Page 1337 – RTO Insider

March 14, 2017

Microgrid Kool-Aid and National Security

By Steve Huntoon

The microgrid Kool-Aid keeps gushing out of the firehose. I wrote a while back about why microgrids are an irrational throwback to the utility islands of the late 19th century.[1]

In a nutshell, microgrids cannot improve on the efficiency of centralized, least-cost dispatch. And in terms of adding reliability, authoritative case studies by the New York State Energy Research and Development Authority found that microgrids would make sense only if annual customer outage time was measured in weeks, rather than the reality of a couple hours.

Yet microgrid proposals continue to proliferate. Especially where subsidized with Other People’s Money.[2]

This column focuses on a microgrid study involving our military bases.[3] This is important not only because taxpayer money is involved, but because our national security is involved.

This study, by a consultancy called Noblis, with assistance from ICF, concludes that replacing backup diesel generators at individual military buildings (the status quo) with diesel/natural gas microgrids at military bases would save money. Their concept is shown in the study’s Figures 4 and 5.

The study includes an incredible amount of modeling and data, no doubt costing its sponsor, Pew Charitable Trusts, a ton of money.

Yet the study is profoundly wrong. The profound error is shown by this “Ownership of infrastructure” pie chart from a Government Accountability Office study,[4] showing who owns the infrastructure responsible for significant outages.

You can see that 87% of outages on military facilities arise on the military’s own distribution systems. Microgrid generation would be dependent on these distribution systems to deliver electricity to individual buildings. Thus, microgrids would cause individual buildings to lose backup for 87% of outages — eliminating the vast bulk of backup.

How could such a profound error be made? The study wrongly assumed that distribution system outages aren’t significant, saying: “Although inside-the-fence problems account for some (unknown) share of all outages, on-base problems can generally be solved through improved maintenance of the base and straightforward investments (e.g., keeping trees trimmed and putting wires underground).”

Instead, on-base problems account for 87% of all outages.[5] And if they were easily avoided, they would be.

In Rumsfeldian parlance, on-base problems are not a “known unknown,” but instead are a “known known.” The study’s profound error was not recognizing this known known.

And another important national security consideration: cybersecurity. The Noblis study talks a lot about cybersecurity, but nowhere does it acknowledge that for microgrids to function as intended, they must have communications links with the greater grid, exposing them to the same cyber risks as the rest of the grid. Backup generators at individual buildings do not need any communication link outside the building.[6]

Beyond these two vital national security considerations, please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.

The study goes through a lot of hypothetical numbers to come up with a capital cost of $17.4 million for a hypothetical microgrid of 24 MW, which works out to $725/kW.

Problem: The Defense Department’s most recent microgrid project at Marine Corps Air Station Miramar in San Diego cost $20 million for 7 MW.[7] That works out to $2,857/kW, which is about 400% of the study’s cost estimate. The study mentions the Miramar microgrid but somehow doesn’t connect the dots to its project cost.

An ounce of fact is worth a pound of hypothetical.

And speaking of fact, the nation’s “flagship” microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.[8]

You can’t make this stuff up.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

[1] http://energy-counsel.com/docs/Microgrids-Wheres-the-Beef-Fortnightly-November2015.pdf.

[2] Not all the news is bad. Pennsylvania’s consumer advocates got PECO Energy to abandon a $35 million microgrid dalliance, and it appears hundreds of millions for Commonwealth Edison microgrids got cut from the Illinois Future Energy Jobs Act, approved in December, which provides zero-emission credits for Exelon’s nuclear generators.

[3] http://noblis.org/media/b6a465e0-4200-42d8-9377-5f20251e52c0/docs/Environment/Power%20Begins%20at%20Home-%20Noblis%20Website%20Version_pdf.

[4] http://www.gao.gov/assets/680/671583.pdf. Figure 3: Disruptions lasting eight hours or longer in fiscal years 2012-14 as reported to GAO by 18 Defense Department installations inside and outside the continental U.S. The data include wastewater and potable water disruptions, but the vast majority of the disruptions are electric.

[5] This is consistent with outage causation outside of military facilities. About 90% are attributed to the distribution system, as opposed to the higher voltage transmission system. See http://www.eei.org/issuesandpolicy/electricreliability/undergrounding/documents/undergroundreport.pdf, Figure 3.3. (Compare the customer interruptions on the combined transmission/distribution system to interruptions on the distribution system alone). One driver of this is that the transmission system is designed with redundancy, so that if one element (a transmission line, a transformer, etc.) fails, there is no loss of service. The distribution system generally is not designed with such redundancy.

[6] Individual backup generators also would seem less vulnerable to electromagnetic pulses (EMPs) because they are simpler, not connected to the grid, and do not operate unless there is an outage. Noblis says that EMPs are “beyond the scope of this report” (footnote 10), which begs the question: “Why?”

[7] https://microgridknowledge.com/military-microgrid-projects/.

[8] http://www.eenews.net/stories/1059996047 (“The university’s two 13.5-MW Trident turbines were running full-bore when power from the utility abruptly went dead. With no time to shed their load, the turbines also shut down, and the campus lost electricity.”)

March 14, 2017

MISO to Fix Recently Discovered Tariff Mistake

By Amanda Durish Cook

CARMEL, Ind. — MISO will file with FERC to correct a recently uncovered eight-year-old Tariff mistake related to the RTO’s day-ahead margin assurance payment.

The RTO has found that Module C of its Tariff contains language saying that any resource that incurs an excessive or deficient energy deployment charge during one hour will be “ineligible for [day-ahead margin assurance payment] in that hour and all remaining hours in the day-ahead transmission provider commitment period.”

day-ahead margin assurance miso tariff — Page from MISO Module C Tariff | *MISO*

The problem: MISO prohibits the receipt of the day-ahead margin assurance payment only for the hour in which the resource incurred the charge; it does not observe an hours-long disqualification. The Business Practice Manuals limit payment ineligibility to the single hour the charge was incurred. A longer disqualification would restrict dispatch flexibility, the RTO said.

Despite the discrepancy between the Tariff and manuals, settlements have reflected guidelines in the latter since the beginning of MISO’s ancillary services market in 2009, said Jeff Bladen, executive director of market design. The erroneous language does not represent current or historical practice, Bladen said, and the error is not repeated in BPM language or MISO training manuals.

“The practice described in the Tariff was neither the intended method nor has it ever been used by MISO before or since 2009,” Bladen said at a March 9 Market Subcommittee meeting.

MISO will submit a Section 205 filing with FERC to remove the Tariff language and payment eligibility will carry on as usual, Bladen said.

“MISO immediately reported the issue to the FERC Office of Enforcement,” Bladen said. The error was uncovered during “unrelated” Tariff research.

Bladen said neither MISO nor its Market Monitor support resettlements, and no gaming was discovered.

David Sapper of Customized Energy Solutions asked what efforts the RTO could make in the future to catch Tariff errors.

“We are regularly undertaking compliance reviews. … We are subject to FERC compliance reviews,” Bladen said. “The level of obscurity of this Tariff language is evidenced by the fact that this wasn’t uncovered during those reviews.”

March 14, 2017

Overheard at NECA Renewable Energy Conference

AUBURNDALE, Mass. — About 200 people attended the snow-delayed Northeast Energy and Commerce Association Renewable Energy Conference on March 6. Here’s some of what we heard at the conference, which was rescheduled after a February snowstorm forced cancellation of the original date.

Offshore Wind

Offshore wind was a frequent topic in the opening session on emerging trends in renewables, which featured Matthew Morrissey, vice president of Massachusetts operations for Deepwater Wind.

NECA renewable energy conference — Morrissey (L) and Fioravanti | © *RTO Insider*

The company, which began operating the nation’s first ocean-based turbines off of Block Island, R.I., in December, won a contract from the Long Island Power Authority in January for a 90-MW wind farm off the island’s Southern Fork. It also hopes to grab a piece of the big prizes to come: Massachusetts and New York have set goals for a combined 4 GW of offshore wind by 2030.

Unlike in Europe, which has a mature offshore industry, the U.S. does not have a fully developed supply chain for developers. Thus, Morrissey said, his company has been tapping the expertise and supply chains of offshore oil and gas drillers.

“There is a lot of commonality between the expertise and innovation that the United States has developed in that industry — putting large structures in the water — and we wanted to tap that both for our benefit but also because … we have to keep costs coming down, and in order to do that you have to have local, stateside … manufacturing,” he said.

Morrissey and fellow panelist Richard Fioravanti, a principal with engineering and scientific consulting firm Exponent, said they were not overly concerned about the federal government reducing its role in energy research under the Trump administration.

“I see [renewable power] as a large, growing opportunity, and when there are opportunities, money follows,” Fioravanti said.

“I would say that 10 years ago, a slowdown in research would have been a problem,” Morrissey said. “But for the 10 or 15 or 20 years, the industry giants — like Siemens and General Electric and Vestas — [will be] driving innovation from a blade design point of view. And a lot of the foundation work they’ve done in the last 20 years — both in the U.S. oil and gas industry as well as the European offshore wind — with fixed bottom foundations, will drive the growth and cost curve downward … regardless of R&D coming out of Washington.”

Morrissey said the offshore industry also can seek support in D.C. by touting its job creation potential.

“When you look at the kind of places with offshore wind-created economic opportunity, those places tend to look like post-industrial, urban forgotten cities like Fall River or New Bedford [Mass.] or other cities like that along the Atlantic seaboard, which actually tend demographically to look a lot like southern Ohio or western Pennsylvania [where Trump did well in the November election]. So we think that there is an underlay of opportunity to talk to the Trump administration about.”

New England’s Duck Curve

Michael Giaimo, senior external affairs representative for ISO-NE, used “duck curve” slides to demonstrate how growing solar photovoltaic penetration is affecting the RTO’s ramps and system peaks. The RTO had 1.9 GW of behind-the-meter solar PV as of the end of 2016, more than two-thirds of it in Massachusetts.

While increasing PV boosts the need for ramping capability during the daylight, it does not affect the system peak in the winter, which typically occurs at about 7 p.m.

But PV generation could begin causing minimum generation emergencies in spring afternoons once PV generation reaches 3 GW, the slides showed. In the summer, increasing amounts of PV will push the net load peak later in the day, from 5 p.m. at current penetration, to 6 p.m. once penetration reaches 3 GW and 7 p.m. at 6 GW or higher.

“The low demand on a normal traditional day is like in the 3 a.m. timeframe,” Giaimo explained. “When you start getting about 3,000 or 4,000 MW of solar, our new low demand for the day happens about 3 in the afternoon. We [are going] from a system that had a low at 3 a.m. to now a system that has a low at 3 p.m.”

A Handful of States Writing the Rules on Community Solar

Eric Graber-Lopez, president of BlueWave Capital, talked about the delayed promise of community solar, noting that solar power adoptions still retain a “barbell” shape, with more than 90% of the market in residential rooftop panels or utility-scale facilities.

Legislative and regulatory debates, net metering capacity limits, program transitions and interconnection problems “have pushed back the promise of community solar,” Graber-Lopez said. “The U.S. installed about half of what it expected to install in 2015, and it was expected to install about two-thirds [of earlier estimates] in 2016.”

Community solar — which Graber-Lopez argues is a “proxy” for distributed generation in states such as Massachusetts — provides a way for renters, apartment dwellers and low-income housing residents to participate. “The problem is there’s no such thing as a DG industry. It varies state by state,” he said.

Massachusetts has been number two to California in DG deployment every year since 2014. Massachusetts, Colorado, Minnesota and New York account for 97% of the national pipeline for community solar over the next five to six years, he said.

“So there’s a lot of talk about the deployment of DG — and by extension the deployment of community solar — but the fact is that there are four states that are setting the standard for how this industry is going to look going forward,” he said.

Another 10 states are pursuing regulations or legislation “trying to either create, stop, modify or enhance DG,” he said.

Ex-DOE Official Hopes Climate Progress is in Economy’s ‘DNA’

In a keynote speech, Kevin Knobloch, chief of staff for the U.S. Department of Energy between 2013 and 2017, said the Trump administration may not do as much to reverse Obama-era climate policies as some fear.

President Trump and EPA Administrator Scott Pruitt, who have expressed skepticism over humanity’s role in global warming, are expected to attempt to cancel the Clean Power Plan. Trump also may withdraw the U.S. from the Paris Agreement on climate change.

But Knobloch, a former president of the Union of Concerned Scientists, said the renewable energy gains made during Obama’s term won’t be reversed.

“The Department of Energy’s early and robust investment in clean energy and low-carbon technologies, with similar investments by industry and the research universities, coupled with forward-leaning and clear public policies, have contributed to dramatic cost reductions and increased deployment of clean energy and ultra-efficient technologies,” Knobloch said. “And clean energy companies, like many of you represented here in this room, are consequently … well positioned to lead and compete in the rapidly emerging multi-trillion-dollar market for clean energy technologies.”

He noted that 195 countries signed the Paris Agreement to reduce their carbon emissions. That’s “195 markets for clean energy, renewable energy,” he said.

Knobloch said the dramatic budget cuts proposed by Trump to EPA and other domestic agencies to fund Defense Department increases would require undoing Congress’ sequestration rules.

He also noted that Congress’ last two major energy bills — the Energy Policy Act of 2005, which authorized loan guarantees for greenhouse gas control technologies and tax credits for alternative energy producers, and the 2007 Energy Independence and Security Act, which updated energy efficiency standards for appliances, residential boilers and other equipment — were approved with bipartisan support. He predicted Republicans such as Sen. Charles Grassley (R-Iowa) would fight any early termination of the wind production tax credit, which is due to be phased out over three years, ending after 2019.

“We also know that it is not so easy to reverse rules like the Clean Power Plan or the energy efficiency rules … with their extensive … rounds of formal public comment periods, prospects of legal challenge. These are all designed on the foundation of laws that were directed by the Congress.

“My hope is having achieved or made dramatic progress toward a lot of those goals, that renewable energy, energy efficiency … is now in the DNA of the economy,” he said. “Those jobs are real. Those tax payments are real. The business plans and technology investments are all real and that that will carry on.”

Lack of Tx in Multistate RFP Puzzles Developer

About 900 of New England’s 1,300 MW of wind is in Maine. But the resources can’t fully access the markets because of insufficient transmission. So Stephen Conant, senior vice president of Anbaric Transmission, said that he was mystified when officials running a clean energy solicitation for Connecticut, Rhode Island and Massachusetts included no transmission projects in their shortlist of projects last October.

Anbaric had proposed a project to unlock Maine’s bottleneck and another project to deliver New York wind power and Canadian hydropower into Vermont. (See New England States Move Toward Renewables Contracts.)

“There’s all kinds of theories out there,” Conant said during a panel on the role of transmission and energy storage in integrating renewables, when asked to explain why his and other transmission projects were shut out. “We’re all sort of scratching our heads.”

Also in that session, Dan Berwick, general manager of the energy storage division at Borrego Solar Systems, said he was not dismayed by the limitations of current battery technology, which remains expensive for many large-scale, long-term storage applications.

“I’m pretty convinced we don’t need a technological breakthrough right now — that the reductions in cost and the improvement in quality and performance that we’re going to see through increasing repetitions and scale is capable of delivering a four- or five-fold decrease in … cost.”

– Rich Heidorn Jr.

March 14, 2017

PJM Fuel-Cost Policy Changes to Take Effect in May

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM expects to implement its new fuel-cost policy rules on May 15, PJM’s Jeff Schmitt told the Market Implementation Committee last week. That would require generators to file any policy changes by March 15 to guarantee approval before the transition date.

PJM fuel-cost policy — Schmitt | © *RTO Insider*

Despite its looming implementation, the new rules continue to raise substantial questioning from stakeholders, which PJM is attempting to address with a FAQ document.

On Feb. 3, FERC largely accepted PJM’s proposed rule changes, siding with the RTO in requiring that policies be verifiable and systematic but not algorithmic, as Monitoring Analytics, the Independent Market Monitor, had proposed. (See FERC Seeks More Details on PJM Fuel-Cost Policy Proposal.)

The Monitor said the policies should be based on a simple average of broker quotes, bilateral offers or a weighted average index price posted on the Intercontinental Exchange (ICE) trading platform. The commission said the Monitor’s insistence that policies be “algorithmic under all circumstances” ignores how natural gas markets operate during stressed conditions that may make them illiquid, potentially understating generators’ real costs.

The Monitor contends the term “algorithmic” is misunderstood by PJM and by FERC. Algorithmic simply means a step-by-step process to get from a defined input to an output; it is therefore virtually impossible to have a verifiable policy that is not also algorithmic, it says.

Schmitt, the manager of market analysis, said PJM’s verification documents the steps taken daily to develop cost-based offers that do not change based on variables. He walked through the documents necessary for an approved policy, including filing a numerical example for each cost-based offer, likely on a spreadsheet, in the Monitor’s Member Information Reporting Application. While generators’ decisions won’t be challenged during the policy review, it’s critical for them to note whether they include emissions and variable operations and maintenance in their offers, he said. The Monitor has required a numerical example for all approved fuel-cost policies for more than two years.

Stakeholders expressed concern that the rules for dual-fuel generators appeared to not allow the flexibility to switch between fuels as desired, essentially requiring a forced outage. PJM and the Monitor said that the preferred resolution would be to create a cost-based offer for each fuel type.

FERC made “a pretty strong statement” on the separate fuel-type offers, and that “flies in the face of only needing one cost-based offer for dual-fuel units,” said Catherine Tyler Mooney of Monitoring Analytics.

“If we commit you on a gas schedule, and you run on oil, that risk exposure is 100% yours,” said Adam Keech, PJM executive director of market operations. “Our intention is not to put you on a forced outage when you have fuel.”

As long as a generator has an approved cost-based offer, “we think [it] should be able to switch as needed based on physical requirements,” Monitor Joe Bowring said.

PJM and the Monitor also addressed ongoing questions about their relationship in approving policies. The sides appeared to have settled their differences, as the tone of their comments were markedly less confrontational than they had been at recent meetings. (See Stakeholders Caught in PJM-IMM Dispute over Fuel-Cost Policy.)

“Once we’ve been through reviewing the policies, it makes it easier for PJM,” Bowring said. “I can’t think of one we’ve approved that PJM hasn’t approved. … It’s proven efficient to go through us first.”

“It’s been helpful for PJM folks to be in listening mode during the IMM negotiations,” said Stu Bresler, PJM senior vice president of operations and markets.

However, the Monitor’s late submittal of proposed revisions in Manual 15 regarding its role in the policy-review process created some heartburn among stakeholders. Before the agenda had even been discussed at the beginning of the meeting, Gary Greiner, director of PJM market policy at Public Service Enterprise Group, questioned why the Monitor had been allowed to file such a late addition. Bowring responded that when his group must respond to late filings, it becomes impossible to avoid filing them late himself.

Mooney explained that the Monitor’s proposed changes would enunciate the separation between it and PJM in the approval process.

“Working together is happening, but it should be clear that the reviews are separate,” she said.

Bob O’Connell of Panda Power Funds questioned why the Monitor elected to propose that it “may” provide its recommendation regarding policy approval to PJM in writing. He requested that it be changed to “shall.”

“Not having that recommendation in writing is troublesome,” he said.

Bowring responded that the Monitor plans to provide its recommendations in writing and that it is always very clear with market participants about issues with fuel-cost policies.

March 14, 2017

MISO Market Subcommittee Briefs

CARMEL, Ind. — MISO will make two changes to improve its year-old emergency pricing structure by this summer in addition to the two emergency pricing floors rolled out last year, RTO staff said during a March 9 Market Subcommittee meeting.

The first change: Commitment costs of offline fast-start units will be allocated into the minimum runtime when calculating the offer floor for emergency prices.

day-ahead margin assurance payment miso market subcommittee — Akinbode | © *RTO Insider*

The second: Emergency-committed units dispatched at their economic minimum prices will be allowed to set those emergency prices.

The two changes were the only selected among the five proposed by MISO staff after a July 2016 emergency event resulted in depressed prices. (See “MISO May Tweak Emergency Pricing Floors,” MISO Market Subcommittee Briefs.)

MISO engineer Oluwaseyi Akinbode said the modifications are meant to produce more efficient prices.

“If you believe what the planners are saying, there’s a chance we will get into these emergency conditions this summer, and we want to be prepared for that,” Akinbode said.

New User Group Aims to Improve Ease-of-Use in MISO Apps

MISO will later this month debut a new Application User Group for people who use the RTO’s technology.

April Peterson, a representative from MISO’s asset registration team, said the group will focus on improvements and common challenges market participants face when using the RTO’s computer market applications. She said attendance is also open to MISO software vendors and IT specialists that are contracted to make software changes.

Peterson said MISO aims to hold conference calls monthly, with the first call scheduled for March 23.

Potential Cost Recovery Gap in Manual Redispatch

Day-ahead resources can see gaps in cost recovery when they are manually redispatched offline — and a Tariff change could remedy the problem, MISO staff said.

When the RTO decommits a day-ahead resource, the day-ahead margin assurance payment does not take into account the resource’s minimum down times or start-up costs for reimbursement, said Jason Howard, MISO market quality manager.

Howard said yet-to-be-written Tariff language could “close the gap.”

“The manual redispatch might only last four hours, but a minimum down time for a resource might be seven hours,” Howard explained. “Our current day-ahead margin assurance payment does not account for these situations.”

Proposed Tariff language will be presented at a future Market Subcommittee meeting.

— Amanda Durish Cook

March 14, 2017

IMAPP Pondering 4 Options for Incorporating Clean Energy in NE

By Rich Heidorn Jr.

AUBURNDALE, Mass. — Stakeholders are considering four proposals for making New England’s markets more accommodating to state clean-energy initiatives, including a carbon adder in the energy market, potential changes to the capacity market and a possible new “clean energy” market.

ISO-NE IMAPP clean energy — Doot | © *RTO Insider*

David T. Doot, counsel and secretary to the New England Power Pool, outlined the changes to about 200 attendees at the Northeast Energy and Commerce Association’s 2017 Renewable Energy Conference on March 6.

Doot said the four long-term proposals were narrowed from the 17 proposed over seven meetings of the Integrating Markets and Public Policy (IMAPP) initiative last year. Officials announced last month that IMAPP will suspend its monthly meetings until May to allow ISO-NE time to develop “a conceptual market approach” that could be implemented in the near term for “accommodate[ing] state-supported capacity resources while appropriately pricing other resources in the Forward Capacity Market.” The delay also will allow states time to analyze long-term proposals discussed to date and for them to hold “off-line” discussions with stakeholders. (See NEPOOL Extends IMAPP Timeline.)

“We at the moment are in a pause … because ISO-NE has said, ‘We have to give you something to deal with the here-and-now that we’re worried about,” Doot explained. “They’re going to come back with something for us to debate and digest in the May timeframe.”

Infancy or Unruly Teens?

Panel moderator David O’Connor, senior vice president for energy and clean technology at ML Strategies, set up the panel by describing IMAPP as a “work in progress,” adding that “by various metrics it could be described as yet being in its infancy.”

But Doot characterized the initiative as being in “the unruly teen years.”

“We’re well beyond our infancy at this point. … We get into this room [and] there’s a lot of people talking to each other, by each other, at each other — in varying levels of decibels depending on what exactly is going on.”

Proactive

Doot said it was essential that New England stakeholders be proactive in developing a solution, noting that FERC has two cases pending before it challenging zero-emission credits for nuclear generators in NYISO and PJM.

“If we — NEPOOL or New England — don’t do something, FERC is going to do it. They will do something to us or for us. And I can predict with some degree of certainty that we won’t like it,” Doot said.

“So I think what we need to do is decide whether we’re going to take the opportunity in New England to establish how we want to change the marketplace in order to help the states achieve what they’re trying to achieve in a way that allows the rest of the market to function, or whether we’re going to have FERC tell us how they’re going to do it. Because what we currently have is not necessarily sustainable in the long term.”

Ron Gerwatowski, an energy and regulatory policy consultant, formerly with National Grid, agreed on the need to eliminate what he called the current “market schizophrenia.”

“Somebody’s going to take a meat ax to this if we don’t fix it on our own,” he said.

Four Proposals Explained

Doot said the proposed carbon adder would be included in energy offers and energy clearing prices and collected from carbon emitters under an allocation to be determined.

A second alternative, proposed by the Conservation Law Foundation, calls for a “Carbon-Integrated” Forward Capacity Market (FCM-C), under which a new ZEC market would be integrated with the FCM.

A third option, offered by RENEW Northeast and NextEra Energy, is a Forward Clean Energy Market (FCEM), a new forward market for new clean energy resources. As initially proposed, the FCEM would expand to include supports for existing renewable resources.

“We’ve been moving a little bit away from that in part because the price tag is so high,” Doot said. “What they’re now talking about is a capacity clean energy market just for new [resources] but that they would allow for support of existing resources through some form of carbon pricing.”

The fourth proposal is a two-tiered pricing construct, with the FCM clearing at one price for existing resources and a lower price for state-supported resources offered at below competitive prices, an effort to protect prices from being suppressed.

‘Civil War’

Gerwatowski said one challenge is that the states are not unified in their goals, referring to “somewhat of a civil war” between the northern and southern states.

“We have some uniformity among Connecticut, Rhode Island and Massachusetts … with respect to the very aggressive goals to reduce greenhouse gas emissions. We’re in a very different place, I think, in New Hampshire and Maine — and in Vermont it’s hard to read with the new administration coming in,” Gerwatowski said, referring to Republican Gov. Phil Scott, who replaced Democrat Peter Shumlin in January.

“If you’re in the southern states, anything that’s going to drive greenhouse gas reduction, even if it comes at some costs, is going to be something that should be under consideration,” he said, referring to carbon pricing and long-term contracts for renewables.

“They have a different perspective in the north. … They’re not quite as convinced that these are the right ways to go in designing the future. We’ve heard some of the states, like New Hampshire in particular, saying, ‘Look, you guys want to do something to raise prices in order to meet your goals, that’s OK. But I’m not paying for it.’”

Capacity Market Limitations

Abigail Krich, president of Boreas Renewables, said that while New England’s capacity market has provided price signals to encourage development of natural gas generators, it is insufficient for resources such as wind. Boreas worked on the FCEM proposal as a consultant to RENEW Northeast.

A combined cycle plant that wins a seven-year capacity contract at $7/kW-month can lock in almost 60% of its overnight capital costs, and a simple cycle turbine with the same contract would lock in 70% of its capital costs — both percentages high enough to secure financing, she said.

“A wind project, even if it’s actually more cost effective overall when you look at energy, capacity, [renewable energy credits], things like that … they can only lock in about 6% of their capital costs,” she said. “You can’t take 6% of your capital costs as locked-in revenues and go get financing for a project based on that.”

That, she said, is why long-term power purchase agreements are being sought for renewables. “We need these to be financeable projects,” she said.

Jon Norman, vice president of government and regulatory affairs for Brookfield Renewable, said the current capacity market was designed primarily to support conventional fossil generation and doesn’t address a growing gap in value recognition for existing sources of non-emitting generation, including hydropower and wind projects with expiring PPAs.

“At some point there needs to be a stable price signal” for existing clean resources, he said. “In the absence of that, you … end up over the long run cycling capital through and just putting it into new resources. And then old resources are either exporting somewhere else or they’re retiring. I don’t think that’s a good outcome.”

Matt Kearns, chief development officer for Longroad Energy Partners, said that states have generally found long-term contracts the cheapest way to meet their renewable portfolio standards.

“We’ve seen the most consumer savings generated by these larger procurements. … The result has been to attract cheap capital and drive down the cost of the product to the consumer,” he said. “Sending a signal to the market for a 15-year contract, you tend to get very competitive, good results.”

What Would FERC Do?

Doot said that he has been asked whether FERC has the authority to approve market rules that incorporate carbon policy. The commission has scheduled a technical conference for May 1-2 on the energy and capacity markets in PJM, NYISO and ISO-NE.

Before President Trump’s election, Doot said, FERC was “begging us to come forward with something under our voluntary market structure that they can consider and potentially say yes to. Now, that was FERC before President Trump.”

After Trump? “There’s just no way of predicting,” Doot said.

Doot ended the session by returning to a question about how consumer advocates can ensure that ratepayers don’t “double pay” for carbon reductions through both an ISO-NE-wide carbon price and state initiatives such as renewable portfolio standards.

“The answer is ‘Show up.’ Because at the end of the day we have to come up with a solution. … If we don’t come up with a solution, I’m not sure you have an assurance that you aren’t double paying.

“It’s up to us — the marketplace — to help define how it is we’re going to address these challenges. If we don’t, the federal government and the state governments are going to do it, and I’m not sure that the marketplace is going to be happy with the outcome.”

March 14, 2017

MISO Contemplates Market Design Changes from FERC Offer Cap Rule

By Amanda Durish Cook

CARMEL, Ind. — MISO is considering how to alter its market rules to comply with a FERC order that “softens” the current energy offer cap and establishes a higher “hard” cap for cost-based offers.

One potential change: The RTO could possibly increase its maximum value of lost load (VoLL), which represents the estimated amount that firm electricity customers would be willing to pay to avoid losing service. The VoLL, established in 2005, caps LMPs at $3,500/MWh. MISO is the only RTO to enforce such a cap.

FERC MISO offer cap market design — Hansen | © *RTO Insider*

“We really should update the value of lost load,” Chuck Hansen, MISO senior market engineer, said during a March 9 Market Subcommittee meeting. “It’s been around for a decade. It’s probably time to refresh that number.”

Hansen said MISO is hoping to implement FERC’s directive by winter 2017/18, although the scope of the market changes could vary from adjusting the VoLL to ending LMP caps altogether.

Order 831 replaces the current energy offer cap of $1,000/MWh with a soft cap of $1,000 and a hard cap of $2,000 for verified cost-based incremental offers. MISO’s offer portal will be reprogrammed to automatically block all offers above $2,000/MWh, while offers between $1,000 and $2,000/MWh will be verified only after the daily market close.

A resource may qualify for uplift payments if legitimate offers above $1,000/MWh cannot be verified quickly enough. For the past three winters, FERC has granted MISO a waiver on the RTO’s energy offer cap policy. (See MISO Granted Winter Waiver on Offer Cap.)

“We have not seen offers above $1,000 yet in MISO,” said Jeff Bladen, MISO executive director of market design. “The degree to which we could see them is just too hard to predict, [but] the likelihood that we see offers above $1,000 or $2,000 — [in] my view is it’s pretty unlikely because we haven’t seen it before.”

Hansen said MISO’s Independent Market Monitor will adapt to the new offer cap by stepping up its monitoring efforts next winter, updating resource reference levels as it keeps tabs on natural gas prices throughout the day. Going forward, market participants will be able to request a consultation with the Monitor for higher reference levels. The Monitor’s Jason Fogarty said it would host a workshop later this year for market participants on the consultation process.

The Monitor’s 2017 State of the Market report will likely recommend that MISO update the VoLL cap to also reflect the “likelihood of real-time capacity loss exceeding a given reserve level,” Fogarty said.

According to Hansen, the higher energy offer cap paired with the operating reserve demand curve during scarcity conditions could easily breach the $3,500/MWh threshold.

Hansen said MISO could try to weather the higher energy cap with an updated VoLL cap and minimal Tariff changes — or undertake a major market redesign, in which the LMP cap would be abandoned in favor of a PJM-style system marginal price cap. MISO could also divorce its operating reserve demand curve from its VoLL cap, although it must be careful to keep LMPs in check, he said.

More involved market changes would “preclude a quick solution” — and MISO is hesitant to pursue a major market redesign, Hansen said. The RTO is asking market participants to submit suggestions on the issue by March 20.

March 14, 2017

PAR Wars: A Struggle for Power

By Rory D. Sweeney

A few months ago in an ISO not that far away…

Unrest grows along the PJM-NYISO border after the dismantling of the CON ED-PSEG WHEEL that for decades held sway over daily operations in the region. Expensive infrastructure replacements loom on the horizon, and stakeholders on both sides suspect the other of attempting to take advantage of the situation.

At the RAMAPO SUBSTATION, a phase angle regulator has failed, sparking a dispute between territorial transmission owners that threatens to reignite longstanding, deep-seated grudges.

As a last resort, a small group of delegates from both sides of the border have journeyed to an unassuming office complex on the outskirts of PHILADELPHIA to meet in person in the hope of averting chaos…

VALLEY FORGE, Pa. — If Friday’s joint PJM–NYISO meeting to discuss replacing a phase angle regulator (PAR) at Consolidated Edison’s Ramapo substation, near the New York-New Jersey border, had a “Star Wars”-like preamble crawling off into space, it would probably look something like that. Ok, maybe a bit less dramatic.

One of the substation’s two PARs failed in June, and Con Ed has hesitated to replace it until it receives certainty on how it will be paid for. That has been in question because the 1993 agreement signed by NYISO (then known as the New York Power Pool) and PJM transmission owners is in dispute.

The agreement covered just the original PARs at the facility, PJM transmission owners argue, neither of which remains in service. They say Con Ed’s decision in 2013 to replace the first failed PAR constituted a breach of the agreement, which requires the PJM transmission owners to be involved in the decision. Con Ed disagrees with that interpretation and believes the cost allocations under the contract — which would put PJM transmission owners who were a party to the agreement on the hook for 50% of the costs — remain in effect. However, stakeholders said that Con Ed’s reluctance to replace the failed equipment without knowing how it will be repaid doesn’t square with the company’s argument for why it replaced the first PAR after its failure in 2013, without consulting transmission owners.

“It seems like your own decision not to replace the PAR is in violation of your own interpretation of the agreement,” said Mark Younger of Hudson Energy Economics.

But before deciding on who should pay for it, some stakeholders are asking whether it needs to be replaced in the first place. In its current form, Calpine can’t support the project’s scope, company representative David “Scarp” Scarpignato said. “You really need to know what projects should be shared before you discuss sharing those costs,” he said. “The cost of paying for the PAR is not the big deal here. It’s that you’re potentially using the PAR to change the winners and losers here.”

PJM NYISO phase angle regulator — Dave Scarpignato, Calpine (foreground) and Adam Keech, PJM | © *RTO Insider*

He argued that the PAR helps alleviate congestion, which mutes the price signals on which generation companies like Calpine depend. “When you’re talking about using transmission to manage congestion rather than dispatching to address congestion, that is direct competition to generation,” he said.

Since the 1970s, operator and planners have operated under an agreement in which Con Ed wheels 1,000 MW of power through Public Service Electric and Gas’ transmission system in northern New Jersey into New York City. Con Ed announced last year that it no longer needs the service and would be canceling it as of May 1. Con Ed also canceled its membership in PJM and ended all commitments for cost allocation in the RTO, despite having been the reason for a substantial amount of now-unnecessary transmission upgrades. PJM stakeholders have taken issue with being forced to take on additional financial responsibility for maintaining infrastructure that’s no longer in use or being paid for by its intended beneficiary. (See NYISO Members OK End to Con Ed-PSEG Wheel.)

PSE&G’s Vilna Gaston asked if there had been an analysis regarding the benefits of replacing the PAR to determine if that’s even the best investment. “It seems like we’re proposing a solution before we do the investigation. This is putting the cart before the horse,” she said.

Despite their disagreements, stakeholders produced a list of objectives for a potential analysis, including ensuring the endorsed solution adheres to competitive market principles and that the cost allocation is aligned with who receives the benefits.

PARs are an expensive solution. Beyond the millions of dollars in installation costs, PARs require about $200,000/month in upkeep, PJM’s Stan Williams said. Additionally, NYISO allocates such costs through all of its load-serving entities, while in PJM, only the signatories to the original agreement would share the costs, so there is a larger group to distribute through in NYISO than in PJM.

The group’s next meeting will be on April 18 at NYISO’s offices.

[Editor’s Note: An earlier version of this article incorrectly reported that the phase angle regulators on the 5018 line at the Ramapo substation were part of the CON ED-PSEG wheeling service. The Ramapo PARs were not part of the wheel.]

March 14, 2017

MISO Resource Adequacy Subcommittee Briefs

CARMEL, Ind. — Recent preliminary load forecast data for the 2017/18 Planning Resource Auction show that each of MISO’s local resource zones has enough capacity on hand to meet its own clearing requirement.

The RTO’s 172 GW worth of total installed capacity can handily meet its 135 GW of planning reserve margin requirements, John Harmon, MISO manager of resource adequacy, said during a March 8 meeting of the Resource Adequacy Subcommittee.

A general slowdown in manufacturing and continued energy efficiency efforts across the footprint is slowing load growth and lowering peak forecasts, Harmon said.

MISO Resource Adequacy Subcommittee — Robinson | *RTO Insider*

MISO derives its load estimates from a random sampling of load-serving entities and data reviews from LSEs whose load represents 45% of the RTO’s annual peak demand, according to Michael Robinson, MISO’s principal adviser of market design.

Robinson said MISO this year encountered issues with LSEs not providing historical data, excluding methodologies for non-coincident peak and accounting for transmission losses, which the RTO already does once it receives the data. He said all LSEs eventually met the forecast reporting requirements.

“We did see a rash of LSEs that didn’t provide all the information originally,” Robinson said, suggesting the “tightening” of some documentation requirements.

Multiple stakeholders expressed concern that MISO still has 7,300 MW of unconfirmed unforced capacity a month before the auction and asked about the potential for moving up registration deadlines to get more complete data earlier — something Harmon said the RTO would consider.

Harmon said that the unforced capacity data includes about 15 generators that have applied to defer completion of their generator verification tests — which qualify resources as capacity resources or load-modifying resources — until after the 2017/18 PRA.

The RTO said that it will separately report reserve margin data from Michigan’s Local Resource Zone 7, after receiving permission from market participants there that were concerned about protecting competitive information.

Zone 7 shows a 20-GW coincident peak load and a 22-GW planning reserve margin.

Zones 3, 5 and 7 were previously grouped together, as were zones in MISO South (Arkansas’s Zone 8, Zone 9 covering Louisiana and Texas, and Mississippi’s Zone 10). Iowa’s Zone 3 and Missouri’s Zone 5 will continue to be grouped together. (See “Preliminary Load Forecast Released,” MISO Resource Adequacy Subcommittee Briefs.)

MISO will host a stakeholder call to review the results of the PRA on April 14, followed by a longer meeting on the subject April 17.

In a related matter, the deadline to seek rehearing on FERC’s order prohibiting MISO’s three-year forward auction design has passed without any parties requesting a rehearing. (See MISO Won’t Seek Rehearing on Auction Redesign.)

“MISO still believes that mechanisms are needed to support competitive retail areas,” RASC liaison Shawn McFarlane said. He added that the RTO will work with Illinois officials to develop separate capacity auction provisions for retail areas that will not affect regulated areas.

The RTO is also awaiting FERC’s decision on whether it can apply a more stringent physical withholding rule and remove some resources from market monitoring in next month’s PRA (ER17-806). (See MISO Plans Additional Capacity Auction Revamps for 2017.)

MISO attorney Jacob Krause said the RTO could implement the changes — subject to refund — prior to the auction, or that FERC could issue a deficiency letter delaying the changes until the 2018/19 PRA. The commission has until March 17 to act on the filing.

IMM Offers Own PRA External Zone Design

The Independent Market Monitor is recommending its own option for the proposed locational element to the PRA — a year after the RTO began discussing the matter.

Monitor David Patton wants the RTO to create external resource zones based on neighboring balancing authority boundaries and set a clearing price for each external zone set using a shadow price and shift factor. By comparison, MISO staff have proposed six smaller, external resource zones based on geographic groupings of generation and transmission that would be priced using sub-regional prices and clear in the PRA.

Patton’s suggestion would require MISO to quantify how much capacity would be delivered from SPP and PJM and model how the power would flow through MISO’s internal zones. He said his approach would create consistency for MISO operations even as PJM and SPP resources supply capacity.

Some stakeholders asked why an LSE would purchase from external suppliers when the price would be different from auction clearing prices.

Patton said he didn’t see a difference between an LSE contracting bilaterally to purchase power from a different MISO zone and buying megawatts from an external resource. He said he would return to the RASC next month with a more detailed proposal.

Indianapolis Power and Light’s Ted Leffler said buying externally for commercial purposes — and not for reliability — represents an “imperfect hedge.”

However, MISO staff have proposed that external zones clear the PRA at a systemwide or sub-regional clearing price — and not at their offer prices. Akshay Korad of MISO’s market design and evaluation team said the RTO’s three simultaneous feasibility tests run after the auction could limit the capacity export limit of external resource zones if constraints bind and price the external zones as a marginal resource.

MISO used its four proposed MISO Midwest (formerly MISO North) external zones and two proposed MISO South external zones to run a simulation of the 2016/17 PRA. Using the projected external zones, MISO concluded that zones 2-7 could have cleared at $24.80/MW-day, instead of the actual $72/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.)

A small number of megawatts in the 2016/17 PRA caused the capacity export limit to bind, dictating the high clearing price in zones 2-7, Korad said.

“Even if you see that supply stack change a little bit, you’re going to see a change in price,” Korad said.

The six resource zones proposed by MISO are based on external zones that cleared in the most recent auction, and the number and location of external resource zones could change, said Laura Rauch, MISO manager of resource adequacy coordination.

Stakeholders asked MISO staff to come back with more pricing simulations using external zones.

Like other stakeholders, Leffler remained critical of the entire external zone concept. He asked why MISO couldn’t require LSEs to create fixed resource adequacy plans to hit their full local clearing requirements using only local resources and forbid them from relying on external resources toward their local clearing requirement.

“There ought to be a way that’s easier to do this than create external resource zones,” he said.

MISO Examines Single Year of MISO-SPP Settlement Allocation

MISO stakeholders are questioning the benefits of debating whether some costs of MISO and SPP’s transmission use settlement be allocated to holders of transmission service requests above the 1,000-MW contract path. MISO wants to determine who gets allocated the costs for using the North-South interface for about 300 MW that went above the 1,000-MW North-South limit in 2018/19.

Stakeholders will decide if the RTO can allocate a portion of the costs of just one year of the settlement — the 2018/19 planning year — based on capacity benefits, where firm TSRs from MISO South to MISO Midwest reach 1,304 MW. In all other years of the settlement from 2014-2021, TSRs were or are 1,000 MW or below.

MISO’s Jesse Moser said the question is “narrowly focused” on capacity benefits and is not a forum for negotiating other terms of the settlement agreement.

“MISO is approaching this without a desired outcome in mind. We’re facilitating discussion,” Moser said.

Multiple stakeholders said that an effort to decide the one-year allocation within MISO’s stakeholder process might not be worth pursuing considering the low monetary amount at stake.

Per the settlement agreement, MISO has until Nov. 17 to decide on an allocation to TSR holders, either by filing to alter the terms of cost allocation or making an informational filing to explain that it won’t change allocation.

“That 1,000-MW cap should have been in place in OASIS prior to December 2013,” NRG Energy’s Tia Elliott observed dryly.

Mathis wanted to know the dollar amount at stake — something Moser said he could supply at the April RASC meeting.

The settlement dictates that costs be allocated on a graduating scale based on a ratio that phases out over time — with 100% to load in the first two years of the settlement, decreasing to 45% in the third year and 10% in the seventh year, with the remaining percentage taken on by a flow-based allocation.

MISO pays about $27 million per year for use of SPP’s transmission that links the RTO’s Midwest and South region. The maximum amount MISO could pay under the settlement for heavy transmission use is $38 million per year.

MISO Wants Deferral Year to Create Queue Withdrawal Penalty

MISO is seeking a yearlong extension to develop specific penalties for generation project withdrawal, as directed by FERC in the RTO’s interconnection queue overhaul (ER17-156).

MISO attorney Jacob Krause said the RTO wants to hold off on a filing until March 31, 2017, in order to work with stakeholders to determine an appropriate penalty. He said MISO is currently seeking FERC permission for the deferral.

— Amanda Durish Cook

March 14, 2017

Texas PUC Wary of Using ERS to Avoid Local Blackouts

By Tom Kleckner

The Public Utility Commission of Texas last week asked its staff to revise a rulemaking on emergency response service (ERS), saying it did not favor expanding the program to prevent local load-shed events (Project No. 45927).

As drafted, the proposed order would permit ERCOT to use ERS to prevent firm load shedding (rolling blackouts) in the event of local transmission emergencies. It also would give ERS resources the flexibility to replace reliability-must-run services.

ERS pays loads for reducing their consumption and distributed generation such as backup generators for injecting power during emergencies. ERS currently is used for non-local emergencies and is not permitted to also serve as a must-run alternative (MRA).

Commission staff published the rulemaking for comments in June 2016. The proposed amendments drew comments from 13 different groups, including ERCOT, its Independent Market Monitor and various energy companies and industry and environmental associations.

Price Suppression Concerns

PUC Chairman Donna Nelson said Thursday she “struggled” with the rulemaking and was concerned about ERS suppressing local prices when it is deployed to address local congestion. The draft order said the issue of price suppression should be addressed through the ERCOT stakeholder process.

Commissioner Ken Anderson said he shared Nelson’s concerns, and asked staff to return to the amendment’s original concept of allowing ERS participants to opt out of ERS “if they’re in a situation in which ERCOT is seeking load alternative to RMR.”

“If they’re in an [MRA] contract, they can opt out at their choosing, but they forego the [ERS] payment,” he said.

SCED Integration?

Anderson also asked staff to delete language in the preamble referencing a Shell Energy North America proposal to expand the current ERS program by allowing some resources to submit energy offer curves to ERCOT’s security constrained economic dispatch (SCED) algorithm. As drafted, the proposed order says the commission agrees with ERCOT that requiring ERS resources to telemeter bids and respond to SCED dispatch would “undermine a core purpose of the ERS program — to capture the benefit of demand response or generation that otherwise would be unable to participate in the ERCOT market.”

Anderson said the rulemaking had identified a bigger issue: the integration of distributed generation and allowing the resources to bid into SCED.

“Whether it’s paired with load or just on its own, [DG] needs to be integrated into ERCOT,” Anderson said. DG “should get the LMP. I know ERCOT is working on that, but I would strongly encourage them to make it a priority.”

RMR Alternatives

ERCOT texas puc ERS local blackouts — ERCOT IMM Director Beth Garza | © *RTO Insider*

Anderson told Monitor Beth Garza he thought one reason staff expanded the amendment’s original scope was to address suggestions made by the Monitor that there might be other alternatives than the Greens Bayou Unit 5 RMR agreement. (See ERCOT Ending Greens Bayou RMR May 29.)

“It would be helpful if you could come up with a real concrete proposal that we could shoot at,” he said.

Garza said her initial suggestion for using ERS resources in local emergencies was “not necessarily directed at RMRing Greens Bayou.”

“Frankly, it was a response to … other times we have had to shed load,” she said, pointing to localized events. “I consider ERS as a program that allows loads to be paid, to be the first in line to be curtailed when we’re at the cliff. At that point, the need for effective market mechanisms diminishes. Prices should be reflective of that. ERS is a way for specific loads to step up and say, ‘Yes, I’ll be the first ones to go.’”

Co-Optimizing

Anderson said that with a recent ERCOT cost-benefit analysis indicating a multi-interval SCED would not be cost effective, it opens up the discussion about co-optimizing the real-time market (shifting the responsibility for providing reserve services to online generation resources with the lowest incremental energy cost).

“Which we’ve been talking about for how long?” Nelson asked.

“I still had hair, I think,” Anderson joked. “[Co-optimization] would help with the whole proper price signal and dispatching, hopefully minimizing reliability unit commitments. Then if we co-optimize, we could adopt local [operating reserve demand curves] that reflect that sort of scarcity.”

Anderson was careful to say he was not expressing an opinion, but just hopeful of addressing congestion and local transmission problems.

“To the extent that you just eliminate unnecessary barriers, that’s fine,” he said. “I don’t think ERCOT should spend a lot of time trying to use ERS to relieve localized problems.”

“I would just leave the must-run alternative agreement aspect in the rule, and limit it to that,” Nelson said, saying she was concerned about interfering with ERCOT’s competitive market. “The whole purpose of opening this rulemaking was to look at ways of using ERS as it currently exists and the money that’s being spent. I do not in any way want to enlarge ERS … it shouldn’t be larger than it is.”

The draft order rejected calls to eliminate or increase the $50 million annual cap on ERS spending but promised the commission would review the limit if the new ERS local deployment product results in costs threatening to exceed the limit.

The commissioners asked staff to return with a rulemaking reflecting the day’s discussion for the PUC’s next open meeting March 30. Staff is targeting a March 23 publication of the revised language.

The PUC also:

Approved the City of Garland’s request to amend its certificate of convenience and necessity with a final route for a double-circuit 345-kV transmission line east of Dallas that will interconnect ERCOT with the SERC Reliability Corp. through the proposed Southern Cross DC tie in Louisiana (Docket No. 45624). The line will connect an Oncor substation with a Garland substation, that will then connect with the Southern Cross.
Approved a settlement between Entergy Texas and its customers allowing the utility to recover an annual revenue requirement of $29.5 million, almost $19 million above the amount approved in its previous transmission cost recovery (TCRF) factor proceeding (Docket No. 46357). Entergy will recover almost $3.4 million in additional transmission-related revenues through its base rates than it did when the TCRF baseline was set, because of an increase in billing determinants since its last base rate case.
Reduced revenue requirements for Electric Transmission Texas by $46.2 million (Project No. 44550) and Cross Texas Transmission by $86.5 million (Project No. 45636). The reductions were a result of the PUC’s annual true-up for regulated entities.