KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee last week failed to endorse a revision request that would have required non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.
The Market Working Group’s (MWG) recommended revision request (RR272) will likely be appealed to the Board of Directors for its April 24 meeting.
A roll-call vote resulted in 62.3% of members favoring the measure, short of the necessary two-thirds majority. Transmission-owning members Western Farmers Electric Cooperative and Westar Energy, last in alphabetical order, cast the final two votes opposing the change to seal its fate, at least temporarily.
“I’m not saying I’m going to submit one, but I have a feeling there will be [an appeal],” said American Electric Power’s Richard Ross, who chairs the MWG.
NDVERs converting to DVERs would need to ensure they have the proper communication systems in place and the technical capabilities to reduce their output.
Ross said the Tariff change will increase market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints. The addition of dispatchable resources will only increase reliability, he said.
“Any time you’re taking actions out of market, you are creating inefficiencies,” said SPP’s David Kelley.
The Market Monitoring Unit expressed strong support for the Tariff change, saying it would help reverse the recent growth of negative real-time pricing. The Monitor’s recent quarterly report noted the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017. (See SPP Market Monitor: Negative Prices May Require Rule Changes.)
“Negative pricing is a significant issue in our market,” MMU Executive Director Keith Collins reminded members. “Something that increases flexibility is at a premium, which we will highlight in our next report. Having non-dispatchable resources becoming dispatchable is an important piece of that recommendation.”
Collins said an SPP operations study revealed that “the more flexibility you have, you end up increasing [energy market] pricing” by reducing the magnitude of negative prices.
“All resources will benefit from that change, which will allow the integration of more and more variable resources in the system,” he said.
But Westar said the change would hurt SPP’s “market reputation.”
“NDVERs were a condition of several [market participants] agreeing to transition from [the Energy Imbalance Service to the Integrated Marketplace],” the company said in written comments. “If we go back on our word, will other [market participants] lose confidence in the stability of SPP tariff grandfathering and agreements made to prospective balancing authorities, asset owners and market participants considering the benefits of [joining] SPP as a stable settlement and market platform?”
Members accepted a friendly amendment to the revision, extending the registration deadline to January 2021.
The revision request exempts about 2,000 MW of resources without direct interconnection agreements with SPP or registered as qualifying facilities under the Public Utility Regulatory Policies Act. That drew concerns from members over whether Mountain West Transmission Group entities would be able to acquire similar exceptions.
“If the current language excludes those, it does appear to leave questions about those who joined SPP with a previous interconnection agreement, but not one with SPP,” said The Wind Coalition’s Steve Gaw. “Will they have to comply with this [requirement], or does the language exempt them, including the generators in the Mountain West region?”
“That’s exactly right,” said Oklahoma Gas & Electric’s David Kays. “When you’re being prospective about anyone coming in afterwards … I think it creates a hole in the Tariff, and I’m not sure that’s something we should be doing intentionally.”
Ross said there is no specific provision to carve out the Mountain West entities. “They’ll have to be prepared to comply with these requirements when they’re integrated into the SPP system,” he said. The MWG fashioned the change so that “anyone who wants an exception can make a [Federal Power Act Section] 200-whatever filing from that [requirement] at FERC,” he added.
Kelley pointed out that ISO-NE and CAISO have gone through similar conversions. He said the revision would help a grid that has “grown exponentially in size” with new wind resources and continues to hit new wind-penetration peaks.
“I go back to the overall problems we’re trying to address, which is overall market efficiency and reliability,” Kelley said. “When you hit those [constrained] situations, it’s imperative that the operators and markets have the tools to make the most efficient decisions on a systematic basis, rather than take out-of-market actions.”
The vote followed one of several vigorous discussions that livened up what staff and members had expected to be a perfunctory MOPC meeting.
“If you’re not careful, you’ll have an MWG meeting break out,” Ross joked.
FOLSOM, Calif. — At its first public meeting with potential customers of its reliability coordinator (RC) services Thursday, CAISO divulged that most of the load in the West has signed letters of intent for the new program.
In response to a question, CAISO Regional Integration Director Phil Pettingill said he could not say publicly who has signed letters of intent and nondisclosure agreements to receive RC services.
“What I feel like I can say is, most of the load that is in the Western Interconnection has signed those agreements with us,” Pettingill said. “We are really talking to almost everybody.”
He added that the letters of intent are not binding and can be withdrawn. The notifications that have been sent to Peak Reliability from customers planning to depart its RC program are also nonbinding.
NERC’s reliability standards require balancing authorities and transmission operators to procure RC services, which include outage coordination, real-time situation awareness, and system restoration coordination and training.
CAISO on April 5 issued its initial proposal for RC services, which it hopes to have running by May 2019. The ISO and Peak are also developing competing proposals for new energy markets that could develop into a full RTO. (See Multiple Entities, Markets Now Beckon in West.)
CAISO is now developing prices for its supplemental, non-core RC services, such as hosting advanced applications and addressing certain critical infrastructure protection services, Pettingill said in a presentation.
The ISO says its RC services will be much cheaper than Peak’s, but Peak countered that the comparison is not straightforward because Peak has more RC experience and offers certain customer services such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
In developing the RC services, the ISO will issue straw proposals and gather feedback to revise the initiatives. The final proposal will be subject to approval by the Board of Governors and FERC.
CAISO hopes for the commission’s approval in October.
The goal is for potential RC customers to export their network models by August and begin data integration and system verification in January 2019. RC service agreements would be executed in November with much of the integration and testing occurring next year, Pettingill said.
CAISO will use its “activity-based costing system,” which has been used for all rate design initiatives since 2011, to determine the costs of RC services.
About 6% of CAISO’s annual costs would be allocated to RC services in the revenue requirement for 2019 and 2020 rates, CAISO CFO and Treasurer Ryan Seghesio said Thursday.
“The ISO is committed to a really level, stable revenue requirement,” Seghesio said. CAISO’s revenue requirement of $190 million to $200 million has been stable for about 11 years. There is a FERC-approved $202 million cap on the revenue requirement, he said, to prevent surprises for market participants.
The California Public Utilities Commission will vote later this month on a $98 million settlement agreement regarding its own improper communications with Pacific Gas and Electric related to the fatal 2010 San Bruno gas pipeline explosion and other matters.
The commission will vote April 26 on the proposed decision of Administrative Law Judge Robert Mason regarding ex parte communications with PG&E after the company’s San Bruno pipeline exploded and killed eight people, as well as seven other proceedings.
The five CPUC members that will vote on the agreement April 26 were not involved with the improper communications several years ago. The parties listed on the settlement include PG&E, the city of San Bruno, The Utility Reform Network (TURN), city of San Carlos, and the CPUC’s Office of Ratepayer Advocates and Safety and Enforcement Division.
But the agreement does not close the San Bruno ex parte matter, instead kicking off a new proceeding to explore additional archived emails that PG&E provided to the CPUC in September 2017 that rocked the yearslong settlement process. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)
“This proceeding shall remain open to consider whether PG&E’s newly disclosed email communications violate the commission’s ex parte rules and should result in the imposition of additional fines,” the settlement says.
PG&E said the new batch of emails it submitted to the CPUC last September in the ex parte proceeding were “a recent development” from an unrelated government agency inquiry. The utility said that while the emails dating from 2013 and 2014 were new, “their general nature is not new.”
The “unrelated government agency inquiry” that PG&E referred to appears to be a concurrent investigation into former CPUC Commissioner Susan P. Kennedy that directed her to provide the California Fair Political Practices Commission with communications from 2012 to 2017. The investigation sought communications between the PUC and Kennedy and others at her company, Caliber Strategies, that mention PG&E and legal, legislative or regulatory actions regarding the San Bruno explosion, as well as other matters.
PG&E will pay these penalties under the current terms of the settlement | CPUC
That CFPPC investigation led to a $32,000 fine against Kennedy in February for unreported lobbying for ride-sharing company Lyft and San Gabriel Valley Water Co., an investor-owned public water utility, but the CFPPC decision did not mention any communications with PG&E. (See Former CPUC Member Fined for Lobbying Violations.)
Kennedy was chief of staff for former Gov. Arnold Schwarzenegger, deputy chief of staff and cabinet secretary for former Gov. Gray Davis and previously communications director for U.S. Sen. Dianne Feinstein. She is also founder of Advanced Microgrid Solutions (AMS), a prominent California energy storage company whose investors include Schwarzenegger.
TURN was successful in pressuring the CPUC to consider the emails submitted by PG&E in September separately from the agreement to be voted on this month, rather than lumping them together with the previous violations. But TURN spokeswoman Mindy Spatt told RTO Insider last week that the provisions could still be changed in PG&E’s favor before April 26. Still, she said the settlement “looks pretty good from our perspective.”
The CPUC said the settlement agreement “has, to a great extent, put an end to years of disputes … that has spanned at least nine separate proceedings following the San Bruno tragedy.”
Settlement Mentions Ferron, Florio, Peevey
The new settlement document describes some of the ex parte communications at issue, including an email from PG&E consultant Jerry Hallisey to then-PG&E Vice President Brian Cherry in September 2011. The email described a meeting with then-CPUC Commissioner Mark Ferron to discuss support for a gas pipeline project and cost-splitting between shareholders and ratepayers. Ferron served on the CPUC from 2011 to 2014 and is now a member of the CAISO Board of Governors.
Also listed is a November 2011 email from Hallisey to Cherry and others that described meetings with former CPUC Commissioner Mike Florio, now a private consultant, regarding cost recovery and pipelines.
It also lists an email from Kennedy to Cherry that summarized a meeting with former CPUC Chair Michael Peevey and Kennedy regarding “an independent forensics analysis.” A Jan. 1, 2013, email from Cherry to PG&E Senior Vice President Thomas Bottorff described Cherry’s meeting with Peevey regarding gas settlement mediation and return on equity changes, among other exchanges.
In a separate matter, Peevey’s unreported ex parte communications with Southern California Edison during negotiations of the San Onofre nuclear plant closure led to a reworking of the $4.7 billion deal. (See CPUC Orders Renegotiation of San Onofre Settlement.) Peevey resigned from the CPUC at the end of 2014.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. The scheduled Members Committee meeting has been canceled.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling.
(See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
B. Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the Western region study area definition.
C. Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
D. Manual 11: Energy & Ancillary Services Market Operations. Removes offer cap revisions for price-based offers that were approved at the October 2017 MRC to comply with FERC Order 831. PJM discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The manual is being revised to say that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is more than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.
3. PJM External Capacity Filing (9:40-9:55)
Members will be asked to endorse proposed revisions to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)
4. Balancing Ratio Issue Charge (9:55-10:10)
Members will be asked to endorse proposed revisions to the deliverables in the balancing ratio issue charge that the Market Implementation Committee is currently addressing. The revisions highlight the potential for changes to, and the underlying logic for, the market seller offer cap. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)
5. Operating Committee Charter Update (10:10-10:20)
Members will be asked to approve proposed revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves.” The revisions will match the language of other PJM manuals.
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.
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.”
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.
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.”
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.
“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.”
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.
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.
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’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.
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.
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.”
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.
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.)
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.
“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.”
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.
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.”
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?’”
