Sweltering temperatures led to three new ERCOT demand records in quick succession during June. The ISO has set eight highs for monthly demand during the last 12 months.
The Texas grid operator recorded consecutive peaks of 66.7 GW, 67.5 GW and 67.7 GW during the afternoon of June 23. The final number, and new record, came during the 4 p.m. hour, breaking the previous record of 66.5 GW set in June 2012.
ERCOT stakeholders unanimously approved a pair of revision requests in an email vote last week, following the earlier cancellation of the monthly scheduled Technical Advisory Committee meeting.
Both changes were approved by 22-0 margins. The TAC has 30 voting members.
NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. Adds solar resource registration inputs omitted from the greybox tab for RRGRR009.
The growth of distributed energy resources on the California grid will require new approaches and better coordination between system operators to avoid problems, state officials heard last week at a California Energy Commission workshop.
Representatives from utilities, DER companies and others advised members of the CEC and the California Public Utilities Commission on the various issues related to integration of new technology onto the electric grid.
The grid is becoming more decentralized, and the amount of DERs — including rooftop solar, energy storage and a host of other technologies — is expected to grow significantly in California in the next three to five years. Fleshing out communication methods between transmission operators, distribution utilities, DER providers and CAISO is one of the biggest tasks associated with incorporating the new systems.
The Amount of DER Including Rooftop Solar is Projected To Keep Growing
DER companies are trying to open new markets at various points in the electricity delivery system, including selling to utilities and retail customers, as well as through development of market mechanisms at CAISO. The ISO wants to enable that process to help balance output from renewables, and next month will present its Board of Governors with a suite of related new rules stemming from its Energy Storage and Distributed Energy Resources (ESDER) Phase 2 initiative. (See CAISO Finalizes Rules for DR, Distributed Generation.)
Distribution system operators (DSOs) should be able to advise DER providers and communicate with them on grid integration and operational issues, Pacific Gas and Electric Director of Integrated Grid Planning Mark Esguerra said. CAISO should also provide day-ahead DER schedules to DSOs, as well as develop a pro forma DER integration agreement.
The ISO often dispatches DERs without knowing if they are feasible on the distribution system and when there is little visibility on their effect on load and the transmission-distribution interface, Esguerra said. DERs are different from demand response and energy efficiency resources because distributed energy is not an absence of load, but rather additional energy being put into the system that must be managed.
Tesla Business Development Manager Damon Franz said DERs can mitigate the effects of energy infrastructure on water and the environment. He also argued they provide a wide range of services, including backup power, lowering energy costs and managing the intermittency of renewables.
Franz highlighted the importance of data on what needs DERs can satisfy. He requested that permitting be made easier and said interconnection for energy storage “should be no more complicated than simply deploying a device.”
But Jim Baak, program director at Vote Solar, noted that California utilities are being asked or required to forego capital investment in favor of DERs, which might not be in the interest of their shareholders. There should be a wider focus beyond policies and process changes, and state policy objectives should align with financial goals of stakeholders, he said. There are also concerns about overinvestment in DERs in the wrong locations.
“My concern is the vision is somewhat myopic,” he said. “What we really hope to achieve with distributed resources is to achieve policy goals.”
James Barner, resource planning engineer with the Los Angeles Department of Water and Power (LADWP), said that without an engaged interconnection process, DERs will affect reliability, including the problem of overgeneration at certain times. The utility plans to have 1,500 MW of distributed solar in the next 15 years, but DERs do create new problems on the system, he said, and rooftop and carport solar cannot be curtailed.
LADWP recognizes that DERs “add a lot of diversity to our renewables portfolio,” he said. Renewables represented 21% of the utility’s portfolio in 2016, but that is expected to grow to 65% by 2036. The utility plans to soon issue a Distributed Energy Resources Integration Study.
POUGHKEEPSIE, N.Y. — New York’s push to derive half its electricity from clean energy by 2030 must be accompanied by regulatory consistency to develop the necessary resources, panelists said at an energy forum last week.
State regulatory policy contains inherent conflicts that hinder renewable development, Paul DeCotis, senior director of energy and utilities at West Monroe Partners, said during the June 28 Renewable Energy Conference, hosted by the Business Council of New York State and the Hudson Renewable Energy Institute at Marist College.
DeCotis, who formerly served as energy secretary and chair of the state energy planning board for two New York governors, led a panel on regulatory structure.
Speaking about Long Island solar projects unlikely to be built because they’re proposed for green space, DeCotis said, “It goes against the policy of the state of New York on the one hand, in terms of renewable energy development, but it supports other green space initiatives. There’s always going to be an inherent policy conflict, which makes these goals even more difficult to attain. So it does take some certainty of regulatory environment, and it takes time.”
DeCotis noted that he and fellow panelist Paul Curran — managing partner of BQ Energy, a Poughkeepsie-based developer of wind and solar projects on brownfield sites — started talking about the state’s need for additional transmission infrastructure investments in 2007. Those projects are likely to come online in 2020.
“That’s 13 years for transmission to be built,” DeCotis said.
Consistency is Key
“I can play by any rules … but to the extent that the rules keep changing, it gets very difficult,” Curran said. “From a regulatory point of view, we love consistency.”
Regarding the troubled solar projects on Long Island, Curran said green space is the wrong location for renewable energy.
“There’s landfills all over the place; there’s brownfields all over the place — that’s the right place,” he said.
BQ didn’t build any transmission lines at the 35-MW wind farm it constructed in Buffalo. The developer spent just $1 to buy disused substations from a shuttered steel plant that used to draw 300 MW.
“We do the same thing with landfills,” Curran said. “There’s five or six landfills in the middle of New York City, nothing else can be done with them … but the closer we get to load centers, New York City, Boston, etc., the more people like Central Hudson [Gas & Electric] value the electricity,” adding that NYISO also recognizes the value of siting generation closer to where it’s consumed.
David Pacyna, CEO of North American T&D Group, said that when he talks to utilities about buying technology, “the concept of interconnecting renewables to make the utility assets perform properly under those scenarios of intermittency and so forth are, if not at the top of the list, very close to it.”
NATDG is a private equity fund that buys into technology service providers that sell to utilities in the U.S. and around the world. Prior to working for the company, Pacyna spent 30 years with Westinghouse Electric and Siemens and supervised construction of the Neptune project connecting Long Island with PJM, the Hudson transmission project and the Trans Bay Cable under San Francisco Bay.
“What does take it in hardware and software to make those rules that frustrate all but actually result in electricity coming out of the light socket?” asked Pacyna. “There’s a growing recognition [by regulators] of the need to invest in the grid.”
On rate designs, Pacyna said regulators in states such as Missouri and Illinois are starting to ask how they can best structure rates to incentivize investment in both grid modernization versus the grid of the future.
“Regulators also are asking how they can use performance-based rates to support investment in distributed energy and renewable resources,” he said.
Ray Wuslich, partner at Winston & Strawn, thought it would be easy to make a presentation in Poughkeepsie about the impact of the Trump administration on the power industry. But when he looked at President Trump’s energy policies, he found “there wasn’t much to go on.”
“We haven’t had any big ideas in the energy space, in energy policy, in over 25 years … really going back to the 1980s when FERC and Congress started looking at competition on the natural gas side and unbundling supplies from the pipeline transportation business,” Wuslich said. “It was crystalized in the Energy Policy Act of 1992 … and everything we’ve been doing since then has been evolutions of that.”
Former President Barack Obama pushed EPA’s Clean Power Plan, which Trump made a campaign issue for its impact on the coal industry, Wuslich noted. Now that Trump has called for repeal of the CPP, which may take up to five years to achieve, “the question is, can the repeal of that rule really save the coal industry and resurrect coal-fired generation?”
Wuslich cited the obstacles facing coal: economics (that is, cheaper, more efficient natural gas); an aging coal fleet; unfavorable state policies; renewable portfolio standards in 29 states and D.C.; major corporations that are focusing on sustainability and clean energy; and the apathy of utility executives, who are not rushing out to build new coal plants.
He noted that a recent Energy Information Administration report said repeal of the CPP could boost the prospects for coal.
“But does this make sense? Does this reflect reality, given where we are in the marketplace?” Wuslich asked. “There’s hardly a week goes by where you don’t see another blurb in the trade press that so and so is going to shut down 500 MW of coal, or 300 or 1,500 or whatever. It’s just a constant drip of these plants retiring, and that’s because of the market.”
HERSHEY, Pa. — Attendees at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference heard strikingly different prescriptions for how to fix the wholesale energy markets from the CEOs of New Jersey utility Public Service Enterprise Group and independent power producer Dynegy.
In a presentation Monday, PSEG CEO and Chairman Ralph Izzo argued that there’s a “missing money problem” among non-emitting generators. While net-metered residential solar generators are paid a premium of up to $415/MWh for being emissions-free in New Jersey, nuclear units receive no premium for having the same attribute and are paid PJM’s clearing price in their zone.
“We believe that wholesale power markets are experiencing some basic failures,” he said.
PSEG operates the Salem and Hope Creek nuclear plants in New Jersey and is a part owner of the Peach Bottom nuclear plant in Pennsylvania. With low-cost natural gas and subsidized renewables keeping energy prices low, owners of nuclear plants say the facilities are losing money and might be closed unless the states where they’re located cough up zero-emissions premiums for them as well. Such discussions are ongoing in Ohio, Pennsylvania, New Jersey and Connecticut. So far, only Exelon has been successful in securing credits for its units in Illinois and New York.
Izzo also called for changing customers’ bills to ensure that they see the premium they’re paying for solar. Customers of PSEG’s utility arm, Public Service Electric and Gas, have indicated that they’re unwilling to pay more than $5/month for additional renewable energy, but they’re already paying this much and aren’t aware of it because “we don’t tell them,” he said.
“Over the last three years, New Jerseyans have paid over $400 million a year for renewable energy credits, producing less than 2% of the in-state electricity,” he said. “I think that they are deserving of a transparent conversation on matters such as that, and I would be the first to champion the continued payment of that, but they are deserving of knowing about it.”
Dynegy CEO Robert Flexon stressed the favorable economics of his mainly coal- and gas-fired merchant generation fleet. He argued that subsidies for uneconomic units create a “subsidy death spiral” that pushes other units into becoming uneconomic and seeking a subsidy of their own. The result is a dismantling of the market’s basic function to procure energy at the lowest possible cost.
“That’s kinda what we signed up for,” he said.
Flexon argued that “utilities have a different DNA than a merchant generator” in that they are “leaning heavily on their core competency of dealing with the politics — which the [independent power producers] aren’t nearly as good at — and working special deals that upset the flow of the marketplace.”
When utilities are losing money, they go to governments for help, he said.
“You need to help yourself,” he said. “What I think is the biggest threat to reliability is the lack of coordination between the states and PJM, and the states doing things to take the economic generators and push them to the side.”
Dynegy originally sought a bailout for its Illinois coal units while Exelon was seeking the one it ultimately received for its nuclear units. When state support became unlikely, Dynegy pivoted to fight the zero-emissions credits (ZECs), joining a federal lawsuit challenging the state’s action.
Flexon called on regulators to require utilities to “match” any subsidies they receive with equal reductions to their annual dividend distribution. He cited FirstEnergy receiving an annual $250 million distribution modernization rider in Ohio while it distributes $600 million in annual dividends. He said it is unfair for Exelon to receive millions in ZECs over the next 12 years for five of its nuclear plants when it is able to pay $1.1 billion in dividends.
“I would say to the regulators, if you’re going to give them the money, you ought to look to their dividend,” he said. “If you want to shore up the balance sheet, I need the company match.”
In a panel discussion focused on wind energy, panelists also blamed utilities for artificially stalling market forces, but they defended renewable subsidies.
“The electric utility industry is an industry made of large institutions, and these large institutions have billions of dollars invested in assets that they own and operate, so my concern is that [they believe] renewable energy is a threat to the existing [way] of doing business,” said Markian Melnyk, president of Atlantic Wind Connection.
He referenced the assertions by Izzo and Flexon that the renewable sector is subsidized and “undercuts” their business. “My concern is that the federal government would hear that message and then take action to try to limit the advancement of renewable energy,” he said.
Avangrid’s Eric Thumma also defended existing pathways for renewables development, such as state renewable portfolio standards, joking that “it’s hard to take my blankie and my teddy bear away from me.”
State goals have proven effective, he said. “We know the RPS works. We know that it gets projects built.”
Beth Treseder of DONG Energy agreed. “We, too, are primarily looking to the states for leadership,” she said, but added that her company is also investigating how it can “take advantage” of the current federal focus on infrastructure development to improve critical ports and transmission lines.
For states themselves, the push to meet constituent demand for both cheap and environmentally conscious power means focusing on both costs and results.
“We’re balancing the economic and the environmental in our state,” Delaware Public Service Commissioner Kim Drexler said. “In my opinion, we’re really looking at the least expensive way to meet those requirements.”
HERSHEY, Pa. — A panel of financial analysts at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference peeled back the curtain on elements of their decision-making that can sometimes infuriate energy company executives and state officials alike.
The moderator, Diane Burman of the New York Public Service Commission, set the tone for the discussion by recounting her earliest memory of Wall Street workers. Her mother had warned her never to speak to them — a message that was reaffirmed when she joined the commission.
“The financial health of our energy industry is extremely, extremely important,” she said. “As commissioners, we struggle with what that means, and with what we do … good, bad or indifferent.”
The panel assured the audience that regulators have a major influence over how utilities are viewed by the financial sector. “We pretty much watch everything you do,” said Steve Fleishman of Wolfe Research. “We also care about how you communicate why you’re doing it.”
Analysts’ perception of the relationship between utilities and their regulators is the “primary driver of credit ratings,” said Lesley Ritter of Moody’s Investor Services.
Heike Doerr of S&P Global Market Intelligence said that one of the things that lowers ratings of commissions is inconsistency and uncertainty. Political influence tends to be a negative factor, she said.
One of the reasons why is because continuity can’t always be anticipated from state to state. “Ideally, we’d do things on a national-policy basis,” said Anthony Ianno of Morgan Stanley.
Fleishman noted another issue with a diminished federal vision.
“We’re moving into clearly ‘all of the above’ territory, and the one risk of that is it could get expensive,” he said, referring to recent moves by state legislatures to financially prop up certain types of generating resources. “If you support ‘all of the above,’ that means we’re paying for ‘all of the above.’”
He warned that “it’s crunch time” for states to determine which resources are most important to them.
“If states really have a view that they want to preserve nuclear or they want to preserve coal, they’re going to have to make that call relatively soon. … Now’s the time to make it clear what you’re trying to do,” he said. “There just needs to be an understanding that there’s costs to it, and there could be downsides to market functioning. … Maybe there’ll be a chance to do it in a more coordinated manner that keeps the functioning of markets in place.
“If we don’t figure this out,” Ianno warned, “what will end up happening is that those who can afford it will disaggregate from the grid, and the rest of the ratepayers will absorb all of the costs associated with the grid, and that’s a broken model.”
Doerr explained that her company’s state rankings are far more dynamic than might be expected. “It’s not just if your state is making improvement; it’s the pace at which improvement is coming relative to other states,” she said. “Many of you have companies operating in your jurisdictions that operate in other states, so the pipe needs to be upgraded everywhere.”
Analysts also complained about “black box” rate settlements that don’t provide any clarity on details like rate base or return on capital.
“If the law doesn’t allow it, why not change the law so there’s more transparency?” Ianno asked.
Texas regulators last week again refused to revisit their decision to reject NextEra Energy’s proposed acquisition of Oncor, the state’s largest regulated utility.
The ruling by the Public Utility Commission of Texas came just two days after Florida-based NextEra filed a 57-page request for rehearing. Commissioners Ken Anderson and Brandy Marty Marquez responded to the motion during a June 29 open meeting.
“It is time to bring this chapter in the [Energy Future Holdings] bankruptcy to a close and consider other options more suitable to Oncor and its ratepayers, as well as ERCOT and its market participants,” Anderson wrote in a memo.
Anderson said he remained unpersuaded “by [NextEra’s] regurgitation of essentially the same arguments” made in a previous rehearing request. He noted that “almost every intervenor” in the docket (No. 46238) supported the commission’s original decision and urged the PUC to deny the request.
Marquez concurred with Anderson’s memo during a discussion that lasted 30 seconds.
NextEra did not respond to a request for comment on its next steps following the decision. The company has for years eyed the purchase of Oncor, the lone successful business of bankrupt EFH. Proceeds from the sale would have been spread among EFH’s creditors, who last year reached a settlement to end a bankruptcy first declared in 2014.
NextEra filed its latest request for a rehearing June 27, arguing that the PUC overstepped its authority, ignored evidence, misinterpreted Texas laws and used bad judgment when it shot down the acquisition.
The company contended that the PUC’s opinion “constitutes arbitrary and capricious decision-making and an abuse of the commission’s discretion.” The commission’s final order contained 14 errors of law, NextEra said, and it intends to “preserve the company’s rights to judicial review.”
“The commission must determine whether a proposal to ‘change the ownership of the largest utility in Texas is in the public interest’ or whether the public interest is better served by leaving the state’s largest utility under the constraints of ownership by financial investors mired in bankruptcy,” the company said in its petition.
The PUC continues to operate with two commissioners while it waits on a replacement for former Chair Donna Nelson, who left the commission in May. Texas Gov. Greg Abbott is not expected to name Nelson’s successor until the end of the upcoming special legislative session, which begins July 18 and could last up to 30 days. (See Texas PUC Chair Nelson Stepping Down.)
Summer heat hit New England early this year, with load peaking at 20,181 MW on May 18 as temperatures in Boston and Hartford topped out in the mid-90s, resulting in transmission and unit outages and reductions that led to operational constraints, congestion and divergent pricing.
ISO-NE, which had 5,700 MW in planned outages, was hit with another 2,790 MW in forced outages at the peak hour ending at 6 p.m., COO Vamsi Chadalavada told the summer meeting of the New England Power Pool Participants Committee on Tuesday in his operations report for May.
Chadalavada said that the grid operator initiated an abnormal conditions alert (master/local control center procedure no. 2) at 9:30 a.m., which lasted until 10 p.m.
| ISO-NE
The Hydro-Quebec Phase II import limit dropped from 1,760 to 1,000 MW, while the NY-Northern Interface was nearly full at peak as total transfer capability dropped to 900 MW due to line outages. Northbound imports over the peak hours, coupled with constraints in Maine, resulted in congestion at the North-South Interface.
Fast-start generation was dispatched to meet the peak hour, pushing the average real-time price during the peak hour to $389.17/MWh, almost four times the average day-ahead price of $100/MWh. Real-time prices ranged from a high of $758.88/MWh in the Northeastern Massachusetts and Boston pricing zone, to a low of -$71.07/MWh for power from New Brunswick.
The energy market value in May was $283 million, up $3 million from April 2017 and up $67 million from a year ago. May natural gas prices were 4.7% lower than April but still 44% higher from a year earlier. Average real-time LMPs were $29.44/MWh in May, down 6.6% from April, but up 38% from a year earlier.
Committee Approves Settlement Terms for PER Complaint
Meeting in executive session, the Participants Committee on June 27 approved settlement terms that address all issues set for hearing in a dispute over the peak energy rent mechanism in the Forward Capacity Market.
In January, FERC granted a complaint by the New England Power Generators Association (NEPGA) against ISO-NE, agreeing that a penalty imposed during a summer heat wave proved that the PER is unjust and unreasonable (EL16-120). The commission agreed with the generators that the PER adjustment should be raised but said the amount should be determined in an evidentiary proceeding if stakeholders could not reach a settlement. (See ISO-NE Scarcity Rules Unfair to Generators, FERC Says.)
The settlement term sheet was approved by a show of hands with one vote in opposition and several abstentions.
The motion authorized officers of the Participants Committee to approve the formal settlement offer on the condition that all six committee officers agree. If the officers do not agree unanimously, the committee would need to hold a special meeting on July 14, 2017.
According to a memorandum from NEPOOL counsel David Doot, an agreement on Tariff language needs to wait until the commission rules on the issue of how to reflect capacity invoices issued after the refund effective date of Sept. 30, 2016. “Accordingly, the plan now is to finalize and file an offer of partial settlement without tariff language, and to approve changes to the tariff only if and after FERC rules on the proposed partial settlement and this unresolved, contested issue,” the memorandum said.
Terms of the settlement were not publicly disclosed.
NEPOOL Approves Tariff Changes for DR Integration
| ISO-NE
The Participants Committee on June 28 approved four Tariff amendments related to the June 2018 full integration of demand response resources (DRRs) into the energy, reserves and capacity markets. The changes integrate DRRs into the base Price Responsive Demand market design, as well as into new market designs implemented since the last New England Tariff filing under FERC Order 745 on DR compensation.
MISO and PJM could terminate or suspend pseudo-ties that no longer satisfy agreed-upon requirements under a joint proposal.
The RTOs’ proposal also includes a provision that would make each of them the native reliability coordinator for units pseudo-tied into the other balancing authority area, “responsible for transmission-related congestion on the transmission system where the pseudo-tied units are physically connected.”
The RTOs are adding coordinated pseudo-tie policies to their joint operating agreement. MISO last week released a first draft for stakeholder review.
The proposed rules also stipulate that pseudo-tied units must follow both PJM and MISO modeling procedures and obtain station service according to native balancing authority rules. They also make clear that pseudo-tied units committed as capacity resources in a delivery year cannot be directed to serve load in the native balancing authority when the attaining balancing authority requires the unit’s output — unless they are needed to avoid exceeding NERC operating limits in the native balancing authority. The RTOs also agree that only pseudo-tied units — and not the RTOs — are responsible for compensating an attaining balancing authority for failure to deliver energy.
“There were some common-sense coordination practices to add to the joint operating agreement,” MISO Senior Director of Regional Operations David Zwergel said during a June 29 Reliability Subcommittee call. He said MISO and PJM staff collaborated to come up with the proposed rules.
Zwergel said the RTOs expect to file the agreement changes with FERC in late July and asked stakeholders to submit written comments on the draft language by July 13. PJM is also reviewing the language with its own stakeholders, he noted.
The joint effort stems from two FERC deficiency letters in response to the RTOs’ separate attempts to implement more stringent rules in order to improve control over an increasing number of pseudo-ties between MISO and PJM. The letters asked both MISO and PJM to explain efforts they undertook to work with each other in developing the rules. (See MISO, PJM to Try Again on FERC Pseudo-Tie Filings.)
Both RTOs have said they plan to refile different versions of the stricter pseudo-tie rules. MISO initially said that adding standard pseudo-tie rules in the RTOs’ joint operating agreement was unnecessary but changed course earlier this year. It also recently asked FERC to schedule a technical conference to clarify the rules governing the implementation and use of pseudo-ties. (See MISO Asks FERC for Pseudo-Tie Technical Conference.)
During last week’s call, Entergy’s Jennifer Amerkhail asked why the RTOs also included rules governing “partial” pseudo-ties — an arrangement that accommodates generators that supply both RTOs.
Zwergel responded that earlier this year a MISO partial pseudo-tied resource failed to follow dispatch orders and overproduced on one side of the seam. The proposed rules expressly state that the portion of the generation dedicated to supplying the attaining balancing authority must follow its instructions, while the remaining generation must follow native balancing authority rules and dispatch.
Other stakeholders asked why the RTOs would include a requirement for 42-month written notice in advance of terminating a pseudo-tie.
Zwergel said the requirement is based on a six-month advance in addition to PJM’s three-year forward capacity auction. While the notice is unnecessarily long for MISO, it is necessary to accommodate the RTOs’ disparate capacity auction schedules, he said.
POUGHKEEPSIE, N.Y. — Capital markets this year are more willing than ever to finance green energy projects, said a panel at the Renewable Energy Conference last week.
“None of the terms have changed; the deals haven’t changed. What’s changed is banks’ appetite for renewables, and they’re willing to price down and move in on these deals,” said Denis O’Meara, managing director of energy and natural resources at BNP Paribas, who sat on a panel on renewable project financing.
The Business Council of New York State and the Hudson Renewable Energy Institute hosted the event at Marist College Wednesday.
“If you have a project and the project has merit, it’s going to get financed,” said panel moderator Scott Medla, managing partner at Ansonia Partners. “The institutional investors, the private equity guys, the banks — they have more money than they could possibly ever use to fund every project in America. The issue for them is finding the right project, the one that fits.”
Caroline Angoorly sat on the panel as COO of the New York Green Bank, a billion-dollar fund supported by ratepayers and part of the state’s $5.3 billion Clean Energy Fund.
“The idea of New York Green Bank is to play in what we call that one standard deviation, on either side of where current energy project financing markets play,” Angoorly said. “As these new energy models get new traction [and] become more ubiquitous, [we] provide liquidity when traditional sources of capital may not be ready.”
Medla said that significant improvements in technology are helping drive banks’ interest in financing green projects.
“We’re seeing tremendous advances in creativity around transmission lines. We’re seeing wonderful things happen in the area of storage,” Medla said. “My view is that the lithium-ion batteries … are going to get surpassed pretty quickly with some of the creativity that I see out on the margin.”
Wind projects in New York are more difficult to finance than in other parts of the country, according to O’Meara. “The reason is wind regimes and terrain, so you have to be very specific and you have to have very good wind studies to be able to build a wind turbine or wind farm here. … We’ll go up to 15 years in financing, maybe even longer depending on the [power purchase agreement]. … I’m telling you that because those are really pretty aggressive terms that we’re seeing out there in the market right now.”
Finance pricing now ranges between 1.35 and 1.75 percentage points more than the LIBOR, which O’Meara called attractive terms.
“The variable between the spreads really go to sponsor, technology, capital in, how much you’ve done — we’re going to look at all that when we make that determination of [if] we go ahead and finance,” O’Meara said.
BNP also does bond financing on wind, which tends to be a bit more lenient in its terms.
“You get a longer tenor [loan term] — sometimes less debt — but longer tenor, so you can put the deal to bed,” O’Meara said. “Solar’s more predictable: You know what it’s going to be on each season, and it works out more easily for us to think through a solar financing. Banks will go pretty long on solar as well, construction plus 18 or 20 years.”
Community Power
Angoorly cited the Green Bank’s $600 million pipeline of coming projects, including storage and microgrids, the latter supported by “a lot of pent-up demand for community-aggregated generation.”
O’Meara said he had similar experience with what is called community choice aggregation in California.
“In Marin County, they wanted to do this,” he said. “It’s a very good idea but really hard to bank at this point. … It’s not standardized. Many times I would call it the commune of power, because these people are putting these deals together and I have no idea what they’re saying. … I don’t know where they wrote it — probably in a coffee house — but it did not make sense.”
But fuzzy contracts haven’t stopped projects from moving forward.
“In fact, they’re getting the off-takers and the off-takers want to finance this,” O’Meara said. “It’s an evolving market. I guarantee you it will move into a more commercial purview shortly, but it’s not there now.”
Massachusetts officials said Friday the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020 — an unambitious goal to some observers.
Although the Department of Energy Resources’ (DOER) announcement called the 200 MWh “an aspirational” target, some industry stakeholders expected more from Gov. Charlie Baker’s Energy Storage Initiative. The department’s State of Charge report, released in September, presented recommendations for generating 600 MW of advanced energy storage by 2025, saying it would capture $800 million in system benefits. (See Mass. Considering Storage Mandate.)
| DOE Global Energy Storage database and Massachusetts Department of Energy Resources
“Based on lessons learned from this initial target, DOER may determine whether to set additional procurement targets beyond Jan. 1, 2020,” DOER Commissioner Judith Judson said in announcing the target. The state also agreed to spend $10 million on energy storage demonstration projects in addition to the $10 million that accompanied the ESI announcement in May 2015.
Judson said the state also had begun implementing other recommendations from the State of Charge report, allowing storage to be paired with the state’s plans to procure 9.45 million MWh of clean energy and 1,600 MW of offshore wind.
She also said the state was “incentivizing” storage through the Solar Massachusetts Renewable Target (SMART) program and that storage would be funded by alternative compliance payments under the ACES Grant Program, the Peak Demand Reduction Grant Program and the Community Clean Energy Resiliency Initiative, and that storage would be eligible for future Green Communities grants.
| Massachusetts Department of Energy Resources, Massachusetts Clean Energy Center
It also is considering allowing utilities to use energy-efficiency funds for storage that provides sustainable peak load reductions and expanding energy storage in the Alternative Energy Portfolio Standard.
“It’s less of an aspirational target, something the state’s going to strive for, and more a description of what the state is already doing,” said Ted Ko, director of policy at Stem, a provider of commercial-scale energy storage. “It’s entirely possible they would have met [the target] anyway. For example, Eversource [Energy] has already proposed over 180 MWh of storage projects in a recent rate case.”
Ko said the SMART program, whose regulations were released last month, “by itself conceivably could come up with 100 MWh.”
“Essentially, by setting a low, voluntary target number, you’re not inspiring any new programs or new initiatives as outlined in the State of the Charge report,” he added.
The announcement drew similar, if more temperate, comments from others, including Chris Rauscher, director of public policy at residential solar company Sunrun.
“The decision by DOER to set a soft energy storage target of 200 MWh is a moderate first step in providing long-term market surety,” Rauscher said. “Growing the storage market in Massachusetts has the potential to support local job creation and lower costs for Massachusetts ratepayers, all while providing critical resiliency through backup power.”
Rauscher said the company would work with legislators to expand storage’s potential “by encouraging private investment in Massachusetts through programs like the Alternative Energy Portfolio Standard.”
The Energy Storage Association noted that Massachusetts utilities previously proposed “specific, albeit voluntary, procurement targets of a combination of up to 200 MW/500 MWh of energy storage. Today’s announcement is a more conservative step in that direction.
“Massachusetts is also competing for industry jobs with California, Oregon, New York and other states moving forward on their own storage procurement targets,” ESA added.
Massachusetts becomes the second state in the U.S. to mandate storage. The California Public Utilities Commission in 2013 ordered the state’s three large investor-owned utilities to add 1.3 GW of energy storage by 2020.
New York lawmakers last month passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030. If signed by Gov. Andrew Cuomo, the new law would require the commission to work with the New York State Energy and Research Development Agency and the Long Island Power Authority to set up a storage deployment program. (See NY Bill Sets Stage for Storage Targets.)
