Page 1254 – RTO Insider

April 15, 2019

PJM PC/TEAC Briefs: April 11, 2019

VALLEY FORGE, Pa. — PJM’s Planning Committee endorsed capacity generation rule changes for Manual 21, save for the controversial effective load-carrying capability (ELCC) calculations deferred for a vote until next month.

The endorsed revisions include a new section devoted to obtaining, maintaining or losing capacity interconnection rights (CIRs), as well as sections for installed capacity calculations and testing requirements.

New rules on testing within temperature bounds would take effect June 1, with provisions on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.

The committee will consider PJM’s ELCC calculations, as well as modifiers proposed by the American Wind Energy Association last month, at the May 16 meeting. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)

PJM wants endorsement from the Markets and Reliability Committee at its April 25 meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. The proposal would not affect UCAP values from prior auctions.

Market Efficiency Process Enhancement Task Force Gets Phase 3

Stakeholders agreed to a third phase for the Market Efficiency Process Enhancement Task Force after approving manual revisions that change how often PJM re-evaluates projects and shifts planning timelines.

The phase 2 proposal moves the long-term planning window back two months to January-April from November-February to align it with MISO’s processes. If approved at the April MRC, both RTOs would post economic drivers in January.

The mid-cycle model refresh would be made in late April to allow project proposers extra time to analyze their projects under the revised case prior to a final submission.

PJM’s Brian Chmielewski said the task force agreed the RTO will not re-evaluate any projects once a certificate of public convenience and necessity (CPCN) has been issued or — in the case of states without such a process — once construction has begun. Under current rules, PJM reviews the costs and benefits of economic-based transmission projects annually to ensure they remain economical. (See “PJM Readies Package on Market Efficiency Rule Changes,” PC/TEAC Briefs: March 7, 2019.)

Stakeholders modified proposed language in Section 1.5.7 of the Operating Agreement by adding “or relevant regulatory authority” to ensure projects that don’t require a CPCN or fall under the jurisdiction of any state agency will be covered under the new rules.

Phase 3 will tackle how regional targeted market efficiency projects address historical congestion using the same criteria as used in interregional TMEPs and possibly changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits.

Staff will seek MRC approval of the changes in April and Members Committee endorsement of Operating Agreement revisions in May. PJM wants the new rules effective Aug. 1 for the 2020/21 long-term window.

Revisit Benefit-cost Analysis, Monitor Says

The Independent Market Monitor wants stakeholders to reconsider how it performs benefit-cost analyses, noting the current process turns a blind eye to any drawbacks that come with a transmission project.

“The current analysis ignores anywhere where benefits are negative,” said Howard Haas, of Monitoring Analytics, as he presented the Monitor’s first read of a problem statement and issue charge addressing the matter. “If you are ignoring the effect on locations where the effect is negative and only accounting for effects where they are positive, you’re going to approve things you shouldn’t approve.”

Specifically, the Monitor says PJM’s current method ignores increased congestion in all zones resulting from a transmission project when calculating energy market benefits. Haas said the benefit-cost analysis does not account for the fact that transmission project costs are not subject to cost caps and may exceed estimated costs by a wide margin. When actual costs exceed estimated costs, the benefit-cost analysis is effectively meaningless and low estimated costs may result in inappropriately favoring transmission projects over market generation projects or the option of no project at all, he said.

“We think there is something we could be doing differently, and we’d like to have a discussion about what those could be,” Haas said.

While stakeholders appeared supportive of discussing some of the Monitor’s concerns, many — including PJM itself — pushed back against questioning the RTO’s 15-year planning horizon for measuring benefits.

“That was literally just approved by FERC two months ago,” PJM’s Tim Horger said. “Let’s get some experience with using this.”

In a Feb. 19 ruling, PJM won its bid to revise the benefit-cost ratio to ensure projects with delayed in-service dates only receive analysis within the existing 15-year planning horizon. Under previous rules, PJM said it spent considerable time developing ad hoc projections for years beyond the current cycle, resulting in “risky” and “unreliable” modeling.

The Monitor protested PJM’s reasoning, proposing instead a longer horizon exceeding 20 years. FERC rejected the Monitor’s arguments. (See PJM Extends Planning Window After FERC Approvals.)

“To the extent that we just had the paint dry on one filing … if we had filed our proposal, we do believe it would have been approved,” Haas said on Thursday.

Pauline Foley, PJM’s legal counsel, questioned the Monitor’s insistence on bringing the issue up now instead of during the earlier phases of the Market Efficiency Process Enhancement Task Force.

“There’s a little bit of frustration. … I think the task force is the appropriate place to bring this, and I think we need a new problem statement, frankly,” she said. “My suggestion is that this be a whole new initiative because it looks like you’re trying to revamp the market efficiency process as a whole.”

LS Power Will Seek 2nd Deferral on Transmission Replacement Language

LS Power’s Sharon Segner told the PC on Thursday she will seek another 60-day vote deferral on her company’s proposed revisions to the Regional Transmission Expansion Plan process.

Segner’s amendment to Manual 14B was slated for stakeholder endorsement at the April 25 MRC meeting. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria.

Aaron Berner, PJM manager of transmission planning, said stakeholders agreed to another deferral after conducting two educational sessions last month to discuss how projects are removed from the RTEP. (See “RTEP Removal Discussions Scheduled,” PJM PC/TEAC Briefs: March 7, 2019.)

“There is still some work to be done and some technical discussions to be had,” he said. “It’s a good step to keep moving forward. We are finding some resolution and some common ground on some of the language.”

PJM will schedule as many as five additional meetings on the subject over the coming months, Berner said.

TMI Deactivation Costs Rise $1.5 Million

Three Mile Island’s scheduled deactivation just got $1.5 million more expensive, PJM’s Phil Yum said Thursday.

The plant requested new station service to a control building with a new 230-kV bus ahead of its planned closing in September. Yum said the work is necessary in order to fulfill the deactivation request.

JCP&L Needs Transmission Line Upgrades

Jersey Central Power & Light requested a dozen transmission line upgrades, citing outdated and faulty equipment with few experts left to fix it.

FirstEnergy identified protection schemes using a certain vintage of relays and communication equipment with a history of misoperation, the utility said in a problem statement submitted to the Transmission Expansion Advisory Committee on Thursday.

Affected 230-kV lines include: Atlantic-Red Bank, Atlantic-Eaton Crest-Red Bank, Pohatcong-West Wharton, Gillette-Traynor, Greystone-West Wharton, Raritan River-Werner, Greystone-Portland, Atlantic-Smithburg, Chester-Glen Gardner, Gilbert-Glen Gardner and Chester-West Wharton.

Dominion Supplementals

Dominion Energy said customers requested two new transformers in Northampton County, N.C., and Charles City County, Va. The new units will support commercial load growth and contingency loading for the loss of an existing transformer.

Dominion also proposed a $2.5 million project to satisfy requests for a new substation in Chesterfield County, Va. The plan involves cutting into line No. 2066, installing three switches and a 230-kV circuit switcher on the high side of a new transformer.

In addition to building a third transformer at the Winterpock substation, Dominion suggests installing a four-breaker ring and a circuit switcher on the high side of the new transformer for $8.5 million. The utility also wants to spend $750,000 to install a new 230-kV circuit switcher at the Rockville substation and $4.5 million to replace an old transformer along the Chesterfield line. Transformer replacements near the Peninsula substation are estimated to cost $16.1 million.

AEP Takes over Dayton Line

Dayton Power and Light will retire its Killen substation in June and transfer use of the 345-kV Don Marquis-Stuart line to American Electric Power. AEP said it will need to bypass Killen taps in order to complete the line circuit.

– Christen Smith

April 15, 2019November 5, 2023

OSW Industry Urges Cooperation as States Covet Jobs

By Rich Heidorn Jr.

NEW YORK — Looking for a place to assemble offshore wind farms on the East Coast?

New York officials say their 63 acres at the South Brooklyn Marine Terminal could be just the place. For about $300 million, a report for the New York State Energy Research and Development Authority says, it could demolish existing warehouses, dredge the dock area and fortify the ground to withstand loads of 6,000 pounds/square foot to dedicate the port to OSW staging and deployment.

Massachusetts officials, meanwhile, are touting New Bedford, insisting the new industry can coexist with fishermen in the most productive fishing port in the country. In October, developers signed a lease to use the New Bedford Marine Commerce Terminal to stage and construct turbines for the 800-MW Vineyard Wind project 15 miles south of Martha’s Vineyard.

And Boston office buildings are renting space to members of the European OSW industry looking to create a headquarters for their U.S. operations.

East Coast states are now promising to fund the construction of nearly 18,000 MW of offshore wind, almost equal to Europe’s current capacity. While state officials say the procurements are long-term investments intended to address climate change, they acknowledge the immediate lure is economic development. The European OSW industry employs 40,000 people.

At the Business Network for Offshore Wind’s 2019 International Partnering Forum at the Grand Hyatt New York last week, the talk was all about the jobs and contracts the industry would bring. In the forum’s exhibit area, state economic development agencies and labor unions manned booths alongside engineering firms and providers of everything from cranes to helicopters to drones.

Liz Burdock, CEO of the Business Network, said that while building a local supply chain will lower the cost of U.S. OSW, it is the economic development that the industry should promote in talking with other stakeholders.

“As we talk about public acceptance and getting more people willing to support our industry, I don’t think it is really about what is the lowest cost of energy. It has to be about what is the job creation. And maybe we are going to have to pay a little bit more,” she said. “I think that’s something that we need to start saying.”

“We have every intention to be here locally,” said Jason Folsom, director of U.S. sales for MHI Vestas Offshore Wind, a joint venture between Mitsubishi Heavy Industries and turbine maker Vestas Wind Systems based in Denmark. “We do not want to run our new market businesses from Europe. We’re here to build stuff.”

Cooperation vs. Competition

Numerous speakers at the conference questioned whether states can cooperate to nurture the fledgling industry even as they compete to promote their ports as potential manufacturing hubs. Several urged states to stagger their procurements to create steady, predictable demand.

“The supply chain in the U.K. was really dependent on having consistent procurements happening,” said Eric Thumma, director of policy and regulatory affairs for Avangrid Renewables. “When they had an on-again, off-again nature of the procurements, that made it very difficult to get supply chain folks to be confident enough to invest. So, one of the challenges in the U.S. is how do you get the states to collaborate on sort of a comprehensive offshore policy?”

NYSERDA Chairman Richard Kauffman said the states are cooperating through the National Offshore Wind Research & Development Consortium, which the agency started last year with funding from the U.S. Department of Energy. Other participants include the National Renewable Energy Laboratory, Brookhaven National Laboratory, developers, and the states of Maryland, Massachusetts and Virginia.

“We frankly never realized the power of friendly competition that we started through this collaboration,” Kauffman said. “All Eastern states with water can benefit from scale.”

NYSERDA CEO Alicia Barton was asked by an audience member during one panel discussion at the IPF whether New York would invest in assets outside the state if it can’t build a manufacturing hub in any of its ports.

“We get that question a lot,” she acknowledged, without definitively answering it. “I work for the people of New York, and I am, along with Gov. [Andrew] Cuomo, committed to making New York the center for the U.S. offshore wind industry. We’re not shy about that.

“On the other hand, we are quite realistic. … We want 9,000 MW of offshore wind. That makes us a very large buyer of offshore wind, locally speaking. … It is without a doubt in our interests to see the U.S. supply chain mature [and] develop as fast as possible to see the U.S. industry scale as fast as possible so that as a large buyer, we will get the best deal possible.”

Tim Sullivan, CEO of the New Jersey Economic Development Authority, said he’s realistic. “We’d love to have those 40,000 [jobs] in New Jersey, but it’s going to be a regional thing,” he said.

Sullivan said states will need to work with community colleges and labor unions to develop the workforce needed to ensure the supply chain is developed locally. “Cobbling together wind, offshore wind and oil and gas [resources] from the European supply chain … would be a really unfortunate outcome,” he said. “That would be a terrible outcome for New Jersey … for the Northeast, because this is a once-in-a-generation opportunity.”

Sullivan said officials overseeing port development for OSW also need to balance short- and long-term considerations.

“There will be an impulse to overly design the infrastructure and the supply chain to [accommodate] the first set of projects that are moving forward as opposed to designing for an industry,” he said. “We want a network of ports that is somewhat project-agnostic, that is somewhat developer-agnostic, so it can have multiple users over the next 45 to 50 years.”

Walter Cruickshank, acting director of the U.S. Bureau of Ocean Energy Management, which awards leases and oversees OSW projects in federal waters, said his agency is doing its part to ensure the industry’s growth by developing “an efficient and predictable regulatory process.”

BOEM has issued 15 leases totaling more than 1.7 million acres at a cost of almost $477 million since 2012. The lease price per acre — which had been as low as $39 in 2013 — topped $1,000 in three auctions off Massachusetts last year.

Cruickshank said OSW projects will be subject to President Trump’s “one federal decision” executive order, which requires all federal agencies to coordinate their reviews of major infrastructure projects in a single proceeding and to issue rulings within two years.

BOEM also is taking a regional approach to its evaluation of some potential new wind energy areas (WEAs), he said.

Rather than focus on the small section of the ocean off New Hampshire’s narrow 18.5-mile coast, he said, “We see value in looking at the Gulf of Maine as a whole, and pulling in the states of Maine and Massachusetts to look … at the effect of sharing natural, socioeconomic and cultural resources to plan how we might proceed in that area.”

BOEM also is combining the planning processes for the Carolinas, with plans to identify a WEA there later this year.

Giles Dickson, CEO of WindEurope, a trade group representing the European wind industry, said success for the U.S. OSW industry will require “happy coexistence” with the military as well as the fishing and shipping industries.

NYSERDA was cognizant of those stakeholders when it issued a solicitation for the state’s first, 800-MW OSW procurement, Barton said. The agency is expected to announce the winners next month. (See Four Bidders Vie for NY Offshore Wind Project.)

“We made clear … that we wanted to see great projects,” Barton said. “That we wanted to see strong economic development commitments, that we wanted to see commitments to labor … we wanted to see fishery mitigation plans.”

100% Clean

The Atlantic states’ OSW targets are central to their efforts to reduce carbon emissions and address climate change.

In January, for example, Cuomo announced New York was nearly quadrupling its offshore wind energy goal to 9 GW as part of its plan to reach “100% clean power” by 2040. (See New York Boosts Zero-carbon, Renewable Goals.)

New Jersey, California, Hawaii, New Mexico, Puerto Rico and more than 100 cities across the country have also pledged to move to 100% renewable or “clean” energy, as have more than 150 companies, from Adobe to Walmart.

While the 100% goal has no shortage of critics who question its feasibility, those who support it say OSW will be a big part of the resulting generation mix. A recent Stanford study projected a 19% share for offshore wind, with onshore wind and utility-scale PV at 31% each.

“It’s very ambitious, but we do believe it’s actually achievable,” Barton said of Cuomo’s goal. “To achieve that target, offshore wind has to be a huge piece of the puzzle,” she added, noting that the 9,000 MW of OSW would represent 30% of the state’s load.

Barton said the 100% pledges by Cuomo and other governors reset “the conversation about what’s possible. Even a year or two, three years ago, we would not be talking about California, New York [and] New Jersey — major economies in the U.S. — committing to a 100% clean electricity. It’s been a radical mind shift. It’s clear we don’t have a lot of time … to do what we know needs to be done to combat climate [change].”

Marie Hindhede, deputy permanent secretary for the Danish Ministry of Energy, Utilities and Climate, said higher penetration by renewables doesn’t mean less reliability, noting her country had 99.99% “security of supply” despite getting three-quarters of its power from wind, solar and biomass.

To reach the 100% goal, she said, Denmark needs an active demand-side response and more transmission to sell power across national boundaries. Hindhede said power trading with other countries has been key to balancing intermittent generation thus far but that electric storage will likely be part of the solution in the future.

Steve Dayney, head of North American offshore operations for Siemens Gamesa Renewable Energy, said reaching 100% is “not really an issue of technology. It’s an issue of, do we have the will to do it? It’s an issue of how fast new technologies can emerge and how quickly can we industrialize it to make it cost-competitive.”

Ditlev Engel, CEO of DNV GL, which provides risk management and quality assurance services to OSW and other maritime energy industries, said one key to winning political support for 100% policies is to include the health-related costs of climate change and air pollution in the discussion.

“Everybody talks about the cost of electricity per megawatt or per kilowatt-hour. But what about the costs to society? Are we using the right rulers for how we set the systems up?” he asked.

April 15, 2019November 5, 2023

Longer Tx Planning Horizon Seen for OSW

By Rich Heidorn Jr.

NEW YORK — U.S. grid operators may have to consider a different way of transmission planning for offshore wind, panelists told the Business Network for Offshore Wind’s 2019 International Partnering Forum last week.

Speakers said interconnections to the land-based grid should be shared “social” resources and that queue positions shouldn’t be a deciding factor in states’ OSW solicitations.

Christer af Geijerstam, president of Equinor Wind US, said locating offshore cables is not a concern. “But if you are targeting substations that are 20 miles inland, how many times do you want to go dig up that same road for future projects? Should we pre-invest in capacity?”

Sven Utermöhlen, board member for E.ON Climate & Renewables, agreed that a long time horizon is essential to OSW transmission planning.

“If you think about 15 to 20 individual projects in the next decade or so to be constructed, you may find that there is only a handful of really suitable, sensible grid connection points … you better have a plan in place because you don’t want to dig up the same onshore connection route five times over the next 15 years.”

Repeated construction could undermine public support and complicate permitting, he said. “So, you better start thinking about a real network development plan.”

Clarke Bruno, lead partner for Anbaric Development Partners, said New York will have to expand its onshore grid to move its planned 9,000 MW of offshore wind from delivery points on Long Island and in New York City.

“Long Island [is] about a 2,400-MW load. Taking half of that 9,000 MW and trying to drop 4,500 MW into a 2,400-MW system is going to be a challenge. The same is true in New York City [with] a much larger average load of 6,400 [MW].

“There are very few interconnection points in Long Island and New York that have the degree of robustness that you would like to have. And … getting from offshore to those interconnection points, you have very few good routes, given the congestion on Long Island and the wetlands and, in New York City, the bottleneck of the Verrazano Narrows. So, with those challenges in mind, it strikes me that a planned transmission system is essential.”

The state must “plan and permit the offshore wind so that we are able to … seize the optimal interconnection points and allow equal access to all developers to those very scarce social resources.”

Gil Quiniones, CEO of the New York Power Authority, agreed with Bruno’s description of the challenges.

“Long Island, especially on the East End … we [say] ‘the wires are thinner.’ And New York City is very dense and [does not have] a lot of very easily accessible connection points. … Logic tells you that there is maybe an opportunity to have a collector system … and bring it to the optimal interconnection point. It does require planning. It requires all the regulatory bodies — state and federal — to be aligned in making that happen.”

State officials and grid operators have only begun to consider the transmission challenges of offshore wind.

The New York State Energy Research and Development Authority’s OSW Master Plan, published in January 2018, said an expandable “backbone” transmission system would offer economies of scale and reduced barriers to entry but could also lead to overbuilding and stranded asset costs. A transmission system custom-built for a single offshore facility — the “direct radial” model — would be less efficient and is limited in scope, the report said. (See NY Offshore Wind Plan Faces Tx Challenge.)

Proposed offshore wind projects in Connecticut (1,760 MW), Rhode Island (1,056 MW) and Massachusetts (6,064 MW) represent almost half of the 18,600 MW in ISO-NE’s transmission queue, Alan McBride, the RTO’s director of transmission and strategy services, told the IPF conference in a presentation.

PJM Begins Talks on OSW Tx Rules

In February, PJM’s Planning Committee approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind. (See “PC Moves Forward on Offshore Interconnection Rights,” PC/TEAC Briefs: Feb. 7, 2019.)

Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore.

Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.

The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses.

The first meeting of the initiative, on April 16, will consist of education about the RTO’s current process. Three months of exploration into alternative options are planned before members will return to the PC in August to consider endorsement of proposed changes.

April 15, 2019

ERCOT Board of Directors Briefs: April 9, 2019

ERCOT staff last week warned that forward energy markets indicate high prices this summer, which could lead to unexpected increases in credit obligations.

Given current forward prices, Mark Ruane, ERCOT director of settlements, retail and credit, told the Board of Directors during its April 9 bimonthly meeting that forward adjustment factors may increase materially as summer draws closer, leading to “substantial increases in collateral requirements for ERCOT counterparties.”

ERCOT’s April Board of Directors meeting

Ruane said the market “seems to be expecting high prices,” pointing to August forwards that approached $185/MWh for ERCOT’s North hub but settled back to $160/MWh in mid-March. July forwards were about $100/MWh, and June forwards $85/MWh.

Forward prices are used to adjust the day-ahead and real-time exposure components of ERCOT’s credit calculation. Counterparty letters-of-credit are capped at $750 million, which has been reached only three times — all during last summer.

Ruane said he wants to ensure counterparties are aware of the risks of increased credit requirements and constraints on letter-of-credit issuers, and that they maintain “appropriate collateral” and sufficient letter-of-credit capacity.

“We’re highlighting this risk because we hit the limit three times” last summer, Ruane said.

The Texas grid operator has a historically low planning reserve margin of 7.4% as it heads into summer. It is projecting a record peak of 74.9 GW this summer, with 78.2 GW of capacity on hand. (See ERCOT Summer Forecast: Record Demand, Alerts.)

Ruane also said ERCOT will be holding a mass transition drill with market participants and Texas regulatory staff during the second quarter. The drill is intended to identify potential issues in transitioning a defaulting competitive retailer’s electric service identifier IDs.

Staff, TAC Promise Updates on Cold Weather Event

ERCOT CEO Bill Magness and ENGIE’s Bob Helton, chair of the Technical Advisory Committee, both promised directors and stakeholders a future update on the grid operator’s actions to address events during an early March cold spell that led to much market consternation. (See ERCOT Generators Upset over Early March Weather Event.)

Magness said ERCOT actions “focused on delaying scheduled outages that had not begun prior to forecast peak day morning loads.” Stakeholders complained about a lack of transparency into market information and confusion over communications.

“Sometimes, it’s very important what words you use. ‘Request’ and ‘instruction’ are different things in our world,” Magness said during his CEO update. “The market has to know exactly what to expect from us when we get into these situations.”

The TAC has created a task force to determine improvements that can be made in future situations. Magness said changes could involve:

Communications and procedures during anticipated emergency conditions;
Market visibility of ERCOT forecasts as conditions change;
A process governing delay or withdrawal of planned outages; and
Consideration of cost recovery related to postponing or canceling outages for reliability reasons.

Helton said the TAC plans to hold one or two workshops on the recommendations that might come out of the work.

“We were using new tools, based on where we are today in unchartered territory,” he said. “Sometimes, when you use those tools, you find concerns. There was a little rust on those tools.”

ERCOT Board Chairman Craven Crowell (left) and CEO Bill Magness (right)

ERCOT Projecting $34M Favorable Budget Variance

Magness told the board that ERCOT is already projecting a favorable budget variance of $34 million this year, after having ended last year with a roughly $29 million favorable variance.

The CEO said the variance is driven by interest income from congestion revenue rights and continued load growth. Interest income is expected to be almost $19 million over budget this year as a result of higher balances and rates, and administrative fees are projected to be $6.1 million over budget, based on current system load actuals and forecasts.

A reduction in ERCOT project costs could add another $7 million to the variance. The grid operator moved several projects up from 2019 into 2018, accounting for much of the variance, Magness said.

Magness also unveiled ERCOT’s annual State of the Grid report in a redesigned format that features major accomplishments from 2018’s record-breaking year and highlights the grid operator’s effort to facilitate a competitive retail market, incorporate new technologies and improve cybersecurity awareness.

Directors Approve Changes to NPRR916

The board unanimously approved a pair of Nodal Protocol revision requests (NPRRs) previously endorsed by the TAC during its March meeting.

NPRR916, which changes the mitigated floor for natural gas units from a fuel-indexed price to -$20/MWh, was approved as amended by ERCOT comments. Staff recommended the mitigated floor price be reduced from its original level of $0 and also requested the NPRR’s implementation be accelerated from May 1 to April 10 to “correct inconsistencies in pricing outcomes.” (See “ERCOT to Ask Board for NPRR916 Changes,” ERCOT Briefs: Week of April 1, 2019.)

Mark Ruane, ERCOT director of settlements

The amendments were driven by recent negative gas prices at the Waha Hub and to match the mitigated floor for coal and lignite units.

NPRR909 resolves a gap in the protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators. Morgan Stanley, in the Independent Power Marketer segment, cast the lone opposing vote at the TAC “as a matter of principle,” Helton said.

Directors also approved the Human Resources and Governance Committee’s recommendation to allow business-continuity emergency purchases by ERCOT of up to $5 million and unanimously approved nine other NPRRs, a change to the Retail Market Guide (RMGRR) and a system change request (SCR) on its consent agenda:

NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, Texas Public Utility Commission rules and system design.
NPRR906: Streamlines the protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during the security-constrained economic dispatch (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities (QSEs) to match with RMGRR159’s revisions.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR8920: Modifies the resource ramp rate logic in the protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR159: Clarifies the mass transition processes and communications by shortening required minimum timelines for initial notification to affected parties from two hours to one hour, and allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed. Also clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per QSE and per counterparty. The limit will apply to the number of bid IDs per operating day.

— Tom Kleckner

April 15, 2019March 19, 2025

Supreme Court Won’t Hear ZEC Challenges

By Rich Heidorn Jr.

The U.S. Supreme Court on Monday declined to hear challenges to Illinois’ and New York’s zero-emission credit payments to nuclear plants.

The court denied the Electric Power Supply Association’s petitions for certiorari without comment. The decision left standing last September’s rulings by the 2nd and 7th U.S. Circuit Courts of Appeals that rejected claims that New York’s and Illinois’ ZECs intrude on FERC jurisdiction (18-868 Electric Power Supply Assn. v. Star, Anthony M., et al.; 18-879 Electric Power Supply Assn. v. Rhodes, John B., et al.).

EPSA had been joined by NRG Energy and Calpine in its challenges. The challengers also won support from Courts Misread Hughes on Nuke Subsidies, Supreme Court Told.)

Supreme Court | © RTO Insider

The court’s unsurprising decision — it hears only a small percentage of the cases on which it is petitioned — was a victory for Exelon, the nation’s largest nuclear operator. The company is currently lobbying for nuclear subsidies in Pennsylvania. (See related story, Nuke Talks Continue in Pa. Assembly.)

FirstEnergy also is supporting the legislative effort in Pennsylvania and a similar bill introduced Friday in Ohio to support its Davis-Besse and Perry plants.

New Jersey and Connecticut have also approved nuclear subsidies.

Hughes Ruling

EPSA’s supporters had contended the appellate courts misinterpreted the Supreme Court’s 2016 ruling in Hughes v. Talen, in which the court unanimously rejected Maryland’s contract-for-differences with a natural gas plant.

The court provided state regulators guidance for crafting subsidy programs in the future, saying it rejected Maryland’s initiative only because it was tied to PJM capacity prices. Monitoring Analytics, PJM’s Monitor, contended that legislators could easily avoid the “explicit tether” the court rejected in Hughes.

ClearView Energy Partners said the court’s refusal to hear the New York and Illinois challenges “may cement the ‘fatal defect’” in Hughes.

“In other words, the Supreme Court has not changed its stance that [states] have legal authority to favor certain resources so long as their programs do not require those resources to participate in wholesale electricity markets (even if, as a practical matter, those resources do participate in the markets),” ClearView said.

“Today’s decision likely leaves ZEC opponents looking to the market operators to propose tariff reforms that FERC can approve as the source for relief,” ClearView continued, referring to efforts to ISO-NE’s implementation of a minimum offer price rule (MOPR) for subsidized resources and FERC’s June 2018 order requiring PJM to strengthen its MOPR to address nuclear and renewable subsidies. (See FERC Orders PJM Capacity Market Revamp.)

EPSA Seeks FERC Action

EPSA CEO John Shelk said FERC — which had argued against EPSA’s claim for federal pre-emption of the Illinois law — should now act to protect wholesale market prices from being distorted by nuclear subsidies.

“Even though … FERC determined state nuclear subsides and others impair the integrity of PJM’s wholesale market, FERC has yet to fashion a solution. That is hardly what FERC told the court it would do to protect markets,” Shelk said in a statement.

“The problem has only gotten worse since the June 29, 2018, order, with emboldened nuclear subsidy seekers now pounding on the doors of state legislatures in Ohio, Pennsylvania and again in Illinois for a second helping. FERC told the appeals court the solution lies with FERC; the time for FERC to live up to that promise is now.”

The Electricity Consumers Resource Council (ELCON), which represents industrial customers, said it was disappointed in the ruling. “Subsidizing uneconomic power sources undercuts the competitiveness of U.S. manufacturing, which must maintain a global fuel cost advantage,” CEO Devin Hartman said in a statement.

Environmental Defense Fund Senior Attorney Michael Panfil praised the ruling as “great news for all states that are working to create their best possible climate and clean energy policies.”

“In case after case, our courts have confirmed that states have the fundamental legal authority to craft clean energy policies, address climate change, and work to reduce unhealthy air pollution in order to safeguard the welfare and well-being of their people,” he said. “The Supreme Court’s order today puts any lingering questions to rest.”

April 14, 2019

UPDATED: Nuke Talks Continue in Pa. Assembly

(Updated to include House hearing April 15.)

By Christen Smith

Pennsylvania senators waded into the debate over subsidizing the state’s nuclear fleet on Wednesday, questioning the owners’ need for a legislative solution at a time they are reporting substantial profits.

“You guys are not winning the war in my district,” State Sen. Mario Scavello (R) told a panel of nuclear executives during a public hearing on Senate Bill 510 on Wednesday. “When they are told their electricity bill is going to go up, that just gets to them.”

Exelon and FirstEnergy Solutions told the Senate Consumer Protection and Professional Licensure Committee that SB 510 levels the playing field for carbon-free energy sources unable to profit at low wholesale prices set by polluting fossil fuels. Both companies announced early retirements for nuclear facilities in Pennsylvania, including Three Mile Island in September and Beaver Valley in 2021.

“When the rules allow you to pollute for free, not show up when customers need the power, and get paid the same as power plants that don’t pollute and run 24/7, of course you like the rules,” said Kathleen Barron, senior vice president of government and regulatory affairs for Exelon. “Fossil generators have the luxury of having the costs of their pollution borne by society so they do not have to factor those costs into their market offers.”

Sen. Ryan Aument (R) introduced SB 510 on April 3, more than three weeks after a similar House of Representatives plan drew criticism for its perceived favoring of expensive, aging nuclear facilities instead of cheaper renewable resources or fossil fuels. (See Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill.) Both proposals create a third tier within the state’s Alternative Energy Portfolio Standard (AEPS) program, from which suppliers must buy 50% of their power by 2021. Unlike the House version, however, the Senate bill directs the Public Utility Commission to set credit prices and guarantee between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. The first two tiers of the AEPS include 16 renewable resource types with targets of 8% and 10%, respectively.

“It’s not a zero-sum game where only one resource, nuclear or renewables, can grow,” Aument said on Wednesday. “My bill makes sure there’s space in Tier III to build up a competitive renewable portfolio. I am not, nor have I ever been, interested in a direct government subsidy for the nuclear industry.”

Pennsylvania State Sen. Ryan Aument (R), S.B. 510’s prime sponsor

In February, Exelon reported record-breaking production levels for its nuclear fleet in 2018. It anticipates operating earnings of $3 to $3.30/share in 2019 based on growth in utility revenue, the impact of zero-emission credits on its New Jersey nuclear plants and previously announced cost reductions.

Sen. Kim Ward (R) pressed Exelon about the billions in profits the nuclear industry collected last year and questioned whether the company supported the bill for financial or philosophical reasons.

Barron said the wholesale market values the cheapest price over the cleanest form of energy, saying it is an unfair comparison that leaves nuclear plants with their hands tied.

“We feel like it’s a financial question of what we are earning as a result of market rules,” she said.

Dave Griffing, senior vice president of government affairs for FirstEnergy Solutions, told Ward to look no further than his company’s latest bankruptcy filings.

“FirstEnergy Solutions wouldn’t have entered into Chapter 11 restructuring if this wasn’t a financial concern,” he said. “We have two sources of revenue — generation and capacity — and those are deflated, so yes it’s a financial concern for us.” (See Judge Rejects Liability Release in FirstEnergy Reorg.)

Critics of the bill insist the subsidies disrupt the competitive wholesale market. (See Critics Warn Pa. Lawmakers Against Nuke Subsidy Bill.)

“With respect to nuclear power plants, [financial problems have] largely been limited to single-reactor units that do not possess the efficiencies of scale to be economically competitive,” said David Spigelmyer, president of the Marcellus Shale Coalition. “Currently across the United States, six nuclear power facilities have announced retirement plans. Four of the facilities are single-reactor facilities, while the other two have announced retirements due to a variety of locally significant factors, including opposition from environmental organizations.”

PJM’s Independent Market Monitor said last month that three of the RTO’s 18 nuclear facilities face revenue shortfalls through 2021. The three plants — Davis-Besse, Perry and TMI — each operate just one reactor. The remaining multiunit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without ZECs, Quad Cities would cover its costs for the next three years, according to the Monitor. (See Monitor Says PJM’s Capacity Market n ot Competitive.)

An analysis from the National Conference of State Legislatures determined SB 510 would cost $550 million in tax credits at a rate of $6.68/MWh — far lower than the prices of subsidies in Illinois, New York and New Jersey. Pennsylvania’s sheer amount of eligible megawatt-hours — $83 million spread across nine nuclear reactors — would make it the largest subsidy program nationwide.

House Resumes Hearings

The House Consumer Affairs Committee drilled deeper into questions surrounding Exelon’s profits during a second hearing on the similarly structured HB 11 on Monday. Citing the Market Monitor’s estimates, Rep. Ryan Mackenzie (R) asked Barron whether Exelon’s other Pennsylvania plants — Limerick and Peach Bottom — earned nearly $350 million combined in 2018, compared to TMI’s $37 million loss.

Barron refused to detail individual unit costs and revenue forecasts and said the Monitor’s estimates are inaccurate.

“It is inaccurate to the extent that the data is based on industry averages in terms of costs,” she said. “The Market Monitor does not have unit-specific costs, as that is competitively sensitive information. The estimates assumed there will be no change in costs and costs will stay exactly the same. It also assumes there will be no risks.”

An analysis from the National Conference of State Legislatures determined SB 510 would cost $550 million in tax credits at a rate of $6.68/MWh — far lower than the prices of subsidies in Illinois, New York and New Jersey. Pennsylvania’s sheer number of eligible megawatt-hours — $83 million spread across nine nuclear reactors — would make it the largest subsidy program nationwide.

Discussion on HB 11 will continue April 29. Barron said if no policy solution passes the legislature before June 1, TMI will shut down.

April 14, 2019

Former FERC Commissioner Brownell Named PGE Chair

By Hudson Sangree

As part of its continued leadership shakeup, PG&E Corp. said Thursday that former FERC Commissioner Nora Mead Brownell would be its new board chair and that Jeffrey Bleich, a veteran lawyer and former U.S. ambassador, would chair its utility subsidiary Pacific Gas and Electric.

“We are focused on taking additional actions to bring about real and dynamic change that reinforces our commitment to safety and continuous improvement,” PG&E said in a news release. “The appointments of Nora Mead Brownell and Jeffrey Bleich, two respected leaders with a deep understanding of the California and federal regulatory environments, underscore our commitment to engage with our stakeholders to address the state’s evolving energy challenges.”

Former FERC Commissioner Nora Mead Brownell | © *RTO Insider*

The news came a week after PG&E announced that a “refreshed” board of 13 directors, to be approved at the next board meeting, would include Brownell, Bleich and eight other new members, along with three holdovers from the current roster. The company also said Bill Johnson, the outgoing head of the Tennessee Valley Authority, would be its new CEO starting May 1. (See PG&E Names New CEO, Board Members.)

The selections were a response to calls from California’s political leaders and utility regulators for greater change at PG&E, which has been blamed for more than 90 deaths from a series of disasters in the past decade, including catastrophic wildfires and a gas pipeline explosion. Critics have said the company’s leadership was skewed toward Wall Street and lacked safety and operations expertise.

PG&E Corp. and Pacific Gas and Electric filed for Chapter 11 bankruptcy reorganization in January, citing the potential for billions of dollars in fire liability.

Some officials, including California Gov. Gavin Newsom, said the newly announced board represents only minor improvement. BlueMountain Capital, a New York-based investment firm, has put together its own slate of candidates that includes former California state treasurer and gubernatorial candidate Phil Angelides.

Brownell helped oversee the transition of NERC to FERC oversight during her term (2001-2006). She later co-founded energy consulting firm ESPY Energy Solutions and has served on the boards of directors of National Grid and Spectra Energy Partners and the advisory board of Morgan Stanley Infrastructure Partners. She was president of the National Association of Regulatory Utility Commissioners during her time as a member of the Pennsylvania Public Utility Commission.

Bleich is a former partner at the global law firm Dentons and a leader of its diplomatic consulting group, PG&E said. He previously served as special counsel to President Barack Obama and president of the California State Bar.

Kristine Schmidt, a member of the Energy Imbalance Market Governing Body who was an aide to Brownell at FERC, was also named as a new PG&E board member. Schmidt is president of Swan Consulting Services.

Brownell did not respond to requests for comment. PG&E has said it may make its new leaders available for interviews after they are “onboarded.”

April 14, 2019

MISO Gives Tentative Nod to Seasonal Capacity Design

By Amanda Durish Cook

CARMEL, Ind. — MISO now cautiously estimates that the benefits of a seasonal capacity auction would outweigh potential drawbacks.

“Right now, our working hypothesis is that it makes sense … but at the end of the day, that’s something we’re really going to have to verify,” Laura Rauch, MISO director of resource adequacy coordination, said during an Resource Adequacy Subcommittee meeting Wednesday.

The RTO last month rekindled the idea of a seasonal capacity auction as part of its multiyear resource availability and need (RAN) initiative. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)

MISO planning adviser Davey Lopez said a seasonal auction would likely create price signals that better match the fluctuating value of capacity across seasons and a “better accounting of resource availability outside of summer.” If MISO adopts a seasonal construct, it would probably establish seasonal reserve requirements.

A seasonal auction would provide “additional visibility into risks not currently captured due to variations in capacity, load, outages, transmission limitations and weather,” Lopez said.

“There may be resources that are not participating in the annual construct when it would make sense for them to participate in one season,” Lopez said, adding that retiring generation and new market entrants alike could participate as partial-year capacity resources.

Customized Energy Solutions’ David Sapper said a seasonal auction could provide a solid foundation as MISO prepares for more renewable resources in its fleet. He said seasonal distinctions make sense when considering the varying output characteristics of the “wind and solar we’re worried about.”

“Setting a framework for this in the future is pretty critical,” Rauch agreed.

But Lopez said MISO is thinking about potential tradeoffs in a seasonal capacity future. He said seasonal auctions could produce complex changes to the loss-of-load expectation (LOLE) study and resulting reserve margin requirement.

Consumers Energy engineer Jeff Beattie said that while his utility for years advocated for a seasonal auction, it has now backed off the idea.

“We’re not necessarily seeing the benefit because our fuel mix is changing. We’re going zero-carbon,” Beattie said. He noted that much of the economic benefit of a seasonal auction derived from converting annual fuel contracts into shorter duration contracts.

“Whereas now, as we’re retiring all of our fossil units, we’re not seeing that cost savings anymore. … I hope we see a study with customer benefit and savings,” Beattie told MISO staff.

But some stakeholders said zero-carbon resources reinforce a need for an auction with seasonal granularity.

Xcel Energy’s Tom McDonough said utilities’ solar additions require a more specific seasonal accreditation. He argued that it’s not appropriate for MISO to accredit solar generation according to its summer output.

“As we know in Minnesota, it’s not going to be there in the winter. It’s not diluted so we’re going to get an exaggerated credit. …We have a thing called snow that covers a solar panel,” he joked.

McDonough said he would support even more auction specificity or even a return to MISO’s earlier monthly capacity auction design.

Madison Gas and Electric’s Megan Wisersky said MISO might consider that capacity today isn’t as fungible as it used to be because of characteristics of new types of generation.

Lopez said MISO will return to the RASC in May with a skeleton design of a seasonal auction.

More LMR Details in LOLE Study

MISO will this year also model load-modifying resource availability information into its annual LOLE study, which does not currently include availability and resource lead times.

Rauch said the improved specificity in LOLE data shouldn’t be considered a process change to the study. She said MISO will only be working with more specific availability data.

But Beattie said the small study alteration should still be documented for stakeholders.

MISO also said it will postpone a plan to model sub-optimized scheduled outages in the LOLE study. The RTO took stakeholders’ advice that it should first gauge the impact of its new planned outage scheduling rules before modeling poorly scheduled outages in the LOLE study. (See “History on Repeat?” MISO, Stakeholders Debate Merits of Seasonal Auction.) In the meantime, MISO will continue to gather information on how outages affect supply.

Lopez said aside from an unusual hypothetical testing scenario with high outages and zero LMR response, material loss-of-load risk within MISO still does not occur outside of summer.

April 14, 2019

New MISO Report Starting Point for Major Grid Change

By Amanda Durish Cook

CARMEL, Ind. — MISO’s new annual report on future trends offers few specifics on the future resource mix and how the RTO will manage renewables growth and continued turnover in the resource stack.

But it does include a plethora of suggestions for market changes that could ease the transition to a still hard-to-pin-down future fleet.

Speaking during an April 9 workshop focusing on the report, MISO Consulting Adviser of Market Design Kim Sperry likened the RTO’s future uncertainty to the small row of electric vehicle charging stations in the parking lot of its Carmel headquarters. She said it remains to be seen whether every parking spot will one day host a charging station.

Sperry asked stakeholders in the room if they thought MISO’s previously identified industry trends of demarginalization, digitalization and decentralization will continue. (See Overheard at MISO Market Symposium.) Most of the about 20 attendees raised their hands, with an enthusiastic Jeff Beattie of Consumers Energy raising both.

“What’s the fleet of 2030? It can be a huge range of possibilities,” MISO Senior Manager of Market Strategy Mia Adams said.

MISO previewed its Forward Report last month by identifying three areas of focus: increasing the deliverability and availability of resources, bettering system flexibility and improving its visibility of distributed energy resources. (See MISO: Winter Emergency Another Signal for Grid Ops Change.)

The RTO said it may suggest scarcity pricing, a 15-minute day-ahead market, more storage integration efforts, modeling smart inverters in planning and collaboration with distribution operators so it can anticipate DER contributions. In the report, MISO CEO John Bear said the RTO recognized “seismic changes” affecting the energy industry at the end of 2017.

The report is part of MISO’s new Integrated Roadmap process, which combines the old Market Roadmap list of prioritized market improvements with more research and reporting on industry trends and the annual publication of an insights and strategy report to explain how major trends might affect RTO operations. (See “MISO Rebrands Market Roadmap,” Committee Considers Ways to Streamline MISO Meetings.) MISO is currently asking for new idea submissions for the Integrated Roadmap through May 1. The RTO will send out a stakeholder prioritization survey in June, and the Integrated Roadmap will be finalized in early November.

Ramping Needs

Sperry said that as multiple smaller generating plants replace large baseload plants and more customers install their own generation, MISO will need stronger resource ramping capability. She said solar and wind generation add more variability to an operating day with more peaks and troughs and steeper ramps as the wind picks up or clouds gather. A resource mix containing 20% each of wind and solar generation could require more than 10 GW of ramping ability in either direction within a few hours. MISO currently requires about a maximum 5-GW ramping capability in either direction.

“There’s much more movement occurring throughout the operating day,” Sperry said of a future with more renewable generation.

Indiana Utility Regulatory Commission staffer Dave Johnston asked if MISO has a method of measuring and predicting its zero-cost bid offers, which would drive the need for ramping. Sperry said MISO does collect data on zero-cost energy but must be mindful of confidential and proprietary information.

Adams said zero-cost energy does raise the question of whether a market based on locational marginal prices will continue to be appropriate. She said MISO may devise “more discreet revenue streams for market participants.”

“With old generation, we didn’t think about essential reliability services. Now we have to think about essential reliability service, so we might need a new market product,” Minnesota Public Utilities Commission staff member Hwikwon Ham said.

Sperry agreed and said future solutions should reconsider “planning all the way through markets and settlements.”

MISO ramp needs with a renewable mix | *MISO*

Forecasting and DER Visibility

Sperry said MISO also realizes it may soon have to stop forecasting load using historical averages as a basis.

“As the portfolio changes, that historical information is going to be a little less accurate,” she said.

“If we just had the same mix of coal and gas thermal units, but they were decentralized, would MISO still see a risk?” Johnston asked.

Adams said MISO’s lack of visibility into distributed resources, not necessarily the decentralization itself, carries the most significant planning and operations risk.

But Ham said MISO doesn’t need total visibility into distributed resources, just more open lines of communication. “MISO doesn’t need to see everything. It just needs to be communicating with the distribution companies,” Ham said.

But Adams countered that more volatility in load will require a response from the bulk electric system, most likely in the form of more flexibility to simultaneously accommodate distributed and more traditional resources.

Johnston asked exactly where MISO draws the line between utility-scale and distributed generation. “We all use this term utility-scale. Can anyone tell me what utility-scale means?” Johnston asked.

Sperry said she didn’t have a “firm” megawatt number and pointed out that even FERC rules vary in terms of what it means for generation to reach utility-scale output.

“It can be 100 kW in terms of storage resources, and I think we’re seeing things in our interconnection queue as low as 1 or 5 MW,” Sperry said.

Johnston said he found the report frustrating for its lack of detailed resource estimates. “I want to know what the problem is. I want to know how many resources are self-scheduling and bidding in at zero. … I don’t know what MISO sees. … What’s the situation now in MISO?” Johnston said.

Adams said the report is based in part on utilities’ future resource plans and that while MISO does foresee significant fleet change, the report is not an attempt to quantify the change. The report, she said, is a starting point in the stakeholder process to begin discussion on needed changes.

“We also know it’s going to take a long time to start to change our markets,” Adams said.

She also said MISO currently lacks the specifics to measure DER participation in its footprint.

“We have no DER visibility, and that’s been fine so far because there’s been very little volatility,” she said.

But Adams pointed out that MISO still needs more data and must figure out how detailed new data on intermittent and emerging technologies should be.

“Do we have to detail down to every asset and every smart thermostat? Well that seems a little out of control,” Adams said.

April 14, 2019December 13, 2023

Oncor-Sharyland-Sempra Deals Inch Toward Approval

By Tom Kleckner

A combined $1.37 billion worth of transactions involving Oncor, Sharyland Utilities and Sempra Energy all but gained regulatory approval last week following a brief hearing on the merits before the Texas Public Utility Commission.

The commission reviewed a stipulated settlement among the three companies and seven other parties, complimenting them on the agreement. The proceeding has been placed on the agenda for the PUC’s open meeting Thursday (Docket 48929).

“It took a lot of work to get here and compromise on everybody’s part,” PUC Chair DeAnn Walker said. “Thanks for bringing us something that is a very good solution to this situation.”

“I’m largely content with [the settlement],” Commissioner Arthur D’Andrea said.

The settlement agreement resolves all issues in a complex series of deals announced by the parties in October, with Sempra buying a 50% stake in Sharyland Distribution & Transmission Services and Oncor acquiring transmission owner InfraREIT. An exchange of transmission assets would increase Oncor’s footprint in West Texas and “de-REIT” the Sharyland utility in South Texas. (See Sempra, Oncor Deals Target Texas Transmission.)

Oncor, Sharyland and Sempra filed for approval with the PUC in November.

Approximately 260 miles of InfraREIT’s transmission system were previously owned by Oncor. They were exchanged for Sharyland’s distribution system as part of a 2017 rate case settlement. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)

“This is a rare opportunity for us to acquire assets in ERCOT. Assets don’t come up for sale very often,” Oncor General Counsel Matt Henry said. The assets “happen to be not only on our border but overlapping our existing transmission footprint. As everyone knows, West Texas is absolutely going nuts. We’re excited about the deal from a commercial standpoint.”

The PUC’s approval would mean Oncor will become responsible for building the infrastructure needed to accommodate Lubbock Power & Light’s move from SPP to ERCOT.

“Based on the stipulated language, Oncor would be stepping into the shoes of Sharyland and nothing would slow it down,” said Cody Faulk, an attorney representing LP&L.

PUC staff, the Office the Public Utility Counsel, Alliance for Retail Markets, Steering Committee of Cities Served by Oncor, Texas Energy Association for Marketers, Texas Industrial Energy Consumers and Hunt Consolidated were parties to the agreement. ERCOT, the city of Lubbock, Golden Spread Electric Cooperative and the Texas Cotton Ginners Association do not oppose the revised stipulation.

California-based Sempra acquired an 80% interest in Oncor early last year in a $9.45 billion all-cash buyout. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)

Sempra’s legal counsel, Ron Moss, said the company wants to be part of Texas’ “vibrant utility industry.”

“The proposed transaction represents the next step,” he said.