SACRAMENTO, Calif. — While CAISO has in recent years made strides in incorporating demand response into its wholesale market, it was forced to recalculate its 2016 DR settlements because of missing performance data, the grid operator said Tuesday.
ISO representatives, DR companies, utilities and others industry participants met with state regulators to discuss the challenges associated with implementing more DR into grid operations and markets.
CAISO Infrastructure and Regulatory Policy Manager Jill Powers said the grid operator last year altered its market models to make DR registration and ISO modeling more efficient. But problems within the legacy DR system resulted in settlements that relied on incomplete and missing performance data.
The ISO reprocessed all 2016 DR performance data, which will be reflected on the next settlement recalculation statements for DR providers. Full resettlement is due to be completed by October. The ISO next year will replace its legacy DR process with “more robust systems,” she said.
“We have taken corrective actions for all the dates identified,” Powers said.
CAISO in 2015 implemented a program that allowed emergency-triggered DR to offer spinning reserve services into the ISO market. San Diego Gas & Electric began providing non-spin and spinning reserve market services through the program that same year.
The grid operator is currently managing a number of initiatives regarding integration of DR and distributed energy resources. The ISO’s Board of Governors last month approved a package of market rules that included new baselines to better reflect the performance of various types of DR. (See New CAISO Rules Spell Increased DER Role.) The ongoing Flexible Resource Adequacy Criteria and Must Offer Obligations 2 initiative also includes new flexible capacity categories available to DR. (See CAISO Flex Capacity Effort Targets Increased Variability.)
CAISO’s 2016 enhancements significantly reduced processing timelines and management of new DR resources. They also implemented new sub-load aggregation point boundaries and relaxed telemetry requirements, which lengthened the scan rate when providing telemetry to help lower costs for DR.
An uncertain market structure and frequent rule changes are inhibiting expansion of DR, as well as increasing complexity of integration, EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd said. There are inconsistencies between CAISO rules and Public Utilities Commission rules and frequent changes in program requirements, she said. EnerNOC supplies DR services around the world.
California Energy Commission Chair Robert Weisenmiller said that integrating DR is “a very challenging area.”
“We are moving to a system that is going to be highly decentralized, and we are going to need visibility and automation to manage it,” he said.
On Wednesday, the commission adopted new guidelines for ensuring that publicly owned utility resource plans comply with requirements from SB 350, the 2015 law that included new greenhouse gas emission reductions and increased renewables procurement for utilities.
MISO’s Advisory Committee sectors voted against a proposal to allow stakeholders to annually elect leaders of the RTO’s Steering Committee through an independent nomination and voting process.
The outcome of the email ballot will keep intact MISO’s eight-year-old practice of automatically appointing the chair and vice chair of the Advisory Committee to serve in their opposite capacities on the Steering Committee. The motion, which failed 7-11 with two abstentions, would have permitted Steering Committee leaders to be selected in a process identical to that of the Advisory Committee.
MISO’s Transmission Owners sector had requested the vote to grant the Steering Committee greater independence from the Advisory Committee, which in June decided to delay action on the proposal. (See MISO Steering Committee Elections Decision Delayed.)
“There is an interlocking nature between the Advisory Committee and the Steering Committee,” current Steering Committee Chair — and Advisory Committee Vice Chair — Tia Elliott said during a July 26 Advisory Committee conference call. She said both committees receive stakeholder committee reports and work together to select topics to discuss before the Board of Directors.
MISO Stakeholder Relations Specialist Alison Lane said the Steering Committee began as an ad hoc group to assist the Advisory Committee in “managing the many different topics and charters of the many working groups and task forces” that existed at the start of the RTO’s market.
Ameren’s Ray McCausland said MISO at that time was “a small, start-up RTO” and the “flip-flop” leadership was put in place because there weren’t many stakeholder volunteers from which to choose.
With the stakeholder redesign two years ago, the Steering Committee took on an expanded role, with more authority to update MISO’s Stakeholder Governance Guide, which provides the governing guidelines to stakeholder committees. The redesign also dictated that issues must first be submitted to the Steering Committee for committee assignment in order to be discussed in stakeholder meetings or added to the Market Roadmap list of market improvements.
“The genesis of this proposal really goes back to the stakeholder redesign effort,” said Entergy Vice President of Federal Policy Matt Brown, whose TO sector submitted the unsuccessful motion. “We think it would be more effective and an improvement to directly elect those leadership positions. It’s really just housekeeping — or routine maintenance might be a better way to put it — to improve Steering Committee leadership. It’s anomalous right now. Every other MISO stakeholder committee leadership is elected.”
Brown pointed out that under the proposal, Advisory Committee leadership would still be eligible to run for Steering Committee leadership, albeit alongside any other interested stakeholders. “There’s no reason to restrict anyone from running for the office,” he said.
FERC’s quorum was restored Thursday as former Pennsylvania Public Utility Commissioner Robert Powelson was sworn in, joining former Senate Republican aide Neil Chatterjee, whom President Trump named acting chairman.
The filling of the third seat allows FERC to issue rulings in contested cases, which had come to a standstill when former Chairman Norman Bay resigned in February after Trump named Commissioner Cheryl LaFleur acting chair.
Chatterjee will serve as acting chair pending the confirmation of Republican attorney Kevin McIntyre, whom Trump selected to hold the gavel and direct the commission staff. McIntyre and Democratic Senate aide Richard Glick are scheduled to have confirmation hearings before the Senate Energy and Natural Resources Committee on Sept. 7.
“I want to thank Chairman LaFleur for the tremendous work she’s done in guiding the agency,” Chatterjee said in a statement. “The absence of a quorum was unprecedented, yet she rose to the challenge and created stability through her unwavering leadership.
“I look forward to working with Commissioner LaFleur and Commissioner Powelson on behalf of the American people. And I hope that we will have all five Commissioners here soon with the confirmation of Kevin McIntyre and Rich Glick.”
FERC also announced that it will resume its monthly open meeting schedule next month, with the first meeting set for Wednesday, Sept. 20.
With the quorum restored, Chatterjee said, the commission will soon begin notational votes on its backlog of dockets.
FERC staffers have been acting since Feb. 4. under limited delegated authority that allowed them to grant waivers and approve settlements in uncontested cases, as well as take interim action on rate filings, subject to refund pending further orders by the commission.
According to LaFleur, FERC has issued only a fraction of the 100 commission-authorized orders it averages a month.
The delegation period will end in two weeks following the restored quorum.
NEW YORK — Keith Powers attracted attention in energy circles last month when he wrote an op-ed in Crain’s New York Business advocating that solar panels be floated on the Central Park reservoir.
The park abuts the 4th City Council District — the “Silk Stocking District” — from which Powers is running for a seat. He faces eight rivals in a Democratic primary Sept. 12.
When he spoke to RTO Insider at Times Square early this month, Powers had just been endorsed by the New York League of Conservation Voters, a statewide environmental organization that advocates for clean water, clean air, renewable energy and open space through political action.
“I’ve had very good feedback on my idea to put solar panels in Central Park,” Powers said. “There was a discussion on Mayor Bill de Blasio’s plan, which he calls 80 x 50, to tackle climate change, a very ambitious plan whereby New York City’s greenhouse gas emissions will be 80% lower by 2050 than in 2005. The mayor talks about environmentalism and has big ideas and a plan, so if I’m going to be down at City Hall, I need to be working to make that plan a reality.”
Can New York City on its own create a plan and follow through to reduce its carbon footprint?
“Not only create and follow through,” Powers answers, “but also show the world that a big city can achieve it, can think outside the box, can very realistically help the world tackle climate change.”
Why Floating Solar Panels?
Powers gained government experience working for the State Senate and serving as chief of staff for a member of the State Assembly. Before running for City Council, he was a vice president at Constantinople & Vallone Consulting, a lobbying firm.
He said his point in writing the op-ed piece was to propose something that had not been spoken about so far.
“The district I’m running in includes parts of Times Square, Bryant Park and Museum Mile, all the way up to the Upper East Side, so it truly is the world’s city council district,” he said. “It’s important that the person representing it thinks bigger than just local politics. New York City on its own can be both a global leader on particular issues, but also can solve certain issues just based on the density of the population.”
Solar panels would not detract from the recreational role of the reservoir in Central Park, while their presence would send a powerful signal on the city’s commitment to renewable energy, Powers said.
California is also considering floating solar panels on reservoirs because, aside from the power generation, they also decrease water loss through evaporation and prevent the kind of algae blooms currently afflicting the Central Park reservoir. The cooling effect of the water also increases the efficiency of the panels.
Steal My Idea
“We haven’t seen floating solar in New York yet, but at this moment, when we have a federal government that’s not looking to tackle climate change — in fact doing the opposite — we have cities that are trying to do that work on their own,” Powers said. “We have a very uncertain future in terms of the planet we live on, so not to put all ideas forward would be a missed opportunity.”
Powers wants people to visit New York City and say “our city should be doing that.”
“Philadelphia has a website that features what’s going on in other cities and it’s titled ‘Ideas We Should Steal’ — and I wanted this to be an idea other people would want to steal,” he said. “And many of the ideas featured on that website are from New York City. We learn from each other. I learned of floating solar because I saw that China was doing it. Ideas adapt and migrate, just like birds.”
Huainan Solar Farm in China | Sungrow Power Supply
A lifetime resident of the city, Powers looks to young people to bring about change over the long term — especially to public schools to equip youth with the tools to generate ideas.
“One in 300 Americans are in the New York City public school system, and solving issues like poverty or creating a cure for the next disease can come directly out of our schools,” Powers said. “When we talk about environmental issues, there’s no better way than schools for getting both our students and our city better equipped to deal with the future in terms of climate change.”
Better Buildings
Powers noted that his district has some of the poorest air quality in the city, mainly because its buildings are big polluters.
“We don’t think of buildings that way; we think of vehicles and factories, but our worst polluters in this city are the buildings that we live in,” Powers said. “With new development, we have an opportunity to change the standards and make them more eco-friendly. But with our aging infrastructure, many of the buildings are polluters, so we have bad air quality in Manhattan, period, and my district ranks badly because we’re so dense and have so many big buildings. A lot of the new office buildings are LEED-certified and very progressive in terms of their standards, but old residential buildings keep burning that dirty fuel oil.”
Changing human behavior is the most difficult part, he said.
“We can build nice buildings with the newest technology, but we still have to change human perceptions of what is right,” Powers said. “There is social pressure, the ‘do-good factor.’ And I think it’s great if a company thinks it can win public favor by being a better corporate citizen. But we all go home somewhere every day, and I think a lot of homes are still five to 10 years away from the technology that can really make them energy efficient.”
DTE Energy is making its last stand in a seven-year battle to avoid paying out millions of dollars in penalties after being found to have improperly accounted for emission increases stemming from upgrades performed at a coal plant.
The Michigan-based utility filed a writ of certiorari last week asking the U.S. Supreme Court to review a lower court’s ruling in favor of EPA in the case, in which the agency argued that the company upgraded Unit 2 at its Monroe plant without considering the resulting increase in emissions.
DTE Energy’s Monroe Power Plant | Port of Monroe
The 6th U.S. Circuit Court of Appeals declined to rehear the decision, upholding EPA’s power to halt construction at power plants the agency believes have not properly accounted for possible added air pollution (14-2274 and 14-2275).
“Left standing, the decision … threatens to paralyze substantial maintenance projects throughout the nation,” DTE said in its petition. The company filed successfully in May to delay the issuance of a mandate in the case while it petitioned the high court.
EPA sued DTE in 2010 after the utility replaced boiler components at the Monroe plant without installing additional pollution controls. The agency alleged that DTE violated the Clean Air Act’s New Source Review (NSR) provision, which is designed to protect air quality when industrial facilities are newly built or modified.
DTE maintained that the higher emissions from the Monroe plant were a product of demand growth and not caused by the boiler improvements. The company also claimed the $65 million project was routine maintenance exempted from NSR permitting.
EPA called the project a major overhaul that should have included new pollution controls and asked for civil penalties of up to $37,500 per day. By 2014, DTE had installed four selective catalytic reduction units and four flue gas desulfurization units at the plant for a total of about $2 billion.
The company maintains that it properly evaluated whether the upgrade would trigger the “costly and time-consuming” NSR permitting process, but it found no projected emissions increase.
“To add insult to injury, the government seeks to penalize DTE for failing to make that demonstrably inaccurate preconstruction emissions projection,” the company said in the petition. The utility also called EPA’s suit “an Orwellian type of enforcement action.”
| DTE Energy
In a late July earnings call, DTE CEO Gerard Anderson reaffirmed the company’s recent public announcement to reduce its carbon emissions by more than 80% by 2050 by eliminating coal generation. Under the plan, the 46-year-old Monroe station would cease operations in 2040. DTE has not said how it plans to replace the generation.
CAISO has dropped a proposal that would have allowed third-party transmission providers to participate in the Western Energy Imbalance Market (EIM) after getting negative feedback on the plan — but also said it might revisit the idea in the future.
The grid operator proposed that transmission owners outside the EIM be permitted to provide service between EIM balancing authority areas (BAAs) and receive congestion revenue for increasing the market’s transfer capability. But CAISO determined that the TOs would be decreasing their own potential for collecting congestion revenue by providing the increased capacity, resulting in inadequate compensation. In addition, the ISO cannot pay directly for transmission service.
Diagram of Third-Party Transmission Service | CAISO
“There were concerns that implementing this would outweigh the benefits,” CAISO Senior Policy Developer Megan Poage said in an Aug. 7 call. “Many parties were not sure this would be fully used.” But she asked for more comment, saying that CAISO wanted to ensure that all stakeholders were on board with removing the proposal. While the ISO said the plan could be revisited, EIM entities were generally uninterested in using the functionality.
The grid operator floated the third-party transmission idea as part of its Consolidated EIM Initiatives straw proposal being developed with market participants. The initiative also includes new wheeling policies and tools to manage bilateral schedule changes. (See Consolidated EIM Proposal Effort Gets Underway.)
Imbalance Risks
Regarding the management of bilateral schedule changes, CAISO is trying to address the fact that EIM participants are exposed to unknown imbalance settlement payments for making changes not reflected in their base schedules. Prior to the development of the EIM, firm transmission holders could make schedule changes without facing later settlement payments, CAISO said.
CAISO Senior Market Designer Don Tretheway said that a stakeholder workshop on intertie bidding unearthed concerns that, prior to the EIM, transmission holders could make schedule changes up to a certain point without being exposed to later settlement payments. He said that EIM participants through their transmission tariffs could manage the exposure, and part of it could be solved through the wheeling functionality.
Some EIM participants said that bilateral schedule changes should be subject to imbalance energy charges because they can cause the BAA to incur redispatch costs, CAISO said. However, most feedback on the proposal was neutral. Some stakeholders did say the proposal does not address fundamental issues about the inability to hedge imbalance settlement charges.
Sharing Benefits
The consolidated initiative also aims to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-throughs are on the increase as the EIM footprint expands, but wheeling entities only receive congestion revenue.
“The entity in the middle right now receives no direct financial benefit for facilitating a wheel” if there is no congestion, Poage said. But “without them being there, that transfer would not have occurred.”
The issue will become increasingly important when Powerex is integrated into the EIM in April 2018, with Puget Sound Energy positioned to wheel power from British Columbia to the south. (See Powerex Slated to Become First Non-US EIM Member.) Wheel-throughs could also start occurring in more than one BAA.
The benefit-sharing is seen as essential for some to recover costs of power flows caused by EIM dispatches, and preventing perceived price distortions and free riders. CAISO is also paying attention to cost-shifting between TOs and customers because of the loss of transmission revenues, but it said the issue will not be considered in this initiative. Others say that BAAs doing the wheeling share in other benefits and that the benefit-sharing might reduce incentive to invest in EIM-dispatchable resources. Stakeholders also expressed concerns over rate pancaking and reduced liquidity.
CAISO compiled data on EIM transfers and BAA imports and exports within the market, and asked for help in determining the net benefit of facilitating a wheel-through transaction to better quantify the benefits of the proposal. The grid operator said that net wheeling will increase as the EIM footprint expands.
For more equitable sharing of wheeling benefits, CAISO proposed either an after-the-fact payment based on the amount of net wheeling, or a market-based method that allows for competition.
As part of the Consolidated EIM Initiatives, CAISO proposed a series of new functionalities including automatically adjusting schedules of non-EIM entities to eliminate the need for physical dispatch instructions, which also facilitates management of changes to bilateral schedules.
The EIM Governing Body has primary authority for approving the changes because the market rules would not be proposed absent the existence of the EIM. The body is due to review the proposals Oct. 10, which then go before the ISO Board of Governors on Nov. 1. CAISO is taking comments until Aug. 17.
Weeks after stakeholders introduced six proposals for redesigning PJM’s capacity construct, another three have materialized. Many of the nine are variations on a two-stage auction repricing structure, while others envision vastly different procedures.
All nine were presented and explained at a two-day meeting last week of the Capacity Construct/Public Policy Senior Task Force, which was created earlier this year to address concerns about state subsidies of generators undermining PJM markets. It has been moving to have an agreement endorsed and filed at FERC by the end of the year. PJM has held several two-day task force meetings to accommodate the depth of discussion stakeholders have demanded for the process. (See PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)
The proposals can be broadly categorized among those revamping the entire construct, developing repricing processes that accommodate subsidized units and extending a rule intended to eliminate the impact of subsidies.
The revamp proposals include full-scale redesigns from American Municipal Power and the Natural Resources Defense Council, and a limited revision to existing fixed resource requirement (FRR) rules called “Capacity Choice” proposed by John Horstmann of Dayton Power & Light.
The repricing proposals originated from a two-stage auction design by PJM. Many felt it unfairly discriminated against units on the margin in the capacity auction and proposed tweaks that would either reduce capacity awards (NRG Energy) or reduce the clearing price (LS Power). Another proposal would trigger repricing only if the clearing price rises to a level that incentivizes new generator construction (Exelon), while a fourth would calculate the clearing price by removing subsidized offers and scaling the remaining competitive offers to replace the shortfall (Old Dominion Electric Cooperative).
ODEC’s Mike Cocco said other repricing proposals utilize reference pricing schemes to replace the market offers from subsidized resources but failed to account for what would be corresponding change in the supply stack. ODEC’s proposal was designed to fully synthesize an auction as if subsidized units never existed and competitive units covered the entire demand.
“Once you open that door and decide you’re going to reprice with reconstituted offer prices, you have to open that door all the way,” Cocco said.
Monitoring Analytics, the Independent Market Monitor, proposed an extension of the existing minimum offer price rule that would require units to undergo analysis every year they receive subsidies without an exemption — requiring them tosubmit the variables and equation they used to calculate their offer. The Monitor would then review the submissions for competitiveness, much like it now does with fuel-cost policies and cost-based offers. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)
“If states want control over their assets, they should reregulate — and that’s fine,” Monitor Joe Bowring said. “If we’re going to have markets, we should have markets.”
James Wilson of Wilson Energy Economics also provided comments on the redesign proposals, arguing that “markets are not as fragile as some suggest.” With enough lead time, markets have a “substantial ability to absorb incremental/decremental resources with minimal impact on prices,” said Wilson, who consults for the consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C.
He predicted that the process would settle on “some sort of two-tiered pricing,” for which he has concerns. He also expressed reservations about expanding the MOPR.
The comments found some favor with AMP’s Ed Tatum, who has argued the best solution is to replace reliance on the annual capacity auction with long-term bilateral contracts between generators and load-serving entities.
“With enough notice, the true market would be able to absorb these things,” he said.
He also liked Horstmann’s “Capacity Choice” proposal, which would allow LSEs to determine how they want to fulfill their capacity obligations, either through long-term contracts under the existing fixed resource requirement (FRR) rules, annually through the existing Reliability Pricing Model or some combination of the two extremes.
All current and future subsidized units would be required to choose the FRR option, which would eliminate their potential influence on the RPM auctions. The entity enacting the subsidy would have to elect how it would be funded through its rate base.
“This is kind of a different approach than some of the ones you’ve seen before,” Horstmann said. “As opposed to being told how to manage your capacity obligation, basically what I’m putting on the table here is you get to choose how to manage your capacity obligation.”
He outlined several as-yet unanswered questions but noted that because the structure is largely already approved by FERC, it would require minimal Tariff changes. He said he analyzed the stakeholder proposals to address as many interests as possible but couldn’t include all of them — such as proposals to trigger repricing.
“Clearly it doesn’t accommodate the one that doesn’t think there’s a problem,” he said.
Going forward, PJM plans to distribute a poll to judge stakeholder interest in each of the proposals, including the status quo. The poll results, if emphatic, could determine the CCPPSTF’s ongoing direction and which proposals receive the most attention.
PJM is looking to schedule another meeting on Aug. 17, followed by meetings on Aug. 23, Sept. 11, Sept. 12 (if possible), Sept. 26, Oct. 16, Nov. 1, Nov. 21 and Dec. 11.
NEW YORK — New York’s grid is transitioning from a one-way transmission system to a multidirectional one, and utilities still need time to develop the analytical tools to understand how to deal with distributed energy resources.
“We are at a very early stage of bringing DERs into what has historically been a passive distribution system,” NYISO Senior Manager for Market Design Michael DeSocio said during a panel on the ISO’s DER Roadmap, which outlines the grid operator’s plans for integrating DER into its ancillary services, capacity and energy markets over the next five years.
“We want to get to a 21st-century grid, but we’re still running 20th-century computer systems. We’re still running 20th-century metering,” DeSocio said.
Natara G. Feller of Feller Law Group posed some of the main questions on the topic: “In NYISO’s bulk transmission system versus Con Ed’s distribution system, how do DER resources impact reliability? How can we shave the peak off the grid? How does this impact the state’s requirement for meeting certain capacity standards? What kind of obligations are consumers going to assume, or are they passive obligations where they’re not assuming responsibility?”
“Are we going to have deployment first, or the markets first?” asked Chris Rauscher, director of public policy at Sunrun, the country’s largest rooftop solar company. “As my company and others deploy more storage paired with PVs, are we going to do that in states that already have open access to markets, or are we going to other states that have incentives, for example? And how do we sync all this up together?”
Ben Pickard, a distributed energy analyst at National Grid Ventures, which has a strategic partnership with Sunrun, said the development of a DER roadmap comes with the risk that ISO will “overbuild and structure for every contingency at the expense of just trying to get markets going.”
DeSocio responded that distribution systems must evolve because they haven’t necessarily been designed to deal with all the traffic they will handle with increased DER adoption. The ISO will need enough information to determine whether its own actions create a reliability issue for utilities, which — in turn — are trying to learn how to spot ISO-driven reliability needs on their systems.
Pickard pointed to one outcome of an ISO roadmap that contemplates its system at the sub-nodal level. In such small and specialized cases, he said, “market power becomes a real issue, and you’ve created all these tiny markets that are quite hard for regulators — it’s like a Hydra problem.”
Speaking on a different panel on defining value stacks for DERs, Kelli Joseph, director of New York market and regulatory affairs for NRG Energy, said, “It’s really difficult to forecast some of the values within that value stack. Some of it is intended to be fixed, but then some of those fixed values aren’t fixed for the entire length of what the tariff is supposed to be. These are 20- and 25-year projects where some aspects are fixed for only a couple of years and others for even less than that.”
Capacity Factor
Divorcing the market from physics is a recipe for trouble, DeSocio said. If the market creates incentives that don’t recognize the limited capacity on wires — and price signals are faulty — the system is going to get response that it can’t handle, he said.
“We have to rethink what is capacity,” DeSocio said. “In the wholesale and the retail space, capacity is measured against one hour of one day of one year, and we do that every year. But there’s going to be more days to become important and we need to start to think about how we change both the viewpoint and the value of the ICAP [installed capacity] tag. The ICAP tag is how we currently couple the retail rate with the wholesale rate, and so that will be important for the capacity portion of value DER or other retail rate usage of the capacity portion.”
| NYISO
NYISO prices energy and reserve use on a five-minute basis, but it doesn’t apply that same time-based standard to resources that are asking to sell at the retail rate. Including the time factor would better couple the value of DER with the wholesale market price, according to the ISO.
Paul A. DeCotis, a former state planning official now with West Monroe Partners, said the DER pricing challenge could be likened to the early years of co-generation or energy efficiency when “we had difficulty assigning value to the reductions in load or in the kilowatt-hours saved.”
“A monthly average LMP does not help me drive or motivate behavior of any sort,” DeSocio said. “I smooth it all away, it’s gone. The three days a month that I as a grid operator am worried about how I’m going to meet the next megawatt of load, those price signals are gone in a monthly average LMP. As we do that, there’s less need for some of these other ‘rough justice’ or ‘fudge factors’ in those reads, because now you’ve exposed the exact time and locality information into the rate itself and the resources that can best fit that need are going to profit the most.”
In the longer term — such as over the next 10 years — DER will look a lot like today’s demand response space, where those resources become more capable of providing near-term action for real-time reliability, DeSocio said.
NEW YORK — New York state wasn’t the first out of the gate on offshore wind, but it will be the biggest player if it meets Gov. Andrew Cuomo’s 2,400-MW target. State policymakers are embracing offshore wind for its utility-scale generation, its ability to be developed close to the major load centers of New York City and Long Island — and its potential jobs.
“Right now, there are over 300,000 jobs in the offshore wind industry in Europe,” Sierra Club Senior New York Representative Lisa Dix said last week when she moderated a panel at the Infocast New York Energy REVolution Summit at Times Square.
The federal government has identified more than 100 GW of offshore wind potential off the Atlantic coast, and the Bureau of Ocean Energy Management has moved forward with the offshore wind lease process in New York and seven other states. The first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens, went to Norway-based Statoil last December.
“Offshore wind provides power when it’s needed the most, at peak times,” Dix said. “And it’s at a scale that the state needs not only to fulfill its renewable energy policy goals, but also to help combat climate change, where New York City and Long Island are really on the front lines.”
State and Stakeholder Support
Chris Wissemann represents the U.S. activities of Germany-based offshore wind developer Innogy, which he characterized as being four times the size of Consolidated Edison and generating enough electricity to serve the entire load of New York state.
“Long-term, stable policy is what makes this become cost-effective,” Wissemann said. “Along those lines is the corollary, which is the four P’s: politics-proof purchase program. Look at Cape Wind, several years ago: The minute their benefactor was out of office, they lost their [power purchase agreement]. New Jersey’s OSW economic development program was never implemented because of politics.”
Cuomo in January called for 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island.
The growing breadth and depth of support for offshore wind is spectacular, but not surprising, said New York Offshore Wind Alliance director Liz Gordon. All the different interest groups don’t necessarily have the same reasons to support OSW, she said.
“Environmental groups clearly see clean, reliable offshore wind power as a climate change solution, or at least a mitigation,” Gordon said. “Labor in New York state is all-in; they’re vocally supporting offshore wind because they see massive job potential — good jobs, quality jobs. That will depend on there being a reliable pipeline of projects and ideally a port or two here in New York.”
Greg Matzat, senior adviser on large-scale renewables at the New York State Energy Research and Development Authority, said: “New York has the largest goal for offshore wind in the country of 2,400 MW. Massachusetts is behind us at 1,600. But we’re the only state that doesn’t have enough areas currently leased to support our goal. Massachusetts has more than 1,600 MW [in leased sites] available, so it’s really important for us to identify sites that make sense for New York and hopefully work for BOEM too … so we can move forward with more leases.”
The Statoil site has room for about 800 MW, only one-third of New York’s target.
James F. Bennett, chief of renewable energy programs at BOEM, described the 13 commercial OSW leases contracted so far, extending from Cape Cod to Cape Hatteras.
“There’s at least one off of every state, from Massachusetts to North Carolina, and obviously where the greatest demand would be,” Bennett said. “New York is one of these areas, obviously, where that demand is indeed great. In particular for New York, we have the one area that was leased in December of last year to Statoil for $42 million, which was an incredible milestone for the program. And we also had a sale in North Carolina in March of this year that went for $9 million to Avangrid. Both of those are indicators that the industry, if it hasn’t arrived, it’s arriving. We’re very optimistic about activities in the future.”
According to Bennett, New York has great OSW potential because it has all the factors that make a wind project succeed: wind resources are prime; shallow water off the continental shelf supports seafloor foundations; strong demand that constitutes a good market; and state support.
“I don’t know if there is a stronger demand than immediately from New York,” Bennett said. “All of these leases have occurred with state involvement and state input, and in particular New Jersey and Massachusetts are great examples of states that have put the time and effort into putting the environmental and stakeholder interests together, and that’s the lead that New York is following.”
NYSERDA is drafting a master plan that will include a plan for transmission to get wind-generated power to shore. “Some of this you’ll see in our Public Service Commission filings,” said Matzat, “but the master plan will include recommendations on how to move pre-permit forward for OSW and a timeline on how we see this going.”
| NYSERDA
BOEM manages the lease process and step one is planning and analysis to identify a wind-energy area, “which is where we are now in the process for New York,” Bennett said. “It’s obvious that the biggest one [lease area] is the one to the north, from New York to Nantucket, and right now that probably will include a couple leases off Martha’s Vineyard, which went unleased just two years ago, and we expect very high demand for those areas and are looking to 2018 for an auction for that. Beyond that, and we’re always hesitant to get nailed down to a date, but after that we think we’re in a position to go forward with another sale in New York.”
Docks and Dolphins
NYSERDA applies a similar evaluation process to ocean areas and to the shoreline for the ports needed to fabricate the huge turbine blades and host the purpose-built vessels used in building OSW installations. The authority is looking at 75 sites. The turbines off Block Island, which are 6 MW each, stand 600 feet above the water. The turbines NYSERDA is looking at will average 10 MW and approach 700 feet tall, plus their 200-foot foundations.
“We’re looking at the whole supply chain, so we’re not just looking at New York Harbor and the Port of New York and New Jersey, but we’re looking around Long Island and we’re looking up the Hudson too,” Matzat said.
Certain activities should be done as close to the wind farm as possible, such as staging for assembly, but other parts of the supply chain, such as manufacturing cables or blades, can be done farther away, he said. Most parts cannot be put on a truck and must be put on a ship, so a large part of the supply chain has to be on the water.
“But that doesn’t mean you couldn’t build up on the Hudson, where there are areas of labor that might fit a particular part of the supply chain, and bring that down on a barge to an assembly area,” Matzat said.
NYSERDA is now conducting public comment sessions, with four for the fishing industry alone this month.
“Another big group that isn’t 100% on board with us is the fishing industry, so we’ve really made a point of reaching out to the fishermen, and we’ve had a dedicated fishing liaison who just goes around to docks, not just in New York but in other states too, to talk to fishermen and understand their concerns,” Matzat said.
The master plan also includes intensive surveys of the shoreline and coast.
The authority has a survey vessel about 15 miles south of New York City doing sediment profiles and sediment samples of the sea bottom over a couple million acres so planners can understand the habitat on the seafloor and what the seafloor is made of, which has environmental as well as construction-planning value.
“I don’t believe any state has ever done that in advance of identifying areas for offshore wind,” Matzat said. “Usually that’s done later by developers.”
NYSERDA also is conducting a digital aerial wildlife survey, using a plane with high-resolution cameras to photograph more than 12,000 square miles of ocean four times a year over three years. It has already completed the first year.
NEW YORK — Energy storage developers and utilities in New York are working with NYISO to establish dual participation of storage in retail and wholesale markets.
The goal is to boost storage growth “to get to the gigawatt level, where just five years ago we were talking about one megawatt,” Martha Symko-Davies said in New York on Thursday.
Symko-Davies, program manager for energy systems integration at the National Renewable Energy Laboratory, headed a panel on storage integration at the Infocast New York Energy REVolution Summit held last week in Times Square.
The panel discussed the industry’s progress since FERC last November issued a Notice of Proposed Rulemaking aimed at knocking down market barriers to storage and distributed energy resources (RM16-23, AD16-20). (See FERC Rule Would Boost Energy Storage, DER.)
Tim Banach, vice president of development for microgrid developer GI Energy, said that in the past, “there was little to no coordination with the utility around where these projects would be sited and what impacts the projects might have on the utility grid, both beneficial or potentially doing some harm.”
Now GI Energy is working with U.K.-based software developer Smarter Grid Solutions on storage demonstration projects for Consolidated Edison.
Graham Ault, executive vice president of Smarter Grid, said his company has mainly developed technology to manage DER for utilities. “The same technology as developed for and used by utilities is highly relevant to the owners and operators of fleets of DER, and that is what we as a company are addressing,” Ault said. “The GI Energy-Con Edison project is an excellent example of that.”
Adrienne Lalle, project manager for Reforming the Energy Vision (REV) demonstration projects at Con Ed, said: “We, through our value-stacking goal, are big supporters of dual participation and using the assets for utility grid support and wholesale markets. It enables developers like GI Energy to offer lower-cost storage solutions to us.”
Brian Asparro, chief commercial officer of Demand Energy Networks, said technology must be straightforward to win customers. The company, which in January was acquired by Italian energy giant Enel, provides turnkey services for storage and DER.
On a recent project in Brooklyn, the company used its software to reduce demand charges for Con Ed customers and help the utility manage load reduction on its local network. (See NYPSC Extends Con Ed Demand Program.)
And customers also want resiliency so that in the case of an outage, critical elements of a housing or office complex can keep running, Asparro said.
Banach said that it was sometimes a challenge to educate owners of multi-family housing complexes or commercial enterprises — people whose expertise is not energy — on how storage projects were going to affect their energy bills. His company needed to explain “stand-by rates, contract demands and effects to ICAP [installed capacity] tags, so it was a constant requirement to educate.”
Now it’s a simpler real estate transaction between the developer and the host site, which can rely on predictable lease payments, Banach said. “We are now able to participate in wholesale markets and generate additional revenues. Ultimately our hope is to demonstrate that by stacking all these revenues, we can lower the cost of service to the utility for the energy services provided and provide ratepayer benefits through an effective and targeted non-wires alternative,” he said.
Lalle said Con Ed is looking to simplify the value proposition for the customer by disconnecting the project economics from the customer load profile, bringing the battery in front of the meter but providing a customer with a lease payment for the space.
“So, you get all the benefits of distributed storage,” Lalle said, “but you can add a utility value by directing the location strategically to a network constraint, sizing it a little bit bigger so that we can possibly offset some [transmission and distribution] investment and make the dispatch coincident with the network need as opposed to the customer load profile.”
John Bellacicco, director of Northeast operations at Stem, which focuses on behind-the-meter storage systems, said: “One of the biggest monetizable value streams today for energy storage is demand management, and the best way to get customer participation, especially when we think of REV and how REV wants to bring the customer into it as a prosumer, is to put the energy storage behind the meter and to have the customer participate.”
In front of the meter or behind doesn’t matter to Ryan Wartena, president and cofounder of Geli (Growing Energy Labs Inc.), an Australian company that develops software and services for storage and microgrid systems.
Wartena said he spent years developing batteries “until I realized that you can give the world an everlasting, almost free, solid-state battery, but no one’s really going to know how to use it. We have to think about batteries as a hard drive, where you can co-optimize, run multiple applications. So that’s where our initial intellectual property is.”
A developer can do demand charge reduction behind the meter and be available for wholesale participation, which Geli is doing now in Australia.
“Australia has a different market than the United States does, for they expose wholesale prices to residents,” Wartena said.
Wartena emphasized the need for alignment between developers and utilities. “Not just nodal to nodal, but if it’s a huge market price, I’m going to punch out a megawatt right now,” he said. “But my local distribution system does not want me to do that. The problem is you’re trying to feed the wholesale market from inside the mothership and you’ve got to use the mothership’s pipes, so there has to be that alignment, and that software, and that’s a lot of work to get that type of alignment.”
