NERC is requesting comments from stakeholders on changes to several reliability standards proposed by the team updating the requirements for determining and communicating system operating limits (SOLs), as well as on the team’s implementation plan (Project 2015-09).
The posting was approved by NERC’s Standards Committee at its previous meeting in June, with comments being accepted through Aug. 3. (See “SOL, Training Proposals Accepted,” NERC Standards Committee Briefs: June 17, 2020.) Balloting for the standards and implementation plan will be conducted from July 24 through Aug. 3.
Ballot pools will be formed through July 20; NERC announced Wednesday that existing ballot pools will be reopened to allow stakeholders to join if desired.
Range of Standards Affected
The standards posted for comment and balloting include:
IRO-008-3 – Reliability Coordinator Operational Analyses and Real-time Assessments
The standard drafting team’s questions for respondents mainly focus on the updated Facilities Design, Connections, and Maintenance (FAC), Interconnection Reliability Operations and Coordination (IRO) and Transmission Operations (TOP) standards because of the “numerous and significant concerns” raised by industry stakeholders during the SDT’s previous posting in 2018. Specifically, many commenters objected to the use of FAC standards to define SOL exceedances. In response, the team moved SOL determination from FAC-011-4 and FAC-014-3 to IRO-008-3 and TOP-001-6. The revised standards will leave the definition of SOL exceedances to transmission operators and reliability coordinators.
Additional changes to FAC-011, TOP-001 and IRO-008 deal with industry questions over compliance and administrative burdens from the new logging requirements. The SDT is asking stakeholders whether they agree with the “risk-based approach” for identifying and communicating SOL exceedances that is intended to let operators focus on mitigating issues rather than divert resources for reporting them.
The last major question for stakeholders involves the SDT’s decision to drop its proposed FAC-015 standard — which would have addressed criteria for determining SOLs — and move its requirements into FAC-014-3. FAC-015 was originally introduced because of the planned retirement of FAC-010-3 (System operating limits methodology for the planning horizon), but industry feedback convinced the team that FAC-014 would be a better place for the requirements.
The comment period for Project 2015-09 was originally planned to open in February, after the SDT reported in November that it had resolved most sticking points that had held it back since the 2018 posting, other than those involving logging and communication requirements. (See “Team Expects Feb. Posting on SOL Project,” SOL Project Team Preparing for March Posting.)
One reason the team’s business has taken longer to conclude than expected — according to NERC’s Project Tracking Spreadsheet, it is the oldest standard drafting project still in progress — is its decision to expand its scope beyond its original mandate. This has led to both an increased workload for the team and concern from industry participants about possible overreach.
Pacific Gas and Electric said it had completed its bankruptcy restructuring Wednesday, one day after California Gov. Gavin Newsom signed a bill allowing the state to take over the utility if it fails egregiously over time to obey the Public Utilities Commission’s rules.
Those rules, imposed as a condition of the commission’s decision to accept PG&E’s bankruptcy plan in May, required the utility to submit to enhanced oversight and escalating enforcement for safety failures. Repeated and uncorrected problems could let the commission appoint a third-party monitor followed by a receiver, and eventually to rescind PG&E’s license to operate as the monopoly utility for most of Central and Northern California.
If that happens, the newly enacted Senate Bill 350 authorizes the state to seize PG&E through eminent domain and transfer its operations and assets to a nonprofit public benefit corporation called Golden State Energy, created by the legislature and governor.
“The purpose of this division is to ensure that if Pacific Gas and Electric Co. fails to emerge from bankruptcy as a transformed utility, then Golden State Energy is duly empowered to serve in that critical role,” the new law says. “It is the intent of the legislature that Golden State Energy act pursuant to this division only in the event that a transformed utility does not emerge from the bankruptcy or the transformed utility fails to meet its duty to provide safe, reliable and affordable energy services.”
Some critics have contended the CPUC’s six-step process of punishing PG&E would take so long that a takeover won’t happen. Dozens of public speakers urged the commission to yank PG&E’s license immediately prior to its approval of the utility’s reorganization plan May 28.
“We need a public utility,” one that’s not motivated by profits to forgo safety upgrades and maintenance, San Francisco Bay Area resident Charlotte Quinn told commissioners.
Newsom said in a statement Tuesday, however, that his signing of SB 350 means there will be “no more business as usual for PG&E.”
“As we head into wildfire season amid a pandemic, Californians need to have confidence that their utility is focused on customer safety, preventing wildfire[s] … and making critical safety upgrades,” the governor said. “SB 350 marks a critical step in the transformation of PG&E into a utility that is accountable to those it serves.”
The measure authorizes the state to sell bonds to finance the purchase of PG&E. It cleared the State Senate on Monday and went to Newsom for his signature.
Bill author Sen. Jerry Hill (D) has called the measure a “plan B” if PG&E doesn’t undergo the safety transformation it has promised. (See Plan B for PG&E Takeover Moves Forward.)
“As much as we push forward with that change, we must also be prepared to step in should the company not meet its obligations or commitments in the future,” Hill told the State Assembly’s Utilities and Energy Committee last month. “SB 350 is our preparation. I hope it’s unnecessary and that it’s never triggered, but we owe this preparation to the residents of San Bruno and Santa Rosa and Napa and Butte County and Paradise.”
Those communities were devastated by PG&E-caused catastrophes in the past decade.
The Camp Fire, the state’s deadliest and most destructive wildland blaze, wiped out most of the town of Paradise on Nov. 8, 2018, killing 85 residents and destroying more than 14,000 homes. The wine country fires of October 2017 ravaged the city of Santa Rosa and large areas of Napa and Sonoma counties. A gas pipeline explosion in September 2010 killed eight people and destroyed part of a residential neighborhood in San Bruno, a San Francisco suburb.
An estimated $30 billion in liabilities for the fires of 2017 and 2018 caused PG&E to seek bankruptcy protection in January 2019.
‘One Step Closer to Getting Paid’
PG&E said Wednesday it had emerged from that bankruptcy after nearly 18 months by obtaining the debt-and-equity financing it needed to fund $25.5 billion in settlements with fire victims, government agencies, insurance companies and the hedge funds that bought up billions of dollars in insurance subrogation claims.
U.S. Bankruptcy Judge Dennis Montali approved PG&E’s Chapter 11 plan on June 20, less than a day after it pleaded guilty to 84 charges of involuntary manslaughter in the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan Approved.)
“Today’s announcement is significant for PG&E and for the many wildfire victims who are now one step closer to getting paid,” acting CEO Bill Smith said in a news release. Smith replaced former CEO Bill Johnson, who retired Tuesday.
“Compensating these victims fairly and quickly has been our primary goal throughout these proceedings, and I am glad to say that today we funded the fire victim trust for their benefit,” Smith said.
PG&E plans to fund the victims’ trust with $6.85 billion in cash in three installments through 2022 and with stock shares equal to a 22% stake in the utility, the largest electric provider in North America.
The company also said it had seated a mostly new 14-member board of directors and paid its $5 billion contribution to the state’s wildfire insurance fund, created under last year’s Assembly Bill 1054. (See PG&E Names New Board of Directors.)
Under the legal doctrine of “inverse condemnation,” California holds utilities strictly liable for fires sparked by their equipment. The $21 billion fund, to be paid for equally by ratepayers and utilities, provides financial protection against devastating blazes going forward.
FERC’s proposed new approach to awarding transmission incentives drew some support but also generated much sticker shock among stakeholders, who said it would increase costs in many cases without providing additional benefits (RM20-10).
Wednesday was the deadline for comments on FERC’s March Notice of Proposed Rulemaking that would, among many other things, double the adder for participating in an RTO and shift from awarding benefits based on the risks and challenges of a project to one focused on economic and reliability benefits. (See FERC Proposes Increased Tx Incentives.)
FERC, which gained authority to issue incentives in the Energy Policy Act of 2005, implemented its policy in Order 679 in 2006 and opened a Notice of Inquiry to reconsider the policy in 2019 (PL19-3).
‘But For’ Projects
Alliant Energy and DTE Electric, identifying themselves as “transmission-dependent utilities,” said incentives should only be available for “transmission development that is not otherwise occurring or to accomplish specific policy objectives,” saying bonuses are not needed in MISO’s footprint, which “has experienced robust transmission development over the last 10 years without them.”
The companies said incentives should be reserved for high-risk and high-reward projects such as interregional transmission. “Blanket approval of incentives does little to drive desired behaviors; instead, such actions may encourage overbuild and add unnecessary costs to customers.”
Similarly, the American Council on Renewable Energy (ACORE) said incentives should be limited to projects that prove their proposals “would not be built but for the award of the incentive.”
“FERC explained it has not proposed such a ‘but for’ provision because Congress did not clearly direct the commission to include such a provision. However, Congress did direct FERC to incentivize new transmission capacity if it benefits customers. Awarding ratepayer funds to project applicants that would be built in the absence of an incentive are not being incentivized by the award.”
A coalition of consumer and environmental groups that have opposed transmission projects — including Transource Energy’s Independence Energy Connection project in PJM and Central Maine Power’s New England Clean Energy Connect merchant line — said the commission seemed to ignore the comments in response to its NOI “in favor of proceeding with a predetermined agenda.”
The groups said Congress’ legislation authorizing incentives had a dual purpose of both ensuring reliability and reducing the cost of delivered power by reducing congestion. “As written, the statute clearly intends that the cost of incentives to consumers shall be ameliorated by reduction in their power costs. In practice, the commission’s incentives policy has historically taken liberty with the stated purpose of the statute and congressional intent.”
From ‘Risks and Challenges’ to ‘Benefits’
FERC’s proposal to shift from awards based on “risks and challenges” to one based on “benefits” resulting from the project drew both support and opposition.
ACORE supported the change, saying it would help ensure deployment of energy storage as transmission as well as new technologies. “Dynamic line ratings and other technological innovations can provide quantifiable economic benefits and reduced power costs by increasing the capacity of transmission infrastructure at lower costs than new wire solutions, but these innovations are not properly compensated for their benefits under the current approach.”
Among FERC’s proposals was a 50-basis-point (bp) adder to projects that meet a pre-construction benefit-to-cost ratio in the top 25% of projects examined over a sample period, with another 50 basis points for projects that meet a post-construction b/c ratio in the top 10% of projects.
The commission also proposed up to 50 bp for projects that show reliability benefits through quantitative or qualitative analysis.
The R Street Institute, a free-market advocacy think tank, said that the proposed 100-point economic benefits adder, “on its face, seems absurd, as any project should pass a cost-benefit analysis prior to approval. Increasing ROE [return on equity] for something that should already be happening does not incentivize transmission projects to be more cost effective.”
The American Public Power Association said the ex ante economic benefit adder “would unreasonably grant incentives based on analysis of congestion cost savings that might never materialize, and the ex post economic benefit adder rewards projects that have already been built.”
APPA said any reliability incentive should be limited to the portion of the project investment that is needed to produce reliability benefits above NERC reliability standards. It also said reliability incentives should not be “based on qualitative reliability benefit claims alone.”
The National Association of State Utility Consumer Advocates (NASUCA) said the change “will result in the payment of costly incentives to transmission projects likely to be built anyway, with or without incentives, and thereby serves to increase the cost of transmission projects borne by customers while providing no clear customer benefit.”
“The NOPR fails to provide evidence that the incentives are needed,” said Paul N. Cicio, president of the Industrial Energy Consumers of America, which filed comments jointly with 37 other groups under the name “American Manufacturers.”
“Transmission projects that are needed are getting built,” Cicio said. “Every dollar of financial incentive would be passed onto us, the consumer ratepayer. Given today’s economic uncertainty, this is a terrible time to consider increasing electricity rates on manufacturers, our nation’s job creators.”
Advanced Tech
The Working for Advanced Transmission Technologies (WATT) Coalition and Advanced Energy Economy submitted joint comments noting that FERC has never implemented the requirement in EPAct 2005 that it encourage the deployment of new transmission technologies.
“For all the hundreds, if not thousands, of proceedings on energy market design, significant efficiencies lie untapped in the operation of the physical network hardware,” they said.
The groups proposed “a modest, targeted incentive to support the adoption of advanced transmission technologies like dynamic line ratings, topology optimization, and similar tools that increase the capacity and efficiency of the existing grid.” They said their proposal would fulfill FERC’s statutory obligations.
| Burns & McDonnell
R Street said, “The number of adders that are available to transmission projects is already quite generous and should be examined before handing out more customer dollars for these ventures.” It called FERC’s proposal to replace the current limit on incentives with a 250-basis-point cap on total ROE adders “a good start,” but it said “there needs to be a stop to the layering of incentives, as it is not attracting new and innovative technologies.” It also said the proposed 100-point adder for new technologies is “not enough to retool the transmission system.”
“FERC needs to be … setting up a regulatory paradigm that can usher in new innovations and technology,” R Street said. “Any enhancements to the electric grid need to include more than just ROE incentives; for new technology to be pushed forward, FERC must look to other models to properly incentivize innovation.”
The Energy Storage Association said storage should be eligible for incentives because of its ability to “enhance the flexibility and efficient use” of existing transmission facilities.
“Returns for transmission owners are largely based on allowed rates of return from capital investment. Even if less expensive investments can attain operational capabilities that achieve equal or superior outcomes as a conventional transmission solution, transmission owners would face a reduction in return by undertaking the less expensive investment,” ESA said. “For example, fast-acting energy storage can provide rapid injections pre- or post-contingency events to maintain reliability of the transmission system and reduce congestion on key lines or interfaces. Use of storage in this way can be far less expensive than building redundant transmission conductors, which is the standard way to handle transmission contingencies.”
Doubling RTO Adder
FERC’s proposal to double the adder for participation in an RTO from 50 to 100 basis points attracted much opposition, with some critics saying it should be eliminated altogether.
“What action or decision is influenced by an incentive that rewards a continued payment years after the joining of the RTO?” the Union of Concerned Scientists asked, noting that most RTOs and ISOs already had most of their current members in 2005. “Simply rewarding continued membership seems to provide additional revenue to member utilities without commensurate increase in benefits to consumers,” it said.
“No evidence has been put forth demonstrating that the existing benefits of RTO membership are insufficient incentive for TOs to join and remain in RTOs absent an ROE adder,” the Maryland Public Service Commission said. “The existing 50-bps RTO ROE adder as it stands … provides no incremental benefit to customers. Therefore … the commission’s proposed 100-bps RTO ROE adder [is] simply wholly untenable.”
“The commission’s proposal to double the RTO participation incentive ROE adder in perpetuity will only add costs and provide no discernable benefits to customers who have paid very expensive RTO participation adder for many years,” NASUCA said.
But the PJM Transmission Owners sector said the increased incentive is justified because “the risks to transmission owners of RTO membership are significant, such as giving up control of their system and assets to join and participate in RTOs.”
The TOs said, however, that incentives are not sufficient, saying the commission must also “ensure a stable and equitable policy on transmission owners’ ‘base’ return on equity.”
Need for Transmission Planning Reform
The Electricity Consumers Resource Council, filing with the American Chemistry Council and the American Forest & Paper Association, said they understand the need for new transmission but disagree with that incentives “should be — or can be — a key driver of that development.”
“The root cause of underdevelopment, to the extent underdevelopment is pervasive and problematic, is a set of institutional barriers that should be addressed head-on instead of tangentially, expensively and ineffectively via transmission incentives policy,” the groups said. “The appropriate tools available to federal policymakers to address barriers to development include improvements to transmission planning and cost allocation, as well as new legislation from Congress if it chooses to address any additional federal role in transmission siting.”
ACORE also called for changes to transmission planning procedures. “The incorporation of grid optimization and advanced technologies in the planning process, more standard and broad cost allocation, and increased inter-RTO transfer capability will lead to a more robust and efficient electric grid,” it said. “Where possible within its authority, FERC should enhance efforts to streamline transmission siting and enable construction of necessary transmission lines.”
The group cited research from the National Renewable Energy Laboratory that increased transmission development at regional seams could save consumers more than $47 billion and return more than $2.50 for every dollar invested.
ITC also called for a broader review, saying for incentives to proceed “it is necessary to revisit other commission policies and potentially abandon them (e.g., competitive solicitation processes) or reform them (e.g., transmission planning).”
The company said Order 1000’s competitive solicitation processes are “in direct conflict with the commission’s incentives policy” by encouraging TOs to adopt least-cost projects to address transmission needs.
Instead, it said the commission should use a risk-sharing approach similar to that of the New York Public Service Commission for public policy transmission, which gives the developer 20% of cost savings below the targeted cost with the remaining 80% going to consumers. Developers are responsible for 80% of any cost overruns.
UCS noted that the NOPR does not include any incentives for interregional transmission projects.
“Amongst the topics under review in this process, the insufficient attention and lack of incentives for interregional transmission stands out,” the group said. “The commission should acknowledge in this rulemaking that there is a problem when the borders of the ISOs/RTOs create gaps in market-based transfers of energy, increase costs due to congestion, and introduce obstacles and risks to the planning, evaluation and ultimate construction of interregional transmission.”
Eliminate Transco Adder
ITC Holdings said FERC’s proposal to eliminate incentives for standalone transmission companies (transcos) “is premature and based on flawed assumptions.”
“The last decade has been characterized by steady economic growth in tandem with a transformation in the energy sector once thought unimaginable, thus creating an environment that has allowed transcos and vertically integrated utilities alike to make significant investments in transmission infrastructure,” ITC said. “However, the real measure of a transco’s value is better captured in more challenging economic conditions when vertically integrated utilities are required to make difficult choices between investments in generation, distribution and transmission. Indeed, when one looks at the period from 2000 to 2010 — a period that includes the last major recession — transcos far outpaced vertically integrated utilities in terms of transmission investments.”
PJM has responded to the Independent Market Monitor’s annual State of the Market Report, highlighting five different areas of focus out of hundreds of recommendations.
In its response released Monday, PJM said it met with representatives from Monitoring Analytics, the RTO’s Monitor, on several occasions in the leadup to the March release of the report to discuss areas of prioritization for 2020. Discussions led to prioritizing five different issues out of 213 recommendations contained in the report, including:
a holistic review of the auction revenue rights (ARRs) and financial transmission rights markets design;
five-minute pricing and dispatch;
a capacity market default market seller offer cap;
the future of up-to-congestion transactions; and
energy market power mitigation.
“Some of the recommendations in these areas propose solutions that may require additional analysis by PJM and Monitoring Analytics; stakeholder discussion and vetting; or are recommendations on which PJM and MA have not yet agreed,” PJM said in its response.
PJM categorization of recommendations from the 2019 State of the Market Report | PJM
ARR/FTR Market Design
The ARR/FTR products have been a major area of focus for PJM, the Monitor and stakeholders in recent years, the RTO said, going back to 2017 when PJM filed changes to comply with a FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)
The issue took on greater importance after the 2018 GreenHat Energy credit default, PJM said, calling into question the credit requirements for FTRs and the value of the long-term FTR auction. Subsequent discussions at the ARR/FTR Market Task Force have resulted in movements to alter the auction structure.
As a recommendation contained in the independent consultant report on the GreenHat default released last year, PJM is conducting a “holistic review” of the ARR/FTR products and procedures and is in the process of hiring a consultant to conduct a review. PJM reviewed the final scope for the holistic review to be done by the consultant at the June 26 task force meeting. (See PJM Revises Consultant Scope for ARR/FTR Review.)
“PJM is engaging in this holistic review with an open mind and looks forward to working with Monitoring Analytics and stakeholders on the consultant’s final report,” PJM wrote in its response. “The current structure that is implemented in PJM has been in place for over 20 years. That length of time, in addition to questions raised by stakeholders on the effectiveness of the current structure, necessitates such a review.”
5-Minute Dispatch and Pricing
In May 2019, the Monitor presented a problem statement and issue charge to the Market Implementation Committee addressing transparency and process improvements for real-time energy price formation.
Since then, stakeholders have discussed market rule changes and areas to increase transparency in the governing documents. Several key changes remain under discussion, including: the alignment of energy and reserve prices with the target time of the dispatch instructions; the configuration and periodicity of the dispatch algorithm; the formulation of the real-time dispatch and pricing; and the transparency of the LMP verification process performed by PJM.
PJM said changes in the alignment of prices and dispatch instructions and frequency and configuration of the dispatch algorithm are “beneficial” and will increase incentives to follow dispatch. The RTO said it cannot currently support proposed changes to the formulation of the real-time dispatch because no analysis is available determining the benefits, costs or operational impacts related to the proposal.
PJM said it appreciates the Monitor raising issues regarding transparency and process improvements around real-time energy price formation.
“The real-time dispatch and pricing of the PJM system is complex,” it said. “Taking time to identify where those processes may be improved and where more transparency would be beneficial is important to PJM.”
Default Market Seller Offer Cap
Stakeholders discussed changes to the capacity market’s default market seller offer cap (MSOC) at the MIC in 2017 and 2018, advancing a proposal by PJM before it ultimately failed to pass at the October 2018 Members Committee meeting. (See “Market Seller Offer Cap Balancing Ratio,” PJM MRC/MC Briefs: Oct. 25, 2018.)
The default MSOC is defined as the net cost of new entry multiplied by the average balancing ratio for all performance assessment intervals in the prior three years. The proposal would have calculated the balancing ratio used in the default MSOC and nonperformance charge rate formulas by averaging the balancing ratios from the three delivery years that immediately preceded the capacity auction.
Despite lengthy discussions on the issue, consensus was not reached on changes. In February 2019, the Monitor filed a complaint with FERC explaining the problems it believes exist with the current default MSOC (EL19-47). (See Monitor Asks FERC to Cut PJM Capacity Offer Cap.)
The complaint has yet to be resolved at FERC. PJM said it understands the IMM’s justification for the complaint and recognizes that it has resulted in uncertainty in capacity market rules but would have preferred to address the issues outside of FERC rather than waiting for an answer.
UTC Transactions
As a result of changes in market behavior and stakeholder questions on the value of up-to-congestion (UTC) transactions, PJM wrote a paper in 2015 providing background and education on their value and highlighted concerns with their use. Recommendations included altering the biddable locations for UTCs to generation buses as source only, trading hubs, load zones and interfaces and allocating uplift to UTCs consistent with increment offers (INCs) and decrement bids (DECs).
The second filing, which was rejected by FERC in January 2018, proposed to allocate a portion of the uplift in PJM to UTCs as if they were an INC at the injection point and a DEC at the withdrawal point. PJM and stakeholders chose not to propose an alternative in response to FERC’s invitation to do so in its order. (See FERC Queries PJM on Virtual Transaction Rules.)
PJM said it believes inconsistencies in the allocation of uplift costs existing between UTCs and other virtual transactions is “inequitable” and should be addressed. The RTO is currently working with the Monitor on UTC analysis.
Energy Market Power Mitigation
PJM said its energy market power mitigation rules have been the frequent focus of stakeholder discussions and “have presented challenges,” including debate over the fuel-cost policy (FCP) process, the lost opportunity cost calculator and parameter-limited scheduling.
In September 2018, stakeholders approved a problem statement and issue charge focused on enhancing the FCP process and to explore potential alternatives to PJM’s cost-based offer rules. Discussions on the topic are currently taking place within the stakeholder process, as members approved rule changes at the March MC meeting. (See Revised Fuel-cost Policy Approved by PJM MC.)
PJM said it supports working with stakeholders and the Monitor to investigate ways to “simplify and streamline the current rules without weakening them” but wants to consider several different components of energy market power mitigation rules to make sure they work together.
“PJM firmly believes that strong market power mitigation mechanisms are critical to maintain an efficient, competitive market,” the RTO said. “To ensure those rules remain strong and that they all function cohesively, PJM believes that substantive changes to the calculation of cost-based or mitigated offers should not be considered in isolation.”
Stakeholders appear torn over whether MISO should proceed with a potentially controversial effort to develop reliability guidelines that could establish uniform resource adequacy criteria across its footprint, stepping into territory currently reserved for the states.
With its own studies showing an emerging wintertime loss-of-load risk, MISO has recently signaled that it may define its own system reliability criteria, possibly as part of its ongoing resource availability and need project.
“The transition to a different portfolio is happening, and happening quickly, I would say,” Jessica Harrison, MISO director of research and development, said during a virtual stakeholder workshop Tuesday.
Harrison said MISO faces interconnection of a growing number of gigawatts from intermittent resources.
“There’s a lot more management that has to happen throughout the year,” she said. “There are strong indicators of change, and there are strong indicators that we need to do something.”
While MISO has yet to define what would be the objectives and outcomes of such an effort, officials have said load-serving entities need the RTO to provide more direction on reliability in order to make resource investment decisions.
“People are asking us now, ‘I have a billion-dollar investment. It’s a decade-long asset. Will we need this?’” Executive Vice President of Market and Grid Strategy Richard Doying said at MISO’s Board of Directors meeting last month.
“We need MISO to provide forward-looking guidance,” Xcel Energy’s Kari Hassler said. She said the MISO footprint should operate according to a single set of reliability criteria instead of several disjointed sets established by state regulators.
But other stakeholders said such a requirement would tread on states’ jurisdiction over resource adequacy and their prerogative to create their own resource mixes.
Mississippi Public Service Commission consultant Bill Booth said Mississippi is only looking to MISO to provide annual local clearing requirements and planning reserve margins, which the state adopts only when it agrees with the RTO’s assessment.
“I don’t think Mississippi is looking to MISO for anything beyond those,” Booth said.
But Gabel Associates’ Travis Stewart said inaction by MISO could result in some states developing insufficient resource mixes and enjoying “free ridership,” where one state relies on ratepayers in other states for resource adequacy.
“This is very much the dynamic in some loads,” he said, adding that if loads decide to go 100% solar, they should include reliability mechanisms.
Stewart said MISO can help by developing market rules that send economic signals that incent jurisdictions to build or retire reliably.
Tri-State Generation and Transmission Association and Delta-Montrose Electric Association (DMEA) officially parted ways Tuesday, wishing each other well after 28 years of partnership.
The two cooperatives in April entered into a membership withdrawal agreement in which DMEA agreed to pay an $88.5 million exit fee in accordance with a July 2019 settlement agreement. (See Tri-State G&T, Delta-Montrose Reach Withdrawal Deal.)
FERC approved the breakup in June (ER20-1541, et al.). The Colorado Public Utilities Commission accepted the settlement agreement last year.
In a joint press release, each of the cooperatives’ CEOs extended best wishes to the other organization and its members. It was a friendly ending to a relationship that had turned acrimonious over the last 15 years. DMEA refused Tri-State’s 2005 request of its members to extend their contract from 2040 to 2050 to help pay for a coal-fired plant in western Kansas. Tri-State eventually pulled out of the Holcomb project and has begun a shift to renewable power as part of its Responsible Energy Plan. (See Tri-State to Retire 2 Coal Plants, Mine.)
In 2016, DMEA served notice to Tri-State that it planned to leave the partnership, saying it wanted to pursue cheaper renewable power and escape rates that had risen 56% since 2005. Tri-State initially asked for a reported $322 exit fee but settled with DMEA on the final amount.
Wholesale provider Guzman Energy, which has entered into a contract with DMEA, will pay Tri-State $72 million for DMEA’s contract while the co-op will pony up $26 million to Tri-State for transmission assets. DMEA also forfeited another $48 million in patronage capital to depart.
Tri-State and DMEA have also entered into new contracts for the continued operation of transmission and telecommunications systems.
“This separation marks a new chapter for both DMEA and for Tri-State, and as cooperatives, we both know it’s important to look forward for the benefit of our members,” DMEA CEO Jasen Bronec said. “We recognize our ongoing partnership with Tri-State in various areas, such as transmission, and appreciate the importance of our continued cooperation.”
DMEA, a rural distribution cooperative that serves about 28,000 member-owners in western Colorado, is the second member to leave Tri-State in recent years. Kit Carson Electric Cooperative left in 2016, with Guzman paying its $37 million exit fee.
Westminster, Colo.-based Tri-State is a not-for-profit cooperative with 45 members following DMEA’s exit. It has 42 member utility distribution cooperatives and public power districts in four states, with more than a million customers in nearly 200,000 square miles of the West.
Two of Tri-State’s three largest remaining cooperatives, United Power and La Plata Electric Association, are seeking their own early exits through proceedings at the Colorado PUC.
FERC in June set hearing and settlement judge procedures on Tri-State’s proposal for computing member exit fees (ER20-1559). The commission accepted Tri-State’s methodology but said it raises issues of material fact that cannot be resolved based on the existing record and has not been shown to be just and reasonable. (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)
NYISO energy prices sank to 11-year lows during the first quarter, ranging from $15 to $35/MWh, stakeholders heard Tuesday.
“This is the lowest quarterly average level in more than a decade, so it’s pretty exceptional,” Pallas LeeVanSchaick of Potomac Economics said as he presented the Market Monitoring Unit’s State of the Market report for the first quarter to the Installed Capacity/Market Issues Working Group.
All-in prices ranged from $15 to $35/MWh, the lowest quarterly average levels in more than a decade. | Potomac Economics
Natural gas prices also dropped to their lowest quarterly average since 2009, along with electricity loads, LeeVanSchaick said.
“That was really attributable to a combination of factors, including mild weather conditions, the growth in energy efficiency and behind-the-meter solar, as well as in March we saw the effects of the COVID-19 pandemic, which many of you have heard about reducing load 8 to 9%,” he said.
Congestion Patterns and Revenues
Lower load levels and natural gas prices led to relatively low levels of transmission congestion, supplemental commitment for reliability and imports from PJM, he said.
While congestion was generally mild, the pattern was typical, with the most significant congestion observed on the Central-East interface, which accounted for about 60% of the day-ahead congestion revenues in the first quarter, LeeVanSchaick said. The pattern is typical because gas spreads tend to be largest between western and eastern New York; however, the difference dropped from 32% in the first quarter last year to only 11% in the same period this year, he said.
The total cost per megawatt-hour of load served in the New York markets, broken down by region | Potomac Economics
Day-ahead congestion revenues totaled $56 million, down 49% from the first quarter of 2019, primarily because of lower gas prices and load.
“We also saw New York City [Zone J] constraints account for the second largest share of congestion in the first quarter of 2020, but it was mainly localized to the Greenwood load pocket, because a 138-kV Gowanus-Greenwood line was out of service for a lot of January and February, which reduced transfer capability into the Greenwood load pocket,” LeeVanSchaick said.
While congestion fell by more than 40% in other regions, congestion in Zone J fell just 16% in the day-ahead market and rose 135% in real time. “So that pocket accounted for most of the New York City congestion, which otherwise would have been relatively small,” he said.
Out-of-market Actions
“In this quarter, we saw a significant reduction in the amount of out-of-market actions to manage low-voltage constraints in New York. Not so much a reduction quarter over quarter, but over the last two years we’ve seen big reductions,” LeeVanSchaick said.
The ISO achieved the reductions by modeling most 115-kV constraints in the day-ahead and real-time market models, the report said.
“In the West Zone, there were just three days of out-of-market actions where Ontario imports were curtailed to manage Gardenville-to-Dunkirk constraints,” LeeVanSchaick said.
Map shows the number of days in the quarter when various resources were used to manage constraints | Potomac Economics
Fifteen days of out-of-market actions in the North Zone were predominantly times when the Saranac unit was subject to a supplemental resource evaluation to provide congestion relief as well as operating reserves, while big reductions in the Capital Zone were driven by transmission upgrades, he said. Long Island had 18 days of out-of-market actions, the frequency of which was reduced by low load levels.
“We did see big reductions in the amount of supplemental commitment for reliability … which was obviously way down both in terms of local reliability rule [LRR] commitments and day-ahead reliability unit commitments,” LeeVanSchaick said.
On LRR commitments in New York City, where the ISO is modeling specific load pockets, he showed how the hourly requirement often came in below the static daily requirement, usually because of thermal and voltage constraints that required certain amounts of resources to be committed in certain areas, as the LRR path determines the quantity of resources that are needed on a given day.
Local reliability rule commitments in New York City showing hourly requirement vs. static daily requirement. | Potomac Economics
“If we look in the places where commitments occurred … in terms of the hourly requirement for resources, in [these pockets] you probably need a little over 100 MW in the overnight, but over the peak you need something that averages more like 280 MW,” LeeVanSchaick said.
“One thing to note is the actual requirement that’s used in the day-ahead software is a static, 24-hour requirement, so if at the peak, 280 MW is needed, even though that’s a subset of the hours, the static requirement is essentially imposing that in all 24 hours. So in this quarter, we did see that that led to additional hours of commitment,” he said.
Select N-1 constraints in New York City. The left panel summarizes their day-ahead and real-time congestion values in the quarter, while the right panel shows the seasonal long- and short-term emergency ratings (LTE, STE) for these facilities, compared to the average N-1 constraint limits used in the market software. | Potomac Economics
The MMU did recommend the ISO examine whether it’s possible to represent the requirement only in the hours where the resource is needed in order to avoid excess commitment of generation.
One stakeholder asked whether different resources would be selected if NYISO could better tailor the hourly requirements.
“In principle that could definitely happen,” LeeVanSchaick said. “I don’t recall that being something we observed in this quarter, but of course it would vary over time and under some conditions that could change the selection.”
Rejecting more than 50 years of precedent, the D.C. Circuit Court of Appeals ruled Tuesday that FERC can no longer use tolling orders to delay judicial review of its rulings under the Natural Gas Act.
The 10-1 decision concluded that the commission’s use of tolling orders to stop the 30-day clock for acting on rehearing requests improperly prevents litigants from appealing FERC rulings indefinitely even as it allows gas pipeline companies to seize property under eminent domain and begin construction (Allegheny Defense Project, et al. v. FERC, 17-1098).
“The commission and private certificate holders use its tolling orders to split the atom of finality,” Judge Patricia A. Millett wrote for the majority. “They are not final enough for aggrieved parties to seek relief in court, but they are final enough for private pipeline companies to go to court and take private property by eminent domain. And they are final enough for the commission to greenlight construction and even operation of the pipelines. Tolling orders, in other words, render commission decisions akin to Schrödinger’s cat: both final and not final at the same time.
Under Section 19a of the Natural Gas Act (15 U.S.C. § 717r(a)), “unless the commission acts upon [an] application for rehearing within 30 days after it is filed, such application may be deemed to have been denied. No proceeding to review any order of the commission shall be brought by any person unless such person shall have made application to the commission for a rehearing thereon.”
FERC did not respond Tuesday when asked whether the ruling will also end the commission’s ability to use tolling orders to delay appeals of orders under the Federal Power Act.
[UPDATE: On July 2, Chairman Neil Chatterjee, a Republican, and Commissioner Richard Glick, a Democrat, issued a statement asking Congress “to consider providing FERC with a reasonable amount of additional time to act on rehearing requests involving orders under both the Natural Gas Act and the Federal Power Act.”
“We believe that any such legislation should make clear that, while rehearing requests are pending, the commission should be prohibited from issuing a notice to proceed with construction and no entity should be able to begin eminent domain proceedings involving the projects addressed in the orders subject to those rehearing requests,” they said.]
Precedent Overturned
Millett said the D.C. Circuit erred since 1969 when it ruled in California Company v. Federal Power Commission (411 F.2d 720) that issuing a tolling order meant that FERC had “acted upon” the request under the language of the statute, and that parties must wait until the commission’s review of the request is complete before seeking relief from the court.
Millett said the court may overturn precedent when it decides that a previous holding was “fundamentally flawed” or when intervening developments — such as Supreme Court decisions — have “removed or weakened the conceptual underpinnings from the prior decision.”
In the 1969 ruling, the court “elevated policy concerns about ‘administrative and judicial problems’ over the plain statutory text” of the NGA, Millett wrote. “Of course, in so doing, that panel could not have foreseen the commission’s routinization of tolling orders, the unbounded length of tolling periods or, since California Co. involved rate setting, the severe consequences of the tolling practice for property owners. Stare decisis principles do not require us to continue down the wrong path.”
‘Virtually Automatic’
Millett wrote that FERC’s use of “tolling orders that do nothing more than buy itself more time to act on a rehearing application and stall judicial review has become virtually automatic.”
Over the last 12 years, the commission issued tolling orders in all 39 cases in which a landowner sought rehearing in a proceeding involving natural gas pipeline construction, taking about seven months on average from tolling order to actual rehearing decision.
Natural gas pipeline construction | Williams
Between 2009 and 2017, FERC issued tolling orders in response to 99% of all the requests for rehearing of pipeline certification decisions that it received, giving itself “roughly 10 times as long as the statute allots for it to act,” the court said.
For the 114 natural gas pipeline cases pending before FERC from Oct. 1, 2008, through Feb. 19, 2020, in which any party requested a rehearing, the commission authorized construction to begin before ruling on the merits of the rehearing request in 64% of the cases.
Atlantic Sunrise
The current case arose from FERC’s 2017 approval of Williams Companies’ Atlantic Sunrise project, an expansion of the company’s existing Transcontinental Pipeline, in which the commission took an extra nine months to act on rehearing. Transco initiated condemnation proceedings for the Atlantic Sunrise project less than two weeks after FERC granted it a certificate of public convenience and necessity on Feb. 3, 2017.
Transco told the Pennsylvania district court that, “as to this process, the eminent domain process, the [certificate] order is final” and beyond the court’s jurisdiction to review. Yet Transco and FERC told the D.C. Circuit that “the very same order was ‘non-final’ agency action for purposes of the homeowners’ effort to obtain judicial review,” Millett wrote.
Although the court dismissed FERC’s motion to dismiss landowner and environmental groups’ appeal of the Atlantic Sunrise order on procedural grounds, it concluded FERC acted properly in approving the project.
The homeowners and environmental groups said FERC’s reliance on the precedent agreements was arbitrary and capricious because those contracts only proved demand for export capacity, not domestic use of the natural gas being transported. The court said it did not need to address the homeowners’ and environmental associations’ objections to the reliance on precedent agreements because the commission also relied on other evidence of domestic demand.
Millett noted that Congress gave FERC four ways to act on rehearing requests under the NGA: grant or deny rehearing or abrogate or modify its order without further hearing.
The NGA requires litigants to seek appellate review within 60 days after the commission’s order on rehearing.
Even after a petition for appellate review is filed, the court said, FERC has the power to “modify or set aside” its findings and orders until the administrative record is filed in court, which is typically 40 days after the petition is served on the commission. “So in practice, even if an applicant files a petition for review immediately after a deemed denial, the commission will typically still have at least 70 days total” to act, Millett said.
On June 9, FERC issued a rulemaking saying it will no longer permit gas pipeline developers to begin construction until it acts on the merits of any rehearing requests (Order 871, RM20-15). (See FERC Revises Pipeline Policy on Landowner Concerns.)
However, in taking note of FERC’s action, Millett pointed out that the policy change does not prevent eminent domain proceedings from going forward while a rehearing request is pending on a certificate order.
The court said that although it generally gives agencies deference in interpreting ambiguous statutes, that “deference is available only when an agency interprets a statutory provision that Congress has charged it with administering through application of its expertise,” which does not apply in this case.
To “grant” rehearing “necessarily requires at least some substantive engagement with the application,” the court said.
But FERC’s tolling orders qualify them as being made only “for the limited purpose” of “afford[ing] additional time for consideration of the matters raised.”
“That is not a grant of rehearing of the challenged order; it is kicking the can down the road,” Millett said.
Dissent, Concurrence
Judge Karen LeCraft Henderson dissented on overturning the court’s previous interpretation of tolling orders.
“Section 717r(a) has not changed since [the] Natural Gas Act was enacted in 1938,” she wrote. “Overruling California Co. and its progeny because a majority of our court now believes those cases misconstrued Section 717r(a) renders stare decisis meaningless and draws the judiciary into a policymaking role that is the province of the elected branches.”
Judge Thomas B. Griffith filed a concurrence saying that the court had not gone far enough to address due process concerns and that tolling orders “are just one part of the legal web that can ensnare landowners in pipeline cases.”
Griffith noted that the majority opinion declines to rule on orders that “grant rehearing for the express purpose of revisiting and substantively reconsidering a prior decision” and provide “further hearing processes.”
“That limitation on today’s decision leaves the commission free to grant rehearing by agreeing to consider the applicant’s arguments for modifying or revoking its previous action — i.e., by deciding to decide. “The commission would easily satisfy the act by setting a briefing schedule or by ordering the pipeline company to respond to the claims made in the application.”
While Tuesday’s ruling “rightly jettisons the commission’s signature stalling tactic,” Griffith said, “it doesn’t alter the fact that the commission can postpone review by granting rehearing.”
With less than a month to go before a July 29 deadline for completing tariff changes, CAISO on Tuesday presented the Western Energy Imbalance Market’s Governing Body with its plan for accommodating hybrid generation and storage resources.
The EIM Governing Body plays an advisory role to CAISO’s Board of Governors on its hybrid resources initiative. With thousands of megawatts in the interconnection queue, the ISO is trying to move swiftly to develop policies to let the combined resources take part in its market, but it has concerns too.
CAISO said it adopted the tight timeline because it is trying bring more resources online in anticipation of potential shortfalls during the next three summers and to make up for the impending retirement of aging natural gas plants.
The California Public Utilities Commission required load-serving entities under its jurisdiction to procure 3,300 MW of capacity by 2023. In response, LSEs proposed integrating some hybrid resources into the market as soon as this fall. CAISO must complete its work by the end of July to allow FERC 90 days to approve tariff changes before the resources go live, the ISO said.
“This is a quick one because these things are coming online really soon, and we need to make sure we have the policy around it,” CAISO CEO Steve Berberich told the EIM Governing Body.
However, he urged the body members not to be too hasty in making any recommendations that could undermine the ISO’s ability to control the grid. For instance, hybrid co-located resources can operate as a single unit for dispatch purposes or be separated into battery and generation components to be dispatched separately.
Some stakeholders have urged the single-unit approach. Berberich asked for patience.
“There’s a whole lot of uncertainty and debate,” he said. “Keep in mind we have policy, and we have to operate the grid. And operating the grid with separate [scheduling coordinator] IDs on these things, we think, probably gives us more flexibility, but we’re not certain of it.
“We need some experience in operating these things” before locking in policies that could prove detrimental, he said.
The Governing Body members said they generally supported the recommendations of CAISO staff. They agreed to take the matter under advisement and provide feedback to the ISO board at an upcoming meeting.
“I’m all for additional capacity we can get for the system,” said John Prescott, who was elected by fellow members June 30 as the new chair of the Governing Body. Prescott took over from Carl Linvill in a position that rotates among the body’s five members annually.
“As you know, that’s kind of the No. 1 issue we really face in the system today, and it’s a shame that we don’t grab all this capacity now,” Prescott said. “But I also hear from the experts saying that, ‘You know, you got a controllability issue, and you need to think through this before you just kind of open the gates and create a problem.’”
Some stakeholders feel the process is rushed, CAISO staff said. But EIM Body Member Anita Decker, who was named vice chair, said she hoped CAISO would act “with some aggressiveness” to resolve stakeholder concerns and bring resources online.
The CAISO board is planning to take up the issue at its meetings in July, with final draft tariff language due July 29.
The integration of hybrid resources is expected to be a major issue for CAISO and other organized markets, as battery storage paired with renewables plays an ever greater role.
“The ISO anticipates the quantity of mixed-fuel resources will increase significantly in the coming years,” CAISO staff wrote in their second revised straw proposal on hybrid resources in April. “Today, there is relatively little interconnected to the ISO grid; however, the interconnection queue includes more than 24,000 MW of mixed-fuel projects, including nearly 20,000 MW of storage. This represents roughly half of all generation in the interconnection queue currently.”
House Democrats on Tuesday offered a 547-page Climate Crisis Action Plan, setting a goal of making the U.S. net zero carbon dioxide emissions economy-wide by 2050.
Issued as a majority report of the House Select Committee on the Climate Crisis, the plan says its proposals would reduce net U.S. greenhouse gas (GHG) emissions by at least 37% below 2010 levels in 2030 and 88% below 2010 levels in 2050 and provide almost $8 trillion in climate and health benefits through 2050.
Built around 12 “pillars,” including investments in infrastructure, agriculture, technology and workforce development, the plan identifies “hundreds” of recommendations for legislation. While the proposals are unlikely to advance in the current Congress, they will be central to Democrats campaigning leading into the November elections.
The committee was created in January 2019. Although its plan includes just a single explicit mention of the Green New Deal proposed by Rep. Alexandria Ocasio-Cortez (D-N.Y.) and Sen. Bernie Sanders (I-Vt.), it appears to borrow from it, calling for labor protections and posing climate actions as an economic development driver.
“Environmental justice and our vulnerable communities are at the center of the solutions we propose,” Committee Chair Kathy Castor (D-Fla.) said in a statement. “The health of our families and the air we breathe are at the heart of our plan. We chart the course to good-paying jobs in solar and wind energy, in manufacturing American-made electric vehicles and in strengthening communities, so they are more resilient to flooding, extreme heat, intense hurricanes and wildfires.”
Rep. Kathy Castor (D-Fla.), chair of the House Select Committee on the Climate Crisis | House Select Committee on the Climate Crisis
The plan calls on Congress to enact carbon pricing but warns it “is not a silver bullet and should complement a suite of policies to achieve deep pollution reductions and strengthen community resilience to climate impacts.” It said carbon pricing should be accompanied by policies to reduce pollution from facilities located in environmental justice communities and protect domestic industries from unfair competition from foreign competitors with lower environmental standards.
The Democrats said their proposals have been endorsed by more than 90 organizations, including the Natural Resources Defense Council, Environmental Defense Fund, National Wildlife Federation and The Sierra Club.
Republicans on the committee issued a statement chiding Speaker Nancy Pelosi (D-Calif.), saying that rather than seeking a bipartisan approach, she reversed “more than 200 years of House precedent” with rule changes to limit debate.
“Working together provides the best chance of maintaining U.S. global competitiveness and emissions-reducing leadership at home and abroad — without increasing costs on working families,” the Republicans said. “Policies rooted in innovation lower the cost of energy, drive economic growth and cut emissions. Our own experience with the energy renaissance in the oil and gas sector is proof. Economic growth and energy security do not have to be sacrificed in order to improve the environment. In fact, increased production of American shale natural gas helped produce the greatest emissions reduction in history. Our increased production also checks the ambitions of countries, like Russia, that wish to use energy as a weapon.”
Lisa Jacobson, president of the Business Council for Sustainable Energy (BCSE), said the Republicans’ comments on the report “show many areas of alignment for the parties.”
“While the recommendations in this report begin their path through the legislative process, BCSE urges Congress to pass the American Energy Innovation Act, which has amassed strong bipartisan support under the leadership of Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alaska) and Ranking Member Joe Manchin (D-W.Va.), as a foundational first step,” Jacobson said.
Among the plan’s proposals are the following:
Create a Clean Energy Standard to achieve net-zero emissions in the electricity sector by 2040 and an Energy Efficiency Resource Standard to address rising electricity demand from electrification. The plan would extend and expand clean energy tax incentives and grant programs.
Order FERC to develop a long-range transmission infrastructure strategy to site interstate transmission lines in high-priority corridors. “Congress also should direct FERC to remove roadblocks in power markets that slow the growth of electricity generation from clean sources,” it said.
Expedite deployment of zero-emission technologies where they are already available while setting GHG emission standards for cars, heavy-duty trucks and aviation. It would seek 100% sales of zero-emission cars by 2035 and heavy-duty trucks by 2040.
Incentivize states and cities to adopt updated model building codes, including net-zero-emission building codes, with a goal of making all new residential and commercial buildings net-zero emissions by 2030.
Develop new standards for water infrastructure resilience that account for more frequent and damaging floods, droughts and erosion.
Cut methane emissions from the oil and gas sector by 65% to 70% by 2025 and 90% by 2030, compared to 2012 levels, and eliminate the routine flaring of methane. Update the Federal Power Act to ensure FERC “considers climate science and public input” in siting new natural gas infrastructure. Eliminate oil and gas industry exemptions in the Clean Air Act, Clean Water Act and Resource Recovery and Conservation Act.
Increase funding for federal clean energy research, development and demonstration and reorganize the Department of Energy around a climate mission.
Establish performance standards to reduce emissions from industrial facilities, combined with border adjustment mechanisms to address foreign goods made with higher-polluting processes.
“Dramatically increase” federal investment in carbon removal research and development and improve financial incentives for direct air capture technology.
Repeal tax breaks for large oil and gas companies and restructure the tax code to support reaching net-zero emissions by 2050. Limit new leasing for fossil fuel extraction on public lands onshore and offshore.
Create a Climate Adaptation Program to ensure homes, businesses and critical infrastructure can withstand the impacts of climate change. Require any post-disaster rebuilding to meet “climate-informed” standards against flood, wind and wildfire threats.
Help farmers and ranchers adopt soil health practices to improve their resilience to extreme rainfall and drought.
Protect and restore ocean and wetland ecosystems, forests and grasslands to sequester carbon and improve resilience to wildfires and coastal flooding.
