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 CAISO Day-ahead Could be Tailored for the West.) That effort could face competition from a joint plan by Peak Reliability and PJM Connext to create a new Western market not dominated by California. Peak and PJM last week said they’ve entered the “commitment phase” of their initiative, consisting of confidential discussions of the market plan with potential members. (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.)
FERC last week moved to investigate PJM’s regulation market, rejecting the RTO’s most recent proposal for compensating the systemwide service (ER18-87) and ordering a technical conference on larger concerns identified by stakeholders (EL17-64).
The commission denied PJM’s most recent proposal, filed in October, for the same reasons it had on previous attempts, which date back to the RTO’s efforts to comply with Order 755. The technical conference comes in response to complaints filed in that docket by the Energy Storage Association, Renewable Energy Systems Americas (RESA) and Invenergy Storage Development. They argue that operational changes PJM has made in relation to its filing have had significant negative impacts on battery storage and are “a symptom of the broader problem that the RTO misuses regulation resources to reduce generation on its system for sustained periods of time.”
PJM’s updated regulation rules changed requirements from on- and off-peak to on- and off-ramp | PJM
FERC granted a portion of the complaints but deferred any action until after the conference and set a refund effective date of April 14, 2017.
Regulation Issues
PJM maintains two regulation signals: RegA dispatches slower, sustained-output resources such as steam and combustion resources, while RegD dispatches faster, dynamic resources, such as battery storage. The RTO uses a “benefits factor” curve to reflect the operational relationship between the signals and establish the tradeoff between their capabilities so that the market’s clearing engine can accurately compare their expected performance.
In its original filing on Order 755, PJM had proposed using the benefits factor instead of a unit’s actual “mileage” — the amount of regulation work a unit provides — in determining its payment, but FERC rejected that in November 2012 because the order required accounting for a unit’s mileage. PJM’s January 2013 compliance filing eliminated use of the benefits factor but warned it would create an “unsustainable market structure.”
PJM returned to the issue, arguing that its prediction came true and FERC’s requirements resulted in over-procurement of RegD and incorrectly signaled for additional entry into the market, which exacerbated the problem. The requirement to unconditionally respect RegD resources’ power balance also worked against overall system balance at times, the RTO said.
PJM’s new regulation signal has helped improve its area control error (ACE) control | PJM
The RTO redesigned its regulation signals to work together to manage area control error (ACE) and revised the RegD signal to be neutral over 30 minutes rather than 15, it told the commission. It filed for approval of a four-part plan that would substitute the mileage ratio for a new “regulation rate of technical substitution curve” and adjust calculations for performance scoring, settlements and lost opportunity costs. (See PJM Regulation Compensation Changes Cleared over Opposition.)
Decision
Stakeholders were mixed in their comments to FERC, with several noting the plan was vetted through the stakeholder process and others calling it discriminatory. The commission disagreed with PJM’s contention that the proposal meets its requirements because the market clearing process accounts for the “dollar per mile” cost of RegD resources. It also rejected PJM’s argument that accounting for mileage in the settlement equation double-counts it.
In its December order to RTOs on fast-start resources, FERC noted PJM’s dispatch process doesn’t respect the “power balance constraint” and thus “unnecessarily increases the cost of serving load and puts stress on the frequency regulation resources that are necessary for maintaining system reliability.” (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
FERC last week granted approval for Linden VFT to contract potentially all of its transmission capacity through long-term “anchor customers” rather than its current recurring auction process (ER18-730).
Linden owns a merchant transmission line and three 105-MW variable-frequency transformers between the Public Service Electric and Gas system in New Jersey and Consolidated Edison on Staten Island, which began operation under PJM’s control in 2009. The company has rights to 330 MW of firm point-to-point transmission service from within PJM, 315 MW of export capability from NYISO and 315 MW of delivery into either PJM or NYISO.
Linden VFT’s exterior | Joseph Jingoli & Son
Linden has held five “open season” auctions, through which it receives all of its revenue, since 2007. It told FERC there has been a “declining number and diversity of participants and qualified bidders, resulting in shorter-term contracts” and signaling reduced interest in its transmission scheduling rights.
PSEG Energy Resources & Trade will hold all those scheduling rights as of June, but Linden told the commission it has been approached by new customers seeking “longer-term, more tailored arrangements” and that “the ability to subscribe up to all of [its] transmission capability through such longer-term arrangements with anchor customers will allow it to explore more sustainable, alternative business models and allocate its transmission scheduling rights to the market participants who value them the most.”
FERC approved Linden’s request to amend its existing authorization so it can contract for service and negotiate rates, payment arrangements and agreement lengths and sell any remaining capacity at market-based rates through open solicitations. The company committed to filing a report within 30 days of a solicitation detailing its open-access characteristics, which allowed the proposal to pass the commission’s four-part analysis. Because it had changed its policies on reviewing negotiated-rate proposals since Linden’s project was originally approved, FERC decided to conduct a de novo analysis.
In December, Linden and Hudson Transmission Partners — another owner of merchant transmission between northern New Jersey and New York City — were approved to convert their lines from firm to non-firm service and avoid being saddled with hundreds of millions of dollars in cost allocations under PJM’s Regional Transmission Expansion Plan. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
VALLEY FORGE, Pa. — After nearly two years of intractability, FERC’s order last month on supplemental transmission projects — and PJM’s subsequent compliance filing — have reshuffled the deck in the RTO’s Transmission Replacement Process Senior Task Force (TRPSTF).
The order and filing require transmission owners to change how they plan and represent supplemental projects but also give them greater control over defining that process. They forced stakeholders at last week’s TRPSTF meeting — the first since submitting the compliance filing — to reconsider how they approach topics that have remained largely unchanged since the task force was proposed in January 2016.
PJM’s Steve Herling reviewed the process changes proposed in the filing, which delineate a structure for stakeholder engagement on supplementals and define deadlines for input. Developed internally by TOs through their “local” transmission plans, supplementals are not driven by PJM criteria. They’re included with baseline and market efficiency projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval. All stakeholders are supposed to have opportunities to provide “meaningful” input on them, and FERC’s order determined that TO procedures weren’t allowing that. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
Is Anything Ever Final?
Herling said projects tend to be submitted in “bunches” near the beginning and end of the year.
“I don’t know that PJM would be able to second-guess the timing of those decisions,” he said when asked to explain the reason for the bunches. He said the focus is to “get the solutions accepted, lock them down and move on so we don’t have surprises in the RTEP process.”
The deadlines in the compliance filing drew criticism from American Municipal Power’s Ed Tatum, who said they might not provide enough time to fully vet projects and receive answers. He asked when local plans are finalized so that stakeholders can comment on them in their entirety.
“The only way I can answer that is to refer to the RTEP. The RTEP is never finalized,” Herling said. “I don’t know what it means for the RTEP to be finalized, so I would suggest that I also don’t know what it means for the local plan to be finalized. … I don’t have a problem with putting a flag in the ground and saying, ‘We’re done.’ … I don’t know what the significance is from a planning perspective because every year we finish an RTEP, we start another one.”
Mark Ringhausen with Old Dominion Electric Cooperative said it seems like “there really isn’t a local plan; there’s just approval of supplemental projects.”
Resolving the Task Force’s Work
The TRPSTF went on a 10-month hiatus in response to FERC’s show-cause order on the issue, and TOs remained reticent to engage even after the task force resumed meeting late last year at the urging of load-side interests, citing the lack of FERC direction. The order and compliance filing clear the way for resolving the task force’s assignments, but how that’s accomplished remains to be seen. PJM is hoping the details contained in the order and filing can be accepted by everyone and set aside from debate on the remaining components, but AMP isn’t convinced.
“All we’re suggesting is we leave the parts that were filed on the table assuming they’ll be approved,” Herling said.
Tatum suggested having stakeholders propose solution packages and voting on them at an upcoming meeting as is common in other task forces.
“We have been doing nothing for 16 months. … We’re still getting ready to try to see if anyone is willing to have a discussion with us,” he said. “We’ve got to finish this group. We’ve got to stop meeting like this.”
Exelon’s Gary Guy questioned an all-inclusive approach.
“We’re not debating the pros and cons of a commission-issued order,” he said. “Once the commission has issued an order, we don’t have anything to debate.”
While the order undoubtedly has an impact on the task force, the question remains how much. The order is specific to TOs’ implementation of Order 890 regarding supplementals, but the TRPSTF is charged with addressing the processes for determining and replacing infrastructure that has reached the end of its usable life. The task force’s problem statement, issue charge and charter make no mention of Order 890. PJM’s Fran Barrett, the TRPSTF administrator, said he will research any potential overlap.
Stakeholders have proposed components that they believe are necessary for any solution, and Barrett asked if PJM staff could analyze them to pull out the parts that have been addressed by the order and filing.
“Could we clean up the past without throwing it away?” he asked.
TOs didn’t object to the plan, which would have PJM present an interpretation of what is explicitly addressed by the FERC order, but PPL’s Frank “Chip” Richardson pointed out that TOs remain in litigation on some of the TRPSTF’s topics and are unable to negotiate on them. Tatum and AMP’s Lisa McAlister said they want to maintain the right to go through their proposal and make their own modification interpretations. They didn’t see any benefit to PJM’s interpretation.
“We’re pretty good with what’s in the order and the compliance filing,” McAlister said. “I’m not sure it’s that helpful.”
Guy said he would object to any proposed alternatives to what’s in the commission order and said PJM should rule them out of the bounds of the discussion.
“That would be running amok here in complete disregard of what just took place at the commission,” he said.
“Discussion is one thing,” said Ruth Ann Price, who represents the Delaware Division of the Public Advocate. “Implementation is another. … I’m not sure you have any ability to stop us, the rest of the stakeholder body, going forward.”
“Just because we put it out there, doesn’t mean there’s an affirmation on this,” Barrett explained.
He attempted to point to improvements that have been made to the process since the task force began, but Tatum wasn’t convinced.
“We are not encouraged by the changes that have been made. We see some progress, but we also see a lot of pullback,” he said. “There are certain things that PJM doesn’t think about regarding end-of-life projects … so we’re going to seek to have those things addressed, as we already have. … There’s a lot of things we need to work on. We’re very serious about it.”
Barrett said subregional RTEP meetings have evolved in response to the task force’s work.
“They’re not the same calls they used to be,” he said.
The TRPSTF’s next meeting is scheduled for April 30. Tatum said he hoped that proposed solution packages could be finalized and ready to be voted on by then.
