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October 31, 2024

MISO, PJM Unveil JOA Process for ‘Targeted’ Market Efficiency Projects

By Amanda Durish Cook

MISO and PJM are seeking to hammer out new joint operating agreement language that would allow accelerated approval of short-term projects intended to relieve congestion at the RTOs’ seams before advancing further on a joint study that would identify potential projects.

MISO engineer Adam Solomon said that while the RTOs continue to work on the language detailing joint targeted market efficiency projects (TMEPs), the JOA needs to have a vetted process in place before project selection begins.

PJM MISO Joint and Common Market JOA Targeted Market Efficiency

“We should really have the JOA language worked out before we push further into the study,” PJM engineer Alex Worcester agreed during a July 29 meeting of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC).

Targeted MEPs will differ from ordinary MEPs, which undergo a “longer and more rigorous” review that combines regional approval, modeling and analysis, and a review timeline. MEP rules may also be changing as a result of a FERC order requiring the RTOs to revise their interregional approval processes. (See MISO, PJM Working to Comply with NIPSCO Order.)

The two RTOs are currently evaluating 13 potential small projects in Illinois, Indiana, Michigan and Ohio.

“We’re really looking for the small, low-cost, short lead time projects that alleviate historical congestion at the seam,” Worcester said.

“We’re reviewing the upgrades and we’re working to ensure they’re effective and alleviate congestion,” Solomon said.

Officials from both RTOs said construction of the small projects could begin before the end of the year. That would require a special approval process developed within “a very tight timeline,” said Worcester, adding that the JOA should set out a simple method for TMEP approval.

The JOA stipulates that TMEPs must be in service within three years and cost less than $20 million. Projects exceeding the cap would move to the MEP classification. Because of the near-term nature of TMEPs, inflation rates will not be factored into the cost-benefit calculation.

MISO and PJM also propose to replace the current 1:1 cost-benefit ratio with a requirement that TMEPs produce enough benefits to cover their costs within four years.

“It’s a pretty high hurdle for these projects to pass,” Worcester said. “It’s consistent with our goal of having high-impact projects.”

To determine if a project meets the cost-benefit metric, the RTOs will rely on three years of historical congestion data to project a future case adjusted by market-to-market payments.

The new cost-benefit approach will “avoid complicated analysis,” said Worcester, who added that he could further illustrate the approach at the Aug. 26 IPSAC meeting.

The RTOs also want to be able to discount historical congestion at flowgates — used to determine TMEP project eligibility — by factoring in congestion hedges or auction revenue rights.

Worcester said that flowgates have an average of 30 to 40% of their flow hedged, but some flowgates have 100% hedging while others have zero. “What we’ve seen is a lot of variability from flowgate to flowgate,” he said.

Stakeholders are asked to provide feedback on the proposed TMEP language by Aug. 12. Final draft language will be presented at the Aug. 26 meeting.

“We’re making good progress toward getting this filed,” Worcester said.

Cybersecurity Rules Urged for Distribution Companies

By Rich Heidorn Jr.

NASHVILLE, Tenn. — Regulators from Connecticut and New Jersey last week urged their colleagues to join them in developing cybersecurity rules for electric distribution companies.

Hon.-Arthur-House,-Chair,-CT-PURA-web
House © RTO Insider

“Get in motion. Get started,” Arthur House, chairman of the Connecticut Public Utilities Regulatory Authority, told the National Association of Regulatory Utility Commissioners summer conference. “We have to attack it. It’s too important not to.”

In April, the state released a Cybersecurity Action Plan, which calls for  a voluntary oversight program in which utilities would meet annually with state officials to report on their cyber defense programs, experiences over the prior year dealing with cyber threats and corrective measures they planned.

Hon. Richard Mroz, Prez, NJ BPU
Mroz © RTO Insider

PURA said it will consider adding reviews by “objective, third-party assessors.” The New Jersey Board of Public Utilities issued more prescriptive rules in March requiring senior officers of distribution companies to certify their cyber protection plans, BPU President Richard Mroz said. The rules apply to natural gas, water and wastewater utilities, in addition to electric distribution companies.

The BPU requires the companies to define responsibilities for cyber risk management activities and establish plans for identifying and mitigating risks to critical systems. It also requires companies to provide cybersecurity awareness training and to report cyber incidents and suspicious activity to the agency.

House said it’s understandable that state regulators are reluctant to take on the issue. “There’s just too much work in this job already. We already have too much work to do,” he said.

NERC’s mandatory reliability standards cover only the Bulk Electric System, generally defined as transmission lines operating at 100 kV and above. (See FERC Refines Bulk Electric System Definition.)

Nevertheless, some state regulators see cybersecurity as the exclusive job of the federal government, House said.

Air Gap?

Left to right: Crane and Travis © RTO Insider
Left to right: Exelon CEO Crane and NARUC President Kavulla © RTO Insider

House said he was dismayed to hear Exelon CEO Chris Crane say earlier in the NARUC conference that part of his company’s defense is an “air gap” between Internet-connected computers and the supervisory control and data acquisition (SCADA) system.

“I’ve never met a federal official who believes the air gap exists. We stopped hearing about it from private sector officials in utilities two years ago at least,” House said. “It certainly is an outdated reference to a rather discredited concept.”

On July 21, however, FERC issued a Notice of Inquiry seeking comment on the Critical Infrastructure Protection reliability standards for transmission control centers and whether the commission should require the separation of the Internet and industrial control systems (RM16-18). The notice also asked for input on application “whitelisting” practices to prevent unauthorized programs from running in control centers. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.)

House also disagreed with Crane’s description of the level of cooperation between government and industry. Crane, a member of the Electricity Subsector Coordinating Council, a liaison between the federal government and the power sector, said communication between the government and industry on cyber threats has improved greatly.

“It’s become much better in the last couple of years, having everybody around the table” — U.S. Cyber Command, the FBI and the departments of Defense, Energy and Homeland Security — “really working to communicate across the table much better. The silos are breaking down and the information is flowing.”

House disagreed.

“They’re not sitting at the same table. They’re not talking the same language,” he said. “We have goodwill [and] occasional cooperation. But we do not have an adequate defense system or adequate recovery” plans.

“There is a huge gap,” he continued. “I think we’ll have a partial compliance until we have an attack and then you’ll get mandatory standards” for EDCs.

Defense in Depth

NARUC-Cybersecurity-Panel-(incl-Cheryl-LaFleur)-web
Left to right: Commissioner Mroz, NJ BPU; Commissioner House, CT PURA; Commissioner LaFleur, FERC and Commissioner Jones, WA UTC © RTO Insider

FERC Commissioner Cheryl LaFleur said distribution companies and their regulators don’t need to wait for formal requirements. “There’s a lot that can be done at the distribution level without mandatory standards,” she said, noting that many distribution utilities are NERC registrants because of their transmission assets. “It’s not as if any of them are unaware of cyber challenges.”

LaFleur said the NERC standards approved by FERC rely on “defense in depth,” including perimeter security, virus screening and other measures. Every successful attack, she said, is the result of multiple failures.

Referring to the cyberattack on three EDCs in Ukraine, LaFleur said, “Many things could have stopped it.” (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

On July 21, LaFleur dissented on a FERC order directing NERC to develop a reliability standard for supply chain management, saying the order failed to provide enough guidance and should have been delayed to allow more study (RM15-14-002).

Texas Public Utility Commissioner Ken Anderson said he worried the rule could create a “false sense of security.”

In 2011, he noted, Boeing and the Navy found that the ice detection system on a new P-8 Poseidon, a plane designed for long-range anti-submarine and anti-surface warfare and intelligence missions, was defective because it contained counterfeit components sold by a Chinese subcontractor.

“If the Pentagon — that actually has access to the intelligence — if they can’t catch the defective subcomponents going into a military weapons system … how the heck can a utility know what’s in that chain?” he asked.

Federal Briefs

FERC has granted the developers of the Constitution Pipeline an additional two years to complete the project.

ferc, connected entity, data collectionThe developers said they needed an extension while they appeal the denial by New York environmental officials of a required water quality permit under Section 401 of the federal Clean Water Act. (See Constitution Pipeline Appeals Rejection of Water Permit.)

FERC originally approved the project in 2014, with the condition that it be placed in service within 24 months. The extension gives developers a new deadline of Dec. 2, 2018. The pipeline would deliver Marcellus Shale natural gas from Pennsylvania to pipelines serving New York state and New England.

More: CP13-499

WCS Providing NRC More Info on Nuke Storage Site

wastecontrolspecialists(wcs)Waste Control Specialists began supplying the Nuclear Regulatory Commission more information about the company’s plans to store high-level nuclear waste in Andrews County, Texas, after a letter from the commission fueled opponent groups’ criticisms.

The letter from Mark Lombard, director of NRC’s division of spent fuel storage and transportation, told WCS that its application for the project was deficient and requested more technical data. Opponents said the letter reflected unpreparedness on the part of the company.

WCS officials responded by clarifying the company only wants a license to store spent nuclear fuel rods using a dry-cask design and method already approved by the commission. The company plans to store 5,000 metric tons in the first decade but is seeking approval to store up to 40,000 metric tons.

More: Odessa American

Tribe Sues Corps of Engineers Over Dakota Access Permits

standingrocksiouxtribe(gov)The Standing Rock Sioux Tribe of North Dakota and South Dakota is suing the U.S. Army Corps of Engineers for issuing permits for a crude oil pipeline it says threatens sacred sites and its drinking water supply.

The suit, filed in a federal court in D.C., alleges that the Corps’ approval of the Dakota Access Pipeline is illegal, as it ignored risks to the environment and tribal sites. The pipeline, which would deliver North Dakota crude oil to terminals in Illinois, is being built by Energy Transfer Partners.

The Corps’ approval allows the developer to bury the pipeline under the Missouri River a half-mile upstream of the tribe’s reservation.

More: The Gazette

PSEG Files Opposition to Access Northeast with FERC

Public Service Enterprise Group has submitted a filing to FERC saying that a proposed natural gas pipeline expansion in New England would suppress wholesale prices in the energy market.

The company said the Access Northeast project, proposed by Spectra Energy and being subsidized by four New England states, is not driven by reliability needs, and the utilities that would own the pipeline would rarely use the gas. PSEG also compared it to a New Jersey plan to subsidize power plant construction in the state through the PJM capacity market, which was ruled unconstitutional by the Supreme Court as it infringed on FERC’s jurisdiction.

Critics of the PennEast Pipeline in New Jersey, however, said PSEG’s complaints could also apply to that project, which counts the company among its investors.

More: NJ Spotlight

Nuclear Industry to NRC: Streamline Review Processes

nrcsourcegovA number of industry executives called on the Nuclear Regulatory Commission to improve the efficiency of its review processes, especially when it comes to approving advanced reactors.

“Anything you can do through the regulatory process to assure that the advanced reactors can come online as soon as reasonably possible, it’s going to be important not just for the United States, but for the world to meet this gap of increasing energy consumption,” former FERC Commissioner Philip Moeller, now senior vice president at the Edison Electric Institute, said during a public stakeholder meeting in Rockville, Md.

The meeting was the first of its kind since 1998. NRC was directed to hold it by Sen. James Inhofe (R-Okla.), chair of the Senate Environment and Public Works Committee, which has oversight over the commission.

More: Bloomberg BNA

DTE Expects Boost from Southwestern’s Rig Expansion

DTE Energy raised its 2016 earnings per share guidance from $4.80-$5.05 to $4.91-$5.19 and said the addition of two new drilling rigs in the Utica Shale could boost profits further still.

DTE Expects Boost from Southwestern’s Rig Expansion
Southwestern Energy Drill Rig Source: Southwestern Energy

Houston-based oil and natural gas company Southwestern Energy recently announced it will add five rigs by the end of the third quarter, two of which will be in the DTE-serviced Utica Shale basin, which could boost DTE’s gas storage and pipeline business segment.

The expected increase in drilling activity was excluded from DTE’s revised earnings guidance, which reflected better-than-expected second quarter results. But DTE CFO Peter Oleksiak said during an earnings call last week that the rigs “may provide upside to 2016” earnings and also will aid 2017 results.

DTE reported second-quarter operating earnings of $177 million ($0.98/share), up from $137 million ($0.76/share) in 2015. DTE’s gas segment earned $35 million, up $10 million from a year earlier.

— Amanda Durish Cook

Net Metering Debate Continues in NARUC Session

By Rich Heidorn Jr.

NASHVILLE, Tenn. — Present and former regulators debated the costs and benefits of rooftop solar and the pros and cons of net metering in a spirited discussion at the National Association of Regulatory Utility Commissioners summer conference last week.

Charles-Cucchetti,-formerly-WI-PSC-web
Cucchetti © RTO Insider

Charles Cicchetti, former chair of the Wisconsin Public Service Commission, and former Ohio Public Utilities Commissioner Ashley Brown led off the debate.

Cicchetti, a member of Pacific Economics Group and former economics professor at the University of Southern California, said regulators’ moves to curtail or reduce net metering payments and introduce new demand charges “greatly cut into the benefits that customers who installed rooftop solar expect to earn and use to pay for those systems.”

Cicchetti said regulators should require “vetted … neutral studies” to determine the costs imposed by solar customers and compare them with the benefits they provide.

“When you do that you’ll probably come away with the conclusion that, if anything, the extra costs that are being imposed by rooftop solar [are] far less than the extra benefits both in utility savings and societal benefits,” he said.

He said that time-of-use tariffs are more fair than demand changes, which he called “a blunt instrument.”

“If [rooftop solar customers] take electricity during expensive times, they should pay more. But they should also save more when they reduce electricity — as most of them do — during the time that those systems are operating.”

Ashley-Brown,-formerly-PUCO-web
Brown © RTO Insider

Brown, of the Harvard Electricity Policy Group, disagreed, saying solar customers under net metering are not paying their fair share of the system’s fixed costs.

The value of solar studies is incredibly subjective, Brown said. “Many states have done them; many interest groups have had them done and the findings are all over the map,” with some finding the value of solar is double the retail price and others finding a negative value. “Neither of those cases could possibly be true.

“Several things are always missing from these studies,” Brown continued. “One is, every single one of these values can be obtained from other sources. So why aren’t we disciplining the price we pay for those values by putting it into a marketplace with other sources? And many of these values are provided by other forms of generation who aren’t compensated for it because we don’t pay anybody based on value. We pay them based on market or we pay them based on cost.”

David-Noble,-Nevada-PUC-web
Noble © RTO Insider

Nevada Public Utilities Commissioner David Noble spoke about the state’s bruising net metering battle last year, when the PUC conducted a ratemaking in response to a legislative mandate that rooftop solar result in “no unreasonable cost shifts.”

Noble said the commission was vilified by solar energy providers even though it rejected demand charges, implemented optional time-of-use rates and ordered a phase-in of “value-based” rates for excess energy.

“The rooftop solar companies decided to take an approach … that there should be no change from retail rates,” he said. “When you take an all-or-nothing approach, there’s a possibility that you’re going to lose. And that’s exactly what happened because they put on an inferior case.

“The CEO of SolarCity was claiming that he literally had a gun to his head and the commission was in the back pocket of” NV Energy, he said.

Solar companies bused hundreds of protesters to PUC headquarters, some of them exercising their open-carry rights to travel with guns, Noble said. There they attempted to alarm consumers by claiming utility rates would increase by 3% annually for the next 20 years.

“We haven’t had 3% increases year-over-year for any longer than three years,” he said. “In fact, over the last six years … rates have been flat in southern Nevada and they’ve gone down 20% in northern Nevada.”

Beverly Heydinger, chair of the Minnesota Public Utilities Commission, said the focus on net metering and rooftop solar is myopic, and that policymakers should also consider storage, electric vehicles and other emerging technologies.

“We’re not planning for today. We’re trying to develop a flexible enough template that we can use it and adapt as the times are changing,” she said.

Board Approves Z2 Timeline Extension, Creates Task Force for Further Study

By Tom Kleckner

RAPID CITY, S.D. — The SPP Board of Directors and Members Committee last week agreed to give transmission customers an extra 50 months to pay their Z2 bills while also creating a new task force to address complaints of members charged for costs that were not identified in service agreements.

The two actions illustrated the challenge of trying to ensure the equity of retroactively billing customers, the magnitude of the debts involved and the complexity of determining amounts to be billed and reimbursed under Tariff attachment Z2, which details how sponsors that fund network upgrades can receive reimbursements. Staff has identified $848.8 million in assigned costs from 158 creditable upgrade projects.

Paul Suskie (RTO Insider) - SPP Approves Z2 Timeline Extension, Creates Task Force for Further Study
SPP’s Paul Suskie leads Z2 discussion during July 16 board meeting © RTO Insider

The board and members unanimously approved the Markets and Operations Policy Committee’s earlier recommendation to extend the Z2 payment timeline from 10 months to five years and dismissed waiver requests previously rejected by the MOPC. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

Stakeholders also agreed to a suggestion by SPP CEO Nick Brown and directors Phyllis Bernard and Larry Altenbaumer directing MOPC Chairman Noman Williams to assemble a task force to find “a more rounded solution to this problem,” as board Chairman Jim Eckelberger put it.

The actions all but ensure there will be an additional recalculation of Z2 credits and bills in the near future.

“Does that mean there’s a round two coming? I believe it does,” Eckelberger said. “We’ve got to find a way to be as inclusive and equitable as [the process] can be. We need to get this right.”

The agreement short-circuited another contentious discussion on an issue that dates back to 2008, when SPP was to have begun crediting and billing customers for system upgrades in accordance with attachment Z2. Years of incorrectly applied credits have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.

“We feel we are owed a significant amount of credits … our concern is the same it’s always been,” said NextEra Energy Resources’ Mark Tourangeau, echoing comments by other members waiting on credit payments. “I would urge the board and all the stakeholders to think about equity from the folks who have to pay upgrade costs, the folks who are due credits and the folks who have to go back” and ask for payments.

“It’s fair to say that when we signed service agreements, there was no indication the charges would be as high as what they are. The fact [that] the payment plan was recently extended shows the board didn’t know either,” said Stuart Solomon, COO of American Electric Power’s Public Service Company of Oklahoma. “So as we were making decisions to enter power purchase agreements, we weren’t making informed decisions. Every indication we had at that time was the costs wouldn’t be at this level, as we were signing service agreements that didn’t reflect all of these creditable upgrades.”

“I feel like the red flag on the rope in a tug of war,” SPP Director Bruce Scherr said. “There are compelling arguments on both sides, but I haven’t moved. It leaves me really uneasy about how to vote.”

“Our primary concern is … what did we know, and when did we know it?” said Les Evans of Kansas Electric Power Cooperative. “Frankly, going forward, I have concerns about how to do business with SPP as a customer. I signed a contract saying I have no direct assigned costs. Four years later, I have a bill for $6 million.”

SPP staff agreed that customers should not be obligated to pay Z2 costs for resources that were not designated in the agreements before service began. Staff also said that sponsored upgrade costs should be allocated based on rules in effect at the time a credit payment obligation is assigned, rather than the rules in effect when an upgrade became creditable.

Staff is working to provide historical billing results for stakeholder review before the October MOPC meeting. The first invoices are scheduled to go out in early November.

Southern California Edison Preparing for Distributed Energy Future

By Robert Mullin

Edison International is maneuvering to capitalize on California’s effort to meet its greenhouse gas emissions goals and encourage the use of distributed energy resources.

The 2018-2019 rate case for subsidiary Southern California Edison will include a capital spending request “designed to help California achieve its low-carbon policy objectives and to enable customer choice,” Edison CEO Ted Craver said during a call with investors last week.

Edison’s second-quarter profits fell 27% to $276 million, in part because year-ago earnings reflected a $100 million income tax benefit.

The second quarter of 2015 also included revenue SCE later refunded to ratepayers after a delayed ruling from state regulators on its 2015 rate case.

As a result, the company said, any comparison between the two quarters was “not meaningful.”

Craver said SCE’s rate base is projected to grow 7% over 2016-2017 based on capital spending approved by the California Public Utilities Commission and expected spending on FERC-jurisdictional transmission projects.

While the company expects “relatively little variance” in the timing of its spending on CPUC-jurisdictional projects, it could experience some “variability” in the timing for its FERC projects, which Craver attributed to delays in routing decisions and state and federal permitting approvals.

“A recent example was the $1.1 billion West of Devers project, which has been something of a moving target with CPUC staff — even with CAISO support — but appears ready for final CPUC approval with a supportive alternate proposed decision pending,” Craver said.

Project delays could defer some spending planned for 2017 to subsequent years, he said, but SCE does expect to complete major transmission projects linking the utility’s service territory with renewable generation located farther inland.

Edison anticipates a future shaped by 2015 legislation that seeks to use the grid to help meet the state’s carbon reductions goals, including reducing vehicle emissions through electrification of the fleet. One byproduct of that law is a current CPUC proceeding that seeks to direct utility investment to facilitate the wider adoption of DER.

In response, capital expenditures will be “lumped into two buckets” in the rate case SCE intends to file with the CPUC on Sept. 1.

The first bucket will consist of “traditional” investments, such as replacing aging infrastructure, adding new customer connections, upgrading information technology and maintaining SCE’s generators. The second will reflect investments in the modernization of the utility’s distribution system to facilitate the growth of DER.

Craver said the CPUC has “provided only some early direction on preferred technologies and required investments” for modernization.

Through its upcoming rate case, SCE will be the first utility “to provide specificity for how this technology evolution should unfold,” Craver said.

While Craver said he wouldn’t divulge details ahead of the filing, he noted that some of the utility’s modernization investments amounted to reinforcing the existing system, such as upgrading low-voltage circuits to accommodate increasing amounts of DER.

“But other parts really have no precedent, and therefore we do not know how to handicap how much of our request might finally be approved,” Craver said.

‘Transformative’ Still the Apt Description for New York REV

By William Opalka

NEW YORK — Speakers at Infocast’s 2nd NY Energy REVolution Summit last week pondered how New York’s Reforming the Energy Vision could deliver on its promise of cleaner and more distributed generation, with persistent low power prices.

The challenge is introducing transformative changes in an environment of already record-low prices, changes that would reduce margins for market participants while also requiring massive investments.

Schwartz © RTO Insider - new york reforming the energy vision
Schwartz © RTO Insider

“The state of New York has embarked on two significant transformative issues simultaneously: the Clean Energy Standard driving toward 50% renewables [by 2030] and REV,” Michael Schwartz, CEO of advisory firm New Wave Energy Capital Partners, said during a panel discussion on the latest developments of REV. “If I have seen in the past the potential for stranded investment, this is it. If we’re going to achieve the CES, the state is going to [need to] create incentives for market signals to drive the construction of utility-scale renewables at the same time we’re driving down demand and moving [generation] behind the meter.”

Schwartz said regulators will somehow need to reconcile the initiatives.

“The fundamental change to move from cost-of-service to market-based [utility earnings] is conflicted with maintaining the financial integrity of electric utilities,” he said.

Utilities, while understanding the imperative to revamp their generation fleets, maintain infrastructure and preserve their financial viability, are wary, he added.

“Based on discussions I’ve had, the consensus in other jurisdictions is ‘we’re not doing that,’” Schwartz said.

DeCotis © RTO Insider - new york reforming the energy vision
DeCotis © RTO Insider

New York is moving ahead on another legally uncertain path to create financial incentives for its struggling nuclear fleet until large-scale renewables are built to take their place. On Monday, the New York Public Service Commission approved a zero-emission credit for nuclear plants, at a projected cost of $7.6 billion over 12 years. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)

A proposal earlier this year based the ZEC subsidy on the difference between the cost-of-service from the nuclear plants and the wholesale power prices in NYISO. A PSC staff proposal in July changed the formula to align with EPA’s calculation of the social cost of carbon. Generation owners, customers and some environmentalists object.

David-Applebaum,-NYPA-web - new york reforming the energy vision
Appelbaum © RTO Insider

David Appelbaum, an attorney for the New York Power Authority, said the change was the result of the U.S. Supreme Court’s April decision in Hughes v. Talen, in which the court voided Maryland’s attempt to incent generation by using a contract for differences related to the PJM capacity market. (See Supreme Court Rejects MD Subsidy for CPV Plant.)

“The order has changed significantly. Before the change, it would have been open to challenge in the context of the [Hughes] decision,” Appelbaum said. “It’s less so, but there’s still risk.”

Whatever the eventual outcome, New York has gotten ahead of many places as it embarks on REV.

Gallagher © <em>RTO Insider</em>
Gallagher © RTO Insider

“Once you start looking at the regulatory paradigm, regulation was not intended to support this vision. Regulation is still cost-of-service-based,” said Paul DeCotis, a senior director at West Monroe Partners and panel moderator.

However, Jim Gallagher, executive director of the New York State Smart Grid Consortium, said the model is still relevant for now.

“We need to remember that utility cost-of-service regulation is still going to provide 96% of utility revenues for the foreseeable future and these initiatives are going to provide less than 4%,” he concluded.

MISO Informational Forum Briefs

CARMEL, Ind. — Increased natural gas prices and congestion in MISO South boosted energy prices 23% in June, according to the RTO. Day-ahead energy prices in June averaged $27.36/MWh; the real-time average price followed closely at $27.42/MWh.

MISO also reported that above normal temperatures in June drove the average load to 83.1 GW, a 3.5% increase in a year-over-year comparison. Load peaked at 112.5 GW on June 20.

“We did see above normal temperatures generally throughout the region, throughout most of the month, and we did issue several hot weather alerts in different parts of the footprint on various days,” Vice President of System Operations Todd Ramey said during a July 26 Informational Forum.

Ramey also said MISO tested its new emergency pricing structure on July 21 during a three-hour maximum generation event. Ramey said a Detroit-area thunderstorm and market participants self-deploying emergency resources upon the event declaration reduced peak load by “a couple thousand megawatts,” which resulted in “plenty of supply cushion as [MISO] moved across the peak that day.” MISO’s peak on the day was 121,000 MW, below the forecasted 126,000 MW.

A review by MISO’s pricing team of the emergency event uncovered a software logic error that required a fix from the vendor, Ramey said. MISO will review the event and post recalculated real-time prices for July 21 before the Aug. 2 Market Subcommittee meeting, at which RTO officials will explain the issue and the correction, he said. The RTO rolled out the new emergency pricing structure on July 1. (See “MISO to Set Two Emergency Pricing Offer Floors,” MISO Market Subcommittee Briefs.)

MISO System Wide DA & RT LMPs (MISO) - informational forum briefs

Ramey also said MISO plans to present its response to the eight new recommendations in the Independent Market Monitor’s State of the Market report at the September meeting of the Markets Committee of the Board of Directors. (See Monitor’s State of the Market Report Seeks Changes to MISO ELMP.) In the meantime, he said, the RTO is working with Monitor David Patton “to make sure we understand all of the new recommendations.”

MISO Asks Members to Consider Bylaw Changes

MISO is considering reducing or eliminating the service prohibition on members of its Board of Directors in revisions to its Transmission Owners Agreement and Bylaws.

Deputy General Counsel Eric Stephens said the RTO is considering “less onerous” restrictions on the directors, who currently have two-year pre- and post-service prohibitions from utility and wholesale energy market participants. Stephens said the rule could be eliminated or reduced to either one-year pre- and post-service prohibitions or a one-year pre-service prohibition and no post-service prohibition.

Easing the restrictions would improve director recruiting and be more consistent with other RTOs, Stephens said. Seats currently occupied by Chair Judy Walsh and members J. Michael Evans and Paul Feldman are up for election this year.

Other bylaw revisions could mean that MISO would no longer be required to hold its annual meeting on the second Thursday of December. The RTO also is considering holding board elections — currently held at the annual meeting — earlier to ensure consistency with the new board meeting schedule. The slate would be announced in September, with results announced as early as the Oct. 25 Informational Forum.

Another revision would clarify that a majority of the directors constitutes a quorum for calling a meeting or tallying a vote.

Stephens said MISO also is seeking to change the invoicing of the $1,000 annual membership fee from the current Jan. 1 to dates tied to the time of year each member joined.

The bylaw changes were suggested by MISO’s Corporate Governance and Strategic Planning Committee. Stephens said none of the revisions would impact transmission owner rights or obligations.

MISO is seeking stakeholder feedback on the proposed changes by Aug. 15. If stakeholders are in accord, the RTO could file revisions by the fourth quarter.

EPA Official Makes Case for CPP

Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, made a case for the Clean Power Plan, saying MISO’s comments to the agency were “incredibly constructive.”

She also expressed confidence that the rule will survive legal challenges. Oral arguments on the challenge are scheduled before the D.C. Circuit Court of Appeals for Sept. 27.

EPA is accepting comments until Sept. 2 on its Clean Energy Incentive Program (CEIP), an optional early-action program that would help states meet their CPP emission targets through incentives for investment in demand-side energy efficiency and solar power generation in low-income communities. The program also encourages early investment in non-emitting wind, solar, geothermal and hydropower generation.

MISO Executive Director of External Affairs Kari Bennett said MISO and PJM plan to conduct a joint impact study on the CPP during the second half of this year. MISO stakeholders have asked for a similar study with SPP.

ARPA-E Program Director: Research Collaboration Discussion to Take Place at Symposium

Tim Heidel, program director of the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E), previewed MISO’s Aug. 18-19 Market Symposium, which will focus on technology partnerships among researchers, startups and RTO stakeholders. Heidel will be a panelist at the session in Indianapolis. (See Energy Department’s ARPA-E to Join MISO for First-Ever Market Symposium.)

— Amanda Durish Cook

Overheard at Infocast’s 2nd NY Energy REVolution Summit

The New York State Energy Research and Development Authority is now the lead agency backing a proposed 90-MW offshore wind development south of Long Island. “Offshore wind is clearly a critical part to achieving Gov. [Andrew] Cuomo’s clean energy agenda of achieving 50% by 2030. The numbers offshore are huge, with us talking about 38 GW of potential near the downstate load centers,” NYSERDA CEO John Rhodes said.

Rhodes © RTO Insider</em
Rhodes © RTO Insider

Jamie Resor, CEO of solar project developer groSolar, said his peers need certainty, and a commitment from policymakers could be more valuable than a better credit rating for a project in a state where the likelihood of a failed deal may be higher. “New York surely is not the least expensive place to do business, and it certainly is not the sunniest … but you’re in a state that has big goals, and we have a [committed] partner, and while we’re not certain how we’re going to [reach those goals], we know that somehow we’re going to figure it out,” he said.

Jamie-Resor,-Grosolar-web
Resor © RTO Insider

Doug McMahon, vice president of strategy for the New York Power Authority, said the Reforming the Energy Vision promise of customer-centric engagement between energy consumers and utilities has been slow to develop.

“We’re in for an interesting year, when we’ll have a clearer understanding if there are going to be long-term successes with REV,” McMahon said. “There is increasing frustration in the amount of progress that’s being made. The substance of REV is development of market forces, and at the moment, those forces aren’t strong enough to animate the consumer or the utility into integrated action. Until we see those forces become stronger, we’re not going to see a great deal of momentum.”

Doug-McMahon,-NYPA-web
McMahon © RTO Insider

Craig Lewis is executive director of the Clean Coalition, a nonprofit promoting a modernized grid to hasten the integration of renewable energy. He said failing to understand the way distributed wind, solar or storage add value to the system — in providing reactive power or resiliency to benefit system performance, for example — creates challenges.

Craig-Lewis,-Clean-Coalition-web
Lewis © RTO Insider

“If you don’t understand how these resources are going to work together, there’s no possible way you can optimize them from a policymaker’s standpoint. You cannot go forward and design a market mechanism” that incentivizes participation, he added.

Mike DeSocio, senior manager of market design at NYISO, said the ISO is working on a distributed energy resources roadmap in order to determine how they affect the wholesale market.

Mike-DeSocio,-NYISO-web
DeSocio © RTO Insider

“The questions we are trying to answer are: How do these resources interact with the ISO? What services can these resources provide, and what kind of configurations and uses are we thinking about to utilize these resources? … It’s going to be a little bit of a journey, so the way the ISO is thinking about this is in small stages of three to five years. We’re not trying to project out 20 years.”