Shell Energy wants a seat at the GreenHat Energy settlement table, saying it is “uniquely situated” in the proceeding and could bear a disproportionate financial burden based on its outcome.
In its request for rehearing filed Friday, Shell argued FERC erred when it dismissed more than a score of late-filed motions from intervenors seeking to participate in the unwinding of GreenHat’s financial transmission rights portfolio. The company was declared in default in June 2018 after it failed to make good on its mounting losses.
“Departing from longstanding FERC policy against settlements that may have an impact on others not present during the negotiations, the commission has initiated a course of action that will allow a handful of parties to decide” the best way to liquidate GreenHat’s portfolio, Shell said (ER18-2068). PJM has said having to liquidate the portfolio under existing rules could cost members $430 million or more.
On June 5, the commission gave RTO members 90 days to settle disputes about how to move forward before kicking off a paper hearing on PJM’s request to clarify FERC’s ruling rejecting the waiver. (See FERC: PJM Settle Disputes Before GreenHat Hearing.)
GreenHat’s significant growth in exposure and MTA loss. | PJM
On Monday, Chief Administrative Law Judge Carmen A. Cintron canceled a settlement conference scheduled for Wednesday “to allow more time to prepare for future conferences.” Cintron said the cancellation would not affect a conference set for July 26.
Shell was among more than 20 petitioners that filed after the comment period for PJM’s waiver passed. FERC rejected the late filings, saying none demonstrated “requisite good cause for late intervention.”
But Shell says a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners face.
“Shell Energy entered into three bilateral transactions involving transfers of a portion of GreenHat’s now defaulted FTR portfolio to Shell Energy and back to GreenHat,” the company wrote. “As a result, PJM informed Shell Energy that it would seek guarantee and indemnification from Shell Energy for the portion of GreenHat’s FTR portfolio that was so transferred. Liquidation of GreenHat’s FTR portfolio could substantially affect the amount sought by PJM under the guarantee and indemnification claim.” (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
Shell says PJM didn’t tell the company it would be subject to this clause until after the comment period passed and that no other party participating in the settlement discussions could “adequately represent its interests.”
“Because any settlement to resolve issues related to the massive GreenHat default will necessarily impact all PJM members subject to default allocation assessment (and, in turn, ratepayers), excluding Shell Energy and others from settlement negotiations among only a few parties is unlikely to result in a settlement that is in the public interest,” the company said.
Shell further argued that its participation would not “unfairly prejudice or burden” the allowed parties, none of whom opposed its intervention.
“As Shell Energy originally explained, it is not presenting new evidence or law, nor altering any previously established procedural schedule,” the company wrote. “Shell Energy accepts the record as it stands.”
SACRAMENTO, Calif. — The wildfire package that Gov. Gavin Newsom asked lawmakers to push through in a week cleared two key committees Monday and sailed through the State Senate, 31-7, in an extraordinarily accelerated process.
Some lawmakers complained they hadn’t had time to read the voluminous bill, which was printed late Friday (AB 1054). Newsom has urged them to pass it by July 12, when the legislature adjourns for its summer recess.
The goal of such haste is to signal to credit rating agencies that the state is prepared to prop up its investor-owned utilities in the face of billions of dollars in wildfire liability. The bill includes a multibillion-dollar wildfire recovery fund that would be financed by the IOUs and a surcharge on customers’ bills. Ratepayers and utilities would each pay $10.5 billion.
Gov. Gavin Newsom wants lawmakers to pass his wildfire package by the end of this week. | Cal OES
Assemblyman Christopher Holden, a co-author of the bill and chairman of the Assembly Utilities and Energy Committee, told his Senate counterparts Monday that the measure would help “keep the lights on in order to protect customers.”
“Stable utilities are the backbone of our economy and the necessary background of our daily lives,” Holden said while presenting the bill to the Senate Energy, Utilities and Communications Committee, which passed the bill 9-2. The Senate Appropriations Committee approved it shortly afterward.
Lawmakers are under pressure to help the utilities while avoiding political blowback from any measure that could be labeled a bailout. Voter anger remains high with Pacific Gas and Electric, which has been blamed for starting massive, deadly fires in 2015, 2017 and 2018, including November’s Camp Fire, the deadliest in state history. The state’s largest utility and its parent company, PG&E Corp., filed for bankruptcy in January.
PG&E’s stock price plummeted along with its credit rating, which S&P Global Ratings now lists as “D,” its lowest mark. The price has recovered from its low point of about $6/share in January, closing at $21.73 on Monday.
Stock prices for PG&E and Southern California Edison have dropped amid uncertainly over fire liability and utilities financial stability. | Google
Southern California Edison also has been blamed for deadly fires, such as the Thomas Fire in December 2017 and the Woolsey Fire in November 2018. The Woolsey Fire and ensuing mudflows killed nearly two dozen people.
S&P rates SCE and Sempra Energy, the parent company of San Diego Gas & Electric, as BBB, an investment grade, despite concerns about the IOUs’ long-term stability. But ratings agencies have said they may downgrade the ratings if the state fails to act. Their stock prices have been less volatile than PG&E’s.
AB 1054 includes provisions intended to increase the accountability of utilities for safety. To draw from the recovery fund, the IOUs would have to link executive compensation to safety performance. The California Public Utilities Commission would have to certify a utility had acted reasonably before it could recover wildfire costs.
Testimony and comments at Monday’s hearing were largely positive, even from staunch critics of the IOUs.
Up from the Ashes, a wildfire victims’ group, said it supported the bill because it could compensate victims more quickly. And The Utility Reform Network (TURN) backed the bill, with reservations, because it requires the utilities to contribute billions of dollars to the recovery fund.
Those who opposed it included some fire victims and Sen. Scott Weiner, a San Francisco Democrat, who took issue with a provision that could make it more difficult for utilities to sell assets. San Francisco is considering a bid to purchase PG&E’s equipment and establish a municipal utility.
The legislation goes next to the State Assembly for a concurrence vote as early as Thursday. Because it is an urgency measure that would take effect immediately upon being enacted, it requires a two-thirds supermajority vote by both houses to get to Newsom’s desk.
Saying recent Texas legislation has rendered their case moot, Entergy, Southwestern Public Service and Texas Industrial Energy Consumers have asked to dismiss their appeal of a Public Utility Commission order negating an incumbent utility’s right of first refusal (03-18-00666-cv).
The parties told the Texas Third Court of Appeals in Austin on June 21 that Senate Bill 1938, passed in May, has “mooted the underlying controversy”: an appeal of a 2017 PUC ruling that SPS does not have the exclusive right to build transmission facilities in its service territory.
But Southwest Transmission and GridLiance High Plains asked the Texas court on June 27 to reject the motion to dismiss pending the resolution of a separate federal court challenge to the legislation.
The bill, which Gov. Greg Abbott signed on May 16, amended the Public Utility Regulatory Act to grant certificates of convenience and necessity (CCNs) to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” That essentially cuts out independent transmission companies from competing for projects anywhere in Texas, including for FERC Order 1000 projects in non-ERCOT areas. (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
In their filing, the parties said the Texas Legislature “has thus clarified that Texas law” gives SPS and Entergy “the exclusive right to build new transmission lines in their respective service territories.”
RTO boundaries in Texas | ERCOT
The parties also said the bill clarifies the Legislature’s intent to retain the state’s jurisdiction over retail rates in non-ERCOT areas of Texas “by effectively prohibiting the certification of new-entrant, transmission-only utilities whose rates would be subject to FERC’s exclusive jurisdiction.”
Because no transmission-only utilities currently operate in Texas’s non-ERCOT regions, the parties said, “the exclusivity provisions and limitations on transfers of certificate rights to utilities already certified within a particular power region will act as a bar to any future certification of such entities.”
Entergy, SPS and TIEC, a trade association of the state’s largest consumers, had appealed a Travis County District Court ruling that agreed with the PUC’s 2017 order (Docket 46901). The commission ruled that existing law did not give SPS a ROFR, and that it could award CCNs to transmission-only utilities in the state’s non-ERCOT regions. (See Texas Commission Rejects SPS ROFR Request.)
The PUC told the court June 27 that it was “unopposed” to the motion to dismiss.
But Southwest Transmission and GridLiance High Plains asked the court to consider staying the case pending NextEra Energy’s challenge of the constitutionality of SB 1938. (See NextEra Takes Texas to Court over ROFR Law.)
NextEra’s challenge, filed in the U.S. District Court for the Western District of Texas on June 17, alleges SB 1938 is unconstitutional because it violates the dormant Commerce Clause and the Contracts Clause.
| Wind Energy Transmission Texas
“It is entirely possible that the federal district court may decide that the PURA provisions enacted under SB 1938 are, as alleged in NextEra’s lawsuit, unconstitutional and thus invalid and unenforceable,” the companies said. “A dismissal of the [Texas] appeal at this juncture, when NextEra’s lawsuit is pending, would potentially result in a still valid trial court judgment being vacated and the need for one or more of the parties to this case to refile and pursue a new, redundant appeal of the underlying PUC decision.”
NextEra transmission subsidiaries had won a competitive bid for a MISO 500-kV project in Southeast Texas and had a CCN application pending before the PUC to assume ownership of 138-kV facilities in Northeast Texas.
A huge spike in natural gas prices drove up the cost of wholesale electricity in CAISO by more than 40% in the first quarter of 2019 compared with the same period a year ago, the ISO’s Department of Market Monitoring reported.
However, the disparity between income and payments for congestion revenue rights dramatically improved since the first quarter of 2018, lessening costs for ratepayers, the department said.
The Monitor reported the mixed first-quarter results in a July 2 web conference.
Amelia Blanke, CAISO manager of monitoring and reporting, said it cost about $2.7 billion — or $55/MWh — to serve load in the ISO’s territory during the first three months of this year. That was a 42% increase from Q1 2018.
Gas prices were 73% higher in the first three months of 2019 than they were in the first quarter of 2018, the Monitor reported. Lower temperatures, high heating demand, and supply constraints led to gas prices that more than doubled from January to February of this year.
“High natural gas prices in February 2019, at both SoCal and PG&E Citygate, were the main driver of high system marginal energy prices across the ISO footprint,” the Monitor said in its Q1 Report on Market Issues and Performance.
Gas prices in CAISO spiked in the first quarter of 2019, driving up electricity costs. | CAISO
As a result, average day-ahead electricity prices increased “by around $17/MWh (almost 50%), 15-minute by about $15/MWh (45%) and five-minute market prices by $13/MWh (35%) in comparison to the same quarter in 2018,” it said.
The Monitor noted that natural gas units are often the marginal source of generation in CAISO and the rest of the West.
The Northwest Sumas gas hub in the Pacific Northwest saw record high gas prices during the winter months of 2019.
“The price spike comes amid limited supply deliverability and unseasonably cold temperatures, which drove up demand in the Northwest,” the Monitor said. “Prices at the Sumas gas hub have been volatile since the Oct. 9, 2018, Canadian gas pipeline explosion reducing imports into hubs in the Northwest.” (See NW Price Spike a Wake-up Call,’ Ex-BPA Chief Says.)
The high gas prices were offset by increased generation from wind and hydroelectric resources.
“Compared to 2018, hydroelectric production in the first quarter increased by roughly 47%,” the report said.
The extremely wet winter in California increased snowpack to 175% of normal on April 1, compared to 58% of normal on the same date in 2018.
Compared to the first quarter of 2018, wind production increased while solar production dropped slightly, despite increased solar capacity. “This was likely due to greater curtailments resulting from high hydro and wind production,” the Monitor said. “In March 2019, renewable curtailment reached record levels, roughly 125,000 MWh.”
“The ISO became a net exporter on average during peak solar hours [noon to 3 p.m.] over the entire quarter, as imports fell and exports increased in these hours relative to prior quarters,” the Monitor added.
Closing the Gap in CRRs
The first-quarter 2019 results also suggested that changes CAISO implemented last year to CRR auctions are working.
The gap between auction revenues and payments to owners of congestion revenue rights in CAISO fell in Q1. | CAISO
The Monitor reported that income from the auctions fell short of payments to purchasers by $1.5 million in the first quarter of 2019 — a sharp drop from the $43 million difference in the first quarter of 2018.
Payments and revenues were closer to parity than in any first quarter since 2012, the Monitor reported.
Ratepayers have been covering big losses in the CRR auctions since they were implemented in 2009. The total loss is now about $860 million, the Monitor said in its report. (See CAISO Q4 CRR Revenues Falling Short After Summer Surplus.) The main beneficiaries have been financial entities that purchase the CRRs, betting on profits.
“The decrease in losses to transmission ratepayers from sales of congestion revenue rights is due in part to changes to the auction implemented by the ISO in 2019, which limit the source and sink of congestion revenue rights that can be purchased in the auction,” the Monitor said.
FERC has accepted SPP’s proposal to refine its generator interconnection procedures by instituting a three-stage study process (ER19-1579).
The RTO’s Tariff revisions adopt a three-phase process of thermal and voltage analysis, stability analysis, and facilities study. They also change the eligibility for refunds of financial security.
The commission rejected concerns from Enel Green Power and EDF Renewables that SPP did not have the staff and resources to accomplish all the revisions’ components.
“We are not persuaded to substitute our judgment for SPP’s in determining the level of staff and resources that SPP needs to implement its proposal,” the commission wrote in the June 28 order. It pointed out that the reforms might reduce redundancies and result in the “more efficient use of administrative time” that could be devoted to the new study process.
The changes include the elimination of the feasibility and preliminary queues, changes to the amount and timing of security deposits, publishing study models earlier in the process, and allowing penalty-free withdrawals when costs increase above certain thresholds. They became effective July 1.
The Tariff revisions were approved by SPP stakeholders in January following several years of development. The RTO filed its request in April. (See “Stakeholders Approve Streamlined Generator Interconnection Process,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)
3-Stage SPP Generator Interconnection Study Process | SPP
In its filing, SPP said it had more than 440 interconnection or modification requests, totaling 81 GW of new generation capacity, in its interconnection study queue.
Enel and EDF argued it was unjust and unreasonable to “subject interconnection customers to higher and potentially nonrefundable financial security and a longer queue process” if SPP was unable to efficiently handle the process studies.
FERC disagreed, saying SPP’s proposal to separate the security deposit into three payments, which are due before each of the three phases and become “further at-risk as the interconnection customer progresses through the queue … should help dissuade more speculative projects from entering later study phases, which should decrease the number of late-stage, disruptive withdrawals.”
The commission also found the security deposit’s financial outlays were not “excessive.”
“Under SPP’s design, the total financial security an interconnection customer will pay is roughly 20% of its estimated network upgrade cost responsibility, which is the total payment required for SPP’s existing initial payment,” FERC said.
Michigan regulators are calling on the state’s gas and electric utilities to step up measures to head off supply emergencies like the one that arose this past winter during a deep freeze.
While a draft report released by the Michigan Public Service Commission on July 1 determined that the state’s energy systems are adequate to meet customer needs, it also urged utilities to undertake a raft of improvements to address extreme weather events, security threats and the expanded use of renewable energy sources.
Gov. Gretchen Whitmer ordered the statewide energy assessment after a polar vortex struck the state Jan. 30-31. During the event, both Consumers Energy and DTE Energy issued public appeals for conservation, while Whitmer appeared on video via social media to ask ratepayers to lower thermostats or risk a gas shortage. Consumers’ gas scarcity was compounded by a fire at Ray Compressor Station near Detroit. (See “Gas Shortage Warnings,” MISO Maintains Reliability Through Arctic Midwest Temps.)
Consumers Energy’s Ray Compressor Station | Wallbridge
“Despite the positive outcome, the events of Jan. 30 and 31 raised significant concerns about whether Michigan’s energy systems can reliably produce and deliver energy to all Michiganders as extreme weather events increase,” the PSC said.
The agency was asked to evaluate whether the design of electric, natural gas and propane delivery systems are “adequate to account for operational problems, changing conditions and extreme weather events” (U-20464). The 231-page report makes 36 recommendations within the commission’s jurisdiction and 14 “observations” outside the scope of its jurisdiction.
Among its major recommendations, the PSC said utilities should:
Incorporate five-year-ahead distribution and transmission plans into the integrated resource plans required by the state. The commission said the move would “ensure truly integrated electricity system planning” and could expand electrical connections between Michigan’s peninsulas and neighboring states. It said an expanded ability to import electricity could address short- and long-term reliability issues.
Undertake “long-term, risk-based” natural gas infrastructure and maintenance planning. It also recommended natural gas utilities include equipment and facility outages in risk models and better plan for transmission contingencies.
Make more careful retrofitting, retirement and new power plant build decisions. The agency said utilities should work with stakeholders “to understand the value of resource supply diversity” and not rely so heavily on traditional planning and financial analyses. Utilities should “propose a methodology to quantify the value of generation diversity in integrated resource plans.”
Re-examine natural gas utility curtailment procedures to make sure they “prioritize home heating over electric generation.”
Improve electric demand response programs “since some customers did not respond as expected during the polar vortex, and utility tariffs were inconsistent.” The PSC said natural gas utilities should also work to create DR programs “as an alternative to broad emergency appeals.” Utilities should also review their communication protocols with customers during DR events.
Create rules for cybersecurity and incident reporting for natural gas utilities and improve energy system cybersecurity in general. The PSC suggested utilities undertake regular IT audits, simulated phishing campaigns, multifactor authentication for remote access and cybersecurity performance assessments.
Develop standardized communications with the commission for electric and natural gas emergency events.
Expand use of emergency drills “to provide a range of scenarios besides outage management and restoration.” The PSC said utilities should also test curtailment and DR events. “Communication related to the Ray event and the polar vortex was confusing, inconsistent and erratic,” it concluded.
Improve communications and data sharing in general between electric utilities, PSC staff and RTOs to ensure that the “RTOs will have the information needed to plan and operate the electric system to accommodate an increasing amount of distributed energy resources.”
“Overall, the energy system is strong but would benefit from increased resilience, strengthened infrastructure interconnections and improved communication,” PSC Chairman Sally Talberg said.
The PSC also found that MISO should enact a seasonal capacity auction, “more carefully consider” non-transmission alternatives prior to approving transmission projects and speed up its generator interconnection queue — although those items are outside of the regulator’s purview.
The commission also found that Michigan statue limits the PSC in assessing “meaningful penalties” for utilities that are not in compliance with the Michigan Gas Safety Standards. “This may impact the health, safety and welfare of Michigan residents,” the PSC said.
The commission formed five work groups — focusing on electricity, natural gas, propane, cyber and physical security, and energy emergency management — and hosted more than 40 internal and external meetings to create the initial report.
After a public comment period, the commission will deliver a final report to Gov. Whitmer by Sept. 13. The commission could then order utilities to take steps to improve their energy supply and delivery processes.
Consumers Energy linemen in winter | Consumers Energy
“Moving forward, this report will help to inform our next steps in assuring all Michiganders have reliable access to energy when they need it at home, at school and at work. With the transition to more renewable energy resources and the growing impact of climate change, it is imperative that our utility infrastructure can meet the changing demands while keeping rates affordable and protecting the environment,” Whitmer said in a press release.
In its latest resource adequacy survey, the Organization of MISO States identified Michigan’s Lower Peninsula as one of three MISO areas that could soon experience supply shortages, with a potential 0.9-GW shortage as early as 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)
America’s wholesale electricity markets are at a turning point.
Their rules, products and software were developed in the late 20th century around a fossil fuel-based resource mix in which large central station plants are dispatched to meet unalterable demand. Marginal cost dispatch, in large part determined by fuel costs, has been the principle factor supporting prices and revenues; helping introduce competition into a growing system composed of large baseload power plants with high fixed costs and low production costs; and more flexible power plants with lower fixed costs and higher production costs.
But the 21st century electricity mix is evolving in significantly different ways from the 20th century system. The share of non-fuel resources like wind and solar is growing thanks to falling costs and states like California, Nevada and New York setting 100% clean energy goals. These resources differ in several important ways:
They typically have near-zero production costs, creating implications for market prices and plant revenue.
Newer resources tend to have smaller minimum unit sizes and can be deployed more quickly and in smaller sizes.
These resources have different production characteristics than many existing plants (e.g., output tied to sunlight). Operating the grid around resource availability is not a new concept, but doing so daily for many resources is pushing operators to consider new rules and products.
These resources can provide services better or cheaper than older ones — such as creating (very) fast frequency response using power electronics as a replacement for inertia.
Meanwhile, technological barriers limiting demand-side flexibility are disappearing through smart thermostats, water heaters and the “Internet of things.” Serious technological changes are upon us, but concomitant changes in market incentives and rules are lagging behind.
Given these changes, a new series of research papers by energy policy think tank Energy Innovation seeks to answer the question of whether and how wholesale electricity markets must evolve by asking: “Which market design provides the best framework for reliably integrating clean energy at least cost?”
A Vision of the Future for Wholesale Electricity Markets
Future market designs must answer several important questions as the resource mix evolves; for example, how can sufficient investment signals be maintained, and how will new resources be efficiently financed? Similarly, how will markets expose the value of important system characteristics, such as flexibility, through this transition? Finally, given the trend in state policy, how can future market designs address carbon policy?
ERCOT control room
Two pathways have emerged in conversations that aim to answer these questions about future markets. The “Robust Spot Market” model emphasizes improving today’s markets for energy and services, eschewing capacity markets, and relying on voluntary decentralized bilateral contracting. The “Long-Term Plus Short-Term Markets” model envisions complementing those improved energy and services markets with an advanced, centralized, forward market for needed resources and services.
Both pathways agree on important features for modern markets:
Competitive wholesale electricity markets are a good thing: Trading over a diverse portfolio of resources augments reliability and decreases overall costs. The larger the market, the greater the benefits.
Wholesale electricity markets need to work with external (state or federal) policies governing the electricity system, not work against (i.e., mitigate) them.
Shorter dispatch intervals and multiperiod optimization can make markets more efficient.
The capacity markets in use around the U.S. today, which largely trade capacity without much regard to the operational characteristics of the energy resources being traded, should be fundamentally transformed or eliminated.
But important differences exist between the pathways, driven in part by differing views on key questions:
How big of a risk is political interference in markets?
How much do we expect the “real world” to behave as theory suggests?
How strong are the counterparties in markets, and how strong do we expect them to be in the future; i.e., can we expect utilities or other load-serving entities to be able to buy flexible and well hedged smart energy resource portfolios to serve customers over the long term?
What extent can factors other than strict production costs set LMPs; i.e., congestion in the transmission system, ancillary service needs or other opportunity costs? If those other factors do play a substantial role setting LMPs, what is the risk that real-world prices (which may be in part driven by uneven retirements) are too low to attract needed flexibility resources or too high to expose their value?
Is keeping voluntary bilateral markets (which already underlie centralized wholesale electricity markets) decentralized the best approach, or would centralizing and organizing those bilateral contracts be more beneficial?
Wholesale electricity markets will evolve differently in various regions, but the macro issues facing markets are extremely important for grid managers to study and deliberately consider as the electricity system decarbonizes.
Robbie Orvis is the Director of Energy Policy Design at Energy Innovation, where he works on the firm’s Energy Policy Solutions and Power Sector Transformation programs.
WILMINGTON, Del. — PJM CEO Andy Ott attended his last Markets and Reliability and Members committee meetings on Thursday, capping more than two decades with the organization.
Ott announced his retirement last month — the second top executive to leave PJM this year. (See PJM CEO Andy Ott to Retire.)
“He’s been instrumental in the development of our markets,” MC Vice Chairman Steve Lieberman said. “PJM has really been a leader in these markets, and we certainly appreciate that and his decades of service to PJM. You will leave a very good legacy.”
Lieberman then presented Ott with an inscribed compass on behalf of the membership that read, “To Andy, with appreciation, for your service to PJM.”
The MRC reluctantly endorsed a problem statement and issue charge in March after some doubted the necessity to discuss the fuel security issue and even contended that PJM already had a solution in mind. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)
Tim Horger, PJM’s director of energy market operations, said the task force remains on track to report its recommendations on the first four key work activities at the September MRC, including: providing education on the issue; quantifying the risk of selected scenarios that could risk fuel security; defining fuel/energy security; and determining whether there is a quantifiable and/or locational requirement for fuel/energy security.
RTEP Removal Language Deferred a 3rd Time
Voting on language that alters the way PJM manages supplemental projects in the Regional Transmission Expansion Plan was delayed a third time.
Both RTO staff and LS Power’s Sharon Segner pushed for the 30-day deferral, telling the MRC that stakeholders at the special Planning Committee sessions have four more issues to resolve before seeking a vote. (See “RTEP Poll,” PJM PC/TEAC Briefs: June 13, 2019.)
Segner gave a brief description of the four outstanding issues: conversion and how supplementals become baseline projects without undergoing the Order 1000 planning process; the displacement of supplemental projects through the regional planning process; ensuring that supplemental projects do not undermine the integrity of the Order 1000 process; and PJM’s authority to remove supplementals from the RTEP once permits have been denied.
“Folks are trying to focus on principles here rather than just wordsmithing the manuals,” she said. “At the heart of the issue is PJM’s fundamental authority over its RTEP, especially as it relates to removing supplementals from the plan.”
Capacity Interconnection Rights
Carl Johnson, on behalf of the PJM Public Power Coalition, presented a first read of a problem statement and issue charge that forms a task force to discuss the rights and responsibilities of stakeholders with capacity interconnection rights (CIRs).
“You may recall this issue got tangled up in the must-offer exception process,” he said. “It became very clear that we didn’t all agree what rights they convey or what they meant or what their value was.” (See Showdown Set on PJM Must-offer Exceptions.)
The issue charge divides the work into two phases that will potentially culminate in revisions to section 230 of the Operating Agreement and Manual 14G.
Johnson said stakeholders will consider if CIRs should:
Continue to be the proper mechanism for conveying the rights and responsibilities associated with them, or whether they should be modified or a new mechanism introduced.
Should be returned to system capability due to being unutilized in the capacity market by a resource.
Create an obligation for a resource to participate in the capacity market.
Manuals Endorsed
Manual 14G: Clarifies requirements for term of site control, NERC-accepted stability models and corrections to references and links.
Manual 6: Cover-to-cover review that aligns with parts of the OASIS refresh and removes financial transmission rights credit business rules from section 6.7 and refers readers to Tariff/credit overview and supplemental documents on PJM’s website.
The MRC and MC will no longer meet at the Chase Center in Wilmington after voting to move all subsequent meetings to the PJM Conference and Training Center in Valley Forge, Pa.
NEWPORT, R.I. — A new effort by the New England Power Pool could give ISO-NE’s most “senior” board members a longer shot at keeping their positions rather than aging out of eligibility.
The NEPOOL Participants Committee on June 25 approved a motion to ballot all members on a proposal to amend the Participants Agreement to allow people older than 70 to serve on the RTO’s Board of Directors.
Members will specifically vote on authorizing the Joint Nominating Committee to waive the current 70-year-old age limit for candidates to stand for election or re-election, just as it now is authorized to waive the limit on three consecutive full terms.
According to a memo from PC Counsel Pat Gerity, RTO representatives told NEPOOL officers that the age limit reduces the pool of qualified candidates, risking the loss of “highly qualified and broadly supported board members” who turn 70. Without a waiver, Director Roberto Denis would age out next September after serving only two terms.
Janice Dickstein, ISO-NE vice president for human resources, said that while corporate boards increasingly rely on age limits rather than term limits, the RTO’s age cap is more restrictive than 90% of organizations. She noted that most people serve on boards in their retirement, and that it takes time to get new board members up to speed on the issues specific to the region.
The PC approved the motion to issue the ballots with 76.88% of sectors in favor (Generation, 11.19%; Transmission, 16.79%; Supplier, 13.59%; Alternative Resources, 16.04%; Publicly Owned Entity, 16.46%; and End User, 2.81%).
For the PC to approve the amendment, the returned ballots need to represent at least half of fixed voting shares in each of a majority of NEPOOL sectors and achieve an overall 70% vote in favor.
The PC also approved balloting members on changing a sector definition, with Gas Industry proposed to become Fuels Industry. Subject to a positive vote and FERC acceptance, the American Petroleum Institute may apply to join NEPOOL as a Fuels Industry participant.
No Easing of Credit Requirements
The PC voted down a motion to change ISO-NE’s Financial Assurance Policy (FAP) to allow market participants to use affiliate parent guarantees to obtain “an unsecured market credit limit or transmission credit limit” or use surety bonds “as an acceptable form of financial assurance.”
The vote was 45.13% in favor (Generation, 16.79%; Transmission, 0%; Supplier, 11.55%; Alternative Resources, 9.44%; Publicly Owned Entity, 7.35%; and End User, 0%).
The proposal was sponsored by Calpine Energy Services, Direct Energy Business, Dominion Energy Generation Marketing, Exelon, Massachusetts Municipal Wholesale Electric Co., NextEra Energy Resources and PSEG Energy Resources & Trade.
The PC in 2004 voted to eliminate surety bonds from the FAP and in 2010 to eliminate parent guarantees.
ISO-NE opposed the proposal mainly as a threat to its ability to clear the markets because of reduced liquidity. It also feared that introducing weaker forms of financial assurance could result in substantial or even catastrophic losses to the RTO and its market participants.
Nested Capacity Tariff Changes Approved
The PC unanimously approved Tariff changes to accommodate the new modeling concept of nested export-constrained capacity zones in the Forward Capacity Market, starting with Forward Capacity Auction 14 to cover the one-year capacity commitment period beginning June 1, 2023.
The revisions address those cases where it’s necessary to distinguish between a parent and nested zone (which represents a sub-zone within a parent zone), such as when capacity clearing price calculations differ slightly between the two.
Most of section III.13 of the Tariff already recognizes nested capacity zones, while other sections do not specify the type of zone when dealing with reconfiguration auctions or many settlement provisions.
The first set of changes accommodate nested export-constrained capacity zones in the FCM, while the remainder clarify certain data submittals of costs and revenues for static delist and export bids in the FCM.
The RTO developed the changes, which were recommended by NEPOOL’s Markets Committee.
ISO-NE CEO/COO Reports
ISO-NE CEO Gordon van Welie told the PC that the grid operator recognizes the market has to be adapted to the changing power system.
He said the region is rapidly catching up with California and Europe in the deployment of energy storage resources, but that there are few places as constrained as New England. Nonetheless, the region has a good track record in solving problems, he said.
COO Vamsi Chadalavada reported that the RTO has so far received a record “show of interest” for FCA 14: more than 700 applications, compared to 250 for the last auction.
New generation and new demand resources show new entry dominated by natural gas and energy efficiency. | ISO-NE
New capacity resource qualification is ongoing, and approximately 336 MW are available for the renewable technology resource exemption, he said.
The existing capacity resource qualification is complete, with about 258 MW of retirement delist bids and 21 MW of permanent delist bids received on March 15. Static delist bids were due June 13.
Chadalavada said the region has enough resources to replace the 690-MW Pilgrim nuclear plant, which retired at the end of May, largely with new resources coming into the market in southeastern Massachusetts.
FERC Update
FERC Commissioner Cheryl LaFleur, who is leaving the commission at the end of August, spoke of three broad themes facing the commission: resources for reliability, how to pay for them and needed infrastructure. She said the commission has the choice of regulating in a planned way by giving authority back to the states, or in an unplanned way by letting the market be cannibalized.
LaFleur said she looks forward to seeing NYISO’s carbon pricing proposal when it is submitted and also suggested to the industry that now is not the time to submit filings containing open-ended legal questions, but rather agreements that parties have worked out among themselves.
She congratulated NEPOOL on being vital to the region, but she noted that the organization was not without controversy, mainly concerning its transparency, as evidenced by congressional hearings earlier in June, when Rep. Joe Kennedy III (D-Mass.) told her that “unless you are a member, you can’t even observe any meetings or proceedings, let alone talk about it publicly.” (See FERC Probed on RTO Governance, Market Issues.)
Jette Gebhart, deputy director of FERC’s Office of Energy Market Regulation, told the PC that commission staff are busy now working through energy storage compliance filings.
EMM Report
ISO-NE last year had the highest energy prices of any RTO because of high natural gas costs, as well as the highest net revenues because of higher capacity revenues, External Market Monitor David Patton said, highlighting his still unpublished 2018 assessment of the ISO-NE markets.
The assessment shows ISO-NE had about one-tenth the congestion of other RTO markets because of substantial transmission investments over the past five years. However, transmission service costs were more than double the average rates in other RTO markets, Patton noted.
ISO-NE last year had the highest energy prices of all RTOs because of higher natural gas prices; it also had the highest net revenues because of higher capacity revenues. However, the EMM says this is not sustainable given falling capacity prices. | Potomac Economics
The first 13 FCAs reflect the retirement of nearly 5 GW of nuclear, coal and older steam turbine capacity, with increased reliance on gas-fired capacity. Fuel security concerns are heightened by the potential retirement of Exelon’s Mystic Generating Station and the Distrigas LNG facility, Patton’s report noted.
The EMM’s baseline scenario fuel security evaluation for a two-week severe winter period shows very high utilization of oil inventory capacity and the need for LNG import capability, while load shedding would occur in a scenario with major reductions in natural gas availability.
The RTO’s operational fuel security analysis (OFSA) last year also found tight fuel supply margins that could result in load shedding in the winters of 2022-2023 and 2023-2024, and in March ISO-NE filed an interim proposal with FERC to address winter energy security for those commitment periods. (See NEPOOL MC Debates Energy Security Models.)
Consent Agenda
The PC approved four rule changes on the consent agenda, following unanimous approvals at lower committees:
OP-14 Appendix B (Reporting Requirements for Asset Related Demands and Dispatchable Asset Related Demands): Revisions to establish reporting requirements and cleanup changes to improve document flow. Recommended by the Reliability Committee.
Tariff Section III.1.5.3: Revisions to include all dynamic resources in reactive capability audit requirements and specify criteria for such resources to perform such audits. Recommended by the Reliability Committee.
Tariff Section I.2.2, OP-23 and OP-23G: Revisions related to reactive resources required to perform reactive capability auditing. The PC approved them with the understanding that two additional Tariff definitions would go back to the Reliability Committee, which recommended the measure.
Revisions to Tariff Section II Schedule 2 to accommodate introduction of energy storage facilities and other administrative changes. Recommended by the Transmission Committee.
SAN ANTONIO — Grid safety and security were the focus of the Texas Renewable Energy Industries Alliance’s (TREIA) annual GridNEXT conference last week.
Speakers during the event Thursday addressed a variety of related topics, from protecting critical assets and safeguarding vital data, to the role renewables and microgrids will play in ensuring a more reliable and resilient grid.
TREIA board member Ingmar Sterzing, a vice president with renewable developer OnPeak Power, put things into perspective when he asked his panel, “Are you prepared to operate your business without electricity and cellphones?”
“You need a responsible plan for cybersecurity. You plan to have that event actually happen. You don’t plan for it not to happen,” Mike Allgeier, ERCOT’s director of critical infrastructure security, told attendees gathered at The International Center. “Prepare for the worst. If you don’t prepare for the worst, when the worst happens, it’ll be pretty bad. Plan for what you think is the worst, then double it.”
Allgeier warned that the “bad actors,” or hackers, operating online today are not to be underestimated.
“They’ve been around a while,” he said. “Typically, they’re dedicated and well-trained to do their job. It’s not the 15-year-old kid in the basement. They have goals and they’re measured. They have quotas.
“They’re not only looking at the big guys. They understand that if they can control a wide swath of resources, that can be just as damaging as getting into one large resource,” Allgeier said.
Speaking on the same panel, ABZ’s Trey Kirkpatrick emphasized the importance of raising awareness of cybersecurity issues among employees. He used Berkshire Hathaway’s three-strikes-and-you’re-out approach to phishing emails as an example.
“Their policy is if someone clicks on a phishing email three times, they’re gone. You don’t see that in every organization,” Kirkpatrick said.
Both Allgeier and Kirkpatrick bemoaned the difficulty of finding and retaining cybersecurity subject matter experts, with Kirkpatrick calling it “the biggest risk.”
“The consultants are getting busy; they’re highly paid, and they’re moving around,” Kirkpatrick said. “I know companies that can’t even find a cybersecurity manager, even with the money they are offering.”
Allgeier said he typically fills his cybersecurity staff with personnel that have financial and military backgrounds.
“From the financial side, because they’ve been doing this for a long time; and from the military sector, because they have been trained to fight our online enemies,” he said. “I can’t always compete with salaries the high-tech or financial firms can offer, so we try to keep them with competitive benefits and the collaborative nature of work, building the esprit de corps.”
Place for Storage, New Technologies
Panelists discussing the ability of renewable energy and smart technology to make the grid more secure and reliable suggested looking away from California, where mid-day solar energy peaks reduce demand for other sources, resulting in a “duck curve.” (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)
“California has kind of become the sacrificial lamb,” Energy Storage Consultants CEO Judy McElroy said. “Storage is a good answer to that, but just throwing storage on your grid doesn’t make it more reliable.”
“As we integrate [battery storage and other technologies], we can make them more reliable, but there’s a cost,” said Dean Tuel, global vice president of microgrid and storage solutions sales for Aggreko. “We have a diverse portfolio of technologies we can provide at a cost the customer is willing to accept. We can accommodate this with today’s technology and reach a level of renewable penetration that gets us to the … reliability the customer is looking for.”
TREIA on Track for 50% by 2030 Goal
Buoyed by the large amount of wind and solar projects in ERCOT’s interconnection queue, Sterzing said TREIA’s goal of achieving 50% renewable energy in Texas by 2030 is coming into clearer focus.
Sterzing pointed to the 35.7 GW of wind projects and 58.6 GW of solar projects in the queue as of May as reason for hope. Only 14.3 GW and 7.6 GW of the respective wind and solar projects have signed connection agreements.
“Will it all be built? Hard to say, but that’s a huge industry movement either way,” he said. “There’s a lot of development coming into Texas. There’s certainly a lot more we can do as a state, with this kind of investment, to make Texas an energy center for the country.”
Sterzing noted Texas that has seen a “steady trajectory” over the last five years in renewable energy’s share of the fuel mix. Wind and solar energy accounted for almost 20% of ERCOT’s production in 2018. At the current rate of growth in the state, Sterzing estimated an additional 18 GW of wind energy and 39 GW of solar would help “maintain a reasonable mix and achieve the 50% goal.”
“That’s a huge, huge target, and enough to keep us all busy,” he said.
Energy Industry, Military Collaborate on Grid Security
A panel focused on defense and grid security stressed the importance of the energy industry working closely with the military.
Melissa Miller, Avangrid Renewables’ regional development manager for the central U.S., said technological improvements have led to the construction of wind farms in areas they could not have previously been built. That has only increased the conflicts seen across the country between wind facilities — which are increasingly taller — and military flight paths.
“We’re more successful with wind almost everywhere, but all of a sudden, that creates an impact with military operations,” Miller said. “It’s really important we learn about their missions and what their objectives are, especially in the lower air space. The need to collaborate is so important.”
Shanna Ramirez, CPS Energy’s chief integrated security officer, said the San Antonio utility has long enjoyed a collaborative relationship with the military, which has four major installations and 250,000 retirees in the city. Ergo, the city’s trademarked nickname, “Military City USA.”
“We’ve been really successful about keeping the military aware of how we secure our mutual facilities,” Ramirez said. “We have more people at the table, we keep buying a bigger table.”
“There’s an acknowledgement we will not solve problems alone,” said Christian Delarosa, deputy base civil engineer for Joint Base San Antonio. JBSA is composed of the Army’s Fort Sam Houston and the Lackland and Randolph Air Force bases.
“The Air Force wants to keep focus on resiliency and low costs,” Delarosa said. “We’re still interested in saving energy, but we’re now focused on resiliency and grid operations. It’s going to take industry experts and academia to look at this problem and develop solutions.”
Renewables Enjoy Positive Legislative Session
Attorney Chris Reeder, a partner at Husch Blackwell, reviewed the recent 86th Texas Legislature, painting it as a success for the renewable energy industry despite the efforts of the conservative Texas Public Policy Foundation (TPPF).
Reeder said the TPPF was at the forefront of a “sustained and aggressive and hostile campaign” against renewable energy during the recent session, which ended in May.
“They’ve made it a centerpiece of their political strategy to oppose renewable energy,” he said. “When they say, ‘Level the playing field,’ others would call that a rollback. They have been very vocal and aggressive in shooting down our success to the economy of Texas.
“Any legislation with renewable energy attached to it automatically draws some level of opposition in our state House and state Senate,” Reeder said. “That tends to misread the true situation, in which there’s much more support out there than makes its way into the chatter you see in The Dallas Morning News or the trades.”
