FERC last week approved GridLiance High Plains’ sale of controversial Missouri transmission assets to the nonprofit Missouri Joint Municipal Electric Utility Commission (MJMEUC) (EC22-24).
The commission ruled Thursday that GridLiance’s deal for a 4-mile, 161-kV line, four small 69-kV lines and terminal equipment is in the public interest. The transaction marks MJMEUC’s first foray into transmission ownership; it already owns generation in MISO and SPP.
GridLiance purchased the transmission facilities from the city of Nixa, Mo., in 2018 and placed them under SPP’s control. The transmission-only utility has been involved in an unresolved dispute with the RTO and some of its members over the facilities’ inclusion into one of SPP’s transmission pricing zones. GridLiance’s annual transmission revenue requirement for the facilities has raised costs for the zone’s other transmission customers. (See FERC Remands GridLiance ATRR Settlement.)
FERC considered ongoing disagreement as out of scope, sticking to narrow, predefined criteria to approve the sale. It said the sale will not adversely affect transmission rates, though MJMEUC said it will recover the assets’ net book value through its ATRR. The commission noted that ownership is changing hands from a for-profit business to a not-for-profit utility, which comes with a different capital structure, tax obligation and return on equity.
GridLiance estimated that MJMEUC’s ATRR is about 32% lower than its own because of the latter’s nonprofit status. The TO said the commission has lower administrative expenses and does not pay property or income taxes, thus enjoying a lower cost of debt.
FERC said the transaction won’t disturb competition, state or federal regulation, or wholesale power rates because the sale does not involve the transfer of generation facilities.
Nearby city utilities in Missouri and Arkansas involved in the SPP transmission pricing dispute — Paragould Light Water & Cable, Paragould Light Commission, Poplar Bluff Municipal Utilities, Kennett Board of Public Works, City of Piggott Municipal Light Water and Sewer, and the City of Malden — asked FERC not to presuppose that the transmission facilities will continue to be included in the zonal cost allocation.
The commission declined to address the request, explaining its order focused on the transaction and not the facilities’ rate treatment.
MISO and SPP said Friday they plan to ditch their current affected systems study process for more interregional transmission analyses like their joint targeted interconnection queue (JTIQ) transmission effort.
The RTOs announced the transition to more transmission planning at the seams to allow generation interconnections during a conference call Friday.
“Essentially, we’re proposing a framework … whereby we believe the JTIQ and subsequent studies could serve as a replacement for the affected system studies,” SPP Director of Seams and Tariff Services David Kelley told stakeholders.
Kelley said for the current $1.65 billion JTIQ portfolio and other transmission studies to replace affected system studies, the new studies should occur at least every two years. He also said the grid operators’ proposal is proactive when considering FERC’s advanced notice of proposed rulemaking to improve transmission planning, cost allocation and generator interconnections (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“We’ve been listening to stakeholders over the last several months,” Kelley said. “MISO and SPP have reflected on these comments and concerns. … The affected system study process (AFS) is problematic, even from our perspective of administering these studies.”
Kelley said MISO and SPP have come to regard the AFS process as “a separate layer of inefficiency.”
“We need to design a more optimized transmission system around these seams,” he said.
While conducting the JTIQ study, Kelley said, MISO and SPP have noticed several similarities to the AFS: they detect the same constraints, seek to bring more generation online through transmission construction and dole out cost assignments for system upgrades to interconnecting generation.
The RTOs are attempting to distribute JTIQ portfolio costs based on the projects’ beneficiaries, including their respective loads, and a share to interconnection customers on either side of the seam whose generation will flow between the footprints. They have also said they might assign costs based on added benefits like increased flows or more economic dispatch. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)
The grid operators have kicked around using a per-megawatt charge to allocate costs based on the interconnecting generation distribution factor’s effect on the JTIQ portfolio.
MISO and SPP intend to replace the AFS’ upgrade costs with the predetermined cost per megawatt
Kelley said, “more generation can afford to interconnect” under the new flat fee because it “eliminates unknown cost exposure from other RTOs.”
SPP’s Neil Robertson said the RTOs will determine the per megawatt charge for new generation based on the first JTIQ portfolio and refresh the amount in subsequent interregional transmission planning cycles.
“I just don’t want to see a situation where the charge escalates until load ends up holding the bag,” Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, said of the fluctuating charge.
Stakeholders appeared to approve replacing the AFS, even though the RTO staffs admitted they still must work through several details.
“At a high level, I think this is a good step … and needs to happen to produce higher levels of certainty early on at the beginning of the process instead of the end,” Advanced Power Alliance’s Steve Gaw said.
“It’s a creative proposal, and I think it has the potential to introduce more timing certainty and cost certainty,” Clean Grid Alliance’s Natalie McIntire said.
But multiple stakeholders pointed out that the JTIQ study and cost-allocation design remains untested and unproven.
EDF Renewables’ Arash Ghodsian said he is worried that MISO and SPP might not be able to adhere to a biennial schedule.
“It is concerning that MISO and SPP spent two years evaluating this portfolio,” Ghodsian said.
Robertson said the RTOs envision the JTIQ becoming “a more enduring process” that’s conducted on a regular basis.
Under the proposal, the grid operators said they will likely create a “JTIQ affected system zone,” where they identify new transmission facilities near their seams that are likely to be impacted by their neighbor’s generation-interconnection requests. Nearby interconnecting generators will be assigned the per-megawatt charge based on their zonal impact. Staff said the zonal charge will be adjusted prospectively based on successive JTIQ studies.
Gaw said assigning costs to generators based on their zone seems like “rough justice.”
Kelley said the zonal method would eliminate individual developers depending on other higher-queued interconnection customers’ upgrades to get their own projects online.
Rafik Halim of National Grid Renewables asked how the RTOs will transition existing projects working their way through the respective queues to the new JTIQ charge. He said he was particularly concerned about the projects cycles that entered the MISO queue in 2018 and 2019 and have yet to receive AFS results from SPP.
“We have projects that are effectively being held hostage by an affected system study process,” he said.
Kelley said MISO and SPP have yet to work through a transition plan, but he said they will continue processing their queues until the new system can take effect.
“What MISO and SPP can’t afford to do is to put on hold any of our current study processes,” Kelley said.
The RTOs promised more meetings on the proposal beginning next month.
MISO Director of Resource Utilization Andy Witmeier asked stakeholders to provide their input on the proposal
“We want to really see if this new avenue is worthwhile,” he said.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Stakeholders will be asked to endorse proposed revisions to Manual 3: Transmission Operations resulting from a periodic review. The changes include updating stability limitation process language in accordance with FERC docket ER21-1802 and aligning language with the current TO/TOP matrix language.
D. Members will be asked to endorse proposed revisions to Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing an effective load-carrying capability model run timing update. PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, but current manual language has an expiration date of March 1 for voluntary submissions. The quick fix would remove the March 1 expiration date.
E. Stakeholders will be asked to endorse proposed revisions to Manual 36: System Restoration resulting from a periodic review. The minor changes include replacing System Restoration Coordinators Subcommittee with System Operations Subcommittee and updating the under-frequency load shed table with new data.
Endorsements (9:10-10:20)
1. Start-up Cost Offer Development (9:10-9:30)
The committee will be asked to endorse a revised PJM/Independent Market Monitor proposal addressing start-up cost offer development worked on through the Cost Development Subcommittee, including revisions to the tariff, Operating Agreement and Manual 15: Cost Development Guidelines. Stakeholders endorsed the proposal at the Market Implementation Committee’s meeting April 13. (See “Start-up Cost Offer Development Endorsed,” PJM MIC Briefs: April 13, 2022.)
3. Application of Designated Entity Agreement (9:50-10:20)
Stakeholders will be asked to endorse a proposed solution and corresponding OA revisions addressing the application of the designated entity agreement. FERC rejected a filing in February by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights. (See FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000.)
FERC last week approved MISO’s separate-but-equal postage stamp rate divided between its Midwest and South footprints for some of its major transmission buildout. The Thursday order gives MISO a clear-cut cost allocation for its long-range transmission plan’s (LRTP) first two cycles of projects (ER22-995).
The 100% postage stamp-to-load rate will be used to divide costs on MISO’s $10 billion long-range transmission package, the first of four portfolios the RTO plans to recommend. (See MISO Updates Stakeholders on $10B Long-range Tx Package.)
MISO will limit cost sharing on the first half of its LRTP projects to MISO Midwest, where the projects will be physically located, thus shielding its southern states from the transmission costs. The grid operator has said the allocation design is temporary and that it will seek approval for a new cost-allocation design when it begins studying transmission needs in MISO South and increasing its Midwest-to-North transfer constraint in a few years. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)
FERC said that MISO’s proposal to limit regional cost assignments is fair because it follows the commission’s cost-causation principles that benefits be roughly commensurate with allocation. The agency cited a Brattle Group analysis commissioned by MISO that showed the benefits of Midwestern transmission projects would be overwhelmingly confined to the Midwest unless the RTO secures more transfer capability between the subregions. (See MISO Finalizes Long-range Tx Cost Sharing Plan.)
The design “appropriately reflects the transfer limits between the Midwest subregion and the South subregion,” the commission said.
FERC also noted that MISO replicated its established cost allocation from its 2011 Multi-Value Projects to divvy up long-range transmission costs.
MISO’s clean energy organizations called the allocation design a “prudent interim solution to the transfer limits.” However, industrial customers argued that the RTO didn’t present enough evidence that it will allocate costs commensurate with benefits. They also derided MISO’s method of analyzing the first cycle of transmission projects as a portfolio instead of individually and said applying a uniform postage-stamp-to-load rate is clumsy because project benefits fluctuate over time.
The Mississippi Public Service Commission agreed with separating the Midwest from the South but asked that FERC not consider the postage stamp rate as the default method when MISO begins prescribing projects for its South region. The PSC said it would protest the rate as not specific enough if it were applied to Southern projects.
FERC disagreed and said the postage stamp is an appropriate allocation tool. The commission quoted itself from Order 1000 and reminded industrial customers and the PSC that a postage stamp method is “appropriate where all customers within a specified transmission planning region are found to benefit from the use or availability of a transmission facility or class or group of transmission facilities, especially if the distribution of benefits associated [therewith] is likely to vary considerably over the long depreciation life of the transmission facilities amid changing power flows, fuel prices, population patterns and local economic considerations.”
The commission also reminded Mississippi that the postage stamp rate is already the default allocation style under MISO’s past Multi-Value Projects, even though that portfolio predated MISO South’s integration and none of those project costs were ever assigned to the South. FERC said it considered the PSC’s ask a collateral attack on its past rulings.
FERC pointed out that the U.S. Seventh Circuit Court of Appeals has held that FERC “need not ‘calculate benefits to the last penny, or for that matter to the last million or ten million or perhaps hundred million dollars,’ but rather must have ‘an articulable and plausible reason to believe that the benefits are at least roughly commensurate with’ the allocation of the costs.”
The commission also blessed MISO’s portfolio approach to the LRTP and again referenced itself, this time quoting from its acceptance of the RTO’s portfolio style for its 2011 Multi-Value Projects.
“The portfolio approach will help [MISO] to prioritize its transmission expansion projects in such a way as to ensure global benefits from the projects afforded regional cost sharing and maximize the number of system users who will share in those benefits,” the commission said.
FERC also dismissed as premature some stakeholders’ concerns that MISO would design a different and more favorable cost allocation for the South, thus violating FERC’s cost allocation principle that inconsistent allocations must not be applied to the same class of projects. The commission said that was speculation because MISO has yet to develop the cost allocation it plans to apply for projects concerning MISO South.
Christie’s Cautious Concurrence
Commissioner Mark Christie wrote separately to concur with the order, hinting that MISO may not be doing enough to ensure thorough cost allocation.
“In a large, geographically sprawling transmission entity — MISO stretches from the Gulf of Mexico to Canada — it simply makes sense to allow for more granular cost allocation arrangements that may be subregional rather than imposing an identical cost allocation framework across the entirety of MISO,” Christie wrote.
However, he expressed misgivings with the “pure socialization” of the postage stamp rate and said he hoped MISO and stakeholders could arrive at a more granular allocation for the second half of the long-range transmission effort.
“While MISO’s case for postage stamp cost allocation is weak, I do not believe there has been a showing that this method is unjust and unreasonable,” he said, adding that he was ultimately swayed by the Organization of MISO States’ support of the allocation’s design.
Christie said he is concerned that Brattle’s benefits spread analysis rested on MISO’s internal benefit evaluation of its Multi-Value Project portfolio, and not an outsider’s view of the projects’ benefits. The Brattle Group’s Johannes Pfeifenberger “apparently accept[ed] the benefit-cost ratios in MISO’s 2017 report as self-proving,” Christie said.
He added that the Brattle Group should not accept MISO’s benefit claims “on faith,” especially when billions of dollars are at stake.
“There is nothing in the record to indicate whether MISO’s 2017 analysis was ever introduced into evidence in a rate case or other formal proceeding; whether discovery by other parties ever took place to glean information about the methods, bases and benefit calculations of the 2017 analysis; whether it was ever sponsored by a witness who had to take the stand and be cross-examined on the report by lawyers who knew how to conduct cross; or whether other parties had the opportunity to put their own expert witnesses, friendly and hostile, on the stand who could testify about the MISO analysis,” Christie wrote. “Indeed, ideally, a third-party report without a witness who can authenticate it and be cross-examined on it would not even be admitted as evidence in any serious evidentiary proceeding … the evidence in support of assigning billions of dollars in new costs to consumers should certainly get the same scrutiny as in a routine rate case involving far lower amounts of costs.”
Christie urged “state regulators and all affected stakeholders throughout MISO, especially those representing both residential and industrial consumers, to scrutinize very closely the planning criteria and cost allocation for future [long-range portfolio cycles] as well as claims of projected benefits used to justify regional cost allocation proposals because billions of dollars of consumer costs will be allocated here.”
Former ERCOT CEO Bob Kahn on Wednesday said he hopes Texas regulators and lawmakers continue to focus on reliability as they move ahead with changes to the state’s power market.
Addressing the Texas Reliability Entity Board of Directors’ quarterly meeting, Kahn said the market is working well and that suggestions for a capacity market — a verboten concept in Texas — or even a capacity-light market would do little to help reliability.
“I don’t know how much it might increase reliability, but I think it would increase costs for ratepayers,” he said. “That’s a big concern for the commission and all of us who want to keep rates as low as possible. We just need to make sure there’s enough money out there for the generators.”
Kahn noted that ERCOT’s energy-only market is dependent on high prices during scarcity periods, the theory being that those prices will compensate generators that are running and incent more to be build. However, the Public Utility Commission last year dropped the $9,000/MWh cap to $5,000/MWh when prices stayed at their limit for more than four days during the winter storm. ERCOT’s conservative operations approach, in which it procures more reserves than it previously had, has also reduced scarcity.
“The more reserves you have, the more it impacts scarcity. Generators are counting on those few hours a year,” Kahn said. He also argued that operating reserves are suppressing market prices, an opinion shared by others in the market.
Kahn, who served as ERCOT’s CEO for almost two and a half years (2007-2009) and was a director on the grid operator’s early Board of Directors (2002-2006), was involved in the energy-only market’s construct from the very beginning. He recalled a market-design meeting in the 1990s that was crashed by Texas Lt. Gov. Bob Bullock.
“He said five words: ‘This is all about money.’ He was right.” said Kahn, now general manager of Texas Municipal Power Agency, a nonprofit owned by its four-member cities of Bryan, Denton, Garland and Greenville.
Staff in ‘Shields-up’ Posture
Texas RE CEO Jim Albright said the organization is maintaining a “shields up” philosophy against cyber threats, and he encouraged the industry to do the same.
“Given what’s going on overseas and the uptick in ransomware across the world, as tensions get high, we should be on high alert,” he said. “The major alerts coming out this year are from Russian state sponsored cyber threats. So obviously, given what’s happening overseas, there’s been an uptick.”
Albright said the federal Cybersecurity and Infrastructure Security Agency’s cyber alerts this year are on pace to pass last year’s. Seven of those have come out of Russia, he said.
“There’s a lot of ransomware and a lot of malware. … They’re exploiting basically vulnerabilities,” Albright said. “Some of the big ransomware, the big players, if you will … started back in 2017, and we’re still seeing these type of things in the United States.”
Registered Entities up to 289
Staff told the directors that Texas RE has added 38 registered entities since 2020. It now has 289 registered entities in 516 functions. (Entities can register in any of six functions.)
The board approved its 2023 business plan and budget and a clean audit of its financial statements. The budget, up 3.3% to $17.7 million from 2022’s $17.2 million budget, will be sent to FERC and NERC in June. Texas RE’s statutory assessment in 2023 will be $17.2 million, a 14.3% increase from the 2022 assessment of $15 million.
The RE’s 2022 workplan has five focus areas:
expand a risk-based focus in standards, compliance monitoring and enforcement programs;
assess and accelerate steps to mitigate known and emerging risk to reliability and security;
build a strong Electricity Information Sharing and Analysis Center-based security capability;
strengthen engagement across North America’s reliability and security ecosystem; and
promote effectiveness, efficiency and continuous improvement.
Midwest Reliability Organization’s annual reliability conference last week emphasized the inevitability of the transition to clean energy and avoiding future supply shortfalls with more generation and transmission.
“I don’t have to tell you that we’re seeing a transition in the resource mix,” Mark Lauby, NERC senior vice president and chief engineer, told conference attendees Wednesday.
Lauby said it’s not that today’s fuels are “inherently less secure,” but they are more uncertain. He said reliability should extend beyond the one day in 10-year standard to more multidimensional rules of thumb. He also said he “very forcefully believes” that the country is going to need more transmission projects, although they may be difficult to build.
Lauby said the grid needs more energy, not capacity, to serve future load.
“Capacity was king, but the king has no clothes,” he said. “It was a good trick and we got away with it for a while.”
MRO COO Richard Burt said energy and load are now unreliable variables, to the point where he questions reserve margins. He said that from 2010 to 2020, capacity in North America has dropped by 23 GW while load has grown by 85 GW.
“We’ve created a 100-GW gap,” Burt said.
Currently, MRO estimates that its footprint contains almost 51 GW of wind generation and about 1 GW of solar generation between MISO, SPP, Saskatchewan Power and Manitoba Hydro. But those entities’ interconnection queues show that 43 GW of wind generation and a whopping 102 GW of solar are planned by 2031.
“We could have more solar than wind in 10 years,” Burt said, adding that if all the potential solar is built, it will cover a surface area that spans “all the Disney parks” 40 times over.
Lauby said the transition to renewables is a “good thing” for the country but will require a rethink of reliability.
“It’s time now to no longer admire the problem. It’s time to solve the problem,” he said, noting solutions will require participation from not only the industry, but also state and federal government.
NERC’s Energy Reliability Assessment Task Force might lean toward requiring a new energy reliability assessments standard, Lauby said, but NERC must tread carefully and continue to abide by its policy of not prescribing generation or transmission construction.
“If shedding load is the answer, then that’s the answer,” Lauby said.
Mark Ahlstrom, NextEra Energy Resources’ vice president of renewable energy grid integration, called the resource shift “huge and inevitable.” He said that although “there’s no shortage of technology” to aid the transition, wholesale markets will have to adapt to the disruption.
“We’re talking changing not just the hardware, but markets. … It can be overwhelming, or it can be fascinating,” Ahlstrom said.
He said every renewable energy prediction that the U.S. Department of Energy or the National Renewable Energy Laboratory issued about 15 years ago has now been “far exceeded.” He also pointed out that the nation had about 100 years to perfect reliable electricity delivery using thermal generation.
“It’s not that they were prefect; they have their quirks,” Ahlstrom said of thermal generators, adding that new software is necessary to furnish services that complement clean energy sources.
Despite supply chain issues and solar panel tariff disputes with China, Ahlstrom was bullish on investing in renewable energy and storage facilities. He predicted that prices on commodities like gas, oil and coal will continue to rise.
He said grid operators’ GI queues are hampering new generation and the wait times are so long that some study models must be revised because better technology options are available by the time generation can connect. He said a five-year IC timeline doesn’t make sense when inverters available to developers change and advance about every two years.
Ahlstrom criticized MISO and SPP’s affected system study process for being inconsistent, sluggish and resulting in pricey network upgrades that upend projects.
“We can’t build a future transmission system using band aids from one generator at a time,” he said. “If we’re going to get to [net-zero emissions by] 2050, we’ve got less than 28 years to build massive transmission.”
Ahlstrom said the nation can use an HVDC national backbone and, though it may be unpopular, a national transmission planning committee to recommend projects.
“Society will still do this; it’ll just be twice as expensive,” he said of the pendulum swing to clean energy.
FERC on Thursday continued to tell utilities to refund premiums they earned on top of extraordinarily high prices in August 2020 during a heat wave that strained the Western grid and caused blackouts in California.
The commission ordered Uniper Global Commodities North America, Tri-State Generation and Transmission Association, and Brookfield Renewable Trading and Marketing to refund premiums earned above the average index prices at the Palo Verde hub in Arizona and other market hubs on Aug. 18-19 (ER21-62, ER21-65 and ER21-59).
The average index prices at Palo Verde of $1,400.50 on Aug. 18 and $1,639.60 on Aug. 19 resulted from scarcity conditions. Premiums above the index prices were unjustified, even though buyers offered the premiums as an inducement to sell to them, FERC said.
Tri-State, for example, sold 150 MW of electricity to Arizona’s Salt River Project for $1,500/MWh on Aug. 18 and for $1,700/MWh on Aug. 19, more than the average prices at Palo Verde.
In contrast, the average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas and Electric said in protests to FERC.
“Tri-State’s rationale for its sales above the index price is that Tri-State was a price-taker, the sales were consistent with published market index prices, and the prices reflected emergency conditions due to record high temperatures in the Southwest,” FERC wrote. “However, the Palo Verde price index already reflects scarcity conditions, evident based on a comparison of the index prices on the days of Tri-State’s sales to the index prices for other days in August 2020.”
Sellers in the Western Interconnection, excluding CAISO’s footprint, are required to justify prices above WECC’s $1,000/MWh soft price cap, including premiums.
FERC said Macquarie Energy had failed to justify premiums above hub index prices and in some cases had failed to justify sales above the WECC soft price cap (ER21-64).
The commission denied motions by Macquarie and other sellers to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s soft cap, saying the question was outside the scope of the proceedings.
It ordered all four sellers to make appropriate refunds within 30 days of the orders.
Thursday’s decisions followed seven similar orders in April for utilities to refund premiums for sales into CAISO on Aug. 18-19 as the ISO struggled to keep the lights on following rolling blackouts on Aug. 14-15. (See FERC Tells PacifiCorp to Refund Premiums and Sellers Urgse FERC to Raise WECC Soft Price Cap.) In those cases, FERC also denied motions to raise WECC’s soft price cap.
Commissioner James Danly dissented both in the April cases and in the latest batch, contending that FERC does not have the authority to “abrogate a contract to sell electricity pursuant to market-based rate authority when the contract price is above a commission-imposed ‘soft’ price cap, absent a finding that the public interest so demands,” Danly wrote in each case.
In all four cases decided Thursday, “buyers willingly purchased power during a reliability crisis at a modest premium above prevailing market index prices … [and] there is no showing in the record that these prevailing market prices seriously harmed the public interest,” he said. “Any such argument appears absurd on its face, particularly when internal CAISO prices are capped at levels much higher than the … contract price[s]” in the August 2020 heat wave.
ATLANTA — Utilities in the Southeast are cleaning up their generation fleets, but large consumers say the monopolies remain an obstacle to their decarbonization goals.
Kenneth Shriver, Southern Co.’s (NYSE:SO) chief economist insisted at the RE+ Southeast conference last week that his company is on the side of renewable developers and companies that have adopted net-zero goals. Southern’s generation mix was 70% coal 15 years ago, but it has reduced that to less than 20%, Shriver said.
“We are generating 50% less … carbon emissions today than we were in 2007,” he said. “We committed to that [goal by] 2030. We’re eight years ahead. And we’re on a path to net zero by 2050. That’s what our customers are wanting, and that’s what they are asking us for.”
“We all have the same goal, to get to net zero,” Shriver said. “We had some differences in our timeframes of when we want to do that. And the question mark now is, we’re trying to really work with customers to figure out, ‘Hey, you want to go earlier? How do we work with you and leverage that to the benefit of all customers?’”
Shriver said the company’s desire to ensure renewables benefit all customers “makes us focus on a lot more on more utility scale solutions, and solutions that can fit all customers, not just one particular group. As we work with individual customers, especially for the large C&I [commercial and industrial] customers, we have better economies of scale [and] we have generally found that we can deliver renewable solutions to customers, meet their needs, and then also have benefits to the overall grid.”
Southeast utility solar portfolios (2020) | Southern Alliance for Clean Energy
Shriver said Southern’s shift to renewables — it claims to be the fourth-largest operator of solar in the U.S. — shows that mandates are unnecessary when the economics are right. In the integrated resource processes for Southern’s utilities, utility-scale solar penciled out as the most economic source of new generation, he said.
Capped Programs
But some renewable advocates and C&I customers say Southern and other utilities backing the Southeast Energy Exchange Market (SEEM) and opposing an RTO are slowing the transition to a carbon-free grid.
Jamey Goldin, Google’s (NASDAQ:GOOG) energy regulatory counsel for global energy markets and policy, said the Southeast will be the most difficult region in the U.S. for Google to deliver on its climate goals because of the region’s monopoly utility structure. He dismissed SEEM as “a nothing burger.” (See Southern Co. Takes Heat over SEEM, Opposition to RTO.)
Steve Levitas, senior vice president for regulatory and government affairs for Pine Gate Renewables, said renewable programs in the vertically integrated monopolies of the Southeast are insufficient for C&I customers’ “infinite appetite for clean energy.”
“These programs are almost always limited in size with pretty severe caps, like a gigawatt at the outside of North Carolina,” Levitas said. “So, then the question arises, how do you allocate limited capacity of these programs? … Say you come into a state like Georgia with all kinds of corporate headquarters and data centers and the like and you put up a 600-MW program. It’s not going to go very far.”
North Carolina has allocated on a first-come, first-served basis, while other states use lotteries.
“The way that makes no sense to me … is a pro rata allocation,” he said. “That would mean that if you had 600 MW of capacity available, and you have 3 GW of load that is seeking to participate … everybody gets 20% green energy,” he said. “I don’t know if anybody you worked with would find that very satisfying.”
Pining for a Southeast Market
“Extending an organized wholesale market into the Southeast would go a long way towards solving these problems, so we can structure transactions the way we do in other parts of the country,” Levitas added. “That’s a political hot button and is probably not on the horizon anytime soon. But it would create more opportunities for customers who are trying to accomplish these goals. And I won’t even talk about going to retail choice, but that fully solves the problem.”
Dmitri Moundous, senior manager of storage business development for Cypress Creek Renewables, acknowledged a full wholesale market, or an energy imbalance market, is “obviously wishful thinking.” But he said SEEM is “really not going far enough at all.”
SEEM’s savings from reduced curtailments of renewables is “measured in single millions,” Moundous said. “When you go to an energy imbalance market, there’s multiple studies that show that you can [obtain] savings into the hundreds of millions of dollars — so, an entire order of magnitude higher.”
“That is something that can really catalyze energy storage in the Southeast,” he said. “In markets like the Pacific Northwest, where you have corporates that have commitments to 100% clean energy goals [and] time-matched renewables, that sort of storage is valued a lot more.”
ATLANTA — Solar advocates last week celebrated the defeat of a Florida bill that would have phased out the state’s net metering program — while warning the battle is far from over.
The bill (HB 741), which Florida Power and Light (NYSE:NEE) said was needed to address cost shifting, cleared the House and Senate by wide margins but was vetoed last month by Gov. Ron DeSantis (R). It would have gradually reduced net metering rates until reaching the avoided-cost rate in 2029.
Jim Purekal, manager of market development and policy for rooftop solar company SunPower (NASDAQ:SPWR), told the RE+ Southeast conference that DeSantis vetoed the bill because of rising inflation, a rate increase that followed FPL’s acquisition of Gulf Power (which “drove hundreds of phone calls and emails into the governor’s office”) and a provision that would allow FPL to charge ratepayers for lost revenue from competition with solar.
“The battle is not over yet,” Purekal told the conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA). “The fight is really just kind of beginning at this point, because we know that Florida Power and Light is licking their wounds, rolling up their sleeves, and they’re going to be back again. And I don’t know what that … looks like just yet,” he said. “But we do know that what happened over the last couple of months has shown that the solar industry in Florida is here to stay, and we are a formidable force.”
Will Giese, Southeast regional director for SEIA, said that “when this bill was first introduced, it was like the immediate and sudden death of the solar industry,” and [proponents] wanted to get it through before the legislative session even started in January.
“I think it’s a credit to folks like Jim and a number of other solar advocates that were down there [in the state capitol],” Giese said. “I mean, there was somebody down there every single week until the end of the legislative session from the solar industry, walking the halls, educating people.”
Giese said the industry’s warning that 40,000 jobs were at stake also was a factor in DeSantis’ decision.
“It’s important to remember that Florida is the only state other than California to have installed over 100 MW of residential solar in one quarter. That’s huge,” Giese said.
Yet Florida has fewer rooftop solar installations than New York, said Purekal. “It’s not because New York has more solar insolation. That’s not the case: Florida is the Sunshine State. To me, it comes down to policy.”
Other States
Autumn Proudlove, senior policy program director at N.C. Clean Energy Technology Center, said that while North Carolina and Florida have traditional retail-rate net-metering programs, other states have chosen different compensation structures.
“Net metering reforms are under consideration in states all across the country, including many of the Southeastern states,” she said, citing results from the center’s recent report, The 50 States of Solar.
Mississippi regulators recently considered a change to the state’s program, which credits customers at a rate between the retail rate and the avoided-cost rate. The Public Service Commission ultimately decided to keep the current structure while adding a solar rebate for residential customers to try to spur the market, Proudlove said.
In November, the North Carolina Sustainable Energy Association and the Southern Environmental Law Center announced a compromise with Duke Energy (NYSE:DUK) on proposed new net-metering rules, similar to an agreement approved last year by the South Carolina Public Service Commission.
Lon Huber, vice president of rate design and strategic solutions for Duke, said the proposal includes some non-bypassable charges to ensure full funding of low-income and energy-efficiency programs, and a “minimum bill to ensure recovery of the distribution system [costs].”
“Those conversations might be different for public or private companies … and for municipalities, but those conversations are really important,” she said. “All of us on this panel are pushing hard on this. We all have government affairs teams, and we’re very focused on the policy because we know how important it is,” she said on a panel with representatives from Pine Gate Renewables, Origis Energy and Sol Systems. “But when the energy buyers — all the energy buyers — become more vocal, it will only help propel this momentum around energy purchases [and make it] faster and better for the customers.”
Jeff Pratt, president of Green Power EMC, a nonprofit that helps 38 Georgia electric membership corporations obtain renewables, called for civility and patience.
“Listen, bear with, engage, be friendly and courteous to one another as we work through these processes. The disruption is real. There’s opportunity in disruption for utilities; there’s [also] threats to utilities. There are opportunities for convenience stores with disruption, and there’s threats as well,” Pratt said. “Let’s be kind and courteous and helpful to one another and, and work through these bumps. We’re going to be fine. It’s just going to take us another decade or so to get there.”
Giese said that although net metering has been crucial to the growth of the rooftop market, “there are ways to evolve these tariffs … that aren’t sudden and devastating. There are ways to get there incrementally. And I think sometimes there’s a knee-jerk reaction from the industry, in some ways to say, ‘Oh, no, we don’t want this,’ in the same way that the utility does. And so, if both of those folks can come to the middle and say, ‘Hey, there’s a way to move forward,’ I think that would be the ideal.”
Risk of Backsliding
Dmitri Moundous, senior manager of storage business development for solar and storage developer Cypress Creek Renewables, urged renewable advocates to continue participating in in state policymaking, saying he fears “letting short-term market volatility on the supply side drive decisions that are 15 years out.
“One pretty big risk is that we might see a walking back of state policies or utility commitments, or just slipping timelines, slipping numbers and commitments on renewable deployments [or] carbon targets. It’s like, ‘Oh, we can’t really accomplish this, so we’re going to wait for 2040 technology based on some cost curve that we saw,’” he said.
“That’s not to be negative, but that’s just motivation to stay engaged at the state level … because I think that’s where the energy transition happens, at the state level.”
FERC on Thursday handed down a mixed decision granting partial approval to the ERO Enterprise’s proposed changes to NERC’s Rules of Procedure (ROP) meant to revise the agency’s Compliance Monitoring and Enforcement Program (CMEP) and other elements of its operations (RR21-10).
NERC and the regional entities submitted the revisions to FERC last September, proposing to update the following areas of the ROP:
Section 400 — Compliance and enforcement
Section 600 — Personnel certification
Section 900 — Credential maintenance program
Section 1500 — Confidential information
Appendix 2 — Definitions used in the ROP
Appendix 4C — CMEP
The changes to sections 600, 900 and 1500 concern NERC’s Personnel Certification and Credential Maintenance Program, and are intended to improve the governance and integrity of the System Operator Certification Program. They would also move responsibility for credential maintenance from NERC’s Reliability and Security Technical Committee to the Personnel Certification and Governance Committee.
The remaining proposed revisions relate to the CMEP and are intended to “further enhance the risk-based approach to the CMEP” and remove “unintended or unnecessarily burdensome limitations” found in the current ROP. The planned changes include “eliminating the three-year audit cycle for reliability coordinators, balancing authorities and transmission operators; removing the public posting requirements for certain reports; revising evidence retention periods; [and] modifying reporting of minimal risk compliance.”
NERC and the REs claimed in their proposal that the elimination of the fixed audit cycle would allow responsible organizations to prioritize compliance activities focused on areas of high risk rather than locking them into performing certain activities at certain times. In addition, the petitioners said the revised evidence retention requirements recognized that not all violations of reliability standards “require the same type of processing and documentation.”
In its Thursday order, FERC accepted all of the non-CMEP proposals without exception. However, while the commission also accepted several portions of the CMEP changes, it found that not all the revisions were “just, reasonable, not unduly discriminatory or preferential, and in the public interest.”
Among its objections, FERC noted that some of the ERO Enterprise’s proposed changes would “remove from commission review much of the ERO’s enforcement of reliability standards.” For example, the commission said that removing the three-year audit cycle was inconsistent with FERC’s requirement of “rigorous audits of compliance,” a problem “exacerbated” by the relaxation in evidence retention requirements.
FERC also objected to the proposal to eliminate reporting of self-logged lower-risk violations, on the grounds that the commission’s regulations require NERC and the REs to report self-reports “promptly” along with investigations undertaken by the ERO Enterprise. In addition, the commission warned that entities will have fewer incentives for compliance if the likelihood of being audited is lower and they are not required to keep records that might bring instances of noncompliance to light.
FERC’s order directed NERC to reinstate multiple requirements of its ROP that it had proposed for revision or elimination, including:
that all violations be reported to NERC and the commission, no matter how they are disposed;
that entities retain evidence to demonstrate compliance for the entire audit period, or the time mandated by the relevant standard;
that NERC and the REs establish a program for auditing responsible entities and verifying the findings of previous compliance audits;
that independent audit reports be made public.
The commission also ordered NERC to submit a compliance filing within 60 days of the date of the order confirming that the ROP sections had been reinstated.
