WESTBOROUGH, Mass. — ISO-NE planners last week outlined the scope of a needs analysis that will determine whether the RTO will approve transmission upgrades to accommodate wind development in the Keene Road area in Maine.
An economic study found that the area could qualify for market efficiency transmission upgrades (METUs) — projects designed to reduce the total production cost to supply system load.
At Wednesday’s Planning Advisory Committee meeting, planners said the needs assessment will simulate production costs with the Keene Road export limit modeled at the existing 165-MW limit and three higher limits that top out at 255 MW.
The modeling will provide results for 2020, the projected in-service date for the upgrades, as well as 2025 and 2030. In addition to production costs, the simulations will predict metrics such as congestion, emissions and LMPs at several locations.
Draft results are expected to be brought to the PAC for stakeholder discussion by November, with final results posted in December. If the results show the upgrades qualify as METUs, the RTO could decide to issue a competitive solicitation.
A draft study in 2015 found that increasing the export limit to 225 MW could save $1.4 million to $5.7 million in production costs annually by allowing additional wind development in the area and displacing more expensive hydropower. (See “Draft Study Shows Greater Wind Penetration Benefits,” ISO-NE Planning Advisory Committee Briefs.)
Texas regulators last week accepted a proposal from ERCOT and SPP staff on how they will coordinate their separate studies on Lubbock Power & Light’s planned move to the ERCOT grid.
In a joint letter to the Public Utility Commission of Texas, Warren Lasher, ERCOT’s director of system planning, and Lanny Nickell, SPP’s vice president of engineering, said their studies will use “consistent input assumptions” and “rely as much as possible upon their existing study processes” (Docket No. 45633).
SPP said it will use models from its most recent Integrated Transmission Planning Near-Term (ITPNT) assessment and its 10-year ITP study. ERCOT will use models from its most recent Regional Transmission Plan and its Long-Term System Assessment.
Both RTOs will also conduct near-term reliability studies and longer-term economic studies. “Both parties will analyze their systems with and without the portion of LP&L that is part of the proposed transition,” Lasher and Nickell wrote.
LP&L announced last September it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV rights of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy,” ERCOT Board of Directors Briefs.)
At a meeting Thursday, PUC Chair Donna Nelson said she agreed with the grid operators’ approach, but she expressed concern over who would pay for the studies. “Either LP&L should fund the studies, or we should leave the issue open pending the outcome of the studies,” Nelson said. “I don’t think it’s fair for the ratepayers in ERCOT to pay for that study.”
ERCOT and SPP said they had not come to a conclusion on funding the studies, but they would discuss with the commission “the appropriate allocation of the costs.”
ERCOT said it could complete its assessments before the end of the year, while SPP said it would complete its 2017 ITP10 in January and the 2017 ITPNT in April.
Lasher and Nickell wrote their staff does not have “the expertise or the necessary data” to determine the cost and reliability impacts as separated by customer class. They also deferred to LP&L “to describe measures necessary to ensure that there will be no commingling of electrical energy from the two regions as a result of the proposed transfer.”
At the same time, LP&L is conducting its own study. The utility’s attorney, Chris Brewster, asked the PUC to request ERCOT and SPP disclose their assumptions “to ensure we’re talking about the same things.” LP&L said it had had discussions with ERCOT, but not with SPP, and questioned the latter’s “scheduling constraints.”
“I don’t know what their scheduling constraints are, but they have a lot of employees. They have a lot of smart employees,” Nelson said, pointing out Nickell and SPP attorney Sam Loudenslager’s presence in the audience. “It’s in their best interest that ratepayers don’t end up paying for being unfairly advantaged when Lubbock leaves.”
Any PUC rulemakings will wait until the results are all in next year.
“We want to make sure we can get it right,” Nelson said. “We have people concerned about costs within the SPP system, and we have people concerned about costs in the ERCOT system. Clearly, we ought to be concerned about that.”
A proposal by MISO and ITC Holdings to allocate the costs of phase angle regulating transformers (PARs) to entities outside of MISO is not just and reasonable, FERC ruled last week.
The commission’s Sept. 22 order upheld Administrative Law Judge Steven Sterner’s 2012 decision prohibiting MISO and ITC from allocating the costs of ITC’s two 700-MVA PARs on the Michigan-Ontario border to NYISO and PJM (ER11- 1844-001, ER11-1844-002). The commission also denied as moot requests by several parties for rehearing.
Source: MISO
Failure to Show Benefit
FERC said MISO and ITC “failed to show that NYISO or PJM will benefit from the operation of the ITC PARs.” The commission noted that two NYISO and PJM witnesses testified that the two grid operators could “actually be harmed by the planned operation of the ITC PARs.”
“For example, a reduction in counterclockwise loop flow that may benefit MISO might, at the same time, harm NYISO if both transmission systems are experiencing congestion on transmission facilities that are affected by loop flow,” FERC wrote.
MISO and ITC proposed allocating 49.6% of the PARs cost to MISO, 19.5% to PJM and 30.9% to NYISO, based on each region’s contribution to the loop flows that would occur over the Michigan-Ontario interface without the PARs. Unscheduled loop flows around the Lake Erie region have been a problem since the late 1990s.
FERC ordered MISO and ITC to refund, with interest, all amounts collected pursuant to their Oct. 20, 2010, filing in excess of rates in effect prior to Jan. 1, 2011. MISO also has 30 days to revise parts of its Tariff that pertain to the cost allocation of PARs.
Reversal
FERC, however, reversed Sterner’s ruling that MISO and ITC were precluded from unilaterally filing proposed solutions with the commission. “While the commission has made clear its preference that interconnected utilities strive to resolve loop flow-related issues among themselves rather than resort to unilaterally filing proposed solutions with the commission, a public utility is legally permitted to make a unilateral filing to address loop flow,” FERC said.
PJM opposed the PAR cost allocation, saying that ITC’s two PARs replaced a single failed 800-MVA PAR that was “planned, developed and placed into service to meet local system needs.” NYISO objected to paying cost allocation for the ITC PARs because they “were not developed pursuant to a commission-approved regional planning process.”
ITC and MISO’s case for allocating the costs rested on Lake Erie’s loop flows no longer presenting a problem for PJM and NYISO. In a 2014 report, MISO, PJM and Ontario’s Independent Electricity System Operator (IESO) found that all five of the Lake Erie PARs were able to keep actual flows within 200 MW of scheduled flows most of the time.
Plans on Hold
After completing a yearlong observation of the ITC PARs and three other PARs at the Michigan-Ontario border in 2013, PJM and MISO incorporated the PARs into their market-to-market process on July 28. For now, PJM has put on hold plans to use the PARs for congestion management.
Marcus Hawkins, a senior engineer in the Division of Regional Energy Markets at the Wisconsin Public Service Commission, has joined the Organization of MISO States as its director of member services and advocacy. Hawkins will assist OMS Executive Director Tanya Paslawski.
Marcus Hawkins Courtesy of Marcus Hawkins
Hawkins, who has a bachelor’s in nuclear engineering and a master’s in mechanical engineering from the University of Wisconsin at Madison, considers his engineering experience to be an asset in his new role.
“It’s a very interesting position because it isn’t all technical all the time, but it helps to have the technical background,” Hawkins said. “Working at the commission was that same sort of sweet spot between the technical side and the policy side.”
Hawkins said his previous position with the Wisconsin PSC afforded him multiple opportunities to work with OMS. “I hope to enhance representation of the members of OMS both at MISO and FERC, and I’m excited to get started,” he said.
SANTA MONICA, Calif. — Optimizing distributed energy resources and reducing greenhouse gas emissions cost effectively will require improved forecasting and the elimination of regulatory silos, speakers told Infocast’s California Distributed Energy Summit last week.
Margie Gardner, executive director of the California Energy Efficiency Industry Council, opened the two-day conference with a question that framed the big picture: “What’s the purpose of integrating DERs into long-term procurement?”
The three speakers on the first panel offered variations on a theme.
For Pacific Gas and Electric, “integration means selecting that set of resources” that provides the least-cost solution to reduce GHGs while also maintaining system reliability, said Antonio Alvarez, renewable integration manager for the utility.
The California Public Utilities Commission believes that DER can help the state meet its carbon reduction goals while providing “safe reliable service at just and reasonable rates,” said Pete Skala, deputy director of costs, rates and DER.
“The question is, to what extent and where do they provide costs and benefits?” Skala said. The regulators’ goal is developing the “right amount of DER” to allow ratepayers, utilities and DER providers to all see benefits.
Costs and reliability “are definitely major drivers” for the Southern California Public Power Authority (SCPPA), said Ted Beatty, director of resource and program development for the joint planning agency, which represents the Los Angeles Department of Water and Power and 11 smaller municipal utilities.
“We have some small utilities, too, so we kind of have a wide range of needs there,” Beatty said. “But in general, they all have needs to look at planning for DERs.”
SCPPA’s members meet monthly to discuss issues around forecasting — a process becoming more difficult because of the unpredictability of DER penetration. DERs don’t connect to the grid via the traditional utility planning process.
Members are trying to grasp the technical and financial implications of increased DERs and understand customer trends to gauge the potential distributed solar capacity in their service territories. That effort has been hampered by the fact that some SCPPA members haven’t installed smart meters at customer sites.
“If you don’t have [customer data], you don’t really know what’s going on in your system,” Beatty said. “All you see is the net load that moves up and down, but you don’t know exactly why.”
Alvarez said that his utility’s long-term planning process relies on demand forecasts from the California Energy Commission (CEC), which factors in energy efficiency and distributed generation gains as well as energy consumption.
Recent forecasts put California power consumption growth at less than 1% per year, but that number could turn negative with increased energy efficiency mandates embedded in legislation passed last year (SB 350). That could exacerbate the forecasting complexity brought on by increased DERs.
“This is not new,” Alvarez said. “We’ve seen energy efficiency cutting in half — or more — the growth in demand.”
Next year, the CPUC will require each of California’s load-serving entities to file an integrated resource plan that prioritizes emission reductions alongside other more standard requirements, such as resource diversity, reliability and cost-effectiveness. (See Integrated Resource Planning on the Horizon for California.)
The revised IRP will provide the industry an opportunity to improve forecasting of DER, Alvarez said.
The IRP is an “optimization process” that seeks to determine the least-cost mix of resources to reliably meet California’s goals for energy efficiency, renewable generation and electrification of transportation. “I think at the end of the integrated resources plan, you actually have a demand forecast and a DER forecast,” Alvarez said.
Utilities have to look at more of a range than rely on specific forecasts, added Beatty, who suggested the industry should be employing scenario planning.
“When you’re looking at a forecast, you have to look at the different paths that are out there,” Beatty said. “Today I can’t predict five years ahead how much solar is going to come in [to the system], how much storage is going to be added to the system — or anything, for that matter.”
Skala said that although traditional “utility-scale, one-directional flow” grid planning is adapting to recognize the bidirectional flows stemming from DER, additional changes are still needed.
Utility planners “are a conservative bunch by nature.” When you talk about “safe and reliable service at just and reasonable rates while we achieve the state’s carbon goal, they only hear the word ‘reliable,’” Skala joked.
The variety of distributed resources and energy efficiency efforts adds “thousands of measures to the planning process,” he continued. “It becomes a very messy beast for conservative grid planners to try to figure out and incorporate into their work.”
Gardner asked the panelists to pick the most important thing that could be done to better incorporate DERs into the planning process.
“We need to have better models that analyze customer decision-making [and] factor all those together to figure out where the customer is going to go,” responded Beatty. “Once we know that, I think we can kind of follow along with them.”
Solar is the most significant DER for SCPPA utilities, with some members having already reached their net energy metering caps under state rules. Those utilities also control a large amount of utility-scale solar, which undermines the cost-effectiveness of distributed solar that generates during the same intervals.
“It’s a challenging market for these guys, and it’s difficult to figure out where we’re going and which DERs are the customers’ choice,” Beatty said.
“There needs to be a lot more alignment within the state agencies and the California Independent System Operator in terms of all the various planning activities that are ongoing,” Alvarez offered.
Alvarez would like to see the California Air Resources Board, CEC and CPUC coordinate their efforts to produce more reliable demand and DER forecasts, eliminating the agencies’ planning “silos.”
“It would be helpful to get some of those results as an input into the electric IRP process, so we can actually see the interaction between the different sectors of the economy — where you can get the best reductions in emissions,” Alvarez said. “If you’re trying to find what’s the optimal solution for the state and the electric sector, you need to have a common set of metrics.”
Skala concurred with Alvarez’s view on the need to align regulatory proceedings that require utilities to procure separate types of resources — such as energy storage, demand response and energy efficiency — under different state programs.
“The more we can get process alignment in place, the easier it’s going to make on markets,” Skala added.
The overlapping nature of California’s regulatory proceedings and the complication of integrating DER inspired a humorous analogy from Skala about the “nanny state” approach of setting various resource targets and the rules that apply to them.
“That caused me — in thinking about nannies — to think about the the grid in the child-rearing sense,” said Skala, the father of a 14-year-old daughter.
Historically, the grid — or demand, rather — has been a baby that’s been fed since the first light bulb, Skala said.
“And now we’re squarely in the adolescent period … so it’s a very confusing time, but it’s also a really important time developmentally,” Skala continued. “It’s really important to have clear and simple rules … that are designed to help customers and grid planners and everybody in that relationship make healthy choices.”
That will require sending clear signals to market participants, he added.
“But we also need to figure out what the utility model of the future looks like in that world, because if we don’t — to carry the analogy — we will have an empty-nester syndrome,” Skala said. “We’ve got to work it out in a way that works for the parent too.”
FERC last week rejected proposed SPP Tariff revisions, saying they would unfairly favor network transmission customers over point-to-point customers in how the RTO awards congestion rights (ER16-1286-001, EL16-110).
The commission’s ruling came in response to complaints by Southern Co., the American Wind Energy Association and the Wind Coalition.
The commission accepted changes that eliminated language SPP said had become obsolete as a result of the Integrated Marketplace. It also approved changes preventing firm point-to-point transmission customers whose service is subject to redispatch from obtaining long-term congestion rights (LTCRs).
But it rejected SPP’s proposal to grant such rights to network customers subject to redispatch, setting the issue for a Section 206 hearing.
LTCRs, financial instruments that allow transmission customers to hedge congestion risk, can be obtained through purchase or conversion of auction revenue rights. Transmission customers can nominate ARRs between source and sink points over paths for which they have purchased transmission service.
When SPP receives a firm transmission service request requiring transmission upgrades, the RTO will start service before the upgrades are in service if it is able to temporarily address any constraints through redispatch.
SPP contended it was within its rights in treating point-to-point customers differently than network customers, arguing that the two classes are not “similarly situated.” FERC said SPP’s rationale was “not persuasive.”
“While SPP notes that point-to-point transmission service uses a specific transmission path and network service uses the network as a whole, we note that SPP appears to ignore the fact that ARRs and LTCRs are allocated for both point-to-point and network service from a particular source point on the system serving a particular sink point on the system,” the commission said.
Under SPP’s proposal, the commission said, “firm point-to-point transmission service customers not subject to redispatch could receive a reduced portion of the available ARRs because such firm point-to-point transmission service would be competing with network service subject to redispatch.”
The commission said SPP may be able to resolve its concerns by revising section 34.6 of its Tariff to limit the eligibility for ARRs and LTCRs of network customers with service subject to redispatch.
“Our preliminary review indicates that SPP should not provide network service customers subject to redispatch with any LTCRs until the transmission upgrades are placed into service and the service is no longer subject to redispatch,” FERC said. “The commission notes that this approach would be consistent with SPP’s rationale for not providing point-to-point customers subject to redispatch with LTCRs.”
The commission, however, found that it had “inadvertently” not included in its December order a requirement to calculate interest on refunds related to bandwidth payments. It asked Entergy to submit another compliance filing that recalculates interest, eliminates any refunds related to the sale/leaseback of its Waterford 3 nuclear plant and removes securitized asset accumulated deferred income tax (ADIT) and contra-securitized asset ADIT from the bandwidth calculation.
Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of continuing disagreement. Payments are made annually by Entergy’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average.
MISO Compliance Filings Still Contain Errors
FERC yet again sent proposed Tariff revisions related to demand response back to MISO for further clarification in two orders.
The first order addresses MISO’s Order 745 compliance filings addressing contradictory language in Tariff revisions that laid out a new cost allocation methodology for compensating DR resources (ER12-1266). FERC found that the RTO mostly complied with its directive to clarify its Tariff, but the commission found yet more inconsistencies within and between sections of its Tariff regarding compensation across zones, cost allocation between day-ahead and real-time market participants and the effective date for certain provisions.
FERC also found discrepancies between MISO’s compliance filings regarding Order 719 (ER12-1265). For example, the commission found that MISO used “megawatts” to express maximum daily regulation deployment in its August 2012 filing and “megawatt-hours” in its September 2013 filing. FERC also found that the RTO did not differentiate between consumption baselines for DR resources providing regulating reserves and those providing contingency reserves.
The commission directed MISO to submit compliance filings addressing its concerns in both dockets within 30 days.
Less than half of PJM stakeholders considering the addition of a seasonal capacity product favor a change in the current rules.
Only 48% of members who voted in the Seasonal Capacity Resources Senior Task Force poll last week favored any change, while 52% chose the status quo.
None of the five alternatives to the status quo garnered much support, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — topping out at 43%.
Thirty-four stakeholders representing 190 companies took part in the voting.
The results of the task force’s vote were discussed at its meeting Friday. The sponsors of each option will incorporate the feedback they received into their proposals and resubmit them for reconsideration. Redlines are due Oct. 2, and the changes will be presented at the task force’s next meeting on Oct. 14. Another vote may occur shortly thereafter based on stakeholders’ response.
At question is how to allow seasonal and intermittent generation resources to offer as capacity under the tougher, year-round requirements of PJM’s Capacity Performance rules.
Although CP rules allow multiple seasonal resources to combine in aggregated offers, no such offers have been entered in auctions thus far.
PJM sought to address the issue by relaxing the current prohibition on seasonal resources aggregating across locational deliverability areas, sub-regions such as electric distribution company zones used to evaluate locational constraints.
The RTO’s proposed solution would allow resources to aggregate their production beyond LDA borders with unmatched resources moving up to the next LDA level until a match is found.
For example, an offer containing individual resources located in the EMAAC LDA and SWMAAC LDA would be modeled in the MAAC LDA. An offer with resources in COMED and EMAAC would be modeled in the “Rest of RTO.” Performance penalties would be distributed evenly between the resources, no matter which failed to perform. This proposal received the support of only 32% of respondents.
Eligible resources would include intermittent resources, storage and summer-only demand response and energy efficiency. It would define the summer period as June through October and the following May; the winter period would run November through April.
Another proposal called winter performance equivalents would auction “WIPES” credits that allow capacity resources to not perform in the winter. Created by consultant James Wilson on behalf of the Consumer Advocates of the PJM States, the proposal was opposed by PJM and received only 21% support.
The proposal’s release of 16,500 MW from their winter capacity obligations reduces operational reliability, PJM said in comments on the proposal. The RTO said a planning analysis cited by supporters “cannot capture all the complexities of real-time operations” because of its assumptions that generator forced outages are random and independent of each other. “The winter forced outage rates have exhibited a strong correlation with lower temperatures and higher loads. PJM has also observed common mode failures across generating units. For example, the disruption of a gas pipeline will force out all single-fuel gas units being served by that pipeline,” PJM said.
The RTO also said energy market costs would increase as capacity is released.
DR provider WeatherBug Home offered a solution that would create a way to measure and value seasonal DR by using the firm service level, a predetermined load reduction.
Load is currently paying for capacity that it doesn’t use, and aggregation won’t fix that, according to the proposal. Additionally, because there is far less winter demand, it will create a situation where winter assets will essentially collect “rent” by teaming with summer resources that are much more likely to be called to perform.
WeatherBug’s plan calls for maintaining the current CP rules and limiting the amount of DR that can clear the auction. All resources can participate using their capacity ratings above their must-offer commitment, but such aggregations would only be eligible for performance bonuses if the load drops below unforced capacity obligations. This proposal received the least support at 17%.
EnerNOC’s proposal was the same as PJM’s, but with a different calculation for the balancing ratio that removes what the company called an “unreasonable barrier” for DR performance calculations. The plan received 33% approval.
ALBANY, N.Y. — California’s challenge in integrating large amounts of renewable generation is illustrated by its famous “duck curve” graph. For New York, the future looks more like a platypus.
That’s how Rana Mukerji, NYISO’s senior vice president of market structures, described the impact of large amounts of solar generation on the New York grid in the winter at the ISO’s Distributed Energy Resource workshop last week.
NYISO, which released its DER Roadmap last month, held the session to open public discussion on how it will respond to the state’s Reforming the Energy Vision initiative. (See NYISO Releases Plan for Integrating DER.)
For starters, the ISO is pursuing a modest goal of planning for the next three to five years. A conceptual market structure design will be devised next year.
The roadmap, which officials described as a guide that could change as stakeholders become engaged in the process, anticipates implementation in 2021.
New York’s recently adopted Clean Energy Standard, which calls for 50% renewables by 2030, is the impetus, along with public demand for emissions-free power generation.
“We are moving very rapidly to a resource mix [that] will have intermittent resources [that] are renewable, distributed resources, and we will also have conventional generation,” Mukerji said. “I do not see conventional generation disappearing anytime soon. There is some talk of 100% renewable, but I don’t see conventional generation disappearing over the next 20 years.”
Wind generation, currently 3% of NYISO’s energy production, is projected to reach 13% by 2030.
“It took us 12 years to add 7% of renewables, but in the next 20 years we have to add 22%,” Mukerji said.
He cited projections that distributed generation without subsidies will rapidly reach grid parity. The Clean Energy Standard is going to accelerate renewable energy deployment, with solar growing from its current capacity of about 700 MW.
He added that the ISO has done simulations of up to 9,000 MW of solar in New York, which presents quite a different profile of the state’s demand in the morning and evening peaks.
“We will have needs for managing the ramping during the morning and the evening, so we might have to contemplate new products, like ramping products and load-following products in our market,” he said.
As more distributed resources are added, it will require the ability to manage bidirectional power flows.
“It will get more challenging, but in my mind it will get more interesting, and at the end of the day it gets better efficiency and it’s going to drive a cleaner, more resilient and more reliable grid,” he said.
Role of NYISO
NYISO will be charged with providing a bridge between distributed generation and the central station generators.
“We have to evolve from a corps of 400 central station generators to whatever is left of the corps of 400 with the distributed system platform, which coordinates or controls the distributed resources,” Mukerji said.
That’s where the nexus of REV and the ISO lay, with the distributed system platform, run by the utility. The ISO will not have visibility of the generation resources beyond the substation level.
“That is where the DSP will interact the with the ISO, like a super-aggregator to participate with this animated load and the sum total of the distribute resources into the markets. That is where the interaction of the DSP and the ISO is, where the coordination between the central station generation and the distributed resources happens,” he said.
FERC said MISO can continue doling out refunds to Wisconsin utilities, upholding the RTO’s new cost allocation methodology for three system support resource power plants in Michigan’s Upper Peninsula (EL14-34, et al.).
The commission’s Sept. 22 order determined that MISO’s plan to refund load-serving entities overcharged under the old methodology was satisfactory, rejecting rehearing requests that argued the commission did not have the power to order refunds.
Presque Isle Power Plant Source: WEPCo
The order stems from 2014, when FERC ordered MISO to scrap its SSR cost allocation on a pro rata basis to all LSEs in the American Transmission Co. service territory and instead assign costs to LSEs that required the White Pine, Escanaba and Presque Isle plants for reliability. (See FERC Upends MISO’s SSR Cost Allocation Practice.)
FERC accepted MISO’s revised SSR cost allocation methodology in early May, and the RTO submitted its refund reports in June. The RTO will make the LSEs whole in 14 monthly installments, which began in July.
However, the commission instructed MISO to suspend refunds for the Presque Isle SSR costs until it reaches a decision on an administrative law judge’s finding that Michigan ratepayers were overcharged by Wisconsin Electric Power Co. (ER14-1242-006, et al.). (See ATC Plan Could Eliminate White Pine SSR; Refunds Coming on Presque Isle?) MISO will then have to submit another refund report for the plant within 45 days of the commission’s decision.
FERC also directed MISO to provide “complete, un-redacted” copies of the refund reports to parties that have entered nondisclosure agreements.
