VALLEY FORGE, Pa. — PJM’s plan to add several gas pipeline emergency procedures to its manuals was derailed by stakeholders at last week’s Operating Committee meeting.
Staff had included the pipeline contingency plans in revisions to Manuals 3: Transmission Operations Updates and 13: Emergency Operations, two of five manual revisions set for endorsement votes at the meeting. All five were endorsed by acclamation, but not before the pipeline contingencies were stripped out.
The revisions would have added procedures for assessing the impacts of gas contingencies on the grid, including system conditions triggering the assessment; determining applicable gas infrastructure contingencies; and coordination with generation owners and gas pipelines.
PJM is attempting to get rules for a responding to emergencies on the pipeline system documented before the winter season, but stakeholders fear a repeat of the polar vortex conditions in 2014, when gas prices soared past offer caps and generators were left with no mechanism to recoup costs in the aftermath.
Gas generator representatives convened before and during the meeting to orchestrate moving an informational item on system resilience — scheduled for the tail end of the meeting — to the top of the agenda ahead of the votes. During that discussion, Panda Power Funds’ Bob O’Connell proposed adding a waiver to the manuals that would allow gas generators to recoup all expenses incurred if PJM directed them to operate outside of their dispatch schedule during an emergency.
PJM balked at the proposal. Chris O’Hara, PJM’s deputy general counsel, questioned whether stakeholders could vote to require the RTO to include in its Tariff a waiver of its own rules. O’Hara’s input made other stakeholders, including Dave Mabry of the PJM Industrial Customers Coalition and Exelon’s Sharon Midgley, hesitant to support the waiver until they could vet the motion with their organizations. Both expressed willingness to discuss the matter further at the Markets and Reliability Committee.
The meeting took a short break to discuss the situation. When it reconvened, O’Connell withdrew his waiver proposal and instead moved to vote on the manual revisions without the pipeline-contingency sections. The votes passed, and PJM’s Ken Seiler, who chairs the committee, said that a solution would be developed to present to the Dec. 21 MRC meeting.
Owner Transfer Rules Revision
PJM is planning to revise its rules for alerting it to changes in generator owners. The revisions would require notification at least 60 days prior to the date requested for the generation transfer — time for the RTO to review the information and ensure that all required documentation is submitted.
The request would need to be accompanied by 22 pieces of information, including contact information, a fuel-cost policy for applicable units and reactive credits. The fuel-cost policy would need to be submitted within 45 days of the requested effective date. PJM plans to develop a user guide to provide step-by-step directions on how to fill out the necessary information.
VALLEY FORGE, Pa. — PJM is moving to implement three changes to its financial transmission rights market, developed through its FTR Modeling, Performance & Surplus special sessions. All three received endorsement at last week’s Market Implementation Committee meeting.
The first involves changes in long-term FTR modeling to account for future transmission system upgrades, which can impact congestion revenue. PJM is concerned that long-term FTR clearing prices don’t reflect “true future system capability.” FTRs entitle holders to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. They can be purchased or converted from auction revenue rights, which are allocated to network and firm point-to-point customers.
PJM’s annual ARR/FTR network model includes transmission upgrades that will be in place by the following June 30, and staff proposed expanding that methodology to the long-term FTR network model so that it also looks forward one year. The model would be filtered to only include upgrades that fit a “low-frequency, high-impact” threshold.
That threshold would be defined as the upgrade being a constraint itself or impacting by +/-10% constraints that have contributed at least $5 million to congestion over the past year or any future constraint. For new facilities, the analysis would be based on the line outage distribution factor (LODF), a measure determining how the change in a line’s status affects flows elsewhere in the system. The FTR group would work with PJM’s planning staff to determine which upgrades should be included in the model. PJM included in its presentation an example of how that process would have worked for 2016 and found that three out of 21 upgrades would have been modeled.
PJM would also develop a new long-term residual ARR market to ensure holders maintain priority rights to any incremental capability created by upgrades still to be modeled.
The second set of changes would improve PJM’s ability to finalize and publish FTR auction results on time. Impetus for the solution came after PJM delivered its March auction results late and blamed it on having to simultaneously finish the results for several overlapping FTR auction periods. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)
PJM proposes to resolve the issue by eliminating some auction periods. PJM’s Brian Chmielewski said the proposal, if endorsed on its current timeline, would be filed with FERC in February to be effective for the June overlapping period.
The third set of changes would allocate any surplus from FTR auctions and day-ahead congestion to ARR holders after FTRs are fully paid to their target allocations. The issue developed after FERC required PJM to revise its methods for allocating ARRs and balancing congestion. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)
MIC members had to vote on two proposals: one developed by a coalition of ARR holders that allocated all surplus to holders, and a second developed by financial traders that allocated FTR surpluses to ARR holders up to their target credits and all day-ahead congestion surpluses to FTR holders.
The MIC endorsed the ARR holder proposal with 90% in favor and rejected the financial traders’ proposal with 34% in favor.
EnerNOC DR Aggregation Solution Questioned, Approved
“We don’t think this is a problem,” Independent Market Monitor Joe Bowring said, adding that “it seems to be presupposing the solution.”
Other stakeholders reiterated previous complaints that PJM’s stakeholder meeting schedule is already overbooked and that examining the issue doesn’t provide enough relative benefits to justify adding to the load.
“If we take issues up where there’s not really a problem, we create extra work for ourselves. I don’t think you can blame PJM for that. We have to blame ourselves,” Calpine’s David “Scarp” Scarpignato said.
EnerNOC argues that the current registration process is inefficient and provides a Capacity Performance value that fails to reflect the full reduction that the aggregated resources could achieve. PJM did not update its customer-registration rules when DR rules were revised to comply with CP requirements, nor did it seek stakeholder endorsement prior to unilaterally filing for approval last year of its seasonal aggregation plan. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)
Unable to work out their differences on how to regulate the market path of energy sales coming into PJM, the Monitor and financial marketers are asking the MIC to resolve the issue. They are presenting three different proposals on the issue.
The Monitor’s proposal would develop a list of “prohibited paths” that could be subject to resettlement. The Monitor would develop a monthly report of activity on those paths and share it with PJM so that either entity could refer use of those paths to FERC for enforcement.
Pierce Atwood partners Ruta Skucas and Jared des Rosiers presented a proposal developed by American Electric Power and the Financial Marketers Coalition. It would entail a change in PJM’s Tariff for the initial list of banned paths and require FERC, PJM and Monitor approval for any additions. It would also develop a “query” where users could seek a preliminary evaluation from PJM on whether a potential path would risk resettlement.
Stephen Kelly of Brookfield Renewable presented another proposal that would allow market participants the opportunity to establish with PJM and the Monitor that a potentially problematic transaction is “legitimate” before it is automatically resettled.
The proposals also differed on what level the activity should be evaluated. The Monitor proposed considering it from the level of the parent corporation, but the others called for analysis on the level of individual companies.
State regulators on Monday called on FERC to change its interpretation of the Public Utility Regulatory Policies Act to “align” the 1978 law “with modern realities.”
John “Jack” Betkoski III — vice chairman of the Connecticut Public Utilities Regulatory Authority and president of the National Association of Regulatory Utility Commissioners — wrote FERC commissioners a letter saying he was pleased that interim Chairman Neil Chatterjee had pledged that the commission would be pursuing PURPA reform.
“As the primary point of responsibility for PURPA’s on-the-ground implementation, the states have a strong interest in the reform of PURPA’s associated federal administrative regulations, and we hope this reform will continue to be a priority under the leadership of Chairman [Kevin] McIntyre,” Betkoski wrote.
Betkoski cited four changes since PURPA’s enactment in 1978 that he said required a new look from FERC. “These four changes — the rise of wholesale markets, the place of [qualifying facility] technologies as a commonplace source of power, the open-access regulation of the transmission system and the use of competitive methods to select projects throughout the states — suggest that PURPA’s administrative regulations should be aligned to these developments, instead of obstructing them. Despite these changes, many states incur significant transaction costs administering PURPA pursuant to the law’s arcane, 20th century mandates,” Betkoski wrote.
Pa’Tu Wind Farm Construction | PaTu / White Construction Company
He quoted Montana Public Service Commissioner, and former NARUC president, Travis Kavulla, who told the technical conference that PURPA issues consume more than one-quarter of his commission’s time on electric utility regulation. (See Montana PURPA Solar Saga Continues in State Court.)
NARUC proposed three changes, “each of [which] allows FERC to work within existing law to make meaningful changes to PURPA, while remaining committed to the law’s underlying goals of competition and encouragement of QF technologies,” Betkoski said.
NARUC proposed that FERC:
Adopt regulations that move away from the use of administratively determined avoided costs to their measurement through competitive solicitations or market clearing prices. “We propose that in certain circumstances, such as when a QF has both nondiscriminatory access under an [Open Access Transmission Tariff] and exists in a region where public utilities routinely use competitive solicitation processes, such a construct would qualify as wholesale markets under 18 CFR 292.309(a)(3). Making this determination would allow FERC to erase the false dichotomy between RTO/ISOs regions, and those regions without such an RTO/ISO but where each public utility nevertheless has an OATT and where states oversee utility procurement and require the use of competitive solicitations.”
Lower or eliminate the 20-MW threshold for the rebuttable presumption that QFs with a capacity at or below that size do not have nondiscriminatory access to the markets. “In keeping with the goal that FERC should better align PURPA implementation with modern realities, this threshold should be lowered to whatever the minimum capacity requirement is for a resource to participate in an RTO/ISO.”
Making changes to the 1-mile rule to discourage gaming. “There are a number of well-documented incidents where projects have forgone economies of scale to qualify themselves as individual QFs and evade other regulations; for instance, state commissions requirements for competitive solicitations. The commission should not encourage this form of regulatory arbitrage.” NARUC recommended Idaho Public Utilities Commissioner Paul Kjellander’s suggested criteria for determining whether a single project has been disaggregated in order to create multiple QFs under the generation size limit.
Public Service Enterprise Group and Exelon would receive hundreds of millions in subsidies to maintain the profitability of three in-state nuclear plants under legislation introduced in the New Jersey Senate on Friday (S3560).
Two of the sponsors, Sens. Stephen Sweeney and Jeff Van Drew, represent the area of southern New Jersey where the units are located. The third, Sen. Bob Smith, is chair of the Senate Environment and Energy Committee. PSEG has three nuclear reactors between the Salem and Hope Creek facilities; Exelon owns 43% of the Salem units.
Salem & Hope Creek Nuclear Power Plants | Green Delaware
Under the bill, the plants could be compensated through the issue of “nuclear diversity certificates” (NDCs) representing the “environmental and fuel diversity attributes” of 1 MWh produced by an eligible nuclear unit. All utilities in the state would be required to purchase NDCs from the nuclear plants monthly.
Funding for the program would come from a 0.4-cent/kWh charge on all New Jersey retail customers’ bills. The state Board of Public Utilities would have discretion to reduce the charge as it deems appropriate.
Several groups, including PJM’s Independent Market Monitor, New Jersey’s Division of Rate Counsel and coalitions of in-state citizen advocates and non-nuclear power generators oppose the plan and have pointed out that PSEG’s plants remain profitable. (See Opponents Assemble as PSEG Seeks NJ Nuke Subsidy.)
The three nuclear units provide about 40% of the state’s power. PSEG has estimated the subsidies could cost $240 million a year, about $31 for an average residential ratepayer. The Division of Rate Counsel put the cost at $320 million, or $41 per customer.
Eligibility Process
Plants would become eligible for NDCs by providing, within 30 days of the law’s enactment, certified three-year forward-looking cost projections that include operations and maintenance, fuel, non-fuel capital, and a valuation of operational and market risks that would be avoided if the plant shut down. The plants also could provide “any other information, financial or otherwise, to demonstrate that the nuclear power plant’s fuel diversity and air quality attributes are at risk of loss because the nuclear power plant is cash negative on an annual basis, or alternatively is not covering its costs including its cost of capital on an annual basis.”
Exelon and PSEG would also have to provide “certification that the nuclear power plant will cease operations within three years unless the nuclear power plant experiences a material financial change, and the certification shall specify the necessary steps required to be completed to cease the nuclear power plant’s operations.”
All information could be supplied confidentially.
The BPU would then have another three months to develop an application process for the plants to receive payment for their NDCs, and the plants would have another month to apply. A plant would have to satisfy five inquiries concerning why it deserves to be in the program and pay an undetermined application fee that could reach $250,000.
Justification
The bill references New Jersey’s plan to secure 70% of its energy needs from “clean energy sources by 2050,” calling nuclear a “critical source of zero-emissions energy.”
If the plants close, the void will be filled with natural gas plants, the bill says, and that “capacity challenges on existing natural gas pipelines combined with the difficulty in siting and constructing new natural gas pipelines, along with competing uses for natural gas, such as building heating, have created supply constraints in the past, and those constraints could impact system reliability.”
Part of the bill’s justification is that “recent severe weather events have demonstrated the need to improve the resilience of the electric power delivery system” and that “the mix of generation resources serving New Jersey residents must be capable of handling high-impact, low probability weather events.”
However, selected plants could be excused from performance in the event of natural disasters or other catastrophic events, such as labor disputes, or if the plant would need more than $40 million in capital expenditures. Plants that stop operating for a reason that isn’t covered would need to pay back all the payments it received since its last eligibility determination.
“Gov. [Chris] Christie is attempting one last robbery of the people and environment of New Jersey before he leaves office in January,” Jeff Tittel, director of the New Jersey Sierra Club, wrote in an op-ed about the bill Monday.
“The bill would give PSEG subsidies for their nuclear plants in New Jersey and simultaneously tie Governor-elect [Phil] Murphy’s hands when it comes to promoting renewable energy. Cheap natural gas combined with nuclear subsidies means renewable energy gets pushed out. Christie is trying to dictate New Jersey’s energy policy for the next 40 years, despite the fact that the people want renewable energy, and this bill undermines that.”
BOSTON — Developing trust is vital for the project siting process, according to panelists speaking at Raab Associates’ 156th New England Electricity Restructuring Roundtable last week.
“The thing that most undermines a project is when the proponent is seen as not presenting facts, not disclosing things, misrepresenting things,” Conservation Law Foundation President Bradley Campbell told meeting participants. “And it happens more often than you might think.”
Patrick Woodcock, assistant secretary of energy with the Massachusetts Executive Office of Energy and Environmental Affairs, highlighted the region’s progress in reducing emissions over the past decade and his state’s long list of project approvals in the past six months, including electrical transmission, LNG storage and natural gas pipelines.
But Woodcock, formerly Maine Gov. Paul LePage’s principal energy adviser, also pointed out the “natural conflict” that occurs around permitting. “In Maine, the biggest issues were not with natural gas pipelines or transmission lines, but with wind permitting,” he said.
Developers found that about 10% of the turbines represented about 90 to 95% of the controversy in Maine, he said.
“What that does is not only impede those projects that get a lot of media attention, but it creates a controversy for the entire industry, and I think there are parallels with what we see in Massachusetts,” Woodcock said. “When you start to have bad actors, and we have had a few, that causes a public perception over the entire industry.”
Compare and Contrast
Campbell said a developer’s credibility issues are “the most potent weapon” CLF has when it opposes a project. He then compared two potential projects in New England: Northern Pass and the New England Clean Power Link.
Both projects were proposed in July in response to a Massachusetts solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage), with projects to be selected in January.
Eversource Energy partnered with Hydro-Quebec on Northern Pass, a 192-mile line that would bring 1,090 MW of Canadian hydropower into New England for 20 years starting in December 2020.
Transmission Developers Inc. partnered with Hydro-Quebec on the New England Clean Power Link, which would include a submarine cable under Lake Champlain and an overland section to transmit 1,000 MW of hydropower, solar and wind from Canada. (See Hydro-Quebec Dominates Mass. Clean Energy Bids.)
“There was inadequate public engagement on the Northern Pass side,” Campbell said. “There were many, many points at which Eversource New Hampshire lost credibility with the public by not disclosing or by making representations that later turned out to be inaccurate, and the … process was entirely without significant stakeholder input. As a result of that you have an absolutely oppositional circumstance, which is going to affect the state of the project.”
Even though Northern Pass received a presidential permit on the U.S. side, “that original sin of failing to engage with the public in a credible way stays with them,” Campbell said. “Compare that with TDI, where you have 100% of the line being buried, as mitigation and minimization, as opposed to 30% [with Northern Pass]. Many fewer wetland impacts, many fewer vernal pool impacts. Down the line, a better engagement process and one that, in the case of our initial opposition, resulted in what we think is a robust mitigation package and a piece of transmission infrastructure that would serve the region well and also serve the environment and advance environmental objectives well.”
Lawrence Susskind, director of the MIT-Harvard Public Negotiations Program, said there will always be winners and losers from projects — or people who see themselves that way. The difference between the two, he said, is that a million people in a city who stand to gain $100 from a project have no motivation either way, while just a few people, if they perceive themselves to be big losers, are motivated to oppose.
The key, Susskind said, is to influence the 30 to 40% in the middle who haven’t yet made up their mind. The “guardians,” as Susskind called them, want to be convinced of a project’s merits and will support the opponents if they think that the process is unfair.
Building Trust
Building trust with stakeholders is key, said MU Connections President Mary Usovicz, who works with project developers on strategy.
“Ask, don’t tell. Spend time listening,” Usovicz said. “I recently did a project and the managers came in and said, ‘What are our talking points, what are we going to say, how are we going to pitch this?’ And I said, ‘No, we’re not doing any of that. We’re going to go on a listening tour. We’re going to go and listen to what people have to say. You’re going to introduce yourselves and say, “And what do you think about this project? How would you do this?”’”
That client spent two months just meeting stakeholders and listening, and that leaves a sense of trust, she said.
“That’s how you build trust,” Usovicz said. “When you listen to what people say, acknowledge what they have to say and actually incorporate it. So they changed their entire campaign after they did this listening tour — that builds up trust. Also it allows you to know what are those gains that Professor Susskind spoke about.”
When they go on such listening tours, developers can sometimes be shocked about what is important to people, she said.
“One lady said, ‘I’ll let you build that pipeline if, with all the trees you have to cut down, you stack them as firewood for me,’” Usovicz said. “That was her ask. I was like, ‘Oh yeah, we’ll stack it. I’ll have my husband come and stack it.’ It’s amazing what is important to people, but if you don’t listen and ask, you’re going to jump to conclusions.”
For one LNG project in Connecticut, Usovicz’s polling and research determined that community members trusted first responders more than the developer, the utility and the mayor. Knowing that the project to expand an LNG facility would remove gas tanker trucks from the roads, she took that information to first responders, who wrote a letter in support of the project because of improved community safety.
“And then [first responders] became the point of reference for the project,” Usovicz said.
Andrew Weinstein, legal adviser to FERC Commissioner Cheryl LaFleur, spoke on behalf of his boss, who couldn’t attend the meeting because of family matter.
Weinstein read notes from LaFleur’s speech highlighting issues of the coming years, such as “how energy pricing evolves in the face of so many new technologies and services. We’ve talked for years about non-volumetric energy pricing based on attributes provided, rather than just fuel burned, and it’s closer than it’s ever been.”
ISO-NE CEO Gordon van Welie addressed what he said are the two most important issues facing the region: integrating markets and public policy, and fuel security issues, namely natural gas supply constraints in winter.
Van Welie pondered the issue of state support for renewable resources through contracting: “So the real philosophical challenge is how do you make a competitive market work if one set of resources in that market are going to get cost of service and the rest of the resources are merchant and have to live on the revenues in that wholesale market?”
If one stands back from the details, he said, the question is, “Should the market lean in the direction of creating certainty for the states in terms of the entry of their resources into the capacity market, or should we lean in the direction of ensuring price formation? And I think what you’ll see is the ISO leans a little bit in the direction of price formation, knowing that we’ve got a big, three-decade transition ahead of us.”
Van Welie also noted that the RTO has done a study on fuel security and will wait until issues are settled around the U.S. Energy Department’s Notice of Proposed Rulemaking to subsidize uneconomic coal and nuclear before releasing the report. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)
“We’ve got more gas-fired capacity than we need in the winter, but we don’t have enough fuel to supply it,” he said.
At its final meeting of the year, the New York Public Service Commission approved rules to implement community choice aggregation, a pilot program to reduce air conditioning loads and a waiver allowing an energy service company (ESCO) to market to low-income customers.
Utility Energy Registry
The PSC on Thursday approved fees, procedures and data privacy protection measures for the Utility Energy Registry, an online platform to provide information regarding customer energy use. The order requires utilities to file tariff amendments implementing CCA data fees effective Jan. 6, 2018 (14-M-0224).
Left to Right: New York PSC Commissioners Diane Burman, John B. Rhodes (Chair), and Gregg C. Sayre | NY Department of Public Service
Access to such information is vital to the success of the distributed energy resources market, the commission said; for CCA programs to function, municipalities and program administrators must be able to access both aggregated and individual customer data.
The order directs that customers pay one-half of the estimated cost to prepare queries to populate the registry, with the remainder recovered from fees for customer lists and customized aggregated data. The costs to be recovered via CCA fees will be based on an estimated request rate of 25% of eligible customers over five years.
Rhodes | NY Department of Public Service
“Through the creative bargaining power enabled by the community choice aggregation model, communities are enabled to work with their energy supplier to procure resources that better serve their citizens’ local energy goals,” PSC Chair John Rhodes said. “This order provides a fair and uniform approach to an essential point of enabling CCAs to go forward: an approach on data fees. It will accelerate the opportunity for communities who wish to establish a CCA.”
The commission set a fee of 80 cents per account for all utilities, saying that obtaining the mailing list and the ability to engage in an opt-out program will help CCAs and ESCOs minimize customer acquisition costs.
Con Edison Smart A/C Trial
The commission also voted to approve a three-year, $7.5 million pilot program for Consolidated Edison to control its New York City customers’ air conditioners to help shave peak demand in summer. Customers who allow the utility to install Wi-Fi-enabled ‘smart plugs’ on their A/C units will be eligible to earn $95 or more in rebates and rewards.
While some 21,000 electricity customers already participate in Con Ed’s Smart AC program, the commission’s order on the new pilot program, Connected Devices, expands the demand response measure to millions of people, including public housing tenants (17-E-0526).
Burman | NY Department of Public Service
New York City Housing Authority residents get their electricity from the New York Power Authority and do not pay the monthly adjustment clause (MAC) surcharge through which the programs’ costs are recovered. Commissioner Diane Burman asked how expanding the measure to NYPA customers would affect the cost-recovery mechanisms approved by the commission.
Cully | NY Department of Public Service
“We anticipate the impact of any cost shifts from NYPA to Con Edison customers to be minimal while participation and penetration of these programs is low in the NYPA buildings,” responded Robert Cully, a Department of Public Service staffer.
Con Ed estimates there are 450,000 residential units in the buildings supplied by NYPA, a significant source of untapped load relief. The utility could petition for additional cost recovery, “and Con Edison is not shy about requesting those sort of program modifications,” Cully said.
ESCO Low-income Ban Waiver
The commission gave Utility Expense Reduction permission to serve low-income customers, ruling that the company had fulfilled the waiver requirements of its December 2016 order prohibiting ESCOs from enrolling customers who are participants in low-income assistance programs.
The PSC requires that ESCOs demonstrate an ability to calculate what the customer would have paid to the utility; an assurance that the customer will be paying no more than what they would have paid to the utility; and proper reporting and verification to ensure compliance. (See New York PSC Adopts DER Rules, Sanctions ESCOs.)
The order (12-M-0476) requires the ESCO to report semiannually on the participation of low-income customers in its Green Energy Price Cap Program. The company must report “the number of customers served, the monthly calculated amounts billed and the alternative amounts that the utility would have charged by customer, as well as the amount of any refunds issued to each customer to effectuate the price guarantee,” the commission said.
Burman voted against the waiver. “I’m concerned about doing these individually in standalone petitions and would rather see a more collaborative process that gets to a more global solution in a more standardized way,” she said.
Year-End Performance Wrap
Palmero | NY Department of Public Service
Before adjourning, Rhodes took the opportunity to summarize the major actions by the commission and the Cuomo administration in 2017. Among the highlights: a Con Ed rate ruling intended to encourage energy efficiency and smart grid technologies; the announced closure of the Indian Point nuclear plant; a new compensation structure for valuing DERs; an order allowing large commercial batteries in New York City; an expansion of Con Ed’s Brooklyn-Queens Demand Management project; and a solar project for low-income customers.
“So it has been a productive year,” said Rhodes, the former CEO of the New York State Energy Research and Development Authority, who was appointed to the commission in June to replace Audrey Zibelman. (See NYPSC Chair Promises ‘Continuity’ on State Energy Policies.)
The commission ended the meeting by approving a resolution of appreciation to Tina Palmero, deputy director of the DPS’ Office of Clean Energy, who is leaving the department. Rhodes said that Palmero joined the department as a transmission specialist in 1988 and that her work over the years, including on the state’s Clean Energy Standard, has had “tremendous impact to the benefit of all New Yorkers.”
FOLSOM, Calif. — CAISO’s Board of Governors on Thursday approved new generator contingency modeling, rules extending time for generator interconnections and enhancements to the Western Energy Imbalance Market (EIM).
The board made several unanimous votes and also approved CAISO’s 2018 budget of $197.2 million, which funds ISO operations and salaries based on fees collected from system users. The budget grew by 1% from last year. (See CAISO Seeks Bump in Spending, Revenue Requirement.)
CME Initiative Approved
The board approved a new tool that will allow dispatch of generation to return energy flows to normal levels within a required time frame following the loss of major infrastructure. The contingency modeling enhancements (CME) proposal took years to develop, said Keith Casey, CAISO vice president of infrastructure and market development.
| CAISO
“This was some four years in the making to bring this to you today,” Casey told the board, which unanimously approved the measure with little discussion.
CAISO developed the CME initiative to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line.
The ISO currently dispatches generation to ensure that output does not exceed system limits, but its market model does not consider how to dispatch in a way that returns a line to normal operating limits within the required time. CAISO has been relying on “minimum online commitment constraints” that dispatch generation to meet constraint requirements, but generators are not compensated for the capacity made available to meet contingencies, and exceptional — or out-of-market — dispatch is used to return the transmission system to normal.
The new modeling creates “corrective capacity” in the day-ahead and real-time markets, and resources would be paid for the locational corrective capacity they provide.
Southern California Edison and the Six Cities group of Southern California municipal utilities opposed the change, saying it has limited benefit. SCE said the measure also introduces complexity and makes market prices less transparent. Powerex supported the changes but said it should not be implemented until CAISO overhauls its congestion revenue rights policy. (See CAISO Finalizes Constraint Tool Proposal.)
During the stakeholder process, CAISO removed a provision that would have applied the methodology to lines not subject to the 30-minute restoration time frame, saying it would develop an additional policy in that regard if needed. The ISO also declined a stakeholder suggestion to allow bidding for “corrective capacity” intended to reduce flows across a line within 30 minutes of a contingency, saying the measure would be complex and difficult to mitigate for market power.
New Interconnection Rules
The board also approved a change to CAISO’s generator interconnection policies that will extend the time projects can remain in the queue. The revision is designed to help renewable projects stay financially viable as utility-scale procurement of renewables declines.
“This change will provide additional time to validate and correct interconnection request submittals, which should further streamline the efficiency of the overall interconnection study process,” Casey said in a memo to the board. The change requires approval by FERC.
Many load-serving entities require that generators complete the second phase of the ISO’s interconnection process to qualify for procurement. There is typically about a four-month window between Phase II reports and a transmission deliverability allocation. While projects can currently sit in the queue for a year, there has been a sharp increase in the number of projects unable to secure power purchase agreements before being dropped from the queue.
The new rules extend by a year the “parking” period in the queue, and the ISO also intends to examine its transmission planning deliverability qualification criteria in 2018. (See CAISO Launches Generator Interconnection Effort.)
Governor David Olsen said the proposal is “a good faith effort by the ISO to accommodate the slowdown of project development, especially renewable resources, that we are facing.” But he added “we are under no illusions that taking this step is going to do anything effectively to address the underlying problems behind the effective suspension of procurement.”
That issue, according to Olsen, is rooted in the development of distributed resources and the loss of utility load, “which could very materially affect the ability to develop [utility-scale] renewable resources in the near future. Those are issues that are going to have to be addressed by others.” Olsen said that all parties involved in California policies should ensure that clean energy development can proceed.
The board also approved a set of EIM enhancements that represent a pared-down version of a package proposed earlier this year. The EIM Governing Body in late November approved the package, which automates some manual processes, facilitates bilateral settlements and improves the market’s modeling accuracy. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.)
In executive session, the board also promoted Jodi Ziemathis, the ISO’s executive director of human resources, to vice president of human resources. Chief Financial Officer and Treasurer Ryan Seghesio was also named vice president, while retaining his current titles.
CARMEL, Ind. — MISO last week said it will defer any initiative to account for planned and maintenance outages in capacity planning until it kicks off a broader discussion on overall resource availability sometime next year.
The RTO floated the idea of the initiative last month after observing an increasing number of intentional outages that occurred during periods of peak demand. (See MISO Seeks to Gauge Risk of Peak Season Planned Outages.)
But stakeholders are mixed in their support for accounting for the outages in forecasts for peak periods, MISO Resource Adequacy Coordinator Ryan Westphal said during a Dec. 13 Resource Adequacy Subcommittee meeting.
Instead of accounting for the outages in its mid-2018 capacity planning, MISO now hopes to implement the changes for the 2019/20 planning year. The RTO plans to roll the outage consideration into discussion about its seasonal capacity procurement proposal, which has been rebranded as “resource availability and need,” as planners have increasingly begun to think the answer to capacity issues may not lie in seasonal procurements but in something more granular.
RASC liaison Shawn McFarlane said MISO is now assessing the “hour-by-hour” availability of capacity resources instead of relying on a season-by-season basis of availability. The RTO plans later this month to release a white paper on resource availability trends throughout the year.
“We want to make sure we understand when resources are available, especially in light of the increasing maximum generation events since the 2016/17 planning year,” said MISO analyst Dustin Grethen.
Indianapolis Power and Light’s Ted Leffler noted that MISO once had a Real-Time Sufficiency Task Force that worked on outage-related forecasting issues but ultimately did not come up with a new forecasting process that included planned outages.
“We worked on this for about a year and a half before we gave up,” Leffler said. He urged MISO officials to review the old task force’s documents, if any of them survived.
MISO stakeholders have likewise cooled on defining seasonal capacity procurement requirements.
At an October RASC meeting, some stakeholders questioned the need for seasonal limits, noting that MISO’s emergency conditions in April and September were outside of the summer months, the result of poorly coordinated transmission outages.
NRG Energy’s Tia Elliott suggested that MISO might not need a seasonal definition of capacity at all if it decided to pursue its own transmission project to link its Midwest and South regions. Elliott also expressed exasperation at “being down this dirt road before and ending up in a puddle,” referring to MISO’s two-season capacity market proposal in late 2015 that eventually devolved into the proposal being scrapped to allow the RTO to conduct more research. (See “Seasonal Aspect Back in Conceptual Stage,” MISO Postpones External Zones Until 2019 Auction.)
CARMEL, Ind. — MISO’s market planners last week outlined a potential 30-minute reserve product to reduce uplift and multiday generator commitments to cut production costs. Both concepts are in early planning stages, officials told the Dec. 14 Market Subcommittee meeting.
Engineer Oluwaseyi Akinbode said MISO currently addresses short-term capacity needs using offline resources with quick start-up times and economic generation already online. However, Akinbode said, the approach results in expensive uplift payments.
Akinbode said a short-term capacity reserve would be especially helpful in MISO South, which has less than 500 MW of offline capacity available within 30 minutes. Two southern load pockets — Amite South and the West of the Atchafalaya Basin (WOTAB) — have none and less than 100 MW, respectively.
“We are on track in 2017 to incur about $20 million [in uplift]. Last year, we incurred about $20 million … in day-ahead revenue sufficiency guarantee to manage load pockets,” Akinbode said.
Making the price of the reliability service transparent may cause some generation owners to defer plant retirements and others to develop new fast-start resources, said Jeff Bladen, MISO executive director of market design.
“What we want to make sure is that generators have the best economic signal, and they judge for themselves,” Bladen said.
Northern Indiana Public Service Co.’s Bill SeDoris said that with only some localized parts of the footprint needing the capacity product, he saw a possibility that only generation with access to certain load pockets would be able to benefit financially. “That may raise concerns,” he said.
Bladen said that while MISO doesn’t yet have systemwide need for the short-term product, conditions will change with the increased adoption of intermittent resources. He pointed out that MISO doesn’t expect to have a short-term product ready for use until 2020, when the footprint’s resource mix will have further shifted toward renewables.
“We expect this to be needed systemwide … and by the time we’re fully utilizing it, we expect the need for a 30-minute product to be much more prevalent systemwide. We do see this as a need systemwide even though the short-term value proposition is localized,” Bladen said.
MidAmerican Energy’s Greg Schaefer asked under what conditions a 30-minute dispatch would be valuable.
Akinbode said the option would help eliminate out-of-market commitments that cause MISO to incur uplift payments.
Bladen said the product was needed because MISO’s forecasting of anticipated wind supply is less accurate beyond 30 minutes from dispatch.
“It’s a far less costly way to manage operations until we get to that 30-mintue window where we get a clearer picture of what to expect out of resources like wind,” Bladen said.
SeDoris asked if MISO designers were thinking about creating penalties for units that commit to offer the short-term capacity but don’t deliver.
“There are a lot of details we’re going to have to work through,” Akinbode agreed.
Werner Roth, an economist with the Public Utility Commission of Texas, thanked MISO for its work. “This is something we’ve been asking for a long time,” he said.
Multiday Market
MISO also is considering the use of a screening tool to make recommendations for turning generators with long lead times on and off seven days in advance. The RTO estimates implementation sometime in 2019. (See MISO Exploring Multiday Market.)
“The savings of a multiday optimization window are substantial,” Senior Market Engineer Chuck Hansen said.
Hansen said MISO identified the best candidates for multiday commitments using three criteria: long lead times, high start-up costs and the ability to respond. The RTO then developed a screening tool that estimates potential cost reductions by examining units individually.
“Some units have high emissions upon start-up and sometimes they can only start once or twice per month to avoid going over their emissions” limits, Hansen said.
He said MISO began researching with a multiday candidate list of 85 generators and later increased the number to 113 of the 1,200 units in the footprint after staff spoke with members and the Independent Market Monitor.
Using the 113 candidate generators, Hansen said MISO estimated that the multiday screening tool could reduce production costs by $157.3 million and output by 2,658 MW annually. Hansen said some of the savings were attributable to passing commitments to more nimble and economic units. But he cautioned that costs avoided using a multiday market won’t likely be as dramatic as the study suggests because it couldn’t account for unanticipated weather, unforeseen outages and increased renewable penetration. MISO estimates an achievable savings of between $29 million and $44 million per year, Hansen said.
“Some of this relies on [long-term] forecasts we don’t yet have,” he added.
Some stakeholders said that MISO estimating even a 10 to 15% share of the study’s savings would overstate the benefits.
Customized Energy Solutions’ Ted Kuhn said the multiday commitments could actually increase costs should MISO produce a wildly inaccurate seven-day forecast.
“With this, I just see more make-whole payments,” added Kuhn’s colleague David Sapper.
Bladen added that the screening tool merely suggests commitments to operators, and it’s up to operators to decide whether to act on those. MISO and stakeholders have yet to decide if the tool’s recommended commitment changes will come attached with make-whole payments and other market rules should operators decide to take its advice.
“What the tool is doing is simulating what the participant might change when they self-commit. The screening tool is not dispatch instructions. This is not a new kind of dispatch tool that we’re trying out,” Bladen said.
For financially binding commitments, MISO would have to create a multiday pricing forecast that the RTO would have confidence in, Hansen said.
When a generator decides to decommit, Hansen said, the lost generation will be replaced with new generation with the LMP at the hour, with the idea being to turn off more expensive generation and replace it with the system LMP.
In September, MISO Director Thomas Rainwater said that should MISO move to multiday financial commitments, “we have to make sure natural gas generation is in lockstep with pipeline commitments.”
AUSTIN, Texas — The ERCOT Board of Directors last week unanimously approved a $246.7 million transmission project to address growing energy needs along the Texas Gulf Coast.
Freeport is a highly industrialized region with several large chemical facilities and a major seaport. ERCOT projects that by 2019, the Freeport area’s load will increase 92% to 1,979 MW, with much of that growth coming from a large chemical plant. An additional 300 MW is expected by the end of 2022.
“We continue to see growing demand for electricity in the ERCOT region, especially in areas affected by industrial growth and oil and gas activity,” said ERCOT Senior Manager of Transmission Planning Jeff Billo.
The ISO’s independent review of the project confirmed its necessity. Staff analyzed five options and proposed the most cost-effective to support future electric needs in the area.
CenterPoint Energy, which services the area, suggested a two-phase approach to solve reliability criteria violations caused by the increased load. A $32.3 million first phase, or “bridge-the-gap upgrades,” focuses on near-term reliability needs with a 345-kV loop and a series of reactors, autotransformers and capacitor banks at a key substation.
The $214.4 million second phase comprises a new 48-mile, 345-kV double-circuit line and circuit upgrades to another 345-kV line.
Any projects approved by ERCOT that cost $50 million or more are classified as Tier 1 initiatives and require board approval.
The project must also be approved by the Public Utility Commission of Texas. Work is expected to be completed by 2022.
The board approved two nodal protocol revision requests (NPRRs) recently taken off the table by the TAC, but with varying degrees of opposition.
Brazos Electric Power Cooperative’s Clifton Karnei, representing the cooperative segment, cast the lone dissenting vote against NPRR815. The change increases from 50% to 60% the limit on load resources providing responsive reserve service (RRS), with at least 1,150 MW coming from resources that can provide primary frequency response.
The Protocol Revisions Subcommittee said changing the constraint will allow additional resources to provide RRS at lower costs. However, the Lower Colorado River Authority’s John Dumas, who opposed the measure when it passed the TAC last month, told the board that NPRR815 could harm reliability because of the reduction in generation resources that provide inertia and voltage support. (See “TAC ‘Un-Tables,’ Endorses NPRRs,” ERCOT Technical Advisory Committee Briefs.)
“Our opposition has to do with concerns over reliability risk and commercial risk,” Dumas said. “When you increase the amount of load in responsive reserves, you’re decreasing the amount of potential generation on the grid to manage things like voltage, inertia and ramping capabilities. When you take generation off the grid, you’re reducing reliability, you’re not improving reliability.”
Dumas said the commercial risk comes from a possible increase in RRS price spikes during high-wind, low-load situations.
“You can commit enough capacity to cover your energy position, but you cannot … when you suddenly have a wind variation or a unit trip,” he said. “When you reduce the amount of supply from generation, you’re reducing the offer curve.”
Woody Rickerson, ERCOT’s vice president of grid planning and operations, pushed back on the reliability concerns.
“[NPRR]815 in no way changes what we need for responsive reserves, only how we procure it,” he said. “We’ve gone through probably six months of questions on it. We’ve studied it, and it in no way endangers reliability.”
Rickerson pointed out ERCOT monitors inertia separately from responsive reserves, and that the ISO can always procure more services beyond the minimum amount.
NPRR825 also cleared the board, but with four votes in opposition from cooperative and consumer interests. The revision requires ERCOT to issue a DC tie curtailment notice before curtailing the tie’s load, addressing the ISO’s concerns about declaring an emergency condition before curtailing DC tie load for any reason, staff said.
Several directors were concerned about the NPRR’s price tag — $200,000 to $300,000 in development costs as part of a larger software tool — but staff said the change would result in automated processes and system reports. Rickerson told directors that the day before, staff had to issue a watch to curtail 27 MW.
“It’s increasing transparency in the marketplace,” said unaffiliated director Karl Pfirrmann, speaking in favor of the NPRR. “That should make things more efficient and helps prepare us for emergency situations.”
ERCOT CEO Bill Magness said the ISO is projecting to end the year nearly $8 million under budget following a warmer-than-normal October.
“Revenues go up, but so does congestion,” he told the board.
A positive variance in October for ERCOT’s system administration fee helped reduce an unfavorable year-end projection to about $100,000. Much of the overall positive variance stems from $4.1 million savings in interest expense because of project funding and minimal revolver usage, and interest income because of higher rates.
Magness said staff has completed their reliability-must-run studies of planned generator retirements and determined none of the units needs to be kept on for reliability needs. He also said the Texas grid is seeing higher-than-expected congestion in the day-ahead market, but that congestion revenue rights funding is not a concern.
IMM: Ancillary Services Market Growing in Importance
Beth Garza, director of the Independent Market Monitor, focused her board report on ancillary services, which have declined with the advent of the nodal market in 2011.
| Potomac Economics
Garza said the services cost $1.03/MWh in 2016 and averaged 87 cents/MWh through Oct. 7, but that is likely to change with the pending retirement of more than 2 GW of aging generation (though those units only have provided 2.5% of regulation up and 6.4% of regulation down in 2017 through October). Regulation up and down have seen the biggest decrease since the zonal market was replaced, with dispatch now occurring every five minutes instead of 15.
“It’s that efficiency of procuring on smaller time frames, and not over-procuring, that has brought the overall average down,” Garza said. “These things we call ancillary will become more important in a future market that has more load to zero-cost variable resources. As the [ancillary services market] becomes more important and [resources] scarcer, as less units are around to provide those services, those prices are likely to become higher and more important going forward.”
Asked if she was comfortable with ERCOT’s ancillary market performance, Garza said the interaction between regulation and security-constrained economic dispatch “continues to be refined,” but she noted total regulation has seen about a two-thirds reduction from the 1,800 MW in the zonal market.
“That balance seems pretty good,” she said.
The Monitor is projecting ERCOT’s real-time prices will be above last year’s record low average of $24.62/MWh. Through the first 10 months of 2017, prices are up 17% to $28.97/MWh compared to the same period last year. Real-time prices settled at $24.
| Potomac Economics
Gas prices averaged $2.44/MMBtu last year but were $3/MMBtu for the first 10 months of 2017.
Membership Approves 5 New Directors
ERCOT’s corporate members approved the election of Terry J. Bulger and the re-election of Peter Cramton to three-year terms during their annual membership meeting. Cramton’s current term will expire on Aug. 1.
Bulger is a 35-year banking professional with ABN AMRO and Bank of Montreal, and has more than 25 years of experience in risk management. Cramton is an economics professor at the University of Maryland and the University of Cologne.
Members also approved four new segment directors, who were previously segment alternates, and their alternates, to serve in 2018. The directors are:
Industrial consumers — Sam Harper, Chaparral Steel Midlothian
Independent generators — Kevin Gresham, E.ON Climate & Renewables North America
Independent retail electric providers — Rick Bluntzer, Just Energy Texas
Investor-owned utilities — Kenneth Mercado, CenterPoint Energy
The new segment alternates are:
Industrial consumers — Mark Schwirtz, Golden Spread Electric Cooperative
Independent generators — Amanda Frazier, Luminant
Independent retail electric providers — Mohsin Hassan, VEH
Investor-owned utilities — Mark Carpenter, Oncor
TAC Gets 6 New Members
The membership also approved six new members to the TAC, which makes recommendations to the board and is aided by five subcommittees:
Independent generators — Ian Haley, Luminant
Independent power marketers — Kevin Bunch, EDF Energy Services, and former ERCOT staffer Resmi Surendran, Shell Energy North America
Independent retail electric providers — Sandra Morris, Direct Energy
Investor-owned utilities — Walter Bartel, CenterPoint
Municipals — John Bonnin, CPS Energy
Board Clears 4 NPRRs, Other Measures
The board unanimously approved revisions to the methodology for computing responsive reserves as a result of NPRR815’s implementation, and two changes to determining non-spinning reserves in 2018; associated with NPRR815 and two changes to determining non-spinning reserves in 2018; accepted a clean system and organization control audit; and approved new key performance indicators.
The directors also unanimously approved NPRR846 by itself, and three other NPRRs on the consent agenda.
NPRR846: Allows previously committed emergency response service (ERS) resources to participate in must-run alternative agreements and modifies the methodology for evaluating the impact of ERS load performance during the first partial interval on calculating the alternate baseline. The change also defines acceptable parameters for an ERS generator’s self-serve capacity, and sets the ERS test performance factor to significantly lower values, in some instances to zero for resources with three consecutive test failures within a 365-day period. The NPRR includes additional administrative changes and clarifications to existing ERS protocol language.
NPRR834: Clarifies processes associated with ERCOT’s repossession of congestion revenue rights following a payment breach or other default by a market participant. The change specifies data transparency requirements; documents the disposition of auction revenue funds above amounts owed to ERCOT; clarifies that the one-time auction bids must be positive; and allows the immediate transfer of CRR ownership to the winning bidder should an auction be necessary.
NPRR839: Updates the protocols to clarify that, upon receiving meter data transactions from transmission or distribution service providers, ERCOT will forward the transactions to the designated competitive retailer.
NPRR843: Addresses four reporting items in Section 3 of the Nodal Protocols (Management Activities) by:
Changing the logic of short-term system adequacy reports for more consistent treatment of resource status; adding language to provide clarity to the reports’ end users;
Creating a new report that will show the portion of ancillary service offers at or above 50 times the fuel index price (FIP) when the market-clearing price for capacity of the service exceeds 50 times FIP;
Adding elements to the “48-hour highest price [ancillary service] offer selected” report, including the highest-priced offer selected in a supplemental ancillary service market (SASM); and
Creating a SASM disclosure report to provide transparency into ancillary service offers and awards for any SASMs executed within an operating day.
