NEW BRITAIN, Conn. — Utility representatives and other stakeholders shared their views on evolving cost drivers, changing customer demand and new technologies at the Connecticut Public Utilities Regulatory Authority’s first-ever technical conference on grid modernization on Tuesday (17-12-03).
“We need to have technologies in place that understand how the system is operating in real time, with power coming from any direction on the system,” said Chuck Eves, director of engineering and strategic planning at Avangrid subsidiary United Illuminating (UIL).
Eversource Energy filed comments ahead of the conference calling for “foundational investments in sensing and monitoring communications, analytics, automation and control solutions.”
Jennifer Schilling, Eversource’s director of grid modernization, said her company breaks down its investments “into peak load, new customer growth, reliability and ageing infrastructure, and basic business, which includes capital repairs.”
The new opportunities arising from the growth in distributed energy resources are “adding a new dimension in our planning process,” which is why the company supported the timing of the technical conference, Schilling said.
“The nature of the changes in demand and the forecasting will be important in terms of thinking about what do we need to do differently to be able to say, ‘OK, if I have these categories of investment, how are they likely to change in the future?’” Schilling said.
Using Data
Connecticut Green Bank Associate Director Anthony Clark said his organization’s current investments are following and helping to boost customer demand, “but they are not following grid demand much at all. We just don’t have that insight.”
Clark thanked PURA, the state’s Department of Energy and Environmental Protection and UIL for helping the Green Bank start “really digging into this process on the grid side” through clean energy pilot programs.
“In much of the discussion here we’ve talked about the challenge of having solar PV or other resources where there isn’t sufficient data or resolution into the resource or ability to control it,” Clark said. “The technologies themselves are becoming smarter, so we’re looking at deploying smart inverters that will actually sense grid conditions and respond to them.”
Christian Bilcheck, vice president for smart grids innovation at Avangrid, said it’s important to think of DER in the aggregate, not as individual elements.
The utility is not necessarily going to have the answers to a lot of questions in the early days, he said.
“I can picture a data request coming in and it will look like we’re not sharing information, but we don’t have DER adoption modeling forecasts for circuits and substations right now,” Bilcheck said.
“It gets complicated, but I think if we keep approaching it from a practical perspective, we’ll get there,” he said. “Not just the data needs, but I think the goal of the data is to help inform the types of investments that we should be looking forward to, how DERs can play a role in that frame and even help shape policy.”
Lauren Savidge, DEEP director of energy supply, said the agency is learning from what other states are doing with DER, citing a recent Michigan Public Service Commission solar program report “that was pretty thorough on compensation for solar, how different customers in their territory use solar.”
Cost and Sustainability
PURA Chair Katie Dykes said, “The cost-effectiveness testing will help us learn a lot about — particularly from the utilities’ perspective — what the grid currently can do and where the limitations are.”
Eves said it’s important to consider the long-term sustainability of solutions “as we evaluate the lifecycle costs of the choices we make, to sustain those into the future, five, 10, 20, 40 years down the road.”
In its comments, the Acadia Center said that any calculation of cost-effectiveness should be aligned with the state’s consumer, energy and environmental goals.
“Cost-benefit frameworks should be designed or expanded to fully reflect priorities such as reducing energy bills and reducing consumers’ energy burden, addressing climate change, enhancing consumer control and choice, and systemwide efficiency,” Acadia said.
PURA Commissioner Michael Caron returned the conversation to what Connecticut can learn from other jurisdictions.
“In California and Hawaii, they are blazing the trail ahead of us from the perspective of penetration and how they’re dealing with those issues, so there’s a lot to learn from what’s occurred in those states … learning from their mistakes as well as from their successes,” Eves said.
PURA is seeking written follow-up comments on the technical conference by April 10 and will later this month issue a final notice of scope of procedure for its exploration into the issues of grid modernization. The agency plans to begin discovery in the coming months and form working groups by this summer before soliciting reports from them in the fall.
FERC said yesterday that a preliminary investigation indicates that Public Service Enterprise Group committed multiple violations of PJM market-bidding rules and made “false and misleading statements” to RTO staff, stemming from issues PSEG says it self-reported in 2014 and has since set aside $35 million to address.
The Notice of Alleged Violations charged PSEG Energy Resources & Trade, which markets the output of PSEG Power’s generation fleet, with violating both PJM’s Tariff and FERC regulations. PSEG’s trading arm submitted incorrect cost-based bids into PJM’s daily energy market from as early as 2005 through 2014 and lied to PJM regarding costs associated with certain units, commission staff alleged.
The notice also said the determinations were preliminary and provided few additional details about the confidential investigation. It did not indicate when or whether any definitive action would be taken against PSEG.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
PSEG Power reported in May 2014 through PSEG’s first-quarter financial results that it had “discovered that it incorrectly calculated certain components of its cost-based bids for certain generating units in the PJM energy market, with resulting over-collection of revenues related to its fossil fleet.” It said the issue had been reported to FERC, PJM and PJM’s Independent Market Monitor, Monitoring Analytics, and recorded a $25 million charge to its income to account for potential financial repercussions.
In PSEG’s 2014 second-quarter results, PSEG Power announced that a subsequent internal investigation performed by outside counsel found “additional pricing errors in the cost-based bids” and “that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amounts for which Power was compensated in the capacity market for those units.”
The company said it corrected the errors and revised processes “to ensure that the pricing errors identified in the calculations of the bids and differences in quantities offered into the energy market from those in the capacity market have been corrected” and “to help mitigate the risk of similar issues occurring in the future.” It said it doesn’t have access to PJM data “to determine if the differences in quantity had any impact, and if so, the level of that impact.”
FERC in September 2014 opened its investigation into PSEG’s fossil-fuel fleet in New Jersey, which includes the 1,229-MW Bergen combined cycle gas turbine, 1,566-MW Linden CCGT, 81-MW Essex simple cycle gas combustion turbine, 168-MW Burlington CT and the Sewaren facility, which was a 445-MW gas-fired plant at the time but was damaged during Hurricane Sandy in 2012 and is being rebuilt as a 540-MW CCGT. It also includes the 456-MW Kearny CT, but that unit wasn’t brought online until 2012.
In its 2017 10K report filed with the Securities and Exchange Commission, PSEG said it “believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties.” It has accounted for the low end of that estimate “since no point within this range is more likely than any other.”
“Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial,” PSEG said in the filing. “Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement.”
In an email to RTO Insider, PSEG spokesman Michael Jennings confirmed the company has set aside $35 million over the issue, adding that “we are not discussing the particulars.” Representatives for PJM and Monitoring Analytics confirmed that they could not discuss details of the investigation.
PSEG says its trading arm, based at its corporate headquarters in Newark, N.J., is “among the nation’s first and most successful energy trading organizations.” In addition to marketing PSEG Power’s output, it acquires and hedges fuel and power, dispatches plants, manages gas supply and trades energy-related products.
Generation developers and transmission providers on Wednesday called for more direction from FERC to improve coordination of “affected system” studies in the generation interconnection process.
Suggested improvements on the second day of a FERC technical conference included sharing study models earlier, clear timelines and cost estimates, and better definitions for identifying an affected system — one impacted by new generation in a neighboring region (EL18-26, AD18-8). (See related story, Renewable Gens Face Off with RTOs at Seams Tech Conference.)
Day 2 focused largely on the commission’s generator interconnection Notice of Proposed Rulemaking (RM17-8). The NOPR noted that because affected systems are not bound by the practices of the system processing an interconnection request, its process and schedule may differ from the host.
“The challenge with California is that we are like Swiss cheese, with no requirement that all the utilities had to join the CAISO,” said Deborah Le Vine, CAISO director of infrastructure contracts and management. “We have a total of, believe it or not, [19 potentially] affected systems, and out of [them], two are [FERC] jurisdictional.”
Seeking a FERC Fix
“We’d love for you to tell us a fix, because all the ideas we’ve come up with haven’t worked so far,” Le Vine said. “The challenge has been trying to put together any type of reciprocity agreement. That’s why we don’t have the ‘teeth’ to mandate compliance.”
Brian Fritz, director of transmission development at PacifiCorp, said that since the inception of the company’s interconnection queue, it has received more than 1,000 requests for interconnection totaling over 90 GW. “I heard the term ‘Swiss cheese,’ but ours is Swiss cheese on steroids,” Fritz said. “We’re interconnected with many, many different utilities because we have such a large footprint across the west.”
Lisa Szot, head of transmission and interconnection for Enel Green Power North America, bemoaned the lack of a standardized process for affected-system studies. “It would be nice to have something that forces the affected systems to have to complete a study within the time frame of associated areas to meet the timelines of the interconnection process,” she said.
Scott Seier, vice president of private equity firm and generation investor Tenaska Capital Management, said he preferred FERC direction to lengthy RTO stakeholder processes.
“FERC leadership is vital and necessary to ensure problems plaguing processes are addressed to ensure the efficient processing of the interconnection queue and foster competitive and robust markets for electricity,” Seier said. “Looking at the narrow issue of affected-system study coordination, fixes include limited scope of studies in the early stages, increased RTO study resources and allowing interconnection customers to fund affected-system or other interconnection study work to ensure interconnection agreements can be achieved by a certain date.”
Cost Allocation
Commission staffer Tony Dobbins asked MISO Director of Resource Utilization Vikram Godbole if the RTO calculated cost responsibility on a case-by-case basis, “or has it been pretty much a standardized process or document that may have a couple of variations for each entity?”
Godbole said that MISO’s documentation could be improved to provide more detail to customers at the front end of the process.
“We need to keep in mind how far RTOs have come from a coordination perspective,” Godbole said. Older tariff versions lacked any coordination process, he said.
“About the geography of the upgrades, it doesn’t matter whether it’s 600 miles away or a thousand miles away, it comes down to electric impact that has to be mitigated,” Godbole said. “Upgrades will be identified, and somebody’s going to have to pay those. … We have to keep going with our process, the way we’re doing, look for more feedback from stakeholders. And any guidance FERC wants to provide would be helpful.”
EDF Renewable Energy Project Engineer Anton Ptak said the industry needed tariff provisions to detail how costs are allocated and how models are established between affected systems and host transmission providers.
Rock Falls Wind | EDF Renewable Energy
“One thing we’d like to see is specific tariff requirements on affected systems to perform their affected-system studies and provide results when required under the host transmission provider,” Ptak said. “We’ve experienced several delays with affected systems providing their results to MISO in the recent past, and so we’d really like to see some specific language improving the provision of the affected-system study results.”
Szot agreed that cost estimates need to be provided early in the process.
“The affected systems need to provide base case models so an interconnection customer can try to assess potential costs,” Szot said. “For an interconnection customer, the costs that can occur from an affected system could make the project no longer viable. This is a huge commercial risk to developers.”
Small Utility Perspective
James McFall, manager of electric resources for the Modesto Irrigation District in the Central Valley of Northern California, gave the perspective of a smaller — 560 square miles and 114,000 customers — utility. MID is not a member of CAISO but is an affected system of other systems that are connected to the ISO. As such, it has no ability to control dispatch on generators connected to the host system to manage reliability events, McFall said.
The utility must spend significant staff time and resources on affected-system studies, he said. The utility mitigates costs by waiting until certain milestones are met to maximize potential that projects that are studied will be developed.
“Any cost impacts caused by generators interconnecting to third-party systems are borne by MID’s ratepayers if MID is unable to recoup or avoid the costs created by those interconnections,” he said.
McFall said MID is not in favor of standards for affected-system coordination, and he asked FERC to “consider collateral impacts on smaller entities such as ourselves” if it considers standards.
Interconnection-wide Models?
Tradewind Energy Transmission Manager Aaron Vander Vorst said that the industry has been left to navigate its way through affected-system studies because of the “unscripted process” of Order 2003, including managing departures from the pro forma interconnection procedures.
He proposed a concept of “One Model, One Queue, One Schedule,” including jointly developed interconnection-wide transmission models to improve accuracy and efficiency between systems.
Affected systems should be able to do studies on their own queues and neighboring queues simultaneously to encourage cross-seam coordination, he said. And he said the study schedule should be aligned between neighboring providers to ensure developers have the information they need to make informed milestone decisions.
“Taken to the extreme, use of identical dispatches across seams would largely eliminate the need for affected-system studies,” he said.
“The existing rules, procedures and coordination procedures are simply not adequate for the environment that we have found ourselves in today,” he said, “but change is difficult.” The industry needs clear directives from FERC, he said.
First Solar Development Interconnection Manager Madeleine Aldridge, whose company developed about one-third of utility-scale solar serving California, said CAISO has improved its processes by notifying affected systems at an earlier stage. But, she said, “more needs to be done to incent the host transmission owners to take on the coordination that will provide interconnecting generators certainty and best siting incentives relative to existing transmission.”
Texas Solar Project | Tradewind Energy
Aldridge said her the company has waited for as long as two years for affected-system studies. Under current rules, “we are not really sure when we will get the studies report,” she said.
“The concept of coordinated regional planning has not yet touched the generator interconnection process in an efficient manner,” she said. “The Bulk Electric System is really one grid, except for a few exceptions, and really cannot, and should not, be planned for in discreet sections. With well-planned generation, interconnection study processes, regional coordination that includes utilities outside the boundary of the host transmission owner, can increase least-cost solutions, versus disjointed expensive transmission upgrades.”
But Jay Caspary, director of research development and tariff studies for SPP, said an interconnection-wide transmission planning and interconnection process is impractical in the Eastern Interconnection.
“Our [generator interconnection] models — all the models we use for tariff services whether its transmission service or generator interconnections — are based upon our [integrated transmission plan] model,” he said. “I can’t imagine us trying to do that in one effort. Those are big efforts individually by themselves.”
FERC on Monday rejected EDF Renewable Energy’s request that MISO be required to devise a special fast-track option in its interconnection queue for projects that can demonstrate readiness for development.
EDF filed the complaint early this year, asking FERC for a “workable” interconnection timeline to ensure that wind developers can secure federal production tax credits before they expire at the end of 2020. (See Renewables Developer Escalates MISO Queue Design Dispute.)
| AES
The company said MISO’s year-old, three-phase interconnection queue process is only worsening the backlog of waiting generators and sought a one-time “fast track definitive planning phase mechanism” for generators with at least 80% of site control secured and 10-year power purchase agreements for at least 50% of their capacity.
EDF argued that the RTO is now in a “position far from what it justified using the three-phase process for the 2016 and 2017 definitive planning phase cycles.”
In its April 2 order, FERC said study delays in the interconnection queue are not reason enough for the commission to order MISO to create an accelerated queue option (EL18-55).
“We find that the delays experienced by interconnection customers do not make the existing queue process … unjust and unreasonable,” FERC said.
The commission reminded EDF that the RTO only has to make “reasonable efforts to meet its interconnection queue deadlines” and said that there are factors outside of the RTO’s control affecting the queue.
“EDF has not shown that MISO is performing other than in accord with what the Tariff requires. While we understand that MISO’s revised queue process is intended to minimize delays, interconnection customers are not guaranteed that MISO will meet its projected deadlines,” FERC said.
E.ON Climate and Renewables North America had filed in support of EDF’s complaint and said delays in the RTO’s generator interconnection study process is leaving some developers in “serious jeopardy” over whether they would receive tax credits.
However, FERC agreed with MidAmerican Energy’s contention that wind developers could use the RTO’s provisional generator interconnection agreement to achieve commercial operation before the PTC expires.
Further, MISO has pledged that most transition plan interconnection customers will be eligible for generator interconnection agreements in time to qualify for the tax credit, FERC said.
“We are not persuaded that the existing queue process will result in the commercial harms claimed by EDF,” the commission said.
FERC also agreed with MISO’s argument that EDF had not demonstrated that any part of the current generator interconnection process was unreasonable or discriminatory. But it rejected the RTO’s argument that EDF’s proposed remedy and complaint would undermine the stakeholder process used to design the new queue.
No Ringing Endorsement
However, FERC made clear that its denial of EDF’s complaint was not a show of support for MISO’s current queue design.
“While we find that MISO’s performance of interconnection studies and its [generator interconnection process] have not been shown to be unjust and unreasonable, the repeated and significant delays experienced by interconnection customers in MISO are nevertheless a cause of great concern, as they have resulted in considerable uncertainty for interconnection customers in MISO’s queue,” the commission said. “We understand that the achievement of a [generator interconnection agreement] in a timely and reasonably predictable manner is vital to the development of all new generation in MISO and that MISO’s ongoing queue processing delays are a significant problem for generation developers.”
FERC also noted that while the RTO “is somewhat unique in terms of the sheer volume of interconnection requests it receives,” it is not aware of any other RTO plagued with similar delays. It noted the technical conference it held this week focusing on affected systems-related interconnection issues hampering the construction of renewable projects. (See related stories, Renewable Gens Face Off with RTOs at Seams Tech Conference and Developers, Tx Providers Seek FERC Direction on ‘Affected Systems’.)
FERC urged MISO to consider improvements to its queue, telling it should look to other RTOs for best practices and examine whether additional resources would alleviate queue delays.
Idaho Power and Powerex began transacting in the Western Energy Imbalance Market (EIM) on Wednesday, bringing to eight the number of members participating in CAISO’s regional real-time market.
The expansion equips the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO. It and the market’s seven other members serve more than 42 million customers in an area stretching from the U.S.-Canada border south to Arizona, and from the West Coast east to Wyoming.
| CAISO
“The Western Energy Imbalance Market continues to demonstrate that coordination of energy over a large area can lower costs for electric customers and reduce the cost of the transition to a more renewable-based grid,” CAISO CEO Steve Berberich said in a statement. The market has yielded more than $288 million in benefits for its members since being launched in November 2014.
Idaho Power
Boise-based Idaho Power serves about 542,000 customers across a 24,000-square-mile territory in southern Idaho and eastern Oregon. The core of the utility’s generating portfolio is 17 low-cost hydroelectric projects that serve most of its demand. The company also operates about 4,800 miles of transmission.
“We believe customers will see benefits from the EIM over time, and we expect those benefits to increase as more utilities join the market,” Idaho Power Vice President of Power Supply Tess Park said in a statement.
The utility’s service territory is adjacent to the balancing areas of EIM members NV Energy and PacifiCorp-East (PACE), providing increased transfer capability with the wind-rich area of western Wyoming in the remote northeastern corner of PACE.
Although wind developers see the region as a promising source of exports, transmission constraints — and California’s restrictions on renewable imports not delivered directly into an in-state balancing area — have impeded development of large-scale projects to serve the state. Idaho’s entry into the EIM could open the door for development, expanding renewable portfolio standard eligibility for a larger pool of resources.
Participation in the EIM will also allow Idaho Power to more easily unload the output of excess wind power the utility has been required to contract for under the 1978 Public Utility Regulatory Policies Act. In 2010 — before tightening PURPA eligibility rules — the Idaho PUC received applications for 500 MW of such projects. The minimum system load for Idaho Power, the state’s largest utility, is about 1,100 MW. The utility is still contending with wind developers moving projects across the state line to its service territory in Oregon, where PURPA avoided-cost rates are higher. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)
“Covering a broad territory with a wide variety of resources will help Idaho Power manage our operations and integrate the growing volume of renewable energy sources on our system,” Park said.
Powerex
Vancouver-based Powerex, which markets the surplus generation of parent BC Hydro, becomes the first non-U.S. member of the EIM. (See Power Slated to Become First Non-US EIM Member.) While the company does not directly bring any generation assets into the market, its access to BC Hydro’s ample hydroelectric resources positions the company to provide EIM participants with the flexible ramping capacity needed to firm up the growing number of variable renewable resources coming into the region’s grid.
The company also holds transmission rights on lines throughout the West, including the California-Oregon Intertie, a key transfer point between the Pacific Northwest and California. Constraints on that line periodically isolate the PacifiCorp West and Puget Sound Energy balancing authority areas from the rest of the EIM, resulting in prices that diverge from the rest of the market.
Powerex has actively participated in CAISO’s five-minute market since 2005 through a dynamic scheduling arrangement, but its membership in the EIM will allow it to engage in sub-hourly transactions across multiple balancing authority areas. The ISO worked with Powerex to develop an EIM participation framework addressing the company’s unique situation as a Canadian entity, which FERC approved last year. (See FERC Approves Powerex EIM Agreement.)
Also slated to join the EIM are the Sacramento Municipal Utility District in April 2019 and Salt River Project, Seattle City Light and the Los Angeles Department of Water and Power in April 2020.
CAISO last year proposed to extend its day-ahead market across the EIM, a move that would fall short of creating a full RTO and require members to relinquish control of their transmission assets. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
ISO-NE is moving to keep the 1,998-MW Mystic Generating Station running to ensure grid reliability following Exelon’s March 29 filing with the RTO to retire the plant in 2022.
Chief Operating Officer Vamsi Chadalavada on Tuesday sent a memo to the New England Power Pool Participants Committee outlining the grid operator’s “limited” options ahead of a planned discussion of the issue at the committee’s April 6 meeting.
Mystic Generating Station
Exelon last week said it “may reconsider” the decision to retire Mystic if the grid operator can reform its markets to properly value the plant’s contributions to reliability and regional fuel security. (See Mystic Closure Notice Leaves Room for Reversal.) The Everett, Mass., facility includes a 576-MW dual-fuel unit (Unit 7); two gas-fired units capable of producing a combined 1,414 MW (Units 8 and 9); and Mystic Jet, an 8.6-MW oil-fired peaker.
On the same day it issued the retirement notice, the company also announced it will purchase the Everett Marine (Distrigas) Terminal — an LNG import facility — from ENGIE North America “to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.”
Distrigas Terminal | ENGIE
“Since the ISO received Exelon’s retirement bids, it has been analyzing the potential impacts of losing the Mystic and Distrigas facilities from a fuel security perspective,” Chadalavada said in the memo.
He highlighted the reliability impacts identified in the RTO’s recent Operational Fuel Security Analysis and the limited time to address the issue. (See Report: Fuel Security Key Risk for New England Grid.)
The RTO will ask FERC to waive its Tariff requirements to allow it to retain Mystic 8 and 9 to maintain fuel security on the system, he said.
ISO-NE CEO Gordon van Welie said in February that that the RTO might need to seek such authority for resources required for regional fuel security. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
In addition to discussion at the April 6 NEPOOL Participants Committee meeting, ISO-NE will meet with its stakeholders to explain its reliability analysis of the retirement bids immediately following the RTO’s April 10 Markets Committee meeting, Chadalavada said.
“We plan to commence discussions with stakeholders, beginning at the April 25 Reliability Committee meeting, on the necessary reliability criteria for retaining resources needed for fuel security in the Forward Capacity Market,” he said.
Citing reliability issues focused on transmission security, the RTO rejected the dynamic delist bids for Mystic Units 7 and 8 in Forward Capacity Auction 12, which covers 2021/22.
Oil supplies at plants in New England declined rapidly during a cold snap earlier this winter as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments.
The Distrigas Terminal — which the RTO said is the only fuel supply source available to Mystic units 8 and 9 — is the oldest such LNG facility in the U.S. and has connections with two interstate pipeline systems, the Tennessee and Algonquin pipelines, as well as with the local distribution system owned by National Grid.
By Amanda Durish Cook, Tom Kleckner and Rich Heidorn Jr.
WASHINGTON — Renewable developers and transmission planners for MISO, SPP, and PJM sparred Tuesday over the effectiveness and fairness of “affected system” studies, with RTO staff urging FERC to leave study improvements up to stakeholders and developers asking the commission to order identical requirements for grid operators.
The disagreement came during the first day of FERC’s two-day technical conference, ordered in response to EDF Renewable Energy’s October complaint that the three RTOs do not have clearly defined processes to determine cost responsibility for network upgrades on an affected system stemming from an interconnection request made in a host RTO. EDF contends inconsistencies and a lack of clarity in the RTOs’ rules for affected systems interferes with developers’ ability to judge the commercial viability of proposed projects (EL18-26, AD18-8). (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
Both MISO and SPP planners called attention to their expanding interconnection queues in opening remarks, saying they are coordinating affected system studies while managing record volumes in planned generation.
MISO’s queue has grown to more than 95 GW this year, approximately 80% of MISO’s existing load, said Vikram Godbole, MISO director of interconnection planning.
“Coordination of such a large chunk of projects takes time. It’s challenging,” Godbole said. ” … The affected system was not a big problem back [in 2005], but … when you’re dealing with 95,000 megawatts in one queue, coordinating four subregions and different cycles with other RTOs, it takes time.” MISO divides its interconnection entrants into the Central, East, South, and West subregions.
SPP Manager of Generation Interconnections Steve Purdy said his RTO’s interconnection queue has ballooned 600% in the past four years to 70 GW, an amount exceeding SPP’s 55-GW predicted summer peak in 2021.
Even with expanding queues, Purdy insisted SPP and MISO are improving coordination of affected system studies. Purdy said SPP’s allocations of costs resulting from projects in neighboring regions “are appropriate and consistent with allocation of costs for generation interconnection in SPP.”
What Role for Stakeholder Process?
PJM Senior Engineer Edmund Franks said PJM already has a “fairly detailed set of procedures” to address network upgrades on the seam. He added that MISO and PJM already work together to coordinate affected system studies and said that any improvements should be “decided and agreed upon in the context of the stakeholder process.”
Franks noted PJM’s interconnection process is linked with its annual Regional Transmission Expansion Plan (RTEP). If FERC prescribes changes to affected system studies, “that would cause a divergence in how we evaluate our system from a baseline perspective [for RTEP] compared to how we evaluate interconnection customers. We feel they should be evaluated with the same test and criteria,” Franks said.
Godbole said the RTOs should be given “flexibility and latitude” to set their own regional planning processes, including cost allocation rules, which are “embedded” in planning.
New World ‘Churn’
However, the two renewable developers on the panel said RTOs have already been granted that flexibility, and the result is a confusing and unreliable process.
“It’s unrealistic to think that the stakeholder process is going to come up with a fair procedure to study affected systems when they have the opportunity to shift costs to their neighbor,” said Kris Zadlo, Invenergy senior vice president.
Zadlo said he didn’t doubt RTOs are currently applying their methodology correctly: “I think the debate here is: Is the current methodology that they are using still appropriate in today’s day and age? That’s what needs to get revisited.”
“I feel for these guys. They have large queues, but this sort of churn is a product of the new world,” Zadlo said, referring to newer low-cost generation technologies. ” … The days [when] you build something and forget about it for 50 years are gone. … You’ve got to man up. You’ve got to staff up accordingly.”
SPP’s Purdy said more staff is not the answer. “We’ve run into some very real physical constraints in SPP,” he said. “We’ve got, in fact, more generation requests than we have load.”
“We don’t enter the queue on a whim, and it’s not been easy lately,” said Kate O’Hair, vice president of EDF Renewable Energy’s north region. O’Hair said EDF has been surprised by increasing affected system cost assignments and a seeming lack of explicit rules about how RTOs determine impact cost. She urged the commission to require each RTO to detail the standards used in their Tariffs and joint operating agreements.
Zadlo said the cost associated with identified network upgrades has “spiraled out of control.”
“Addressing affected systems has transformed into an unnecessarily complicated and time-consuming process,” Zadlo said, claiming that remote projects are being forced to pay affected system costs. Zadlo pointed to Invenergy’s Deuel Harvest Wind Farm in South Dakota, which he said ended up responsible for affected system costs “on the PJM system, 800 miles away in Michigan.”
“Codifying the processes that exist today will not solve the problem. FERC needs to provide definitive guidance on what standards the ISOs need to apply [and] bind limitations to studies. RTOs can’t perform a region-wide RTO analysis. It needs to be simple, realistic, and focused on the boundaries,” Zadlo said.
Today, network upgrades are solving “chronic seams issues,” Zadlo said. “Why should generators be forced to solve these seams issues between the ISOs?” He added that he has seen network upgrades resulting from affected system studies appear months later in RTOs’ transmission expansion plans.
“If it’s ‘but for’ the generator, why is it appearing in a transmission expansion plan six months later? I think what you’re seeing here are upgrades that are really needed and folks trying to find a way to pay for these upgrades,” Zadlo said.
“The RTOs will not work it out. There needs to be clear direction by FERC as to what needs to be applied … in these affected system studies. We’re at this juncture, in this situation, because the RTOs have been trying to work this out,” Zadlo said.
‘Misunderstood Process’
“There’s no mechanism to ensure costs are shared between appropriate customers and RTOs,” O’Hair said. She said EDF had a project in the February 2015 definitive planning phase of MISO’s queue with an executed interconnection agreement that “came back with tens of millions in upgrades that had not shown up in previous studies” after PJM completed an affected system study. Eventually, O’Hair said, the costs were reassigned to another generator that dropped out of MISO’s queue.
“It’s a perfect example of how it’s a misunderstood process,” O’Hair said.
What’s the Right Model?
Zadlo said he didn’t understand why 15 years after FERC Order 2003, it’s still a struggle to get all RTOs to align their base cases and said different study methodologies produce different answers: “All of these RTOs are very proud of their study methodologies, and we’ve been in situations where we are mediators because one RTO is saying one thing, [and] the other RTO is saying another thing. Who is right?”
“You have no way to challenge the impacted system study,” Zadlo added. He suggested only projects “truly on the seams” should be evaluated for impacts on neighboring RTOs, saying it’s “kind of inconceivable” that every project requesting interconnection in one RTO is going to impact potentially the reliability of an adjacent RTO.
MISO, PJM, and SPP representatives said not all incoming project requests are evaluated for impacts on other RTOs.
“We’re not going to analyze a project in New Jersey or Delaware for impacts in Indiana,” Godbole said.
When FERC staffer Kathleen Ratcliff questioned whether the RTOs have any written rules specifying when affected system impacts should be evaluated, RTO staff agreed that pursuing a study is based on “engineering judgment.”
Zadlo suggested using more targeted generation dispatch assumptions, relying on a sub-region rather than a footprint-wide dispatch assumption.
Godbole said MISO’s dispatch assumptions have been developed over years. “We can’t create a special model just for affected systems and try to merge that with the overall planning models,” he said.
Cooper South Constraint
FERC staff steered discussion toward a $311-million network upgrade to SPP’s Cooper South constraint identified in MISO’s February 2016 queue study group, asking MISO to explain its reasoning in assigning the upgrade cost to generators.
Godbole said, in that case, MISO relied on affected system study results from SPP that indicated a need for the upgrade.
“MISO is not an expert on SPP transmission or SPP process, so we depend on the expertise of the transmission [operator]. So, when they identify network upgrades required to mitigate constraints on their system due to MISO interconnection projects, we take that information, include that in the reports, and then we have a follow-up call with interconnection customers,” Godbole said. He said although some MISO interconnection customers have said MISO should take on more of the study responsibility of the affected system, “at the end of the day, SPP really is the regional operator for that transmission [and] in the best position to provide MISO with the most accurate analysis.”
15-Day Deadline
O’Hair said the $311 million upgrade is still “not well understood.” She also complained that interconnection customers have only 15 days to review the results of affected system studies and decide whether to continue with a planned project.
“If we’re coordinating, this doesn’t feel coordinated,” O’Hair said.
Zadlo said a new line on the Cooper South constraint will solve chronic congestion issues in SPP.
“So, is it fair and just to just fully allocate the cost of that line to the generators when there is going to be congestion relief to SPP customers?” Zadlo asked. He added that interconnection customers assigned the cost of the Cooper South upgrade all changed their network resource interconnection service requests to an energy resource interconnection service designation to avoid paying the costs of the new line.
Purdy pointed out that SPP’s interconnection studies focus on reliability, not economics or congestion.
Ratcliff asked if impacted system studies frequently shift upgrade costs to interconnection customers. RTO staff said how dramatically cost allocation shifts is entirely situational.
Delays
During the afternoon session, O’Hair complained that study delays have impeded the ability of interconnection customers to assess their projects’ commercial viability. EDF’s complaint noted that MISO produced its February 2016 West cluster phase I system impact study after 250 days, despite a Tariff requirement to do so in 120 days. It said MISO was at least six months behind schedule in processing the cluster, causing delays to cascade through to successive clusters.
“It’s difficult to manage, and extraordinary amounts of risk and capital are tied up wondering when studies will be delivered,” O’Hair said. “It’s feasible and doable to coordinate timely affected system studies; it’s simply a matter of the commission finding the current process is no longer just and reasonable and ordering the RTOs to hash out the details.”
Jennifer Ayers-Brasher, director of transmission and market analysis for German developer E.ON, echoed O’Hair’s complaint: “To my knowledge, [the RTOs] have no detailed procedures governing scope and timing for affected systems processing, and any provisions are vague and outdated. The lack of transparency contrasts with clear commission-approved procedures that each RTO has to process interconnection requests in their own footprint.”
Chad Craven, manager of transmission for Tradewind Energy and a former MISO staffer, called for a “more cohesive process” through improved coordination of the study process.
“I don’t think it’s a secret to anyone here, or [anyone] who follows this issue, that every RTO has its own process and timelines. Even if they have the same basic time frame, they may start and stop at different points in time,” Craven said. … So, the essential ask here is for the commission to come up with a ruling, preferably not even a recommendation, but some sort of mandate to better align these processes.”
PJM’s Aaron Berner said many study delays come from customers withdrawing or reducing the size of their projects, “which has a ripple effect.”
FERC staff asked the RTO representatives whether it was feasible to use a consistent base-case model across their regions. Berner said while the RTOs do have consistent base-case models that are coordinated at different times, “changes must continue to occur.”
“Those changes have to be just passed through to our affected systems, neighbors, and updated in models as is necessary,” he said.
“If we do not maintain that link, if we change that interconnection customer model to be something that is some type of dispatch consistent across the entire Eastern Interconnection but disregards differences in the markets … I’m not sure I would understand how we could have a consistent set of assumptions,” Berner said.
Judah Rose, chair of ICF’s energy advisory practice, called for six changes that could be made “right away,” starting with an adequate description of the base case being used by the host or affected system.
Rose also called for clear standards, the prompt availability of models, a comparison of the studies’ inputs and outputs, documentation of missing data and causes of delays, and a clear description of the RTOs’ responsibilities and requirements to ensure adequate staffing and other resources.
“These are things that can be done immediately and without prejudice to more complicated issues that may need to take longer to achieve,” Rose said.
Given a chance to comment before the afternoon session concluded, Tradewind Vice President of Transmission Derek Sunderman said he had written down at least nine variables that differ among the RTOs. Multiply those nine variables across the three entities, and the number of permutations and outcomes is astronomical, he said.
“The only way to make a complex problem less complex is [to] remove some variables,” he said. “The best way is for FERC to actually provide some orders on a lot of these issues. Over time, each RTO has developed its construct for reliability procedures, under their own stakeholder silo. What we need are orders that fix what variables mean because, right now, you have everybody making a different interpretation what the variable means.”
Second Day
The second day of the conference Wednesday will focus on broader affected systems issues raised in the generator interconnection NOPR (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
A California Senate committee on Tuesday approved a bill that would allow publicly owned utilities (POUs) that meet certain criteria to run their gas-fired plants at a minimal level to ensure related bond debt is paid off and not passed to taxpayers.
Bill sponsor Steven Bradford (D) said that SB 1110 “protects individual customers of a public utility from extraordinary cost shifts” stemming from POUs’ outstanding debt for natural gas plants built in response to the Western Energy Crisis of 2000/01. Supported by the Northern California Power Agency, the bill was passed unanimously by the Energy, Utility and Communications committee and now goes to the Appropriations Committee for consideration.
Under existing law, POUs are subject to California’s ambitious renewable portfolio standard (RPS) that requires them to meet 50% of their electricity needs with renewable generation by 2030 (escalating from 33% by 2020, 40% by 2024, and 45% by 2027). But unlike the state’s investor-owned utilities, POUs are authorized to adopt measures allowing for delay of timely compliance and set cost limitations for procuring renewables.
SB 1110 would expand those exceptions by allowing a POU to amend its renewable procurement plan to mitigate against the loss of public revenues if complying with the RPS would lead to decreased output from a power plant with outstanding public debt. The proposed rule change, which would not apply to peaker plants, applies only to plants planned and built after Jan. 1, 2000, with financing secured before 2017. To be eligible, a plant must be expected to operate below a 20% capacity factor for an upcoming year based on the POU’s forecast, risking employment of a power plant employee who receives a prevailing wage.
The legislation does not apply to independently owned gas plants that are not financed by taxpayers.
POUs would notify the California Energy Commission by Jan. 31, 2019, that they might have power plants eligible for the provision. The measure is most likely to affect Silicon Valley Power’s Donald Von Raesfeld Plant, Roseville Electric’s Roseville Energy Park, and Redding Electric’s Redding gas plant units 5 and 6, according to a bill analysis.
The Assembly Utilities and Energy Committee is due to consider several energy bills Wednesday. A major piece of energy legislation, AB 813, which would regionalize CAISO, is not on the agenda. (See CAISO Presses Law makers on RTO Conversion.)
NEW ORLEANS — While MISO’s various sectors last week voiced differences in their views of what constitutes grid resilience, they could agree on one thing: Its specific attributes are still difficult to pin down.
Resilience was in the spotlight after MISO stakeholders selected the subject as their quarterly “hot topic” industry discussion held before the RTO’s Board of Directors on March 28.
Meeting participants offered a mixed bag of suggestions.
Minnesota Public Utilities Commissioner Matt Schuerger agreed with FERC’s definition of resilience as the “ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
But Schuerger said he sees a lot of overlap between reliability and resilience, making the latter largely covered by NERC’s portfolio of standards.
Otter Tail Power’s Stacie Hebert said some of MISO’s transmission-owning members viewed resilience more narrowly as the ability of the system to recover from a failed state.
MISO’s Environmental sector is concerned about double-counting resilience as resource adequacy and reliability, said sector representative John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project. He argued instead that there are degrees between “fragile reliability” and “resilient reliability.”
“So much of what MISO already does in planning relates to resilience indirectly or directly,” Moore said.
Coal- and oil-fired generators became comparatively economic during early January’s cold snap because they had not been regularly run until emergency conditions nudged them “higher in the dispatch stack,” he said. “They were the most expensive resources in the system until we needed all resources.”
North Dakota Public Service Commissioner Julie Fedorchak said states may have to increasingly turn to MISO’s markets to fulfill generation requirements as uneconomic units retire.
Alliant Energy’s Mitchell Myhre said his Transmission-Dependent Utilities sector was trying to avoid being “too prescriptive” in defining resilience, a concept he called “hard to define.”
Still, others saw a clearer distinction between resilience and reliability.
“My kids will never know what it’s like to sit around with candles playing war games during a thunderstorm because the power is out. That just doesn’t happen anymore. That’s reliability,” Wisconsin Public Service Commissioner Mike Huebsch said. Resilience goes further than that, entailing better communication between grid operators, utilities and customers when disruptions occur, he said.
MISO Already Managing Resilience
Multiple members said MISO already has processes in place to tackle resilience.
“We think MISO is resilient. It’s always been part of our base business, even if we didn’t call it resilience,” said MISO Vice President of System Planning Jennifer Curran.
In response to FERC’s call for RTO/ISO comments on resilience in early March, MISO reported no “imminent or immediate” concerns in its footprint and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” (See “MISO: Work Already in Progress,” RTO Resilience Filings Seek Time, More Gas Coordination.)
“The resilience issue is broader than the transmission grid, and we all have a role to play in ensuring resilience,” Curran told stakeholders.
Director Baljit Dail asked sectors what the RTO should do incrementally beyond what it already does.
“It seems to me that the bulk of the resilience issue is not at the MISO-level, but the distribution level, and that’s not MISO’s purview, but all of you sitting around this table,” he told members.
Moore said MISO could expand cybersecurity measures, with which Dail agreed.
Kevin Murray, representing the Coalition of Midwest Transmission Customers and MISO’s End-User Customers sector, pointed out that much of the RTO’s cybersecurity efforts can only be discussed in closed-session meetings to avoid release of sensitive information.
“I think one of the things that will be a challenge for us is sharing as much of that information as we can,” board Chair Michael Curran agreed.
Director Todd Raba said it seems the distinctions between transmission and distribution systems are becoming increasingly blurred. He rhetorically asked if MISO and its members have to reorganize the metrics placed on each system.
Schueguer said it will be a state-by-state choice to develop mandates to “harden” the distribution system.
‘Accidental’ Resilience
Independent Power Producers sector leader Barry Trayers said he thought MISO is heading toward resilience “almost accidentally” with increased distributed energy resources and a more diverse fuel mix.
“This movement towards DER should bolster the system because there’s less risk of a single large contingency,” said Director Thomas Rainwater.
The difference between the electrical recoveries from Hurricane Harvey in Texas and Hurricane Maria in Puerto Rico last year should help MISO and stakeholders define resilience attributes, Rainwater said. He pointed out that parts of Puerto Rico still don’t have power six months after the storm.
Murray pointed out that during hurricanes last year in Florida, bucket trucks and lineman were already queuing up before they hit, readying restoration efforts.
Director Mark Johnson said MISO and its members will at some point have to identify a list of the likely low-probability, high-impact events that could occur in the 15 states in its footprint, as well as the Canadian province of Manitoba.
“The actions that need to be taken will be very much event-specific,” Johnson said.
“There comes a point where maybe we put pen to paper or steel to ground,” agreed Advisory Committee Chair Audrey Penner.
Studying Weather Events
End-Use Customers sector representative and Louisiana Public Service Commission counsel Katherine King said a better understanding of resilience will require MISO to conduct an in-depth investigation into its South region’s two most recent maximum generation events: one last April after heavy outages and high temperatures, and another in mid-January triggered by extreme cold. (See “Several Factors in Spring MISO South Maximum Generation Event,” Louisiana Regulators Question MISO South Max Gen Event.)
“I think it’s very important to go back in after these events occur and ask what caused them and what we can do better,” King said.
The Louisiana PSC is opening a docket and scheduling a technical conference to investigate the January maximum generation event, King added.
Mississippi Public Service Commissioner Brandon Presley said the RTO should also study contingency impacts on the 3,000-MW contract path connecting MISO Midwest and South.
“Everybody has an interest in that connection and woe be it on us if we ignore that,” Presley said.
Rainwater said any changes made in the name of resilience must be cost-effective.
“At the end of the day, the end-use customers will have to pay for whatever resiliency measures we deem necessary, and we have to keep that in mind. We cannot build the system to protect it from … interruptions of any kind,” Rainwater said.
NEW ORLEANS — A seasonal post-mortem at MISO’s Board Week provided stakeholders with insight into the RTO’s market performance during the near past, near future — and beyond.
MISO and its Independent Market Monitor agreed that markets generally performed well during a challenging winter, and the RTO predicts more operational efficiency throughout spring. But it foresees considerable market changes over the next decade.
The RTO said the sustained cold snap that opened the year was “managed nearly routinely by MISO and members.”
Executive Director of Strategy Shawn McFarlane said the RTO’s $31/MWh December-February average energy price was about 10% higher than last winter.
MISO’s winter peak of 106.1 GW, set on Jan. 17, was 3.2 GW lower than its all-time winter peak set in January 2014. Loads exceeded 100 GW for the first five days of 2018, with forced and planned outages reaching 36 GW. (See MISO Breaks down Recent Cold Snap.)
“While it wasn’t routine, it was handled quite routinely — not a lot of excitement,” McFarlane said during a March 27 meeting of the Markets Committee of the Board of Directors.
MISO committed one unnecessary unit on Jan. 1, an inefficient outcome in what was an otherwise more efficient performance when compared to 2014’s polar vortex weather event.
However, the RTO said a brief mid-January cold spell concentrated in MISO South “proved more challenging, but reliability maintained.” During his quarterly report, Monitor David Patton agreed that mid-January generation patterns “were more fascinating.”
In that instance, another round of arctic air pushed loads above 106 GW over Jan. 17-18, and MISO South set a new winter peak of 32.1 GW in the face of record low temperatures in the region. (See Louisiana Regulators Question MISO South Max Gen Event.) MISO was forced to call a maximum generation event in the South region Jan. 17 after outages there hit 17 GW.
McFarlane said MISO South’s icy weather froze the region’s water and air lines, which are not nearly as insulated as in MISO Midwest. The RTO compensated for South’s shortfall with generation from Midwest, at one point flowing just over 3,000 MW — the maximum allowed by the MISO-SPP agreement — along the contract path between the regions.
“The [South] generators just aren’t as prepared for freezing temperatures,” Patton said. “Part of the reason we were in such bad shape is because the forced outages kept growing and growing. … This is about the most stressful situation I can imagine for MISO South.”
Patton said if the RTO had not made emergency power purchases for the South on Jan. 17, regional supply would have dipped below load for about three to four hours. He referred to the “lights going out in MISO South.”
But Director Michael Curran immediately rebuked Patton’s use of such dramatic language, while also responding that MISO should “burn down” SPP’s transmission on the contract path before it allows MISO South to shed load.
Patton said the situation highlights the need to create a regional capacity reserve product that can be delivered within 30 minutes, a recommendation he repeated from last year’s State of the Market report. He also said MISO’s emergency prices are still too low because its extended locational marginal pricing (ELMP) does not properly account for regional dispatch transfer flows. Accounting for such flows in ELMP would be an easy fix, he added.
Spring
Executive Director of System Operations Renuka Chatterjee reiterated a previous report of MISO’s spring preparedness but noted that volatile spring weather can “break load patterns.”
MISO staff said earlier in March that the RTO faces a small possibility of spring emergency conditions if either loads or forced outages are higher than normal. (See Outages Small Risk for MISO Spring Operations.)
Director Thomas Rainwater asked if the outage risk comes from large, thermal units whose loss “MISO has to scramble to replace.”
“Yes, it’s obviously the 1,000-MW units,” Chatterjee replied.
She said as little as an additional 2 GW in forced outages over forecasted load could force the RTO to call upon reserves this spring.
“We’ve seen a chance in the last couple of years of tight operating conditions in the shoulder seasons,” Chatterjee said. “[Reserves] are the end of our stack, and we’ll get into those if we have to.”
However, Chatterjee reassured the board that MISO faces a very slim chance of spring load shedding.
Patton said he now recommends that some generators take planned outages during winter rather than spring to lessen the impacts of mass outages in shoulder periods.
Beyond
With winter and spring covered, a MISO executive outlined a rough to-do list to design a market for a future grid that includes renewables, storage and smart devices.
Richard Doying, now head of future market design, delivered to the board the first report of his exploratory-style role. (See “MISO Shuffles Leadership,” MISO Informational Forum Briefs: Jan. 23, 2018.)
“MISO will be operating transmission with very different assets in the future,” he said.
Doying and MISO staff are evaluating what changes are needed to incorporate renewables, distributed energy supply and storage, and digital flow control devices such as smart appliances and thermostats. The RTO will complete an analysis of market, operational and planning impacts, and prepare a report by the first quarter of 2019, he said.
“Software cycle time really drives digitalization. When you think about an app on your phone that you can install today that wasn’t available yesterday — that took just a few weeks for someone to develop,” Doying said.
Digitalization will affect the grid much more than owners and operators may realize. “Although we can’t see when the changes will arrive, we know that they are coming,” he said. “Waiting until they arrive is a problem and will be imprudent.”
MISO must address, for instance, windy nights when LMPs fall to negative values, a situation that becomes unworkable for non-wind generators serving load. He also said the RTO’s market team will investigate how to properly value essential reliability services.
Director Baljit Dail asked what the RTO’s version of California’s “duck curve” may look like.
Doying responded that MISO is investigating a “double up” of its renewable sources in the next 10 to 15 years, as indicated by new entrants to the queue, but he didn’t elaborate on specific demand curve shapes.
“This is an exciting, but scary, pallet of issues,” said Director Barbara Krumsiek.
Rainwater asked how MISO will begin to value other attributes in a system designed around cost-based ratemaking.
Doying did not get into specifics, but he said that “pricing will be a critical element of any reforms.”
