California will need between 229,000 and 279,000 electric vehicle chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles, the Energy Commission said in a new report.
The higher range of the estimate includes 133,000 workplace and public chargers, 9,000 to 25,000 fast chargers and 121,000 chargers at multifamily dwellings, the commission said. The numbers do not include chargers in single-family homes.
There is a projected need in California for up to 279,000 non-single family home chargers by 2025.
A March 2012 order by Gov. Jerry Brown directed the commission to support the goal of 1.5 million zero-emission vehicles on state roadways by 2025. Another January 2018 order by Brown called for the construction and installation of 250,000 zero-emission vehicle chargers, including 10,000 DC fast chargers, by 2025.
According to the new CEC study, the state’s goal is to allow drivers to maximize the number of electric miles they can drive, provide guidance on plug-in electric vehicle (PEV) and plug-in hybrid charging, and ensure the effectiveness of private and public sector investments. As of the end of last year, the state had about 14,000 public chargers — 1,500 of them DC fast chargers — serving 350,000 PEVs.
For the study, CEC staff worked with the National Renewable Energy Laboratory to develop a computer simulation tool known as the Electric Vehicle Infrastructure Projection Tool (EVI-Pro). The commission plans to add an EVI-Pro portal to its website to allow users to view charging station quantities, load shapes, infrastructure cost estimates and other information.
At a CEC workshop on Tuesday, analysts discussed three central questions around charging infrastructure: how many chargers to deploy, what kind of chargers and where to locate them. A big part of determining where to place chargers is understanding the behavior of vehicle operators and studying patterns such as worker commutes and rural versus urban settings.
“What we’re really talking about is trying to reduce range anxiety as a barrier to increased PEV sales,” NREL’s Eric Wood, one of the study’s authors, said at the workshop.
EVI-Pro focuses on behaviors of mainstream drivers, such as origins, destinations and schedules, as opposed to those of early EV adopters. Mainstream drivers are more likely to favor convenience and less likely to alter driving habits, for example. The modeling also studied how different charging locations such as home or work might be chosen based on the price of electricity, and how users charging for free at work might block other chargers and drive up costs of workplace charging.
The study used four major inputs: vehicle attributes, charger attributes, county-level household travel data and composition of the vehicle fleet. It calculated several charger-per-1,000-PEVs ratios under differing technology and market scenarios.
The transportation sector is the largest polluter in California, responsible for 80% of nitrogen oxide emissions and 90% of diesel particulates. Including indirect emissions from fuel refining and production, transportation accounted for “nearly half” of the state’s greenhouse gas emissions as of 2015, the report said.
The study showed that weekday charging peaks occur when vehicles arrive at work in mornings and when they arrive home in evenings. By 2025, workplace chargers on weekdays will draw more than 200 MW at 9 a.m. and residential chargers nearly 900 MW at 8 p.m. By 2025, aggregate demand from residential, workplace and fast-chargers will push up demand by 500 MW from 4 to 7 p.m., with a maximum demand of nearly 1,000 MW before 8 p.m.
The commission said that an important conclusion of the study is assuring drivers that charging infrastructure will be visible, accessible and reliably maintained, with real-time networking technologies being a valuable tool. Networked technologies will enable shared usage of chargers and reduce the size of the network needed to support the growing electric fleet.
CAISO’s first-quarter revenues were $1.2 million more than it had budgeted, primarily because of entrance fees it collected for the Western Energy Imbalance Market, the ISO reported last week.
About $1.6 million in EIM entrance fees were partially offset by grid management charge (GMC) revenues that were $400,000 less than budgeted. CAISO did not specify from whom it had collected the EIM fees, but Idaho Power and Canadian power marketer Powerex both began transacting in the market last month. (See Idaho Power, Powerex Begin Trading in Western EIM.)
CAISO’s total market settlement collections in 2017 were about $4 billion.
The ISO’s operating costs, capital expenditures, debt service and an operating reserve are recovered through the GMC. Most charges other than the GMC collected by the ISO are distributed to the appropriate market participants.
CAISO “monitors changes in GMC revenues and will adjust rates, if necessary, to align actual GMC revenues closer to budget, as required by the Tariff,” the ISO said in its first-quarter report.
Total market settlement transactions collected by the ISO were about $4 billion last year, including about $3.8 billion in market settlements and $200 million collected through the GMC, according to the ISO’s continuing disclosure report posted May 22. This compared with $3.4 billion in settlements and GMCs collected in 2016.
| CAISO
CAISO reported audited operating income of $26 million for the year, compared with $14 million in 2016. Operating expenses were at $195 million, “other expenses” were $5 million and operating revenues were $221 million.
The ISO in February had reported unaudited operating income of $47.4 million for 2017. (See CAISO Sees 2017 Revenue Boost.) The new operating income figure of $26 million includes depreciation and amortization of about $29 million.
Each year, CAISO establishes a revenue requirement that is allocated to the three GMC service categories: market services, system operations and congestion revenue rights services. Other financial collections come from EIM participants, generator interconnection studies and for operation of the California-Oregon Intertie.
The two largest of the 160 participants in the market, Pacific Gas and Electric and Southern California Edison, paid a little more than half of GMC revenue in 2017. The 10 largest participants were responsible for about 75% of the charge and the top 25 participants paid 89%. These levels have remained about the same since 2015.
Operating expenses last year included $118 million in salaries and benefits, $20 million in communications and technology costs, $18 million legal and consulting and $12 million in leases, facilities and administrative costs.
The ISO increased its number of full-time employees to 599 in 2017 from 584 in 2016.
CAPE NEDDICK, Maine — New England state regulators agreed last week that their region faces a growing winter reliability challenge but expressed skepticism over ISO-NE’s proposed solutions.
Speaking at the New England Conference of Public Utilities Commissioners’ (NECPUC) 71st annual symposium May 21, a panel of regulators pressed ISO-NE CEO Gordon van Welie on the need for an out-of-market contract for Exelon’s Mystic Generating Station, asking why it can’t be replaced through the capacity market and its Pay-for-Performance program.
The proposed Mystic contract represents the first of ISO-NE’s “three-track” plan for addressing its winter fuel reliability concerns. Last week, dozens of intervenors filed comments in response to the RTO’s request for a Tariff waiver needed to authorize the procurement, most of them in opposition (ER18-1509). (See related story, Mystic Waiver Request Spurs Strong Opposition.)
‘A Point at Which We Can’t Hold Things Together’
Van Welie said that Pay-for-Performance — which was premised on gas plants adding oil-fired capability — has been hampered by its stop-loss provisions and states’ resistance to oil-fired generation.
The CEO also said there isn’t enough oil storage or allowable air permits to rely on the fuel as the region’s backstop. During the Dec. 26-Jan. 8 cold snap, oil prices fell below gas, making oil-fired generation effectively baseload for two weeks, he said. The region burned about 2 million barrels of oil during that period — more than it used in all of 2016 and 2017 — drawing down supplies from 68% of tank capacity on Dec. 1 to 19% by Jan. 9. “The ISO had to step into the market to slow down the burn rate,” he noted.
Fuel delivery logistics also are a concern. Heating customers get priority for oil as well as gas. Oil deliveries can be delayed by storms and drivers’ working hour limits.
Van Welie said the RTO must firm up fuel deliveries and ensure that the market “uniformly” values all resources with such service, including its Millstone and Seabrook nuclear plants, which produce one-quarter of the region’s power during winter.
In addition to the region’s precarious fuel infrastructure, ISO-NE is concerned that state-sponsored renewable resources will reduce energy market revenues, causing increases in capacity market costs and plant retirements.
“Our concern is there’s a point at which we can’t hold things together,” van Welie told the regulators.
ISO-NE is seeking to delay Mystic’s retirement because its analysis indicated the loss of Units 8 & 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would leave the RTO depleting its 10-minute operating reserves “on numerous occasions” — a violation of NERC reliability rules. The analysis also predicts load shedding during the winters of 2022/23 and 2023/24.
The RTO has asked FERC to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only for local transmission security issues (Track 1). It hopes to file a Tariff change by the end of the year to make fuel security a reason resources can be retained (Track 2). In addition, the RTO is seeking a long-term plan to ensure sufficient firm energy for winter that would compensate needed resources through the market rather than reliability contracts (Track 3).
A Menu, not a To-Do List
Despite the hand he’s been dealt by the region’s resistance to oil generation, additional gas pipelines and electric transmission, van Welie was careful to couch his comments not as a “To Do” list but as a series of questions and menu choices for the states.
“We are an energy-constrained region. Do we want to maintain that constraint going forward, or do we want to do something about that? And specifically, can the states shape their resource procurements … in a way that they get at the winter constraint? Because I think in doing that the states can help us as well as maintaining or meeting their other policy goals.”
“The magnitude of that problem is in [question] but there is a problem,” said Bob Stein, vice chair of the New England Power Pool’s Reliability Committee, who joined regulators on the panel.
NEPOOL has “a range of positions [on the RTO’s plans], and they’re not fully formed,” said Stein, principal of Signal Hill Consulting Group. The range, he noted, is framed by the two types of NEPOOL members: “Those that are long and those that are short. And you can instantly tell what people are going to say by where they are.”
Maine Public Utilities Commission Chairman Mark Vannoy and other commissioners pressed the RTO for a “definition” of the problem, saying he is concerned that “New England is on a course to a very expensive future.”
“I’m not arguing that there is not a problem,” Vannoy said. “But we need to define what the problem is and then — if our intent is to use market mechanisms to solve that — we have to be precise … so that we can move to those market solutions.
“We have a very complex and dynamic market, and as price signals drive fuel procurement questions … [as fuels] substitute for other fuels … we need to understand how that dynamic market reacts before we move to the Markets Committee for a solution.”
Vannoy said New England helped create its dilemma by “separat[ing] itself from the rest of the country’s energy … potentially, to our economic peril.” He cited states using their EPA-delegated authority under the Clean Air Act to prevent access to Marcellus shale and other gas supplies.
As an example, Vannoy later cited the Atlantic Bridge pipeline project. In the face of local opposition, Massachusetts officials said in December that they would take up to a year to review the impact of a compressor station in Weymouth, Mass., that is part of the project.
Seeking an Honest Conversation
Angela O’Connor, chair of the Massachusetts Department of Public Utilities, called for an “honest” conversation.
“Whether you want to reduce greenhouse gases or simply reduce the rising outrageous cost of energy … burning 2 million barrels of oil in five days and killing baby seals to get to expensive Russian gas cannot and should not be part of any intelligent conversation about energy policy in this region,” she said. “It clearly does not meet any of our New England collective goals for the states. We need to have an intelligent and honest — emphasis on honest — conversation to develop the right solutions, and we need to do it all together.”
Is Pay-for-Performance Broken?
New Hampshire Public Utilities Commissioner Kathryn Bailey said her state is not convinced that the out-of-market contract with Mystic is the only possible solution to the region’s near-term concerns. She said the Operational Fuel-Security Analysis released by ISO-NE in January suffered from “problems with the assumptions and the lack of analysis on how likely scenarios are to play out.” (See Report: Fuel Security Key Risk for New England Grid.)
She said maintaining Mystic could create incentives for other non-gas generators to seek cost-of-service agreements.
“I have to ask: What happened to the market-based solution to fuel security? Just a few short years ago, ISO-NE reported to FERC that Pay-for-Performance was a long-term, market-based solution designed to address generator availability concerns and the region’s vulnerability to interruptions in gas supply. … What changed? Why does the ISO think it won’t work, even before the incentives take effect next month? Where’s the analysis that demonstrates it won’t work? When the ISO originally brought this plan to FERC, there was a lot of analysis.
“If Pay-for-Performance had worked as expected … and Mystic announced its retirement, prices in [Forward Capacity Auction] 13 would likely separate to provide incentive for new resources to take on the supply obligation in that zone. But apparently Pay-for-Performance can’t work.”
Bailey also noted “the irony that ISO-NE refused to allow a 200-MW renewable exemption backstop to integrate state public policies because of the impact it would have on the market. But now they want to waive the Tariff and allow a 1,700-MW out-of-market contract.”
In a period of low gas and renewable prices and flat load growth, Connecticut Public Utilities Regulatory Authority Chair Katie Dykes asked: “Why is everybody so unhappy?”
Her theory: “Legacy” deals, conflicting state policies, and overlapping jurisdictional authority between FERC, state legislators, state commissions, siting councils and the courts make it difficult for economic regulators to achieve the “fairness” they seek.
“We were one of a few states that got our legislature to give us fresh, brand new authority to procure not only gas pipelines but LNG storage. We got all of that authority. We opened a [request for proposals]. …
“We opened up the bids. We were ready to go. [Then] we looked at the costs and we realized that if we didn’t have all the states moving with us that Connecticut was going to pay 100% of the cost of these resources and only get 25% of the benefit because that’s our share of load. And so, the bids are still sitting in a desk drawer somewhere.
“The challenge of the multi-jurisdictional process is it is guaranteed to be unfair to some parties. … There’s a temptation to retreat within our own borders and pursue this sort of righteous unilateralism. … But that’s not really an acceptable tactic. If it comes to those outcomes, everyone in this room is going to be blamed for that occurring. No matter how hard you’ve been working on this issue, no matter how small your slice of the jurisdictional pie is, you’re all going to share responsibility for [reliability problems], which will hurt people and drive businesses out of New England,” she said, raising her arms like a cheerleader waving pom-poms. “So, what we really need to do is buck up, little soldiers. We can do this. This is New England.”
Rhode Island Public Utilities Commissioner Abigail Anthony stressed affordability, saying customers are best served by investments that “prioritize highly cost-effective measures that improve the reliability resiliency of both the distribution system and the [transmission] system.”
“So, the resources that we invest in need to do double or even triple duty to improve the energy system on multiple levels,” she said. She added, “Some of the best solutions to maintaining and improving reliability resiliency and affordability may lie outside the power system.”
She noted that 16,000 of her state’s residential electric accounts were terminated for nonpayment in 2016. “Rhode Island’s experience, consistent with national data, shows that the vast majority of customer outages are the result of disruptions of the distribution system or due to affordability,” she said.
Vermont Public Utility Commissioner Sarah Hofmann said she would like more data on resilience risks, the costs of reducing them and residential customers’ willingness to accept outages.
“The tolerance of consumers for the bad thing happening, such as rolling blackouts, that’s a conversation that … I don’t think we have as much as maybe we should, in terms of what can a residential customer tolerate as opposed to … a commercial customer.”
Enough LNG? Rewrite Capacity Market?
Van Welie said the two top sensitivities for its fuel study was the timing of retirements of its non-gas fleet and the size of LNG injections.
Over the last five winters, ISO-NE says the region has received an average LNG injection of 0.2 Bcfd, only occasionally spiking to the 1-Bcfd level assumed in the baseline case. In its recent analysis, Synapse Energy Economics said import terminals could handle 1.5 Bcfd.
ISO-NE CEO Gordon van Welie says New England’s growing price volatility since the winter of 2012-13 reflects the region’s increasingly constrained fuel infrastructure. | ISO-NE
“We’re talking about unprecedented levels of LNG imports into this region,” van Welie said. “And the big question is: Is the market signal strong enough to incent that behavior?”
Of New England’s 17 GW of combined cycle capacity, only 5 GW have dual-fuel capability. “There are three with large tanks. The biggest one is 10 days’ [capacity]. The next one down is five or six days. The next one down from that is three days. The tanks that are being built, if they do get built today, are [only] two days.”
“So, the issue is, Pay-for-Performance was calibrated to the economics around dual fueling, [which] may not be a good assumption in the long term.”
Van Welie also questioned Pay-for-Performance’s annual and monthly stop-loss limits for generators that fail to perform, which he said has many of them rolling the dice that they won’t need firm fuel. “Is that the right incentive to send generators? That they could end up still collecting capacity payments without necessarily having to feel that they need to run for the winter?”
Van Welie also said the decisions the RTO made when it designed its capacity market 14 years ago need to be reconsidered. The market’s design is based on meeting the summer peak rather than the winter peak, which is now the bigger risk. A seasonal construct that acquires resources separately for the winter and summer would be preferable, he said.
“Do we throw out the capacity market — go back to blank sheet of paper and redesign the seasonal capacity market? Or do we … do something complimentary, really specifically targeting … the firmness of energy that we required during the winter period?
“We have not landed on … the specific solution to this problem. … But we recognize that … some of the things that we assumed as far back as 14 years ago may not be valid.”
AUSTIN, Texas — It’s finally official. Southwestern Public Service can now begin construction on its 478-MW wind farm in West Texas.
The state’s Public Utility Commission on Friday quickly approved a second draft order of the utility’s request for a certificate of convenience and necessity and a power purchase agreement with Bonita Wind Energy. The commissioners had given their verbal approval in April but delayed a final order to allow parties in the docket additional time to provide written responses to their questions (No. 46936). (See Texas PUC Delays Final Approval of SPS Wind Farm.)
“We’re just pleased we now have a resolution in hand and a final order,” said SPS CEO David Hudson, noting it was the fourth time the utility has appeared before the commission in hopes of receiving a final order. “We can now begin construction on the Hale [County] project and the Sagamore project” in New Mexico.
SPS expects to have the Hale project in service no later than 2019, at a cost of $769 million, so that it will be able to receive 100% of its federal production tax credits.
PUC Chair DeAnn Walker had expressed concerns over SPS’ proposal to recover costs by flowing PTCs through fuel, but she was satisfied with the parties’ responses.
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
SPS had reached a settlement agreement in February with all parties in the docket but two, the International Brotherhood of Electric Workers Local 602 and Lea County Electric Cooperative. However, neither opposed the settlement.
Commission Streamlines Smart Meter Texas Portal
The PUC also approved a final order streamlining Smart Meter Texas (SMT), the state’s web portal, and aligning it with national data-transfer standards (Docket No. 47472).
SMT is maintained by utilities AEP Texas, CenterPoint Energy Houston Electric, Oncor and Texas-New Mexico Power. It allows customers to download and view their energy data or share them with competitive service providers (CSPs), companies that market energy efficiency, demand response, distributed generation and other services.
Transmission and distribution providers are prohibited from selling, sharing or disclosing advanced meter data but are required to provide “convenient, secure, read-only access” to a customer, the customer’s retail electric provider and other entities authorized by the customer. The data include meter readings used to calculate charges for service, historical load and other proprietary customer information.
The order requires the utilities to support the portal’s home area network (HAN) functionality through their advanced metering systems. It also forbids them from disconnecting an existing HAN device from the meter without the customer’s requests. The HAN devices are costly and have had few takers for their services.
PUC staff last year requested the commission determine what changes, if any, should be made for SMT’s continued operation while its contract was being renegotiated. The four utilities signed a joint development and operations agreement for SMT that dates back to December 2008.
The utilities reached a unanimous settlement agreement in January, with the only contested issue related to the maximum time period that a residential customer or smaller commercial customer may grant a CSP access to the customer’s SMT data, without the customer affirmatively renewing the access.
The commission adopted an administrative law judge’s recommendation that the maximum time period remain 12 months.
PUC to Intervene in SPP-AEP Filing Before FERC
Following its executive session, the PUC moved to intervene in SPP’s recent FERC filing on behalf of American Electric Power (ER18-1541, ER18-1542).
SPP made a compliance filing on May 8 to revise AEP West’s transmission formula rate to reflect the recent change in the federal corporate income tax rate (ER18-63). The filing was made on behalf of AEP Service Corp. and its AEP Oklahoma Transmission and AEP Southwestern Transmission affiliates.
The Oklahoma Municipal Power Authority and DC Transco have already intervened.
AUSTIN, Texas — ERCOT’s legal department again delayed votes endorsing final changes to the grid operator’s bylaws and articles of incorporation, saying it needed additional time to evaluate a last-minute comment from Luminant.
Assistant General Counsel Vickie Leady told the Technical Advisory Committee last week that legal staff would delay final votes on the revisions until the August set of leadership meetings. She said ERCOT and Luminant are “on the same page,” but they are trying to figure out the language.
“We appreciate having people poke holes in the language,” Leady told the TAC during its May 24 meeting. “Given the importance and relative permanence of the language, we need more time to address it. Once we put stuff in the bylaws, it’s there for a long, long time.”
Legal staff had originally planned to put the proposed changes up for votes in April but pushed the final recommendation back to the June Board of Directors meeting. (See “ERCOT Legal Staff Delays Bylaw Revisions,” ERCOT Technical Advisory Committee Briefs: March 22, 2018.)
Luminant sent its comments after working hours on May 23, suggesting clarifications to the proposed affiliate definition. The generating company added language to the definition that read:
“A person who is not controlling, controlled by or under common control with another person as described above may nonetheless be determined to be an affiliate of another person, if ERCOT or a member alleges that such exercises directly or indirectly, through one or more intermediaries, substantial influence over another person. Such a determination may be made by the board only after notice and an opportunity for hearing at an ERCOT board meeting. The burden of proof to show substantial influence is on ERCOT or the member alleging such influence.”
Luminant’s Ian Haley apologized for the late filing, saying it was the first time the company had been able to gather together its legal counsel.
The company also suggested a central repository for the various clean and red-lined documents, which Leady said ERCOT would follow. Legal staff also plan to hold a workshop following the June board meeting to “facilitate a final set of comments.”
Leady said she has received no stakeholder comments on the articles of incorporation but that they should “travel together” with the bylaw changes.
Southern Cross Transmission (SCT) also filed comments requesting a delay of a decision regarding in which market segment it should be placed. SCT believes it should be included in a newly created DC Tie Operator segment.
Cratylus Advisors’ Mark Bruce, who represents the project’s developers, said SCT hopes that when the market segment question is revisited, “greater stakeholder familiarity with the SCT project will ease some of the controversy currently associated with the question of the appropriate market segment assignment for DC tie operators.”
Bruce wrote that he saw no harm in delaying the membership decision. Leady said staff would “reinitiate” stakeholder discussion of the segment definition “upon further certainty that the SCT project will be interconnected” to ERCOT.
Texas’ Public Utility Commission last year directed ERCOT to address several issues as a condition for energizing SCT’s project. The conditions include determining “the appropriate market participation category for [SCT] and for any other entity … for which a new market-participant category may be appropriate” (Project No. 46304).
Staff Recommend 2 Transmission Projects
The committee endorsed staff’s recommendation of a $327.5 million Oncor project that addresses reliability concerns in ERCOT’s Far West region.
If approved by the Board of Directors in June, Oncor’s work will include building 40 miles of new 345-kV lines on double-circuit structures, adding two new 600-MVA, 345/138-kV autotransformers at a switch station, installing a second 345-kV circuit between Odessa and Riverton, and building two 20-mile segments of 138-kV line on double-circuit structures.
Construction is expected to begin next year, with completion in 2023.
Staff said the project will provide operational flexibility and resolve potential reliability issues in the face of oil and gas-related load growth.
Staff also shared with TAC members an additional study evaluating a Rayburn Country Electric Cooperative proposal to transfer its existing facilities and load into ERCOT, a plan filed last year with the PUC (Docket No. 47342).
The ISO said it is now recommending a “modified alternative option” to integrating Rayburn’s load, following an Oncor study of a transmission alternative than eliminated a 345-kV interconnection.
Staff concluded the second option, which still includes two 138-kV interconnections, has “similar reliability and long-term load-serving capability.” However, the modified alternative has a lower estimated capital cost of $31.7 million, leading ERCOT to propose the Oncor suggestion.
Staff’s initial study indicated capital costs of $41.7 million.
Rayburn, which sits on the ERCOT-SPP seam in East Texas, has proposed transferring load and transmission facilities into ERCOT. The co-op is an SPP member, but only about 150 MW (or less than 20%) of its load and 160 miles of its transmission sit in the Eastern Interconnection. (See “ERCOT, SPP Agree to Rayburn Country Migration Studies,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)
Members Approve Subcommittee’s Restructuring
Members unanimously approved a task force’s recommendation to designate the Commercial Operations Subcommittee (COPS) and several of its working groups as inactive, agreeing that it has reached a “steady state” situation concerning market communication and settlement issues.
The Wholesale Market Subcommittee will inherit the Settlement Working Group and the Commercial Operations (COP) Market Guide, while the Retail Market Subcommittee will pick up the Profiling Working Group, Load Profiling Guide and market communications.
The TAC Subcommittee Restructuring Task Force brought its recommendations to the committee in February. (See “Committee Endorses Task Force Restructuring Recommendations,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
The restructuring will require the following changes for the COP Market Guide and the Load Profiling and Retail Market guides:
COPMGRR047: Relocates the COP guide to the WMS, moves other portions of the manual to the retail guide and removes language that is no longer applicable from the COP guide.
LPGRR064: Moves the Load Profiling Guide and load-profiling responsibilities from COPS to the RMS and removes language from the guide that no longer applies.
RMGRR151: Incorporates the market notice communication process and renewable energy credit information from the COP guide into the retail guide.
The task force will continue its development of a “three strikes” attendance policy for TAC and its subcommittees, whereby seated segment representatives that miss three meetings or fail to assign an alternate for those meetings will lose their seats. It will also aid the RMS with moving RMGRR151’s market notice process language into a standalone Other Binding Document.
TAC Re-elects Helton as Chairman
TAC once again elected Bob Helton as its chair, an action required following the latest change in his employment status and market segments.
Helton moved from ENGIE to Dynegy last year when the latter bought the former’s 17 U.S. power plants. He left Dynegy when it was subsequently acquired by Vistra Energy, recently rejoining ENGIE as its director of government and regulatory affairs.
“I know you guys may not know this person, and I know we’ve elected him three times in the last seven months,” began Sharyland Utilities’ B.J. Flowers as she teasingly nominated Helton for the vacant chair position.
Helton thanked the members for their support, saying he hopes to finish out the year as committee chair.
“Of course, you never know, the way jobs change around here,” he joked.
Committee Endorses 4 NPRRs, 7 Other Changes
The committee endorsed four Nodal Protocol revision requests, a revision to the Nodal Operating Guide, a pair of Other Binding Document revisions, two changes to the Planning Guide and two changes to the Verifiable Cost Manual.
NPRR847: Incorporates an intraday or same-day weighted average fuel price into the mitigated offer cap to ensure that resources are capped at the appropriate cost during high fuel price events and LMPs reflect the true incremental cost of fuel.
NPRR851: Establishes a clearly defined disconnection process within the market rules applicable to a transmission voltage connection to the grid that uses one electrical connection for both generation and load services.
NPRR867: Caps the amount of each counterparty’s available credit limit locked for congestion revenue rights auctions at the pre-auction screening credit exposure amount.
NPRR870: Deletes the gray-boxed requirement for ERCOT to post a forward adjustment factors summary report on the Market Information System’s certified area. The information in this report is already provided on each counterparty’s estimated aggregate liability summary report.
NOGRR176: Clarifies that all transmission owners and qualified scheduling entities representing resources can participate in ERCOT hotline calls.
OBDRR004: Revises the risk-weighting factors available for assignment to each emergency response service (ERS) time period; describes the process for updating the ERS time period expenditure limits for any subsequent standard contract terms (if money is needed to fund) and the ERS renewal contract period; and updates a table to reflect the risk-weighting factors’ proposed changes.
OBDRR005: Revises the generic transmission constraint (GTC) shadow price cap that is used in SCED for base case constraints from $5,000/MWh to $9,251/MWh. The revision also updates the associated examples in SCED and makes an administrative edit to a protocol reference.
PGRR059: Includes Regional Planning Group-related changes intended to improve and clarify existing processes.
PGRR060: Updates the reliability performance criteria by defining a DC tie’s unavailability as a new contingency and clarifies the voltage level of transformers referred to in the reliability performance criteria.
VCMRR020: Delays VCMRR014’s sunset date to permit stakeholders additional time to find a long-term solution that determines an appropriate adder for coal- and lignite-fired generation resources.
VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing language providing for make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.
CAPE NEDDICK, Maine — The future of the grid, electric vehicles, high costs, and the tension between state and federal jurisdiction were among the topics discussed at the New England Conference of Public Utilities Commissioners’ (NECPUC) 71st annual symposium last week.
New England faces “some of the highest costs in the country, resource constraints, reliability concerns, retirement concerns, storm costs, increasing resiliency needs — and that’s just right now,” said Elin Katz, Connecticut consumer counsel and president of the National Association of State Utility Consumer Advocates.
“I get really frustrated when people dismiss the advocate perspective and say all you care about is cost, because I love technology,” Katz said. “But I’m really worried about the cost.”
Katz serves on a scholarship board for the University of Hartford, where she said this season’s applicants are poorer, needier and have higher needs than the year before.
“That’s happening all over the country … so I worry about the consumer and what is happening with respect to our consumers and what they can afford,” Katz said.
Cost was also on the mind of Maine Gov. Paul LePage, who told NECPUC on May 22 that he is looking to Canada to help supply his state with natural gas because his state has so far been unable to access the plentiful Marcellus gas in Pennsylvania because of environmentalists’ opposition to pipelines.
“You can live in Montreal, have a flat in the most expensive part of town and heat with electricity” because of low-cost Canadian hydropower, LePage said.
Maine enjoys the cheapest electricity prices in New England, but the region has the highest prices in the country, so the distinction means nothing when the state competes against Alabama for a new manufacturing plant, he said.
LePage brought up the case of an aircraft manufacturer looking to site a new plant. The $600 million cost of building in Alabama beat the $200 million cost in Maine because of the cheaper electricity rates in Alabama, he said.
LePage said high power prices are particularly challenging for the aging demographic in Maine, where many residents are retired and live on fixed incomes.
Resilience and the State/Federal Divide
The debate over grid resilience has highlighted new tensions in the line between state and federal jurisdiction, former FERC Commissioner and North Dakota PSC Chairman Tony Clark said.
“We thought [resilience] was basically about black start resources — the grid goes down and you have to have certain resources available that can bring the grid back up fast,” said Clark, now an adviser with law firm Wilkinson Barker Knauer.
Now regulators are asking about the value of fuel diversity, onsite fuel storage, dual-fuel units and the risk of gas generators with single-source pipelines.
“Some of those things begin to look an awful lot like resource adequacy, and once you start straddling that resource adequacy divide, you’re right in the middle of that state-federal jurisdictional pull,” Clark said.
Montana Public Service Commission Vice Chair Travis Kavulla said, “There’s no honest man in the conversation or debate about which jurisdiction is better, because utilities will opportunistically latch onto either side that’s perceived to maximize their profit, and the same goes for the rest of the stakeholders.
“This jurisdictional strife should probably be understood to be, as much it’s a function of law, as a function of rent-seeking or its first cousin, regulatory arbitrage,” Kavulla said.
In the absence of federal authority, there’s only so much states can do, said Kate Konschnik, director of the Climate & Energy Program at Duke University’s Nicholas Institute for Environmental Policy Solutions.
“One things states cannot do is reach into other states and dictate policy across state lines,” Konschnik said, referring to the Supreme Court’s 2016 Hughes v. Talendecision, which found that Maryland’s contract for differences with a generator could distort price signals in PJM.
Konschnik said the zero-emission credit cases in Illinois and New York are interesting because “in those two states alone, the state itself steps in and actually runs the [renewable energy credit] programs and now the ZEC programs, so there is this funny exception to the dormant Commerce Clause if the state itself is a market participant.
“So, if a state is building a public property and decides to only hire union workers from in-state, they can do that because they are acting as a purchaser or purveyor of goods rather than a regulator,” Konschnik said. “So, Illinois and New York may prevail, as they have so far in the lower courts.” (See 2nd Circuit Hears New York ZEC Appeal.)
Sen. King Calls for ‘Offensive’ on Cyberthreats
Speaking to NECPUC via video from D.C., U.S. Sen. Angus King (I-Maine) told regulators that the federal government needs to develop an “offensive response” to attacks on the grid and other critical infrastructure.
“I’m deeply concerned about the vulnerability of the grid to cyberattack either by malicious individuals, or more particularly, by international adversaries,” said King, a member of the Intelligence and Energy and Natural Resources committees. “We are not going to defeat this threat simply by defensive measures. As I’ve heard in numerous hearings, one of the great problems here in Washington is that we have no cyber doctrine. We have no cyber strategy that involves a response — an offensive response. … People that are taking advantage of those vulnerabilities essentially now pay no price. We are only trying to patch and defend.
“I believe until we develop an effective deterrent — and this is a federal responsibility — that these attacks are going to keep coming, they’re going to escalate and they’re going to become more and more serious. We have to communicate to the world that there is a price to be paid for attacking America, whether its cyber or kinetic.”
King said he is seeking to build bipartisan support “to push the administration … to form some kind of rational response so that our adversaries know there will be a price to be paid if they’re going to attack our critical infrastructure.”
Along with Sen. Jim Risch (R-Idaho), King is sponsoring a bill to partner the National Laboratories with industry to develop ways to “simplify and isolate automated systems” to holes in software systems that could be exploited by hackers.
FERC Commissioner Robert Powelson told regulators that New England’s pursuit of greenhouse gas reduction is being undermined by its aversion to adding natural gas pipelines.
“We have a lot of natural gas we’d like to share with you,” the former Pennsylvania regulator said. “During the recent bomb cyclone, this region, that’s very committed to GHG reductions, in order to keep the lights on … burned 2 million barrels of oil.”
Last year, he said, the U.S. put 763 miles of new gas pipeline into service, but only 20 miles of it, representing less than 3 Bcfd, were built in New England.
“That’s a problem,” Powelson said. “You can’t have it both ways in this conversation. The renewable portfolio standards are states’ rights, and you can … adopt those policies. But if you don’t want to deal with resource adequacy, that’s our problem. And we’re kind of hitting these little friction points that pretty soon we might as well just hand the keys over and go back to the integrated resource planning model.”
Matthew Stanberry, vice president of market development at Advanced Energy Economy, an organization of businesses promoting clean energy, said electric vehicles represent “a market that fuels vehicles differently than we have in the past and plugs into our electric system, so you have an increase in regulatory activity and examination across the country.”
Twelve states have set EV charging rates, and 13 states have opened proceedings for public feedback on the topic, he said.
Vermont Department of Public Service Commissioner June Tierney said regulators have to start thinking about what it means for every single American to be driving an EV: “Who bears the risk of bringing the supply to fuel those EVs? Who pays for the infrastructure? What do you do about the loss of [gasoline tax] revenues from the transportation fund?”
Michael Brown, manager of EV infrastructure for Nissan, said the key to EV adoption is lowering the total cost of ownership. “That includes not just the financial cost but also the customer experience, which in some ways, especially in the light-duty market, is almost the most important piece,” Brown said.
“We see in surveys that over 50% of people say they’re interested in buying an EV, and then 85% say they’re concerned about charging infrastructure not being there,” Brown said. “Just yesterday, one of our colleagues in the industry, a huge supporter, who really wanted to buy an EV, said ‘Well, it’s 100 miles to the place I go to take my vacation, and I can’t take the risk that I might not find a charging station.’”
Massachusetts Energy Secretary Matthew Beaton said regional coordination is important on an issue like EVs, which “doesn’t really know state boundaries,” to develop charging infrastructure efficiently and ease drivers’ range anxiety.
“We need to know that if we’re going from point A to point B, the infrastructure is there,” Beaton said. “That’s going to be an amazing thing and a switch that will get flipped in the psychology of the consumer … people just need to get over range anxiety.”
PowerOptions CEO Cynthia Arcate said her organization, an energy-buying consortium for nonprofits and the public sector in Massachusetts, Connecticut and Rhode Island, has learned to be selective in the technology it uses.
“When we talk about all these nifty things that we’re going to be able to do with all this technology, you really have to think about and make sure that a) the market’s not going to deliver it anyway for free; and b) that you don’t pick the wrong technology, which a lot of these companies are doing on the data analytics side,” Arcate said.
PowerOptions’ more than 400 members range from large universities and hospitals to churches and YMCAs.
Four years ago, billing analytics was the hot new thing, with everyone eager to put sensors on their circuits and know exactly what’s going on, she said.
“We spent a lot of time and money working with big sophisticated institutions, and uniformly they came back and said ‘we’re not interested,’” Arcate said.
She said customers told her, “‘I’m sick of getting reports. I don’t need another report to read. Don’t send me a report unless you’re going to tell me what it says, what I’m supposed do with it. And then do it for me.’”
PowerOptions offers customers several ways to pay for their electricity or gas service, including a fixed all-in contract, fixed price with capacity pass-through, or “two products that let the customer get visibility into the wholesale energy market without becoming a member of” New England Power Pool.
Gas customers can also purchase a “layering portfolio” to hedge prices.
“I have spent nine years … trying to get customers to move off the fixed all-in,” Arcate said. “They listen to me very patiently. They say, ‘I understand what you’re saying, but I’m going to go with the fixed price.’ That’s what customers want. They want predictability, they want certainty, they want to fix their budget and forget about it.”
Capacity prices increased sharply in most of PJM for delivery year 2021/22, with prices for the RTO rising to $140/MW-day from $76.53 last year, an increase of 83%.
The ComEd zone increased $7 to $195.55/MW-day, while Eastern MAAC dropped to $165.73 from $187.87 last year (-12%). The PSE&G zone, which cleared as part of EMAAC last year, rose to $204.29.
| PJM
The ATSI zone, which cleared along with the rest of the RTO last year, separated this year, jumping to $171.33. BGE, which was part of MAAC last year, separated at $200.30. MAAC cleared at $86.04 last year. (See Capacity Prices down in Most of PJM in 1st Year of 100% CP.)
The Base Residual Auction procured 163,627 MW for 2021/22, resulting in a 21.5% reserve margin. That was down from 165,109 MW last year and a reduction of almost 2 percentage points from last year’s 23.3% reserve margin. That was still substantially above PJM’s 15.8% reserve requirement. About 192,450 MW offered into the auction, an increase from 189,918 MW that offered in last year.
The RTO obtained 893 MW of capacity from new generation and 508 MW from uprates to existing or planned generation, a 50% drop from the new capacity acquired in the 2017 auction.
“We did see a decrease in offers from new capacity resources. That certainly was not unexpected given the trends we have seen in the last several years,” Stu Bresler, PJM’s senior vice president for operations and markets, said during a news conference Wednesday.
PJM said the higher prices in most locations reflected continued low energy market prices, which causes generators to make higher capacity offers; an increase in the net cost of new entry, reflecting depressed energy revenues; and a drop in cleared capacity and the number of new generators. Partially offsetting those factors was a lower reliability requirement reflecting lower demand forecasts.
The auction, the second under 100% Capacity Performance, also saw increases in cleared demand response, energy efficiency and renewable resources.
| PJM
DR cleared 11,126 MW, up 3,305 MW, while EE cleared 2,832 MW, a jump of 1,100 MW.
Wind cleared 1,417 MW, an increase of 529 MW. Solar cleared 570 MW, more than quadrupling from 125 MW last year.
Coal generators increased their share by 500 MW, while gas rose by 1,000 MW, including one new combined cycle plant.
Cleared imports totaled 4,052 MW, most from west of the RTO. Deducting 1,320 MW in exports resulted in a net import of 3,405 MW.
Nuclear Decline
Cleared nuclear generation totaled 19,900 MW, a drop of 7,400 MW.
“I don’t think that came as much of a surprise to the market,” Bresler said, noting he had seen estimates of an even higher drop. “We continue to see a good amount of diversity across the system.”
Exelon announced afterward that its Three Mile Island and Dresden nuclear plants, and all but a small portion of the Byron plant, failed to clear in the auction. The company’s Oyster Creek plant, which is set to retire by October 2018, did not offer in the auction.
Robbie Orvis of the clean energy consulting firm Energy Innovation said the trend wasn’t consistent across all zones.
“Not only did a substantial amount of nuclear not clear (a 7.4-GW decline from last year), but capacity prices in regions with a lot of nuclear didn’t necessarily improve much, if at all. In EMAAC, which has roughly 25% of PJM’s nuclear capacity, prices actually dropped by $22.14/MW-day,” he said. “In ComEd, which has about 32% of PJM’s nuclear capacity, prices only increased by $7.43/MW-day. The remaining regions with nuclear capacity saw healthy price increases ranging from $53.96/MW-day to $94.80/MW-day.
“It’s unclear how units might have changed their bidding behavior in response to state nuclear subsidy programs, but given the economic hardships for many nuclear plants in PJM, these results don’t point to any kind of dramatic change in market conditions,” he said.
Jennifer Chen of the Natural Resources Defense Council pointed to a theory that Exelon might have “sacrificed” some nuclear megawatts, effectively holding them out of the auction to maintain a higher price.
Exelon and the Nuclear Energy Institute said the results pointed to the need for changes in market rules to recognize nuclear plants’ contributions to greenhouse gas reductions and grid resilience.
The company said it was the fourth consecutive year that TMI failed to clear, and that the plant, which it has threatened to close in October 2019, has not been profitable for six years.
It said its Quad Cities plant cleared “as a result of” Illinois’ zero-emission credit program.
Dresden and Byron, which have capacity obligations through May 2021 and May 2022, respectively, are not in immediate risk of retirement, the company said.
NEI CEO Maria Korsnick said the results “demonstrate the economic pressures facing well-run nuclear plants” because of “distorted market forces.”
“Energy Secretary [Rick] Perry has been ringing the warning bell that fuel security and resilience are critical to energy security and national security. Only by bringing the capacity and energy markets into better balance will we be able to realize the benefits of a diverse energy supply,” she said.
Coal Increases
Although coal’s share of cleared capacity increased by 500 MW, Bresler said the auction rewarded only some coal units.
“We did see some fairly large plants that had cleared last year that did not clear this year. On the other hand, we saw … increased cleared capability on a lot of existing units. I think what that may speak to is improvements in efficiency at those plants that are making them more competitive. I think they’re real close right now, in some cases, [to] natural gas. Coal plants that have larger capabilities, that can operate efficiently, that have made the environmental upgrades that are necessary … hung in there this year,” Bresler said.
“What this auction showed is — quoting a former colleague of mine — the death of coal has been greatly exaggerated,” he added.
Orvis said the outcome “indicates that these units are doing all right in PJM, and it certainly pours some cold water on arguments in favor of providing subsidies for coal units.”
End to Seasonal Concerns?
DR offered into this year’s auction increased almost 21% to 11,887 MW, nearly 94% of which cleared. Of the 11,126 MW of DR that cleared, 96% cleared as annual CP and 452 MW cleared as summer-only resources that were aggregated with other products to meet CP’s requirement for year-round commitment.
“I was a little bit surprised by the magnitude of the increase in annual demand response that was willing to commit to the [year-round] Capacity Performance requirements in this auction,” Bresler said.
“There’s been a lot of concern expressed in some parts of the stakeholder community about limiting demand response and not allowing that summer-only capability. Frankly, between the increase in aggregation we saw here and the amount of annual that was willing to commit to those Capacity Performance requirements, I have to question whether we still have an issue there.”
In total, 715.5 MW of seasonal capacity resources cleared as part of aggregated packages, an 80% increase from the 398 MW of seasonal resources that cleared last year. This year’s total included 452.3 MW of summer DR, 209.3 MW of summer EE and 53.9 MW of summer intermittent resources, which were packaged with 715.5 MW of winter resources — mostly wind.
Chen and Orvis questioned whether the higher-than-necessary reserve margin made seasonal resources less concerned about potential CP penalties and willing to take the risk to cash in on the auction revenue.
“There’s a structural issue and maybe PJM has a point that there’s always innovation … but the issue is if you have a structural issue, there is the potential for even more seasonal resources to participate and at lower clearing prices,” Chen said.
Orvis speculated that resources might have had trouble aggregating and bid in less megawatts than they have available to leave headroom if a CP assessment occurs in the winter.
“PJM should be careful not to imply that these results mean seasonality is not an important factor, and should think carefully about why the resources participated in the way they did, and how create a more efficient and optimized market down the road,” he said.
Katherine Hamilton, executive director of the Advanced Energy Management Alliance, attributed the increase in DR to “the more reasonable amount of time that providers had to work with their customers in preparation for the new capacity market rules; to improvements in customer-sited technologies; and to investments customers have made in their back-up generators to be compliant with an EPA rule.”
“We have yet to determine the real potential of consumer load response capability, which is expanding significantly this year,” she added. “Consumer participation and choice are critical for managing cost and reliability.”
DR provider EnerNOC said it will collect more than $180 million in capacity payments from the auction.
Vistra Energy said it will receive $559 million in capacity revenue after clearing almost 9,800 MW at a weighted average clearing price of $156.47, including 2,450 MW in ComEd and 6,435 MW in the rest of RTO.
Revenues Still Down
The increase in capacity prices won’t fully make up for lower energy prices, which account for the “vast majority” of wholesale costs, Bresler said. Capacity prices are perhaps 20 to 30% of wholesale costs, while energy revenues make up between 60 and 70%, he said.
“The increase in capacity prices certainly does not outstrip … the reduction in energy prices, however there is a relationship between the two,” he said.
Chen said she was “surprised that the prices increased so much given the oversupply.”
Orvis said the near doubling of prices for most of the RTO is good for generators in general but agreed with Bresler that they don’t represent large increases.
“For a 1-GW nuclear plant running at a 90% capacity factor, a $63.47/MW-day capacity market price increase is roughly equivalent to a $3/MWh increase in the average energy market price. For a 1-GW coal plant running at a 45% capacity factor, it’s roughly equivalent to a $6/MWh increase,” he wrote in an email. “Those are pretty small in the grand scheme of things, especially for nuclear plants.”
He said the “healthy” reserve margin, even with the reduction in nuclear, was “more evidence that Trump administration claims that losing generation will cause a grid disaster are complete nonsense.”
VALLEY FORGE, Pa. — PJM stakeholders resoundingly endorsed LS Power’s controversial proposal to bring cost-containment measures into the RTO’s transmission planning process following more than two hours of debate before the Markets and Reliability Committee on Thursday.
The proposal will require PJM to evaluate cost commitments — including construction costs, return on equity and capital structure — in its analysis of competitive bids for transmission construction.
The approval came after a last-ditch attempt to delay a vote fell short.
TOs, who have been fighting the proposal for months, overwhelmingly opposed the measure, but stakeholders were won over by the chance to inject more competition and transparency into the process.
“We stand for markets. We stand for competition. We believe this … expands competition even further into the PJM processes,” said LS Power’s Sharon Segner, one of the main sponsors of the endorsed proposal.
Amendments
Thursday’s standoff was set in motion at January’s MRC, when stakeholders voted to defer a vote on an earlier LS Power proposal.
While LS Power had been heavily involved in special sessions of the Planning Committee that focused on the issue, the company had not sponsored a full-fledged proposal through PJM’s stakeholder process. It instead focused on attempting to change the RTO’s less comprehensive proposal. On the night before that proposal was set for a vote at the January MRC, LS Power submitted an alternative motion that differentiated between cost estimates and cost commitments and required PJM to weigh guarantees in its evaluation of bids.
When PJM’s proposal failed, TOs scrambled to bury the alternative LS Power proposal, eventually succeeding in having its vote deferred until the May MRC meeting with more special sessions scheduled in the interim for stakeholders to work toward consensus.
As its dispute with the TOs escalated, LS Power found allies among state consumer advocates, who pushed PJM into developing evaluation templates to standardize the bid process. TOs continued to fight the LS Power initiative and rallied behind a new RTO proposal that incorporated the templates but limited consideration of cost commitments to construction costs. LS Power also incorporated PJM’s templates but maintained its wider analysis of all cost guarantees.
At the Planning Committee meeting earlier this month, stakeholders endorsed PJM’s newest proposal, along with a recommendation that the MRC remand the issue back to the PC for further discussion. An effort to strip LS Power’s proposal of being the first voting item on the issue ultimately failed. (See Cost Containment Proposal Survives; Headed to MRC.)
In a final special session, just days before the MRC, LS Power teamed with Erik Heinle of the D.C. Office of the People’s Counsel to add several “friendly amendments” to the proposal. The revisions removed consideration of operations and maintenance cost guarantees but pushed for additional transparency and instructed PJM to work with its Independent Market Monitor to develop “comparative frameworks” for analyzing cost commitments versus cost estimates.
One would focus on construction costs, while the other would analyze ROE and capital structure commitments. While the friendly amendments were motioned and endorsed, opponents complained the repeated revisions subverted the stakeholder process.
“Once again, we haven’t followed the full process to vet the alternative motion,” Exelon’s David Weaver said.
LS Power attorney Mike Engleman of D.C. firm Engleman Fallon stridently refuted that argument, calling it “absolutely not true.”
The PC’s recommendation to remand the issue received substantial discussion at the MRC on Thursday, but supporters of the LS Power proposal opposed the delay, saying they feared it might never return for a vote.
“We are asking for a vote on the LS Power proposal, and we are strongly opposed to this notion of remanding this back to the PC,” Segner said. “Maybe it will get a vote at the PC, and maybe it won’t be based on how [the remand proposal was] drafted.”
“I think we have very different philosophical views, and I think we do need to vote” on the proposal, Heinle said. “Some things we’re not going to solve in the [stakeholder] process.”
Weaver said forcing a vote “will give an impression that the [stakeholder] process was a waste of time.”
“We do feel like that it’s not intractable,” he said, noting that TOs endorsed the templates. “But we do feel strongly that we do need time to understand impacts … so we can make sure that all stakeholders’ interests in cost containment are brought forward.”
Susan Bruce, who represents the PJM Industrial Customers Coalition, expressed “grave misgivings” with deferring the vote again, saying she felt the stakeholder process had worked. The conversation during the meeting was “very reasonable … but I worry,” she said.
“I’ve seen the conversations at the PC. I’ve read the letter,” she said, referring to a letter send by TOs to the Board of Managers requesting it order the MRC to not vote on the proposal. “With that lens, it’s a tough thing to be asked to defer this again.”
Several stakeholders, including the Monitor, urged members to reject the remand, which received a 1.95 sector-weighted vote, far short of the 3.335 threshold necessary for approval.
Following the vote, PJM’s Steve Herling said the proposals share many aspects and that while he “obviously … would have preferred” the RTO’s proposal, he was confident LS Power’s proposal is feasible.
“We believe we can implement their proposal, so at the end of the day, we’ll implement whatever is approved,” he said. “We have concerns, but we believe we can implement it.”
TOs’ Letter to Board
The sides then argued the legality of the LS Power proposal. Just a day before the meeting, 10 PJM TOs sent the board a letter arguing the proposal would infringe on the TOs’ rights under the Consolidated Transmission Owners Agreement, the Tariff and Section 205 of the Federal Power Act.
Proponents of the proposal disagreed, saying it only created a framework for PJM to evaluate bids that include cost guarantees, and that it doesn’t require TOs to include such guarantees in their bids. Heinle described the proposal as a “three-legged stool”: transparency through the evaluation templates; cost caps on ROE and capital structure; and comparative analysis informed by the Monitor.
“If incumbent transmission owners don’t choose to make a cost guarantee they don’t have to, but if they do, this puts some parameters around it,” Engleman said.
“At the end of the day, PJM looks at all relevant factors — cost just being one of them — and decides which is the right one to move forward with,” Segner explained.
American Municipal Power offered another friendly amendment, which added several small clarifications and confirmed that “neither PJM, the designated entity [winning bidder] nor any stakeholders are waiving any of their respective FPA Section 205 or 206 rights through this process.” An additional clarification on whether agreements between PJM and the winning bidder, known as designated entity agreements, would be filed at FERC was removed after PJM noted legal concerns. The remaining amendments were approved by LS Power and the proposal’s other sponsors.
PJM’s board did not respond to the TOs’ letter before the LS Power proposal was brought to a vote, where it received 92 votes in favor versus 17 votes opposed, or 3.79, well above the 3.335 threshold needed for approval.
The RTO must now work with the Monitor to develop the comparative frameworks, the first of which on construction costs is expected to be introduced in September and endorsed at the MRC on Dec. 6. It would be effective for long-term transmission proposal submission window, which runs from November to March. The second framework comparing ROE and capital structures is expected by May 1, 2019, to be effective for all submission windows going forward.
Kansas and Missouri regulators on Thursday approved Great Plains Energy’s merger with Westar Energy, the final hurdles in a stock-for-stock merger of equals with an equity value of about $15 billion.
Shareholders of Kansas-based Westar will own 52.5% of the combined company, with Missouri-based GPE, the parent of Kansas City Power & Light, controlling 47.5%.
The new company, to be called “Evergy,” will have about 964,000 Kansas and 611,000 Missouri customers. The new company’s board will initially be composed of an equal number of directors selected by Westar and GPE.
| Great Plains Energy
The Kansas Corporation Commission approved the deal Thursday afternoon after the Missouri Public Service Commission cleared it in the morning.
“We appreciate that regulators and shareholders recognize the value in combining the companies,” said GPE Chairman and CEO Terry Bassham, who will be president and CEO of Evergy. Initially, the company will continue to serve its customers as Westar and KCP&L.
The Kansas commission approved the merger based on a March 2018 settlement agreement among commission staff, the Citizens’ Utility Ratepayer Board, Sunflower Electric Power, Mid-Kansas Electric, the Kansas Power Pool, Midwest Energy and solar developer Brightergy (18-KCPE-095-MER).
Westar and KCP&L retail electric customers in Kansas will receive one-time bill credits of $30.5 million and annual credits of $11.5 million from 2019 through 2022. Following their 2018 rate cases, KCP&L and Westar will be subject to a five-year base rate moratorium assuming their authorized return on equity is at least 9.3%.
The Kansas commission imposed an additional requirement that the companies develop an integrated resource plan process to “ensure the merger maximizes the use of Kansas energy resources,” it said in a press release.
The new company will maintain headquarters in both Topeka, Kan., and Kansas City, Mo., with the Topeka headquarters guaranteed for at least 10 years. There will be no involuntary severances because of plant closings, and the company’s 5,000 employees will receive compensation and benefits at current levels for at least two years.
The Kansas commission approved the deal over the objections of Kansas Electric Cooperative, which said the settlement did not address all its concerns.
Earlier in the day, Missouri regulators approved the deal, which provides initial bill credits of $29 million for their retail ratepayers.
“The merger will create a stronger combined company, with more customers, more geographic diversification, no transaction debt to complete the merger, and the prospect for higher earnings growth rates than either GPE or Westar would be able to achieve on a stand-alone basis,” the Public Service Commission said in its order (EM-2018-0012).
Kansas regulators last year pushed back on GPE’s original plan to buy out Westar, forcing the companies to recast the transaction as a “merger of equals.”
“It’s been a circuitous route to get here,” the Topeka Capital-Journalquoted PSC Chairman Daniel Hall as saying. “We had to fight through the jurisdictional issues, then we had to dismiss the case when our sister jurisdiction ruled it was not in the public interest and start all over again with this one.”
The deal is expected to close in early June. The company expects to rebalance its capital structure by repurchasing about 60 million shares of its common stock over a two-year period.
Great Plains stock closed Thursday at $19.75/share, up 1%. Westar shares ended the day at $54.58, an increase of 0.66%.
MISO’s Steering Committee this week submitted eight new possible market improvement ideas to the Market Subcommittee for stakeholder discussion.
During a May 23 conference call, Steering Committee Chair Tia Elliott said all new Market Roadmap ideas will receive more in-depth discussion at the subcommittee, which could assign them to other stakeholder committees. MISO will also hold a stakeholder workshop on June 7 to discuss the new ideas.
Originated by the Independent Market Monitor and stakeholders, the suggestions include:
Creating financial incentives for members that provide frequency response service, as suggested by Indianapolis Power and Light.
Allowing dispatchable intermittent resources to provide regulation service, a suggestion Xcel Energy submitted with the support of several other market participants.
Evaluating the feasibility of implementing a day-ahead market on a 15-minute basis rather than on an hour-to-hour schedule under MISO’s market platform replacement project. Monitor David Patton claims that a more specific schedule would reduce make-whole payments.
Removing transmission charges from coordinated transmission service transactions with PJM, another Monitor suggestion. MISO currently applies transmission charges to these transactions when they are offered, not just when they are scheduled, and the Monitor said the charges discourage CTS offers and “undermine the potential for substantial savings.”
Expanding modeling to include equipment operating characteristics and constraints of other types of generation resources, much like MISO is improving modeling for combined cycle generators, as suggested by Ameren Missouri.
Requiring that the installed capacity of planning resources be guaranteed as deliverable through firm transmission service, as suggested by the Monitor.
Allowing load-modifying resources and emergency-only resources to receive Planning Resource Auction capacity credit “if they are expected to be reasonably available in an emergency,” according to the Monitor.
Creating a look-ahead dispatch tool for generators. DTE Energy said MISO’s current practice of publishing the next dispatch instructions on a five-minute basis “can lead to inefficiencies with generators who need to bring on or off equipment to meet this dispatch.” DTE said it has support from several other market participants on the idea.
MISO Senior Manager of Market Strategy Mia Adams said that, after the workshop, the RTO and stakeholders will begin to rank the ideas in order of importance to determine when — if at all — MISO will begin to propose market changes to address them.
The Steering Committee has the authority to veto Market Roadmap improvement ideas before they reach the Market Subcommittee if they do not fit the definition of market improvements — although it cannot discuss the merits of the ideas — but it has never exercised that power.
