Page 1186 – RTO Insider

April 15, 2018

Court Questions FERC Change on ISO-NE Renewable Exemption

By Michael Brooks

A three-judge panel of the D.C. Circuit Court of Appeals on Friday questioned whether FERC had changed its position without adequate explanation in its approval of ISO-NE’s renewable technology resource (RTR) exemption from its minimum offer price rule (17-1110).

New England generating companies — including NextEra Energy Resources, NRG Power Marketing and PSEG Energy Resources & Trade — sued the commission last year over the exemption, which allows 200 MW of renewables annually (up to a 600-MW maximum) to clear ISO-NE’s capacity market without regard to the MOPR. The companies charged that FERC reversed its position from previous orders finding that out-of-market entry into the market can suppress prices and that it never justified the 200-MW cap.

FERC ISO-NE Renewable Exemption MOPR — Meade and Prettyman Courthouse | *DC Circuit*

The companies previously sued over the issue in 2015, but the court allowed the case to be remanded back to FERC at the commission’s request. FERC affirmed its approval in April 2016 (ER14-1639-004) and denied the generators’ request for rehearing in February 2017 (ER14-1639-005). (See Bay Blasts MOPR on Way Out the Door.)

“The narrowly tailored renewables exemption, in combination with ISO-NE’s sloped demand curves, balances our responsibility to promote economically efficient prices, while accommodating states’ ability to pursue legitimate policy objectives,” FERC said in its order on remand.

As FERC attorney Carol Banta attempted to explain Friday how the RTO’s implementation of a systemwide sloped demand curve — approved along with the RTR exemption — has lessened the price effects of the exemption, Judge David B. Sentelle interrupted her, saying he wanted to focus on “the more mundane aspects of administrative law.” He asked that she defend the charge that FERC had unreasonably changed its position.

He cited FERC saying “the orders cited by [the plaintiffs] and the first two orders in this proceeding demonstrate that the commission’s view on the question of a broad (i.e., not resource-by-resource) exemption for renewable resources has evolved.”

“That’s a lot like saying it ‘changed,’” Sentelle said. “Now we certainly have a lot of precedent that says that an agency can change, but we say that in order to avoid being arbitrary and capricious they have to explain why they changed.” He asked Banta to show where FERC explained its reasoning.

Banta cited a passage in the commission’s last order denying rehearing, in which it said, “Moreover, not only has the commission’s view of the relationship between state-sponsored renewable resources and the capacity market evolved over time, but in the five years since the commission accepted the minimum offer price rule to mitigate buyer-side market power, New England states have continued to intensify their renewable resource development. The commission does not regulate in a vacuum. We recognize that, as ISO-NE stated in its original filing, it is seeking to balance its need to retain and attract capacity with its obligation to meet customers’ needs in an economically efficient manner.”

The commission is “balancing its responsibility to promote economically efficient prices,” Banta said. If the increased entry of state-sponsored renewable resources is not accounted for, “the price signal is actually false if it’s signaling the need for new entry [and] ignoring the new entry that’s there.”

“Wouldn’t any prudent company take that into account before making a multimillion-dollar investment in a new generating facility?” Judge A. Raymond Randolph asked. “They wouldn’t take into account just the so-called ‘false signal.’ They would take into account the fact that there are all these renewables out there.”

“This is about making sure the capacity market is a just and reasonable mechanism,” Banta responded, “and that includes, is it sending accurate price signals? Is it incentivizing new entry that the system needs? And is it ensuring fair prices for consumers? And these all go into the mix.”

CASPR Rehearing Requests

NextEra and NRG cited the RTR exemption case as a reason why FERC’s reasoning was flawed in its approval of ISO-NE’s Competitive Auctions with Sponsored Policy Resources capacity market construct (ER18-619). (See Split FERC Approves ISO-NE CASPR Plan.)

As part of CASPR, the RTO plans to phase out the exemption by allowing accrued exempt megawatts to be used through Forward Capacity Auction 15. The companies cited Commissioner Richard Glick’s dissent on the order, in which he said FERC’s pursuit of “investor confidence” would cause over-procurement of capacity.

“While we agree with Commissioner Glick that respecting settled market expectations are important, the RTR exemption is not based on settled law, as the matter is pending before the D.C. Circuit,” the companies said in their request for rehearing last week. “Prior to the RTR remand order, the justness and reasonableness of the FCA had continuously been based on the principle that ‘over the long run, the average price for capacity should reflect [cost of new entry], in order to attract new entry needed for reliability.’ In the RTR remand order, without any explanation, the commission for the first time stated that ‘the renewable exemption fulfills the commission’s statutory mandate by protecting consumers from paying for redundant capacity.’”

The Eastern New England Consumer-Owned Systems also requested rehearing, criticizing the commission’s accepted definition of sponsored-policy resources, which limits participation in the second auction under CASPR to renewable resources procured by distribution utilities as part of state mandates.

FERC’s “adoption of the discriminatory ‘sponsored-policy resource’ definition results in the exclusion of conventional generating resources developed by New England’s consumer-owned utilities from the eligibility to participate in the Substitution Auction without identifying any rational basis for its conclusion that public power conventional resources are not ‘similarly situated’ to state-mandated renewables purchases by investor-owned distribution utilities,” the municipal utilities said.

Several clean energy advocate groups, including the Natural Resources Defense Council and Sierra Club, reiterated their complaint that the RTO had not justified eliminating the RTR exemption.

“CASPR replaces a proven mechanism for reconciling state policies with competitive capacity markets with a totally unproven construct that offers little likelihood of integrating renewable resources,” the groups said.

Like NextEra and NRG, consumer advocacy group Public Citizen cited Glick, agreeing with his criticism of the commission’s focus on investor confidence in its justification.

“The commission never bothers to define ‘investor confidence’ for the purposes of this order,” wrote Tyson Slocum, the group’s energy program director. “There are many owners of power plants that talk incessantly about the dangers of the ‘erosion of investor confidence’ if power prices aren’t high enough to provide the generous financial returns the owners promised to shareholders. Because hey, we all feel a lot more confident when we get paid more money.”

April 15, 2018

Lovins: We’re Only Scratching the Surface on Energy Efficiency

By Rich Heidorn Jr.

NEW YORK — Amory Lovins knows the conventional wisdom on energy efficiency. And he doesn’t buy it.

Lovins ERCOT energy efficiency — Lovins | © *RTO Insider*

Economic theory says you stop investing in EE when the heat savings from insulation, for example, no longer outweighs the costs. But “integrative design” — optimizing buildings, vehicles and factories as whole systems rather than individual parts — changes the equation, he says.

Lovins, the visionary founder of the Rocky Mountain Institute, ascribes to Dwight Eisenhower’s advice: “If a problem cannot be solved, enlarge it.” Expanding the boundaries of the problem uncovers new options and synergies, he says.

Thus, he told the Bloomberg New Energy Finance’s Future of Energy Summit last week that electric intensity — which he said dropped a record 4.4% in 2017 — could fall even more dramatically in the future.

“If you keep investing well beyond that supposed cost-effectiveness limit, suddenly your marginal cost goes back down because now your house loses so little heat that it no longer needs a furnace, ducts, fans, pipes, pumps, wires, controls [and] fuel-supply arrangements,” Lovins said.

Lovins displayed a photo of him with his latest harvest of bananas, grown in his 35-year-old passive solar home near Aspen, Colo. “Integrative design saved 99% of its heating energy and $1,100 of construction cost because the super insulation, super windows and so on cost less than the heating system they displaced,” he said. “Now over 160,000 European buildings do this.”

Fat, Short and Straight

Lovins cited the 2011 retrofits to the Empire State Building. Replacing 6,000 leaky windows with ones that pass light but block heat, plus improved lighting and office equipment, cut the skyscraper’s energy costs by 38% and the peak cooling load by a third. “Then renovating smaller chillers instead of adding bigger ones saved over $17 million in capital cost, paying for most of those savings and cutting the payback to three years — the same payback as saving a sixth as much energy with standard disintegrative design.”

Three years later, Lovins said, the retrofit of an office building in Denver reduced energy costs by 70%, “making this half-century old federal office more efficient than what was then the best new U.S. office, which in turn is less than half as efficient as [RMI’s] own net positive, no mechanicals office. And now there’s a German building using three-fifths less energy than ours.”

The results were not from new technology, he said, but from design improvements. Making pipes and ducts “fat, short and straight rather than skinny, long and crooked as in normal practice,” he said, eliminates at least 80% of the friction and energy consumption. “If that were done worldwide, it could save about half the world’s coal-fired electricity. The payback is typically less than a year in retrofit and zero in new build. But this is hardly noticed because it’s not a technology, it’s a design method.”

He also cited the engineers on the Tesla Model S, who realized batteries work better if prewarmed. “Many other components also needed heat added or removed at various times, so rather than separately heating or cooling each, they were all choreographed so that in each stage of driving, thermally linked coolant loops shuttle heat around from where it’s not wanted to where it is. That means longer [battery] range, lower weight, lower cost. And not needing the radiator for first 50 km — which is longer than most trips — keeps it shuttered until needed, further improving aerodynamics.”

An All-Renewables ERCOT

Lovins said ERCOT could address its steep late-afternoon ramp rate — the so-called “dead armadillo curve” — by moving to 100% distributed renewables, with 86% wind and solar PV, and the remaining 14% supplied by dispatchable renewables, including burning animal manure in existing gas turbines.

ERCOT energy efficiency lovins — Amory Lovins presented this graph to demonstrate how ERCOT could run on 100% distributed renewables in the summer of 2050. | *Rocky Mountain Institute*

“Then match the load by putting the surplus electricity into two kinds of distributed storage worth buying anyway, namely ice storage air conditioning and smart charging of [electric vehicles]. And then recovering that energy when needed and filling the last gaps with unobtrusively flexible demand yields 100% renewable energy every hour of the year,” he said. “Five percent annual spill, very low prices using no bulk storage but eight cheaper kinds of grid flexibility resources.

“Efficiency is not a dwindling, rising-cost resource like copper,” he concluded. “Energy efficiency resources are ubiquitous and infinitely expandable assemblages of ideas depleting nothing but stupidity — a very abundant resource. So, to all you smart designers, I give you this charge: Blessed be your negawatts. Go forth and be fruitful and subtract.”

April 15, 2018

Solar Industry Looks for Bright Spots on Tariffs

By Rich Heidorn Jr.

NEW YORK — Solar industry officials last week expressed confidence that the sector will continue to grow despite the Trump administration’s tariffs on imported solar cells and modules. But they told Bloomberg New Energy Finance’s Future of Energy Summit that the levies have hurt in the short term.

Trump tariffs solar industry — BNEF’s Hugh Bromley (far left) interviewed (left to right) Vikram Aggarwal, EnergySage; Abigail Hopper, SEIA; Nam Nguyen, SunPower; and Scott Wiater, Standard Solar | © *RTO Insider*

“They were more of a punch to the gut than a complete decapitation, which is what we feared,” said Abigail Hopper, CEO of the Solar Energy Industries Association. “And so, while they will certainly have a dampening effect on the industry — and I think we’ll see that for years — I feel fairly confident that it will continue to grow.”

“It certainly slowed things down. We were seeing a slowing of project flow,” said Scott Wiater, CEO of Standard Solar, which provides financing and management of utility-scale solar projects. “But recently we’ve seen it start to pick up tremendously. I think a lot of developers have been sitting on projects, waiting for the tariff decision and tax [legislation] to settle down. [There was also] some seasonality thrown in there. And now we’re really starting to see it ramp back up.

“I do think in some states where it’s a difficult environment [to operate] it may have iced the markets. But in states that are solar-friendly, I think we’re going to hit the ground running.”

Vikram Aggarwal, CEO of EnergySage, which provides a portal for homeowners researching pre-screened rooftop PV installers, agreed that the impact has varied by geography. Aggarwal said a survey of his company’s installers indicated two-thirds planned to absorb all or most of the cost increases, with one-third saying they would pass most of the increases to consumers.

“It actually seems like it’s playing out that way. … We’re seeing prices roughly 1% down on a national basis compared to last year. In certain markets like California, the prices are actually down quite a bit. In markets that are less developed, less mature, prices are trending up. It’s a tale of two cities.”

Aggarwal said consumers have not been scared away by the tariffs. “The consumer interest is actually very strong this quarter. We’re running about 150 to 200% above year-over-year.”

Wiater said he has no fear of higher prices squelching consumer interest. “I think we may have an oversupply situation coming very quickly and prices could come down below what … analysts are expecting very quickly.”

Hopper said the tariff debate brought it new conservative allies in D.C., with the American Legislative Exchange Council (ALEC), the Heritage Foundation and R Street Group joining SEIA in opposing the levies.

Portrayals of the solar industry as split over the tariff debate were inaccurate, she said. “It really was two companies [who filed the complaint that prompted the tariffs] against 1,000 others.” She said about 20 solar companies have reported the loss of jobs or investments. “It is serious and harmful,” she said. (See Tariff to Pinch US Solar Growth; Factory Surge Unlikely.)

The solar industry lost 10,000 jobs (3.8%) last year, dropping to 250,271, according to the Solar Foundation’s National Solar Jobs Census. It was the first year-over-year drop in employment, said Hugh Bromley, head of U.S. solar for BNEF, who moderated the discussion.

Even so, 29 states added solar jobs. The prospects of job growth has helped open doors for the industry, Hopper said.

“In terms of electricity generation, solar creates more jobs than all fossil fuels combined, which is an incredible statistic that now more people in Washington know,” she said. “One of the great outcomes [of the tariff case] was we did so much education among all these brand new policymakers in Washington. And when we talk about the amount of jobs, and the jobs in relation to other industries and other fuel sources, that was always a point on which I felt like we’re getting traction. Because we’re now talking about jobs in lots and lots of red states.”

April 15, 2018

FERC Rejects CAISO CPM Proposal

By Jason Fordney

FERC last week rejected a major CAISO proposal to expand its backstop procurement process to prevent the early retirement of generation needed to maintain near-term reliability, saying the grid operator needs to “propose a more comprehensive package of reforms.”

In its April 12 order (ER18-641), FERC sided with parties that had protested CAISO’s Capacity Procurement Mechanism Risk-of-Retirement (CPM ROR) program, including the California Public Utilities Commission (CPUC), six California cities, the state’s three investor-owned utilities and the ISO’s Department of Market Monitoring.

CAISO CPM ROR FERC resource adequacy — Calpine’s Yuba City plant is one that is under a reliability-must-run contract

“We find that CAISO has not adequately demonstrated that its proposal addresses the front-running concerns raised by protesters and that the proposal will avoid potentially deleterious effects on the competitiveness of capacity procurement under CPUC’s resource adequacy program,” FERC said.

CAISO spokesman Steven Greenlee said Friday that the ISO is reviewing the order “and will be considering our next steps as part of the ongoing stakeholder process.” In recent meetings, ISO officials have been telling market participants they expected FERC to approve the rule changes.

But stakeholders had been critical of the program throughout the development process. (See CAISO, Stakeholders Debate RMR Revisions.)

CAISO has two major backstop procurement programs, CPM and its mandatory reliability-must-run program that is also raising stakeholder objections for providing out-of-market payments to keep gas-fired generators online. The ISO is considering merging the two programs.

The rejected CPM ROR program would have expanded the existing CPM process to include procurement of at-risk capacity needed for the next resource adequacy compliance year. The process would have included two request windows for generators to seek a CPM designation, one in April and other in November of each year. FERC said that in practice, CAISO currently makes the designation in mid-December at the earliest for the following year, which generation owners complained occurs too late in the year for their planning decisions.

CAISO CPM ROR resource adequacy — CAISO’s proposed two windows for units to pursue CPM designations | *CAISO*

But the CPUC argued that the spring application window would allow resources to “front-run” its resource adequacy process and could lead to other gaming by resources because CPM revenues might exceed market revenues. IOUs raised concerns that a more holistic approach is needed and that CAISO did not consider the interplay with RMR, which is a mandatory contract unlike the voluntary CPM.

The CPUC has also battled with CAISO over RMR designations for gas units, and in February it hastily crafted and passed an order mandating that CAISO-approved RMRs be replaced with energy storage by 2019. (See CPUC Targets CAISO’s Calpine RMRs.)

Stakeholders also complained that the CPM proposal’s cost-based compensation provides for full cost recovery while also allowing resources to retain revenues earned in the ISO’s market. The Monitor had argued the units should not receive compensation beyond their cost of service, and that the changes could affect the bilateral resource adequacy market.

CAISO had contended that “front-running” of the RA process would not occur, but FERC said “the potential for the spring request window to distort prices or otherwise interfere with the bilateral resource adequacy process have merit and are significant enough to render CAISO’s proposal unjust and unreasonable.”

FERC also said that CAISO’s development of the current package of RMR/CPM changes indicate a need to more closely align the two programs. The commission said there is a “need to evaluate the fundamental reliability and market factors associated with resource adequacy as a whole.”

The commission said CAISO should revisit the issues of RMR/CPM compensation, evaluate whether both need to be retained and examine how the CPM designations could affect procurement. CAISO will make quarterly filings beginning June 1 to give updates on the stakeholder process and any changes that occur as it progresses. FERC said it would not move or act on the filings.

April 15, 2018

FERC OKs MISO Queue Deadline Change

FERC last week approved MISO’s proposal to shorten the window of time it allows generation owners to alter estimated capacity volumes for projects in the interconnection queue.

The commission’s decision clears MISO to require interconnection customers to finalize their requested network resource interconnection service (NRIS) megawatt values during “Decision Point II” — roughly 200 days into the queue (ER18-835). The revision became effective April 11.

MISO Decision Point II — | © *RTO Insider*

FERC said requiring a final figure earlier in the process should help MISO achieve its goal of reducing unscheduled queue restudies in order to cut down on the number of months projects spend in the queue.

“MISO’s current proposal is a modification to further streamline its interconnection process and to prevent unscheduled, ad hoc restudies late in the interconnection process. We agree with MISO that unscheduled restudies will be less likely under the timeline established by MISO’s proposal,” FERC said.

The RTO’s previous process allowed interconnection customers to revise their requested level of NRIS up until after the final system impact study of the definitive planning phase of the queue.

MidAmerican Energy protested the change, saying that MISO and neighboring balancing authorities often do not complete affected-system studies on each other’s territories in time for Decision Point II, making an informed decision on NRIS levels impossible. But FERC ruled MidAmerican’s argument was underdeveloped and that “the benefits of reducing the potential for restudies and keeping the queue process on schedule outweigh MidAmerican’s concerns about potentially having less information at the earlier decision point.”

FERC held a technical conference earlier this month to gather ideas on how RTOs can better align their affected-system studies. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)

— Amanda Durish Cook

April 15, 2018

Overheard at Bloomberg New Energy Finance Summit

NEW YORK — Hundreds of investors, utility executives and others gathered last week for Bloomberg New Energy Finance’s Future of Energy Summit, where electric vehicles, energy storage and renewables dominated discussions. Here’s some highlights.

Murray Weeps over a Future Without Coal

Robert Murray has been trying for more than a year to persuade President Trump and Energy Secretary Rick Perry to provide subsidies for the utilities that buy Murray Energy’s coal. (See Photos Show Murray’s Role in Perry Coal NOPR.)

Last week, he took his message — that the grid cannot be resilient without coal generation — to a skeptical audience at the BNEF conference.

“I’m probably the only coal guy in the room. I’m also an American,” he said, pausing to gather his composure after tearing up. “The recent polar vortex shows our grid is not as reliable as grid operators would like you to believe.”

Murray criticized FERC for rejecting Perry’s proposal to subsidize coal and nuclear plants with onsite fuel and said Perry should approve FirstEnergy’s request for an emergency declaration to protect coal plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)

Hundreds of investors, utility executives and others gathered last week for Bloomberg New Energy Finance’s Future of Energy Summit, where electric vehicles, energy storage and renewables dominated discussions. | © *RTO Insider*

The declaration “has to be [made] or we’re going to have a disaster. … Will we have to have a system collapse before recognizing that something has to be done about the security, resiliency and reliability of the power grid?” he asked. “Barely one-half of [remaining coal] plants generate enough revenue to cover their expenses. There has to be a capacity payment there.”

Lynn Doan, head of power and renewables for Bloomberg News, asked Murray about reports by NERC and others that some coal plants were unable to run during recent cold spells because of frozen coal piles. “Did not happen ma’am,” he insisted.

“The poorest 25 million families in this country are putting out 31% of their income for energy — gasoline, oil and electricity,” he continued. “We have an energy poverty problem in this country. We don’t have a global warming problem.

“All of you are building your businesses around climate change. The best thing that could happen is overturning the [EPA’s CO₂] endangerment finding — that artificial thing that has put political correctness ahead of getting the lowest-cost electricity for the people on fixed income, for that single mom, for that manufacturer.”

Power Markets Under Stress

Although most of the conference focused on advances in renewable technologies, there was some discussion of the impact of those resources on organized power markets.

“We know that clean, zero-marginal cost energy does fundamentally change the way the power markets work,” said Albert Cheung, BNEF’s head of global analysis. He cited BNEF modeling on the impact of adding 5 GW of solar in Texas. “It creates $300 million going toward solar. But you also destroy about $2 billion worth of revenue for other generators, whether it’s gas or coal or wind or nuclear. In California we already see this happening,” he said, with even solar “cannibalizing itself already.”

“Be wary of capacity mechanisms which bake in solutions of the past,” he added.

Former FERC Commissioner Nora Mead Brownell said she is confident organized competitive power markets will survive state and federal interventions to protect favored generation resources.

Brownell (left) and Nason | © *RTO Insider*

“I think it’s easy to sit in a vertically integrated market where you have elected regulators who pretty much approve what [utilities] wish and say this life is perfect. What we’ve seen in organized markets is a decrease in price, an increase in innovation and an increase in reliability and investment.”

FERC, she said, is acting properly in considering market redesigns to respond to decreased prices resulting from renewables and cheap shale gas. “They’re doing it in a methodical way based on a fact pattern, unlike kind of throwing subsidies at old solutions. They want to keep the market open for this continuing innovation that you will only see if you let the market drive decisions. You don’t see big huge mistakes in organized markets with big huge ratepayer-funded R&D projects. You don’t see that at all. There’s financial discipline, there’s transparency and there is encouragement of new solutions. It’s not happening fast enough … but I think it’s moving forward now. So, we need to step back and make economic decisions and not political decisions.”

Storage vs. Gas?

David Nason, CEO of GE Financial Services, was asked whether he sees storage as a threat to investments in gas-fired generation.

“I don’t know if storage is a complete competitor to gas yet,” he said. “It’s just one of the variables that we [consider in projecting] a long-term return for these investments. The difficulty with investing in gas without a structured market or without [power purchase agreements] is that these are 30-year, very capital-intensive investments. So, if I can’t get some level of confidence that I’m going to get an adequate return on my cost of capital, I’m just never going to put the money to work there.”

Seeking Deeper Penetration for Electric Vehicles

Reza Shaybani, co-founder and interim CEO of The EV Network, said the EV industry must not be paralyzed by concerns over which charging technologies and business models will survive. “This is going to evolve. This is going to change. What we see today is not necessarily going to be the future business model,” he said. “But it has to start from somewhere.”

Shaybani’s company, which is developing the charging infrastructure in the U.K., conducted a survey of EV buyers in the country and found that 90% were “middle-age men, well educated, very affluent and living in the Southeast and they have at least two or three other cars in their household. That’s … not going to take this revolution forward.”

The revolution will need cheaper vehicles and many more charging stations so that the drive from London to Manchester takes only three hours. “That should not take 18 hours if you are going to stop every 150 miles to charge,” he said.

FERC ISO-NE Allco Renewable Finance Infocast New York Energy REVolution Summit — Urban | © *RTO Insider*

Bryan Urban, executive vice president of Leclanche North America, said there is already a compelling business case for EVs and fast-charging infrastructure for mass transit and fleet vehicles. His company is conducting a pilot project in India for its plan to separate city buses from the batteries to make the capital expenditure model similar to that for diesel vehicles.

The company’s plan — which he dubbed, “taking the sun and putting it on the run” — replaces buses’ depleted batteries for charged ones three or four times daily, a swap which he says takes about three minutes each.

Mary Nichols, chair of the California Air Resources Board, said EVs need more marketing. “Even in California, where we pride ourselves that half of all EVs have been sold in the U.S., we … have done polls that show most people who are in the market for a new car aren’t even aware that there might be an electric car that could serve their needs,” she said. “So, we have a long way to go to really penetrate the thinking of customers.”

Nichols talked of Nissan’s hope to lease the batteries for its Leaf when it launched the first widely available all-electric car in Los Angeles. The plan was to include a mileage guarantee on the batteries, like the miles-per-gallon ratings for gasoline vehicles. “The only way they could do that at a level price was if they could negotiate with the electric utilities a product that would cut across state lines and local lines,” she said. “And after a period of time, they gave up on that idea. There was no practical way to do it.”

“And that’s in a relatively vertically integrated market, as most of the Western U.S. is,” added Colin McKerracher, the head of BNEF’s advanced transportation coverage. “It’s … even harder if you were to be in an unbundled market.”

Utilities are “unfortunately a very fragmented industry in the United States,” acknowledged Pedro Pizzaro, CEO of Edison International. “I think as an industry, we realize that and we’re trying to come to terms with that to help solve that issue. … We get your point, that from an automaker perspective or from a charger manufacturer perspective, they’re looking for as cohesive a national market as possible.”

LNG: No Glut Worries

Speakers at a panel on U.S. LNG exports expressed little concern over a potential glut in supply.

Meg Gentle, CEO of LNG exporter Tellurian, said she expects strong demand from China, which is converting coal furnaces to gas and adding natural gas-powered autos. Gas only represents 6% of total primary energy in the country, she said. Boosting that share to 10% would represent a nearly 70% increase in Chinese demand for the fuel.

She predicted Henry Hub benchmark prices will stay at $3/MMBtu or less for the foreseeable future, noting that it can now be produced for less than $1.

Greg Vesey, CEO of LNG Limited, which provides liquefaction for LNG export terminals, said he expects demand for gas to continue despite the growth of energy storage.

“Obviously the trend toward renewables and the need for storage with those is something to keep watching. … But in all cases, natural gas is going to provide that backup,” he said. “It’s been called the bridge fuel. I think we’re going to see that for a long time.”

Peak Oil Demand by 2035?

Bloomberg energy storage renewables future of energy — Gilvary | © *RTO Insider*

Even if EVs supplant internal combustion vehicles, BP Chief Financial Officer Brian Gilvary said, oil will remain a “baseload” fuel.

“When I first joined the industry 32 years ago, people talked about peak oil supply. We now talk about peak oil demand,” he said. BP projects that peak to hit between 2035 and 2040.

“But we don’t think of it as a peak; we think of it as a plateau,” he added. Even under a scenario in which all internal combustion engines are banned by 2040, “we can see oil demand plateauing at round about 100 million barrels, which is what it is today.”

Corporate Purchasing of Renewables

Rob Threlkeld, global manager for renewable energy General Motors, said he’s been encouraged by the increasing number of utilities offering “green” tariffs to corporate buyers who want to purchase renewables. “I want price stability. I want to be able to understand what my costs are today and tomorrow. That allows me to be able to then [make] long-term commitments.”

“For a while, there was this huge tension between the renewable energy market and the regulated utilities. There was a significant pushback for years and years,” said Conor McKenna, managing director at investment bank CohnReznick Capital. “It was like when you were going into the regulated markets, you just had to put your mouthpiece in because it would be a battle. Now it feels like a lot of the guys that are coming to us [to deploy renewables] are regulated utilities [asking], ‘How can we incorporate a greater allocation of these resources into our portfolio?’”

— Rich Heidorn Jr.

April 15, 2018

MISO Market Subcommittee Briefs: April 12, 2018

MISO last week said it has concluded that a short-term capacity reserve product would be cost-effective and beneficial to reliability.

An evaluation paper released last month said the product would “strengthen MISO’s vision for reliable and economically efficient markets.”

MISO Market Design Advisor Bill Peters told an April 12 Market Subcommittee meeting that the RTO plans to design a market product that can provide capacity within 30 minutes on the recommendation of the Independent Market Monitor, who last year said a local reserve product could provide voltage support, local reliability and subregional capacity. (See MISO Board Hears State of the Market Recommendations.)

Last year the RTO incurred about $35 million in revenue sufficiency guarantee payments to cover load pocket needs and regional dispatch transfers over its contract path on SPP transmission from MISO Midwest to MISO South. The annual amount was “much more in some previous years,” MISO said.

MISO short-term capacity reserve — Make whole payments MISO has incurred to manage the MISO-SPP contract path between MISO Midwest and MISO South | *MISO*

The RTO currently makes “inefficient, out-of-market commitments to address operational needs” in both load pockets and regional areas, Peters said.

Staff have said that a short-term capacity reserve would be especially helpful in South, which has less than 500 MW of offline capacity available within 30 minutes. West of the Atchafalaya Basin (WOTAB) has 100 MW of 30-minute reserves, while Amite South has none. (See MISO Researching 30-Minute Reserves, Multiday Commitments.)

Peters said MISO envisions the short-term capacity reserves as an ancillary service to be deployed in late 2019. The RTO will now move into a conceptual design phase.

Minnesota Public Utilities Commission staff member Hwikwon Ham asked how MISO arrived at the requirement that the reserve product must be delivered within 30 minutes rather than another length of time.

“Some of the needs, particularly the [regional dispatch transfer] constraint, are 30 minutes,” Peters replied.

Northern Indiana Public Service Co.’s Bill SeDoris asked if the cost of maintaining a reserve product would be shared footprint-wide.

Peters said MISO is considering employing a “nesting” approach for the product in which load needs are determined by specific demands on load pockets.

“I’m just concerned that the entire footprint could be responsible for what are very localized problems,” SeDoris said.

Peters said MISO must still iron out numerous details of a new reserve product, including determining how the service would interact with other existing ancillary services, creating scarcity pricing and demand curves for the new reserves, and identifying how commitment would be justified in settlements.

MISO Manages Chilly February

MISO reported a 76-GW average load during February, down from the average 83 GW in January as winter wound down across the footprint.

Average prices likewise decreased month over month from $41.75/MWh to $25.05/MWh in the day-ahead market and $39.68/MWh to $25.36/MWh in the real-time. Systemwide energy prices in February were “kept flat” with the help of natural gas prices below $3/MMBtu. Average Henry Hub gas prices were $2.64/MMBtu.

Load peaked for the month at 94.6 GW on Feb. 8, 7.5 GW above the previous February’s peak load of 87.1 GW. MISO said average monthly temperatures were lower than the prior two years but higher than in February 2015.

— Amanda Durish Cook

April 15, 2018

Former Intergen CEO Recommended for PJM Board

PJM’s Board of Managers announced in a letter to members last week that the Nominating Committee is recommending former InterGen CEO Neil H. Smith to replace Chairman Howard Schneider, who will retire from the board at the RTO’s Annual Meeting next month.

The committee also recommended re-electing current board members Neel Foster and Sarah Rogers. The Members Committee will vote on the candidates at the Annual Meeting.

Smith was selected following a national search, assisted by the Heidrick & Struggles search firm, that included candidates suggested by current board members. He retired from InterGen in 2016 after 25 years with the company, working his way up from development director.

InterGen operates 11 power plants with a generation capacity of 7,686 MW, three compression facilities and a 40-mile gas pipeline. The facilities are located in the U.K., Netherlands, Mexico and Australia. The company is jointly owned by the Ontario Teachers’ Pension Plan and China Huaneng Group/Guangdong Yudean Group.

Smith also served as a non-executive director and board member of The Wood Group, a worldwide service provider for the oil-and-gas and power generation industries. He was on the board for nine years, between 2004 and 2013, according to his LinkedIn profile.

— Rory D. Sweeney

April 15, 2018

MISO Resource Adequacy Subcommittee Briefs: April 11, 2018

Stakeholders learned Wednesday that MISO will delay for another year a plan to account for previously un-forecasted planned outages at times of peak demand after getting mixed feedback from market participants.

MISO RASC planning reserve margin import and export limits — Westphal | © *RTO Insider*

Speaking at an April 11 Resource Adequacy Subcommittee meeting, MISO Resource Adequacy Coordinator Ryan Westphal said the RTO will wait until the 2020/21 planning year to implement a new, unspecified calculation that accounts for planned outages during peak demand, which could increase the RTO’s planning reserve margin requirement.

MISO had proposed to factor the effects of planned and maintenance outages on peak in its loss-of-load expectation (LOLE) study by the 2019/20 planning year. (See MISO RASC Zeroes in on Priorities.)

Westphal said some stakeholders asked the RTO investigate further before making any changes to the LOLE study. Others urged it to define “safe” periods during the summer months to take planned outages.

Director of Resource Adequacy Coordination Laura Rauch said MISO would delay accounting for planned outages on peak until it develops solutions based on a more comprehensive conversation about the RTO’s shifting resource availability. (See MISO Looks to Address Changing Resource Availability.)

Some stakeholders expressed frustration that the RTO first presented the issue as requiring expeditious treatment, then moved it into a discussion about resource availability and needs, only to again this month single it out to proceed separately. (See MISO to Fold Outage Forecasting into Larger Resource Effort.)

Reprieve for Out-year Import and Export Limit Estimates

MISO is taking a cue from stakeholders and switching gears on a previous proposal to discontinue its practice of forecasting long-term capacity import and export limits, instead proposing to modify the process that produces the forecast.

MISO’s Matt Sutton said the RTO expects by early 2019 to revise its process for predicting capacity transmission limits for its 10 local resource zones. It had proposed in February to altogether scrap out-year import and export limits, saying results were too unreliable and volatile, but stakeholders countered that the limits provided useful information. (See “Scrapping Out-Year Import and Export Limit Estimates?” MISO Resource Adequacy Subcommittee Briefs: Feb. 7, 2018.)

While the RTO still plans to compile the long-term limit estimates, it will use more zone-specific information, including data from past Planning Resource Auctions and the Organization of MISO States-MISO annual resource adequacy survey.

Sutton said the RTO would not commit to annual restudies for capacity zones that don’t experience notable changes.

“If a zone could potentially bind, a study isn’t necessary every year unless a significant supply or transmission change occurs,” he said. “The number of studies is being reduced significantly. … We’ll have fewer zones to review.”

The selective study process will allow MISO to focus on zones that could bind on their import and export limits or carry capacity surpluses beyond their export capability, Sutton said.

The more thorough process to estimate out-year limits should spark discussions around new transmission and generation projects and the impact of external system changes on capacity zones, he said, not just the usual conversations about transfer limits, constraints and redispatch options.

MISO will pass its recommendations for improvements to its stakeholder-led Loss of Load Expectation Working Group, which will produce a new prediction methodology for stakeholder review as early as September, Sutton said. He asked stakeholders to submit written comments on the RTO’s plan by April 27.

Different Method for Economic Uncertainties in LOLE Study?

MISO is exploring how to improve its modeling of economic load uncertainties in the LOLE study.

For the 2018/19 planning year, the RTO relied on a GDP growth comparison to account for the uncertainties, which increased the annual planning reserve margin by 0.2 percentage points year-over-year.

In June, MISO will have a 17.1% planning reserve margin, which represents the extra generation the RTO should have on hand to meet a probability of shedding load no more than one day in 10 years. MISO maintained a 15.8% planning reserve margin in the 2017/18 planning year.

MISO staff have attributed the increase to an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO last year also added the new modeling step to capture economic load uncertainty that increases risks associated with high peak loads, which also boosted the reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)

“We’re reviewing our methodology and investigating other approaches for the 2020/21 planning year model,” MISO Resource Adequacy Senior Engineer William Buchanan said.

In future years, the RTO may model economic uncertainty using a calculation based on comparisons between forecasted and actual demand in past years, Buchanan said.

— Amanda Durish Cook

April 13, 2018

NJ Lawmakers Pass Nuke Subsidies, Boosted RPS

By Peter Key

New Jersey lawmakers on Thursday passed a pair of bills that could significantly shape the state’s generation portfolio over the next decade.

One bill would provide two Public Service Enterprise Group nuclear power plants with subsidies costing ratepayers about $300 million per year. The other would require the state’s power sellers to get half their electricity from renewable sources by 2030.

New Jersey Nuclear Subsidies RPS ZEC — New Jersey’s State Capitol Building

By a 29-7 vote, the state Senate passed S2313, which would create a zero-emission certificate (ZEC) subsidy for nuclear plant operators that can show the New Jersey Board of Public Utilities their plants need financial support to remain operating. The bill passed the General Assembly on a vote of 60-10.

The bill now goes to Gov. Philip Murphy, who will have 45 days to decide whether to sign the bill, veto it or allow it to become law without his signature. He could also conditionally veto the bill and send it back to the Legislature with proposed changes.

ClearView Energy Partners gave Murphy a 65% chance of signing the bill but said he may conditionally veto it, in which case the Legislature could agree to his proposed changes with a simple majority vote. If he vetoes it, the Legislature would need a two-thirds majority vote for the bill to become law.

If Murphy does sign the bill, ClearView says it expects opponents will file a lawsuit in the U.S. District Court for New Jersey challenging the ZEC program on grounds similar to those of lawsuits challenging similar programs in New York and Illinois. ClearView also said it thinks New Jersey lawmakers structured their state’s ZEC program with such lawsuits in mind.

The nuclear subsidy bill drew a mixed reaction. The Natural Resources Defense Council has said it will not oppose the bill, while Jeff Tittel, director of the New Jersey Sierra Club, said it would have “a chilling effect on spending more for renewable energy, because to build out renewable will cost much more.”

The Electric Power Supply Association and New Jersey Petroleum Council also panned the nuclear bill, while PSEG spokesman Michael Jennings called it “a sensible solution that protects the viability of nuclear energy and its benefits for New Jersey, while at the same time ensuring consumers are protected, as well.”

The other bill (A3723) would require electric power suppliers to procure 35% of their power from renewable resources by 2025 and 50% by 2030.