MISO will take another crack at identifying a project that could provide an alternative to the constrained transmission path linking its North and South regions.
But staff now have the “bandwidth” to take on the effort as part of this year’s market congestion planning study, MISO Planning Manager Matt Ellis told the Planning Advisory Committee on Tuesday. The study is designed to identify congestion-relieving projects that provide economic benefits exceeding the costs stemming from congested flowgates.
Ellis said MISO’s motivation to find possible solutions stems from both its research into showing that renewable growth is set to increase flows on the contract path, and the uncertainty around future terms and costs of its settlement agreement with SPP.
He said the RTO will reuse some underlying data from its 2017 footprint diversity study, which was exclusively aimed at finding a solution to alleviate the contract path. He said the lack of solutions from that effort isn’t deterring staff, pointing out that there are two years of fresh data on the contract path to study now.
“This is classic transmission planning. Many times, we look at the same flowgate multiple years in a row. The idea is ‘Hey, it’s a been a few years; let’s see what’s changed,’” Ellis said.
Beginning April 25, MISO will open a second, special project submission window for the market congestion planning study. Project submissions will be limited to solutions that physically cross the North-South interface and terminate on either side in MISO territory. Solutions must either eliminate or reduce settlement costs, or increase MISO’s regional transfer capability.
MISO will test project candidates against a scenario based on the possibility that the terms of its agreement with SPP continue in perpetuity. Ellis said MISO will also consider a sensitivity where the agreement is terminated and flows are again limited to the original 1,000-MW contract path. The agreement currently limits MISO line flows to 3,000 MW north-to-south and 2,500 MW south-to-north.
Ellis said MISO will likely develop a more specific list of design requirements. All project ideas will be due June 21.
While MISO intends to produce project recommendations by late August, Ellis stressed the research will be thoughtful and methodical. “Throughout this process, if we feel that we’re rushed … we have the flexibility to push back the timeline [and] add meetings. We’re not bound by an MTEP 19 decision point in this study.”
By Michael Kuser, Christen Smith and Rich Heidorn Jr.
WASHINGTON — FERC on Thursday ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable.
The order concludes investigations FERC began in December 2017 under Federal Power Act Section 206 and directs the grid operators to eliminate inflexible operating limits and other rules that the commission said are preventing prices from reflecting the marginal cost of serving load. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
“Fast-start resources are typically committed in real time, very close to the interval when needed, and can respond quickly to unforeseen system needs. But without some form of fast-start pricing, some fast-start resources are ineligible to set prices,” the commission said in a press release.
FERC said the changes it is requiring will more accurately reflect marginal costs when the dispatch of a fast-start resource is the next action taken to meet load. It said the new rules will provide more accurate and transparent price signals to influence investment decisions, minimize production costs and reduce uplift.
“We find that commitment costs for fast-start resources are marginal because they are generally incurred in coordination with the real-time dispatch,” the commission said.
FERC ordered NYISO to revise its pricing logic to reflect the start-up costs of fast-start resources and relax the economic minimum operating limits of all fast-start resources by up to 100% to allow them to set prices (ER18-33).
The commission gave PJM a longer list of changes, ordering it to make a compliance filing by July 31 (EL18-34).
In opening the investigations in 2017, the commission said MISO and ISO-NE have already implemented fast-start best practices and that CAISO would get limited benefit from such changes. The commission also opened a Section 206 investigation into SPP’s practices, which remains pending (EL18-35).
NYISO
The commission directed NYISO to make a compliance filing by Dec. 31 and implement the Tariff changes by Dec. 31, 2020.
NYISO currently applies fast-start pricing logic to online and offline fixed block units that can start in 10 minutes. The ISO defines a fixed block unit as one that, “due to operational characteristics, can only be dispatched in one of two states: either turned completely off, or turned on and run at a fixed capacity level.”
In the first step of its optimization process, NYISO establishes resources’ physical base points in their real-time energy schedules. In the second step, the pricing run, the ISO relaxes the economic minimum operating limit of fixed block units to allow them to be eligible to set prices. The price of offline fixed block units can include a unit’s start-up costs.
“However, NYISO neither relaxes the economic minimum operating limits of dispatchable resources (i.e., resources that are not block-loaded), nor does it include the start-up costs of these or any online resources for the purpose of setting prices,” the commission said.
FERC acknowledged that NYISO does have fast-start pricing rules and said it is not proposing that the ISO implement a new pricing concept, nor would it require it to change its offline fast-start pricing or its rules on overgeneration “at this time.”
The Electric Power Supply Association and the Independent Power Producers of New York filed comments in February 2018 supporting the changes, saying that “reflecting all resources which have fast-start capability in energy and operating reserve real-time pricing is a fundamental concept,” and “it is critical that fast-start pricing includes all commitment costs.”
NYISO’s Market Monitoring Unit also filed supportive comments last year, saying that, “We agree with this proposed change because it is fully consistent with the economic principle that the competitive price for any good should reflect the marginal cost of supplying the good. Hence, well-designed fast-start pricing rules allow real-time prices to include the cost of committing and running peaking units when they are the marginal source of energy.”
PJM
The commission identified six Tariff revisions needed to correct PJM’s rules.
First, the commission said PJM must update its software to consider fast-start resources dispatchable from zero to their maximum operating limits for the purpose of setting prices.
Fast-start pricing also must apply to all applicable resources, which FERC said should only include those with a start-up time of one hour or less and minimum run time of one hour or less. Currently, PJM identifies combustion turbines with a two-hour start-up time as fast-start resources.
FERC also required PJM to:
Alter the real-time energy market clearing process to consider fast-start resources in a way that is consistent with minimizing production costs;
Include commitment costs in energy prices for fast-start resources in both the day-ahead and real-time markets; and
Implement its proposal to use lost opportunity cost payments to offset the incentive for overgeneration or price chasing.
In addition to submitting a compliance filing by July 31, PJM must make a one-time informational report by Aug. 30 explaining how the revisions do not raise new market power concerns.
FERC said PJM has special pricing rules only for block-loaded units — resources whose economic minimum operating limits equal their economic maximums, meaning they have no dispatchable range. The RTO seeks to let them set prices by relaxing the economic minimum operating limit of online block-loaded resources by up to 20% — increased from 10% in 2016.
“Even with this increase, we remain concerned that without allowing relaxation by up to 100%, marginal actions taken by system operators will not be reflected in prices,” FERC said.
The commission also said PJM’s limiting of applying fast-start pricing to block-loaded resources alone does not reflect the marginal cost of serving load when a dispatchable fast-start resource is needed. It said it agreed with commenters on “a technology-neutral approach [that] ensures that no resource that can perform the same service is unnecessarily excluded from fast-start pricing treatment.”
Commissioner Cheryl LaFleur noted that the order limits fast-start resources to those with start-up or minimum run times of one hour or less, rejecting PJM’s request for a two-hour threshold.
Daniel Kheloussi, of FERC’s Office of Energy Policy and Innovation, said the order finds that resources with start-up and minimum run times exceeding an hour “lack the flexibility to operate in a manner consistent with unforeseen and transient real-time needs, and therefore, commitment and dispatch of such resources are not analogous to a marginal decision.”
The RTO is in the process of “refreshing” an ongoing list of possible new benefit metrics, planning adviser Adam Solomon said during a Planning Subcommittee meeting Tuesday.
MISO last year created two new metrics to help size up the benefits from market efficiency project candidates: the value of deferred or avoided reliability transmission projects resulting from an MEP, and the value of increased capacity on the contract path connecting its Midwest and South regions.
The RTO said it may develop even more benefit metrics by the end of the year, including increased capacity import and export limits, reduced congestion from fewer transmission outages, reduced transmission losses and whether projects can boost grid resilience. (See “More Benefit Metrics?” MISO MEP Cost Allocation Plan Goes to FERC.)
In 2017, MISO and stakeholders participating in the Regional Expansion Criteria and Benefits Working Group (RECBWG) created a “high potential” list of possible benefits that included the transmission losses and resilience metrics, as well as reduction of capacity costs from reduced peak load losses and the value of future capacity expansion deferral from increased capacity import/export limits.
Stakeholders asked MISO to elaborate on how it plans to measure the benefits of added resilience.
“We were hoping you would actually,” Solomon joked, noting the RTO is seeking stakeholder input on the metric.
“Resilience seems so vague and broad … you would almost have to create a separate stakeholder process to [define it]. I would just hate to see this bog down the process when you have other, specific and quantifiable ideas,” said Sam Gomberg, senior energy analyst with the Union of Concerned Scientists.
Solomon said he would return to the RECBWG with an updated list of benefit ideas stakeholders want to explore. MISO and stakeholders will work on prioritizing the list in the middle of the year, then discuss the feasibility of the selected benefit metrics in the third quarter. He asked stakeholders to submit written comments on the issue by May 17.
Release of 2nd Tx Cost Estimate Guide
MISO and stakeholders are finalizing the second-ever version of a cost estimation guide for the RTO’s 2019 Transmission Expansion Plan.
The RTO released its first cost estimation guide for market efficiency or multi-value projects early last year with the intent of updating the estimates as appropriate. (See MISO Releases Transmission Cost Estimates Guide.)
MISO divides transmission costs into four categories: land and right of way; structures and foundations; conductor, optical ground wire and shield wire; and professional services and overhead. Substation cost estimates are the sum of land and site work; equipment and foundations; protection and control; and professional services and overhead.
This year, MISO has added estimates for wooden poles as a structure type and for removing existing transmission lines.
But the cost estimates will be limited to traditional transmission construction components. The guide does not include estimates for HVDC lines and burgeoning technology such as energy storage-as-transmission, design engineer Alex Monn said.
“More specialized and customized project ideas are challenging to generalize for the purposes of a cost estimation guide. MISO will consider these project types on a per project basis,” the RTO said.
“From our research … those projects are really customized and site-specific, so you won’t find those in our cost estimate guide,” Monn said.
MISO could finalize and post the guide for MTEP 19 as early as the end of this week.
MISO is considering moving ahead with a plan to streamline its report detailing the projects in its annual Transmission Expansion Plan (MTEP) beginning with this year’s.
Project Manager Sandy Boegeman on Wednesday told MISO’s Planning Advisory Committee that the RTO is considering removing brief histories of previous MTEPs, some descriptions of regional studies, an introduction to the resource adequacy construct, and descriptions of MTEP futures development and independent load forecasting.
Last month, MISO said it planned to reconfigure the MTEP report to emphasize the justifications and analyses behind the list of proposed projects while condensing planning process narratives. The RTO aims to create a more concise and readable report, which typically runs about 200 pages and always includes descriptions of the studies and processes used to recommend projects. (See MISO Considering Slimmed-down MTEP Report.)
MISO hopes the new format will help guide the RTO’s Board of Directors in its deliberations over project approvals, Boegeman said.
Jesse Moser, MISO director of economic and policy planning, said the RTO is also examining the accessibility and usability of the planning section of its website to ensure that information removed from the report is easier to locate online. He said the web improvements could take a few years to complete.
“We’re trying to do this in a way that retains what’s important,” Moser said.
Veriquest Group’s Dave Harlan said that removing futures development information from the report may inadvertently weaken its rationale for some transmission projects.
“To just sort of poke around on the website … is a burden that’s going to frustrate everyone,” Harlan said. He asked MISO to create a “definitive” appendix of website links in the report supporting the necessity of the projects in the plan.
Moser said he and his team would consider the idea and asked for additional stakeholder feedback by May 3.
PAC Chair Cynthia Crane urged stakeholders to think about what pieces of the report are essential and which should be memorialized. The PAC is scheduled to vote on whether to recommend the MTEP 19 report at its Oct. 16 meeting.
In rejecting a request for a declaratory order on Tuesday, FERC provided the petitioners exactly what they were seeking: assurance that ISO-NE will not alter its energy efficiency performance standards outside the stakeholder process.
In February, Advanced Energy Economy (AEE) and the Sustainable FERC Project petitioned FERC to issue a declaratory order that would prevent ISO-NE from retroactively revising Forward Capacity Auction 13 qualification packages to include new measurement and verification (M&V) standards not previously applied to EE resources. They also asked FERC to clarify that the RTO must seek commission approval to make any such changes. (See Groups Seek to Head off ISO-NE EE Changes.)
In their initial filing, the groups said their petition arose from reports that ISO-NE staff had made a series of phone calls to Forward Capacity Market participants with qualified EE capacity resources. During those calls, staffers said the RTO intended to change how it measures the demand reduction value of EE resources for participation in the FCM.
Graph shows New England’s projected energy savings from energy efficiency projects. | ISO-NE
The petition alleged the changes could include new “net-to-gross” conversion factors to revalue EE resources, meaning the resources could only offer into the FCM their net energy savings, rather than their gross reduction to load from baseline federal standards. The petitioners noted the factors were “never previously required of, nor imposed on, market participants” nor defined or described in the RTO’s Tariff or manuals.
The groups contended ISO-NE staff indicated the RTO would potentially make the changes retroactively and without seeking commission or stakeholder approval, “even though the contemplated changes could significantly change the quantity of the resources that have already qualified for, and cleared, the most recent Forward Capacity Auction, FCA 13.”
The petition garnered widespread support, including from public interest organizations, the Massachusetts attorney general and Eversource, which asked that ISO-NE follow the New England Power Pool stakeholder process before making any changes.
FERC on Tuesday dismissed the petition as “premature,” citing ISO-NE’s own statements in response to the petition and its lack of action on the issue (EL19-43).
“We find that the harm alleged in the petition is speculative in light of ISO-NE’s clarification that it has not made any proposal, nor does it currently have any plans, to change its M&V standards,” the commission wrote. “Furthermore … because ISO-NE has not proposed a change to its M&V standards, there is not concrete proposal for the commission to evaluate to determine whether a Tariff filing is required. As such, there is no controversy or uncertainty necessitating a declaratory finding at this time.”
ISO-NE said it was all a misunderstanding.
“As the script used by an ISO staff member for calls to energy efficiency providers makes clear … the ISO was informing energy efficiency providers that it is in the process of evaluating the implication of potential changes in federal energy efficiency standards and new information regarding net-to-gross savings ratios,” the RTO said in its March 7 initial response to the petition. “The communications do not reflect that the ISO was proposing a practice change or intending to make one.”
The RTO said it was evaluating current M&V practices because expected changes in lighting efficiency standards under section 321 of the Energy Independence and Security Act of 2007 “could substantially affect the baseline against which the savings from efficient lighting programs are determined.”
It also cited “a growing disparity between gross savings and net savings values for energy efficiency resources” reflected in updated state studies on the performance of energy efficiency measures.
“These factors warrant evaluating current practices regarding the measurement of energy savings for energy efficiency resources to assess whether changes to the ISO’s measurement standards are appropriate,” ISO-NE said.
But it said any changes would require modifications to ISO-NE manuals or Tariff and would be done “only after any such changes are vetted through the stakeholder process and any Tariff changes are filed and accepted by the commission.”
The commission’s order included comments reassuring to the petitioners. “In particular, in its second answer [to the petition], ISO-NE committed that it would only implement a gross-to-net savings methodology for determining the capacity value of energy efficiency resources through a Section 205 filing.”
AEE said it was happy with the outcome.
“As the commission states in its order, ISO New England has committed that it will not make changes to the measurement and verification standards for energy efficiency resources without engaging stakeholders and making a filing with FERC,” Jeff Dennis, AEE managing director, said in a statement. “We appreciate this commitment by ISO-NE in its answer to our petition, and the commission’s recognition of it, which brings needed clarity and certainty for energy efficiency resource providers.”
The standard authorization request (SAR) was prepared by the Inverter-Based Resource Performance Task Force (IRPTF), based on disturbance analyses and the development of the PRC-024-2 Gaps Whitepaper. The IRPTF identified potential modifications to PRC-024-2 to “ensure inverter-based generator owners, operators, developers and equipment manufacturers understand the intent of the standard.” (See NERC to Try Again on Inverter Rules.)
One of the most significant changes is in Section 4.1.2., where NERC proposes expanding applicability to include transmission owners “that own a bulk electric system (BES) generator step-up (GSU) transformer or collector transformer.”
It also requires inverters not trip or “enter momentary cessation” — an interruption in their injection of current into the grid — within the “no trip zone,” except for “documented and communicated regulatory or equipment limitations.”
Slight Change to Standards Efficiency Review Retirements
The standard drafting team for Project 2018-03 Standard Efficiency Review Retirements informed the committee of a need for a minor tweak to existing rules.
Reliability standard INT-009-2.1 Requirement R1 references standard INT 010-2, which has been selected for retirement. The team will remove references to INT 010-2 from the remaining standard to avoid confusion.
The drafting team arose from NERC’s 2017 Standards Efficiency Review (SER) to consider the retirements of all or part of more than 30 reliability standards. (See “Team Gets Go Ahead on Standards Retirement Review” in NERC Standards Committee Briefs: Jan. 23, 2019.)
Standards Drafting Team Set for Response to FERC Order 851
The committee unanimously approved nine nominees for a standards drafting team to respond to the directives in FERC Order 851, which approved NERC’s revised geomagnetic disturbance standard.
NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events.
Order 851, approved in November, directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. (See Revised NERC GMD Standard Approved.)
The standard authorization request (SAR) was prepared by the Inverter-Based Resource Performance Task Force (IRPTF), based on disturbance analyses and the development of the PRC-024-2 Gaps Whitepaper. The IRPTF identified potential modifications to PRC-024-2 to “ensure inverter-based generator owners, operators, developers and equipment manufacturers understand the intent of the standard.” (See NERC to Try Again on Inverter Rules.)
One of the most significant changes is in Section 4.1.2., where NERC proposes expanding applicability to include transmission owners “that own a bulk electric system (BES) generator step-up (GSU) transformer or collector transformer.”
It also requires inverters not trip or “enter momentary cessation” — an interruption in their injection of current into the grid — within the “no trip zone,” except for “documented and communicated regulatory or equipment limitations.”
Slight Change to Standards Efficiency Review Retirements
The standard drafting team for Project 2018-03 Standard Efficiency Review Retirements informed the committee of a need for a minor tweak to existing rules.
Reliability standard INT-009-2.1 Requirement R1 references standard INT 010-2, which has been selected for retirement. The team will remove references to INT 010-2 from the remaining standard to avoid confusion.
The drafting team arose from NERC’s 2017 Standards Efficiency Review (SER) to consider the retirements of all or part of more than 30 reliability standards. (See “Team Gets Go Ahead on Standards Retirement Review” in NERC Standards Committee Briefs: Jan. 23, 2019.)
Standards Drafting Team Set for Response to FERC Order 851
The committee unanimously approved nine nominees for a standards drafting team to respond to the directives in FERC Order 851, which approved NERC’s revised geomagnetic disturbance standard.
NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events.
Order 851, approved in November, directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. (See Revised NERC GMD Standard Approved.)
RENSSELAER, N.Y. — A new NYISO study will examine the energy market and reliability implications of a grid being transformed faster by public policy than by market forces, stakeholders learned Monday.
“We are addressing the reliability, resilience and flexibility needs of the grid transitioning to a greener New York,” Nicole Bouchez, NYISO principal economist, told the Installed Capacity/Market Issues Working Group during an April 15 meeting that discussed the study’s outline.
New York state policies will add large volumes of zero variable-cost resources to the market, with 15,000 MW of new intermittent resources expected to lead to the retirement of 4,000 to 6,000 MW of conventional generation over the next decade, the outline said.
“We’re trying to figure out what has been done and what needs to be done, so we want stakeholder feedback,” Bouchez said.
The ISO will release the first draft of the study May 22 for discussion on May 30, ahead of the Board of Directors’ June meeting, followed by another draft at the end of August to help inform the board’s strategic planning meeting in September, she said.
NYISO thinks the market needs appropriate investment signals to attract, retain and operate new and existing resources while avoiding additional out-of-market compensation.
“The goal here is not to get ourselves into an RMR [reliability-must-run] world,” Bouchez said. “We will be looking at market revenue sufficiency; I think in many ways that’s the most ambitious part of this whole paper.”
Transitional Roles
David Clarke, director of wholesale market policy for Power Supply Long Island, asked about the transitional role of carbon pricing.
“There are ways carbon pricing can lead to short-term carbon savings,” Clarke said. “The big question is, ‘Can the state count on the market to achieve its goals?’ Is there a robust market structure that can reliably get you to 2040?”
Bouchez said the ISO sees the situation differently; the state is the one achieving its clean energy goals, with the wholesale market trying to accommodate the changes while remaining effective. (See NYISO Seeks to Refine Carbon Price Equation.)
Erin Hogan, representing the New York Department of State’s Utility Intervention Unit, asked the ISO to provide more precise definitions of the state’s goals. The study refers to a carbon-free grid by 2040, for example, when in fact the current announced target is a carbon-neutral grid, which is not the same thing, she said.
Raj Addepalli, representing the Alliance for Clean Energy New York, asked whether the ISO knows of anyone in the world with experience fully operating a system on resources with no variable costs and how markets can be structured in such a scenario.
Bouchez noted California has been thinking about the topic somewhat longer than New York but has not yet figured it out.
Miles Farmer of the Natural Resources Defense Council asked if the ISO has plans to address the inconsistency between its market mitigation rules and the state’s announced plan to pursue 100% emissions-free resources. He contended mitigating state-supported resources does not make sense with “a state-driven market entry model.”
“We will be looking at the mitigation rules and their compatibility with the desire of the state to have programs that value different attributes,” Bouchez said.
The ISO also announced April 23 as the date for a second presentation by Analysis Group on the outline of a new study to provide additional insights into pricing carbon into NYISO’s wholesale electricity markets. The firm’s Sue Tierney and Paul Hibbard will present initial analysis results May 14, and the ISO expects to post the final results by the end of May. (See Analysis Group Presents NYISO Carbon Pricing Study Plan.)
Fuel Security
NYISO also said Monday it will take a second look at assumptions being used in a separate study commissioned to assess winter fuel and energy security for the New York Control Area.
Hibbard presented additional details on the study, reviewing weather and natural gas market assumptions.
“The 17-day cold snap from last year is used in the new model, but it also includes three days from an older and more severe cold period,” he said.
Graph shows degree days and local distribution company natural gas demand for the 17-day modeling period to be used in the fuel security study. | NYISO
Based on review of local distribution company documents, Hibbard said essentially all pipeline export capacity from New York to New England is assumed to be under firm contract to deliver flowing gas or transport stored gas, with 889 MMcfd of natural gas available for electric generation after accounting for retail gas demand in New York, equivalent to roughly 5 GW of electricity generation under severe cold conditions.
Hogan asked what kind of validation process Analysis Group used “to make sure [it was] in the ballpark with results.”
“We’re trying to see where the risks are to the electric power system based on natural gas supply constraints, not the worst-case or best-case scenario,” Hibbard said.
Wes Yeomans, the ISO’s vice president of operations, said, “Remember, on the supply side, we’re going to have Indian Point out and no coal. … Things will be different in 2023 from what they were in earlier forecasts.”
One stakeholder mentioned the importance of considering the impact of energy storage on fuel demand, given the state’s programs to help finance development of 800 MW of new energy storage resources. (See NYPSC Expands Storage, Energy Efficiency Programs.)
Weather assumptions for the fuel security study will now include data from a previous 3-day severe cold snap. | NYISO
“We likely will not change base assumptions in the initial scenario but will address storage and various other stakeholder concerns in the scenarios and as part of the findings of the analysis,” Hibbard said.
Analysis Group currently expects to present initial findings of the energy security study in May, additional findings in June and final results in July.
FERC handed PJM a mixed ruling Monday on a set of proposed Tariff and Operating Agreement revisions intended to equalize the cost recovery treatment of gas-fired plants with that of other thermal generators.
The commission approved the Tariff changes, agreeing PJM’s existing rules “unduly discriminate” against combined cycle and combustion turbine generators by preventing them from recovering inspection costs as a “maintenance adder” in their energy prices.
Those types of variable costs are considered related specifically to electricity production and should be recoverable in the energy market, the commission said (ER19–210). Many nuclear and fossil generators currently factor these expenses into their avoidable-cost rates in the capacity market.
In approving the Tariff changes, FERC rejected the PJM Independent Market Monitor’s argument that major maintenance costs incurred as a result of electricity production should be recovered in the capacity market because they are not short-run marginal costs. The PJM Load Coalition likewise insisted variable operations and maintenance costs belonged in capacity market offers only.
The commission also dismissed concerns that the changes risked double recovery by generators in both the energy and capacity markets.
FERC agreed with PJM that its existing rules for maintenance cost recovery discriminates against CC and CT generators | Panda Power Funds
“We accept PJM’s Tariff revisions to clarify that all resource types are prohibited from recovering variable maintenance costs that are directly attributable to the production of electricity in their avoidable-cost rate in the capacity market,” the commission wrote.
But FERC found related changes in PJM’s Operating Agreement to be “unjust and unreasonable” because “the definitions of maintenance adders and operating costs fail to provide sufficient clarity with respect to permissible cost components of cost-based energy market offers.”
The commission directed PJM to submit a compliance filing clarifying what maintenance costs sellers can include in their energy market offers. The revised OA must do the following:
Create a single, properly defined operating cost component.
Remove “incremental fuel costs” and “other incremental operating costs” from the list of permissible components in a cost-based offer.
Add a definition for “opportunity costs” and create a new section detailing this component.
Create a new section for the “application of cost components to three-part cost-based offers.”
Move definitions for “maintenance adders” and “operating costs” to a new opportunity costs section.
Expand the list of maintenance costs to include cooling towers, fuel and water pumps, emissions-reduction catalyst equipment, and replacement of filters and cartridges.
Add sections to memorialize PJM’s process of calculating major maintenance costs based on 10- or 20-year histories.
Revise the section related to the review of maintenance adders and operating costs to require market sellers to specify the maintenance history years on which their maintenance adders are based.
The Monitor had pushed for the required clarifications.
FERC on Monday also accepted PJM’s quadrennial revision of its variable resource requirement curve used in the Reliability Pricing Model, effective Jan. 17 (ER19-105).
NEW YORK — U.S. grid operators may have to consider a different way of transmission planning for offshore wind, panelists told the Business Network for Offshore Wind’s 2019 International Partnering Forum last week.
Speakers said interconnections to the land-based grid should be shared “social” resources and that queue positions shouldn’t be a deciding factor in states’ OSW solicitations.
Christer af Geijerstam, president of Equinor Wind US, said locating offshore cables is not a concern. “But if you are targeting substations that are 20 miles inland, how many times do you want to go dig up that same road for future projects? Should we pre-invest in capacity?”
Sven Utermöhlen, board member for E.ON Climate & Renewables, agreed that a long time horizon is essential to OSW transmission planning.
“If you think about 15 to 20 individual projects in the next decade or so to be constructed, you may find that there is only a handful of really suitable, sensible grid connection points … you better have a plan in place because you don’t want to dig up the same onshore connection route five times over the next 15 years.”
Repeated construction could undermine public support and complicate permitting, he said. “So, you better start thinking about a real network development plan.”
Clarke Bruno, lead partner for Anbaric Development Partners, said New York will have to expand its onshore grid to move its planned 9,000 MW of offshore wind from delivery points on Long Island and in New York City.
“Long Island [is] about a 2,400-MW load. Taking half of that 9,000 MW and trying to drop 4,500 MW into a 2,400-MW system is going to be a challenge. The same is true in New York City [with] a much larger average load of 6,400 [MW].
“There are very few interconnection points in Long Island and New York that have the degree of robustness that you would like to have. And … getting from offshore to those interconnection points, you have very few good routes, given the congestion on Long Island and the wetlands and, in New York City, the bottleneck of the Verrazano Narrows. So, with those challenges in mind, it strikes me that a planned transmission system is essential.”
The state must “plan and permit the offshore wind so that we are able to … seize the optimal interconnection points and allow equal access to all developers to those very scarce social resources.”
Gil Quiniones, CEO of the New York Power Authority, agreed with Bruno’s description of the challenges.
“Long Island, especially on the East End … we [say] ‘the wires are thinner.’ And New York City is very dense and [does not have] a lot of very easily accessible connection points. … Logic tells you that there is maybe an opportunity to have a collector system … and bring it to the optimal interconnection point. It does require planning. It requires all the regulatory bodies — state and federal — to be aligned in making that happen.”
State officials and grid operators have only begun to consider the transmission challenges of offshore wind.
The New York State Energy Research and Development Authority’s OSW Master Plan, published in January 2018, said an expandable “backbone” transmission system would offer economies of scale and reduced barriers to entry but could also lead to overbuilding and stranded asset costs. A transmission system custom-built for a single offshore facility — the “direct radial” model — would be less efficient and is limited in scope, the report said. (See NY Offshore Wind Plan Faces Tx Challenge.)
Proposed offshore wind projects in Connecticut (1,760 MW), Rhode Island (1,056 MW) and Massachusetts (6,064 MW) represent almost half of the 18,600 MW in ISO-NE’s transmission queue, Alan McBride, the RTO’s director of transmission and strategy services, told the IPF conference in a presentation.
PJM Begins Talks on OSW Tx Rules
In February, PJM’s Planning Committee approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind. (See “PC Moves Forward on Offshore Interconnection Rights,” PC/TEAC Briefs: Feb. 7, 2019.)
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore.
Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.
The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses.
The first meeting of the initiative, on April 16, will consist of education about the RTO’s current process. Three months of exploration into alternative options are planned before members will return to the PC in August to consider endorsement of proposed changes.
