“What we know for sure is we’ll have a different FERC at the end of 2017 than we did going into the year,” LaFleur told the New England Conference of Public Utilities Commissioners’ (NECPUC) 70th Annual Symposium at the Omni Mount Washington Resort.
The Senate Energy and Natural Resources Committee is scheduled to vote June 6 on approving nominees Robert Powelson and Neil Chatterjee to two Republican vacancies on the commission. The committee questioned the two nominees at a mostly cordial hearing May 25. (See No Fireworks for FERC Nominees at Senate Hearing.)
In addition, LaFleur said, there are “rumblings” that Trump will name a Democrat to replace Commissioner Colette Honorable along with a third Republican nominee.
The five-member commission has been without a quorum since February, when then-Chairman Norman Bay resigned after President Trump stripped him of the chairmanship and promoted LaFleur.
LaFleur said the commission has issued only a fraction of the 100 commission-authorized orders it averages a month. Without a quorum, FERC staffers have been able to issue only delegated orders. Contested dockets and rulemakings have been at a standstill.
“So we are piling up quite a few cases for potential voting when [new] folks come in,” LaFleur said. “On some of these bigger policy issues … it’s not a matter of striking up an order. We’re looking to shape the policy choices in as transparent a way as possible for the incoming commissioners.
“We do have several dozen open rulemakings or generic dockets … multiple rulemakings on price formation in the electric markets, interconnection rules, [the Public Utility Regulatory Policies Act], hydro licensing terms, taxation [and] master limited partnerships in the pipeline area are some of the big ones that come to mind.
“But nothing’s higher on the mind than the issue du jour of harmonizing wholesale market rules and state policy initiatives,” she added, citing an issue that was the subject of a two-day technical conference in May. (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)
LaFleur said Trump’s decision to pull the U.S. from the Paris Agreement “could only accelerate the extent to which climate policy is increasingly being made in the states.” More than a dozen states — including Connecticut, Massachusetts, Rhode Island and Vermont in New England — have joined the U.S. Climate Alliance, with pledges to meet the Paris commitments on carbon emission reductions. (See related story, Trump Pulling U.S. Out of Paris Climate Accord.)
“There always seems to be one topic that sucks a lot of the air out of the room. I remember back when it was integrated resource planning and whether it worked. When I first came to FERC it was demand response,” she said. “Well now it’s this. … I do think this is one of the bigger things that FERC will be facing when FERC reconstitutes itself.”
Powelson, a member and former chair of the Pennsylvania Public Utility Commission, is the current president of the National Association of Regulatory Utility Commissioners. Chatterjee, of Kentucky, is a senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.).
Assuming the nominees clear the committee vote, how soon they join the commission will be dependent on when their nominations are scheduled for a Senate floor vote.
The commission canceled its open meeting for June 20, as it has all previous meetings since February. The July 20 meeting is still listed on FERC’s calendar.
LaFleur repeated her promise to remain on the commission until the expiration of her term in June 2019.
“I’m very optimistic that we will keep the bipartisan and collegial tradition that has really characterized the commission. I think cultures are slow to change. There’s a lot of swirl in Washington right now, but I believe that FERC is very strong.”
Developers of certain hydroelectric projects can feasibly get federal approval within two years under current regulations, FERC staff said last week.
With the passage of the Hydropower Regulatory Efficiency Act of 2013, Congress directed FERC to study the feasibility of implementing a two-year process for issuing hydropower licenses to non-powered dams and closed-loop pumped storage projects.
After conducting a pilot program, FERC staff determined the time frame is doable, noting that “site selection, a well-defined project proposal, thorough pre-filing consultation and a complete application” are the most important elements.
Staff said that updating and improving the “small/low-impact hydropower” portion of its website would expedite the process.
“Staff also commits to providing more frequent processing updates, when appropriate, to provide additional clarity and certainty during the licensing process,” the report said.
Eligible projects under the program were required to be at a non-powered dam or closed-loop storage project, have a well-developed proposal, result in little environmental impact and be in areas with substantial information on environmental resources and effects.
FERC staff determined in August 2014 that Rye Development’s Kentucky Lock and Dam No. 11 project met the criteria and issued the project a license in May 2016. The 5-MW capacity project will generate about 19,000 MWh annually.
Kentucky Dam and Lock 11 Hydropower Project | Rye Development
Staff also examined processing times for 83 projects that were issued licenses or small hydropower exceptions between 2003 and 2016. Evaluations of 28% of these projects were completed in two years or less, with a median processing time of 1.4 years. Projects that were not licensed in two years tended to be larger, more complex and had more issues to examine.
A majority of commenters agreed the pilot was a success and that it is feasible to implement a formal two-year licensing program, staff said. Changes to the Federal Power Act are not required, but factors outside of FERC’s control, such as the actions of other agencies, could affect permitting timelines, according to the report.
The Senate Energy and Natural Resources Committee voted 20-3 Tuesday to advance Neil Chatterjee and Robert Powelson, President Trump’s nominees for FERC.
Senate Energy and Natural Resources Committee
Sens. Ron Wyden (D-Ore.), Bernie Sanders (I-Vt.) and Mazie Hirono (D-Hawaii) voted no.
Murkowski
“Both FERC nominees failed to commit to avoiding political interference from the White House or maximizing public engagement in proposed energy projects,” Wyden said. “Given FERC’s important role in energy infrastructure in Oregon and communities across the country, I am also concerned that nominating commissioners from only one political party is a signal from the White House that it has no intention of ensuring FERC continues as the bipartisan and independent agency it has long been. I will continue to insist FERC considers local voices in its decisions and that the administration moves beyond politics to keep FERC bipartisan and independent.”
Otherwise, the nominees received bipartisan support.
Cantwell
“I am assured both have understood the important role that FERC plays in ensuring fair markets and guarding against market manipulation,” said Sen. Maria Cantwell (D-Wash.), the committee’s ranking member.
This prompted Ted Glick, of environmental group Beyond Extreme Energy, to interrupt the meeting with shouts of protest against FERC. The hearing was interrupted two more times.
The committee also advanced Trump’s nominees for deputy secretary of energy and deputy secretary of the interior, Dan Brouillette and David Bernhardt respectively, mostly on party line votes. The committee voted 17-6 for Brouillette and 14-9 for Bernhardt.
RENSSELAER, N.Y. — NYISO and adjacent grids will likely be able to serve load throughout summer based on historical performance of generation and transmission infrastructure, the ISO reported last week.
However, an unlikely scenario of extreme heat could pose challenges for system capacity reserves, if not the system itself, according to the ISO’s Summer 2017 Capacity Assessment.
Under a baseline scenario in which this summer’s load peaks at 33,178 MW, NYISO expects to have a capacity margin of 386 MW, down 746 MW from the 2016 baseline forecast. The positive margin represents the amount of surplus generation available after factoring in peak load plus a required 2,620 MW of operating reserves.
Under extreme weather conditions — the 90th percentile forecast — the ISO predicts a capacity shortfall of 1,924 MW, compared with a 1,191-MW shortfall in last summer’s forecast.
“That’s taking the 90th percentile peak forecast, which is a very large peak, adding 2,620 of reserve requirement, saying that’s the requirement on a day-ahead basis, and then comparing it to that available capacity,” Wes Yeomans, NYISO vice president of operations, said during a May 31 meeting of the Management Committee.
Despite the expected deficiency under those conditions, the ISO expects it could avoid involuntary load curtailments by relying on up to 3,083 MW of demand resources available under emergency procedures.
NYISO activated demand response during its all-time summer peak of 33,956 MW in July 2013, which would have hit 34,900 MW without DR, Yeomans said.
| NYISO
Yeomans explained that the 90th percentile projection slightly exceeds NYISO’s all-time high. For an extreme heatwave, the capacity requirement would reach 38,000 MW.
“If we compare that against the capacity resources assuming 4,800 MW of derates — and we may or may not have that amount in a very hot heatwave — on paper we would be short on capacity by about 1,900 MW … but we have at least 3,000 MW of emergency operating procedures we would activate to make up that difference,” he said. (See New York Geared for 2017 Summer Load.)
MC Approves Funding 2nd PAR at Ramapo
The Management Committee approved a Tariff modification to fund Consolidated Edison’s replacement and operation of the Ramapo 3500 phase angle regulator, destroyed in a fire last June, as well as the operating expenses for the existing PAR at the substation close to the New Jersey border. The estimated $5.5 million in annual costs will be allocated statewide across all New York load-serving entities, but they would be reimbursed with any monies eventually paid by PJM, PJM transmission owners or refunded by Con Ed.
Mark Younger of Hudson Energy Economics asked for a definite commitment from either Con Ed or NYISO on the timeline for installation.
Jane Quinn of Con Ed said that upon an affirmative vote, the company will begin moving the PAR into place, which should take three to four weeks. Installation should take an additional eight to 10 weeks.
“We anticipate having the PAR, absent contingencies, in place on or around September 15,” Quinn said. (See “Con Edison Gets Approval to Install 2nd PAR at Ramapo,” NYISO Business Issues Committee Briefs.)
Market Participants to Review Monitor’s Performance
Shaun Johnson, NYISO director of market mitigation, asked market participants to join in an annual review of the Market Monitoring Unit’s performance.
NYISO last year signed a three-year contract with Potomac Economics to perform monitoring functions through March 31, 2019. The MMU’s duties include ensuring that the markets administered by NYISO function efficiently and appropriately, as well as identifying market violations, market design flaws and market power abuses. The Monitor also produces annual and quarterly State of the Market reports assessing the performance of the New York electrical markets.
The budget for the MMU for 2017 is $3.5 million, up $400,000 over last year. Most of the additional costs cover additional work related to cybersecurity and new requirements mandated by reliability-must-run and FERCOrder 1000 filings.
One participant said that Potomac sometimes shows up at FERC and protests what NYISO is doing.
“Something just seems at odds there, that we’re paying a company $3.5 million a year and we’re fighting with them at FERC,” he said.
Such action is part of the duties of an MMU, according to NYISO, and one thing FERC cited in a recent review of the SPP Monitor was the lack of reporting on disagreements with the grid operator.
Tariff Changes on Tx Cost Recovery
The Management Committee approved proposed Tariff revisions to add a mechanism to recover and remit costs associated with regulated transmission projects eligible under the ISO’s Congestion Assessment and Resource Integration Study or the public policy transmission planning process. Following board approval in July, the revisions to the cost recovery mechanism for regulated transmission projects under Rate Schedule 10 — and related amendments to the Tariff’s Attachment Y — would be filed with FERC under Section 205 of the Federal Power Act.
The Rate Schedule 10 revisions establish a new regulated transmission facilities charge (RTFC) to LSEs, with payments allocated to developers of such projects.
John P. Buechler, NYISO regulatory policy adviser, said the revisions do not in any way “affect or change the cost allocation provisions, which, relevant to our transmission planning process, are in Attachment Y, Section 31.5.”
Eligible projects include:
Regulated backstop transmission solutions proposed by a responsible transmission owner;
An alternative solution NYISO selects as a more efficient or cost-effective solution to a reliability need;
A regulated transmission gap solution proposed by a responsible TO;
An alternative regulated transmission gap solution determined by an appropriate state regulatory agency;
An approved regulated economic transmission project;
A public policy transmission project selected by NYISO;
Costs incurred by a developer in preparing a proposed transmission solution in response to a request by the Public Service Commission or Long Island Power Authority; and
The portion of an interregional transmission project selected by NYISO in the Comprehensive System Planning Process that is allocated to the NYISO region.
NYISO will calculate and bill an RTFC separately for each eligible project.
NYISO to Enhance Buyer-side Mitigation
The committee approved proposed Market Services Tariff changes to improve inflation forecasting and how mothballed units are treated in the capacity and energy forecast used to make buyer-side mitigation determinations.
The committee recommended that the Board of Directors authorize revisions to buyer-side mitigation rules in the Market Services Tariff, which would then be filed with FERC under Section 205 of the Federal Power Act.
In FERC docket ER13-1380, filed in 2013 to create NYISO’s G-J locality, the commission determined that such an enhancement was outside the scope of the docket but encouraged the ISO to work with stakeholders on the issue.
NYISO analyst Lorenzo Seirup presented the rationale for mitigation enhancements and said that, since the topic first arose in 2013, “we discussed this ad nauseam and also had a vote that failed and then a vote that passed — that’s the 30-second highlights.”
The proposal would include in the forecasts existing units as well as additional units, “which is the more complicated” category, Seirup said. Units that would be excluded are those transferring their capacity resource interconnection service (CRIS) or that have expired CRIS.
Additional units include mothballed facilities, units under forced outages, retired units and those in similar condition with unforced capacity deliverability rights. These additional units either must have CRIS or show positive indicators of repair or have a new present value greater than $0 in the “inclusion test” performed for resources that have the ability to re-enter the market under more favorable conditions.
The Tariff changes on inflation would call for use of the most recently published 10-year inflation projections from the Survey of Professional Forecasters, or if no longer available, a similar source to identify net cost of new entry projected for the mitigation study period, and the price on the installed capacity demand curve projected for such a period.
DALLAS — SPP’s Strategic Planning Committee last week ended more than nine months of discussion on cost shifts within existing transmission pricing zones, agreeing unanimously to let the Markets and Operations Policy Committee take up the issue when it meets in July.
The agreement represented a victory of sorts for Kansas City Power & Light’s Denise Buffington, who has drafted a revision request that would create a process for choosing the zone for a new SPP transmission owner’s facilities, and how to submit the TO’s annual transmission revenue requirement (ATRR) or formula rate to FERC for inclusion in the Tariff.
RR172 has been sidelined since October, when it was pulled from the Regional Tariff Working Group (RTWG) and placed on the SPC’s agenda for discussion. (See SPP Moves to Head off KCP&L Measure on Tx Cost Shifts.)
While Buffington will get her long-awaited up-or-down vote on the measure, she told RTO Insider she was still disappointed RR172 had been delayed and that KCP&L’s concerns about “unnecessary and unfair” cost shifts to existing TOs were not addressed.
“I expect a robust debate at MOPC,” she said. “But I expect the ultimate resolution will need to be addressed by FERC and, potentially, the courts.”
The committee, meeting at American Electric Power’s Dallas office, accepted a motion from Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission, to conclude the discussion as it became apparent stakeholders would not agree on anything beyond directing staff to use a process document to codify previously approved steps for notifying affected parties of zonal placement decisions. The communications process was approved when the SPC last met in April. (See No Consensus for SPP on Zonal Price Shifts.)
“It’s clear there are issues we can agree upon and issues we can’t agree upon,” Starnes said, reminding the committee that KCP&L’s proposal is still “technically” on the RTWG’s agenda. “Ending discussions of those issues allows RR172 to move directly to MOPC.”
SPP COO Carl Monroe stressed the need to provide a structure for the MOPC to debate KCP&L’s request, suggesting bringing the request up through the stakeholder process and the RTWG. Among Monroe’s concerns were having the MOPC vote on Tariff language that had not already cleared a working group.
Buffington noted RR172 includes proposed Tariff language that she said would be revised to include the discussions before the SPC.
“MOPC can vote on the Tariff language,” she said. “RR172 includes not just the policy issue, but Tariff language that solves the policy problem.”
American Electric Power’s Richard Ross, who seconded Starnes’ motion, pointed out SPP’s working groups don’t decide policy but recommend it.
“There’s only one group that decides policy. It stops at the board, or it goes all the way to FERC,” he said. “I’m all for letting KCP&L have their shot at the process. … Kansas City or John Doe or whoever submits a revision request has their right … to put it through the stakeholder process. They shouldn’t be put in limbo indefinitely. If KCP&L doesn’t get their way at MOPC, they can appeal it to the board.”
“It seems like a member has been allowed to bring an issue directly to MOPC before when a working group failed to approve a request,” said the Nebraska Public Power District’s Paul Malone, who also chairs the MOPC. “I would think that’s the case here too.”
Larry Altenbaumer, one of three SPP directors present at the meeting, weighed in on the issue as well. He advocated having RR172 presented to the MOPC, “where there’s better representation and broader membership.”
“MOPC can decide where it goes,” Altenbaumer said. “I don’t think sticking it in some working group is the right answer.”
“I want a policy decision from MOPC and the board,” Buffington said. “I want an up-and-down vote, where all members have an opportunity to vote on it. If the board ultimately approves it, or through modifications, my expectation is SPP will file it at FERC. … I would ask this group complete its work so I can move forward with my proposal.”
By codifying SPP’s zonal selection criteria in the Tariff, KCP&L says RR172 strikes a balance between attracting new transmission-owning customers to SPP and eliminating the ability for them to shift costs to existing members. The revision is intended to establish a bright line between the costs of legacy transmission and new facilities planned by SPP.
The SPC’s eventual agreement helped short-circuit a series of examples for how staff would handle zonal cost shifts under various scenarios. Staff’s suggestion that there was value in walking through six more examples following a lunch break left one stakeholder wide-eyed and slack-jawed in apparent horror.
Staff has proposed zonal-placement criteria that included:
Whether the facilities’ ATRR is less than the minimum zonal ATRR;
The extent to which the facilities substantively increase the SPP footprint; and
The extent to which the load served by the transferring facilities received network or long-term, firm point-to-point (PTP) service within existing zones before the transfer.
If not placed in a new zone, the facilities would be placed in an integration zone according to:
The extent to which the facilities are embedded within an existing zone;
The extent to which the facilities are already integrated with an existing zone; and
The extent to which the load served by the transferring facilities received network or long-term, firm PTP service within each existing zone prior to the transfer.
Staff will continue working on assessments to determine whether a new member’s facilities meet minimum system reliability requirements, and whether they are similar in design to the integration zone’s facilities and are eligible for inclusion in the existing zonal TO’s ATRR.
CARMEL, Ind. — MISO is asking FERC to schedule a technical conference to clarify the rules governing the implementation and use of pseudo-ties.
The RTO made the request in a May 26 filing under two dockets: PJM’s proposal to apply more stringent requirements on external capacity resources (ER17-1138) and MISO’s proposed pro forma pseudo-tie agreement (ER17-1061). FERC sent deficiency notices seeking more information in response to both initiatives.
MISO said a technical conference could “provide a foundational understanding of pseudo-ties, their application, and the challenges they pose” and help FERC “better understand the benefits of pseudo-ties, the potential impacts pseudo-ties have on reliability and efficiency of market operations, and the current status of coordination between neighboring RTOs.”
“We talked about these things for two years now, and there are still questions,” MISO Senior Director of Regional Operations David Zwergel said at a June 1 Reliability Subcommittee meeting.
MISO’s Independent Market Monitor, who wants FERC to eliminate PJM’s requirement that external resources be pseudo-tied, joined in the call for a technical conference. “What we would like the technical conference to make clear is … there are potential alternatives that should be considered to pseudo-ties. What we hope comes out of this conference is a full hearing of the cost and the benefits,” said Michael Wander of IMM Potomac Economics.
The request comes as PJM and MISO are still working on draft joint operating agreement changes to create a standard pseudo-tie definition and rule set. (See MISO, PJM to Try Again on FERC Pseudo-Tie Filings.)
The joint language, which has not been released to stakeholders, will remove the need for MISO to sign off on PJM’s proposed pro forma pseudo-tie agreement. Late last year, MISO staff said there was no need to write standardized pseudo-tie definitions into the RTOs’ JOA; by early spring, the RTOs had agreed to add coordinated pseudo-tie policies to their JOA.
Zwergel said MISO is hoping to file the JOA in the next few months. “Good progress has been made,” he said.
While it awaits FERC’s decision on a technical conference, MISO will respond to the deficiency letter on its pro forma filing by June 12, he said.
State officials in New England said last week that only they should have the ability to identify public policy-driven transmission needs for evaluation by ISO-NE.
“The plain language of [ISO-NE’s Tariff] designates NESCOE as the entity that identifies whether there are state or federal public policies driving transmission needs and, in turn, whether a public policy transmission study should be commenced to evaluate potential solutions,” the New England States Committee on Electricity said in a June 1 rebuttal to the Conservation Law Foundation.
CLF Senior Attorney David Ismay asked ISO-NE on May 16 to conduct a study to determine public policy transmission needs despite NESCOE’s contention that there are currently no such needs. (See CLF to ISO-NE: Override States, Order Public Policy Tx Study.)
Ismay said a D.C. Circuit Court of Appeals ruling in April confirmed the responsibility of ISO-NE, “not the states, to evaluate transmission needs and potential solutions as part of its Regional System Plan process, regardless of whether those transmission needs arise from state public policy requirements or any other source” (Emera Maine v. FERC, No. 15-1139). (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
Misreading of Order 1000
| Massachusetts Clean Energy Center
NESCOE responded that “CLF misunderstands the Order 1000 process … and has conflated the process for evaluating solutions to policy-driven transmission needs with the process of identifying if there are any needs in the first place. Emera imposes no requirements on ISO-NE to determine public policy requirements driving transmission needs and directed no changes to the [Open Access Transmission Tariff].
“CLF mistakenly claims that Emera requires ‘ISO-NE to make its own determination … regarding the existence of [public policy requirements] that are driving, or may drive, transmission needs relating to the New England transmission system.’”
NESCOE said that ISO-NE’s rules on the identification of policy needs have never been in controversy, were not before the court and that FERC itself had affirmed to the court NESCOE’s role in that process. “If anything … Emera affirms the process reflected in the current OATT whereby NESCOE must first identify a state policy driving a transmission need before ISO-NE begins expending consumer dollars on evaluating a need. As Emera plainly states, ‘ISO-NE has no role in setting public policy for the states.’”
The organization closed its response by bemoaning CLF’s request as “precisely the kind of after-the-fact market participant action that causes the states serious pause in using a FERC-jurisdictional tariff to achieve their clean energy requirements.”
ISO-NE Director of Transmission Planning Brent Oberlin had told the Interregional Planning Stakeholder Advisory Committee for New England, NYISO and PJM on May 19 that if the RTO decides to conduct a public policy transmission study, it will need to provide a scope to stakeholders by Sept. 1.
California has moved a step closer to adopting a 100% clean energy standard.
The State Senate on Wednesday passed a bill that would require California load-serving entities to obtain all of their electricity deliveries from renewable resources by 2045 (SB 100).
de León
Sponsored by Senate President pro Tempore Kevin de León, a Los Angeles Democrat, the bill passed 25-13 along party lines. It now moves to the State Assembly.
“When it comes to our clean air and climate change, we are not backing down,” de León said in a statement. “Today, we passed the most ambitious target in the world to expand clean energy and put Californians to work.”
De León said it is now critical for California to “double down on climate leadership” given President Trump’s announcement today that the U.S. would withdraw from the Paris Agreement on climate change. (See related story, Trump Pulling U.S. Out of Paris Climate Accord.)
“We are sending a clear message to the rest of the world that no president, no matter how desperately they try to ignore reality, can halt our progress,” he said.
The new bill would accelerate the timeline for California’s current 50% RPS from 2030 to 2026, with an interim 45% goal put in place for 2023. The 2030 requirement would increase to 60%, and the bill gives the California Energy Commission discretion to establish “appropriate” three-year compliance periods subsequent to 2030.
The bill also directs state agencies to incorporate the planning goal into any energy and climate programs subject to their jurisdiction, which would include the utility integrated resource plans administered by the PUC.
Passage of the bill got expected support from environmental groups and advocates for renewable energy.
“Getting 100% renewable is 100% possible and 200% necessary,” said Kathryn Phillips, director of Sierra Club California. “SB 100 responds to what survey after survey shows that Californians want: clean energy, clean air and a future for the next generation.”
Strela Cervas, co-director of the California Environmental Justice Alliance, said the proposed law would move California away from fossil fuels that that have a disproportionate impact on disadvantaged communities and communities of color.
“The bill charts a pathway for the public health and economic benefits of local renewable energy to reach communities that need it the most,” Cervas said.
“Transitioning to a 100% carbon-free future in an economy the size of California’s requires persistence, commitment and vision,” said Bernadette Del Chiaro, executive director of the California Solar Energy Industries Association.
Solar Field | Sunworks
In urging his colleagues to vote against the bill, Republican Sen. Jeff Stone warned that the state might be getting ahead of its ability to actually implement a 100% RPS.
“If we don’t have the science to back up the methodology to get to 2030 with 60% coming from renewables, then it’s going to increase costs for our constituents,” Stone said. “We need to let the technology drive the innovations in alternative energy and not put mandates out there that may be unachievable.”
If it becomes law, the bill would make California the second state after Hawaii to require LSEs to rely on 100% renewables by 2045.
The Los Angeles Department of Water and Power (LADWP) on Thursday agreed to join the Western Energy Imbalance Market (EIM), adding the country’s largest municipal utility to the growing electricity market.
LADWP is the 11th utility to announce plans to participate in the CAISO-run market, which is designed to better balance supply and demand across the region by making more electricity resources available in real time.
LADWP General Manager David Wright touted the benefits of joining with other utilities across the western U.S. to more reliably integrate renewable energy resources.
“We are pleased to enter the EIM in what will be a solid step forward in partnering with our neighbors to find benefits for the City of Los Angeles,” Wright said in a statement.
While LADWP expects to begin participating in the market in April 2019, that timeline could be extended an additional year to accommodate the utility’s unique configuration and required upgrades. A separate agreement will have to be made once the LADWP system is integrated into the EIM.
Total implementation costs are estimated at $15 million to $20 million, and recurring expenses are projected at about $2.3 million per year. Third-party analysis pegged annual savings for ratepayers at $2 million to $5 million.
About 40% of LADWP’s 7,600 MW of capacity is coal-fired, 20% renewable, 22% natural gas-fired, 9% nuclear and 7% classified as “other.” The municipal utility began distributing electricity in 1917 and serves about 4 million customers.
The utility also individually or jointly controls about 4,600 miles of transmission, which includes the Pacific DC Intertie connecting Southern California with the Bonneville Power Administration system in the Northwest and the Intermountain DC system that carries output from coal-fired generation in Utah.
| CAISO
Already participating in the EIM are PacifiCorp, NV Energy, Puget Sound Energy and Arizona Public Service. Portland General Electric is due to join in October; Idaho Power in April 2018; Seattle City Light and Balancing Authority of Northern California/Sacramento Municipal Utility District in April 2019; and Salt River Project in April 2020.
Vancouver-based Powerex earlier this week became the first non-U.S. entity to announce its intention to join the market starting next spring. (See Powerex Slated to Become First Non-US EIM Member.)
The EIM began operating in November 2014 and now includes participants in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming. CAISO estimates the market has so far produced approximately $173 million in gross benefits for its members.
SPP stakeholders approved a revision request Tuesday that allows the RTO to lower its planning reserve margin as it waits on a quorum-less FERC to act on a proposed Tariff change.
The Markets and Operations Policy Committee approved RR230 during a special conference call, changing SPP’s criteria to allow it to reduce the planning reserve margin to 12% from 13.6% effective June 1.
The new reserve margin was included in SPP’s March filing asking FERC to approve the changes effective June 1 (ER17-1098). SPP COO Carl Monroe said the RTO had yet to hear from the commission, necessitating a vote on an interim solution.
“We don’t know why they haven’t acted … we assume because of a lack of quorum,” Monroe said during the hour-long conference call.
On Wednesday, FERC responded by saying SPP’s resource-adequacy requirement filing was deficient and that additional information is required to process the request. The commission listed 18 questions to be addressed related to:
SPP’s firm power, firm capacity and net peak demand requirements.
How market participants may assign their obligations and responsibilities to other market participants.
The RTO’s annual deliverability study that determines the load a resource may deliver to the balancing authority area without effecting reliability or requiring additional transmission upgrades.
Deficiency payments and distributions of revenues.
FERC has been operating with only two commissioners since February, when former Chairman Norman Bay resigned and left the commission with three vacancies. The Trump administration only recently nominated two commissioners, who went through confirmation hearings last week. (See No Fireworks for FERC Nominees at Senate Hearing.)
SPP stakeholders resisted staff’s initial request to approve RR230 by an email vote, made when it became likely FERC was not going to act by the effective date. American Electric Power, Westar Energy, Kansas City Power & Light, Oklahoma Gas & Electric and Duke Energy were among those requesting further discussion.
Westar Energy’s Murray Gill Energy Center near Wichita, Kansas | Westar
“I feel like we’re pushing something through that would be better in a thought-out process,” Westar’s John Olsen said. “It’s a little item, but I don’t know what the unintended consequences are. If FERC doesn’t approve [the proposed Tariff] language, then where are we at?”
“Had this been advanced as an issue by OGE rather than staff … I would have worked with [OGE] beforehand,” AEP’s Richard Ross said.
As it was, Ross worked with OGE Energy’s Greg McAuley, Omaha Public Power District’s Joe Lang and Midwest Energy’s Bill Dowling to hammer out the final motion’s language. A key addition was language making RR230 effective for only 10 business days after FERC rules on SPP’s filing.
Members overwhelmingly approved the motion, with only five opposing votes and two abstentions.
RR230 earlier cleared the Supply Adequacy, Transmission, and Regional Compliance working groups with two opposing votes and three abstentions.
SPP’s filing came after the MOPC and the Board of Directors in January approved a package of policies that included the 12% planning reserve margin, which translates to a 10.7% capacity margin.
A task force spent two years on that package, which it says will reduce the RTO’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
The original revision request incorporated previously approved policies defining a resource adequacy requirement, identifying who is responsible for resource adequacy, and how and when the requirement should be met. The policies are to become effective this summer, with the exception of an assurance policy requiring entities short on their planning reserve margins to make payments to entities with excess capacity, based on forecasted information.
Members agreed to use 2017 as a “dry run” for the resource adequacy process.
LADWP is the 11th utility to announce plans to participate in the 
