Page 1435 – RTO Insider

December 21, 2017

MISO Competitive Tx Task Team Concludes Work

By Amanda Durish Cook

A MISO task team is slated for retirement after successfully developing several changes to the RTO’s competitive transmission process that were approved by FERC.

The Planning Advisory Committee on Tuesday passed a motion recommending that the Steering Committee approve the immediate retirement of the Competitive Transmission Task Team. Six sectors voted in favor with three abstaining.

Pedersen at the MISO PAC in May 2017 | © *RTO Insider*

Brian Pedersen, MISO senior manager of competitive transmission administration, said the task team has completed its work to improve the selection process behind competitive transmission projects. The team was created last December days after the conclusion of the RTO’s first competitive process, for the Duff-Coleman 345-kV transmission project in southern Indiana and western Kentucky. (See LS Power Unit Wins MISO’s First Competitive Project.)

“In 2017, we sought out incremental operational changes to scale our competitive transmission process. From our perspective, this has been a successful process,” Pedersen said during a Dec. 19 PAC conference call.

Consequently, MISO submitted five FERC filings to amend the competitive process portions of its Tariff — all of which were accepted without changes by the commission. (See FERC OKs Changes to MISO Competitive Tx Process.)

The changes allow the RTO to:

Review and weight competitive projects that contain both substation and transmission line facilities (ER18-44);
Stagger its current proposal submission and evaluation timelines should the RTO encounter two simultaneous competitive projects (ER18-41);
Replace the annual qualified competitive transmission developer recertification process with a biennial process (ER18-40); and
Request a description of safety measures transmission developers will take during both construction and operations and maintenance (ER18-42).

A fifth filing was made to correct grammar, citation and formatting errors (ER18-39).

MISO updated its Business Practices Manuals and request for proposal forms to align with the changes, Pedersen said. He added that MISO will still take up any future stakeholder improvement suggestions “as conditions permit.”

Pedersen said the changes will be in effect for MISO’s second-ever competitive project, the $130 million Hartburg-Sabine 500-kV line market efficiency project in eastern Texas, which will be bid out in early 2018. MISO has hired two new employees to help with the evaluation and selection process for the project, which includes substation construction — a first for its competitive projects.

The project — originally intended to be approved with MISO’s 2017 Transmission Expansion Plan — is currently subject to an approval delay while the RTO awaits a FERC decision on separating cost allocation zones in Texas and Louisiana. (See MISO Board Approves $2.6B Transmission Spending Package.) The Board of Directors has pledged to approve the project no later than Feb. 5, and the RTO plans to issue its RFP on Feb. 6. The window for proposals will be open until July 20, with MISO expecting to announce a developer no later than Jan. 2, 2019.

Pedersen said the Hartburg-Sabine project will be evaluated similarly to last year’s evaluation of the Duff-Coleman project, with cost and design details weighted at 30%, project implementation at 35%, operations and maintenance at 30%, and transmission planning participation at 5%.

Forty-seven existing qualified developers will not be required to recertify next year after FERC accepted MISO’s biennial qualification process, although Pedersen said developers must still disclose annual audited financial statements along with statements of any material changes to keep the RTO aware of developments such as bankruptcies or business name changes.

Queue Task Force Extension

PAC sectors also voted overwhelmingly to extend the RTO’s Interconnection Process Task Force through December 2018. The group will oversee and suggest further improvements to MISO’s major queue process changes made at the beginning of this year. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)

December 21, 2017October 31, 2023

Mass. Receives Three OSW Proposals, Including Storage, Tx

By Michael Kuser and Rich Heidorn Jr.

BOSTON — Three developers submitted proposals Wednesday in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.

The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)

| BithEnergy

The state’s first request for proposals (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”

The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management.

Bay State Wind

Bay State Wind, a joint venture between Ørsted and Eversource, proposed a 400-MW or 800-MW wind farm 25 miles off of New Bedford. It would be paired with a 55-MW battery storage facility, “the largest battery storage system ever deployed in conjunction with a wind farm,” it said.

Ørsted, formerly DONG Energy, is the No. 1 offshore wind generator in the world. The company would use New Bedford as the staging area for construction and the base of its operations and maintenance through the wind farm’s lifetime. The storage facility and an onshore substation would be located in Somerset.

Deepwater Wind

Deepwater Wind’s proposal would firm its project’s wind output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.

Interior of Northfield Mountain pumped storage facility | Northfield Mountain

Deepwater proposed two versions of Revolution Wind, a wind farm of approximately 25 turbines to generate 200 MW, or double that size to generate 400 MW. The company had proposed an initial 144-MW phase of the project in response to the state’s 83D solicitation for 9.45 million MWh of clean energy. The state is due to announce winners of that RFP on Jan. 25.

Deepwater is the developer of the Block Island Wind Farm off Rhode Island, the nation’s first commercial offshore wind farm. It also partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)

The company’s project would connect to land at the Brayton Point substation in Somerset.

Vineyard Wind

Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, is betting that its promise to deliver an operating project by 2019 will win the state’s favor. It submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. Avangrid owns Unitil.

| BOEM

Vineyard Wind said it has already submitted applications with BOEM and the state Department of Public Utilities’ Energy Facilities Siting Board for the wind farm, about 15 miles south of Martha’s Vineyard. “By filing for construction permits, Vineyard Wind is on track to complete the permitting process in time to begin construction in 2019,” it said.

Deepwater said if it is selected it would begin construction in 2022, with the project in operation in 2023. Bay State did not mention a timeline in its press release.

The state will announce the winners of the offshore wind solicitation on April 23, 2018, and contracts are to be submitted at the end of July.

This month saw an early offshore wind project, Cape Wind, exit the stage. It announced Dec. 1 that it had notified BOEM it was stopping development of its proposed wind farm project in the Nantucket Sound and filing to terminate its offshore lease issued in 2010.

Nevertheless, the state’s solicitation has been a cause for optimism among green energy advocates, who note the attractiveness of the Atlantic’s strong winds and shallow waters. (See ‘Momentum’ Seen for U.S. Offshore Wind.)

December 21, 2017

Entergy Asks FERC to Clarify Indian Point Retirement Process

By Michael Kuser

Entergy on Monday asked FERC to clarify the deadline for NYISO to complete a final market power review for the deactivation of the Indian Point nuclear plant, or grant the company’s request to rehear the commission’s approval of a previous ISO compliance filing (ER16-120, EL15-37).

Market Power Review Indian Point Entergy — | *Entergy*

At issue is FERC’s November conditional acceptance of NYISO tariff revisions to implement a new reliability-must-run program. (See FERC Approves NYISO Reliability-Must-Run Plan.) The ISO in September submitted a compliance filing to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. The commission had accepted an earlier compliance filing for the proposal, but in April 2016 directed NYISO to make further changes to the program.

In its Dec. 18 filing with FERC, Entergy said that while NYISO’s second compliance filing contained a 90-day deadline for completing reliability studies related to plant shutdowns, it did not contain a provision for a 120-day market power review deadline included in the first compliance filing. As a result, the commission’s Nov. 16 order was “arbitrary, capricious, unsupported by substantial evidence and not a result of reasoned decision-making” because FERC conditionally accepted the ISO’s compliance filings without requiring it to establish a clear deadline early in the process for deactivating generators, the company argued.

Entergy contended that without a clear deadline for review, the 2,311-MW Indian Point plant lacked certainty about its authorization to exit the market in accordance with NYISO’s tariffs.

“At the very least, the NYISO should be held to its own assertions,” Entergy said. “Here, the NYISO has emphasized the need to perform any necessary market power review at the start of this process and has expressly confirmed its ability to complete this analysis in the first four months after receiving a completed generator deactivation notice … [and] a final market power review both in presentations to stakeholders and pleadings before this commission.”

The company is seeking a March 13, 2018, deadline for NYISO to complete a market power study for the closure of the Indian Point.

An ISO report earlier this month found that new gas-fired and dual-fuel generation coming online in the next few years, led by the 1,020-MW Cricket Valley plant in Zone G, will provide sufficient capacity to maintain reliability after Indian Point shuts down completely in 2021. (See New Builds to Cover Indian Point Closure, NYISO Finds.)

December 21, 2017February 19, 2025

NJ Nuclear Subsidy Bill Moves Swiftly out of Committee

By Rory D. Sweeney

TRENTON, N.J. — If opponents of nuclear subsidies in New Jersey had an opportunity to sway the opinions of state legislators on the issue, it didn’t last long.

During a joint meeting Wednesday of the state Senate Environment and Energy Committee and Assembly Telecommunications and Utilities Committee, members early on indicated their support for a bill that would provide hundreds of millions of dollars in financial support to state nuclear plants. (See Nuke Bailout Bill Introduced in NJ Senate.)

pseg new jersey subsidies nuclear plants — PSEG CEO Ralph Izzo testifying at the NJ Legislative Hearing on Nuclear Subsidies | © *RTO Insider*

After five hours of testimony, their opinions had not changed. Both committees unanimously voted to move the bill to their respective legislative bodies. ClearView Energy Partners, an energy research firm, said in a statement that the legislature could vote on the bill before the end of next week. It predicted Gov. Chris Christie would sign the bill into law before he leaves office on Jan. 16.

“There’s this constant question about ‘why now?’ The answer is: It’s one of the greenest bills we’ve run into in a long time, and No. 2, we can get it done,” said Sen. Bob Smith, who chairs the Environment and Energy Committee.

Opponents argued that the bill required no commitments from Public Service Enterprise Group, such as a plan for a transition to renewable energy when the plants are eventually decommissioned or a mechanism for the company to pay back any money if market conditions change to make its nuclear plants profitable again.

“You’re feeding the problem that this country faces right now with Donald Trump. We are losing faith in government, and if you [approve] this bill during lame duck, you are part of the problem,” said Doug O’Malley, director of Environment New Jersey. “So hold the bill. Let’s do this right in January, February and March.”

PSEG CEO Ralph Izzo opened the hearing by assuring legislators that enacting the bill was a vote of confidence for his company to commit years ahead of time to investing as much as $200 million annually for the plants’ supply chains.

“There’s been a lot of discussion about this being an automatic handout to utilities. That is not true,” Izzo said, noting that it will be at least 300 days until PSEG will know if its plants qualify for the subsidies proposed under the bill. “Over that time, we will have to decide whether or not to invest between $100 [million] and $200 million in those plants and make an estimate as to whether or not those plants will continue to operate for the remaining 20 or 30 years of their life to make that money back.”

PSEG currently has $275 million in commitments for fuel-related expenses until 2025, he said, and must decide over the next year whether it will commit to keeping the plants open through 2021.

“This is not a rush. This has been an eight-year discussion,” Izzo said. “I encourage you to recognize that driving the vehicle by exclusively focusing on the rear-view mirror is not the safest way to proceed. Most companies look forward on the prospects of their assets.”

Izzo’s comments were rebutted by Stefanie Brand, director of the New Jersey Division of Rate Counsel, who argued that the bill is unclear on how much money PSEG should make or how unprofitable the plants will be without support. Izzo said they will remain profitable at least until next year when a number of PSEG’s energy contract hedges expire.

“There are offramps for the company. There are no offramps for the ratepayers,” she said. ““I’m not advocating for [the plants] to close. I’m advocating for a system that doesn’t allow a single company to hold us hostage in this way.”

Senate President Stephen Sweeney grilled Brand on her concerns, asking whether she thought the state Board of Public Utilities, which would oversee distribution of the plan’s nuclear diversity certificates (NDCs), is capable of fulfilling that role. Brand said it was impossible to know because eligible plants could submit information confidentially without public review. She noted that the subsidized plants would also likely be subject to PJM’s minimum offer price rule (MOPR).

“The rest of us don’t have the information that PSEG does to claim they’ll close. … The consumer protections in this bill are really a delusion,” Brand said. PSEG is “deregulated, so there is no set cost of capital that they are set to earn.”

She added that out-of-state plants, such as Exelon’s Three Mile Island plant in Pennsylvania, might be eligible for the subsidy the way the bill is currently written.

Industry analysts also traded opposing studies on the issue. Dean Murphy with The Brattle Group outlined a study sponsored by PSEG and Exelon that argues it would be cheaper to pay to keep the plants running than to develop replacement power. Tanya Bodell with Energyzt said that report is “flawed” and includes substantial “uncertainty.” She challenged Izzo’s assertion that they might close within two years if they become uneconomic.

“The plants are committed to operate through 2021,” she said. “It would be more costly to retire before 2021.”

Dominguez testifies as Dr. Joseph Bowring, PJM’s Independent Market Monitor, listens | © *RTO Insider*

Joe Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, said that while his company can’t decide whether to close the nuclear plants, it can stop investing in them. Exelon can nix any investment over $5 million into the plants, he said, and has come to an agreement with PSEG to begin deferring capital projects “in anticipation of the closure of” the Salem facility.

“As we looked at the market forwards … our concern was that we could no longer invest in the machine given what we were looking at in terms of future energy prices,” he said. “We are already acting on the belief that if adequate attribute payments aren’t provided for nuclear energy in New Jersey, we’re going to take the unit out of service, or at least from Exelon’s perspective, stop investing in the machines.”

One significant opponent to the bill received short shrift from legislators.

After calling NRG Energy CEO Mauricio Gutierrez to testify, Smith referred to him as “Maurice” and declined to attempt his surname, asking him to instead introduce himself. Gutierrez argued that the bill “creates only one winner and many losers, including my company.”

NRG owns no nuclear assets in New Jersey and has a portfolio of mostly gas-fired units. Substantial supplies of natural gas have kept commodity prices low and helped gas-fired generation offer into PJM’s markets at prices below nuclear units. The shift in generation economics has prevented some nuclear units from clearing auctions and denied them payments they say they need to remain profitable.

Gutierrez told the committees that had the subsidies existed before he decided to base his company in Princeton, N.J., he would have placed the headquarters elsewhere. The legislators asked no questions about his testimony, and Gutierrez appeared visibly frustrated as he returned to the audience.

December 20, 2017December 12, 2023

NERC Assigns SPP RE Registered Entities to MRO, SERC

By Tom Kleckner

NERC is offering SPP’s 128 registered entities a chance to comment after assigning them all to a new Regional Entity.

The reassignments became necessary when the SPP RE announced its dissolution in July, addressing NERC and FERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.) Responses are due back to the organization by Jan. 5.

NERC said it received 122 transfer requests spanning five REs, with six entities expressing no preference for a “transferee” RE. The organization placed most of the registered entities into the Midwest Reliability Organization (MRO), with 13 Arkansas, Louisiana, Mississippi and Missouri entities assigned to SERC Reliability.

Arkansas Electric Cooperative Corp., which provides power to Arkansas’ 17 distribution cooperatives, was placed in both MRO and SERC.

In a message to the registered entities, RE President Ron Ciesiel said it was the RE’s “understanding” that NERC is on target to present final transferee recommendations to the organization’s Board of Trustees at its February meeting.

“We believe there is a high probability the transfer can be completed in the July time frame,” Ciesiel said.

After an initial review and analysis of entity requests, NERC said it determined that granting all the requests “would neither result in effective and efficient administration of compliance and enforcement activities, nor a cohesive functional alignment to support and promote BPS [bulk power system] reliability and security.”

In reviewing the requests, NERC considered the location of an entity’s BPS facilities in relation to the geographic and electrical boundaries of the transferee RE. The agency also assessed the impact of a proposed transfer on other BPS owners, operators and users, including affected reliability coordinators, balancing authorities and transmission operators, as appropriate.

NERC said it recognized that its procedural rules do not contain criteria for “the allocation of multiple registered entity transfers” when an RE dissolves, so it used criteria from another rule for considering requests. The organization reviewed each transfer request using that criteria and other “entity-specific circumstances.”

When NERC’s recommendations differed from the entities’ requests, it contacted the entities and explained its rationale, the agency said.

Created in 2007, the SPP RE is responsible for auditing and enforcing NERC reliability rules in three balancing authorities: SPP, the Southwestern Power Administration and parts of MISO.

SPP said it is dissolving the RE in part because the RTO’s expanded footprint no longer aligns with the RE’s territory. However, FERC criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO.

Calling 2017 a “tumultuous year for SPP RE,” Ciesiel told its registered entities that RE staff, while working at reduced levels, achieved its highest ever metrics performance.

“A good way to close out the year for us,” he said.

The dissolution is expected to be completed by the end of next year.

December 20, 2017

ERCOT: Tightening Reserve Margins no Cause for Concern

By Tom Kleckner

ERCOT’s reserve margins may be tightening, but executives on Monday assured reporters that all is well with the Texas grid.

The ISO’s year-end Capacity, Demand and Reserves (CDR) report projects a 9.3% planning reserve margin for 2018, half of what it was in the May report and 4 points below the 13.75% target ERCOT established for itself in 2010. But during a conference call with media, staff described the CDR report’s reserve margin projections as a “snapshot in time” and detailed a list of tools available to handle any emergencies.

“The reserve margin that comes out of the CDR is a snapshot,” said Warren Lasher, senior director of system planning. “Reserve margins are expected to fluctuate in the current market design.”

The May CDR reported an 18.9% reserve margin for next summer. Since then, Vistra Energy has said it would retire about 4 GW of coal resources and ERCOT has reported a year’s delay in completing construction of almost 4 GW of planned capacity. (See Vistra Energy to Close 2 More Coal Plants.)

ERCOT CDR report reserve margins — | *ERCOT*

Lasher pointed out that since 2010, the Public Utility Commission of Texas has directed ERCOT to develop a new standard for determining the planning reserve margin, similar to a 2014 Brattle Group study on estimating “economically optimal” margins that minimize total system and operating costs. The ISO is currently conducting its own study, which it intends to complete in the third quarter of 2018 before reporting back to the PUC, Lasher said.

“I wouldn’t call [the CDR] cause for concern,” he said.

ERCOT expects 14 GW of resources to be in service by 2020 and will still have 77.2 GW of capacity on hand to meet a 2018 summer peak demand forecast of almost 73 GW. That would break the August 2016 record peak of 71.1 GW.

Demand is expected to grow at a 1.7% average annually over the next 10 years. The reserve margin is expected to increase to 11.7% by summer 2019, peaking at 11.8% in 2020 before dropping to 9% in 2022. Total capacity is expected to reach almost 83 GW in 2022.

“We see these types of shifts as the ERCOT market experiences cycles of new investments, retirement of aging resources and growing demand for power,” CEO Bill Magness said in a statement.

If the worst comes to worst, Lasher said ERCOT can always request emergency assistance across DC ties with Mexico or the Eastern Interconnection, or fall back on interruptible customers and switchable units obligated to other regions.

The December CDR report includes information about existing and planned generation resources and expected energy needs over the next 10 years. The report does not include the potential additional migration of nearly 600 MW of load should Lubbock Power & Light and Rayburn Country Electric Cooperative eventually migrate customers from SPP into the Texas grid. (See “ERCOT, SPP to Coordinate Second Load-Migration Study,” PUCT Briefs: Aug. 17, 2017.)

December 20, 2017January 3, 2024

MISO Studying Transmission Upgrade for Massive Foxconn Factory in Wisconsin

By Amanda Durish Cook

MISO is reviewing an expedited project request from American Transmission Co. to connect a massive Foxconn manufacturing plant that would be Wisconsin’s largest power user.

ATC’s proposed $140 million Mount Pleasant Tech Interconnection Project is one of the first two expedited review requests for MISO’s 2018 Transmission Expansion Plan. Along with a small substation upgrade in Minnesota that the RTO has approved, the project was presented to stakeholders at Tuesday’s Planning Advisory Committee conference call, days after MISO’s Board of Directors approved MTEP 17.

ATC has proposed a new 345/138-kV substation, 14 miles of new 345-kV line and four short 138-kV underground lines to connect a southwestern Wisconsin manufacturing plant proposed by Foxconn to We Energies supply.

Foxconn, headquartered in Taiwan, is the world’s largest electronics manufacturer, responsible for building Apple mobile devices, Amazon Kindles and video game consoles.

Its factory will be similarly outsized. Wisconsin Gov. Scott Walker has framed the $10 billion plant, which is expected to create as many as 13,000 jobs, as a “once-in-a-century opportunity” and called for it to be operating by 2020. ATC has said the plant will require up to six times as much power as the next-largest manufacturing facility in Wisconsin.

ATC hopes to get the $10 billion plant connected to the grid by the end of 2019 and plans on ordering some long-lead time equipment beginning in February. It said MTEP 18 approval would arrive too late for its planned construction timeline.

The company said it received the load interconnection request from WE on Oct. 12. MISO posted ATC’s expedited request on its website Dec. 6, although it is not clear when the RTO received it.

MISO is still studying the implications of the request and will convene a Technical Study Task Force meeting in January to go over study results with stakeholders, according to Lynn Hecker, manager of expansion planning.

ATC plans to seek project approval with the Wisconsin Public Service Commission in February, with hope for approval in August.

In addition to the new substation, ATC plans to string a new 12-mile, 345-kV circuit from Pleasant Prairie to Mount Pleasant, Wis., and create two 1.2-mile, 345-kV loops into the new substation on existing transmission structures. The project also includes the construction of four new 138-kV underground lines at less than a mile apiece connecting the Mount Pleasant substation to the manufacturing plant.

Minn. Capacitor Bank

Meanwhile, MISO has already studied and approved a much smaller substation upgrade in Minnesota, making it the first expedited project approval in the 2018 package.

The project — a $500,000, 14.4-MVAR capacitor bank addition to a substation in southern Minnesota — is expected to be in service by the end of January, according to developer Great River Energy. Capacitor banks counteract a power factor lag or phase shift in a power supply.

MISO recommended the project be granted expedited status in MTEP 18 as a baseline reliability project because the substation is currently susceptible to low voltages when a generator outage is followed by a line outage, a NERC-defined contingency. The project will also improve local area voltage performance in general, Hecker said.

December 20, 2017

CAISO 2030 Vision Gets Mixed Reviews

By Jason Fordney

Developers of renewable energy and emerging technologies are predictably supportive of CAISO’s vision for the grid of the future, but operators of more traditional resources say the proposal drifts outside the ISO’s purpose of assuring reliability and managing markets.

The nearly 200 pages of comments on CAISO’s Vision 2030 paper illustrate concerns about the ISO’s changing grid mix, laying out arguments that the transition is coming at the expense of reliability, fair markets and reasonable costs to ratepayers.

CAISO’s Board of Governors and management published the discussion paper in October, saying it was “intended to help focus discussion on both technical and policy issues involved in decarbonizing and decentralizing electric service.” The document identified California energy trends over the next 12 years, including more efficient energy use, a significant decline in gas-fired generation, more variable energy resources, decentralized service, regional collaboration and integration of electric vehicles. (See CAISO Symposium Panelists Talk Grid of the Future, Western RTO.)

The Independent Energy Producers Association, which includes both fossil fuel and renewable interests, suggested that CAISO had wandered from its core mission and is picking winners and losers by focusing on decarbonization and distributed resources.

“Overall, we find the Vision Paper not particularly helpful in illuminating what, if anything, the CAISO management will be ‘tasked’ to accomplish over the near term, e.g. one to five years, related to the CAISO’s primary function to maintain 60 Hz on the electric transmission grid and administer just and reasonable wholesale markets,” said IEPA CEO Jan Smutny-Jones, a former CAISO board chair.

The group urged the ISO to focus on accessing low-cost, transmission-connected renewables. It also complained that while the California Public Utilities Commission’s integrated resource plan assumes that about 30,000 MW of gas-fired generation will not be subject to retirement because of environmental rules by 2030, CAISO’s paper makes no accommodation for sustaining those resources.

“The evidence clearly recognizes a need for this type of generation (flexible capacity), yet the market provides little if any means to ensure that competitive resources that can provide these necessary services are available to the CAISO when and where needed. Importantly, the Vision Paper is silent on what, if anything, CAISO intends to do to address this matter,” the group said.

The California Municipal Utilities Association (CMUA) filed brief comments saying that issues identified in the paper, such as energy efficiency, vehicle electrification and economic impacts, “may all have an indirect impact on how the CAISO operates the grid. But the policies and choices inherent in each of these issues are not the CAISO’s core function, which is critical and complex [in its] own right without these additional challenges.”

CMUA Executive Director Barry Moline mentioned reliability-must-run agreements, the congestion revenue rights auction and the fact that most load-serving entities in the Western U.S. are vertically owned utilities that regulators want to remain in business.

“The CAISO should be cautious when opining on these issues of industry structure, rather than focusing on its core functions, as it seeks to expand collaboration beyond California,” Moline said.

NRG Energy, which operates some fossil fuel plants, said that relying on natural gas plants in constrained areas “is environmentally preferable to spending large amounts of money to eliminate those resources.” CAISO recently determined that NRG’s proposed Puente power plant would be the cheapest alternative out of a mix of alternative resources, but the company suspended its application after the California Energy Commission indicated it would not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)

NRG also noted that many topics in the paper are outside of CAISO’s traditional role, such as developing a new zero-energy building plan and shaping the state’s resource adequacy plan, which is under CPUC jurisdiction.

In Powerex’s comments to the ISO, CEO Teresa Conway promoted “forward arrangements” for flexible capacity and renewable integration. The Canada-based power marketer is due to join the CAISO-run Energy Imbalance Market (EIM) in April 2018. (See FERC Approves Powerex EIM Agreement.)

“We believe the pursuit of forward arrangements, along with expanding short-term energy markets like the EIM, can be an effective strategy for unlocking the capabilities of existing clean resources outside of California, and in particular the unique capabilities of northwest hydro systems,” Conway said. She said the state is at a “critical point” in the transformation of its energy grid and “the initial approaches responsible for the state’s success cannot be scaled indefinitely, and signs of renewable integration challenges are already present.”

Increased regional electricity trade and coordination will provide economic and environmental benefits by meeting customer needs with the cheapest resources, Powerex said, but increased coordination must accommodate differing and sometimes conflicting policy goals.

Powerex proposed establishing a “clean” resource adequacy requirement, aggressively pursuing storage, expanding forward commitment and procurement, and accurately measuring California’s greenhouse gas emissions associated with out-of-state resources.

Southern California Edison said it is not sure it agrees with CAISO’s assessment that, by 2030, demand-side resources will be as important as supply in balancing the system. About 4,500 MW of San Diego peak load will need to be met with supply sources, and “similar conclusions apply to loads in the SCE and [Pacific Gas and Electric] distribution service areas.”

CAISO vision paper 2030 reliability — | *CAISO*

SCE said it supports a “well-designed” carbon cap-and-trade program and properly implemented regionalization, including a Western states committee advisory body.

The Public Generating Pool, which represents 10 publicly owned utilities in Oregon and Washington, gave a regional perspective as other states look to possibly join markets operated by CAISO. California’s neighboring states have more hydro and coal resources and traditional cost-based utility regulation.

“The broad nature of this document and the numerous recommendations for policy, however, do not seem to fit the expected role of the CAISO as an independent system operator,” the group said. “If there are future versions of this document, it would be helpful for the CAISO to be more specific about its role relative to California legislature and state agencies.”

But the ISO’s vision did get solid support from some corners. The California Electric Transportation Coalition said, “We agree with and support Cal ISO’s emphasis on transitioning from fossil fuels to electricity in the transportation sector.” The group said that EVs will be increasingly important to manage load and store excess renewable generation. The ISO’s plan stated that California cannot reach its greenhouse gas reduction goals without electrifying the fossil energy now used in buildings and vehicles.

Arizona-based First Solar, which develops utility-scale photovoltaic modules, offered praise for the CAISO board’s effort to provide a “guiding vision” for strategic planning. And while the company agreed with the “trends and solutions” offered in the paper, it also urged the ISO to consider transmission needs for renewable integration goals.

“Again this year, the CAISO is not addressing additional policy-driven transmission projects in its Transmission Planning Process, creating potential problems for the increased interconnection of renewables required to meet California’s policy goals,” First Solar said.

The CAISO board issued a statement of appreciation for the comments Tuesday, saying they “will be valuable input into the ISO’s ongoing strategic planning process.”

December 19, 2017

PJM Market Implementation Committee Briefs: Dec. 13, 2017

VALLEY FORGE, Pa. — PJM is moving to implement three changes to its financial transmission rights market, developed through its FTR Modeling, Performance & Surplus special sessions. All three received endorsement at last week’s Market Implementation Committee meeting.

The first involves changes in long-term FTR modeling to account for future transmission system upgrades, which can impact congestion revenue. PJM is concerned that long-term FTR clearing prices don’t reflect “true future system capability.” FTRs entitle holders to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. They can be purchased or converted from auction revenue rights, which are allocated to network and firm point-to-point customers.

PJM’s annual ARR/FTR network model includes transmission upgrades that will be in place by the following June 30, and staff proposed expanding that methodology to the long-term FTR network model so that it also looks forward one year. The model would be filtered to only include upgrades that fit a “low-frequency, high-impact” threshold.

That threshold would be defined as the upgrade being a constraint itself or impacting by +/-10% constraints that have contributed at least $5 million to congestion over the past year or any future constraint. For new facilities, the analysis would be based on the line outage distribution factor (LODF), a measure determining how the change in a line’s status affects flows elsewhere in the system. The FTR group would work with PJM’s planning staff to determine which upgrades should be included in the model. PJM included in its presentation an example of how that process would have worked for 2016 and found that three out of 21 upgrades would have been modeled.

PJM would also develop a new long-term residual ARR market to ensure holders maintain priority rights to any incremental capability created by upgrades still to be modeled.

The second set of changes would improve PJM’s ability to finalize and publish FTR auction results on time. Impetus for the solution came after PJM delivered its March auction results late and blamed it on having to simultaneously finish the results for several overlapping FTR auction periods. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)

PJM proposes to resolve the issue by eliminating some auction periods. PJM’s Brian Chmielewski said the proposal, if endorsed on its current timeline, would be filed with FERC in February to be effective for the June overlapping period.

The third set of changes would allocate any surplus from FTR auctions and day-ahead congestion to ARR holders after FTRs are fully paid to their target allocations. The issue developed after FERC required PJM to revise its methods for allocating ARRs and balancing congestion. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

MIC members had to vote on two proposals: one developed by a coalition of ARR holders that allocated all surplus to holders, and a second developed by financial traders that allocated FTR surpluses to ARR holders up to their target credits and all day-ahead congestion surpluses to FTR holders.

The MIC endorsed the ARR holder proposal with 90% in favor and rejected the financial traders’ proposal with 34% in favor.

EnerNOC DR Aggregation Solution Questioned, Approved

Stakeholders endorsed by acclamation a problem statement and issue charge to examine the aggregation rules for seasonal demand response, but not before thoroughly questioning the proposal’s sponsor, EnerNOC. (See “Seasonal DR Aggregation Registration Rules,” PJM Market Implementation Committee Briefs: Nov. 8, 2017.)

“We don’t think this is a problem,” Independent Market Monitor Joe Bowring said, adding that “it seems to be presupposing the solution.”

Other stakeholders reiterated previous complaints that PJM’s stakeholder meeting schedule is already overbooked and that examining the issue doesn’t provide enough relative benefits to justify adding to the load.

PJM DER aggregation Market Monitor — Scarpigato | © *RTO Insider*

“If we take issues up where there’s not really a problem, we create extra work for ourselves. I don’t think you can blame PJM for that. We have to blame ourselves,” Calpine’s David “Scarp” Scarpignato said.

EnerNOC argues that the current registration process is inefficient and provides a Capacity Performance value that fails to reflect the full reduction that the aggregated resources could achieve. PJM did not update its customer-registration rules when DR rules were revised to comply with CP requirements, nor did it seek stakeholder endorsement prior to unilaterally filing for approval last year of its seasonal aggregation plan. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)

EnerNOC’s Katie Guerry said the issue is worth examining because it could lead to more efficiency for both DR aggregators and PJM dispatch operations.

“If status quo comes out [as the result], we’re ok with that as well,” she said.

Other DR stakeholders supported her.

“I hope this doesn’t take 20 meetings, but I think it’s worth working on,” NRG Energy’s Brian Kauffman said.

Monitor, Financial Marketers Propose Different Paths

Skucas (left) and des Rosiers | © *RTO Insider*

Unable to work out their differences on how to regulate the market path of energy sales coming into PJM, the Monitor and financial marketers are asking the MIC to resolve the issue. They are presenting three different proposals on the issue.

The Monitor’s proposal would develop a list of “prohibited paths” that could be subject to resettlement. The Monitor would develop a monthly report of activity on those paths and share it with PJM so that either entity could refer use of those paths to FERC for enforcement.

Pierce Atwood partners Ruta Skucas and Jared des Rosiers presented a proposal developed by American Electric Power and the Financial Marketers Coalition. It would entail a change in PJM’s Tariff for the initial list of banned paths and require FERC, PJM and Monitor approval for any additions. It would also develop a “query” where users could seek a preliminary evaluation from PJM on whether a potential path would risk resettlement.

Stephen Kelly of Brookfield Renewable presented another proposal that would allow market participants the opportunity to establish with PJM and the Monitor that a potentially problematic transaction is “legitimate” before it is automatically resettled.

The proposals also differed on what level the activity should be evaluated. The Monitor proposed considering it from the level of the parent corporation, but the others called for analysis on the level of individual companies.

— Rory D. Sweeney

December 19, 2017

NARUC Calls for PURPA Reforms, Outlines Proposed Changes

By Rich Heidorn Jr.

State regulators on Monday called on FERC to change its interpretation of the Public Utility Regulatory Policies Act to “align” the 1978 law “with modern realities.”

PURPA FERC NARUC — Betkowski | © *RTO Insider*

John “Jack” Betkoski III — vice chairman of the Connecticut Public Utilities Regulatory Authority and president of the National Association of Regulatory Utility Commissioners — wrote FERC commissioners a letter saying he was pleased that interim Chairman Neil Chatterjee had pledged that the commission would be pursuing PURPA reform.

“As the primary point of responsibility for PURPA’s on-the-ground implementation, the states have a strong interest in the reform of PURPA’s associated federal administrative regulations, and we hope this reform will continue to be a priority under the leadership of Chairman [Kevin] McIntyre,” Betkoski wrote.

PURPA is a persistent source of annoyance to state regulators, who sounded off at a July 2016 technical conference (AD16-16). (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)

Betkoski cited four changes since PURPA’s enactment in 1978 that he said required a new look from FERC. “These four changes — the rise of wholesale markets, the place of [qualifying facility] technologies as a commonplace source of power, the open-access regulation of the transmission system and the use of competitive methods to select projects throughout the states — suggest that PURPA’s administrative regulations should be aligned to these developments, instead of obstructing them. Despite these changes, many states incur significant transaction costs administering PURPA pursuant to the law’s arcane, 20th century mandates,” Betkoski wrote.

He quoted Montana Public Service Commissioner, and former NARUC president, Travis Kavulla, who told the technical conference that PURPA issues consume more than one-quarter of his commission’s time on electric utility regulation. (See Montana PURPA Solar Saga Continues in State Court.)

NARUC proposed three changes, “each of [which] allows FERC to work within existing law to make meaningful changes to PURPA, while remaining committed to the law’s underlying goals of competition and encouragement of QF technologies,” Betkoski said.

NARUC proposed that FERC:

Adopt regulations that move away from the use of administratively determined avoided costs to their measurement through competitive solicitations or market clearing prices. “We propose that in certain circumstances, such as when a QF has both nondiscriminatory access under an [Open Access Transmission Tariff] and exists in a region where public utilities routinely use competitive solicitation processes, such a construct would qualify as wholesale markets under 18 CFR 292.309(a)(3). Making this determination would allow FERC to erase the false dichotomy between RTO/ISOs regions, and those regions without such an RTO/ISO but where each public utility nevertheless has an OATT and where states oversee utility procurement and require the use of competitive solicitations.”
Lower or eliminate the 20-MW threshold for the rebuttable presumption that QFs with a capacity at or below that size do not have nondiscriminatory access to the markets. “In keeping with the goal that FERC should better align PURPA implementation with modern realities, this threshold should be lowered to whatever the minimum capacity requirement is for a resource to participate in an RTO/ISO.”
Making changes to the 1-mile rule to discourage gaming. “There are a number of well-documented incidents where projects have forgone economies of scale to qualify themselves as individual QFs and evade other regulations; for instance, state commissions requirements for competitive solicitations. The commission should not encourage this form of regulatory arbitrage.” NARUC recommended Idaho Public Utilities Commissioner Paul Kjellander’s suggested criteria for determining whether a single project has been disaggregated in order to create multiple QFs under the generation size limit.