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.)
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.
Peak Reliability and PJM Connext have entered the “commitment phase” for their proposed Western energy market, refining their pitch to convince potential participants to finally embrace an organized market for the region.
The organizations on Friday issued a three-page abstract of their new business plan to potential members and has also set up a public comments page on a partnership for what could possibly lead to a Western RTO, an effort that has previously been stymied by difficulties in developing a governance process acceptable to all the states involved.
“It is envisaged that these services will expand over time, evolving towards a full RTO offering. Whether and when this occurs will be a matter for the market’s participants to determine,” the abstract says. The full business plan remains confidential and will require interested parties to enter nondisclosure agreements.
In response to the proposed market plan, CAISO has filed to depart Peak as its reliability coordinator (RC) and developed a rival plan to offer RC services across the West to Peak’s existing customers. (See Multiple Entities, Markets Now Beckon in West.)
Peak said it continues to receive notices from utilities intending to withdraw from its reliability services but is not making public the number that have filed. The organization has noted that market participants are highly likely to receive RC services and market services from the same source.
An outline of the Peak Reliability/PJM Connext reliability and market services offering | Peak Reliability, PJM Connext
“I can say we have not received notices from all of our funding parties,” Peak spokeswoman Rachel Sherrard told RTO Insider. “I would note that, with the exception of one entity, all notices received so far are revocable.” The non-revocable notice is from CAISO, which will leave Peak on Sept. 2, according to organization documents.
The Peak/PJM commitment phase will consist of confidential meetings with interested parties “to review more details on the plan’s assumptions, market size scenarios, expected transactional cost ranges, projected aggregate efficiency savings and proposed services within the business plan,” the organizations said.
They envision the market will initially roll out with a day-ahead and real-time market using LMP and forward transmission rights for hedging. A full RTO would then be developed at the behest of market participants. (See Peak Touts ‘Independent’ Western Market Plan.) Existing RC services would be offered as well as balancing authority services, transmission operation, real-time grid monitoring and control, and interregional congestion management. A NERC-certified RC is needed to comply with the reliability organization’s standards.
Peak has highlighted its knowledge of the Western grid as an RC, while PJM brings its experience in market design and operation. (See PJM Chief Confident on Western Market Proposal.) The real-time market would include spot energy, synchronous and nonsynchronous reserves, and frequency regulation. The day-ahead offering would include a virtual energy market, while the FTR offering would allow a forward hedge price differential between nodal and aggregate locational pairs.
Peak says its funding level will remain flat through 2019. It has scheduled an April 11 conference call on its market initiative.
CAISO says it will “shadow” Peak RC services and then launch its own RC offering by spring of 2019.
Unilever, which sells Breyers ice cream, Dove soap and hundreds of other consumer products, plans to eliminate coal from its energy mix by 2020. It hopes to become “carbon positive” by 2030, by supporting the generation of more renewable energy than it consumes.
Thus far, the company has used onsite solar and power purchase agreements for Texas wind power. But the company has been frustrated in its inability to do more. “If we’re buying wind in Texas and trying to get it to my plant in Virginia, in Tennessee, in Missouri … right now we’re just not able to do that,” Stefani Millie Grant, the company’s senior manager for external affairs and sustainability, said last week.
“If we’re going to actually get [renewables] … actually running our facilities, instead of just being out there buying the [renewable energy credits], we’ve got to really focus on transmission.”
| David Gardiner and Associates for the Wind Energy Foundation
Even as President Trump has moved to undo the Obama administration’s climate initiatives, large corporate energy buyers such as Unilever have accelerated their commitments to purchase carbon-free electricity. But their efforts may be frustrated because of insufficient transmission to move Midwest wind power to load centers, according to a study released by the Wind Energy Foundation. The study was the subject of a webinar last week by Americans for a Clean Energy Grid (ACEG), a coalition whose members include the Natural Resources Defense Council, WIRES, ITC Holdings and American Electric Power.
15 States Hold Most Onshore Wind
The study concluded that transmission expansions currently planned will likely be insufficient to support large corporate energy buyers’ renewable energy goals because most of the solar and wind power potential is in 15 Midwestern states, far from load centers. The 15 states hold 88% of the country’s wind technical potential and 56% of its utility-scale solar photovoltaic potential, but they are home to only 30% of projected 2050 electricity demand.
15 Midwestern states have 88% of the U.S.’s total onshore wind potential and 56% of its utility-scale solar PV potential. But they are far from load centers and will consume only 30% of projected electricity sales in 2050. | David Gardiner and Associates for the Wind Energy Foundation
This is based on the Renewable Energy Buyers Alliance (REBA) goal of obtaining 60 GW of new renewables by 2025 and the 52 GW of new transmission capacity planned in 14 near-term projects in advanced development in MISO, SPP, PJM and NYISO (see table).
In three of the four scenarios studied, transmission would be insufficient to meet corporate renewable demand. With 9 GW of renewables procured by corporate purchasers since 2013, about 51 GW remain to meet the goal. If RTOs build 90% of the capacity in the 14 projects, only 70% of the corporate demand would be filled, the study said. If corporate procurements fall short at only 20 GW, the transmission projects would meet the corporate needs, the study said.
| David Gardiner and Associates for the Wind Energy Foundation
According to the study, one of the biggest obstacles to bringing more renewable energy online is “the absence of transmission planning across RTOs and other regional planning authorities.”
Not Counting All the Benefits
“I think that current [transmission] planning process doesn’t do an adequate job of really counting up all of the benefits, and then it doesn’t think about it … in a … broader geographic scale,” said David Gardiner, president of David Gardiner and Associates, which conducted the study for the foundation.
“We’ve built the interstate highway system in this country not because the highway system went from point A to point B, and the people along point A and point B paid for it, but because we recognized that it provides national benefits, and therefore everybody contributed nationally. We need to be thinking about how we assess the benefits and think about how we want to pay for things more along those lines than we currently are.”
The study recommends that corporate and institutional energy buyers participate in regional and interregional transmission planning and urges FERC and RTOs to improve interregional planning under Order 1000. It said RTOs should incorporate voluntary, large customer demand in transmission planning.
“While we highlight a few examples in the report of companies like Stefani’s that have engaged in some of the planning for transmission lines, it’s been limited, and we’re going to need to step up the kinds of engagement in the transmission planning process as we go forward,” Gardiner said.
Gardiner’s study found that while transmission planners “in rare instances” account for voluntary goals, such as statements by governors, they do not account for growing voluntary demand from large corporate purchasers. “Instead, RTOs typically only focus on mandatory renewable energy requirements prescribed by [renewable portfolio standards].
“If a governor issues a voluntary goal to develop 1 GW of renewable energy in the state, some RTOs would typically include assumptions to meet that 1-GW target in transmission planning models. Although the goal may not be a mandate … other RTOs do only what FERC requires, which is to ‘consider’ public policy and may ultimately opt not to include state RPSs or other policies in their plans.”
RTOs Respond
Officials of MISO, PJM and SPP told RTO Insider last week they are adding transmission for renewables as best they can under FERC transmission planning and cost allocation rules.
“Lack of transmission expansion to facilitate renewable deliveries across regions is not due to inadequate transmission planning between the regions,” said SPP Vice President of Engineering Lanny Nickell in a statement. “Rather, the lack of expansion primarily derives from the difficulty in achieving agreement among multiple groups of customers as to who receives the benefits and, thus, who should pay for transmission upgrades.”
Nickell noted that SPP and other RTOs consider varying amounts of renewable transfers between regions in their interregional transmission planning studies. “RTOs have largely addressed this issue within their regions due to FERC-approved cost allocation mechanisms for service contained in their areas. However, customers in other regions are sometimes challenged to deliver renewable energy from regions like SPP’s because they are unwilling to bear the costs of required infrastructure upgrades or because it is difficult to find other customers willing to share the costs of those upgrades that they don’t believe benefits them,” he said.
“We believe our transmission planning process does adequately address large customers’ increased demand for renewable energy,” said Eli Massey, MISO’s senior adviser for policy studies, in a statement. “MISO’s top-down transmission planning examines regional economics, and its bottom-up planning examines local load growth and reliability issues in order to optimize the transmission system. MISO’s transmission planning process already facilitates the study’s recommendation that large customers engage in the transmission planning process through the industry sector mechanism of the Planning Advisory Committee.”
PJM spokesman Ray Dotter said the RTO accounts for transmission for renewables through its markets and interconnection process.
“We do not plan or build transmission lines on speculation alone,” he said “The developers of new generation of any type are required to pay for the transmission upgrades necessary to deliver the output of their projects. The principle has been that consumers should not pay for transmission required because of generation developers.”
He noted that PJM’s state agreement approach allows states to take responsibility for the costs of transmission expansions addressing their public policy requirements. FERC approved the state agreement approach in a 2015 ruling as part of the RTO’s plan to integrate multi-driver projects into the Regional Transmission Expansion Plan (ER14-2864). (See PJM Wins OK on Multi-Driver Tx Projects.) PJM said the multi-driver concept could lower the cost of states’ public policy transmission projects by incorporating them in upgrades that address market efficiency or reliability.
Nickell said SPP considers voluntary and mandatory renewable goals in its planning assumptions. “If a wholesale customer, under the SPP Tariff, desires to buy from a new or existing renewable resource to supply the needs or goals of its customers and submits a request for transmission service from SPP, we are obligated to plan the system to accommodate the requested service, as long as the customer agrees to fund any requisite upgrades. SPP will consider any and all requests for transmission service made to deliver energy from existing or future renewable resources to prospective buyers and will direct construction of transmission upgrades on the SPP system needed to accommodate those requests in accordance with the respective customers’ service agreements.”
RPSs — which currently represent 10% of MISO’s load — are considered the base level of renewable penetration in its transmission planning modeling futures. “Large customer demand for renewable energy is included in alternative modeling futures on an additive basis that range up to 30% penetration of MISO system load,” Massey said. “We believe that level of penetration fully captures the stated goals of large customers and still leaves room for additional growth.”
Massey, who also spoke at the webinar, said it is the scheduling of transmission to deliver power under a PPA that signals load growth to MISO.
The RTO also learns of PPAs from stakeholders. “But because MISO is not a signatory to the power purchase agreement, we don’t always know about these power purchase agreements, so it’s difficult to plan in that context.”
ACEG Executive Director John Jimison, who moderated the webinar, noted that “it only takes a couple of years” to bring a wind farm or central solar plant into operation, shorter than the timeline for developing new transmission. “How do you anticipate the need for transmission so that you don’t expect people to put up a wind farm and then wait five years before they can actually transmit the power?” he asked.
Massey said MISO accounts for that disparity through its multi-value projects (MVPs). He cited the wind-rich Buffalo Ridge area of southwest Minnesota, northwest Iowa and eastern South Dakota. “We know that there’s a tremendous amount of wind capacity there, and in the current incentives regime with the production tax credit … and because the cost of wind generators is coming down rapidly, we know that there’s going to be wind locating there.”
MISO has about 37 GW of wind and 21 GW of solar in its interconnection queue. “The good news is that it takes a long time for even those plants to get through the generator interconnection process, and this gives us a little bit of lead time in the transmission planning process to identify projects that we’re going to need on a regional basis, that we can predict based on what the wind capacity is and where we know the load is,” Massey said.
Order 1000
Although Order 1000 requires RTOs to jointly plan transmission with their neighbors — and to “consider” whether needs identified in local and regional transmission plans could be addressed more cost-effectively through joint projects with a neighboring region — it does not require them to build anything.
The commission will conduct a technical conference beginning Tuesday on how RTOs coordinate generator interconnection studies on projects near their seams, saying their practices may not be just and reasonable (EL18-26, AD18-8).
FERC called the conference to address issues raised in EDF Renewable Energy’s complaint against PJM, MISO and SPP last year, which contends that 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. An affected system is one that may be impacted by an interconnection in a neighboring “host” system.
MISO and PJM will decide by May 18 whether to undertake a coordinated system plan study this year, the RTOs said last week.
The decision could be announced at the next Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on May 11. Staff from both RTOs confirmed the timeline at last week’s IPSAC meeting, which included the issues review required as part of the process of determining whether a study is required.
“We don’t anticipate taking that long,” PJM’s Alex Worcester explained, referring to the May 18 deadline. He later added that PJM is “likely supportive” of a study.
The RTOs will provide justification for their decision, MISO’s Adam Solomon said. It will be based on whether there are projects that “make sense,” addressing reliability issues on either side of the border that are close to each other.
PJM and MISO in January jointly reviewed their separate regional issues, newly approved projects near their border, coordinated interconnection requests and historical market-to-market congestion, which RTO representatives said would form the basis of the study, if it’s undertaken. The results were presented at last week’s meeting, along with analysis of stakeholderfeedback.
RTOs’ Review
Worcester reviewed projects approved through PJM’s monthly Transmission Expansion Advisory Committee analysis, including 27 baseline reliability projects near the RTOs’ shared border, six market efficiency projects and another six supplemental projects.
All reliability issues identified for 2022 are being addressed through a single proposal window open last summer. Market efficiency projects are addressed on a 24-month cycle that last identified issues in October 2016, but an addendum window to address thermal constraints on the Tanners Creek-Dearborn 345-kV line was closed in February. Supplemental projects are developed internally by transmission owners and are not driven by RTO 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.
Solomon reviewed the 2018 MISO Transmission Expansion Plan, which began in June 2017 and is scheduled to culminate in December 2018 with approval from the Board of Directors for recommended projects. He highlighted 52 approved projects near the RTO border that might spur interregional projects if there are needs nearby in PJM’s territory. They are all TO-submitted ‘bottom-up’ projects.
MISO is also reviewing 15 of its most congested north/central flowgates, which will be included in its Market Congestion Planning Study this year to potentially identify market efficiency projects, he said. Nearby PJM economic issues could drive the need for an interregional project. He also noted 21 congestion flowgates that were eligible for the MCPS but were excluded for individual reasons.
Stakeholder Issues
The RTOs also reviewed issues identified by stakeholders. Ameren submitted four issues, while three issues Northern Indiana Public Service Co. highlighted were included in Solomon’s presentation.
“We will look at those as appropriate and as they show up in the interregional process,” Worcester said.
NIPSCO’s final concern involved PJM’s finding of 10 facilities with infeasible auction revenue right paths. ARRs are rights to the revenue from congestion charges allocated to firm network and point-to-point customers because they fund the embedded costs of the transmission system. MISO and PJM are each addressing one of the infeasible ties with approved internal projects. Three others have projects under consideration, and two others will be included in a future proposal window. The three remaining infeasible paths are pseudo-tie flowgates. (See “ARR Analysis IDs Constraints,” PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017.)
Worcester said MISO has no process comparable to PJM’s ARRs, so “if it’s outside of PJM, it’s unclear how it would move through the [RTOs’ joint operating agreement] with the competitive transmission process,” he said. PJM will investigate internally ways to address the issues and engage with MISO on any potential solutions, he said.
Wind on the Wires and EDF Renewable Energy asked that the RTOs re-evaluate previously considered targeted market efficiency projects (TMEPs) that did not qualify last year if congestion has continued.
“We certainly agree with that in principle,” Worcester said. He said the RTOs aren’t planning on reconsidering the Thayer-Morrison project, which Wind of the Wires had specifically requested.
JOA Changes
Seven stakeholders provided feedback on three potential JOA changes, which informed the RTOs’ decision-making on the issues. References to joint economic models will be removed.
“NIPSCO prefers a joint model,” the company’s Clark Gloyeske said, noting past differences between the regional models in wind-unit profiles. “More coordination between the regional models to fix some of these modeling issues would be really helpful.”
The RTOs have decided against changing the number of benefit years, fixed charges and discount rates used in analyses, Solomon said. While changes were recommended, they were “wildly varying” on what the correct number of years should be.
“Considering all the feedback, the RTOs think this should be a regional discussion,” he said. “We think the regional processes are working … and that we shouldn’t be deviating from the regional criteria.”
“I understand the simplicity of working just within the regions … but if the number of years the benefits are calculated over are significantly different … I think there’s a risk of coming up against significant stakeholder or state concern about another region not paying its fair share because they haven’t calculated the same level of benefits over the same years,” said Natalie McIntire of Wind on the Wires.
Solomon acknowledged the “valid concern” but said it had to be weighed against “regional differences.”
“Each region has its own definition of how benefits should be calculated, and that’s in line with what we do with our regional projects,” he said. “Deviating from that for an interregional project would be difficult, but certainly, your point is taken.”
The generation-to-load distribution factor test will be removed, Solomon said, and the RTOs will rely on their own regional materiality tests. This removes a “triple-hurdle concern” that would require projects to pass tests for each region as well as an interregional review, Worcester explained. PJM will develop its test through its recently formed Market Efficiency Process Enhancement Task Force, while MISO is still considering where it will address the question.
“The Tariff is silent on how projects qualify materiality-wise,” Solomon said.
Ameren’s Adam Weber asked that the regions’ materiality tests be delineated in the JOA so stakeholders aren’t surprised by a project not clearing both tests. RTO staff hesitated to endorse that proposal but were aligned on addressing Weber’s concern.
An analysis of site location compared to benefits of interregional projects between MISO and PJM shows that there are nine potential cost-allocation categories into which a project could fit. | MISO, PJM
The grid operators will replace the distribution factor (DFAX) cost allocation method with an approach that allocates costs to the RTO with the reliability need, with split projects allocated based on the ratio of avoided costs. Cross-border baseline reliability projects will be replaced with interregional reliability projects because no scenario exists where the baseline projects would be used. An RTO will be obligated to construct projects that benefit the other RTO, but the benefiting RTO will cover the costs.
“There’s not going to be a scenario where there’s a new project developed and we would need to come up with a new cost allocation methodology,” Solomon said.
The RTOs said they “don’t see a need for” EDF’s request to add benefit metrics for projects, but a second request to broaden the JOA’s definition of a flowgate will be forwarded to the Congestion Management Process Working Group, which has representatives from most RTOs.
The RTOs hope to have the JOA changes in place for the next interregional market efficiency project window, which opens around Nov. 1.
“We’re thinking that a filing should be made by July to allow for the FERC process to go through,” Solomon said.
