Bernard W. Dan resigned unexpectedly from NYISO’s Board of Directors last week, less than a year after joining.
Dan
Dan announced his resignation at the board’s March 21 meeting. NYISO Chairman Michael Bemis relayed the news to stakeholders at the board’s Liaison Committee meeting afterward.
“Mr. Dan was interested in pursuing other opportunities,” NYISO spokesman Dave Flanagan confirmed. “He felt it was best to leave the board to avoid any potential conflicts.”
Flanagan declined to provide any details about Dan’s plans. Asked about plans to replace Dan on the 10-member board, Flanagan said, “Stakeholders will work that out through their normal process.”
Dan did not respond to an email asking for comment.
Turnaround Exec
Dan’s LinkedIn page describes him as a “Board Advisor, CEO and Turnaround Executive.”
He has been a senior advisor to the board of directors of OneChronos Group since 2015. The company, a startup that has gone through Y Combinator’s accelerator program, says it is building a new type of financial exchange that will make trading cheaper.
Dan was the CEO of Sun Holdings, which trades in stocks, currencies, futures and bonds, for five years ending in July 2015.
Dan also had a nearly two-year stint at MF Global, a broker of exchange-traded futures and options. After joining in June 2008 as the chief operating officer for North America, he rose to become CEO. He resigned in March 2010 and was replaced by former New Jersey Gov. Jon Corzine. The company, which filed for bankruptcy protection in October 2011, settled a lawsuit with its auditors, PricewaterhouseCoopers, on March 23.
Before joining MF Global, Dan was CEO of the Chicago Board of Trade, taking part in its initial public offering in 2005 and its sale to the Chicago Mercantile Exchange in 2007.
AUSTIN, Texas — The ERCOT Technical Advisory Committee agreed last week not to pursue a change in how ISO operators commit and dispatch resources, agreeing with a Wholesale Market Subcommittee study that the software changes required would not produce sufficient production cost savings.
The TAC then asked the subcommittee to begin working on real-time co-optimization of reserves.
The ISO developed an in-house software platform to perform multi-interval real-time market (MIRTM) simulations for selected operating days from 2015 and 2016. The study found MIRTM is feasible for both fast-responding generation resources and load resources with temporal constraints. But the feasibility study concluded that “the estimated cost[s] are in excess of the measured benefits and therefore insufficient to support [moving] forward with MIRTM at this time.”
ERCOT’s real-time market dispatches and prices energy in single five-minute intervals and does not consider potential changes in system conditions more than five minutes into the future. As a result, it is unable to coordinate the commitment of combustion turbines and demand response resources that are available within 10 to 30 minutes but unable to respond within five minutes.
The study was ordered to determine whether the ISO could improve the efficiency of its short-term commitment decisions by analyzing multiple consecutive five-minute intervals to determine the most economical commitment and dispatch.
ERCOT will share the study with the Board of Directors during its April 4 meeting. If approved, the study will be filed with the Public Utility Commission of Texas.
The WMS now finds itself freed up to take on real-time co-optimization, which shifts the responsibility for providing reserve services to online generation resources with the lowest incremental energy cost. Co-optimization has been the subject of discussion at the PUC, most recently during its last open meeting. (See Texas PUC Wary of Using ERS to Avoid Local Blackouts.)
“We’ve been waiting for [MIRTM] to clear the decks, and the decks have been cleared,” Morgan Stanley’s Clayton Greer said.
“We have an obligation at this point to explore this,” Citigroup’s Eric Goff said. “[The PUC] has given various hints that they’d like additional information. As a stakeholder body, I believe we have the obligation to make those hints and wishes reality.”
TAC Vice Chair Bob Helton, of Dynegy, agreed. With members raising concern over ERCOT’s estimate of $20 million for software changes, he directed the WMS to define a study scope and what components of co-optimization should be analyzed.
Staff Shares Draft Principles for Market Continuity
ERCOT staff shared with the TAC a draft of principles to address the ISO’s lack of guidelines on restarting its markets following outages. The principles do not change existing black start procedures.
Staff raised the issue last year with the board and conducted a workshop in May to frame the discussion around gaps in the processes.
The principles include:
Prioritizing the real-time market’s restart before other markets or activities;
Starting congestion revenue rights auctions and other functions only after the real-time and day-ahead markets are restored;
Expecting limited settlements functionality during market restoration;
Payments being made in “as timely a manner as possible;”
Relaxing credit requirements and releasing cash or other collateral to provide short-term liquidity to market participants;
Seeking emergency funding to pay resources before other alternatives are considered; and
Uplifting market restart costs on a load-ratio share basis after market recovery.
ERCOT staff is expected to build on the principles with more formal procedures.
“This is a good start. ERCOT didn’t have transparent principles before,” Direct Energy’s Read Comstock said.
Committee Approves 16 Revision Requests
The TAC also approved nine other NPRRs, three revisions to the Planning Guide (PGRRs), two revisions to the Load Profiling Guide (LPGRRs) and revisions to the Retail Market Guide (RMGRR) and Nodal Operating Guide (NOGRR).
NPRR776: Aligns protocol language with currently used verbal communication practices between transmission service providers (TSPs), qualified scheduling entities (QSEs) and generation resources. Also identifies new requirements for data TSPs provide to ERCOT, QSEs and the generators. The committee tabled NOGRR167, which aligns the Nodal Operating Guide with NPRR776.
NPRR799: Requires that TSPs and resource entities — generation and load that can reduce electricity usage or provide ancillary services — submit updates to the outage scheduler within one hour of the facility’s outage start or completion.
NPRR802: Clarifies current settlement practices and protocol language, including how reliability unit commitment resources opting out of settlement are treated in calculating real-time online reserve capacity.
NPRR804: Clarifies that ERCOT should post both a systemwide network model and a set of station one-line diagrams, and that the model posting does not disclose data about private-use networks.
NPRR808: Extends the CRR auction process into the third year forward, revises the percentages sold in the auction’s long-term sequence and aligns modifying load zones to the timetable.
NPRR809: Defines the terms “initial energization” and “initial synchronization;” adds a reference to a quarterly stability assessment for interconnecting generation resources when evaluating the need for a generic transmission constraint; and clarifies a resource’s requirements prior to initial synchronization.
NPRR810: Removes the applicability of a reliability-must-run agreement’s incentive factor to reservation and transportation costs associated with firm fuel supplies, and accordingly separates costs in the RMR standby payment equation.
NPRR812: Clarifies short-term system adequacy report language; aligns protocol language with current ERCOT practices and Public Utility Commission of Texas rules for posting resource and load information; and modifies the requirement for posting a RUC initial-conditions report to only include the process as originally intended in NPRR314.
NPRR813: Requires references to service organization controls for the annual ERCOT market settlement audits.
NOGRR166: Eliminates a redundant report of daily operational information that can be found elsewhere on the Market Information System.
PGRR052: Ensures a new generating unit’s operating limits are established by setting a timeline for stability studies following a full interconnection study (FIS), incorporating model data or transmission system changes, not known during the FIS, before a new unit is brought online.
PGRR054: Clarifies the content, review period and process for posting an FIS’ results, and establishes a process for identifying, proposing and implementing solutions to stability issues identified during the FIS.
PGRR055: Defines the process for revising the Planning Guide to first consider PGRRs at the subcommittee level.
RMGRR144: Eliminates the requirement for transmission and/or distribution service providers to maintain a secure list of retail electric provider data numbering systems for all electric service identifiers (ESI IDs) with “switch-holds” — measures to prevent customers with unpaid bills from changing retail electricity providers.
LPGRR060: Provides additional clarification to the load-profiling guide by removing “orphaned language” not captured in LPGRR057, which was approved by the TAC in October.
LPGRR061: Modifies the annual validation timelines for residential and business ESI IDs by starting the validation activities on March 30 and concluding them on Sept. 30 of each calendar year.
Though one director is reaching his term limit, MISO’s nine-member Board of Directors could look the same going into 2018.
Directors Thomas Rainwater’s, Paul Bonavia’s and Baljit Dail’s terms expire at the end of 2017. Rainwater and Bonavia have not reached MISO’s limit of three three-year terms, and both agreed to seek re-election by MISO membership for another term.
Dail has reached the term limit, but Board Chairman Michael Curran said at the March 23 board meeting that Dail has agreed to seek re-election for an additional term if a waiver is recommended by the Nominating Committee and approved by the board.
MISO’s Principles of Corporate Governance state that the term limit can be waived if the board determines “that a director’s continued service is necessary to retain his or her skills or expertise, to maintain geographic or other diversity of the board, or is otherwise in the best interests of” the RTO.
MISO’s board has seen considerable turnover in the past two years, with two directors — Phyllis Currie and Mark Johnson — added in late 2015 to replace former Director Eugene Zeltmann, and three directors — H.B. “Trip” Doggett, Barbara Krumsiek and Todd Raba — brought on in late 2016 to replace former Directors Judy Walsh, Michael Evans and Paul Feldman.
This year, stakeholders elected Arkansas Public Service Commission Chairman Ted Thomas to serve on the Nominating Committee. The vote for the second stakeholder seat ended in a tie between Madison Gas and Electric’s Megan Wisersky and Entergy’s Matt Brown. Stakeholder relations staffer Alison Lane said the vote for the second seat will be redone, with ballots sent out again this week. She said if all seven voting-eligible sectors participate, the vote cannot end in a tie.
MISO Market Software Adequate for Another 5-7 Years
MISO will be able to squeeze an extra couple of years out of its aging market system, said Dail, chair of the Technology Committee.
Late last year, MISO Executive Director of Market Design Jeff Bladen said officials expected to replace the system in two to three years, announcing that the RTO had hired consultants to study system improvements. (See MISO to Study Aging Software; Market Improvements Planned for 2017.)
But Dail said the system can take on more complexity and remain usable for five to seven years.
The RTO’s staff said the Clean Power Plan’s likely rejection by the Trump administration defers the need for new system technology, because intermittent and behind-the-meter generation is not expected to be added at such a rapid pace. Currie asked how much money MISO could expect to save because of the IT deferral. MISO CEO John Bear said the savings would be reported in future budget projections.
“That’s a welcome, but somewhat dramatic, change in timeframe,” Krumsiek said.
Dail also said that an internal technology audit again ranked MISO low when it comes to removing employee access to MISO systems after they are transferred or leave the RTO’s workforce. MISO had a self-imposed goal of 24 hours to remove both critical system access and perform an administrative cleanup. NERC standards allow 24 hours to remove an employee’s system access and 31 days to scrub employee information from the system. Dail said MISO has since allowed itself a more doable seven days to perform an administrative cleanup, separating it from the 24-hour access deadline.
MISO Operations Under Budget; Project Timing Nudges Capital Spending Over
MISO’s $37.7 million in spending so far in 2017 is under budget by $100,000, or 0.3%, newly hired Chief Financial Officer Melissa Brown said. She said the savings can be attributed to a slower hiring rate and MISO delaying some travel and the hiring of consultants.
Actual expenses of $37.7M resulted in YTD being under budget by $0.1M or 0.3% | MISO as of February 28, 2017
However, MISO’s capital spending is over budget by 2.4%. Tony Guisinger, strategic development and operations executive, said capital spending is higher than planned because of some later-than-planned equipment purchases and related installation fees.
Guisinger, who assumed financial duties after former Vice President of Finance Jo Biggers left unexpectedly last year, is still assisting Brown, who joined MISO in late January. (See MISO Appoints Melissa Brown as New CFO.)
Board May Conduct Long-Term Incentive Review
Human Resources Committee Chair Todd Raba said MISO is planning a review of its long-term executive incentive plan.
The long-term bonus plan, which gauges and rewards performance for longer than one year, has not been changed in 15 years. Raba said his committee would complete a review of the current plan in June and act on proposed changes by October.
The board unanimously voted to grant RTO membership to two non-transmission-owning companies.
Clean energy project developer and operator ALLETE Clean Energy joined the Independent Power Producers sector, and transmission developer Verdant Plains Electric joined the Competitive Transmission Developers sector.
AUSTIN, Texas — Despite opposition from independent generators and competitive retailers, ERCOT stakeholders last week approved a protocol change that clarifies that the ISO can curtail DC tie loads without having to declare an emergency condition.
The Technical Advisory Committee on Thursday approved a nodal protocol revision request (NPRR818) that specifies that ERCOT may curtail DC tie loads during a watch, before declaring an emergency condition.
| ERCOT
Representatives from two independent generators (Luminant and Dynegy) and three competitive retailers (Direct Energy, Just Energy and Reliant Energy Retail Services) abstained from the vote but made their opposition known.
Luminant’s Amanda Frazier said she was concerned about the way in which the NPRR was developed. It was written after ERCOT operators issued a power operations bulletin (POB) on Sept. 28 that changed the ISO’s operation of its five DC ties, which have a capacity of more than 1,250 MW. The POB, which took effect two days after its issuance, particularly affected exports into Mexico over Comision Federal de Electricidad ties.
Unilateral Action
“ERCOT has been curtailing DC ties in emergency situations. Then they unilaterally decided to stop doing that — and did that by issuing a [POB], a process not reviewable by stakeholders,” Frazier said. “That materially changed market outcomes for those market participants using DC ties into Mexico. I find that problematic. I think if something needs to be changed in the protocols that has major market impacts, we should know about it. We should be able to look at it, and we should know the policy decisions behind it.”
Luminant’s written comments recommended ERCOT only curtail DC ties during a Level 2 energy emergency alert (EEA), and not during a watch. It pointed out that voluntary load curtailment is not fully deployed until the ISO declares a Level 2 EEA. Involuntary load shed should not be used ahead of other “compensated, voluntary reliability deployments,” the company said.
‘Future Fix’
“I understand that wouldn’t work in a localized problem, but this language [isn’t limited to] a localized emergency,” Frazier said, “I don’t think it’s … appropriate to curtail DC ties before an EEA2 for a systemwide emergency, but I understand that’s going to be looked at in a future fix to this.”
Shams Siddiqi, representing Rainbow Energy Marketing Corp., the NPRR’s sponsor, told the TAC that “future fix” will be an additional protocol change.
Reliant Energy’s Bill Barnes said he would not oppose the NPRR given that additional revisions would be filed. He said that would fix “the problem we see: loosening reliability actions to allow these DC ties to be curtailed sooner, which has market impacts.”
“I think the ops team took what they viewed as appropriate actions, considering some of the changes that occurred,” ERCOT COO Cheryl Mele told the TAC, referring to the issuance of the POB. “The question I’m hearing is POBs with such a significant impact shouldn’t come out [two days] before we implement it. I concur with that. We should use the proper forums and processes.”
Mele’s comments related to recent changes in ERCOT’s capacity, including the Frontera Plant’s move from ERCOT to Mexico, and an increase in DC tie capacity, ERCOT spokeswoman Robbie Searcy said after the meeting. (See ERCOT Board OKs Rio Grande Valley Fixes.)
‘Fair Request’
Garland Power & Light’s Dan Bailey asked ERCOT to report back to the committee on how often curtailments are made during watch events.
“That is a fair request,” Mele responded. She said the reports will be filed with the TAC’s Reliability and Operations Subcommittee, “so you guys will be engaged.”
Rainbow Energy contended the NPRR would “minimize inefficient wholesale market operations and consequent harm to market participants.” The revision would be effective April 5, assuming ERCOT’s Board of Directors approves it the day before.
Before ERCOT issued the operations bulletin, it would accept DC tie e-Tags up to the physical limit of the ties, rarely curtailing the tags close to the operating hour.
Under the POB, e-Tags have been denied when day-ahead prices were relatively high while real-time prices were depressed and DC tie capacity was under-utilized, according to Siddiqi’s “business case” for the change. The result: “an avoidable inefficient outcome for the market and loss for the market participant,” Siddiqi said.
Siddiqi also said ERCOT prefers to take action in advance to avoid the chance of an emergency condition “and subsequent [NERC] scrutiny of why ERCOT did not act in advance to avoid the emergency.”
“Market participants wanting to export power have to procure power in the day-ahead market without knowing whether the e-Tag will be approved or denied,” according to the NPRR. “In turn, they are subjected to a loss and contractual difficulties with their counterparties if the e-Tag is denied.”
By allowing e-Tags to be curtailed in a watch before an EEA2, “ERCOT can revert back to its pre-POB operating procedure of approving e-Tags up to the physical limits of the DC ties,” Siddiqi said. “E-Tag approval can again be done prior to DAM [the day-ahead market] — allowing market participants to correspondingly procure energy in DAM and have the added certainty in its contractual obligations.”
“We have worked with Rainbow to implement what we understand the stakeholder’s intent, so we can be very transparent in the future,” said ERCOT’s Dan Woodfin, senior director of system operations. “The protocols don’t affect how we set limits today. With this change, how we set those limits will be clarified.”
WASHINGTON — President Trump signed an executive order Tuesday directing EPA to begin the lengthy process of undoing its Clean Power Plan, a centerpiece of American efforts to battle climate change.
Trump signed the order following remarks in the wood paneled Map Room at EPA headquarters, surrounded by his top energy lieutenants and a group of coal miners. “You know what this says?” Trump asked the miners, pen in hand. “You’re going back to work.”
Trump’s remarks followed those of Energy Secretary Rick Perry, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence, who noted the decline in coal mining jobs in recent years. “Those days are over,” Pence promised, “because the war on coal is over.”
“We’re no longer going to have regulatory assault on any given sector of our economy,” Pruitt said. “We’re not going to allow regulations here at the EPA to pick winners and losers.”
President Trump signs executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence watch.
“Our nation can’t run on pixie dust and hope,” Zinke said.
The administration’s promises that coal mining jobs will return may be equally fanciful, however. Natural gas and renewable generation have become cheaper than coal-fired power in many regions, and the most productive mines are increasingly automated.
Years of Litigation to Come?
Trump’s bid to undo the CPP, meanwhile, could take years.
The Supreme Court stayed the rule in February 2016 pending a legal challenge by more than two dozen states that contended the rule overstepped EPA’s regulatory authority. The D.C. Circuit Court of Appeals heard arguments in the case in September. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
Legal experts differ on whether the D.C. Circuit will dismiss the states’ challenge based on the Trump administration’s withdrawal of support for the CPP. Environmental groups immediately promised to fight the reversal of the plan.
Trump’s order will put EPA officials in the odd position of having to contradict the findings the agency cited when it issued the final rule in August 2015, which incorporated feedback from 4.3 million comments and months of meetings with state regulators, utilities and RTO officials. (See Revised Clean Power Plan Allows More Time, Sets Higher Targets.)
EPA also will have to overcome its 2009 finding that greenhouse gases endanger the public health and must be controlled.
Paris Agreement Threatened
Although the order does not indicate whether the U.S. will withdraw from the 2015 Paris Agreement on climate change, eliminating the CPP would make it far more difficult for the nation to meet its obligations to cut its carbon emissions to 26% below 2005 levels by 2025. The CPP requires a 32% reduction in power plant CO2 emissions from 2005 levels by 2030.
Economic consultancy company Rhodium Group estimates the U.S. would reduce carbon emissions by 21% below 2005 levels in 2025 under the CPP but that the reduction would flatten at 14% under Trump’s rollback.
| Rhodium Group Analysis
The Paris Agreement is intended to prevent the planet’s temperature from increasing by more than 3.6 degrees Fahrenheit, which many experts say would lead to an irreversible future of rising oceans and extreme weather, leading to drought, flooding, and food and water shortages.
Other Provisions
The executive order also ends a moratorium on federal coal leasing and eliminates the requirement that federal officials consider the impact of climate change when making decisions.
Press Secretary Sean Spicer said the order directs federal agencies to review all rules “that put up roadblocks to domestic energy production and identify the ones that are not either mandated by law or actually contributing to the public good.”
It also orders a review of the standards for new generators, which effectively banned new coal plants without carbon sequestration. The levelized cost of a new coal generator with sequestration is about double the cost of new solar PV and wind, according to the Energy Information Administration.
Coal Jobs
EIA’s annual coal report last November found that U.S. coal production dropped 10.3% in 2015 to less than 900 million short tons, the lowest annual production level since 1986. Employment at U.S. coal mines dropped 12% in the year to less than 66,000, the lowest since the agency began collecting data in 1978.
More than 21 GW of coal generation retired in 2015 and 2016, largely as result of the Mercury and Air Toxics Standards, and EIA says another 14 GW is at risk of retirement by the end of 2028.
Energy economist Robert W. Godby, of the University of Wyoming, told The New York Times that Trump’s order could delay the closing of some endangered coal mines for as long as a decade. But because of increasing mechanization, “they’re not hiring people,” he said. “So even if we saw an increase in coal production, we could see a decrease in coal jobs.”
Economic Impact
Trump’s cabinet members portrayed the Obama administration’s environmental policies as a drag on the economy, with Perry decrying “poorly designed government policies, distorted markets” and a power grid whose reliability is being “tested because fuel diversity has been diminished in order to benefit one technology over the other.”
“The executive order will begin the process to unravel the red tape that’s been keeping investment on the sidelines and innovation stymied,” Perry said.
EPA’s Regulatory Impact Analysis of the CPP — which is not given credence by the agency’s critics — predicts the rule would produce economic and health benefits far exceeding its costs.
Critics say walking away from the Paris Agreement would hurt American leadership in clean energy technologies.
“The Trump administration is turning the nation’s back on the historic opportunity to build a clean energy future — a future that will modernize our energy system, offer consumers better value for their energy dollars and invest in state and local economies while taking the right steps to reduce climate pollution,” said Daniel Sosland, president of Acadia Center, which supports clean energy policies.
EIA predicts renewable electricity generation will grow 3.9% annually through 2030 without the CPP and 4.7% a year with it.
| EIA, Annual Energy Outlook 2016
Regardless of what happens with the CPP, utilities, major corporations and many states are likely to continue their efforts at decarbonizing the generation mix.
New York Gov. Andrew Cuomo and California Gov. Jerry Brown issued a joint statement reaffirming their commitment to exceed the CPP’s targets.
“Climate change is real and will not be wished away by rhetoric or denial,” they said. “Together, California and New York represent approximately 60 million people — nearly one-in-five Americans — and 20% of the nation’s gross domestic product. With or without Washington, we will work with our partners throughout the world to aggressively fight climate change and protect our future.”
Reaction
Other reaction to Trump’s order was, unsurprisingly, mixed.
Environmentalists said the order could damage climate change efforts while producing no benefits for the coal industry.
“The fact that major utilities in Ohio are planning to shut down a number of dirty coal-fired power plants throughout the state should be an indication that the market is moving on to less costly and cleaner resources,” said Shannon Fisk, managing attorney for the Earthjustice coal litigation program. “We will be advocating to maximize energy efficiency and renewable energy as the best options for replacing coal plants, and for providing a just economic transition for coal workers and communities.”
David Doniger, director of the Natural Resources Defense Council’s Climate and Clean Air Program, tweeted: “Coal country needs a path to the economy of the future, not false hopes Trump won’t deliver.”
Paul Bailey, CEO of The American Coalition for Clean Coal Electricity, called the CPP “the poster child for regulations that are unnecessarily expensive and have no meaningful environmental benefit.”
The American Public Power Association also supported the president’s action. “Public power has previously voiced its legal objection to the rule for requiring utilities to fundamentally alter the way they generate electricity. In some cases, utilities would have been forced to abandon functional power plants while continuing to pay them off,” the group said.
WESTBOROUGH, Mass. — ISO-NE planners will make a several changes in their procedures in 2017, including revisions to Planning Procedure 3, incorporating probabilistic planning, a review of how the RTO identifies Bulk Power System (BPS) assets and a streamlined method of developing models, Director of Transmission Planning Brent Oberlin told the Planning Advisory Committee last week.
The process changes and the incorporation of updated load, energy efficiency and photovoltaic forecasts may have a significant impact on both the system’s identified needs and their year of need, Oberlin said.
Responding to stakeholder concerns about too much time being required for ISO-NE to complete needs assessments, Oberlin said that planners will move from a work flow based on serial preparation to one based on parallel modeling.
“We’re stealing from PJM here, which has inspired us to create generic case studies to look at all of New England at once rather than state by state,” he said at the March 22 meeting. “Right now, our start-to-finish case study process takes six months.
“After we talked to PJM, [we] kind of hit [ourselves] in the head” for not making the change sooner, Oberlin said. The current process is “serial, it’s slow and I don’t think it’s effective.”
ISO-NE plans to create a “library” of generic cases and study files for use in the future. Once the RTO and its transmission and other facility owners update the system topology data, the generic cases and study files will be updated with the latest load, energy efficiency, photovoltaic and resource data and posted for stakeholder review.
The RTO also is comparing its assumptions for classifying assets as BPS with those of other transmission operators in the Northeast Power Coordinating Council (NPCC). “It’s not lost on us that New England has more than half of the BPS classified substations within the NPCC, so we may revise the definition of what is a BPS,” Oberlin said.
The changes to Planning Procedure 3, which took effect Feb. 10, reduced the types of contingencies required for second contingency testing, limiting them to those with the greatest potential to impact the identification of system needs.
No longer required to be tested as the second contingency: the loss of two adjacent circuits on a multiple circuit tower and a permanent phase-to-ground fault with breaker failure. These second contingencies must still be tested under NPCC requirements, but solutions will be required only when the problems impact BPS facilities.
After more than a year of work with the PAC, the RTO will begin incorporating probabilistic dispatch methods in late spring, starting with the inclusion of probabilistically based local dispatches in the base system conditions used in needs assessments. The use of probabilistic methods will likely increase in the future, Oberlin said.
Eversource Towers Show Their Age
Eversource Energy engineering manager John Case showed slides of rusting steel and deteriorating concrete foundations to prove the need for replacing four aging towers carrying transmission lines over the Thames River in Connecticut.
Part of rusted transmission tower | Eversource
About half a mile of the 1410/100 lines from Montville to Gales Ferry Junction shares double-circuit steel lattice towers that straddle the river at the Montville-Ledyard border.
“These structures were constructed in 1921 and have exceeded their planned life, and may have done [so] before I was born,” Case said to laughter. “And I am not a young man.”
Recent inspections of the structures revealed severe degradation of the foundation, towers and hardware. The four towers will be replaced with six galvanized steel poles at an estimated cost of $8.5 million (-25%/+50%).
NEW ORLEANS — A debate over the fairness of the postage stamp cost allocation method and how to quantify transmission benefits took center stage at the MISO Advisory Committee’s quarterly hot topic discussion.
MISO Vice President of System Planning and Seams Coordination Jennifer Curran noted that the RTO has not changed cost allocation rules since the integration of MISO South.
“Are there benefits that are no longer relevant? Are there benefits that we haven’t even realized yet? These questions are critically important,” Curran said during the March 22 discussion.
As part of a review of its cost allocation procedures, MISO is considering lowering the 345-kV threshold on market efficiency projects and replacing the footprint-wide postage stamp rate with a method that assigns costs to benefiting transmission pricing zones. It is also seeking to identify other economic benefits in addition to production cost savings, including eliminating the need for future fixes by pursuing a long-term project over a short-term project and projects that aid planning reserve margins. (See MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.)
Curran said she didn’t expect unanimous sector support on any revised cost allocation procedure, but there is some consensus within sectors. “The biggest challenge we face is a common definition given the challenges we face,” Curran said.
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, introduced the topic, saying it was “incredibly hot and had incredible significance.” She then cued the O’Jays’ “For the Love of Money,” eliciting applause.
Transmission Owner sector representative Matt Brown of Entergy pointed out that MISO changed aspects of its transmission cost allocation in 2003, 2007, 2009 and 2012. “This is not a static set of rules, and MISO has shown the ability to change and adapt,” Brown said. But he said that “experimental” changes should not be made to MISO’s “mature” cost allocation process.
“There is a lot that works with what we have now, and I caution everyone not to lose sight of that,” Brown said.
Northern Indiana Public Service Co.’s Paul Kelly cautioned MISO against “speculating” on transmission benefits, saying they should be represented with an equation that can be repeated across projects.
WEC Energy Group’s Chris Plante said most in his Transmission Dependent Utilities sector support a postage stamp rate because many benefits of transmission projects are not quantifiable or are realized later.
“Today’s reliability project could be tomorrow’s multi-value project,” Plante said.
Brown said the TO sector is not interested in pursuing a postage stamp allocation, which assesses a uniform rate on all MISO transmission owners, simply for the sake of benefits that may be missed. “If you can’t measure it, it’s not a benefit that should be considered. Benefits need to be demonstrable, repeatable and non-duplicative,” he said.
Thomas: Postage Stamp not Always Best
Arkansas Public Service Commission Chairman Ted Thomas, the delegate for the Regulatory sector, said MISO should conduct extensive analysis before implementing any change.
“The business is changing, but modeling is changing too, and we have more operational history. If there need to be sub-zones — better ways of how a true beneficiary pays — then we need to do that,” Thomas said.
Thomas also said postage stamp allocation is not always the most equitable method. “Let’s not use a postage stamp when we can’t figure [benefits] out. Let’s go back to the lab and figure it out,” he said.
MISO Director Michael Curran said he understood stakeholder frustration if too many benefits are swept into a “common good” category and applied on a postage stamp basis.
Plante said that while MISO’s modeling has improved and can identify a beneficiary “right down to a point of delivery,” the modeling is only as good as the assumptions on which it is based, including forecasting natural gas prices and impacts of future regulations.
Public Consumer sector representative and attorney Kevin Lemley said postage stamp allocation fails to recognize that non-transmission alternatives can solve some problems.
ITC Holdings’ Devin McMackin said MISO’s list of project types is probably too “rigid” and said he supports more flexibility or an expansion of project types.
Allocation by Project Type
MISO’s allocation procedures vary by project type:
Costs of market efficiency projects 345 kV and above are split 80% to local resource zones based on benefit and 20% to load through postage stamp.
Generation interconnection projects above 345 kV assign 90% of costs to the interconnection requestor, with 10% allocated to load on a postage stamp basis.
Multi-value projects are allocated entirely to load via postage stamp.
Baseline reliability projects are allocated entirely to local pricing zones.
Projects arising from transmission service requests are paid for by transmission customers, but the transmission owner can elect to roll costs into local pricing zone rates.
Participant-funded projects are left out of cost allocation procedures entirely, and projects not eligible for allocation can be recovered through a zonal transmission rate.
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Plante said cost allocation needs to be resilient, able to survive an expanding footprint and shifting resource mix. Stakeholders again brought up MISO’s hourglass-shaped footprint and constrained MISO South interface, which some maintain precludes a benefits ratio from being applied to the footprint uniformly.
Alliant Energy’s Mitchell Myhre, representing the TDU sector, said adjusted production cost benefits should remain the primary metric when deciding allocation. All other benefits should be secondary considerations in cost allocation, Myhre said.
Director Paul Bonavia asked for a future session between the board and MISO staff on a preliminary cost allocation proposal.
‘Rough Justice’
Director Curran urged MISO and stakeholders to create a proposal, citing an adage: “‘Done is better than perfect.’”
Several stakeholders said that any cost allocation revision that MISO files with FERC would be an example of “rough justice,” meaning it would be generally fair but not acceptable to all parties.
MISO stakeholders are discussing possible allocation changes in the Regional Expansion Criteria and Benefits Working Group (RECBWG). Group chair Carolyn Wetterlin said the working group is considering simplifying its name to the Transmission Cost Allocation Working Group.
A day earlier, during a presentation on the 2017 MISO Transmission Expansion Plan (MTEP 17) at the March 21 Markets Committee of the Board of Directors, Director Phyllis Currie asked what MISO’s biggest challenge is when it comes to transmission planning.
“At the end of the day, I think it comes back to who pays,” Jennifer Curran said.
Director Mark Johnson asked for a review of MTEP-approved projects to determine if their projected cost benefits had been realized. Curran said MISO could collect that information.
Director Thomas Rainwater said he liked the idea of cost allocation post mortems, in which MISO staff would examine whether transmission benefits are being distributed as they were estimated.
NEW ORLEANS — MISO Independent Market Monitor David Patton last week used PJM’s proposed pro forma pseudo-tie agreement to renew his call for an end to pseudo-ties.
On March 9, PJM made a Section 205 filing with FERC to add criteria for accepting pseudo-ties (ER17-1138). PJM would require that it have dispatch control over new and existing pseudo-ties from NYISO and MISO. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)
On Thursday, PJM officials delayed a stakeholder vote on the agreements. (See related story in PJM Markets and Reliability and Members Committees Briefs.)
Having NYISO units dispatched by PJM — which may not be fully aware of all the ISO’s data — is not a sound idea, considering New York’s transmission congestion, Patton said. He added that at least 18 units in MISO would be dispatched by the other RTO in the 2017/18 planning year beginning June 1. PJM currently dispatches 13 MISO units.
“It’s very inefficient. … It’s just a terrible idea,” Patton told the Markets Committee of the Board of Directors on Thursday.
Patton said PJM’s filing signals a good time for MISO to again propose replacing pseudo-ties with a firm capacity delivery procedure. MISO’s proposal would guarantee the delivery of the capacity purchased by PJM by the host RTO scheduling a firm export in the real-time market and having the external capacity supplier settle the export with both RTOs. Patton said MISO’s proposal is an “attractive” idea. (See “MISO IMM Warns Again of PJM Pseudo-Ties,” MISO Market Subcommittee Briefs.)
MISO Director Michael Curran said the creation of pseudo-ties itself was an “emotional response” to manage electricity flows from different balancing authorities in the early days of RTOs. “It’s difficult to try to get this to work, because it never worked in the first place. It sounds like it’s coming to a critical point here, and we’ll have to work with New York to bring some sanity to the situation,” Curran said.
Patton said MISO and NYISO might face resistance from PJM because PJM staff and stakeholders generally view the pseudo-tie concept as a way to maintain control of the quality and reliability of the generation on its system.
“I wouldn’t be opposed to a megawatt limit” on the volume of exports from MISO to PJM, Patton added.
Curran did not let the comment go unnoticed. “I’m shocked by that. You’re a fundamentalist, and suddenly you’re in favor of limits,” Curran said lightheartedly. “I’d hate to see you close the borders.”
Director Barbara Krumsiek asked which of PJM’s neighbors support the RTO’s proposal.
“That’s a good question,” Patton said laughing. He added that NYISO has no pseudo-ties with PJM and would most likely want to keep it that way.
Director Baljit Dail asked when the pseudo-tie issue might be solved.
Richard Doying, MISO executive vice president of operations and corporate services, said resolving the issue would be a long-term project. He said MISO would consult both its Monitor and stakeholders before proposing a Tariff solution to FERC.
NEW ORLEANS — MISO experienced a quiet winter, aside from early February tornadoes in Louisiana and high congestion charges from a MISO-PJM constraint.
Demand peaked at 100 GW, about 9 GW below MISO’s all-time winter peak during the 2014 polar vortex.
“We had a relatively mild winter and that turns into relatively mild operating conditions,” MISO Executive Director of Market Design Jeff Bladen said during a quarterly operations report at the March 21 Markets Committee of the Board of Directors meeting.
Average LMPs rose to $28/MWh from $21/MWh last year as gas prices rose 55% year-over-year, Markets Committee Chair Paul Bonavia said. He said MISO’s plentiful wind output kept prices from ticking further upward.
Independent Market Monitor David Patton said the most significant event in the quarter was a series of tornadoes in Louisiana on Feb. 7 that resulted in multiple transmission outages and pushed Louisiana Hub prices above $1,000/MWh for three hours. The storms led to $19 million in real-time congestion.
Patton said the storms caused real-time prices to be 30% higher than day-ahead prices for all of February.
“An event like this can cause a huge spike in balancing congestion charges,” Patton said. Balancing congestion charges, which normally average $1 million per month, totaled $11 million.
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Bladen said the weather incident caused MISO’s monthly market efficiency metric to increase by $15 million. “The impact was appreciable due to the outages,” Bladen said.
Director Baljit Dail expressed worry that an “act of God” caused such havoc on MISO’s markets, and said the Human Resource Committee of the Board of Directors could look into purchasing insurance against it. “When you consider the world we live in, more of these severe weather events will happen,” he said.
“We certainly do quite a bit to prepare for these severe conditions,” Bladen replied.
Director Michael Curran asked if approved transmission projects in Louisiana would help relieve congestion in future emergency conditions. MISO staff agreed that they would.
Not all of MISO’s winter real-time congestion could be attributed to severe weather. Most congestion occurred along the MISO-PJM seam and was caused by transmission outages and high wind output, Patton said.
A single MISO-PJM market-to-market constraint alone accounted for $40 million worth of congestion and was “difficult to manage because it is dominated by PJM resources,” Patton said. On Feb. 7 — coincidentally the day of the tornadoes — MISO transferred control of the constraint to PJM, “reducing congestion on the constraint and improving the dispatch,” according to Patton.
The Monitor said he would like to see MISO, PJM and SPP become more active in transferring monitoring of constraints “but it requires agreement and improved processes.” There are a number of cases where the non-monitoring RTO has all of the transmission loading relief on a flowgate, he said.
Patton also said there are several instances in which MISO and a neighboring RTO have to manually control flowgates, which is not as efficient.
“We feel the RTOs should develop better software and procedures” to switch control of the constraint to the RTO with the most relief, Patton said.
A jump in wind production also contributed to higher congestion in the quarter. Wind output rose 21% from the fall and 20% over last winter as MISO set an all-time wind output record of 13.7 GW on Dec. 7, beating the previous 13.3-GW record set in late November.
Patton said wind output contributed to $47 million of real-time congestion costs. He said the increase in wind output was most significant near the MISO-SPP seam where MISO wind resources are plentiful. SPP had difficulties controlling power flows from MISO into SPP.
“We get into situations where it’s difficult because we have a lot of wind resources that whip the flows around,” Patton said, adding that SPP sometimes will control the flows manually, which is more expensive.
“When your neighbor is dominating the constraint, you should hand the constraint over. SPP in particular has been resistant to this. PJM has been more willing to do this than SPP,” Patton said.
He said MISO and SPP should continue to work together to address monitoring control of constraints rather than “abandon economic coordination.”
MISO and SPP are working together on transfers of monitoring control and hope to agree on a smoother process later in the year, MISO staff said.
A top California lawmaker last week introduced a bill that would require the state’s utilities to meet an increasing amount of their peak energy demand with renewable resources and energy storage systems.
The proposed law would set a “clean peak energy standard” to reduce the reliance on flexible, gas-fired peaking plants to meet peak ramping needs as the state seeks to obtain 50% of its electricity consumption with renewable energy resources by 2030 (AB 1405).
State Assembly Speaker Pro Tempore Kevin Mullin (D), the bill’s sponsor, said that while California’s renewable energy and ambitious greenhouse gas reduction goals are “laudable,” they are “ultimately incongruous in the absence of a policy framework and new market mechanisms” that would allow CAISO to manage the impacts of increasing renewable penetration on the grid.
Mullin
“As more renewables are built toward the 50% [renewable portfolio standard] goal, more fossil fuel power plants will be built to provide flexibility and reliability, which is incompatible with the GHG reduction and cost-effective goals,” Mullin said in a statement.
The legislation defines a four-hour “peak load” time period that includes the hour leading up to, and two hours following, the hour of peak demand.
The law would require the California Public Utilities Commission to determine by Dec. 31, 2018, the percentage of “clean peak resources” — renewables and storage — being used by each of the state’s utilities to serve demand during the peak load period.
Each utility would have to meet increasing clean peak targets every three years beginning in 2020 and reaching 40% in 2029. The first year of the program would entail a 5% increase in such resources. Utilities would be required to meet the minimums for at least 15 days every month.
The rules would also apply to the state’s publicly owned utilities, which are not subject to CPUC oversight.
Use of clean peak resources would be subject to CAISO-approved measurement standards, while the CPUC would be charged with devising an “appropriate mechanism” for determining compliance with the clean peak standard, which could include a program of tradeable credits.
The bill also requires the PUC to consider developing other targets that would encourage the use of clean peak resources to provide additional flexibility and ancillary services.
A similar but less comprehensive bill has been introduced into the State Senate.
SB 338 would require the CPUC and California Energy Commission to consult with CAISO and “establish policies or procedures to ensure that electrical service providers meet net-load peak energy and reliability needs while minimizing the use of fossil fuels and utilizing low-carbon technologies and electrical grid management strategies.”
Under the Senate bill, “net-load peak energy” is defined as a daily period of three hours in which the last hour represents the interval of highest demand. The bill would permit the use of demand response and energy efficiency measures, in addition to renewables and energy storage.
