DENVER — SPP’s on-again, off-again high-priority congestion study of the Texas and Oklahoma panhandles region is on once again following approval by the Board of Directors.
The study, ordered by the board in April to address historical congestion and frequently constrained areas (FCAs) in western Oklahoma and Texas caused by large amounts of wind energy, met pushback from the Markets and Operations Policy Committee three weeks ago. It was then revived with new direction by the Strategic Planning Committee later in that week. (See “Committee Gives Congestion Study New Life,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
When SPP Vice President of Engineering Lanny Nickell presented a revised study scope to the board and members based on stakeholder feedback last week, he said he couldn’t recommend proceeding with the study.
“It’s to the point where the scope is so watered down now, I don’t think you’re going to get any value out of it,” Nickell said. “If you want to do a study, let’s do it right.”
Kelly Harrison, Westar Energy’s vice president of engineering, agreed, pushing for a more in-depth analysis that would provide that value to the market.
“If we could get some type of study to determine what it would take to move wind out of SPP — maybe to somebody who wants to buy that wind — it might send a price signal of what it would cost to move that wind with firm transmission,” he said. “Right now, [developers] don’t know what to pay. A longer study would give us a goal post and send a signal to the marketplace. We’re putting states in a bind with what I think is a pretty valuable resource.”
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Nickell suggested a compromise by “tweaking” the scope of the 2018 integrated transmission plan near-term (ITPNT) assessment currently underway to include a summer scenario that models large amounts of wind. Stakeholders have taken the model out of previous studies because of concerns of “too much wind in the model for a summer-peak condition,” he said.
“It may make sense to reassert that model and use it in the 2018 ITP near-term, if evaluated against other needs,” Nickell said.
“That satisfies me!” board Chair Jim Eckelberger said.
Stakeholders agreed using the 2018 ITPNT would produce more timely results and reduce the drain on staff resources already engaged in regular studies. Staff’s workload is sure to be exacerbated should the Mountain West Transmission Group integration proceed. The ITPNT study is to be completed no later than April 2018. (See SPP, Mountain West Members Get Acquainted.)
“I don’t want anyone to forget why this began,” said West Texas-based Golden Spread Electric Cooperative’s Mike Wise. “The genesis of this discussion is based on … endemic congestion north and south of [Southwestern Public Service] and the continuation of a FCA south of there.
“Find me a solution. That’s what I’ve been asking for … for 10 years. I’m waiting for when the congestion goes away,” he said. “One of your members here is crying out. Please, please, let’s get this FCA taken care of, and don’t forget us.”
The Members Committee endorsed the revised high-priority study 10-8, with two abstentions. The board also voted in favor of the new study approach.
Work to improve SPP’s transmission congestion rights market will continue in the Market Working Group.
Separately, the board and Members Committee approved the expiration of the Export Pricing Task Force, which was charged with evaluating “mechanisms to establish equitable and not unduly discriminatory prices” to ship electricity in and out of SPP’s footprint. The task force was unable to provide a recommendation to handle the RTO’s growing wind energy (23 GW in the interconnection queue and not in service).
“We determined there are no really good solutions. There’s no silver bullet, so to speak,” said Wise, the group’s chair. “We asked for views on potential solutions that doesn’t, in the end, have SPP consumers footing the bill. The consumers that benefit from this wind are going to need to pay for the transmission.”
That was before AEP’s announcement it would build a 2,000-MW wind farm in western Oklahoma and send the energy eastward. (See related story, AEP to Spend $4.5B on Largest Wind Farm in US.)
WILMINGTON, Del. — The Pennsylvania State Senate approved a tax on virtual transactions, moving the measure to the state’s House of Representatives, PJM CFO Suzanne Daugherty told the Markets and Reliability Committee on Thursday.
Senators passed the tax on a 26-24 vote as part of a larger budget-funding package that includes several other consumer and corporate taxes. The Senate bill is the latest in a series of funding proposals after Pennsylvania legislators approved a budget by their constitutional deadline on June 30 but failed to agree on how to fund it. However, the Senate Appropriations Committee officially booked $0 for the PJM tax.
The state’s interest in developing the tax came to light in mid-June, after PJM attempted to explain to Department of Revenue representatives the issues with levying a tax on RTO transactions. Daugherty alerted several PJM financial stakeholders, who launched their own advocacy efforts at the State Capitol, but ultimately blamed the RTO for not making them aware early enough to develop a comprehensive response. (See Traders: PJM Delay Could Mean Pa. Tax; RTO Denies Supporting Levy.) PJM remains opposed to any new taxes on its membership.
FirstEnergy’s Jim Benchek asked Daugherty about PJM’s plan to address the situation. She responded that the RTO will continue to watch the tax’s progress and that it’s “too early to see” how it might respond if the tax is implemented.
Stakeholders Question Focus on DR in Seasonal Capacity PS
While aggregation rules allowed a substantial amount of seasonal resources to clear the 2020/21 Base Residual Auction as annual products, thousands of megawatts of such resources that have cleared past auctions didn’t this time around. To address those situations, PJM is proposing a problem statement and issue charge, which received a first read last week.
However, stakeholders questioned the limitations PJM put on the scope of the analysis. The issue charge focuses on “the impact of peak-shaving resources on the load forecast” and exploring “non-capacity wholesale market mechanisms to value demand response resource flexibility.”
“I struggle with why you’re limiting this to nonmarket issues,” said John Farber of the Delaware Public Service Commission.
Farber argued that adding market opportunities would spur innovation “so all stakeholders could get the benefit of managing that peak.”
Several stakeholders, including American Municipal Power’s Ed Tatum and Carl Johnson representing the PJM Public Power Coalition, asked why the documents focused on DR.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his members are concerned about opportunities for residential customers, which he said have been “significantly limited” in recent years.
Organization of PJM States Inc. Executive Director Greg Carmean asked that PJM’s education on the topic explain how the RTO came to develop the products it currently has and the impact of important legal decisions, such as FERC v. EPSA.
Tom Rutigliano, who consults with several energy management companies, requested that the analysis not be precluded from providing preliminary recommendations available for the next BRA in May 2018, despite a stated timeline that would provide results late next year.
PJM’s Pete Langbein, who is overseeing the proposal, said he is open to any suggested changes.
“We’re trying to be realistic about what it’s going to take and not be overly aggressive,” he said about the timeline.
Jim Jablonski announced he has retired as the executive director of the Public Power Authority of New Jersey. Jablonski, a former chair of the Members Committee, said it was a “pleasure and an honor” and a “humbling experience” to be involved in the PJM stakeholder process over the past decade.
He said some of the hardest issues he dealt with included the development of the minimum offer price rule and the Capacity Performance construct.
“It was a reaction to an anomalous event that may never, ever happen again, and we made these broad, sweeping changes to the capacity market that only increased costs to customers.”
He said that while he agrees with the need for reliability, the people paying the bills need to be considered.
“I still am concerned about cost to customers,” he said. “It seemed like every time we turned around here, we were raising costs to customers.”
He has no immediate plans following retirement, but given his broadcasting background, he may consider media opportunities involved with PJM. He said he joked with PJM’s Stu Bresler about starting a 24-hour PJM TV channel.
Brian Vayda, a former PJM employee, is succeeding Jablonski as executive director.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. Revisions developed to comply with NERC reporting requirements. Transmission operators will be required to maintain certain data during outages, including bus voltages for all 345-kV substations or higher and megawatt flows for all tie lines and all lines 345 kV or higher.
Manual 11: Energy and Ancillary Services and Manual 18: PJM Capacity Market. Clarifies language on what is needed to qualify for exempt or bonus megawatts during performance assessment hours in Capacity Performance. PJM says it needs certain data to determine how close generators follow its schedule. The data include values for economic minimum and maximum and emergency maximum.
Pseudo-tie pro formaagreement and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
Manual 14B: PJM Regional Transmission Process and Operating Agreement revisions. Redesigns to the Transmission Expansion Advisory Committee reflecting the change from the annual, 12-month Regional Transmission Expansion Plan cycle to an overlapping 18-month cycle beginning each September. The window for short-term projects will expand from 30 to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)
An endorsement vote on Tariff and Operating Agreement revisions to clarify the two-year limit on requests for billing adjustments was postponed to a later meeting.
Members Committee
Stakeholders Endorse Consent Agenda
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other Operating Agreement and Tariff changes:
Pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See MRC item 3 above.) Eighteen members opposed and six abstained.
Stakeholders Endorse Regulation Changes Despite Continued Opposition
Stakeholders endorsed Tariff and Operating Agreement revisions to regulation market rules on performance scores, clearing and settlements that were previously endorsed by the Regulation Market Issues Senior Task Force and the MRC. The revisions change the rate for substituting traditional RegA and fast-response RegD. (See PJM Regulation Compensation Changes Cleared over Opposition.)
John Horstmann of Dayton Power and Light reiterated his past objection to the changes, which he said don’t provide a sufficient transition period for the energy storage units developed for the original 15-minute neutrality requirement. However, the measured passed handily with 4.24 in favor out of 5 in a sector-weighted vote. Such votes require an approval of 3.33 (66.7%).
DENVER — The SPP Regional State Committee unanimously agreed last week with its Cost Allocation Working Group to leave the aggregate study’s safe harbor cost limit unchanged at $180,000/MW.
The study assesses which projects are necessary to satisfy transmission service requests (TSRs) to move energy around the SPP system, as well as who pays for those projects. Transmission upgrades under the safe harbor limit are base-plan funded through the RTO’s highway/byway approach.
The safe harbor is applied when the aggregate study’s waiver criteria are met:
The utility does not have more than 20% of its designated resources (used to meet a load-serving entity’s capacity margin requirement) come from wind energy when the TSR is granted.
It has a five-year minimum commitment term for the TSR.
The utility does not have designated resources greater than 125% of its forecasted load when the TSR is granted.
SPP has not recommended a change to the safe harbor amount since it was first established in 2005. Staff does file an annual letter at FERC (ER05-652), testifying as to whether the amount is correct.
Adam McKinnie, chief regulatory economist with the Missouri Public Service Commission and the CAWG’s chair, said an annual limited review of the safe harbor could include a discussion of the FERC letter and the methodology behind SPP’s recommendation on whether to change the amount.
CAWG members, staff and stakeholders have been discussing the correct methodology for calculating the limit. No consensus has been reached, but the discussions continue, McKinnie said.
The RSC also agreed with the CAWG to review the base-plan funding eligibility criteria and the safe harbor limit on an annual basis, with in-depth review at least once every five years. Both votes were unanimous.
The group just spent two years conducting the first review of the safe harbor waiver criteria. McKinnie estimated it would take nine to 12 months to conduct intensive reviews of safe harbor issues in the future, while a limited review could be done during a quarter and focus on issues of interest to the RSC or stakeholders.
“Frankly, we don’t want this to be our full-time job,” John Krajweski, a consultant with the Nebraska Power Review Board, told the RSC.
The Kansas Corporation Commission’s Shari Feist Albrecht agreed, saying, “The motion provides sufficient flexibility and doesn’t impede the RSC’s ability to request a study.”
SPP Wind Capacity Nears 17 GW
Bruce Rew, SPP’s vice president of operations, said the RTO is continuing to successfully integrate large amounts of wind energy.
The RTO currently has 16,280 MW of installed and operational wind capacity, with another 100 MW of wind registered but not yet operational. It expects another 5 GW to become operational before production tax credits expire in 2020, and it has another 18 GW in its interconnection queue.
SPP set a record for North American RTOs in April when it recorded a 54.47% wind penetration level. Rew noted SPP had not seen wind penetration levels of 40% until last Christmas. It exceeded 40% for seven days in the first quarter, and another seven days in April.
SPP’s Integrated Marketplace currently has 191 market participants, up from 172 a year ago, with 125 classified as financial-only and 66 as asset-owning. Rew said the RTO lost a financial-only entity during the second quarter.
The RTO’s balancing authority has successfully maintained NERC control performance standards while maintaining high system availability, he said. The day-ahead market’s posting has not been delayed during the last year, Rew said, and the real-time balancing market has successfully solved 99.95% of all intervals.
Interested Observers: Colorado’s PUC
Colorado Public Utilities Commission Chairman Jeff Ackermann and Commissioners Frances Koncilja and Wendy Moser were guests of honor and given front-row seats for the July 24 RSC discussion.
SPP CEO Nick Brown welcomed the commissioners, along with the new members of the RSC.
“It’s always been a strategy for SPP, and one we identify every strategic cycle, to maintain and establish a good relationship between staff and the RSC,” Brown said. “We’ve recognized for more than a decade how important it is to get you engaged in the process.”
The Colorado PUC will be among the bodies passing regulatory judgment on the Mountain West Transmission Group’s potential membership in SPP. The commission has held two public information sessions on the merger and has scheduled a third for Aug. 24. (See SPP, Peak Reliability Pitch RC Services for Mountain West.)
“The [Mountain West] expansion is an important decision, not only for the 10 members of the Mountain West, but for SPP as a whole,” Brown said. “We encourage you to stay engaged.”
DENVER — SPP stakeholders made another effort to revise the RTO’s transmission-zone placement process last week, but once again came up short when the Board of Directors sustained its earlier rejection.
The revision request’s (RR172) defeat likely means future disputes over cost shifts caused by SPP’s zonal-placement decisions will be resolved through litigation.
“I’m not sure about next steps, but you can be sure it will be argued about at FERC in both current dockets and future dockets,” Kansas City Power & Light’s Denise Buffington told RTO Insider.
Several cases involving cost shifts are currently before FERC (ER12-959, ER16-204 and ER17-2020). Another (ER15-1499) has been settled between KCP&L and the City of Independence, Mo., and the terms are being phased in. After KCP&L objected to Independence being placed in its zone, the parties agree to phase in the city’s annual transmission revenue requirement in three tranches ($3 million for June 2015-December 2016, $3.5 million for 2017 and $5 million for January 2018-May 2019).
Buffington has been the driving force behind RR172 for more than a year. She says there is a gap in SPP’s process for placing applicant transmission owners (ATOs) in existing zones. Staff currently determine which of 18 transmission pricing zones to place new TOs, which can result in cost shifts for those in the incumbent zone.
“When SPP provides analysis to an impacted zone, SPP specifically states which zone the new TO comes into,” Buffington said. “One of the issues in litigation is whether or not SPP should even make that decision. SPP has argued in litigation that that’s within their scope and is their responsibility.”
Buffington said she revised RR172 to incorporate that concept, saying it mitigates the costs of zonal-placement decisions and protects both existing and new customers from cost shifts by capping cost shifts for legacy facilities at 2% of the annual transmission revenue requirement or $1 million, and creating an 18-month period without cost shifts for the facilities following integration. It also would have provided an exclusion for legacy facilities that were jointly planned for the benefit of all customers in the zone.
“We’re trying to isolate the cost of legacy facilities built outside the SPP planning process,” Buffington said. “We want the board to give us some guidance on the policy. We feel we need some bookends around the cost structure, to help both existing and new members.”
The revision had been through nine in-depth discussions in three stakeholder groups. Three weeks ago, it was rejected following a contentious discussion at the Markets and Operations Policy Committee, setting the stage for last week’s appeal. (See Divide Evident Between SPP Tx Owners, Users.)
Public power entities led the opposition to RR172. Dave Osburn, general manager of the Oklahoma Municipal Power Authority, was among those signing a letter that was submitted four days before the board meeting. The letter, co-signed by Golden Spread Electric Cooperative and Northeast Texas Electric Cooperative, charged “KCP&L has been transparent that the RR172 process, and the expected failure, is simply a prerequisite” to a Section 206 complaint at FERC.
“One of the concerns we have on this is as a transmission-dependent utility we should be careful to not approve something that keeps the smaller entities from building transmission and getting cost recovery,” Osburn said during the discussion. “We’ve been paying a load-ratio share of transmission customers for quite a while. Some assets in existing transmission zones may not benefit all customers either, but we pay our load-ratio share regardless. The money we pay is just as important as the TOs’.”
“This is an additional burden for a new ATO. They are going to have to present a lot of data people haven’t in the past,” said NTEC Vice President Jason Atwood. “It concerns me we’re always talking about expanding the footprint. The concern about something like this is it could impact the expansion.”
Nebraska Public Power District’s Paul Malone, whose company is involved in one of the FERC dockets, wondered aloud whether there was an ulterior motive to the current zonal-placement process.
“Costs shifts are not a one-time issue. They come back year after year,” Malone said. “Are the new members joining because they expect someone else to pay for their system? Is that the windfall to entice them to join? I hope not.”
“We’re all trying to do the right thing for our customers. They’re the ones impacted by these cost shifts,” Buffington said. “Nothing in this proposal is intended to prevent entities from collecting the revenue requirement. It’s all about which customers pay.”
The Members Committee approved RR172 by an 11-9 vote. However, the board voted against the motion.
Midwest Energy’s Bill Dowling was among those supporting RR172, though he was reluctant to change the Tariff language.
“That gives us the flexibility to continue to adjust the process, especially when some of the issues around cost mitigation and cost shifts are still in flux,” he said. “It’s been an issue, and it continues to be an issue.”
“It’s not the end of the story,” SPP Board Chair Jim Eckelberger said. “There was a suggestion to let some time pass and see what we learn from it. That may be one answer to it, but sooner or later, if nothing is forthcoming and the problem still exists — and I think it’s a problem — we’ll have to assign the problem to someone.”
“We’ll continue to work with the stakeholders to find a path forward,” Buffington said. “I don’t know if that will be in a FERC proceeding or through the stakeholder process, but we’ll do some work on that.”
The board did approve a four-step communications process for SPP staff to follow in making zonal placement decisions. The Transmission Owner Zonal Placement Process document addresses the growth of transmission zones in SPP’s footprint and concerns expressed over the process in FERC proceedings. (See “SPC Approves Zonal Placement Process Document,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
However, Buffington found little solace in the document’s passage.
“The process document does not solve any of the underlying issues,” she said, referring to her concerns about a lack of notice and transparency. “SPP has used informal criteria to determine which zone to place a new entity in. They’ve never included cost impacts in their solution. The process lacks transparency and harms existing customers.”
Arkansas Electric Cooperative Corp. CEO Duane Highley reminded the board and members that his company’s long-time stakeholder representative, the recently retired Ricky Bittle, always believed SPP should consist of one zone.
“Maybe the time for Ricky’s dream has come,” SPP Director Phyllis Bernard said. “It seems the difficulty of this whole issue, trying to talk through it and work it out, has seemed to be intractable. It seems to take up so much resources, good will, time and results that no one is satisfied with it. A [single postage-stamp] rate is a worthy goal to work towards.”
MISO’s Steering Committee last week declined to reconsider a stakeholder proposal that would allow funders of transmission upgrades for lines under 345 kV to recover some of their costs through the RTO’s allocation process.
Wind developer EDF Renewable Energy and nonprofit Wind on the Wires approached the committee during a July 26 conference call to insist again that costs for customer-funded upgrades be categorized as “non-[MISO Transmission Expansion Plan] upgrades,” a project type they said would address “chronic congestion on existing transmission elements that do not meet the criteria for market efficiency projects or multi-value projects.”
EDF’s Great Western Wind Project in Oklahoma | EDF
Under MISO’s current rules, only upgrades on lines 345 kV or above qualify as market efficiency projects.
The call marked the second time the issue had come before the Steering Committee, which had previously assigned the issue to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG) in the spring. EDF representatives argued that the issue wasn’t given a fair hearing and was dismissed too quickly, and asked the committee to direct the RECBWG to re-examine the issue.
Xcel Energy’s Carolyn Wetterlin, chair of the RECBWG, said the working group generally agreed that “if a market participant chose to fund [an upgrade], they should have done it without an expectation of future reimbursement.” Stakeholders participating in the working group voted against taking up the proposal, which some attributed to buyer’s remorse after EDF voluntarily decided to upgrade the MISO grid but did not receive the expected benefits.
According to Wetterlin, RECBWG members pointed out that customer-funded upgrades are performed outside the MTEP. As such, they aren’t subject to the RTO’s transparent standards for determining whether a project is the most efficient solution for solving the transmission issue.
The RECBWG concluded that the issue is still not worth pursuing, Wetterlin said.
The ‘but for’ Principle
“We think there’s need for a deeper discussion at the RECBWG,” Wind on the Wire’s Natalie McIntire countered.
EDF argued that its simple cost reimbursement would only apply to new customers that could not have been granted new service by MISO “but for” the customer-funded upgrade.
“We’re trying to get some compensation when new users come on the grid,” said Bruce Grabow, an attorney representing EDF. “This wouldn’t be a full-blown cost recovery … it’s just a reimbursement of a portion of installed costs if the next customer coming down the pike couldn’t get network service but for the network upgrade.”
New interconnection customers can currently enter the grid and reduce some of the benefit that the original funders of the project had expected, as MISO grants non-firm usage rights to the customers that paid for the upgrades, he said.
Grabow said the poor financial benefits of market participant-funded projects are evident: No such projects were brought forward in MISO’s transmission plans from 2014 to 2016.
“This occurred notwithstanding known congestion on voltages below 345 kV. Participants see the need but are not utilizing this avenue because of the lack of reimbursement and/or retained benefit,” EDF and Wind on the Wires said in a joint presentation.
‘Devastating’ Rate Shocks
Indianapolis Power and Light’s Lin Franks said that “having after-the-fact cost allocation would seriously complicate” MISO’s planning processes.
“It could cause rate shocks that could be quite devastating,” Franks said, adding that customer-funded upgrades are “just the way the world works,” with customers accepting the risks of funding their own upgrades. She noted that transmission rates cover the cost of using existing upgrades on the system.
NRG Energy’s Tia Elliott said that the stakeholder process was not necessarily flawed even if EDF and Wind on the Wires did not receive the stakeholder response that they wanted from their proposal. ITC Holdings’ Cynthia Crane, who attended the RECBWG meetings, said she thought the issue was “properly vetted” at the RECBWG.
Elliott pointed out that the Steering Committee’s decision does not preclude the two companies from approaching the Advisory Committee with its proposal. And the two companies could always file a complaint at the FERC level, according to We Energies’ Tony Jankowski.
Participant-funded transmission projects have always been excluded from MISO’s cost allocation procedures, while projects not eligible for allocation can be recovered through a zonal transmission rate. The RTO is considering changes to its cost allocation rules — which have not been altered since the integration of MISO South in 2013 — especially given that Entergy’s integration transition period, which limits cost sharing in MISO South, expires next year. The RTO has said that it may lower the 345-kV threshold on market efficiency projects. (See MISO Stakeholders Debate Postage Stamp Cost Allocation.)
FOLSOM, Calif. — The CAISO Board of Governors last week greenlit new rules that allow the grid operator to constrain the operations of gas plants across the state and the Western Energy Imbalance Market (EIM), part of a package of initiatives drawn up in response to the loss of the Aliso Canyon storage facility.
The board unanimously approved the new market rules in a 5-0 vote, as the broader public discussion over Aliso Canyon intensified.
CAISO Director of Market and Infrastructure Policy Greg Cook explained to the board that there are still operational risks around the loss of Aliso Canyon. The gas constraint tool is limited to use for physical constraints on the grid, not to manage economic conditions.
“There is potential for similar types of physical gas constraints elsewhere outside of Southern California, and our operators have found that this is a valuable tool” to maintain electric and gas system reliability, Cook said.
CAISO asked the board to approve extending some temporary provisions and make others permanent as it develops a new long-term suite of market rules in its Commitment Cost and Default Energy Bid Enhancements (CCDEBE) proceeding, expected to be implemented in fall 2018.
The EIM Governing Body previously approved elements of the Aliso Canyon Gas-Electric Coordination Phase 3 proposal. (See EIM Leaders Endorse CAISO Gas Constraint Measure.) CAISO will submit the rules to FERC for approval.
The board’s approval extended a temporary rule that the day-ahead market gas price index use information published every morning to better reflect gas costs, and requires a scalar to be included for the next-day gas index to account for tight gas conditions in Southern California and higher gas costs.
Cook said he hasn’t seen much need for gas constraints in Southern California in the past year, but the ability to use the scalar would be there if unforeseen events happen.
Also approved was a right for gas generators to file for after-the-fact cost recovery of energy costs if units are mitigated down to their default energy bid.
Stakeholders generally support the gas constraint tool but do not want it to replace or affect the package of bidding rule changes being developed in the CCDEBE proceeding. Representatives from NRG Energy and Pacific Gas and Electric said there are concerns about the package but were generally supportive. But many stakeholders have commented that there are broader problems that must be adequately addressed in the CCDEBE proceeding. The Western Power Trading Forum did not support use of the gas constraint tool unless the scalar is retained.
CAISO’s Department of Market Monitoring had expressed concerns about the Phase 3 proposal, but its concerns have been addressed, including an eventual automation of the process whereby constrained transmission paths are deemed uncompetitive and constraints are implemented.
NRG Director of Regulatory Affairs Brian Theaker told the board that his company originally opposed the Aliso Canyon mitigation procedures because it distracts attention from CCDEBE and “long-standing problems with regards to the ISO bidding structure.” Suppliers cannot reflect gas procurement costs in bids and could not recover those costs, he said.
The company’s opposition has been “tempered a little bit” because of process on CCDEBE, he said. “CCDEBE is a long way off,” and the company supports extending the Aliso Canyon measures.
FOLSOM, Calif. — The CAISO Board of Governors last week approved a set of market rules designed to aid the integration of distributed energy resources and transmission-connected energy storage into the ISO’s markets.
ISO staff closely consulted with market participants over the past year to develop the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal in response to the growing volume of distributed resources in California. The board’s approval of the measure sends the rules to FERC for a new round of comments and review.
DER developers such as energy storage companies are aggressively moving into an area that is seen as increasingly important and profitable — balancing renewables and addressing California’s “duck curve,” which graphically describes the impact of the variable output of solar generation on the ISO grid at different times of the day. (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)
CAISO CEO Steve Berberich told the board that ESDER Phase 2 is part of a broader strategy to accommodate emerging technologies, including demand response, storage and other new types of systems that might be coming to the grid.
“We think that leveraging them is going to be critical to how we manage the grid, and help decarbonize the grid as well,” Berberich said. He added that “we are committed to continue to work with all those that provide these services,” and with the California Public Utilities Commission.
Storage makes up 20% of the resources in CAISO’s interconnection queue, which contains 325 projects totaling 58,000 MW, according to the grid operator. Renewables represent 68% of the generation waiting to interconnect, while conventional resources account for 9%.
Beyond 10-in-10
As part of ESDER, the board approved a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also approved new rules that distinguish between charging energy and station power for storage resources, and a net benefits test for DR resources that participate in the Energy Imbalance Market (EIM).
The ISO currently relies on a “10-in-10” baseline methodology that works well for many large commercial and industrial customers but not for all customer types, CAISO said in briefing documents. Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. It then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in the absence of DR dispatch under similar weather and on similar days, using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not appear in the historical data.
The package approved by the board also includes a new definition for station power, to distinguish between power used to charge a storage device and energy for station power. It simplifies the definition of station power to align with local regulatory authorities.
The newly approved initiative also incorporates additional gas pricing indices into the “net benefits test” that determines a price threshold to indicate when DR provides a net benefit to all purchasers by reducing the wholesale price. The price threshold is used to determine if an adjustment is required to the settlement of the load-serving entity that procured the load curtailed by the DR resource.
Greg Cook, CAISO director of infrastructure and policy, told the board that the measure allows the ISO to “take into account that the real-time market now has a much broader footprint than just the ISO balancing area, and we should take that into account in the calculation of the net benefits test.”
‘All Hands on Deck’
Tesla’s Powerpack is an example of utility-scale storage | Tesla
CAISO stakeholders are supportive of the new baselines and the station power proposals. Tesla and other storage companies urged CAISO to move quickly to develop a new DER product that would pay for storage to take excess generation, but the ISO said that measure needs more development, and it was not included in ESDER Phase 2. (See Storage Advocates Urge CAISO on DR Product.)
Ted Ko, director of policy for energy storage company Stem, told the board that the ESDER package and DER will be an important tool in reducing the duck curve and curtailments of excess renewables.
“It seems like a time for all hands on deck,” Ko said. “We should be looking for all solutions to reduce that curtailment and bring all solutions to bear.” This also includes developing the EIM and regionalization of CAISO, he said.
Stem has been participating in CAISO as a proxy demand resource and has contracts to deploy more than 400 MWh of DER over the next several years in California. The company needs the ISO to provide a market signal to know when charging is most helpful to the grid, Ko said, and technical and policy guidance from the ISO and other companies. He said that Stem and other companies want the ISO to “take this leadership position with urgency” on developing a load consumption proposal.
Berberich said that CAISO will brief the board at its next meeting on the integration of the load-consumption DER product. There are jurisdictional issues to be worked out with the PUC, he said, and he asked storage companies to contribute their ideas.
American Electric Power, once the biggest coal-burning utility in the U.S., now plans the nation’s largest wind farm, a 2,000-MW project in the western Oklahoma Panhandle that would be connected to subsidiaries in Arkansas, Louisiana, Oklahoma and Texas by a 350-mile EHV transmission line.
AEP’s total investment in the project would be $4.5 billion — $2.9 billion for the wind farm and $1.6 billion for the Wind Catcher Energy Connection line. Its Southwestern Electric Power Co. and Public Service Company of Oklahoma subsidiaries would own 70% and 30% of the project, respectively.
| AEP
The wind farm, made up of 800 2.5-MW General Electric turbines, will be built for AEP by Invenergy. In addition to being the largest in the U.S., it will be the second largest in the world, behind only the 6,000-MW Gansu wind farm in China.
PSO and SWEPCO seek approvals from regulators in the four states the project will serve, as well as from FERC, by April, AEP CEO Nick Akins said in the company’s second-quarter earnings conference call Thursday. The company will re-evaluate the project at that time.
| AEP
“We are going to have to sit down at the end of that April time period and figure out, ‘OK, what are the risks to our shareholders moving forward with this particular project, given not only the regulatory outcomes but also the other risk components that are involved with this,’” Akins said.
One of those other risk components is the project’s completion date. It has to be up and running by 2020 to qualify for the federal production tax credit, which ends at the end of 2019. Akins said AEP will recover $2.5 billion through the credit.
SPP confirmed that the project is in its generator interconnection queue for study of its impact on the system.
SPP Wind Growth
The RTO has seen considerable wind-energy development in the Oklahoma and Texas panhandles, which has caused congestion in the area. SPP will be conducting a high-priority congestion study to address the situation. (See “Committee Gives Congestion Study New Life,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
AEP’s announcement came as the American Wind Energy Association reported that wind projects under construction or advanced development rose 40% year-over-year in the second quarter. Kansas became the fifth state with more than 5,000 MW of installed wind, joining Texas, Iowa, Oklahoma and California.
The transmission segment of the project is similar in scale to Clean Line Energy’s proposed Plains & Eastern Clean Line, a $2.5 billion, 700-mile HVDC transmission line that would deliver 4,000 MW of wind power from the Oklahoma Panhandle to the Tennessee Valley Authority near Memphis, Tenn.
‘Exciting Development’
“It’s a pretty exciting development for transmission,” Clean Line founder and President Mike Skelly told RTO Insider. “We’ve always believed building wind in the windiest places of the country with long-distance lines to load is a great answer for ratepayers and energy overall. These guys believe in the same thing.
“When the biggest utility says, ‘You know what? We believe that too’ … that’s a very positive thing for our industry. It bodes really well.”
Asked about advice he would give AEP given regulatory approvals and landowner opposition, Skelly said, “AEP is one of the biggest utilities we have. Far be it from me to offer them advice.”
Akins said the project would not cause AEP to shutter any of its other generators. He said only 7% of the power coming out of the wind farm “counts as capacity, so you still need the other units to provide capacity, and they fill in from an energy perspective as well.
“We’re not shutting any other units down; those units are absolutely needed. But what it does is provide more diversity from a resource perspective.”
AEP also is touting the project’s effect on its service areas’ economies, saying it will save ratepayers $7 billion over 25 years and support 8,400 jobs during construction. The project will support 80 permanent jobs once it’s operational and contribute approximately $300 million in property taxes over its life, according to the company.
AEP said it earned $375 million ($0.76/share) on revenue of $3.6 billion in the second quarter. Its earnings, adjusted for non-recurring gains, were 75 cents/share. That was short of the average estimate of seven analysts surveyed by Zacks Investment Research, which was 82 cents/share.
Eversource Energy’s second-quarter profits this year increased 13.3% over the same period a year ago, driven mainly by higher distribution revenues and lower operations and maintenance expenses.
The company reported net earnings of $230.7 million in the second quarter of 2017, compared to $203.6 million a year earlier. In a July 28 earnings call, CFO Phil Lembo highlighted the company’s transmission expansion plans, and its move away from electricity generation and into the water industry with its planned $1.7 billion acquisition of water utility Aquarion Water, which operates in Connecticut, Massachusetts and New Hampshire. Eversource expects to close the deal by year-end following regulatory approval.
ROE Revisited
Lembo commented on the D.C. Circuit Court of Appeals’ April ruling overturning a 2014 FERC order that lowered the base return on equity for New England transmission owners from 11.14% to 10.57%. The court said the commission failed to meet its burden of proof in declaring the previous 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
In June, the New England TOs — including Eversource — filed with FERC to begin billing customers based on the prior ROE, with retroactive billing to June 8 of this year, 60 days after FERC assembles a quorum.
The commission has lacked the necessary three-member quorum since the February departure of former Chair Norman Bay and has been down to one commissioner — acting Chair Cheryl LaFleur — since Colette Honorable left last month. LaFleur may be joined by four new members if Democrat Richard Glick and Republicans Kevin McIntyre, Robert Powelson and Neil Chatterjee win Senate confirmation. (See Trump Names Energy Lawyer McIntyre as FERC Chair.)
“As a reminder, every 10 basis points [0.1%] of change in transmission ROEs results in about $3 million after-tax earnings annually,” Lembo said. The posted Q2 earnings reflect the lower ROE rate ordered by FERC.
Northern Pass
| Eversource
Company executives also touted the benefits of a proposed project designed to help Massachusetts meet its ambitious clean energy goals.
Eversource and Hydro-Québec on July 27 jointly bid the Northern Pass transmission line into the state’s solicitation. The 192-mile line would carry 1,090 MW of Canadian hydropower into New England and deliver up to 9.4 TWh/year for a period of 20 years starting in December 2020. The RFP encouraged bids able to begin delivering all or part of the state’s required 9.45 TWh/year of renewable energy by the end of 2020. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
New Hampshire’s site evaluation on Northern Pass is moving forward this summer, and the company estimates the project will be fully permitted by the end of September, allowing construction to start in early 2018, Executive Vice President Lee Olivier said.
“We believe this schedule would put us ahead of any other major project to import Canadian hydro into New England,” Olivier said. “Our confidence in the construction schedule is also supported by the firm contracts we have with two of the most pre-eminent firms in the world in terms of electric transmission design and construction, ABB and Quanta Services.”
Bay State Wind, a 50/50 partnership between Eversource and DONG Energy, will also bid into a separate wind project RFP in December to develop an offshore site south of Martha’s Vineyard.
Regulatory Activity
The company also noted that Massachusetts regulators last month wrapped up hearings on rate cases filed by Eversource subsidiaries NSTAR Electric and Western Mass Electric, which have asked to raise their base distribution rates by $60 million and $36 million, respectively. Eversource also sought approval to combine the two utilities.
“Hearings have concluded on the rate case, except for rate design topics,” Lembo said. “We expect a decision on the financial aspects of the case by the end of November, with the rate design decision around year-end. New rates would be effective in January of 2018 and to date we’ve had no surprises in the rate review process.”
In New Hampshire, binding bids to buy the company’s Public Service of New Hampshire generation fleet are due in August. “There, too, the overall divestiture process is moving along well and we expect regulatory approval of the sale by the end of the year, with securitization activities to follow soon after the closing,” Lembo said.
Tony Clark’s term as FERC commissioner ended nine months ago, but he hasn’t stopped thinking about the issues that animated him during his four-year tenure.
Clark, a non-attorney who joined law firm Wilkinson Barker Knauer as senior adviser in January, had his coming out in a 16-page white paper titled “Regulation and Markets: Ideas for Solving the Identity Crisis.” It was released at the National Association of Regulatory Utility Commissioners’ summer meeting in San Diego, a fitting venue for Clark, a former North Dakota regulator who served as NARUC president before his FERC appointment.
Clark’s paper mostly addresses the eastern organized markets being buffeted by state policy initiatives, but he also discusses new technologies and trends. He offers his familiar wit, for example, linking the 1978 Public Utility Regulatory Policies Act (PURPA), which Clark has long criticized, to the era of bell bottoms and disco.
Nothing in his recommendations are particularly divisive, surprising or novel. His recommendations on performance-based ratemaking and changes to distribution rate structures, for example, are sensible but no surprise to anyone following New York’s Reforming the Energy Vision (REV).
Perhaps his most interesting observation is that moves by New York, Illinois and New England states to subsidize nuclear plants or require utilities to sign out-of-market contracts for renewables have exposed “how thin the veneer of pro-market fidelity” is. It’s an issue he first considered in the 1990s when he — then a state legislator — weighed whether North Dakota should abandon its traditional regulated utility model for retail choice.
Although his “philosophical conservative” side favored competitive choice, his “operational and practical conservative” side won out. “Like nearly all other states with much below-average-cost electricity, the value proposition for [competition in] North Dakota did not pencil out,” he decided.
Clark concludes that recent moves to increase state control over wholesale generation market “is consistent with the factors that have driven public policies in electricity for the last two decades, not a departure from it.”
“For many, a ‘freer market’ was never the end goal,” he said. “The market was a tool. Affordable power was the goal. The current markets are still procuring affordable power, but many state public policy makers no longer see that as the only goal.”
He also expressed doubts that the eastern RTOs will succeed in their efforts to accommodate state choices while maintaining capacity markets as the primary source of resource adequacy. “While I applaud their efforts to look at creative solutions, I am skeptical of whether further dissection of administrative auctions into state-sponsored resources and competitive resources can succeed,” he said. “The complexity of these administrative constructs is remarkable as it exists today. Layering even more auctions, set-asides and carve-outs onto to the current construct may ultimately tumble the house of cards.”
RTO Insider talked to Clark last week about his paper and his new role. This interview has been edited for length and clarity.
RTO Insider: OK, so I read through your white paper and I’m curious: Who was the audience for the white paper and what was your goal in writing it?
Clark: Yeah. Well, I suppose there’s two audiences. One is more general and then one is probably a little bit more specific. The general audience is just for the public policymakers and certain thought leaders within the electric industry. On a more specific level, the way the paper turned out, it tended to be pretty focused on states. What I would hope is, especially thought leaders in the states in regulatory commissions — but also in legislatures and governors’ offices — would take a look at it and say, “You know what? There’s some things we should be thinking about.” So that at least we’re purposeful as we’re moving through this time of transition in the electricity sphere. The concern is that it’s not purposeful and it’s sort of an ad hoc collection of moves like I talked about in the paper, which is one piece at a time, where we keep layering on all these different public policies that when you step back and look at, it may not make sense in the whole.
RTO Insider: Yes. I liked your reference to the Johnny Cash song [“One Piece at a Time,” which tells a story of an assembly line worker who sneaks Cadillac parts out of the factory, later building a car mismatched from models from 1949 through 1973.] That’s one of my favorite songs.
Clark: Yeah, that’s a great song.
RTO Insider: Now that you’re no longer a commissioner, were there things in this paper that you said that you would not have been able to say before?
Clark: That’s an interesting question and I hadn’t thought of it that way. I don’t think so. I mean, it’s not dissimilar to some things that I thought and said along the way at first. It’s probably the sort of biggest compendium of all these thoughts put together in one spot. I probably would have said similar things. It’s just when you’re in the commission, you usually don’t have the time, sometimes, to sit down and really think about these things a little bit more holistically. Your day-to-day grind of just moving through your cases kind of takes things over. … Now I have a little bit more time to, I guess, sit back and contemplate.
RTO Insider: I recall covering [Wilkinson Barker Knauer partner] Raymond Gifford at the [Independent Power Producers of New York] conference in New York back in May. The subject there was the carbon adder, and he had said, “It’ll never happen.” (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.) He agreed that “the most elegant solution is you price carbon into the market” but said “FERC is not going to sign off on a carbon imposition.” Do you agree with that?
Clark: Well, generally yes. I mean, some of it depends a little bit on how you frame the question. If the question is, “If the states, or a collection of states, or the federal government for that matter” — [chuckles] but I don’t see that going to happen any time soon — “put on some sort of carbon adder, would FERC recognize it and allow it to be bid into the markets?” I think the answer there is probably “yes.” The commission already does that in the case of [the Regional Greenhouse Gas Initiative] and California. Other governmental bodies through their own legitimate authority putting on a carbon adder — would the commission allow that to be bid in the market? I think so, because it would just be like any other governmentally imposed cost: It’s allowed to be offered into the market.
Now, do I think FERC on its own motion is going to go out and throw on a carbon adder? I don’t think so. I don’t think it would be a wise idea beyond that. I mean, one — just take the politics of what the commission is [facing] now and for the foreseeable future. I don’t think it’s going to happen. No. 2 … it wouldn’t be in the commission’s own interest to do it for a number of reasons. You’d get beat up on Capitol Hill like you can’t imagine. And it probably is a little bit, I think, legally suspect. … I think it’s a stretch under the Federal Power Act. … And then No. 3, which is as big as anything — if you’re a commissioner who is interested in seeing the potential benefits of a joint dispatch model [traditionally regulated states that have joined ISOs or RTOs, such as most of MISO] migrate to other areas of the country, the fastest way to stop that development would be for FERC to go in and start imposing carbon taxes.
And if you look at what’s starting to come together in the West, we’ve talked about not just the [Energy Imbalance Market] but potentially more of a joint dispatch market in certain regions. … If you want western commissioners to flee from that idea and never come back to FERC again, [never] talk about it, just throw on a carbon tax. I think it would be self-defeating itself in terms of development of markets. It would probably halt markets where they are, in their tracks. You might even have some states start seriously thinking about pulling out of markets that they’re already in. If you’re from the part of the country I’m from — big red states in the middle of the country that are part of an organized market — if FERC starts looking at levying quote-unquote “carbon taxes” on its own, theoretically, you could see a real backlash in state legislatures in terms of what they allow their utilities to do. And remember that … these markets, they’re voluntary.
RTO Insider: When I was reading through your recommendations, they all seemed very sensible, very much in accord with some of the things that have been discussed in other states. For example, [New York’s Reforming the Energy Vision initiative], with their attempt to de-couple usage from revenues and provide ways for performance-based ratemaking and ways for utilities to make money as system platforms. Am I missing anything in your paper? Was there anything that you felt where you were striking new ground, where you were carving out new proposals, or were you more surveying the landscape and saying, “This is a round-up of what I think makes the most sense,” based on the current state of play?
Clark: Yeah. I think it’s probably more the latter, and my hope was to put it in the conversational style, so that it was accessible to a wide variety of policymakers. Some of them maybe don’t every day play in the electricity space. As much as anything, it was probably a distillation of trends that are out there and potential ways to frame the issues as you think about it.
A lot of that deals with rate design, making sure that you’re getting the distribution side of things right because this grid is changing. If you keep the same old rate structures that you’ve always had, you’re going out come out with a lot of arbitrage opportunities for new entrants and things like that. You want utilities to be able to provide the platform that allows for other players to do what they’re going to do, but to do it on a level playing field in a fair manner that allows them to, and gives them incentives to, invest in that network.
RTO Insider: You’re not going to have a robust distribution side network if you don’t come up with a mechanism to allow those investments to be made. Anything I haven’t touched on that you think is important in the context of this paper?
Clark: The thing that struck me as interesting over the last few years is, I thought, if there’s one region of the country where you might actually get a strong consensus for some sort of carbon price, it was going to be New England because you’ve got, politically, a group of states that probably are seeing the issues [similarly] and they’ve already joined RGGI and are part of the organized market.
I would have thought there might be a coalition here that says “maybe you need to step back from some of the other public policies and instead really depend on carbon price to drive the market.” But it’s just never coalesced and I think it shows the difficulty — even where there’s relatively fertile ground for policymakers to rally around the very transparent carbon price. Because it really — it’s transparent, which is maybe why it’s so tough to get done even under favorable circumstances.
RTO Insider: Yeah, I think some of the smaller [New England] states are just not as willing to take on more renewables in the way that Connecticut and Massachusetts are. We heard that loud and clear in some of the sessions we’ve attended from the likes of New Hampshire and Vermont and Maine, that the size of the carbon price, to make a difference, would be kind of a non-starter for them.
Clark: Yeah. That’s just it. RGGI, as I mention in the paper, has never really been used to strike dispatch or drive resource selection. It’s really been just a funding source for energy efficiency programs and things like that. It funds programs at the state level, but it doesn’t really drive resource selection in any meaningful way if the prices are just set too low.
RTO Insider: Right, right. Well, great. Well, thank you very much for your time this morning. I appreciate it.
