MINNEAPOLIS — A frequency response study that NERC engineers began more than two years ago to model the potential impact on the Eastern Interconnection of replacing old coal power plants with wind and solar resources has reached a tentative conclusion that may present market issues to the developers of renewable energy.
The study has concluded that wind and solar generators, which precisely synchronize their power flows into the transmission system with electronic inverters, can respond to frequency disruptions far more quickly than a traditional synchronous machine response, which is based on the speed of governor action on the steam turbines and generators in conventional power plants.
But the catch would be that wind and solar developers would have to set aside some percentage of a wind or solar farm’s generation potential. In other words, the current rules that require transmission organizations to take all of the output of wind and solar whenever it is available would have to be changed.
“It sounds sacrilegious,” explained Robert Cummings, NERC’s senior director of engineering and reliability, who designed the study with his colleague Olushola Lutalo, lead engineer of power system analysis.
“If you really want to make the [transmission] system perform, you can curtail, you can spill wind and spill sun, in order to get a non-carbon-based reserve margin that can outperform anything else you’ve got out there,” he told members of NERC’s Planning Committee.
“If I can curtail solar or wind by 5% instead of reserving very large amounts of head room with synchronous machines, I can outperform the synchronous machines. That is the bottom line,” Cummings said.
Having sufficient backup reserves is a question that electric utilities have had to deal with since the birth of the industry a century ago. For decades, the answer was “spinning reserves,” the practice of keeping certain boilers hot enough to quickly produce power to deal with the failure of other boilers operating to generate power continuously.
“You’ve pointed out very clearly that IBRs [inverter-based resources] can respond faster and perhaps eliminate the need for carbon-based spinning reserves,” consultant Gary Brownfield said. “That’s a huge game changer and paradigm shift for the industry.”
Cummings said he’s been asked, “Are you ever going to get to an all renewables” grid?
“Well, we might get to all renewables, but you’re not going to retire Grand Coulee or Hoover Dam. … And so, you’re still going to have synchronous machines. There might come a time when it makes sense to couple them electronically.”
John Moura, director of reliability assessment and technical committees, said the research has major implications for system planners. “In the future, your largest contingency might not be the huge nuclear units tripping offline. It might be a cloud cover [affecting a large solar farm] in South Carolina.”
Planning Committee members had a lot of questions and comments about the study’s findings. The immediate question was how the sun or wind could be curtailed without paying a solar or wind developer for what in effect would be spinning reserves.
“We are not trying to address the economics or the market issues here,” Cummings said in response to questions that zeroed in on the regulatory implications of such a change. “We are just talking about what you can do with these devices.
“It’s not the mechanics. It’s the politics,” he added when pressed for more detail. “Right now, we are in a mindset of ‘you are going to take all the sun, you are going to take all the wind and you are going to swallow it.’
“You can’t. California is a good example of that with the duck curve. This [situation] is the freshman class trying to drink all the beer in the Ohio State University stadium. You keep on filling the stadium and the class cannot drink that much.”
Cummings, who is a member of the Department of Energy’s Electricity Advisory Committee, added that he will present the modeling conclusions to the committee next month.
Cummings said NERC’s Inverter-Based Resource Performance Task Force (IRPTF) has been talking with inverter manufacturers to understand the capabilities of inverters as part of the IEEE P2800 project to develop a performance capability standard for IBRs connecting to the bulk power system.
“The [original equipment manufacturers], they’re listening,” Cummings said. “We’re asking them, ‘Can you do this?’ They say, ‘Yeah, we can do that.’ … So, we’re being effective without the standard even yet being in place, because we’re not going to ask them to do something they can’t do. … We’re working really hard to make this a real solution as opposed to an argument. That’s the beauty of the IRPTF.”
FERC last week established briefing procedures for MISO and SPP as it investigates potential “overlapping and/or duplicative” congestion charges being imposed on pseudo-tie transactions between the RTOs (EL17-89, EL19-60).
The commission is looking into Tariff, contract provisions and practices imposed by the RTOs on pseudo-tie transactions in response to complaints under Section 206 of the Federal Power Act by American Electric Power’s Southwestern Electric Power Co. subsidiary (EL17-89) and the Arkansas city of Prescott (EL19-60).
Water tower in Prescott, Ark. | Waymarking
The RTOs admitted that in “limited circumstances,” congestion charge overlap occurs on pseudo-tied transactions involving certain flowgates coordinated under their market-to-market (M2M) process. MISO said the overlap is “due to the independent application of the [M2M] process” under their joint operating agreement and their congestion-management provisions. SPP acknowledged that when M2M constraints are bound in more than one market, “it is reasonable to conclude that some overlap may occur in the congestion settlements … for pseudo-tied assets.”
FERC granted the complaints on the overlapping and duplicative congestion charges and ordered the RTOs to file initial briefs within 45 days. The commission asked them to address:
Tariff and JOA provisions that may allow overlapping congestion charges to be assessed;
The specific circumstances under which congestion charges overlap;
Revisions to the Tariffs, JOA or other documents or procedures that could eliminate overlapping charges;
Existing tools or market products that pseudo-tied loads and resources can use to mitigate or eliminate overlapping charges;
The status of discussions between MISO and its stakeholders on solutions to the congestion overlap; and
Pseudo-tied loads or resources being assessed overlapping or duplicative congestion charges or vulnerable to overlapping charges.
SWEPCO’s complaint alleged that MISO violated the JOA with SPP regarding congestion charge assessments for its loads that are pseudo-tied out of MISO and into SPP. It said the charges resulted in an overpayment to MISO of $963,974 for one four-month period in 2016.
FERC said SWEPCO did not show MISO has violated the JOA, pointing to language in the grid operators’ congestion-management process that it said does not state or imply “that pseudo-tied loads … should be exempt from the congestion charges otherwise applicable under the RTOs’ individual tariffs.” The commission agreed with MISO that as a network service transmission customer, SWEPCO is subject to congestion and loss charges.
The commission did find that overlapping or duplicative congestion charges for loads pseudo-tied from MISO to SPP are unjust, unreasonable, unduly discriminatory or preferential. They established a refund effective date of Sept. 15, 2017.
AEP’s service territory | AEP
Prescott’s Section 206 complaint against MISO and SWEPCO said its municipal utility system, which interconnects with Entergy Arkansas, saw its monthly transmission costs increase from $65,000 to $175,000 with Entergy’s integration into MISO in 2013 and the opening of SPP’s Integrated Marketplace in 2014. The city said its load, supplied by SWEPCO resources in SPP through a pseudo-tie, is assessed both MISO and SPP M2M congestion charges.
It also said MISO and SWEPCO “thwarted” Prescott’s efforts to secure power from other suppliers and asked permission to settle congestion charges based on day-ahead prices. The city also said SWEPCO had not hedged its congestion costs effectively, contrary to the power supply agreement (PSA).
FERC denied the complaint in part, saying Prescott had not shown SWEPCO and MISO thwarted its efforts and that it was “evident” MISO provided guidance to the city on its pursuit of alternative supply arrangements. The commission found SWEPCO did not have to grant Prescott’s request to change its supplier and declined to terminate the company’s role as Prescott’s agent.
The commission also said Prescott had not “persuasively shown” that FERC should direct MISO to allow pseudo-ties to settle financially based on day-ahead prices.
The city had asked for a $770,000 yearly refund from SWEPCO, dating back to the 2019 complaint, but FERC commission denied the request. It said Prescott’s request relied on a “misreading” of the PSA’s terms. The commission did agree the city’s load was subject to unjust and unreasonable duplicative congestion charges and established a refund effective date of April 5, 2019.
FERC issued the following orders at its open meeting Thursday.
CAISO/WECC
Rehearing Denied in Asset Management Cases
FERC denied rehearing of two 2018 orders that concluded that Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity.
The commission approved Sempra Gas & Power Marketing’s request to sell resource adequacy capacity at market-based rates to its affiliate, San Diego Gas & Electric (ER19-2422).
FERC said that a competitive solicitation and benchmark evidence filed by the companies ensured there was no affiliate abuse.
Refund Report OK’d
FERC accepted a refund report filed by Panoche Valley Solar to address its unauthorized wholesale sales of electric power made before receiving commission approval (ER18-855). The commission authorized CAISO to distribute the $58,107 refund on a pro rata basis to all market participants that paid its grid management charge during the refund period, Oct. 31, 2017, through April 14, 2018.
206 Proceeding in Idaho Power Market Power Case
The commission ordered a proceeding under Federal Power Act Section 206 to determine whether Idaho Power may continue to charge market-based rates in the Idaho Power balancing authority area (ER10-2126-005).
The company’s updated market power analysis passed the pivotal supplier and wholesale market share indicative screens in the Avista, Bonneville Power Administration, Nevada Power, NorthWestern Corp., PacifiCorp-East, and PacifiCorp-West BAAs and in CAISO’s Energy Imbalance Market.
But it failed the wholesale market share indicative screen in one season in its own BAA.
FERC said Idaho Power must show cause within 60 days why the commission should not revoke the company’s market-based rate authority in its BAA. “In addition to the previously filed delivered price test, Idaho Power may present alternative evidence, such as historical sales and transmission data, to rebut the presumption that it has the ability to exercise horizontal market power in the Idaho Power balancing authority area,” the commission said.
As an alternative, Idaho Power may file a mitigation proposal to eliminate its ability to exercise market power or agree to accept cost-based rates, the commission said.
TEP Rebuffed on Tx Cost Recovery
FERC rejected Tucson Electric Power’s request for 100% recovery of prudently incurred costs on the abandoned 345-kV Sahuarita-Nogales transmission project, saying it is entitled to only 50% (ER19-2023).
The project was delayed for years over siting issues, and in 2012, the Arizona Corporation Commission found it was no longer economically justified because of reduced load forecasts and UNS Electric’s improvements to its electric system, including a proposal to upgrade an existing 115-kV line to 138 kV to address reliability issues in Santa Cruz County.
The commission rejected the 100% request authorized by FERC Order 679, saying that the company’s work on the transmission project “largely took place prior to” the issuance of the order in 2006.
Instead, FERC said the company can recover 50% of its prudently incurred abandonment costs. The commission established a hearing and settlement procedure to determine the costs to be included and the appropriate amortization period.
ISO-NE
New Brunswick Energy Clears Market Power Review
FERC ruled that New Brunswick Energy Marketing satisfied its standards for market-based rate authority in the New Brunswick System Operator balancing authority area, terminating a Federal Power Act Section 206 proceeding (ER14-225-005).
The commission initiated the review in May after the company’s parent, NB Power, purchased a 290-MW generation facility in the province of New Brunswick.
NB Energy Marketing told FERC it passed the pivotal supplier and wholesale market share screens in the ISO-NE market and the pivotal supplier screen in the NBSO BAA. But it said it failed the wholesale market share indicative screen in that area in all four seasons. The company filed a delivered price test to rebut the presumption of horizontal market power.
“After weighing all of the relevant factors, we find that, on balance, NB Energy Marketing has rebutted the presumption of market power for the New Brunswick balancing authority area,” the commission said.
MISO
SWEPCO Settlement Approved
FERC approved a settlement on a power supply agreement (PSA) between Southwestern Electric Power Co. and the city of Minden, La., over the objections of the city of Prescott, Ark. The commission ruled that the benefits of the settlement for the settling parties outweighed Prescott’s objections (ER18-1225-001, EL18-122-001).
SWEPCO supplies all of Minden’s capacity and energy requirements above the city’s allocation from the Southwestern Power Administration. Minden alleged that after Entergy’s integration into MISO, it began seeing markedly higher congestion charges and that SWEPCO failed to effectively hedge them as required under its contract.
Prescott said it has a contract with SWEPCO that includes provisions identical to that in the Minden PSA and argued that because it was excluded from participation in the proceeding, the settlement should not be accepted. The commission disagreed, saying “Prescott’s interests [are] too attenuated and that the benefits of the settlement outweigh the nature of the objections.”
SWEPCO will pay Minden $400,000 under the settlement.
Extra Time for Wabash Valley 205 Filing
FERC gave the Wabash Valley Power Association up to 90 days to make an FPA Section 205 filing proposing rates, terms and conditions for the early termination of its contracts with Tipmont Rural Electric Member Cooperative, which serves 21,000 members in west-central Indiana (EL19-2).
Last October, Tipmont asked the commission to allow it to terminate its all-requirements wholesale power supply contracts with Wabash on Jan. 1, 2020, in return for paying any stranded costs incurred by Wabash.
Tipmont said Wabash is citing a “buyout policy” that requires Tipmont to give Wabash 10 years’ notice of termination of service and to pay stranded costs at a rate set unilaterally by Wabash. Tipmont contends the policy is unenforceable because Wabash never filed it with the commission.
Both parties told FERC the issues related to the termination could be addressed in a Section 205 filing by Wabash. As a result, the commission said it would hold the complaint in abeyance pending further action.
NYISO
PSE&G Denied Rehearing in Con Ed Dispute
FERC denied Public Service Electric and Gas’ request for rehearing of the commission’s September 2018 order dismissing its complaint against Consolidated Edison over the latter’s termination of the “wheel” it used to move power from upstate New York to New York City via northern New Jersey (EL18-143-001).
Con Edison and PSE&G jointly own the B and C transmission lines under the Hudson River. | PJM
PSE&G said Con Ed violated the NYISO Tariff by failing to cooperate with PSE&G to remove dielectric fluid and transmission cables from the B and C Lines, two 345-kV lines co-owned by the companies that run under the Hudson River to connect NYISO and PJM.
The commission had ruled that it lacked exclusive jurisdiction to determine the validity of PSE&G’s claim, saying the issue should be resolved in federal court. The commission affirmed that the line agreements between the companies will terminate on Dec. 31, 2020. (See FERC Dismisses PSE&G Complaint Against Con Edison.)
PJM
NJ Gas Plant Granted More Efficiency Waivers
FERC approved two waivers for a New Jersey cogeneration plant last week that will exempt it from having to meet qualifying facility operating and efficiency standards in 2018 and 2019 (EL19-72).
Kenilworth Plant — a 29-MW dual-fuel combined cycle unit that supplies electricity and steam to Merck’s international headquarters in Union County — has been struggling to meet the Public Utility Regulatory Policies Act standards since 2016, when the company converted the property from a manufacturing and processing facility to a corporate campus, reducing its need for steam.
FERC granted waivers for the plant 2016 and 2017 but held off on approving one for 2018 in hopes that a scheduled overhaul of its combustion turbine would improve efficiency. Kenilworth told the commission in June that although the turbine’s efficiency rating improved after the maintenance, it still fell short of the minimum qualifying efficiency standard of 42.5% for several months afterward. Further repairs and increasing on-site load at the campus, however, will eventually bring the plant back into full compliance with the QF standards.
FERC granted the waivers for 2018 and 2019 but dismissed the request for 2020, saying that a combination of the plant’s investments and the anticipated growth at the Merck campus make a waiver unnecessary.
Calpine Reactive Service Settlement Approved
The commission approved a settlement that lowers reactive service rates for Calpine generating units in PJM (ER14-874).
Calpine’s Bethlehem Energy Center | Calpine
The settlement between Calpine, Old Dominion Electric Cooperative and PJM’s Independent Market Monitor includes an annual revenue requirement (ARR) of $10.1 million for Calpine units in Pennsylvania, New Jersey, Delaware, Maryland, Virginia and Illinois. PJM, the Monitor and ODEC had filed motions questioning whether Calpine’s rates were justified.
Calpine’s Bethlehem, Pa., plant will have an ARR of $2.02 million, a 25% reduction from the $2.6 million Calpine had proposed. Since the ARRs are now lower, Calpine agreed to refund the difference.
SPP
NPPD Rehearing Request v. Tri-State Denied
FERC last week denied Nebraska Public Power District’s request for rehearing of the commission’s order dismissing its complaint against SPP and Tri-State Generation and Transmission Association over Tri-State’s annual transmission revenue requirement (EL18-194, ER16-204).
Sunflower Electric Power has acquired Mid-Kansas Electric, prompting SPP to combine them into a single Sunflower zone. | Sunflower Electric, Mid-Kansas Electric
NPPD filed a complaint under Section 206 of the Federal Power Act last year asking the commission to determine that the inclusion of certain costs in Tri-State’s ATRR and failure to credit certain revenues to its revenue requirements for network integration transmission service under SPP’s Tariff are unjust and unreasonable.
FERC denied the complaint, finding that each of the disputed cost components were covered by a settlement agreement that included NPPD and that the utility failed to demonstrate that its proposed modifications to the ATRR satisfy the heightened “public interest” standard.
Commission Accepts Sunflower, Mid-Kansas Merger
The commission conditionally granted Sunflower Electric Power’s request for a 50-basis point adder to its return on equity to reflect its acquisition of Mid-Kansas Electric (ER19-2273).
The commission also set for hearing and settlement procedures SPP’s proposed revisions to Sunflower’s formula rate template and implementation protocols to combine the existing Mid-Kansas and Sunflower zones into a single Sunflower zone under the Tariff.
— Rich Heidorn Jr., Christen Smith and Tom Kleckner
A New Hampshire law that requires the state’s utilities to purchase power from biomass and waste generators encroaches on federal jurisdiction under the Federal Power Act and the Public Utility Regulatory Policies Act, FERC ruled Thursday (EL19-10).
The commission granted a petition for declaratory order requested by the New England Ratepayers Association over the New Hampshire statute, Senate Bill 365, which requires electric distribution companies to purchase power from biomass and waste generators within their service territories, with the price equal to 80% of the default retail rate.
Seven biomass or waste generators with a capacity of 25 MW or less qualified for contracts under the law, all within the territory of Public Service Company of New Hampshire (PSNH). PSNH was previously given relief from its mandatory purchase obligation under PURPA and is not required to purchase from qualifying facilities over 20 MW.
In its ruling Thursday, the commission agreed with the ratepayers’ group that the New Hampshire law is pre-empted by the FPA because it establishes a wholesale rate for energy and violates PURPA because the price exceeds the avoided-cost rate.
The commission said the law encroached on federal jurisdiction the same way Maryland’s contract for differences on a state-sponsored gas-fired generator did, a policy that was struck down by the Supreme Court in Hughes v. Talen in 2016. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
Wheelabrator Concord in Penacook, N.H., can burn up to 575 tons daily of post-recycled waste from homes and businesses, generating as much as 14 MW of power. | Wheelabrator Concord
“Although the facts here differ from Hughes, we conclude that the result is the same because SB 365 does explicitly what the Maryland program in Hughes did implicitly. Whereas the Maryland program overturned in Hughes established a wholesale rate by adjusting the revenue that the generator received in the PJM auction to reflect a predetermined rate, SB 365 directly establishes a predetermined rate and requires utilities within the state to offer to purchase electricity at that specific state-established rate. We find that the logic of the court’s opinion in Hughes applies with equal force here.”
The commission said the law is also “inconsistent with” PURPA because 80% of the default energy rate exceeds PSNH’s avoided cost, which the New Hampshire Public Utilities Commission has said is equal to ISO-NE’s real-time market price.
SB 365 was enacted after the legislature overrode Gov. Chris Sununu’s veto in September 2018. The challenge to the New Hampshire law was supported by the Electric Power Supply Association and the state Office of the Consumer Advocate.
Opposing the challenge were the state attorney general and several New Hampshire generators: Bridgewater Power Co., DG Whitefield, Pinetree Power, Springfield Power and Wheelabrator Concord.
New Hampshire had contended the ratepayers’ petition was premature because the Public Utilities Commission has not reviewed any contracts under the law.
In January, the PUC issued an order saying it would “abstain from deciding the constitutional arguments” by the ratepayers’ group. “If we are presented with a question that requires resolution of the pre-emption issue, and if pre-emption has not already been decided by FERC or a court of competent jurisdiction, we will consider certifying the issues to the New Hampshire Supreme Court,” the commission said.
In May, Springfield Power, one of the opponents of the ratepayers’ FERC case, shuttered its 17-MW biomass plant.
State Consumer Advocate Donald Kreis said Friday that the biomass plants appealed the PUC’s “refusal to turn on the SB 365 money spigot while the pre-emption question was unresolved” to the state Supreme Court.
Initial briefs are due in October. “We will address their arguments in our own brief, due in early November,” he added.
PUC spokeswoman Amanda Noonan said the commission will wait a decision from the Supreme Court before addressing the FERC ruling.
However, a lawyer involved in the dispute, who asked not to be identified, said the state Supreme Court proceeding may be moot as a result of FERC’s ruling. The next step for the generators would be a request that FERC rehear the case, a prerequisite to appealing the ruling in federal court, the lawyer said.
The judge overseeing PG&E Corp.’s bankruptcy case will probably get an earful Tuesday from lawyers advocating for two warring reorganization plans.
One was drafted by PG&E and its utility subsidiary Pacific Gas and Electric, the debtors in the case. It proposes using $14 billion in new equity financing to pay off wildfire claims and to emerge from bankruptcy by June, in time to take advantage of a new $21 billion wildfire recovery fund established by the California State Legislature. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)
The other is by PG&E’s unsecured bondholders, which recently partnered with fire victims. The bondholders propose injecting billions of dollars of cash into PG&E and paying $24 billion to settle wildfire claims in exchange for a controlling stake in California’s largest utility and full payment of their notes.
The bondholders and victims made an impassioned plea for their plan in a joint filing Thursday. It says PG&E’s proposal essentially is a sham offer intended to delay proceedings while benefiting one of the utility’s largest shareholders. That shareholder, a high-risk hedge fund from Boston called Baupost Group, bought up billions of dollars in claims from insurance companies, known as subrogation claims, which PG&E recently agreed to settle for $11 billion. (See PG&E and Insurers Agree to Settle Wildfire Claims.)
(Under PG&E’s plan, fire victims would get about $8.4 billion for damages stemming from November’s Camp Fire, the deadliest in state history, and a series of fires in Northern California wine country in October 2017.)
That means even if Baupost loses money on its PG&E stock, much of which it bought for three or four times its current worth, the hedge fund can still make a killing on PG&E’s payments for fire damages, the bondholders and victims argued.
“The settlement of the subrogation wildfire claims will enrich Baupost enormously at the expense of individual wildfire victims that have suffered actual loss,” the joint motion says. “Baupost is reported to hold more than $3.3 billion in subrogation wildfire claims, much of which, upon information and belief, was purchased at approximately 35% of face value. [PG&E’s plan] would pay Baupost’s claims at roughly 59% of face value, allowing it to reap hundreds of millions of dollars in profit from the debtors’ plan, at the expense of actual wildfire victims.”
PG&E said in a news release that the plan by bondholders, led by Elliott Management Corp. of New York and fire victims’ lawyers, is “a blatant attempt to unjustly enrich the noteholders who proposed it. The Elliott proposal would cost all PG&E customers billions of dollars in additional interest payments over 15 years – while providing an unfair windfall for the noteholders and plaintiffs’ attorneys.”
The bondholders and fire victims, called the Ad Hoc Committee of Senior Unsecured Noteholders and the Official Committee of Tort Claimants, asked U.S. Bankruptcy Court Judge Dennis Montali to end PG&E’s period of exclusivity, the time it has to file its own reorganization plan without interference. That period is set to end by the end of this month if Montali doesn’t extend it.
The judge will have to begin to sort through the arguments at Tuesday’s hearing in San Francisco. The parties to the case are all trying to move it along so PG&E can benefit from the state wildfire fund.
The California Public Utilities Commission, which also must approve a reorganization plan, will need months to consider it, adding to the time pressure. The CPUC is scheduled to consider a proposed order to begin an investigation of PG&E’s reorganization plan, and its effects on ratepayers, at its meeting Thursday.
ST. PAUL, Minn. — Google gained a foothold in the MISO system last week as the RTO’s Board of Directors approved a subsidiary’s membership application.
Google Energy joined MISO’s Eligible End-User Customers sector. The subsidiary was founded nearly a decade ago in a push to power its parent’s operations with 100% renewable energy. It has multiple investments and power purchase agreements with wind farms along the western border of MISO’s footprint, enough by 2017 to match its annual electricity consumption.
“Although our 100% renewable milestone signifies that we buy enough renewable energy over the course of a year to match our annual electricity consumption, it does not mean that our facilities are matched with renewable energy in every hour of every day,” the company says. Its ultimate goal “is to source enough carbon-free energy to match our electricity consumption in all places, at all times.”
MISO President of Market Development Strategy Richard Doying said the RTO is anticipating more non-traditional membership applications like Google as more companies become enmeshed with distributed resources’ push to join wholesale markets.
The RTO’s approval of Google’s membership came a day before the company announced a $2 billion global investment in solar and wind generation across 18 new renewable energy deals.
The board also allowed Upper Peninsula Power Co. into the Municipals, Cooperatives and Transmission Dependent Utilities sector. Both applications for membership were approved unanimously.
Lurie Joins Board
The board also filled a vacant seat with former New York Power Authority CFO Robert Lurie. The selection was made without input from MISO membership, as the seat was vacated earlier in the year by Thomas Rainwater. MISO’s bylaws stipulate that vacancies are dealt with by solely the board, and not through the usual Nominating Committee process and subsequent stakeholder vote.
“We had a robust discussion of the candidates and their qualifications, and I think he will serve MISO well,” Chair Phyllis Currie said.
MISO could have seen up to four new faces on its board in 2020, but the Nominating Committee opted only for existing board members as eligible candidates: Todd Raba, Trip Doggett and Barbara Krumsiek. (See MISO Board of Director Briefs: June 20, 2019.) The RTO will again use VoteNet Solutions to conduct its membership vote on the candidates. Electronic polls are set to open Thursday for 37 days.
This year’s Nominating Committee consisted of Directors Baljit Dail, Mark Johnson and Theresa Wise; the two stakeholder seats were occupied by Minnesota Public Utilities Commissioner Matthew Schuerger and Ameren’s Jeff Dodd.
ST. PAUL, Minn. — MISO staff are done assembling the RTO’s 2019 Transmission Expansion Plan (MTEP 19), presenting a nearly $4 billion draft package to the Board of Directors last week.
Instead of concentrating solely on this year’s plan, however, MISO executives at the board’s System Planning Committee meeting Sept. 17 emphasized what changes they would make to modernize the 15-year future scenarios used annually to justify transmission projects.
The proposed 2019 portfolio — 472 new projects totaling nearly $3.9 billion — is open for stakeholder review through the end of the month. The latest draft is trimmed from an earlier version that contained 483 projects at a cost of $3.95 billion. Even with the reductions, it’s still the RTO’s second-most expensive transmission buildout. (See MISO 2019 Transmission Expansion Plan Takes Shape.)
Vice President of System Planning Jennifer Curran told the board to expect some additional changes in response to stakeholder comments.
MISO said MTEP 19 is “consistent” with MTEP 18 because the package primarily consists of reliability projects. That trend appears likely to continue in the 2020 package, as the RTO has announced it would recycle its futures next year. The RTO has promised an extensive reboot of its planning projections beginning with the 2021 portfolio. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)
“I think [with] the status quo coming for 2020, there will be more interest in the 2021 futures,” Director Nancy Lange predicted, urging careful thought from MISO on the new futures. “I think the pace of change is only accelerating, so it’s important for MISO to think about its key planning assumptions.”
Asked by Director Phyllis Currie if there was any discord as MISO prepared MTEP 19 with stakeholders, staff cited discussions over how prominently batteries should be featured in the planning landscape.
“That’s a big focus for our team,” said Executive Director of System Planning Aubrey Johnson, adding that MISO first must create a cost recovery mechanism for storage devices.
Director Trip Doggett asked if batteries are gaining more traction because of recent technological breakthroughs or because of their transmission capabilities.
“I think it’s a ‘Yes, and…’ question,” Johnson responded, noting that batteries can mimic generation.
MISO President Clair Moeller pointed out that MTEP 19, which recommended a single battery project, anticipates just 2.5 MW of load growth. (See MISO Recommending 1st Storage-as-Tx Project.) “For perspective, 2.5 MW is the size that could be compared to a large neighborhood’s load,” he said. Moeller said that although load growth has remained flat since about 2007, load has shifted with demographics.
“So, the standard load growth isn’t driving transmission decisions. … But people are moving around,” he said.
Moeller also said differing state goals regarding their energy mixes have emerged as a planning challenge in recent years.
“When we began the [MISO] market, everyone’s fleet was about the same,” he said. “Now, not everyone thinks high wind penetration is the future. So that complicates things.”
Currie asked if neighboring RTOs were planning transmission around battery storage buildout.
“To my knowledge, we haven’t seen a strong push toward batteries,” Johnson said.
Futures Edit too Late?
Clean Grid Alliance’s Beth Soholt made use of the public comment period to call for a rework to MISO’s transmission planning strategy sooner than MTEP 21.
MISO MTEP 19-20 futures (year 2033) | MISO
She pointed to utility integrated resource plans full of renewable goals, carbon-cutting pledges from state governments and a “huge customer preference and demand for renewables” as evidence that MISO cannot afford another year of waiting before it reshapes its future scenarios.
“Over another year, we’re going to use static futures,” Soholt said. “We risk the MISO system not being able to deliver what customers want in the Midwest.”
Soholt cited MISO’s February 2017 interconnection queue cycle, where all but 250 MW of the originally proposed 5 GW of renewable generation projects dropped out because of prohibitively expensive transmission upgrades.
“The processes and the systems in MISO are misaligned to solve these challenges,” Soholt said, calling the RTO’s current planning method and assumptions “frustrating and irrelevant.” She said needed transmission projects are being overlooked because of MISO’s continued underestimation of renewable growth.
Soholt said the $32 million, 345-kV Helena-to-Hampton Corner circuit project, originally identified in this year’s Market Congestion Planning Study, should have made the cut into MTEP 19. The project was set to solve congestion in southern Minnesota, but MISO said that once forecasted wind generation was removed from the equation, the project quickly lost value.
A System from Interconnection Upgrades?
Organization of MISO States President and Missouri Public Service Commissioner Daniel Hall said the RTO is ignoring “substantial” renewable growth and expressed concern over a “number of interconnection projects dropping out very late” in the queue process. He said some renewable projects were already approved by state commissions and under power purchase agreements when they were forced to exit the queue.
“We’re currently trying to plan a transmission system one interconnection at a time. … It’s a wake-up call,” Hall told the board at its meeting Thursday.
“They’re stale,” Moeller admitted of the four futures.
“I think there’s [been] more planning and more discussion over the two years I’ve been here. … I’ve seen more coordination. I really think it’s a case of just because there’s congestion there doesn’t necessarily mean that it warrants a project to correct it,” Johnson said.
ST. PAUL, Minn. — The MISO footprint didn’t come close to its forecasted summertime peak and is unlikely to hit its forecasted fall peak either. But ways to improve resource adequacy in a time of grid transformation were on the minds of those at MISO Board Week here.
Times a-Changin’
MISO’s interconnection queue is further evidence of the urgency of its resource availability and need (RAN) project, Richard Doying, president of market development strategy, told the Markets Committee of the Board of Directors on Sept. 17. RAN ideas currently include a 30-minute reserve product, a resource accreditation rethink, a seasonal capacity auction and a multiday forecast. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)
Based on utility and state announcements, MISO forecasts wind and solar generation will overtake coal and natural gas. By 2030, wind and solar will total 30 to 35% of generation output, while natural gas and coal will have 29% and 24 to 29% shares, respectively. Nuclear’s contribution is projected to be nearly halved to 9%. In 2018, MISO reported a fuel mix of 48% coal, 26% gas, 16% nuclear and 7% wind and solar combined.
Proposed solar projects currently comprise 59 GW of MISO’s 101-GW interconnection queue. Wind generation has a 27-GW share, while natural gas-fired resources represent 9 GW. Storage resources, still nascent in MISO, total only 3 GW. No new nuclear generation is proposed in the queue.
“We do expect to see more storage,” Doying told the board, adding that MISO is particularly anticipating solar-and-storage hybrids.
“I think you can get the whole community behind this,” Director Baljit Dail said, commending the RTO on RAN’s catchphrase, “All hours matter.”
Dail compared it — in rhetoric only — to 2001’s No Child Left Behind Act. Since last year, MISO has said it needs to shift from its one-day-in-10-years loss-of-load expectation to an approach that accounts for different risks across all operating hours.
“We have not considered ‘No Hour Left Behind,’” Doying laughed.
Director Barbara Krumsiek compared the RAN effort to “changing a tire [while] going 60, 70 mph on the interstate.”
Director Trip Doggett asked if NERC appeared to be also shifting from its one-in-10 reliability standard.
“It is something that lots of other folks are looking at,” Doying said.
But WPPI Energy economist Valy Goepfrich was quick to remind leadership that RAN is merely studying whether MISO needs to pivot to an all-hours risk. She said it could turn out that preparations for a summer peak still cover reliability risks in every other operating hour of the year.
“We’re letting the data drive what the peak is,” she told the board.
“It’s still that one hour that we have to meet. The problem is we don’t know when that hour is any more. It used to be a warm day in July or August. Now that’s shifted,” MISO CEO Joh Bear explained at Thursday’s board meeting.
Peak Forecasts Averted
MISO Executive Director of Market Operations Shawn McFarlane predicted that the RTO won’t hit its forecasted 112-GW fall peak, saying the highest risks of September’s heat have passed. (See MISO Unruffled by Fall Supply-demand Outlook.)
“Right now, the highest load we’ve had is 107 GW on Sept. 7,” McFarlane said.
MISO also fell short of its nearly 125-GW forecast summer peak, instead experiencing a 121-GW summer peak July 19.
MISO forecasted portfolio change | MISO
The RTO weathered a heat wave and a hurricane in July without reliability problems. It declared conservative operations on July 18 and issued an open-ended maximum generation capacity advisory effective 10 a.m. ET on July 19 as several Midwestern cities issued excessive heat warnings and heat indexes exceeded 100 degrees Fahrenheit even in Minneapolis. Both alerts were terminated July 20. MISO’s capacity advisories ask members to prepare for emergency conditions, ready load-modifying resources for a possible call-up and ensure resource availability is up to date in the RTO’s communication system.
On July 11, MISO declared a severe weather alert for its Gulf Coast region for July 12 to 15 as Tropical Storm Barry was forming over the gulf. MISO’s weather alerts ask that maintenance and testing on any critical transmission or generation system be deferred or canceled. The alert lasted through July 20 as Entergy mobilized crews to restore power in flooded portions of Louisiana.
Independent Market Monitor David Patton said the most exciting part of the summer occurred in eastern Texas on Aug. 13, when a transformer lost cooling in the West of the Atchafalaya Basin load pocket from 4 to 6 p.m.
“We were extremely close to shedding load; if there had been another contingency…” Patton trailed off.
MISO interconnection queue breakdown | MISO
Prices during the contingency spiked to $560/MWh, but just over the border in sunbaked ERCOT — which was experiencing high load — prices were $8,800/MWh
Patton said the area should have been more appropriately priced at about $4,000/MWh. He added that ERCOT prices had to be attractive to MISO members, who were prohibited from lending supply because of the RTO’s own reliability risks.
“The reliability situation was far more dire in MISO than in ERCOT,” Patton said.
He again called for MISO to “beef up” its emergency and shortage prices, especially for times when portions of the footprint are “on the verge of load shedding.”
“As we grow our intermittent sources, we’re going to see more shortages,” he warned.
The effort to expand CAISO’s Western Energy Imbalance Market from a real-time trading platform to a day-ahead market took a significant step forward Wednesday, when members of the ISO’s Board of Governors and the EIM’s Governing Body said they supported launching a stakeholder process in October.
The first step will be an issue paper. Then the stakeholder process is expected to continue well into next year, said Keith Casey, CAISO’s vice president of market and infrastructure development. It will address issues such as resource sufficiency in a tightening Western market and interstate transmission challenges, ISO staff said.
Board Chair David Olsen and EIM Governing Body Chair Carl Linvill gave their verbal support to the stakeholder process; there was no formal vote. The occasion was a briefing on the results of an eight-month feasibility study of the extended day-ahead market (EDAM).
Fourteen current and future EIM entities, in addition to CAISO, participated in the assessment.
The non-CAISO entities wrote a joint letter to ISO and EIM leaders emphasizing they have not committed to the EDAM and want to make sure it addresses a number of concerns, including the continued independence of the Governing Body and the representation of a range of interests from across the West.
A continuing worry among EIM participants is that California politicians and CAISO might try to dominate the regional market. CAISO’s bid to form a Western RTO stalled in part because CAISO’s governors are appointed by the governor and approved by the State Senate.
“The issues to be resolved to make EDAM a reality should not be underestimated,” the entities wrote. Those that signed the letter included Arizona Public Service, Idaho Power and PacifiCorp.
“Governance structures must be considered that reflect the new market design and the legitimate interests that all within the broader market footprint will have in the operation and rules of the day-ahead market,” it said. “In addition, it is likely EDAM will need to include a test to ensure that all participating balancing authorities are not leaning on neighbors to meet their continued reliability obligations.”
Estimated Benefits
A goal of the feasibility study was to estimate the financial benefits to EIM participants to gauge their potential level of interest, Mark Rothleder, CAISO vice president of market quality, told the board and Governing Body.
The EIM has continued to add new members, but some entities from the interior West have cited the economic bonuses as their primary motivation while lamenting the tie to California. The uneasy political alliance is part of the reason SPP recently launched its own Western Energy Imbalance Service. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
Rothleder said the study group and its consultants, E3 and Brattle Group, had projected the operational benefits of a day-ahead market at $119 million to $227 million annually, which he called a conservative estimate. (In their letter, the EIM entities pointed out that the estimate doesn’t consider how “benefits may be reduced should only a limited number of EIM entities elect to participate in EDAM.”)
The expected financial benefits will come partly through more efficient day-ahead hourly trading and better use of available transmission in an organized market, according to Rothleder’s presentation.
| CAISO
The EIM says its real-time market has saved participants more than $736million since it began in 2014.
A day-ahead market could limit the curtailment of excess renewable resources by up to 2 GWh a year, sending energy where it’s needed and producing tens of millions of dollars in additional revenue for generators, Rothleder said.
Environmentalists have generally supported regional markets as a way to maximize the sharing of renewable resources, for example, by sending wind energy from New Mexico to California and solar power from California to the Pacific Northwest.
Jennifer Gardner, senior staff attorney with Western Resource Advocates and a member of the committee that nominates Governing Body members, praised the move in a news release. Adding a day-ahead market to the EIM would “allow utilities to better plan for and optimize renewable energy use on the grid through more efficient unit commitment and more effective integration of variable energy resources across a larger footprint,” Gardner said.
Sarah Edmonds, transmission director at Portland General Electric, and Jim Shetler, general manager of the Balancing Area of Northern California, were part of the assessment team. They spoke at Wednesday’s meeting and acknowledged the challenges and effects of a day-ahead market that stretches across the Western Interconnection.
“This is going to be significant and complex,” Edmonds said. “It could have consequences for the Western market as a whole.”
EIM Governance Review
The board and Governing Body also named 10 members of a committee to review the governance structure of the EIM, as required by the market’s original charter. (See CAISO OKs EIM Governance Review.)
The charter recognized that the EIM would evolve over time, and the expansion to a day-ahead market could necessitate governance changes, said Stacey Crowley, CAISO vice president of external affairs.
Members named to the Governance Review Committee (GRC) included Gardner; Therese Hampton, chair of the EIM’s Regional Issues Forum and executive director of the Public Generating Pool in the Pacific Northwest; and Eric Eisenman, PG&E’s director of ISO and FERC relations.
Their colleagues nominated Governing Body member Valerie Fong and CAISO Governor Angelina Galiteva as representatives to the GRC.
Board Chair Olsen said he’s hoping to add another member from the EIM’s investor-owned utilities because he felt the committee was light on IOU representation.
The committee will eventually include 11 to 13 members, said Peter Colussy, CAISO manager of regional affairs.
FERC told MISO, PJM and SPP last week that their joint operating agreements don’t provide enough clarity on how the RTOs’ handle generator interconnections along their seams (EL18-26).
The commission agreed in part with EDF Renewable Energy and ordered the RTOs to update their JOAs and Tariffs to make the queue priority process more transparent within 60 days of its ruling Thursday. The commission declined the company’s related request (AD18-8) to expand the review of affected-system coordination in the generation interconnection process beyond MISO, PJM and SPP, however.
“Because the queue priority processes are not described in their tariffs or JOAs, we find that there is a lack of transparency in MISO, SPP and PJM that makes it difficult for interconnection customers to understand how affected-system network upgrade costs are being allocated to them,” FERC wrote. “Requiring the RTOs to detail this information in their JOAs will provide additional transparency to interconnection customers on their potential responsibility for affected system network upgrade costs, thereby reducing uncertainty that may hinder interconnection development.”
| EDF Renewable Energy
The order comes nearly 18 months after FERC staff held a technical conference with the RTOs to address the issues raised in EDF’s October 2017 complaint that their governing documents, particularly the JOAs, lack details about the timing of affected-system analyses, the standards applied to determine impacts from proposed interconnections and how network upgrade costs are assigned. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.
EDF argued that the lack of clarity regarding the RTOs’ delivery requirements and modeling standards violates the commission’s requirement for transparent, open-access interconnection service.
FERC said that despite insistence from the RTOs to the contrary, their existing documents lack transparency and cause “harm due to uncertainty” for EDF and other interconnection customers who struggle with decisions about whether to remain in the queue for fear of incurring unknown costs.
“Cost uncertainty presents a significant obstacle to the development of new resources, as some interconnection customers are less able to absorb unexpected and potentially higher costs for interconnection facilities and network upgrades that may occur once affected-system study results are considered,” FERC wrote. “This lack of transparency in the current affected-systems coordination process between MISO, SPP and PJM has the potential to hinder the timely development of new resources and thereby to stifle competition in the wholesale markets, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.”
The commission, however, rejected EDF’s request that the RTOs unify their modeling systems and study timelines, deeming neither necessary for providing greater transparency.
The RTOs’ compliance filings must include:
Current affected-system coordination processes, including the provision of clear references to where affected-system study information can be found in their business practice manuals;
A description of the modeling standard (external resource interconnection service or network resource interconnection service) they use to study, as the affected RTO, interconnection customers that request ERIS in the host RTO and interconnection customers that request NRIS in the host RTO;
The location in their manuals or other coordination documents where interconnection customers can find the modeling details that they use when studying a project as ERIS or NRIS for interconnection requests on their own systems;
For MISO and SPP specifically, a description of how they study the impacts on the affected RTO and clarify that the each RTO’s study criteria apply to its own facilities;
How the three RTOs monitor each other’s systems during the course of each of their interconnection studies;
PJM’s process for monitoring neighboring systems for affected-system impacts; and
PJM’s timeline provided to interconnection customers to review affected-system study results.
