are applicable to other load,” FERC wrote. “Therefore, we direct ISO-NE to submit on compliance within 60 days of the date of this filing, Tariff revisions that comply with this aspect of Order Nos. 841 and 841-A by applying transmission charges to an electric storage resource.”
FERC also found MISO had mainly complied with Order 841 but rejected its plan to assess transmission charges to electric storage resources dispatched to withdraw energy pursuant to their downward ramping capability (ER19-465).
“We are not persuaded by MISO’s arguments that this dispatch is not providing a service,” FERC said. “Order No. 841 specifies that electric storage resources should not be assessed transmission charges when they are dispatched by an RTO/ISO to provide a service such as frequency regulation or a downward ramping service.”
FERC also granted MISO more time than the other grid operators to implement the order.
“While the commission … declined to provide the RTOs/ISOs with additional time for implementation, we find here that MISO’s request to implement the requirements of Order No. 841 after the deadline established … is reasonable based on the specific circumstances outlined in its filings,” FERC said.
San Diego Gas & Electric’s 30-MW battery energy storage facility in Escondido, Calif. | SDG&E
MISO announced in April that it would seek at least another year to comply with the order, saying the intricacy and expense of incorporating storage into its markets was greater than it originally expected. The RTO is trying to create a new market platform, making compliance with Order 841 by December infeasible, it said. (See More Time Needed for Storage Compliance, MISO Says.)
“We note that MISO’s request to defer the effective date of its compliance filing was not opposed,” FERC said. “Therefore, we grant MISO’s request to defer the effective date of its compliance filing to June 6, 2022.”
McNamee, States Want Opt-out
As he did in the compliance filings of PJM and SPP in October, Commissioner Bernard McNamee issued concurring statements that said the commission “should have, at the very least, provided states the opportunity to opt out of the participation model created by the storage orders.”
McNamee was not on the commission at the time Order 841 was issued but expressed his “continuing concern” that FERC had exceeded its statutory authority by not allowing states to determine whether storage may use distribution facilities to access the wholesale markets.
He also noted that state regulators, utilities and public power groups have asked the D.C. Circuit Court of Appeals to overturn part of the order, challenging the commission’s refusal to allow states to opt out. (See States, Public Power Challenge FERC Storage Rule.)
Order 841, 20 Months Later
FERC first issued Order 841 in February 2018, requiring each RTO/ISO to establish a participation model for storage resources to ensure they are eligible to provide all energy, capacity or ancillary services of which they are capable, while also enabling them to set clearing prices as both a buyer and seller. Grid operators also need to establish a minimum threshold for participation that doesn’t exceed 100 kW.
Order 841 “will enhance competition in these markets and help ensure that they produce just and reasonable rates,” staff told commissioners at the time. (See FERC Rules to Boost Storage Role in Markets.)
FERC, grid operators and stakeholders then had a year to review, revise and implement the plans by Dec. 3.
FERC staff issued deficiency letters to all six RTOs and ISOs in April over their proposed energy storage rules, pressing for definitions, tariff citations and details on issues including metering, make-whole payments and self-scheduling. (See FERC Asks RTOs for more Details on Storage Rules.)
In October, FERC issued its first two orders implementing its rulemaking, mostly accepting PJM’s and SPP’s proposals but also objecting to some aspects. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
For instance, FERC rejected SPP’s proposed provisions related to aggregation of storage resources, because Order 841 did not address aggregation. It gave SPP 60 days to submit a compliance filing removing the provisions.
The commission also established a paper hearing procedure to investigate whether PJM’s 10-hour minimum run-time requirement was unjust and unreasonable as applied to capacity storage resources.
FERC has yet to rule on NYISO’s compliance filing. Speaking to reporters after the commission’s open meeting Thursday, Chair Neil Chatterjee said he was “confident we will move forward with New York ISO when it’s ready.”
FERC last week approved the New York Power Authority’s request for transmission rate incentives for its portion of a new AC transmission line (EL19-88).
The commission approved NYPA’s request for:
recovery of 100% of prudently incurred plant costs if the project is abandoned for reasons outside of the authority’s control (abandoned plant incentive);
inclusion of 100% of construction work in progress (CWIP) in rate base (CWIP incentive); and
a 50-basis-point return on equity for the risks of developing the projects (ROE risk adder).
Segment A will add 350 MW of “Central East” transfer capacity by replacing National Grid’s two existing 80-mile 230-kV transmission lines with a new 86-mile, double-circuit 345-kV line from the Edic substation in Oneida County to the New Scotland 345-kV substations, and adding a new Princetown 345-kV switchyard between them. It is expected to cost $750 million, with NYPA’s share at $281 million.
Segment B will add 900 MW of transfer capacity between upstate and southeast New York. It includes a new double-circuit 345/115-kV line from a new Knickerbocker 345-kV switching station to the existing Pleasant Valley substation, a rebuild of the Churchtown 115-kV switching station, an upgrade of the existing Pleasant Valley 345/115-kV substation and 50% series compensation on the 345-kV Knickerbocker-to-Pleasant Valley line.
The two projects are projected to cost a combined $1.2 billion and provide production cost savings of up to $1.2 billion and $9.6 billion in reduced demand congestion charges over 20 years. The projects also will avoid transmission refurbishment costs of $839 million and provide capacity benefits of approximately $1.9 billion.
The two AC transmission projects are projected to cost $1.2 billion and provide production cost savings of up to $1.2 billion and $9.6 billion in reduced demand congestion charges over 20 years. | NYISO
The projects are expected to be in service in December 2023. In its request, NYPA noted that NYISO requires both to be completed at the same time, and that the failure of one may lead to the abandonment of the other, “thus enlarging the potential for the loss of NYPA’s investment.”
“We find that NYPA has demonstrated that each of the requested incentives that we grant here, and the incentives package as a whole, address the risks and challenges faced by NYPA in undertaking Segment A,” the commission ruled.
The commission in 2015 said it would grant NY Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — the same transmission rate incentives requested by NYPA if NY Transco were selected for any of the AC projects (ER15-572). (See Divided FERC Trims ROE on NY Tx Projects, Orders Hearing.)
FERC last week ordered Ameren Illinois to revise its accounting for some expenses but otherwise rejected the latest round of challenges by Southwestern Electric Cooperative to the utility’s annual formula rate update (ER18-1122).
Southwestern challenged multiple inputs to Ameren’s 2018 formula rate update.
Ameren Illinois linemen | Ameren
The commission ordered Ameren to make a compliance filing within 30 days:
Moving expenses associated with responding to formal challenges before a regulatory body into Account 928 and exclude them from the annual transmission revenue requirements (ATRR), “consistent with” the commission’s rehearing order on Southwestern’s 2017 formal challenge (ER17-1198-002). (See Challenge to Ameren Illinois Rate Rejected Again.)
Moving any expenses related to donations for charitable, social or community welfare programs from Account 566 to Account 426.1 (Donations), which is not included as an input to formula rate. The commission said it could not determine whether Ameren appropriately recorded only transmission-related expenses to Account 566. “To the extent Ameren Illinois is including donations for charitable, social or community welfare purposes as part of its contribution and membership expenses, we require Ameren Illinois to report the specific items and amounts as part of the compliance filing and also remove them and account for this removal in its next true-up,” the commission said.
Eliminate costs of association membership fees associated with lobbying activities from accounts included in the ATRR.
