PJM’s Board of Managers said Tuesday it will conduct an “independent review” into GreenHat Energy’s massive default in the RTO’s financial transmission rights market.
The investigation comes amid pressure from PJM members for answers regarding the June default, which — with losses expected to exceed $100 million — is likely to be the RTO’s largest ever. (See PJM Reeling from Major FTR Default.) The board said it will throw open its books in response.
GreenHat listed its address as 826 Orange Ave., Suite 565, Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google
“Examiners will have complete access to PJM records and staff for interviews and documentation review,” according to a news release.
The default highlighted flaws in the FTR market that allowed GreenHat traders, who had already been linked to a 2013 energy-market scandal, to amass the largest-ever portfolio of positions — 890 million MWh — on $600,000 in collateral. PJM has since identified “lessons learned” following a workshop staff conducted with independent experts and addressed many of the gaps through stakeholder-endorsed rule revisions, but member questions still remain. (See Doubling Down – with Other People’s Money.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
The board has formed a special committee, chaired by board member Susan Riley, that also includes members John McNeely Foster and Mark Takahashi, along with “independent third-party experts.” Among the experts are Robert Anderson, executive director of the independent nonprofit Committee of Chief Risk Officers, and Neal Wolkoff, CEO of Wolkoff Consulting Services. Wolkoff was previously chairman and CEO of the American Stock Exchange and chief operating officer of the New York Mercantile Exchange. The Philadelphia firm of Schnader Harrison Segal & Lewis LLP has been retained as counsel.
The committee promises to answer outstanding questions about the default and highlights four goals:
examine the facts and circumstances associated with GreenHat’s participation in the FTR market and its subsequent default
assess PJM’s actions in connection with GreenHat
review lessons learned and make recommendations for the future of FTR markets
address questions raised by the members concerning the circumstances of the default
PJM members pressed the board for an independent investigation at their Oct. 3 meeting of the Liaison Committee. The committee, which bans media attendance, is an opportunity for PJM members to meet directly with the board several times throughout the year.
East Kentucky Power Cooperative’s Chuck Dugan, the committee’s chair, detailed members’ concerns in an Oct. 10 letter to PJM CEO Andy Ott. Dugan said several questions about the default were raised at the meeting and members are “pleased” the board agreed to the investigation.
The letter outlines six questions members have about PJM’s awareness, responsiveness and transparency regarding GreenHat’s portfolio, including why staff, after apparently learning about the potential default in February 2017, failed to inform members and instead proposed modifications to the RTO’s credit policy for members’ endorsement as if they were unprovoked.
Dugan acknowledged the investigation “will require time” but requested progress reports at upcoming Members Committee meetings. A PJM spokesperson could not provide a target date for completing the investigation.
RENSSELAER, N.Y. — NYISO on Monday floated a carbon pricing proposal that would leave importers and exporters to manage the risk of predicting carbon charges for real-time imports into New York, rather than saddling consumers with that uncertainty.
NYISO staffer Nathaniel Gilbraith recommended to New York’s Integrating Public Policy Task Force (IPPTF) applying carbon charges to external transactions such that they compete with internal resources and each other as if the ISO were not applying a carbon charge to internal suppliers.
Gilbraith cautioned adopting a carbon charge without considering the pricing effects at New York’s borders would likely cause large shifts in import and export dynamics because in-state suppliers would carry an additional cost burden not shared by external suppliers.
“Total carbon emissions as a result of not addressing this seams issue are up in the air and would depend on whether or not external marginal generation is more or less efficient than internal New York Control Area marginal generation,” Gilbraith said. “However, one thing is certain, there would be large financial implications.”
Under the plan, NYISO would base the carbon impact on LBMP (LBMPc) on the real-time system dispatch to determine carbon charges and credits, as opposed to forecasting the impact. The change would be consistent with the LBMPc used to allocate residuals to loads, and the ISO would also create a new billing code for carbon charge settlements.
By basing the LBMPc on real-time system dispatch, the ISO would not be required to produce a binding forecast of the carbon impact, and energy traders would bear the risk of carbon impact uncertainty.
Several stakeholders took exception to the “big change” in the way the ISO does business, but IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said energy traders would be privy to the same information as the grid operator and have the ability to manage that risk.
“Where we landed is that it really wasn’t the best place for consumers to bear that risk because they don’t have the hedges available to [traders] and because the marketers have both the ability to manage the risk and also in many ways the direct incentive to manage that risk,” Bouchez said.
With the new separate line item for a carbon charge on bills and invoices, an import will see both a payment equal to the LBMP and a charge equal to the LBMPc, Gilbraith said.
“Carbon charges and credits will only occur if the transaction flows in real-time,” Gilbraith said. “For example, if an importer receives a day-ahead schedule at a certain $50/MWh, and they buy out of that schedule prior to flowing in real-time, they will not be responsible for any real-time dispatch carbon charge because the transaction did not flow.”
NYISO is targeting the Oct. 22 or 29 task force meeting to discuss LBMPc calculation and transparency of data with stakeholders.
The study assumed lower-emission dispatch leading to a need to buy fewer renewable energy credits (RECs) to meet the Clean Energy Standard decarbonzaion goals, “so if you get this low-cost emissions abatement through the carbon price, you don’t have to do quite as much higher-cost abatement,” Newell said.
The IPPTF is attempting to ensure that consumers derive the maximum benefit from carbon pricing through reduced payouts for RECs. | Brattle Group
The effect is “not very big because it’s assessed at the REC price post-carbon charge, which is quite low, but that’s always been there and it ends up being trivially small,” he said.
The grid operator the previous week had recommended steps to prevent certain wholesale market suppliers, designated as carbon-free in the CES, from collecting double payments for carbon emissions reductions that have already been captured by REC contracts. (See NY Carbon Task Force Looks at REC, EAS Impacts.)
The ISO proposed applying a carbon charge to wholesale market suppliers with active, fixed-price REC contracts with the New York State Energy Research and Development Authority that are based on a REC solicitation that began or was completed prior to the carbon pricing rules taking effect, which the ISO estimates to be the second quarter of 2021 at the earliest.
Clawback Issues
The Brattle study accounted for pre-2020 RECs getting a so-called “clawback,” and Newell emphasized that “we’re not endorsing that at all; that’s a very tricky issue. That was our assumption because it was a proposal by New York ISO.”
Warren Myers, Department of Public Service director of market and regulatory economics, asked, “If New York doesn’t change its policy and index future contracts, do you think the clawback might have an effect on that discount, on how much of that credit is translated into these future REC contracts?
“Yes, in general it raises regulatory risk with the state on anything,” Newell said. “I think there are a number of fairly compelling arguments why not to do it.”
The perception of a double payment is not quite accurate and a clawback carries a lot of potential unintended consequences, Newell said.
Newell said including pre-2020 RECs poses questions: Was the REC payment generators were receiving unambiguously just for carbon or for something else? To what extent did the suppliers already offer a lower price because of the potential upside from getting carbon pricing?
“There also may be some hedging instruments that would have the effect, if you gave them a lower price at their generation node, of impoverishing the generation owners,” Newell said. “They’d actually be losing money if you clawed back the carbon component of the LBMP.”
Rule changes create regulatory risk in general and not just for the next REC payments, he said.
“Even if you believe that these REC prices were based on a view of the world that would never have carbon pricing and was fully just compensating them for their non-emitting attributes, the carbon component of the LBMP would be too much to claw back because there are dynamic effects that have already lowered the energy and capacity prices,” Newell said.
Looking Ahead
Michael DeSocio, the ISO’s senior manager for market design, listed the stakeholder requests so far for additional analysis, such as considering assumptions of a higher social cost of carbon or different RGGI values for 2030. The ISO will prioritize the requests and recommend what analyses the task force undertake, he said.
The task force next meets at NYISO headquarters Oct. 22 to follow up on the treatment of resources with existing REC contracts and to hear a Calpine presentation on how a carbon charge might affect hedges on transmission congestion contracts.
In a victory for transmission owners, FERC on Tuesday signaled a major change in how it sets TOs’ return on equity rates, saying it will no longer rely solely on the discounted cash flow (DCF) model it has used since the 1980s.
Instead, the commission said it will give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model.
The commission’s new policy came in its long-awaited response to the D.C. Circuit Court of Appeals’ April 2017 ruling vacating Opinion 531, FERC’s 2014 order on the New England Transmission Owners’ (NETOs) ROE rates. (See Court Rejects FERC ROE Order for New England.)
Tuesday’s order proposes a methodology for addressing the issues remanded to the commission in Emera Maine v. FERC and pending in three other proceedings involving NETOs’ ROEs, setting a paper hearing on how the methodology should apply.
“In relying on a broader range of record evidence to estimate NETOs’ cost of equity, we ensure that our chosen ROE is based on substantial evidence and bring our methodology into closer alignment with how investors inform their investment decisions,” the commission wrote (EL11-66-001, et al.).
Higher Hurdle for ROE Complaints
FERC said it would use the methodology to determine initially whether an existing ROE remains just and reasonable. It said it will use three of the models — the DCF, CAPM and expected earnings — to establish a composite zone of reasonableness, which will be “an evidentiary tool to identify a range of presumptively just and reasonable ROEs.” (The risk premium model results in a single number and cannot produce a range of reasonable rates, the commission said.)
Zone of reasonableness quartiles | FERC
“Under this approach, we intend to dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile — unless that presumption is sufficiently rebutted,” the commission said.
This new threshold, and FERC’s indication that it will act more quickly on complaints, appears to address complaints by TOs and the Edison Electric Institute over “pancaked” ROE complaints being filed while prior cases remained pending. (See EEI White Paper Calls for End to ‘Pancaked’ Rate Cases.)
When the existing ROE has been shown to be unjust and unreasonable, the commission said, it will use all four models to produce four individual cost of equity estimates; the just and reasonable ROE will be the average of the results.
“For each of the DCF, CAPM and expected earnings models, we propose to use the central tendency of the respective zones of reasonableness as the cost of equity estimate for average risk utilities. We would then average those three midpoint/median figures with the sole numerical figure produced by the risk premium model to determine the ROE of average risk utilities. We would use the midpoint/medians of the resulting lower and upper halves of the zone of reasonableness to determine ROEs for below or above average risk utilities, respectively. Because our current policy is to cap a utility’s total ROE, i.e., its base ROE plus incentive ROE adders, at the top of the zone of reasonableness, we propose to use the composite zone of reasonableness produced by the DCF, CAPM and expected earnings to establish the cap on a utility’s total ROE.”
Based on evidence from the first NETO complaint, the new approach resulted in a range of presumptively just and reasonable ROEs of 9.6 to 10.99%. Based on this analysis, the commission said the just and reasonable base ROE would be 10.41% and the cap on NETOs’ total ROE, including incentives, would be 13.08%.
“However, these findings are merely preliminary,” it added, saying the paper hearing would incorporate feedback on its proposed framework.
The commission’s 2014 ruling — prompted by a 2011 complaint by New England state officials and others alleging that the NETOs’ 11.14% base ROE was excessive — reduced the base ROE to 10.57%. (See FERC Splits over ROE.) But the D.C. Circuit said FERC failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable.
‘Administrative Burden’
Although FERC acknowledged that using multiple models increases the “administrative burden” in ROE cases, the commission said it decided to broaden its approach after concluding that the DCF methodology no longer captures how investors make decisions.
“We believe that, since we adopted the DCF methodology as our sole method for determining utility ROEs in the 1980s, investors have increasingly used a diverse set of data sources and models to inform their investment decisions. Investors appear to base their decisions on numerous data points and models, including the DCF, CAPM, risk premium and expected earnings methodologies.”
FERC said the discounted cash flow methodology produced lower ROEs than the three other models for the four test periods at issue in the New England Transmission Owners’ proceeding. | FERC
The commission said the DCF methodology produced lower ROEs than the three other models for the four test periods at issue in the NETO proceeding. It noted that the models’ results sometimes “move in opposite directions.”
Models Explained
The commission’s order includes an appendix explaining the four approaches. The two-step DCF methodology incorporates both short-term and long-term growth projections. CAPM is used by investors to measure the cost of equity relative to risk.
The risk premium methodology considers interest rates as a direct input to compare returns on stock investments to that on less risky bonds.
The expected earnings analysis is based on the book value of individual stocks and can be either backward-looking using historical earnings, or forward-looking using analysts’ earnings forecasts.
Analyst: Higher Rates Likely
ClearView Energy Partners analyst Christine Tezak said the commission’s new approach will likely result in higher top values to the zone of reasonableness than seen since Opinion 531’s adoption. “This potential re-expansion of the zone of reasonableness would make it more likely that transmission owners will realize higher base ROEs than the DCF model alone indicated without a subsequent subjective upward adjustment. A broader range of reasonableness returns also looks likely to restore the full value of incentive adders awarded to transmission owners in prior proceedings.”
Information on how FERC may apply the new methodology to other TOs may come at Thursday’s open commission meeting, the agenda for which includes the NETO docket.
“We will be looking for an indication at the open meeting as to whether the industry should begin integrating these new principles into pending, recently filed and upcoming rate cases and pending complaints now, or wait” for the conclusion of the paper hearing, Tezak wrote.
The commission set a 60-day deadline for filing initial briefs (Dec. 17), with reply briefs due 30 days after that (Jan. 17, 2019).
The New England TOs are Emera Maine (formerly Bangor Hydro Electric); Avangrid’s Central Maine Power; National Grid; New Hampshire Transmission; The United Illuminating Co.; Unitil Energy Systems; Fitchburg Gas and Electric Light; Vermont Transco; and Eversource Energy (formerly Northeast Utilities, Connecticut Light and Power, NSTAR Electric, Western Massachusetts Electric Co. and Public Service Company of New Hampshire).
Commissioner Richard Glick, who formerly worked at Avangrid, did not take part in the ruling.
Commissioner Neil Chatterjee on Wednesday acknowledged concerns that uncertainty over how FERC would respond to the D.C. Circuit’s remand had chilled transmission investments. “So, our action should help ensure [there is] more clarity going forward,” he said during remarks at the Department of Energy’s Electricity Advisory Committee meeting.
At the commission’s open meeting Thursday, Chatterjee said “the commission will need to make important decisions about how the policy we’ve proposed in Emera Maine applies” in other ROE dockets.
Commissioner Cheryl LaFleur, who was chair when the commission issued Order 531, said that ruling was a compromise that set a tighter zone of reasonableness, with the ROE higher within the zone. “Here we’re allowing a much wider band and the ROE is in the middle of the band.”
VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s annual reserve requirement study and recommendations for a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both slight reductions from last year. (See “IRM, FPR Reduced,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
The study found a reduction in the standard deviation for the RTO-wide forced outages from the 2017 study to the 2018 study, which indicates the outliers “are slightly less extreme than they were last year,” PJM’s Andrew Gledhill said.
Staff traced the change back to a “slightly smaller” average unit size this year of 121 MW compared to 129 MW in 2017.
Ride Through
PJM’s Emanuel Bernabeu detailed the results of the RTO’s two-day workshop on distributed energy resources ride-through held on Oct. 1 and Oct. 2.
“We made tons and tons of progress,” he said, adding that staff plan to seek an endorsement vote at the Nov. 11 PC meeting on a problem statement and issue charge to address questions surrounding implementation of a new Institute of Electrical and Electronics Engineers standard on how DERs should react to system voltage fluctuations.
The PC will then vote on endorsing required settings for resources wishing to participate in PJM’s markets, but it will not vote on guidance developed by staff for state regulations on locally regulated resources. The issue raised stakeholder concerns at last month’s meeting. (See “Workshop Set on DER Ride-through Standard,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
Bernabeu confirmed that several revisions have been made to the problem statement and issue charge since then, including not making the standards retroactive for existing resources and creating rules for both inverter-based and synchronous resources.
“They behave quite differently. … We are trying to tackle the entire DER space and not just focus on inverters,” he said. “We are trying to achieve both.”
Alex Stern of Public Service Electric and Gas and Tonja Wicks of Duquesne Light expressed appreciation for PJM’s willingness to address stakeholder concerns.
“We just have to be sure at the RTO level that, as we incorporate greater levels of distributed energy resources, … we’re doing it safely and reliably,” Stern said.
“That’s why we want to solve this now as opposed to California,” Bernabeu said in reference to solar generators disconnecting from the grid during wildfires. “I don’t want to be like California.” (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
Offshore Wind Interconnection
The growing wave of interest in offshore wind is finally hitting PJM. Staff announced plans to review the Tariff for revisions necessary to address the “new and creative ways” offshore wind developers are proposing to interconnect facilities, which include offshore transmission networks with multiple interconnections.
“We haven’t anticipated this,” PJM’s Susan McGill said of the developers’ proposals. “There’s some ideas out there that this [current] construct doesn’t fit perfectly.”
Ken Foladare of Tangibl requested that PJM also look into other long-term firm transmission projects that sometimes cause delays with generation interconnection queue requests and asked that staff investigate ways to eliminate these delays.
“For generation project developers, these delays often cost them a considerable amount of time and money,” he said.
Impacts of the Energy Transition on Transmission
PJM’s Yuri Smolanitsky detailed plans for two new 500-kV lines and substations that highlight the changes resulting from shale gas and solar development in the RTO.
The Flint Run 500/138-kV substation west of Clarksburg, W.Va., will tap the Belmont-Harrison 500-kV line to provide extra-high voltage for Marcellus shale load growth in the area. The $40.1 million project in the Allegheny Power Systems zone — b2996 in PJM’s Regional Transmission Expansion Plan — will run 138-kV lines of approximately 3 miles each to 138-kV buses at Waldo Run and Sherwood. It’s expected to be in service by December 2019.
In addition, a $5.7 million project in Dominion’s zone will upgrade the Spotsylvania substation and construct approximately half a mile of 500-kV line to connect with the 500-MW Spotsylvania Energy Center solar farm. Smolanitsky said it will be the largest solar farm in the RTO when it goes into service, which is expected next fall. It was developed by Sustainable Power Group (sPower), which was acquired by AES and AIMCo in February 2017, according to the project’s website.
TMEP Congestion Analysis
Two recently approved targeted market efficiency projects (TMEPs) would have resolved $55 million (approximately 11%) of the total $523.2 million in congestion costs over 2016 and 2017 from the 61 facilities that MISO and PJM identified as part of study begun in the spring, PJM’s Alex Worcester announced. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
Other planned system changes would have resolved $213 million (approximately 41%). Outages drove $201 million (approximately 38%), and $6 million (1.1%) were caused by situations where the congestion isn’t persistent. The remaining $48.2 million (9.3%) includes potential TMEPs, as well as ones where the effectiveness is uncertain, the upgrade is unknown or the proposal didn’t meet the necessary benefit-to-cost ratio.
RTEP Recommendations
PJM’s Board of Managers approved another $214.9 million in RTEP baseline reliability projects at its Oct. 2 meeting. The recommendations come after the board approved $629.23 million in recommended baseline projects at its July 31 meeting.
The majority of the cost comes from a $155 million plan to construct two new 69/13-kV substations in the Doremus area of the PSE&G zone.
Dominion Supplementals
Dominion’s Ronnie Bailey presented three new need assessments and two planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. (See “First M-3 Experience,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
The planned solutions address the first and second needs identified by Dominion last month. The solution for the first need, which would serve a new data center campus in Loudoun County, Va., with total load in excess of 100 MW, is estimated to cost $27.8 million.
The second solution, which would accommodate a request by Old Dominion Electric Cooperative to serve residential, commercial and industrial growth south of Fredericksburg, Va., that is expected by 2023, is estimated to cost $1.4 million. The summer load in the area is around 35 MW, Bailey said, and the winter load is expected to be around 41 MW.
VALLEY FORGE, Pa. — The Mid-Atlantic region experienced heavy precipitation this summer that was great for hydro generation, PJM staff told attendees at last week’s meeting of the Operating Committee.
“The story of this summer has been rain,” PJM’s Chris Pilong said.
He noted that several states within the RTO’s footprint recorded some of the wettest months of July and August since records began in 1895. While all the rain created localized flooding and high rivers, it didn’t result in any system issues. Generation outages on Aug. 28, when the RTO had its peak demand this year at 150,650 MW, were down compared to generation outages during last year’s peak on July 19. There were 13,590 MW on outage this year, while there were 16,538 MW on outage last year during a lower peak of 145,638 MW.
There were seven hot weather alerts between Aug. 27 and Sept. 6 that resulted in 100 planned transmission outages being deferred.
Staff also addressed the impacts of Hurricane Florence, which impacted 2,000 Dominion Energy customers in the North Carolina section of PJM’s zone. Staff held calls with several industry stakeholders and federal officials and declared conservative operations for the period.
Pilong also noted that the Oyster Creek nuclear facility in New Jersey went offline at noon on Sept. 17 and that there were no related system impacts.
Resilience Study Delayed
PJM’s Dave Souder announced that the special session of the Markets and Reliability Committee on fuel security scheduled for Sept. 22 had been moved to Nov. 1 to coincide with the revised publication date of the RTO’s study of the issue. (See related story, PJM CEO Ott Briefs Senate Committee on Black Start.)
The study had to be revised because of new deactivations that have been “communicated” to PJM, Souder said. The goal of the study is to identify locations with fuel delivery risks, evaluating how resources can reduce them and determine the need for additional mitigation efforts. (See Stakeholders Debate PJM Fuel Security Scope.)
PJM’s Jonathon Monken outlined the remainder of the RTO’s “resilience roadmap,” which includes short-, mid- and long-term goals. Short-term actions are expected to be completed by the end of the year and encompass mostly analysis and planning. Mid-term changes, which include incorporating “resilience criteria” in the RTO’s Regional Transmission Expansion Plan, gas-electric coordination for its Dispatcher Interactive Map Application (DIMA) and gas-electric contingency pricing, are targeted to be implemented by the end of 2019. The long-term changes are intended for 2020 or beyond and include strategic islanding of critical infrastructure, enhancing tools for dynamic restoration and a “deep dive” vulnerability assessment with the Department of Homeland Security.
Regulation
PJM’s Danielle Croop said an MRC proposal to revise pricing for regulation will fix what is “a little broken” in the regulation market but won’t impact operations. The proposed problem statement and issue charge, which would consider not allowing the benefits factor to decrease past 0.1, received a first read at the MRC’s September meeting.
“I really don’t think we’re going to see operational changes at all,” she said. “You’re talking about very small megawatts at that point.”
Croop noted the average clearing price for regulation in September was $20/MWh, which was $1 lower year-over-year and in line with the trend. She said manual moves of resources, in which PJM operators manually direct resources up or down for a maximum of two minutes, was “drastically down” thanks to the new regulation signal that was implemented in April 2017. Resources are set to automatically follow the signal, but many resources following the RegD signal often ended up moving the wrong direction. Operators performed approximately 16 manual moves in September for a total duration of roughly 1,600 seconds compared to approximately 40 moves in January for a total duration of roughly 4,600 seconds.
Croop said a spike in the number of RegD pegging incidents, in which a resource is held at the top or bottom of its regulation continuum based on system conditions for a certain amount of time, wasn’t “anything chronic” or an issue necessary to consider revising the signal. There were nine incidents of resources pegged for between 20 and 30 minutes, compared to August when there was only one such incident.
“I think it’s probably just a shoulder-month operation,” she said, referring to the weather vacillations in spring and fall months as the seasons change.
PJM’s Vince Stefanowicz discussed cold-weather preparations for generators, which include submitting a checklist preparations into the RTO’s eDART system by Dec. 15. A seasonal fuel and emissions survey must be completed by Nov. 16.
“We’re focused on fuel supply and delivery,” Stefanowicz said.
PJM will create a list by Nov. 10 of generators eligible to participate in a cold-weather exercise “to identify and correct start-up, operational and fuel switching issues prior to cold-weather operations,” and owners will have until Nov. 20 to identify participating units. Only non-Capacity Performance units are eligible for compensation.
PJM’s Rebecca Stadelmeyer reviewed a problem statement and issue charge proposed by the RTO to document timing and tasks required by generators in its Resource Tracker application. Staff believe the solution is “simple and straightforward” and have already proposed a solution, which would survey generation owners about windows and deadlines for inputting information in the application. PJM prefers one four-week window at the end of the year for revising information rather than the current two-week biannual windows.
The proposal would also install the final details in Manual 14D.
Mount Washington 115-kV RAS Done
Ken Braerman with Baltimore Electric and Gas announced the retirement of the Mount Washington remedial action scheme (RAS), which has been in service since June 1, 2014. The RAS addressed potential N-1-1 voltage drops at five buses in BGE’s territory by “reliev[ing] load to acceptable voltage levels,” but it will no longer be necessary once the Camp Small ring bus and capacitor bank goes into operation of Oct. 31.
SACRAMENTO — Pacific Gas and Electric pre-emptively shut down power to thousands of its customers on Sunday and Monday, one year after high winds toppled live utility lines and started wildfires that burned through large swaths of Northern California.
The shutdown happened during similar conditions to those that preceded the 2017 blazes. The National Weather Service issued a red-flag warning for the potential rapid spread of fires through 11 p.m. Monday. Wind gusts of up to 55 mph were predicted in the state’s coastal mountains and inland valleys. PG&E, which has installed 100 weather stations in fire-prone areas, said it also weighed factors that included low humidity, dry fuel on the ground and the low moisture content of live vegetation.
PG&E shut off power to thousands of customers in Northern California because of high winds and extreme fire conditions. | National Weather Service
Up to 87,000 customers would be without power in mostly rural communities of the northern San Francisco Bay Area and the Sierra Nevada foothills, PG&E said in a news release Sunday.
“We have made the decision to turn off power as a last resort given the extreme fire danger conditions these communities are experiencing,” Pat Hogan, PG&E’s senior vice president of electric operations, said in the statement.
One major urban area, Santa Rosa, was also slated to have its electricity turned off. A significant part of the city was leveled in the Tubbs fire of October 2017, with 2,800 homes destroyed. The cause of that fire has yet to be determined.
PG&E is facing billions of dollars of liability for last year’s fires, many of which started after the company’s equipment came into contact with trees and other vegetation, according to the California Department of Forestry and Fire Protection.
Cal Fire most recently blamed PG&E equipment for starting the Cascade fire on Oct. 8, 2017, in Yuba County, saying in a news release, that “a high wind event in conjunction with the power line sag on two conductors caused the lines to come into contact, which created an electrical arc.” That fire killed four people, destroyed 264 structures and burned 10,000 acres.
The weekend shutdowns were meant to prevent additional blazes. The company said it would conduct line inspections after the winds had passed and restore power once it deemed conditions were safe.
The electrical shutdown was extraordinary for Northern California, although San Diego Gas & Electric has implemented similar measures in Southern California during recent fire seasons.
The northern part of the state experienced by far its largest fire ever this summer, when the Mendocino Complex of fires burned more than 400,000 acres in rugged terrain north of San Francisco. Previous fire records also were set in 2017 and 2016.
The State Legislature and Gov. Jerry Brown have been seeking ways to prevent wildfires. Proactive shutdowns were a major topic of discussion during discussions this year of SB 901, a wildfire prevention and liability-relief act for utilities.
The final measure, signed by Brown in September, requires electrical corporations to submit wildfire mitigation plans to the Public Utilities Commission. The plans must include “protocols for disabling reclosers and de-energizing portions of the electrical distribution system” as well as procedures for notifying customers. (See California Wildfire Bill Goes to Governor.)
Over the weekend, PG&E sent automated voice messages, texts and emails to customers alerting them to potentially extreme weather conditions with high wildfire danger starting Sunday evening and lasting through Monday morning.
PG&E’s automated call to potentially affected customers said: “Extreme weather conditions with high fire danger are forecasted in (county name), starting today and lasting through Monday morning. These conditions may cause power outages. To protect public safety, PG&E may also temporarily turn off power in your neighborhood or community. If there is an outage, we will work to restore service as soon as it is safe to do so.”
MISO last week proposed bringing the three major players in its load forecasting together to coordinate on predictions for long-term transmission planning in the footprint.
MISO’s proposal would have both Purdue University’s State Utility Forecasting Group (SUFG) and consulting firm Applied Energy Group working with 20-year forecasts provided by load-serving entities. The RTO uses Applied Energy for distributed resource data predictions in its annual Transmission Expansion Plan.
The idea came in part from the Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of utilities and regulators, which proposed to require LSEs develop a 20-year base load forecast that includes monthly predictions for energy and non-coincident peaks. (See MISO Utilities Float New Load Forecasting Approach.)
The RTO put a temporary hold on ordering more independent load forecasts from the SUFG while it explored other stakeholder-proposed forecasting options. (See MISO Looks to Members for Load Forecasting Ideas.) It had received stakeholder criticism for its plan to order four versions of the Purdue forecast, each tailored to one of the futures used to inform its annual transmission plan, beginning with MTEP 20.
Speaking during an Oct. 12 special conference call, MISO planning manager Tony Hunziker said the RTO’s new approach draws from the CUOS proposal in incorporating the LSEs’ 20-year forecasts.
MISO would send LSE-originated demand and energy forecasts to the SUFG, which would compile and analyze them to inform its state-by-state forecast. The RTO also envisions the SUFG using LSE data to produce a complete 20-year demand and energy forecast for each of the 140-plus LSEs, which will influence the four MTEP futures. The SUFG uses its state-by-state forecast to corroborate what share of a state’s load is located within MISO territory.
The LSEs’ gross forecasts would not include energy efficiency or other demand-side factors, such as distributed resources and electric vehicle programs. MISO staff said the RTO will ask LSEs to submit demand-side data separately to AEG, which would use them to develop the demand-side management potentials in the futures.
But some stakeholders are unconvinced that LSEs can simply change their forecast methods in under two years to detach energy efficiency totals from their forecasts.
Hunziker said LSEs, MISO staff and the SUFG will be able to communicate throughout the forecasting process.
“As [the SUFG] is looking at the data and they see an irregularity, there’s a feedback loop. They can get ahold of the LSE that made the forecast and discuss and hash [it] out,” Hunziker said.
Stakeholders were also concerned about how the SUFG would adjust LSEs’ original forecasts to make the final LSE-specific forecasts used in the MTEP.
Hunziker said the SUFG will use its independent load data to fill in any missing gaps.
“There may be entities that don’t provide some information, and we want to fill in those gaps. That’s always been a concern for MISO,” Executive Director of System Planning Aubrey Johnson said. “We still need to fill in for LSEs that don’t provide forecasts or submit incomplete data.”
He promised stakeholders that LSE data would be the “foundational piece” of the load forecast and said MISO will provide more detail on how and under what conditions the SUFG will modify LSE forecasts.
Johnson said MISO will present a firmed-up proposal at the Nov. 14 Planning Advisory Committee meeting. He asked for stakeholders to send written input on the proposal by Oct. 31.
VALLEY FORGE, Pa. — A proposal to revise PJM’s credit requirements for financial transmission rights in response to the historic GreenHat Energy default will be delayed a month but should still be on track for April implementation, PJM’s Lisa Drauschak told attendees at last week’s Market Implementation Committee meeting. RTO staff had previously planned to bring a problem statement and issue charge to the meeting for consideration.
“We think it’s important to take a breath,” Drauschak said, explaining that the RTO’s Credit Subcommittee has decided to further vet the proposals before it.
“We still feel we can get a filing to FERC in January” to be effective April 1, she said.
Dayton Power and Light’s John Horstmann asked that staff consider alternatives to the current market design to eliminate the structural credit flaws that allowed the default and to the usual stakeholder process that develops the credit requirements for the risky and sophisticated long-term FTR product. Attorney Steve Huntoon asked why the list of “lessons learned” from GreenHat didn’t address PJM’s efforts to increase GreenHat’s collateral. [Editor’s Note: Huntoon is a columnist for RTO Insider and is representing it in its effort to open meetings of the New England Power Pool to the press and public.]
Staff said it will prevent the situation from occurring again by revising the credit policy to give the RTO increased authority to make collateral calls.
“That agreement did not come out of a collateral call. It came out of something else,” Drauschak said.
“If we had the authority to do a collateral call, we would have done that,” PJM counsel Jen Tribulski said.
Despite the revisions, staff were careful to avoid suggesting the FTR market has no risk of defaults.
“Nothing is 100% absolute,” Drauschak said.
However, stakeholders pressed PJM to take more responsibility for the market’s security.
“We agree that you can’t prevent defaults — those things will happen — but we depend on PJM to protect us,” Rockland Electric Co.’s Brian Wilkie said.
DC Energy’s Bruce Bleiweis questioned whether the lessons learned fully encapsulated the advice PJM received during the closed-door workshop that precipitated the document. He said he was told by one of the participants that they weren’t given an opportunity to review a draft of the RTO’s takeaways.
“These items did come out of the workshop. … I’m not sure why someone would say that, but these items did come out of the workshop,” Drauschak said, defending staff’s work.
Independent Market Monitor Joe Bowring, who attended the workshop, concurred that the document accurately reflected the results of the meeting.
Must-offer Exception
Stakeholders deferred a vote on revising exceptions to capacity providers’ must-offer requirement after PJM changed its proposal from the last time it was presented to the MIC. Staff revised the proposal to give resources receiving an exception three years before being required to change their status from a capacity resource to energy-only. Capacity resources must offer any uncommitted capability into all capacity auctions unless they have been granted an exception.
PJM’s Pat Bruno explained that, after three consecutive years of exceptions, a unit would be modeled as energy-only in the capacity model, so its capacity megawatts would be reduced to zero and its owner would have 12 months to nominate its capacity interconnection rights (CIRs) elsewhere. The nominated generator wouldn’t have to be operational if it’s in the interconnection queue, he said. CIRs, which grant access to inject generation into the transmission system, have value and can be sold. (See PJM, Generators Debate Injection Rights for Exempted Capacity.)
The proposal, which has undergone several iterations, was satisfactory for some stakeholders.
“I feel pretty confident in this,” said Carl Johnson, who represents the PJM Public Power Coalition.
Bowring, however, objected to the changes.
“We’re not confident at all that this will prevent exercising market power,” he said, noting that resources could potentially delay reallocation of the CIRs for perhaps six years. “This is a very long time period. It’s not consistent with maintaining open access to the grid.”
Exelon’s Sharon Midgley said that while her company — which requested the rule changes — would like to vote, she was willing to wait another month.
Surety Bond Use
Stakeholders endorsed two competing proposals to allow use of surety bonds as credit in PJM’s markets, despite concerns raised by Bowring and others. The proposals will receive consideration at the Markets and Reliability Committee.
A proposal developed by the PJM Credit Subcommittee that would allow surety bonds as credit for all activity except FTR portfolios received 61% in favor in a sector-weighted vote, easily surpassing the necessary 50% threshold. The proposal would also set a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
Exelon’s proposal, which would allow using surety bonds for all credit requirements with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer, received 58% in favor. Stakeholders also indicated their interest in making a change, voting 66% in favor of not keeping the status quo.
Bowring repeatedly asked PJM and Exelon, which proposed the change, to verify that surety bonds are as secure as letters of credit (LOCs), which the RTO currently accepts.
“We believe they are legally as strong,” PJM’s Hal Loomis said.
“They’re a weaker form of credit,” Bowring said. “That’s why they’re cheaper.” He asked PJM whether it had requested the opinion of the same expert panel it used for a review of FTR credit issues on the advisability of using surety bonds and whether it has determined whether exchanges permit the use of surety bonds in place of LOCs.
Midgley countered that surety bonds are cheaper than LOCs because of Basel III and a more robust underwriting process. Since 2008, banks must now realize LOCs as a liability on their balance sheet, which affects their capital ratios for regulatory purposes.
“We don’t share your view that this is an inferior product. … We would not be seeking to [get them approved] unless they were comparable,” she said. “What you have before you is a proposal that would reduce cost for market participants, provide diversification for PJM and, at the end of the day, benefit customers.”
Other stakeholders were concerned about comparing PJM’s markets to those of NYISO and ERCOT, where surety bonds are already accepted for credit needs.
“It’s extremely smaller than the amount of dollars we’re talking about in PJM,” Direct Energy’s Marji Philips said. “Now I am mindful of a huge default happening [again like GreenHat], so now I’m seeking detail.”
PJM staff’s proposal to modify the FTR forfeiture calculation rules to include loop flow impacts doesn’t go far enough for some stakeholders. Staff proposed incorporating loop flows when determining whether virtual transactions in the day-ahead market have a 10% or greater impact on coordinated market-to-market flowgates.
Chris Carpenter of VECO Power Trading would also like to see the FTR impact test relaxed so that a virtual trade that creates a very small contribution to an FTR’s settlement wouldn’t trigger forfeiture of the FTR profit. Exelon and NextEra Energy supported VECO, which proposed three alternatives to mitigate that situation:
Forfeit the portion contributed by the “triggered” constraint instead of the entire FTR settlement value;
Require the FTR to have a 0.1 distribution factor (DFAX) on the triggered constraint; or
Require the triggered constraint to be “substantially linked” and contribute a “significant dollar share of the FTR settlement value.”
The current FTR impact test, which has been in effect only since last year, triggers forfeiture if the DFAX multiplied by the shadow price is greater than or equal to $0.01. The previous test triggered forfeiture if the DFAX was greater than or equal to 0.1.
“There is a pretty significant impact from that change,” Carpenter said. “From our perspective, this forfeiture amount doesn’t really line up with the impact of the activity.”
“One penny manipulation is manipulation,” the Monitor’s Howard Haas said. “What we have seen, under the current rule, is a dramatic reduction in forfeitures because of changes in behavior.”
Carpenter acknowledged the reduction but attributed it to market participants “not feeling the risk tradeoff is worth” attempting the virtual trades.
“My firm has stopped doing [increment offers] and [decrement bids] because we’re concerned about this rule,” Midgley said. “In the FERC proceeding, PJM raised concerns that the new rule would restrict legitimate market activity that promotes market convergence and increases market efficiency. I’m here today to say this is happening. … I think it’s a really beneficial conversation to have.”
Gabel Associates’ Michael Borgatti, representing NextEra, said the rule should be very selective in not penalizing unforeseen impacts and only punishing manipulative behavior.
“We agree that we think the PJM package takes a meaningful step forward. … Having a rule that serves as a [deterrent] to that activity is healthy,” he said. “It’s an oversimplification at best to say that a penny change in the FTR is tantamount to manipulation.”
Carpenter argued that the first alternative proposed is like CAISO’s forfeiture rule in that “the concept of forfeiting by constraint is something that has been done.”
Haas countered that CAISO’s definition of an FTR is different from PJM’s. “You have to rethink the FTR product itself,” he said.
BOSTON — “We Are Still In” said the button Anne Kelly wore Wednesday as New England’s clean tech community gathered here, three days after a dire report by the U.N.’s Intergovernmental Panel on Climate Change.
For Kelly, senior director of CERES’ Business for Innovative Climate and Energy Policy (BICEP) Network, the button was a rebuke to President Trump’s plan to pull the U.S. from the Paris Agreement on climate change.
The IPCC report — which warned that preventing catastrophic effects from climate change will require unprecedented global cooperation — had a sobering effect on the Horizon 18 conference, where New England clean tech companies looking to make sales and forge partnerships met with other stakeholders. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.) But there was no hint of defeatism in the crowd.
“The need to move to action is more and more compelling,” said Patricia Fuller, Canada’s ambassador for climate change.
Keeping temperatures from rising more than 1.5 degrees Celsius (2.7 degrees Fahrenheit) from 1850-1900 levels will require carbon pricing, maximizing renewable energy and energy efficiency, and incorporating carbon capture and storage, Fuller said. “There is no silver bullet. Really, as someone put it recently, you need silver scattershot. You need all the tools.”
Fuller cited a September report by the Global Commission on the Economy and Climate that recently concluded that “bold action” on climate could produce economic gains of $26 trillion through 2030 and create 65 million jobs compared with business as usual. “So, this is also an opportunity,” Fuller said.
Canada is passing legislation for a federal carbon pricing system, reducing methane emissions and emissions from heavy duty vehicles, and accelerating the phaseout of coal-fired electricity. All federal buildings will run on clean power by 2025.
Because the Trump administration and Congress have failed to take similar action in the U.S., it is the states that “are in charge of progressive energy policy,” said Ed Krapels, CEO of Anbaric Development Partners.
Krapels said proposed offshore wind projects in New England represent “probably the largest single investment opportunity in clean energy in the country.” Citibank has estimated as much as $100 billion of capital spending is needed to develop 20 GW of offshore wind on the East Coast.
“While I can see why some people would be a little pessimistic about where we are with respect to the latest U.N. report, there really is an enormous amount of stuff that is very positive and very constructive that is happening. The money is here; it’s available. And I think the challenge is to create a set of policies and market structures that enable that market structure to be deployed,” Krapels said.
Transmission’s Role
Among the policy challenges, Krapels said, are how the offshore transmission infrastructure is developed and the role of energy storage. (See Anbaric Pushes Offshore Grid Plans.)
“Every transmission line should look at … the role that storage can play in increasing the capacity factor of renewable resources. I think the RTOs are very open to this idea. There is a lot to be done because they’re reactive organizations. They need to have developers put forward innovative new ideas.”
Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), said renewable generation will never reach its potential without the ability to site transmission in areas like New England. “We need to be able to have transmission to renewable resource areas and so we’ve got to get beyond the NIMBY issues,” he said.
Wetstone called the lack of carbon pricing “the biggest externality in the history of economics.”
“If you care about these issues, vote,” he told the audience.
Matthew Nicholls, managing director of distributed energy solutions for General Electric, said his optimism comes from his prior career as a semiconductor engineer, where — per Moore’s law — computers’ processing power doubled about every two years. “Everybody lowered their heads, worked with partners, worked with capital and made it happen, year after year,” he said. “We see a similar type of transformation happening in the energy industry now.”
Researchers haven’t been as successful in cracking challenges such as carbon capture, despite billions in investments. But Rolf Nordstrom, CEO of the Great Plains Institute, said he was optimistic about the success of the “carbon capture coalition,” which won a federal tax credit for the technology in February. “We had the most liberal and the most conservative members of Congress voting for that — which probably deserves the Nobel Prize,” he joked.
Patrick Woodcock, Massachusetts’ assistant energy secretary, noted that the rise of natural gas and renewable generation has reduced U.S. power sector emissions below that of the transportation sector.
In contrast to the “unprecedented transition” in the electric sector, there has been only “incremental progress in transportation,” he said. “I see components of that disruption occurring in transportation. We have those fundamentals of cost curves coming down in batteries; disruptive companies receiving billions of dollars in investment to be at the vanguard of a new transportation system.”
Carol Grant, Rhode Island’s commissioner of energy resources, said progress also has been slower in converting the heating of buildings.
“We really have to work on transportation and on heating. Those are two areas that we have not made the same kind of progress in. … This is hugely important in heavy transport, in marine transport, in air transport. It’s not just about all of us getting electric vehicles.”
Jed Dorsheimer, managing director for financial services firm Cannaccord Genuity, also sees transportation as ripe for disruption, noting that personal vehicles sit unused about 95% of the time.
“Greed always trumps green,” he said. “I do believe most decisions — while we like to take an altruistic view of things — the economics play a heavy role. I do think this area is ripe for economics to drive decisions to change the transport industry.”
Cities and Universities
In addition to states, cities and universities are also providing climate leadership, speakers said.
Jon F. Mitchell, mayor of New Bedford, Mass., and head of the United States Conference of Mayors’ Energy Committee, boasted his city of 100,000 has the largest EV fleet of any city in the state, with 30% of its vehicles electrified. The city also has won recognition for its high per capita municipal solar capacity. The largest fishing port on the East Coast, New Bedford also is hoping to become a hub of the offshore wind industry.
Mitchell said the city’s efforts were motivated by climate change and cost savings “but also because, as an older industrial city, we saw that it’s pretty good for our brand. Instead of being seen as older and gritty and sort of struggling, we’re emerging as a place that’s seen as progressive, forward thinking and creative. And that’s what we want to be.”
Rosalie Kerr, director of sustainability for Dartmouth College, said universities can be nimbler than states and cities because renewable investments can be made with approval of just a handful of decision-makers. “There are 4,200 universities around the country. We control something like 3% of GDP. So it’s not a tiny market,” she said.
Lance Pierce, president of CDP North America, a nonprofit that runs a global disclosure system for investors concerned with companies’ environmental impacts, said utilities “sit at the hinge” of the old and new energy models. “In that regard they can be catalytic, I think, in helping make some of the changes.”
Although “utilities have been spotty” in disclosing their emissions and other environmental metrics, he said, Southern Co. and Dominion Energy began providing his company with data in the last year.
Marcy Reed, executive vice president of U.S. policy and social impact for National Grid, said her company no longer refers to itself as a utility. “We consider ourselves a clean energy transition company. And that is because … we deem it our obligation, and indeed our privilege, to help think through some of these challenges.”
New York and the New England states have pledged to reduce carbon emissions by 80% below 1990 levels by 2050. That will require 10 million EVs in New England, with all light-duty sales to be EVs by 2030, Reed said.
“That just calls for a massive shift,” she acknowledged. “People think it can’t happen. Well actually it can. That’s a decade from now.”
BP, which dropped its “beyond petroleum” marketing slogan several years ago following losing bets on solar power manufacturing, is seeking to get back into the sustainability game, said David Gilmour, vice president of business development.
Gilmour said the company’s sustainability goals and investments in the Oil and Gas Climate Initiative were prompted by customers’ demand for more environmentally friendly products and the company’s need to attract new talent. “I think we really do need to be inspiring our workforce to be working for a company that actually works for real positive benefits for society. … For BP to be around in 100 years, we need to be part of the energy transition. … Given that most of these technologies are highly disruptive to our existing business, we want to be part of and actually shape the future through the work we do.”
Jarett Carson, managing director of venture firm EnerTech Capital, said although U.S. venture capital investments are likely to set a record of more than $100 billion this year, investments in clean technology and energy will be below $6 billion, down from $7.5 billion in 2011. “That seems to be a direct dichotomy with the challenge issued by the IPCC, talking about the $2.4 trillion being needed to be invested almost every year,” he said.
But Daniel Goldman, co-founder and managing director of Clean Energy Venture Management, another VC firm, said a lot of investments before 2011 were in very capital-intensive technologies. “Today we’re involved in companies that aren’t capital intensive. Our fund will only invest in a company where you don’t need more than $30 [million] or $40 million to get to cash flow break even and have a product that can scale.”
Adam E. Bergman, Wells Fargo’s senior vice president for clean tech banking, also was less troubled by the availability of capital, citing the increasing involvement of corporate venture funds and “family office” investors, who tend to have longer time horizons and lower hurdle rates than Silicon Valley VC funds. He also noted that many of the big technology bets of the past, such as solar and wind, have reached maturity.
Emily Reichert, CEO of Greentown Labs, which claims to be the largest clean tech startup incubator in the U.S., said there are also more strategic investors now, such as BP, that can provide expertise to help new companies grow. “Ten years ago, there was definitely a green bubble. There were a lot of people that were investing in clean technology that perhaps didn’t necessarily have the knowledge or information they needed. They were not experts in energy,” she said. “I think it’s a lot more positive now.”
ALBANY, N.Y. — Carbon pricing, siting challenges for new renewables and new funding for energy storage initiatives all topped the discussion at the annual fall conference of the Alliance for Clean Energy New York on Oct. 9-10, which opened in the wake of a renewed warnings about global warming.
State University of New York Chancellor Kristina Johnson pointed to the newly released report by the U.N.’s Intergovernmental Panel on Climate Change that said catastrophic effects will likely occur sooner than previously thought and that preventing them will require unprecedented global cooperation. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
Johnson, a former U.S. undersecretary of energy, said some people believe that any construct that would reduce greenhouse gas emissions enough to stop the planet from getting warmer would cost too much, but SUNY analysis conducted with the Boston Consulting Group determined it would “cost $1 trillion invested over 25 years.”
That works out to $40 billion a year to decarbonize the electric sector, electrify personal vehicles, modernize the grid and ramp energy efficiency, she said, “so that’s basically a grande latte per household per week. Who in their right mind wouldn’t do that?”
New York State Energy Research and Development Authority CEO Alicia Barton said her organization is “very close” to being able to issue the first request for offshore wind proposals, and it announced $40 million in energy storage funding incentives through the NY-Sun initiative.
“We’re not only serious about setting the targets but serious about getting the projects built,” Barton said.
Sunrun Chief Policy Officer Anne Hoskins, a former member of the Maryland Public Service Commission, shared her experience going to Puerto Rico to help with recovery from last year’s hurricane.
“We are partnering with three local installers … and the amazing thing is how everybody I talked to — the cab driver, the governor — all want distributed solar,” Hoskins said. “It’s because they realize they need to do something different.”
Pricing Carbon
Participants also discussed New York’s effort to price carbon into its electricity market. The state’s Integrating Public Policy Task Force (IPPTF) has been meeting almost weekly this year to model the impact of carbon pricing on emissions and prices in New York and neighboring regions. (See ‘Negative Leakage’ from NY Carbon Charge, Study Shows.)
“A lot depends on the assumptions being used … low gas price projections may not be realized, and if natural gas prices spike, then the dollar value of the environmental benefits rises, too,” said former NYSERDA head Frank Murray, now with the Natural Resources Defense Council.
Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers, said, “The past six months have seen many new state initiatives and mandates on things like storage … and we haven’t had time to digest the analyses released over the past month or so by Brattle [Group], [Resources for the Future] and Daymark [Energy Advisors].”
Mager characterized a carbon charge as potentially the biggest market design change since NYISO was formed in 1999 and said his clients have two main concerns: What are the likely consumer impacts, and what are the environmental benefits?
“We’re also concerned about how the Public Service Commission sets the social cost of carbon and how they update it, and how often,” Mager said. “And we’re concerned about the potential for double cost recovery.”
In addition, he said that two out of three recent analyses indicate emissions would increase in New York state and drop in the region as a result of implementing a carbon charge.
“We’re undecided, not yet opposing, and may never oppose,” Mager said.
Christopher LaRoe of Brookfield Renewable Energy Group said a carbon adder may be the best way to achieve the state’s aggressive policy goals. He said his company provides the environmental benefits sought by the state but does not get compensated for it.
The state “recognizes the value of maintaining existing baseline resources, and yet you go incremental to that to achieve your 50[% renewables] by [20]30 goals,” LaRoe said, referring to the state’s Clean Energy Standard target. The PSC didn’t see fit to provide a revenue stream for Tier II resources, outside of a maintenance tier, which is “basically a nightmare,” he said.
Brookfield has lobbied to value Tier II resources at 75% of the Tier I price: “Not quite a made-up number, but it was meant to provide a discount off of the Tier I price,” LaRoe said.
That effort failed at the last minute in the legislative session this year, but FERC would like to see progress by the states and grid operators putting their policies and markets together, so hopefully New York “can get there voluntarily and not through coercion,” LaRoe said.
Clean Energy Progress
Anne Reynolds, executive director of ACE NY, highlighted progress over the past year, including new offshore wind targets, energy storage programs and energy efficiency targets.
“NYSERDA completed their first Tier I procurement, awarding contracts for 3.2 million more megawatts than they set out to do, and they issued the second Tier I procurement on schedule, delivering the much-needed certainty and regularity in the Clean Energy Standard procurement process,” Reynolds said.
In addition, Gov. Andrew Cuomo announced an ambitious energy efficiency goal of 185 billion Btu of savings by 2025, she said.
“Energy efficiency was a missing piece of the puzzle last year, not just because it can save ratepayers money and it’s good for the environment, but because under the CES, when they determined the Tier I, they assumed a lot more energy efficiency than New York was then achieving,” Reynolds said.
However, “developers still need efficient and predictable processes for permitting large-scale wind and solar under Article 10,” she said, referring to the state law governing the siting of generating facilities.
“Since last October, there’s been real progress with the queue itself, with one project certified, four projects deemed complete [and] one additional application. But in that same year, 21 new projects embarked on the process,” Reynolds said. “The process in itself in the last year hasn’t gotten faster or more predictable.”
Peter Olmsted, assistant secretary for energy to Cuomo, said, “We need to double down on collaborating with each other,” and that Article 10 process improvements should be coming faster now with the appointment of Sarah Osgood, director of policy implementation at the Department of Public Service, to speed implementation.
Siting Challenges
Osgood said there are currently 34 active projects in the Article 10 pipeline, 31 of them renewable energy projects.
“Overall we have over 6,300 MW of generation capacity proposed, three-quarters of it renewable energy,” Osgood said. “The projects are split pretty evenly between wind and solar, but we are noticing that the projects that came into Article 10 earlier tend to be more large-scale wind. We’re starting to see a little bit of a shift to have more solar entering the pipeline.”
David Gahl, director of Northeast state affairs at the Solar Energy Industries Association, said that some shortcuts have been taken on value of distributed energy resources (VDER) compensation.
“Right now, the VDER provides compensation for the avoided pollution, and that’s great, but I think some decisions were made in determining what that value should be that essentially shortchange what a number of solar projects or DER projects should receive,” Gahl said.
“There are little changes on the margins that have reduced that compensation, and ultimately that’s probably not the direction the state wants to go if it wants to put more DER on the system,” Gahl said. “We shouldn’t take shortcuts, shouldn’t shave off value.”
Jeff Bishop, CEO of storage developer Key Capture Energy, said there are several frameworks to consider and that “as we move to the energy future, there’s a role for all the new technologies.”
VDER doesn’t include hydro, biomass, small wind or PV, he said, “but there is a role for storage … we have to be sure that technologies get paid for all their attributes.”
Dan Hendrick, head of external relations for Clearway Energy, said New York is heading in the right direction, but with considerable gaps.
“There’s a talk of devaluing in a five-year timeline, but some of these facilities generate for 30 years,” Hendrick said. “Con Edison has only 8 MW of community-distributed generation in the pipeline around New York City.”
Michael Gerrard of Columbia Law School reviewed some of the legal history around siting requirement waivers and the tug of war between state and municipal officials.
“The main difference between the old version of Article 10 and the new is that the former had the phrase ‘unreasonably restrictive,’ which has been supplanted by the phrase ‘unreasonably burdensome,’” Gerrard said. “There’s no clear explanation anywhere of why that change was made or what it amounts to. My own view is that it probably means that economic considerations can certainly be a factor in addition to everything else that used to be considered.”
