The D.C. Circuit Court of Appeals on Friday backed FERC in its revised interpretation of a PJM Tariff provision governing responsibility for transmission upgrades, turning aside a challenge by the owner of a power plant in Marcus Hook, Pa. (ESI Energy v. FERC,16-1342).
At issue was whether LS Power Associates, the parent of West Deptford Energy, should be liable for transmission upgrades ordered before the developer entered PJM’s interconnection queue. In 2014, the court vacated FERC’s order ruling the company was liable, calling the commission’s decision “the very essence of unreasoned and arbitrary decision-making.” (See Appeals Court Scolds FERC over West Deptford Interconnection Dispute.)
West Deptford (N.J.) energy plant under construction| MJ Electric
West Deptford submitted its interconnection request on July 31, 2006, and was later informed it would be assessed $10 million for improvements PJM ordered as a result of two previous projects, FPL Energy Marcus Hook and Liberty Electric.
Tariff Change
Under section 37.7 of the PJM Tariff then in effect, the RTO could seek reimbursement for a previously constructed network upgrade if the new proposed project used the added capacity created by the project or would have required it itself. The reimbursement request only applied if the cost of the upgrade was at least $10 million and it was placed in service no more than five years before the interconnection customer’s queue closing date.
If section 37.7 controlled, West Deptford would have been required to reimburse Marcus Hook and Liberty Electric for the upgrade. (Ninety percent of the upgrade’s cost had initially been assigned to Marcus Hook.)
In 2008, however, while West Deptford’s interconnection request was pending, PJM won approval for an amendment changing the assignment of responsibility for prior upgrades. Section 219 of the revised Tariff allowed PJM to seek reimbursement for previously constructed upgrades for only five years “from the execution date of the interconnection service agreement for the project that initially necessitated” the upgrade.
FERC initially ruled that West Deptford must pay, concluding that the 2006 rules applied. But the court said FERC’s ruling “provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”
FERC Reversal
In response to the remand, FERC in August 2016 reversed its ruling, relieving West Deptford of the reimbursement obligation (ER11-4073). FERC said it based its decision on the “significant skepticism” the D.C. Circuit expressed in the remand order and the “numerous shortcomings” the court identified in the commission’s analysis.
Marcus Hook appealed, saying the old rules should apply to West Deptford and challenging FERC’s interpretation of the five-year trigger under the new rules. (Florida Power & Light subsidiary ESI Energy was later substituted for Marcus Hook as petitioner.)
In siding with FERC, the court said the commission “directly and adequately addressed” Marcus Hook’s challenges to the determination that section 219 applied.
FERC was required to provide a “reasoned explanation” of how applying section 219 comported with the Federal Power Act and commission precedent, the court noted. “Unlike its prior decision, the commission’s decision on remand did both,” it said.
5-Year Trigger
Although section 219 did not specify what action was required within the five-year window to trigger cost responsibility, FERC said the most reasonable interpretation was that the “end date” was that on which West Deptford signed its interconnection agreement.
Marcus Hook argued that section 219 made an interconnection customer liable for an upgrade that entered service during the five years preceding the customer’s queue entry. It said the dispositive date should be either when West Deptford submitted its interconnection request (July 31, 2006) or when PJM determined that the upgrade was required for its interconnection (November 2006).
“Although Marcus Hook’s suggested interpretation is a possible reading of the Tariff provision, it is no more reasonable than the one the commission put forward,” the court ruled. “Accordingly, we find that the commission did not err in its interpretation of section 219 of the revised Tariff.”
FALMOUTH, Mass. — New England is up to the task of managing the tough challenges facing its wholesale market and grid — even if there is no grid in the future, regional energy experts said last week.
“The feds are less important now, and New England used to live by its wits — we never had oil or gas — but now we’ve got offshore wind,” Douglas Foy, president of energy consultancy Serrafix, said Monday at the 25th annual New England Energy Conference and Exposition. The event is hosted jointly by the Northeast Energy and Commerce Association and the Connecticut Power and Energy Society.
Looking back on the era of restructuring electricity markets in the 1980s and 90s, “the most significant feature of those times was a collaboration between government, private industry and environmentalists,” said Foy, formerly both a secretary of commonwealth development in Massachusetts and president of the Conservation Law Foundation. “There were a bunch of very smart players all trying to get to a common goal.”
“That’s a remarkable thing and quite a contrast to what we see today,” said David O’Connor, senior vice president for energy and clean technology at ML Strategies. “The way our country is polarized now, it’s harder to imagine collaboration.”
Fletcher School professor Barbara Kates-Garnick, a former Massachusetts undersecretary of energy, said the challenge today is to recreate that collaborative dynamic: “I think it was both trust, collaboration and a recognition of the need to address looming issues that contributed to our willingness to tackle different problems in a collaborative rather than adversarial fashion, as is the mode today.”
“Energy efficiency created an environment where now it’s so successful, so prevalent, we’ve levelized the demand that used to be growing inexorably every year,” O’Connor said.
Paul McCary, of law firm Murtha Cullina, said the financial incentives of wholesale markets helped form the consensus to try something different, which brought lower-cost power.
“But restructuring the electricity market was not done to face the problems we have today,” McCary said, adding that deregulation didn’t address the resource mix.
“There are a couple layers to the challenge — the state/federal split, for example,” McCary said. “Can you tweak and tweak the market until you get there? I question how many ornaments you can hang on the FERC market-structure tree. The 90s were more simple politically — today is a bigger challenge.”
“Screw the feds,” Foy said. “I’ll always bet on New England.”
Speaking on the second day of the conference, Peter Kelly-Detwiler of Northbridge Energy Partners said the industry can thank the Trump administration for bringing resilience to the fore, both with last fall’s Notice of Proposed Rulemaking and the president’s June 1 order directing the Department of Energy to maintain uneconomic coal and nuclear plants. (See FERC Blindsided by Half-Baked Trump Order.)
“On climate change, irrespective of one’s political beliefs, science is science, and it ain’t going away,” Kelly-Detwiler said. “I used to think that if I put my hands over my eyes, nobody could see me, but I was 3 when I thought that.”
Kelly-Detwiler looked to the future, imagining what the energy space will be in 2050, and said experts are not good at forecasting, as evidenced by looking back to 2001 at anticipated electricity sales, solar penetration or natural gas production.
“Why? Because all our forecasts are based on what we know, not on what we don’t know, and on what trends are accelerating and why they’re accelerating,” he said. “We have to start thinking about what that new dynamic looks like and have that inform our future forecasting.”
NASA for several years has been delivering power to an experimental aircraft via laser. “Let’s fast-forward to a grid in 2050,” he said. “We can send energy to a plane with a laser right now, and we have 32 more years of high-performance computing that’s going to accelerate its ability to solve problems for us. One question that would be worth asking is: Do we have a grid at all?”
“Even if we transition the electric power sector to zero-carbon electricity today, we still would still not be able to meet even the 2030 goals [40% greenhouse gas reduction],” said Courtney Eichhorst, lead analyst for regulatory strategy at National Grid. “Clearly the challenge is in two sectors: transportation and heating.”
Michael Sloan, managing director of natural gas for energy services company ICF, said public policy should be set with an eye to the future, especially regarding electrification of the residential sector.
“First of all, would residential electrification reduce carbon emissions? It’s not clear. What are the impacts on the grid? What are the impacts on consumers, on voters? We’ve seen policy changes that hurt consumers lead to a change in government in Ontario,” he said.
“Policy-driven residential electrification would be a very expensive approach to reducing greenhouse gas emissions,” Sloan said. “We should look at the most efficient ways to reduce emissions first, and let the market decide how best to meet residential heating load, at least until the less expensive approaches to reducing GHG emissions have been exhausted.”
On the issue of eliminating the internal combustion engine and turning to electric vehicles, Matt Solomon, transportation program manager for the Northeast States for Coordinated Air Use Management, said “there are so many advantages, so many ways that driving electric is a better experience for the consumer,” and people “get it” in one drive.
“States aren’t the best communicators … but Massachusetts is the first state to have actually put money into putting on test-drive events,” Solomon said. After an event targeted at high-earning, tech-savvy people, 68% of participants say they are more likely to buy an EV, he said.
On residential distributed energy resources, Ian Schneider, a Ph.D. candidate at the Massachusetts Institute of Technology, said that tariff design has to match the grid reality.
“If we don’t design the markets correctly, then outdated tariffs will leave this energy revolution to not necessarily benefit all customers,” Schneider said.
DERs are disrupting an already outdated rate design, he said. MIT’s Energy Initiative identified four obvious inefficiencies with current rate designs: They’re neither time-based nor location-based, and “they tend to recover fixed costs volumetrically, so the utility is recovering fixed costs for previous expenses” on a per-kilowatt-hour basis.
As those who can afford solar panels consume less of the utility’s power, lower-income people are forced to pay a higher percentage of those fixed costs, which is inherently unfair, he said.
The fourth inefficiency: that the rates don’t account for capital investments going forward, “so in a world where the marginal cost of producing electricity is very low, but capacity costs, both for the distribution system and for generation, can be very high, it becomes more important to think about coincident peaks and how consumers are driving peak costs on the system,” Schneider said.
Daniel Allegretti, Exelon vice president for state government affairs in the East, said there is a continuing tension between the utility and competitive paradigms.
Philip O’Connor, president of energy consultancy PROactive Strategies, said flat load, disruption of traditional generation economics and digital deployment are driving the electricity industry toward a second wave of competitive restructuring.
“We’ve had a decade in this country in which overall electricity consumption, served by the grid, has not increased,” O’Connor said. “The entire business model and the regulatory scheme for the traditional, vertically integrated utility, and for the wires-only company, is predicated on the idea of growth and expansion.”
Digital deployment leads to one big thing — customer sovereignty, he said. “Unfortunately, the structure of the industry, especially the vertically integrated part, stymies that development. So what are we left with? We have rising fixed costs, particularly in the monopoly environment, but flat sales, so you’ve got to keep raising the price.”
Brian Conroy, Avangrid director of network projects, said, “We see ourselves as a platform provider, and our collection of projects will deliver the platform and functionality envisioned for a future marketplace and a future grid operating environment.”
Public policy for reducing greenhouse gases or increasing the use of renewables usually means starting demonstration projects, he said.
“As we plan the future, everything we do … for least-cost planning, we have to look at what are the non-traditional alternatives,” Conroy said. “We see ourselves as a smart integrator, pulling all these diverse things together with a very smart or intelligent platform … to squeeze the value out of the distributed energy resources to get the most for our customers.”
The smart grid might outsmart the customer, according to Harrison Grubbs, director of strategic partnerships at marketing firm KSV. The firm surveyed people on their attitudes on renewable energy and found that utility customers don’t think much about their energy use.
“We wanted to drill down and get an understanding, what exactly customers do know and where those opportunities are,” Grubbs said. “We asked customers where does the majority of their electricity come from. Thirty percent said they don’t know. We also found that 27% of customers in New England believe that the majority of their electricity comes from coal and oil.”
FERC OKs Reliability Standard on Fault Protections
By Rich Heidorn Jr.
FERC last week gave final approval to NERC reliability standards on training requirements and the coordination of protection systems to detect and isolate faults (Order 847, RM16-22).
Standard PER-006-1 (Specific Training for Personnel) sets training requirements for real-time operations personnel to ensure they understand the purpose and limitations of protection systems schemes. It also adds more precise and auditable requirements, FERC said.
PRC-027-1 (Coordination of Protection Systems for Performance During Faults) seeks to ensure protection systems operate in the intended sequence. It requires applicable entities to perform a protection system coordination study to determine whether the systems are operating in the proper sequence during faults or compare present fault current values to an established fault current baseline. In the latter case, a coordination study would be required only if there is a 15% or greater deviation in fault current values. The reviews are required every six years.
The commission’s June 7 order also approved new and revised definitions for three terms: protection system coordination study, operational planning analysis and real-time assessment.
FERC, however, rejected a proposal in its Notice of Proposed Rulemaking to modify PRC-027-1 to require an initial protection system coordination study as a baseline, bowing to complaints by NERC and others.
NERC said that although the requirement could help reduce misoperations caused by a lack of coordination, it would be costly and burdensome. The reliability organization said it “expects that many entities will choose to do a full protection system coordination study … for their more impactful [bulk electric system] elements” and that “it is highly likely that the overwhelming majority of entities have already conducted coordination studies for their protection systems.”
FERC said it agreed that applicable entities will conduct studies on their significant facilities even without the requirement.
“We recognize the concern that were the NOPR directive adopted, applicable entities could be required to rerun protection system coordination studies for the sole purpose of generating compliance documentation, even if such entities already performed protection system coordination studies that remain valid but lack documentation to substantiate compliance,” the commission said.
FERC on Tuesday rejected a Michigan request for a stay of a previous order approving MISO’s refund report related to a system support resource (SSR) on the state’s Upper Peninsula.
The Michigan Public Service Commission joined with multiple load-serving entities in the state to request a stay of the surcharges associated with MISO’s 2017 refund report, arguing that a FERC-ordered reallocation of the SSR costs for the Presque Isle coal plant amounted to retroactive ratemaking.
Presque Isle Power Plant
But FERC determined that the requestors “will not suffer irreparable harm absent a stay” of the reallocation of costs to cover the unprofitable but necessary operation of the plant in 2014 and 2015 (ER14-2952-005).
The PSC and many of the same load-serving entities are also party to an ongoing D.C. Circuit Court of Appeals case challenging FERC’s 2015 order directing MISO to reallocate SSR costs to LSEs that required the SSR for reliability, instead of to all LSEs in the American Transmission Co. pricing zone on a pro rata basis. The groups argue the reallocation requires Upper Peninsula ratepayers to cover a disproportionate 98% share of the SSR costs, which Wisconsin ratepayers should help defray. (See Michigan Groups Contest Presque Isle Cost Allocation.) MISO’s 2017 surcharge report includes cost reductions from a FERC-ordered $24.6 million refund, after the commission decided Presque Isle owner Wisconsin Electric Power Co. overcharged ratepayers for the two SSR agreements.
The Michigan groups contended that, absent a stay, the refund process would become too complex, especially if FERC’s reallocation order is reversed. They also said relocation of customers complicates the refund process.
“ … It would be impossible to ensure that the surcharges imposed by MISO are billed to the retail customers who received service during the surcharge period in 2014, and it would be impossible to ensure that any future refunds received by load-serving entities from MISO are credited to the same customers who paid the surcharges,” they said.
But FERC said overseeing the surcharges after reallocation and refund, while challenging, is not impossible. The commission also said the parties’ “irreparable harm” argument does not hold up, since corrective relief could be ordered by the D.C. Circuit.
“The difficulties alleged by the Michigan parties are typical of the challenges that jurisdictional entities must overcome to implement the commission’s remedial actions,” FERC said. “ … Nothing the Michigan parties have argued has shown that issuing a stay is required by the public interest.”
FERC also said the Michigan parties could not prove the surcharges amounted to retroactive rate increases, noting the commission has “broad equitable discretion in determining whether and how to apply remedies in any particular case.”
BOISE, Idaho —The budding efforts to make U.S. marijuana operations more energy efficient will become increasingly critical as the commodity grows into a global market, energy industry experts — including one state utility commissioner — said Monday.
“Cannabis is already a $10 billion industry and is becoming a global marketplace,” Derek Smith, founder and executive director of the Resource Innovation Institute, said Monday at the annual meeting of the Western Conference of Public Service Commissioners (WCPSC). The Portland, Ore.-based non-profit works with utilities and growers to improve energy efficiency and develop standards.
With extensive lighting and HVAC requirements, the marijuana industry currently represents about 1% of electricity demand in the United States. Growing facilities that are not energy efficient can have up to eight times the energy impact of regular buildings.
“The energy impacts are really all over the board, they are broad, and they are pretty large … it is something to keep track of,” Smith said.
Cannabis cultivation is one of the most rapidly changing markets in the world, emerging from the shadows of what was formerly a black market. Growers tend not to trust utilities and the government, he said, as pot is still illegal at the federal level. But a “LEED for weed” certification will eventually be developed, according to Smith.
Marijuana has been legal since 2012 in Washington State, where it is now the third largest agricultural commodity after apples and milk, Washington Utilities and Transportation Commission Chairman Dave Danner said. Sales in the state were $1.4 billion last year, yielding tax revenues of about $312 million.
“It has had quite an impact in our state,” Danner said. “It has required our utilities to take a specific interest in it, and for that reason we are interested in it as well.” Industry participants have expressed concern about the longevity of pot-growing operations, raising the question of whether utilities could end up investing in assets that will later be abandoned, such as substations or feeder lines.
“What we are seeing now is that these companies are pretty stable,” Danner said. “It is going pretty well.”
Another concern: that growing and possessing marijuana is still illegal at the federal level, raising the question of whether the operations might be raided and shut down. Attorney General Jeff Sessions has stated publicly his desire to go after the industry, but so far that has not happened.
State and utility officials have questions about how to extend state energy efficiency programs to marijuana growers in this environment, but many efficiencies could be captured in lighting and HVAC, Danner said. Avista Utilities and Puget Sound Energy have developed incentives and rebates for growers to adopt more efficient lighting, he said. Advanced metering infrastructure will also make it easier to identify illegal growing operations, which still proliferate and use a lot of energy, he said.
“There is also still, in all of your states and mine, an illegal marijuana industry,” Danner told fellow commissioners.
At a separate panel discussion, Linda Gervais, Avista Utilities senior manager of regulatory policy, said dealing with pot growers was something “we didn’t see coming.” Even large growers get paid in cash and don’t bank in traditional ways because of federal illegality. Large growers can have monthly bills of $30,000 to $40,000, and one grower brought his payment in to the utility’s office in plastic garbage bags. The utility has had to buy a cash counter, hire a security guard and hire an armored truck to haul the money.
“It has been a challenge, but I think we have a really good process in place now because we learned how to adapt,” said Gervais.
WASHINGTON — A senior Department of Energy official told Congress on Thursday his agency has no estimates on the cost of the coal and nuclear power bailout President Trump ordered last week, as Democrats blasted the proposal.
Trump directed Energy Secretary Rick Perry last Friday to force grid operators to provide a lifeline to struggling coal and nuclear plants, saying their retirements threaten national security. Trump’s directive came after the leak of a 40-page draft DOE memorandum that cited the Defense Production Act of 1950 and Section 202c of the Federal Power Act, which allows the energy secretary to issue emergency orders during energy shortages.
The memo proposed creation of a “Strategic Electric Generation Reserve (SEGR) to promote the national defense and maximize domestic energy supplies.”
Walker
Rep. Don Beyer (D-Va.) confronted DOE Assistant Secretary Bruce J. Walker over the directive at a hearing of the House Committee on Science, Space, and Technology’s Subcommittee on Energy on Thursday. Walker, head of the Office of Electricity Delivery and Energy Reliability, responded tersely.
Beyer asked Walker about his pledge at DOE’s Electricity Advisory Committee meeting on Feb. 20 that “‘We would never use a 202 to stave off an economic issue. That’s not what it’s for.’”
Beyer
“And now, FirstEnergy Solutions has recently asked that the department use a 202 to stave off an economic issue,” Beyer continued. “Do we understand that you won’t use a 202 for them?
“The 202 application from FirstEnergy is being reviewed by my department as we speak,” Walker responded poker-faced.
Beyer quoted the president of the Electricity Consumers Resource Council (ELCON), who said the DOE memo’s proposed requirement that RTOs purchase capacity and energy from at-risk plants would “devastate” U.S. manufacturing.
“Have you calculated the costs on American business, specifically American manufacturing?” Beyer asked.
Beyer then cited ELCON’s estimate that DOE’s earlier Notice of Proposed Rulemaking to provide cost-of-service payments to plants with on-site fuel — made under Section 403 of the Department of Energy Organization Act — would cost $8 billion annually in PJM alone.
“Now the new plan nationalizes the 403 proposal, so I would expect that $8 billion is going to go up very significantly,” Beyer said. “In putting together this draft plan have you estimated what this will cost the U.S. taxpayer?”
Walker: “I have not.”
“I have to give you wonderful credit for being able to answer these things very, very tightly,” Beyer responded. “I would suggest though … this is something that you and Secretary Perry and others look very seriously at and should have numbers available for. I think it’s within my purview as a member of this committee to ask you to go back and do the elementary research and report back to the committee on those two things please.”
Walker said nothing, his expression unchanged.
Once the hearing had ended, Walker hurriedly left the room and did not make himself available for questions from reporters.
‘False Narrative’
Beyer yesterday sent Perry a letter, co-signed by more than 30 Democrats, asking the Trump administration to “cease the false narrative that bailing out uneconomic energy sources in competitive markets is needed for electrical grid resilience.”
Republican leaders of the committee made no reference to the order at the hearing, the topic of which was grid modernization. Ranking member Marc Veasey’s (D-Texas) opening remarks, however, focused on the bailout order.
“The Trump administration is inventing emergencies to bail out coal and nuclear plants, while ignoring the real problems,” Veasey said. “I’m sure the White House views this legal loophole that surfaced … as an easy way to try to fulfill campaign promises, which is very bad and very unsound when it comes to energy policy. … It would wreak havoc on our energy markets and create a number of misaligned incentives.”
Rep. Paul Tonko (D-N.Y.) noted that he had worked with Walker on deregulating New York’s electricity markets. He acknowledged the markets are not perfect, “but in 2018, the toothpaste is out of the tube, and drastic and unnecessary market interventions under the false pretense of an emergency to bail out uncompetitive generators like ones being discussed by the administration I think are unacceptable.”
Gramlich
Also testifying at the hearing was energy consultant Rob Gramlich, former economic adviser to former FERC Chair Pat Wood III.
Gramlich said the directive ignores coal and nuclear plants’ cyber risks, vulnerability to droughts and lesser ability than wind plants to ride through frequency deviations. “Fifty-year-old plants have outage rates that are typically three times as high as new plants,” he added.
“All technologies …. have their strengths and weaknesses and contribute to reliability and resilience in different ways, but none of them are essential,” he said. “Reliability comes from having reserves. In fact, each region already has a Strategic Generation Reserve. It’s called a reserve margin.”
Retirements Discussed at FERC-NRC Meeting
Nuclear and coal plant retirements also were the subject of a joint meeting Thursday morning of FERC and the Nuclear Regulatory Commission at FERC headquarters.
Mark Lauby, NERC’s senior vice president and chief reliability officer, discussed his organization’s concerns about the loss of “conventional” generation and the increase in renewables and natural gas.
“When you look in certain areas and you’ve got 60 to 70% of their fuels [being procured] on spot [markets], it makes me worried that we have a risk there that we have to start thinking about addressing,” he said.
But he said “firming up” fuel supplies is more important than fuel diversity. “Diversity really is only extremely helpful when you deal with things like Aliso Canyon, Fukushima, coal strikes. Diversity is helpful when you have those kind of unusual type events.”
FERC Commissioner Richard Glick noted that nuclear plants can’t provide frequency response, ramping or load following.
FERC Commissioner Rob Powelson asked if there was any validity to complaints that NRC’s regulations are unduly burdensome and could be contributing to plant retirements. “Is that fake news?” he asked.
NRC Chairwoman Kristine L. Svinicki said for the nuclear retirements to date, “I think we could have radically changed our regulations. It would not have been enough to change the business case and the decisions to shut those units down. … I’ve seen a little bit of the profit and loss statements, and I don’t know what on earth the regulators could have done that could have saved those units.”
CARMEL, Ind. — MISO’s supply picture for the next five years is less rosy — and less clear — than it was a year ago, according to an annual capacity survey released Friday in conjunction with the Organization of MISO States.
This year’s OMS-MISO resource adequacy survey projects that the RTO’s 2019 spare capacity will exceed its regional requirement by anywhere from 0.6 to 6.6 GW, yielding a reserve margin ranging from 17.6 to 22.4%.
OMS MISO 2018 survey results | MISO
But survey results show the volume of spare supply after next year is less certain, owing to expected decreases in resource commitments, although it’s still possible the RTO’s excess capacity could outpace the high end of its 2019 prediction through 2022. Using the current 17.1% planning reserve margin, over the next five years, MISO’s footprint could see anything from a 7.5-GW surplus to a 4.5-GW shortfall:
In 2020, MISO could have anywhere from a 7.3-GW surplus (representing a 22.9% planning reserve margin) to a 0.1-GW shortfall (a 17% reserve margin).
In 2021, the RTO could experience anywhere from a 7.5-GW surplus (23%) to a 0.9 shortfall (16.4%).
In 2022, the chance of a shortfall increases, with a range between a 7.5-GW surplus (23%) and a 2.3-GW shortfall (15.3%).
In 2023, MISO’s possible high-end capacity surplus drops to 6 GW (21.8%), while the possible shortfall could reach 4.5 GW (13.5%).
Last year’s survey showed MISO would have anywhere from 2.7 to 4.8 GW of excess resources from 2018 to 2022, translating into a 16 to 22% reserve margin because of lower demand forecasts and a lukewarm growth rate of 0.5%, down from 0.8% in 2016. (See Capacity Survey Shows MISO in the Black.) In this year’s five-year outlook, the regional growth rate again decreased from 0.5% to 0.3%. MISO said 97% of load responded to the survey.
“While we continue to see decreasing demand in the MISO footprint, the story continues to be the evolving generation portfolio,” MISO CEO John Bear said in a statement. “As the MISO footprint continues to transform, we must learn to adapt in areas such as our transmission planning studies, market-based solutions that focus on speed and flexibility and enhancing coordination with our neighboring seams partners.”
During a June 8 conference call to discuss results, MISO Executive Director of Resource Planning Patrick Brown acknowledged that this year’s survey shows more risk to resource adequacy than projected last year.
“The main driver of this resource adequacy risk are generation retirements,” Brown said, adding that more retirement announcements have occurred since MISO and OMS collaborated on the 2017 survey, resulting in about 4.6 GW of decreased resource availability. The RTO said the majority of potential deficits are concentrated in Illinois’ Zone 4 and Michigan’s Zone 7. Brown noted the resource adequacy risk is higher because the RTO predicts it will require higher future reserve margins because of its increasing forced outage rate.
But Brown also pointed out that the survey represents a “snapshot,” and that more capacity than currently expected could come online to offset retiring generation.
“MISO fully expects this forecast to change going forward,” he said.
Zones with surplus capacity can help neighboring zones with capacity deficits, Brown added.
“Zones with deficits do not automatically face a reliability risk,” he said.
But by 2023, zones enjoying surpluses may not be sufficient to entirely cover possible capacity deficits in three zones. By that year, the survey showed Zone 4 could face either a 1.1-GW capacity surplus or a 2.8-GW capacity shortfall, while Zone 6 in Indiana and Kentucky could experience anywhere from a 0.3-GW surplus to a 1.6-GW shortfall. Zone 7 faces the most certain shortfall, ranging between 0.8 and 1.8 GW.
Brown said MISO’s current 93-GW interconnection queue contains 80 GW of renewable energy, with just 580 MW of storage in the works to make renewable capacity more dependable. However, he said, MISO fully expects more storage to enter the queue in the future.
“It’s particularly import that we’re doing this in light of the evolving resource mix,” OMS Executive Director Tanya Paslawski said of the survey.
This year’s survey relied on a new calculation for estimating the volume of future new resources. MISO tallied projects not yet in the three-part definitive planning phase (DPP) of its interconnection queue (and those having entered the DPP’s first phase) at a 10% completion rate. Conventional and intermittent resources in phase two of the DPP were counted at 50% and 25%, respectively, which increased to 75% and 50% in phase 3. Projects still negotiating a generator interconnection agreement were tallied at 90% completion, while those with signed agreements were counted as new generation in the survey’s weighted averages. (See MISO RASC Briefs: Little Change to Capacity Forecasts.)
MISO staff will present a more detailed rundown of OMS-MISO survey results at the RTO’s July 11 Resource Adequacy Subcommittee meeting.
BOISE, Idaho — Two top federal energy regulators told state utility commissioners that they will take a light-handed approach as the West develops new market structures, allowing flexibility and acknowledging regional differences.
Long-time FERC Commissioner Cheryl LaFleur, and Richard Glick, who joined the commission in November, made their remarks to state regulators and industry representatives at National Association of Regulatory Utility Commissioners’ Western Conference of Public Service Commissioners (WCPSC).
LaFleur on Monday noted that dramatic shifts have taken place in the West just this year, with membership changes at Mountain West Transmission Group and competing market proposals from CAISO and Peak Reliability/Multiple Entities, Markets Now Beckon in West.)
“I think the West is the biggest story of 2018, just because of the level of interest and the number of changes,” LaFleur said. She told Idaho Public Utilities Commission President Paul Kjellander that she is “trying to send positive vibes out to the West” and “a warm current of support.”
She acknowledged that when it comes to federal oversight of the West, the California energy crisis and opposition to FERC’s Standard Market Design are still on people’s minds. There are also concerns among Western states about increased regulation by FERC during the administration of President Trump.
“Anything that happens cannot be driven from Washington, D.C., because we tried that, and it really failed,” she said, adding that “we are trying to not make it a FERC thing — it doesn’t really matter what we want.”
She said the West “seems to be in a very dynamic place right now.” The commission’s default answer on Western market integration proposals should be “yes, you can do things differently, unless there is something that is going to be wrong for customers and not just and reasonable.”
Appointed in 2010, LaFleur has worked alongside 11 commissioners and is a former chairman and acting chair. Kjellander asked what lessons LaFleur had learned during her time, which last year included a stint as the sole commissioner.
“I definitely have had a very unusual run,” LaFleur said. “It’s really been a magical mystery tour.
“One my little aphorisms is that life is a movie, not a snapshot,” she added. “Things change.”
She acknowledged changing political headwinds in the transition from President Barack Obama to Trump. “I really wanted to stay through and come out the other side and be happy, and I have,” she said. “I love the work.”
She said that the current FERC membership is still finding its center as a body.
FERC’s newest challenge is Trump’s June 1 directive to Energy Secretary Rick Perry to prevent further nuclear and coal plant retirements. The announcement was a major topic among attendees at the conference. LaFleur in comments to RTO Insider indicated a wait-and-see approach on the directive. (See More Questions than Answers for FERC, RTOs on Bailout.)
Glick Discusses Regionalization, Tx Incentives
Glick told the conference that when it comes to FERC’s regulation of the West, “more of a hands-off approach is best.”
He took to the stage on Tuesday under emergency lighting, with no microphone or sound system as a local substation problem had the Boise Centre operating with backup generators.
“Obviously, if we just had more coal and nuclear plants, this wouldn’t be happening,” Glick joked as he opened his speech, drawing laughter from the state officials in the audience. Power was restored during his comments.
Glick noted that when he was at the Department of Energy, he spent a year and a half working “almost exclusively” on the Western Energy Crisis, which he called “an interesting learning experience.” He also worked for PacifiCorp, Iberdrola (now Avangrid Renewables) and for Sen. Maria Cantwell (D-Wash.) as counsel to the Senate Energy and Natural Resources Committee.
“We are in an incredibly interesting time in the energy industry right now,” Glick said. There have been benefits to the rapid change, he said, including more choices for consumers, lower costs and cleaner energy resources.
“That doesn’t mean there aren’t some challenges,” he said, mentioning integrating renewables and the “duck curve” in California, communities being affected by coal and nuclear plant closures, and difficult issues around Western market regionalization.
He noted that benefits of the Western Energy Imbalance Market are multiplying, the market is growing and “it seems to be working very well.” But he added that “I am very aware of the politics vis-a-vis FERC and the Western states,” mentioning hostility toward Standard Market Design, and lingering mistrust between California and other Western states. Glick said his approach at FERC will be to support regionalization, but “we need to be as deferential as possible.”
“If we push the envelope, given the history of FERC and the West, that might not necessarily work out the best for anybody,” he said.
Glick also reiterated his call for FERC to review its policy on transmission incentives. “I’m not sure we are really incenting the right thing,” he said, noting that FERC routinely grants return on equity bonuses for participation in an RTO or ISO.
“I think the argument is they would be in an RTO or ISO anyhow.” He said FERC should be encouraging “right-size” transmission and using existing transmission more efficiently.
RENSSELAER, N.Y. — NYISO continues to propose a cost-levelizing approach for allocating carbon charge residuals to load-serving entities, it told New York’s Integrating Public Policy Task Force (IPPTF) and stakeholders on Monday.
The ISO’s preferred approach would have suppliers embed the carbon charges into their all-in day-ahead and real-time energy offers, as they currently do with emissions costs under the Regional Greenhouse Gas Initiative, as it presented to the task force in April. (See NY Task Force Briefed on Carbon Charge Mechanics.)
The June 4 allocation discussions were part of issue Track 2 in the group’s five-track effort to price carbon emissions into New York’s wholesale electricity market.
Progress Review
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, reviewed the task force’s progress in meeting almost weekly every Monday over the past eight months. She said the group is on track to deliver by December either a proposal to incorporate the cost of carbon into the wholesale market, provide a detailed schedule to complete the proposal next year or notify the task force if it concludes that the plan is not viable.
A draft proposal is slated to be delivered Aug. 1, Bouchez said.
“It is absolutely critical that we move quickly to get to a point of either this is going to happen or this is not,” said Mark Younger of Hudson Energy Economics. “We need clarity on that as soon as possible so that if it’s not going to happen, we can proceed with other things that will.”
Couch White attorney Kevin Lang, representing New York City, asked why stakeholders needed to move quickly.
“Because we have a serious problem with a substantial mismatch between public policy actions and our markets, and it is causing severe damage in our markets,” Younger said.
“No, that’s your view that there’s a mismatch,” Lang said. “The [Public Service Commission] is adhering to its public policy, which it has every legal right to do. You may not like the result, but that doesn’t mean we need to move very quickly on this issue, which is not yet fully developed.”
Fair Cost Burden
Locational-based marginal prices would increase according to the emissions rate of the marginal, price-setting resources — the marginal emissions rate (MER).
“As a result of load paying the full LBMP for their energy withdrawals, and suppliers not receiving the full LBMP for their energy generation — then being charged for their carbon emissions — there is an imbalance between bills and credits,” said ISO staffer Nathaniel Gilbraith. “This imbalance is what we’re calling a residual, and it’s going to be returned to loads using one of the methods we discuss today.”
| NYISO
The ISO’s presentation Monday detailed three approaches to allocation of residuals: load ratio share, cost levelizing and proportional allocation, with the latter two based on the carbon effect on each zone’s LBMPs.
The load ratio share results in all LSEs receiving the same refunds on a dollar-per-megawatt-hour basis, causing greater differences in the net cost of carbon pricing. On the plus side, it would provide LSEs with price signals more reflective of the carbon intensity of their consumption.
Cost levelizing produces the most similar cost burden in terms of dollars per megawatt-hour of carbon charge, but it also limits the differential price signal to reduce consumption, Gilbraith said. Zones with high MERs would not necessarily see an incentive to reduce consumption relative to those with lower rates.
Proportional allocation would return carbon charge residuals to all LSEs based on the proportional effect carbon prices have on their gross energy payments. It would return more revenues to LSEs facing higher dollar-per-megawatt-hour cost impacts but would not go as far as levelization.
The ISO said this provides some balance between economic efficiency and equity of cost burden by maintaining some of the differential price signals to encourage reduced consumption and emissions.
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In its 2025 base case analysis, the ISO said downstate LSEs would face the highest net increase in energy payments (carbon payments minus residuals) under the load ratio share (8.93 cents/kWh) and the lowest under levelizing (8.96 cents/kWh).
The impact on upstate would be reversed: 6.57 cents/kWh under load ratio and 6.71 cents/kWh for levelizing.
Gilbraith added that the analysis did not cover allocation by LSEs to retail customers, which would be under PSC jurisdiction.
Lang said he understood not considering retail allocation but noted that the ISO assumed that a carbon charge would affect the price of renewable energy credits, which is entirely under PSC jurisdiction. “So why are you picking and choosing which area of PSC jurisdiction you’re going to intrude into and which parts you’re not?” he said.
Michael DeSocio, the ISO’s senior manager for market design, said the ISO is working “to make sure that if a market-based carbon pricing effort like this would move forward, that future determination of RECs and other products like that could be adjusted to consider that alternative. … We’re filing comments [with the PSC] regarding ORECs [offshore wind RECs] on how a contract structure could work with a carbon pricing mechanism [to] minimize any double compensation.”
Topics for discussion include whether residuals allocated to an LSE should be allowed to exceed that entity’s gross carbon payments and what criteria stakeholders are looking for in terms of equity vs. cost burden.
Status, Schedules
The ISO in May began running the task force, which it set up last year in partnership with the state’s Department of Public Service.
The straw proposal assigned to issue Track 1 was delivered on April 30 and reviewed by stakeholders May 14, and therefore will be closed, said Bouchez.
Track 2 focuses on the market mechanics of a carbon charge and has so far had the broadest range of topics covered of any track, Bouchez said. The IPPTF will discuss the track on June 18 and July 9, and the schedule has five open Mondays through October in case the group needs more time on it.
Track 3 covers how a carbon charge should be set and adjusted for the Track 5 customer impacts analysis. No additional work has been scheduled on Track 3 since DPS staff and a stakeholder both presented recommendations for setting the carbon charge, which is ultimately the responsibility of the PSC.
Track 4 focuses on a carbon charge’s interactions with other state policies and programs, and there is no additional work currently scheduled. The group plans one more meeting on Track 5 customer impacts analysis before starting the base modeling work. The group will also meet to review assumptions used in the “dynamic change case” analysis, with stakeholder review in September and October, Bouchez said.
The task force next meets June 18 at NYISO headquarters to address Track 5 assumptions and scenarios on customer impacts, and wholesale market processes under Track 2.
Electric storage resources (ESRs) 100 kW or larger would be eligible to offer capacity, energy and ancillary services under a straw proposal MISO officials presented to stakeholders Wednesday.
The Market Subcommittee will take the lead on six of the issues:
definition, elements and modeling, including minimum size requirements;
market participation (bid parameters, offers, commitment and dispatch);
state of charge measurement and management;
market participation (eligibility, as seller and buyer);
metering and accounting; and
settlements (make-whole payments, compensation, performance and penalties).
The Reliability Subcommittee will address reliability (qualification) and non-market products. The Resource Adequacy Subcommittee will focus on capacity and resource adequacy administration.
MISO officials outlined the proposal during a daylong joint meeting of the three subcommittees and the Planning Advisory Committee.
The RTO expects stakeholder discussions through October and completion of the plan for a compliance filing on Dec. 3. Implementation would begin in December 2019. The first resources registered under the new participation model will be able to participate starting March 1, 2020.
In meeting Order 841’s requirements, MISO’s compliance filing will also address shortcomings FERC identified in the RTO’s existing Tariff rules on Stored Energy Resources (SER) – Type II. MISO previously proposed the SER – Type II category in response to FERC’s partial granting of Indianapolis Power and Light’s earlier complaint on its storage rules. (See FERC OKs MISO Plan to Expand Storage.)
Four Commitment Modes
The new rules will apply to batteries, flywheels, compressed air, pumped hydro and any other technologies meeting FERC’s definition of an ESR: one “capable of receiving electric energy from the grid and storing it for later injection … to the grid.”
Resources could be connected to the interstate transmission grid, a distribution system or behind the meter. Demand response, which cannot inject energy, is excluded. The initial ESR participation model also will not accommodate distributed energy resource aggregations across multiple pricing nodes.
The RTO said it will expand the ESR category in the future based on improvements to its Market Systems, the Market Roadmap and advances in storage technologies.
Offline, charging and discharging modes | MISO
ESRs would participate under four modes of commitment: charging, discharging, continuous operations and outage/offline, as specified by the market participant for individual dispatch periods. When in online mode, storage will be treated as must-run resources.
Continuous operation mode | MISO
The state of charge will be managed by the market participant and communicated to MISO via telemetry and offer parameters.
A storage resource would pay the LMP of their commercial pricing node when withdrawing charging energy and receive payment at the LMP during injections. Storage will be eligible for make-whole payments under MISO dispatch decisions consistent with eligibility rules for other resource types.
In addition to providing energy, capacity and ramping, storage will be permitted to offer non-market-based services (reactive supply and voltage control and black start).
Rehearing Request
On March 19, MISO asked FERC to clarify or change some aspects of the order. For example, it requested a phased approach for small ESRs (less than 5 MW). It suggested up to 50 be permitted in the first year and 150 in the second.
It also requested a six-month extension for implementation relating to issues pending in the commission’s separate DER proceeding (RM18-9, AD18-10).
MISO asked for feedback on the straw proposal, including responses to a questionnaire by June 22. The proposal is expected to be discussed at the RASC on July 11 and MSC on July 12. The proposal is also expected to be mentioned at the Energy Storage Task Force meeting on June 27.
