MISO Resource Adequacy: How Bad is it?

By Chris O’Malley and Rich Heidorn Jr.

INDIANAPOLIS — MISO will release the results of its latest resource adequacy survey later this month, after a survey last year caused alarm, with forecasts of capacity shortages in three zones in MISO North and Central.

How bad will the new numbers be? And how can MISO increase its reserve margins in the future? Those were among the topics that dominated discussion at Infocast’s MISO Market Summit last week.

“We do not have a capacity shortage,” Lin Franks, Indianapolis Power & Light’s senior strategist for RTO, FERC and compliance initiatives, said flatly. “The message has been ridiculously presented to the world as if the sky is falling. The sky is not falling. It’s been very difficult with [the Environmental Protection Agency] disrupting all our planning processes, but we are rallying. We are solving it. We have an obligation to serve load and damn it, we’re going to.”

Franks found some support from Kathleen Spees, a principal of The Brattle Group. “There’s more [capacity] that gets offered than comes out in these surveys. So I’m not particularly worried that we’re really going to have a shortage.”

Snapshot in Time

Franks said the survey data, which is collected by the Organization of MISO States, makes the situation look worse than it is.

Utilities are asked, for example, about the certainty of their plans for new generation. “[You] are never certain at all until you get your certificate of public convenience and need. So it’s not a graduated certainty. It is or it isn’t, period,” she said. “What you’re seeing is a snapshot in time. It doesn’t mean that there won’t be a solution [when the capacity is needed].”

Joseph Gardner, MISO’s vice president for forward markets and operations services, said the RTO will change how it presents the survey data in the new report. “So hopefully it will address some of those things,” he said.

There is no question, however, that MISO, which has enjoyed reserve margins exceeding 20% in the past, is facing a much tighter future.

Calls on Interruptible Loads to Increase

Gardner noted that it’s been nine years since MISO last deployed its load-modifying resources — currently about 6 GW of behind-the-meter generation and 4 GW of interruptible loads.

“We’re going to start having to use that quite often. I don’t expect we’ll have to use it very often this year, but we do expect to use it very often starting next year,” he said. “How often is hard to tell. It depends on what kind of a summer we have. If we have a summer like we did three years ago: not much. If we have a summer like we did two years ago: a lot — upwards of two dozen times of more.”

That could result in departures from the program, Gardner and others said.

“Essentially those interruptible customers start to look like a peaking generator,” said Chris Plante, director of resource planning and policy for Wisconsin Public Service. “Those customers … are not accustomed to regular interruptions. Our thought is that as they start to experience those interruptions, they may actually decide to leave the interruptible program and become firm load, which of course makes the situation even more tight.”

David Sapper, director of midcontinent regulatory affairs for Customized Energy Solutions, said MISO officials’ recent suggestion that they are considering testing the response of interruptible loads may also contribute to defections.

Challenges to Adding Generation

Losses of interruptible loads would make the construction of new generation even more crucial. But that won’t be easy, Plante said, because of “friction” in MISO’s interconnection process.

“You have to get into the MISO interconnection queue early enough so that you get your study results done and you get the transmission issues identified. Usually that time frame is so long that I don’t even have a good idea yet on whether I’m going to build a one-on-one combined-cycle or a two-on-one. If it’s a one-on-one, is it 400 MW or is it 450 MW? That might not seem like a big deal, but to MISO’s interconnection process it’s a big deal. You can’t go in with 400 and later say, ‘Well it’s really 450.’ You have to get out of the queue and get back in with 450.”

Plante also criticized MISO’s modeling of wind power at 100% of nameplate capacity during off-peak hours. “When my combined-cycle is modeled at 100% and the wind’s modeled at 100%, there’s all kinds of constraints. And those constraints show up in my interconnection agreement as issues that I need to resolve before I can count that generator as capacity. Depending on the lead time of those constraints, I might have to wait for 10 years [for a major transmission project] before I can get the capacity value out of that combined-cycle when in reality … we believe that off-peak wind probably won’t be at 100% and the constraints that MISO identifies might not ever show up.”

No Rescue from IPPs

Don’t expect to see independent power producers riding in like the cavalry to build new generation.

Brett Kruse, vice president of market design at Calpine, said his company won’t build in MISO without a contract because all but two of its states are dominated by vertically integrated utilities and its voluntary capacity market provides too little revenue.

“The contract has to be 10 or 20 years depending on how much you can frontload it … where you basically have to stick all the value of your plant into that contract, because once you get out and you’re a merchant plant in a construct like [MISO], you have very little value other than what you’re seeing the IPPs in Michigan do: Either you build a line to get into PJM like [Tenaska Capital Management’s Covert, Mich., plant] did or you sell to the utilities.”

As the biggest natural gas buyer in the U.S. and one of the biggest operators and builders of gas-fired generation, “I can build … a gas-fired plant cheaper than anybody else in America. … We’re very confident we can run circles around any utility self-build in America.”

But he added, “If I went to my board and said I wanted to invest $500 million into building a [merchant] plant in MISO, they’d laugh me out of the room — and then fire me.”

Until recently, MISO’s ample reserve margins have meant there hasn’t been much need for merchant entry, said Brattle’s Spees.

Capacity Prices Too Low?

But, she said, “That’s not going to last forever. The only way it can last forever is if the regulated states overbuild into perpetuity by a sufficient margin that they can meet the resource adequacy needs of their neighbors” in Illinois and Michigan, the two MISO states with retail competition.

Spees said she sees promise in the concept of setting up a PJM-like forward capacity market for the states with retail choice.

Marka Shaw, a director of wholesale market development for Exelon, also criticized MISO’s structure, saying it is not only unable to attract new entry but also provides insufficient revenue to cover expenses for existing baseload generation, such as Exelon’s Illinois nuclear fleet.

Kruse and others agreed that MISO’s capacity prices are too low, with some noting that the $150/MW-day price seen in Illinois Zone 4 in the most recent auction — which sparked complaint to the Federal Energy Regulatory Commission last week — is less than two-thirds of the $247/MW-day cost of new entry in the zone. (See Public Citizen to FERC: Investigate Dynegy Role in MISO Capacity Price Jump.)

Gas vs. Nuclear

But Kruse’s Calpine colleague, Joe Kerecman, jumped into the discussion from the audience to criticize what he called Exelon’s request for “out-of-market subsidies.” Exelon has been lobbying for the Illinois legislature for a bill that would charge Illinois electricity users a fee to ensure continued operation of three nuclear generators that the company says are unprofitable. On Monday, Exelon acknowledged that the legislation would not pass during the current legislative session.

“These plants are also getting old,” Kerecman said, accusing Exelon of abandoning its support for competitive markets. “There’s a fallacy that they won’t get replaced.”

“Clinton [one of the generators Exelon says is losing money] is one of our newest plants,” Shaw shot back.

Shaw found support in Spees, who said the relief nuclear operators are seeking is to address the unpriced cost of carbon emitted by coal and natural gas plants. “That’s a market failure,” she said.

May 26, 2015June 15, 2023

Organic Farmer Turned Fracking Protester: ‘I Never Figured to be Engaged in Protest Activities’

By Rich Heidorn Jr.

Maggie Henry, a 61-year-old organic farmer from Western Pennsylvania, never expected to become a protester.

“I was happy working like a mule to produce food for my community,” she said.

fracking — Henry collects eggs on her organic farm in Pennsylvania. (Source: “Gas Rush Stories” documentary by Kirsi Jansa)

Her 100-acre farm in Bessemer, near the Ohio border, produced eggs, meat and vegetables for top restaurants in Pittsburgh, including the Fairmont Hotel, the Enrico Biscotti cafe and Crested Duck Charcuterie. Over four years it grew from six to 400 chickens. “I had a thriving business going! It was all I could handle,” she said.

But after a shale gas operation began drilling in a neighboring farm in 2010, she says, her life changed.

Her farm, which has been in her family for almost a century, is located above an historic oil field. Plugged wells can serve as pathways for methane and other pollutants, allowing them to seep to the surface and into aquifers.

She has a monitor that measures particulate matter that is “off the charts all the time.”

“The toxicity of the air and the contamination of the water is absolutely unbelievable,” she said. “People are covered with rashes and blisters. They experienced all sorts of neurotoxic symptoms. Their children suffer nose bleeds and asthmatic reactions.”

She blames drilling in the Utica shale for a series of earthquakes in March 2014 that she says cracked her basement foundation, drywall and chimney pipe. “When it rains, water pours through my basement wall,” she said. “That never happened before.”

In February, two pigs and a cow unexpectedly died within two and a half weeks of each other.

A year ago, she told her story in a documentary. And on May 14, she traveled to D.C. to attend the Federal Energy Regulatory Commission’s open meeting, becoming one of three protesters to evade a security dragnet and enter the meeting room. (See Another Meeting Day, Another Drama at FERC.)

She stood up at the end of the session, shouting “In the shale plays of Pennsylvania, you are killing people!”

She mentioned Terry Greenwood, a farmer who she said “made a chilling prediction years ago. He said, ‘First it is the animals, then it will be the people.’ We buried him in June of last year, the victim of a rare form of brain cancer,” she said.

After the FERC meeting, Chairman Norman Bay called the protesters’ repeated interruptions of the commission’s meetings “disrespectful” and noted that it is the states — not FERC — that regulates fracking.

Henry insists FERC shares responsibility because it has approved liquefied natural gas export terminals. “They are poisoning us so they can make more money selling this fracked gas overseas,” she said. “No way am I going to permit this. I intend to give voice to the struggle every chance I get.”

She stopped farming her land after the 2013 harvest, no longer able to guarantee that her products were pure.

“I don’t care about anything [else] anymore,” she said Tuesday morning, shortly before marching to FERC headquarters again with other protesters. “I have been radicalized.”

May 26, 2015June 15, 2023

PJM’s Annual Meeting Marks CEO’s Departure

By Suzanne Herel

ATLANTIC CITY, N.J. — PJM’s Annual Meeting last week marked a number of milestones: It was the largest yet, with 525 attendees, and it heralded the end of CEO Terry Boston’s eight-year tenure as well as the retirement of PJM employee No. 13, Jim Kirby, after half a century.

In remarks at the Members Committee meeting that ended the three-day event, Boston employed his trademark humor. During Superstorm Sandy, Boston said, “We got caught with our plants down.”

In his presentation, “21st Century Power Grids or ‘The Future Ain’t What It Used to Be,’” Boston revisited his time at PJM and identified the challenges facing the industry and his successor, Andy Ott.

He noted the flat demand for electricity, saying, “The load forecast is the lowest in my entire career.”

He followed that with discussions of extreme weather; the world’s largest fuel switch to low-carbon sources; the integration of demand response; and the need for more high-voltage direct current transmission.

“If we’re smart, over this next century we’ll focus on the electrification of automobiles,” Boston said, noting the rise in EV sales in the PJM footprint from nearly nothing in 2010 to about 28,000 in 2014.

He juxtaposed industry predictions from 15 years ago with the state of the market today to underscore the need to keep a balanced generation portfolio.

Fifteen years ago, he noted, gas-fired plants were to be avoided, with their high, volatile fuel prices. Wind and solar were absent from long-range plans. “The resiliency of the future is what we’re here to protect,” said Boston, who closed to a standing ovation.

“Thank you for your great and unique style of leadership,” Board of Managers Chairman Howard Schneider said, calling Boston’s tenure, “an incredible career that has improved the lives of millions of Americans.”

Schneider then introduced Ott, PJM’s executive vice president of markets, who will succeed Boston sometime in the fall. (See Incoming PJM CEO Ott Expects Challenges from an Industry in Transition.)

“Andy has led or has been intimately involved in every facet of PJM’s mission during his 18-year career at PJM, and prior to that at [General Public Utilities Corp.],” Schneider said.

Ott praised Boston for building a culture of openness and consensus-building at PJM. “You set a standard when you came on board,” Ott said. “You set an example for us all.”

Ott promised to continue Boston’s tradition, saying “I value diversity of opinion, diversity of thought.”

He added that he would work to help PJM “be more nimble, more innovative as we go forward.”

May 26, 2015June 15, 2023

Company Briefs

The Federal Aviation Administration will allow Xcel Energy to use drones to inspect the company’s power lines in lightly populated areas. Xcel wants to use the unmanned aerial devices to inspect lines in some inaccessible and environmentally sensitive areas.

The company said it will conduct some field tests this summer. A spokesman said the company might use drones as damage assessment tools after major storms. Some drones, if equipped with special sensors, could also be used to detect leaks from natural gas lines. The company already used a drone to inspect the inside of a massive boiler at the company’s Sherco plant in Becker, Minn.

Xcel is one of about 400 companies to get approval to use the drones. Southern Co. received FAA authorization earlier this month.

More: Star Tribune

Dominion Fires Back After Tx Line Complaint

Dominion Transmission strenuously responded to a complaint before the Virginia State Corporation Commission that it misled the public about its plans to rebuild a 500-kV transmission line. Farmer Kristopher Baumann, of Rockbridge, Va., said Dominion’s inclusion of a new 230-kV line that added 60 feet to the transmission line’s towers violated terms of the project and ruined the scenic view.

The project was built “entirely within existing right-of-way” of the existing 500-kV Dooms-Lexington Line, Dominion wrote in response to Baumann’s complaint. It did acknowledge, however, that due to an oversight, the project’s website didn’t include information on the additional line. “The company has rectified this administrative oversight and the structure comparison is now accurate.”

It is now up to the SCC to determine if Dominion violated any public notice rules.

More: News Leader

A Mellow Month for MISO

Falling natural gas prices helped make for a rosier April monthly market metrics report by MISO’s Independent Market Monitor.

Average day-ahead energy prices declined about 40% to $25.23/MWh, and real-time energy prices were $24.85/MWh, Monitor David Patton told MISO’s Markets Committee of the Board of Directors last week. The value of real-time congestion fell to $86 million — down 18% from last month and 60% from last year.

The price drop was due to lower fuel costs and lower spreads between the dispatch costs of coal-fired and natural gas-fired generation resources, Patton said.

Meanwhile, MISO’s monthly operations report to the board noted that average temperatures for the month were near-normal and that all metrics were in the “expected” status, a not all-that-common event.

More: IMM Report

Paslawski to Succeed Smith as OMS Executive Director

The Organization of MISO States board of directors Thursday voted unanimously to appoint Tanya Paslawski as executive director, effective June 1. Paslawski, who currently is deputy executive director, will succeed William H. Smith.

Before joining OMS, Paslawski worked for the Michigan Public Service Commission, Direct Energy and ITC Holdings. She holds a bachelor’s in political science from Oakland University and a law degree from the Michigan State University College of Law.

Smith, who has been executive director since 2004, will be retained in a part-time, emeritus role through the end of 2015 to help in the transition, OMS President Libby Jacobs said during the organization’s May board meeting. Smith’s career includes a role as government relations manager for the Iowa Utilities Board and as a legal advisor to commissioners of the Federal Energy Regulatory Commission.

Duke Spending $1.1 Billion on New Gas Plant and Solar Farm

Duke Energy announced last week that it will spend $1.1 billion to construct a 650-MW natural gas-fired combined-cycle plant on the site of a to-be-retired coal-fired plant. It will also install a solar farm of undetermined size on the plant’s ash site. The company said it made more sense to demolish the two 51-year-old coal units at the plant on Lake Julian near Asheville, N.C., than to install new emissions controls to extend their lives.

Duke estimated the cost of the facilities at about $750 million. The company will spend another $320 million to build a new substation and a 40-mile transmission line in Spartanburg, S.C., to bring the plant’s electricity to the grid.

Duke said it would be filing a full plan with the North Carolina Utilities Commission by the first quarter of 2016.

More: Citizen-Times; Charlotte Observer

Jennifer Murphy Hired by NARUC as Asst. Gen. Counsel

The National Association of Regulatory Utility Commissioners has hired a former Massachusetts regulatory attorney as its assistant general counsel.

Jennifer M. Murphy, who worked for the Massachusetts Department of Public Utilities for five years, will represent NARUC before the Federal Energy Regulatory Commission, the Department of Energy and federal courts. She will also be involved in the development and implementation of the association’s Washington Action Program and will serve on the Consumer Affairs, Electricity, Energy Resources and the Environment, and Gas subcommittees.

Murphy received a law degree from Vermont Law School and has master’s degrees in Marine Affairs and International Studies.

More: NARUC

Wisconsin Brewer Goes All-Wind for Power Needs

A Green Bay, Wis., craft brewer has entered into a partnership with Arcadia Power to purchase all its electricity from Midwest wind farms.

Andrew Fabry, president of Badger State Brewing, said renewable energy is a focal point of the company’s business plan. Arcadia, based in D.C., buys the output of nine wind farms in the Midwest and the Pacific Northwest.

More: Journal Sentinel

National Grid Profits Up; US Investments Increasing

London-based National Grid reported $5.86 billion in operating profit for the year ended March 31, a 1% increase over the year earlier. Adjusted results, reflecting continuing operations before exceptional items, were $5.99 billion, up 5%.

The company’s regulated gas and electric operations in New York, Rhode Island and Massachusetts recorded a 3% increase in operating profit to $1.8 billion. Although it absorbed additional costs due to prolonged cold weather, the company benefited from rate increases and new customers. It also made record capital investments of $2.4 billion, boosting its U.S. rate base by 7%. U.S. operations generated an average 8.4% return on equity, down from 9% a year earlier.

“The benefit of filing and delivering effective rate cases can clearly be seen in the progress we have made with NiMo Electric [Niagara Mohawk] and our business on Rhode Island,” CEO Steve Holliday said in an earnings call. Although the Federal Energy Regulatory Commission reduced Niagara Mohawk’s allowed ROE, the company “is achieving over 95% of its allowed return in the second year of a three-year plan,” Holliday said. “That’s a very far cry from the performance in 2011, a full 340 basis points up.”

National Grid says its customers in Rhode Island who signed up for the company’s energy efficiency programs will save $427 million over 13 years. The company said 41,500 customers participated in the programs in 2014. The company has invested $102 million in the programs, funded through an energy efficiency charge on customers’ bills.

More: National Grid; Fierce Energy

FirstEnergy Crews Use Aerial Saws for Trimming in Rural Areas

Vegetation management crews with FirstEnergy subsidiary Mon Power in West Virginia are using helicopter mounted aerial saws to trim trees in areas that are inaccessible to bucket trucks. A company spokeswoman said an aerial saw can cover in one day the work a ground crew could handle in a week.

“Suspended from a vertical boom beneath the helicopter, the saw can trim both sides of a 10-to-12-mile right-of-way in about a week,” Mon Power said. “Ground crews work in tandem with the pilot, flagging traffic and removing limbs and smaller branches from roadways, trails, waterways or other sensitive areas.”

Mon Power spends about $70 million a year on vegetation management, maintaining reliability along 4,500 miles of transmission and distribution lines.

More: Fierce Energy

Former Duke CEO Slams NC Lawmakers for Freezing Green-Energy Goals

Jim Rogers, former CEO of Duke Energy, was sharply critical of North Carolina legislators after a Senate committee approved a bill that would freeze the renewable energy standard. The current law calls for utilities to obtain 12.5% of the energy they sell from renewable sources by 2021. The bill now before the Senate would freeze the standard at 6%.

“They are not focused on the future,” Rogers said of legislators. Renewable standards, he said, are “something we need to get behind and figure out how to educate those who claim to be leading us into the 21st century.”

Solar advocates say that the new measure will reduce incentives for renewable power developers. Currently, North Carolina ranks fourth in the U.S. for installed solar generation.

More: The Charlotte Observer

Customers Will Be Able to Phone in Comments on Next PPL Rate Hike

Customers of PPL Electric wishing to weigh in on the company’s latest rate increase request will be able to phone in their comments instead of attending a Pennsylvania Public Utility Commission hearing.

PPL spokesman Paul Wirth said the company welcomes the pilot program, which will be used in two of three scheduled PUC meetings. “We are in favor of getting as much comment into the process as possible,” he said. Acting Public Advocate Tanya J. McCloskey said her office will see how it works before passing judgement. “At this point, this is the first one we have tried and I’m sure we will learn a lot of lessons.”

The company is seeking a $167.5 million rate increase, representing a 3.9% jump in residential monthly bills, or about $10 a month.

More: The Morning Call

NextEra North Dakota Wind Project in Limbo After County Votes No

NextEra Energy Resources said it is shelving a proposed 150-MW wind energy project near Dickinson, N.D., after opposition to the project’s location and aesthetics spurred the Stark County commissioners to deny the project a conditional use permit earlier this month.

NextEra asked the Public Service Commission to suspend its review of the project. “We’ve been talking to those who support and oppose the project as well as looking at potential changes to the project layout that would address concerns expressed by commissioners,” NextEra spokesman Steven Stengel said.

More: ReNEWS

May 26, 2015June 15, 2023

Microgrids: Evolutionary or Disruptive? That Depends on Who’s Talking

By Suzanne Herel

ATLANTIC CITY, N.J. — The eye of Superstorm Sandy swept over this city nearly three years ago, leaving 2.8 million residents without power. That made the Borgata Hotel Casino a fitting spot to debate the value and challenges of microgrids, Richard Mroz, president of the New Jersey Board of Public Utilities, told a group at PJM’s biannual General Session.

“Sandy had a cascading effect on all critical systems,” he said, highlighting their interdependency and the role microgrids could play in strengthening their resiliency against natural, accidental and manmade threats.

“It’s resulted in debates over the grid — the role of generators, distribution companies and regulators,” he said. “It’s a discussion worth all of our efforts.”

Joined for a roundtable on just that topic were Michael Burr, director of the Microgrid Institute; Lawrence Jones, North America vice president for utility innovations and infrastructure for Alstom; Micah Kotch, director of the New York Prize program at the New York State Energy Research and Development Authority; Thomas Nyquist, executive director of engineering and campus energy for Princeton University; and Thomas Fenimore, technology development manager for Duke Energy.

‘Nested’ Microgrids

Centralized grids are reliable but not resilient, Burr said. That’s where distributed energy technologies can step in.

In particular, he pointed to a trend of “nested” microgrids, where critical facilities such as hospitals and water towers that are located in different areas of town can be served by a cluster of “nodes.”

One such community is the Olney Town Center in Montgomery County, Md., part of a U.S. Department of Energy technology research program to study microgrid models. When completed in the fall of 2016, the community’s six nodes will operate together during normal conditions to maximize economic efficiency and “island” during outages to preserve resiliency.

However, there are challenges to such a model, he said. The nested architecture contains more points of coupling, requiring more interconnection and safety equipment, Burr said. In addition, non-critical loads must be disconnected during islanding.

Princeton Keeps the Lights On

Nyquist brought to the table Princeton University’s experience operating two generators on campus to serve the school’s need for power for labs and data centers. During Sandy, it was this energy independence that saved 50 years’ worth of DNA research, he said.

Princeton uses energy from the PJM grid at night, when the prices are lowest, and generates its own power during the peak period.

“We save a lot of money doing this, but it also reduces load on the grid,” he said.

Kotch likened the innovation erupting in the energy industry to the disruption that tech companies such as Uber, Facebook, Alibaba and Airbnb have effected in their spaces — none owns a product, but they’re providing services that have eclipsed their brick-and-mortar competitors.

“Thomas Edison would be the first to agree that energy isn’t about moving commodity but delivering services,” he said. “Utilities have traditionally thought their business ends at the meter. That notion is fundamentally trying to change. There is this customer pull — not a top-down push — for more control.”

Outgoing PJM CEO Terry Boston agreed. “I think choice and control are going to drive microgrids as much as economic viability,” he said.

Energy as a Service

Jones also spoke of the idea of rethinking energy as a service.

“If kilowatt-hours are not selling, if they’re reducing … how do we evolve from a kilowatt-hour approach to more of a service model?” he asked.

He recounted the experience of one African region where residents were so used to the government subsidizing electricity that they were unwilling to pay for it. What they valued, however, was refrigeration — so they paid more for that in a bundle of services, which made up for the low price of electricity.

Such a paradigm change, Jones said, is where regulators must get involved.

Other core issues, he said, are whether microgrids can benefit the overall transmission system and how to quantify the value of distributed energy.

“How will the markets evolve?” he said. “How do we unlock the value of distributed resources? Do we keep the assumptions we’ve had?”

As for whether microgrids are considered evolutionary or disruptive, “It’s all relative to who you’re talking to,” he said, and depends on where you are in the world.

Value

Fenimore, of Duke Energy, echoed some of Jones’ questions.

“We know how to operate and build these assets,” he said. “How do we integrate these newer technologies … and then how do we understand in a regulated space what the value of that is on the market side?”

To address the changing landscape, Duke in 2014 created the Distributed Energy Resources Group. Fenimore highlighted the company’s energy storage efforts, which charge and discharge based on market signals to help maintain grid stability.

Boston, who did his graduate thesis on the optimization of energy storage, applauded the project.

“I’m for storage,” he said, adding, “I did learn something today, and that was about the innovation and change that are inevitable here.”

May 26, 2015

Sights from the 2015 PJM Annual Meeting

PJM’s Annual Meeting in Atlantic City was a chance to meet up with old friends and say goodbye to retiring CEO Terry Boston and veteran PJM staffer Jim Kirby.

[metaslider id=”102312″]

May 26, 2015

PJM Ponders Changes to Virtual Trades, DA Market

By Rich Heidorn Jr.

ATLANTIC CITY, N.J. — PJM officials and the Independent Market Monitor are considering changes to the treatment of virtual transactions to reduce uplift and gaming opportunities and allow quicker solving of the day-ahead energy market.

PJM Executive Vice President for Operations Mike Kormos and Market Monitor Joe Bowring floated ideas for potential changes during a Year in Review presentation at the PJM Annual Meeting at the Borgata Hotel Casino last week.

pjm — Mike Kormos gives the Year in Review presentation at PJM’s Annual Meeting. © RTO Insider

Bowring suggested PJM consider NYISO’s model, which limits virtual transactions to zones or hubs. Kormos said the RTO could consider either removing the financial transactions from the day-ahead market or making the day-ahead a pure financial market.

In interviews afterward, Bowring and PJM officials said the changes could address uplift and allow quicker solving of the day-ahead market to reduce the disconnect with gas trading schedules.

NY Model

Bowring made his suggestion first, saying PJM might benefit from adopting NYISO’s treatment of virtual transactions — increment offers (INCs), decrement bids (DECs) and up-to-congestion transactions. “Should that be a secondary derivative market or in the PJM market?” he asked.

He said virtual transactions were introduced into the market to improve efficiency. “I think we’ve gone well past that now,” he said, saying they affect unit dispatch and commitments and cause congestion. “I haven’t come to a full and final opinion on this, but questions need to be asked,” he added.

Bowring said his primary motivation for wanting to change the treatment of virtual transactions is to reduce gaming opportunities. “The ability to manipulate the market … would be substantially reduced by limiting financial transactions to zones and hubs or putting them all in a secondary market where they do not affect the actual operation of the market,” he said.

Executive Vice President for Markets Andy Ott said Bowring’s suggestion is “something we need to look at.”

Ott said large volumes of virtual trades are “dumped into the market” because there’s no cost for doing so. Although most do not clear, the large volumes slow processing time for the RTO’s security constrained economic dispatch.

Kormos made his suggestion in response to questions after Bowring’s presentation. “It’s the blending of the physical and the financial that’s causing the uplift” and making the market more difficult to solve, he said.

If the day-ahead market became purely financial, the reliability assessment and commitment (RAC) run could determine the day–ahead schedules for generators, said Mike Bryson, executive director of system operations.

Eliminating physical generation from the day-ahead market could aid efforts to post day-ahead results sooner, Kormos said. A market with no generator minimum run times “would solve a lot faster,” he said.

Under the current system, Bryson said, virtual trades can hurt reliability by masking transmission congestion.

An increment offer — an offer to sell to the day-ahead market if prices go above a specified price — can act like a dispatchable resource. But transmission constraints that are “solved” financially by virtual trades remain in the physical market, Bryson said. “In real time there wasn’t truly a generator there.”

Any changes would be subject to stakeholder review to determine their impacts. For example, limiting virtual transactions to only zones and hubs would prevent them from using generation buses, reducing their value as hedges for generation.

Gas-Electric Scheduling

Ott said PJM hopes to reduce the day-ahead market solution to three hours from the current four-hour average in time for the Federal Energy Regulatory Commission’s April 1, 2016, deadline for changes to gas-electric scheduling. (See PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order.)

PJM officials are considering parallel processing and sequencing changes to speed the market solution. Ott said further reductions would not be “feasible” in the next year.

Bowring said the 85% reduction in UTC trading since FERC suggested the transactions might be subject to uplift charges had contributed to a recent reduction in the processing time required for the day-ahead market. (See FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October.)

Ott demurred. “Before we jump to conclusions, we have to see what is the cause of the day-ahead market running faster,” he said.

PJM currently posts its day-ahead results at 4 p.m. The time required to solve varies from day to day depending on factors such as transmission outages and load projections. Most days it takes three to three and a half hours. But some days can take more than four hours, according to a PJM analysis that will be presented at Thursday’s Markets and Reliability Committee meeting.

“Some days you’re bringing it all [generation] on or you’re hardly bringing anything on,” and solution is easier, Kormos said.

Ideally, Kormos said, PJM would like to post its results by 1 p.m. ET, an hour before the first gas nomination deadline at 2 p.m.

Members Polled

PJM is compiling the results of a poll that closed May 18 to gauge members’ preferred response to the FERC order.

The poll asked members which day-ahead market start time would allow them adequate time to construct their offers, with choices ranging from 9:30 a.m. to 11 a.m. It also asked preferences on posting times to provide sufficient time to purchase fuel, offering choices between 1 p.m. and 2 p.m.

Because FERC declined to change the start of the gas day, however, RTO officials say there is no escaping some uncertainty. Other RTOs are wrestling with the same dilemma. (See SPP Trying to ‘Balance the Risk’ on Gas-Electric Schedules.)

“In [either the gas or electric] markets you have to commit before you have your numbers locked up,” Kormos explained.

May 26, 2015

NYPSC Rejects Renegotiation on Biomass Contract

By William Opalka

New York regulators on Wednesday declined for the third time to renegotiate a contract with a financially troubled biomass generation plant, saying that doing so would threaten the integrity of the state’s renewable energy procurement program.

In 2007, the 51-MW co-firing Niagara Generating Facility (NiGen) in Niagara Falls won a $21.6 million contract to provide up to 180,500 MWh of energy per year from renewable-eligible biomass for 10 years. The contract was awarded under the main tier of New York’s renewable portfolio standard following a competitive bidding process.

Sterling Energy Group, which purchased the NiGen plant in 2013, mothballed it in August 2014, saying the fall in wholesale energy prices had left it unprofitable despite its $11.99/MWh in RPS incentives.

Sterling told the New York Public Service Commission it should be given extra credit for increased clean energy generation because it is now able to generate 80% of its power from wood products, without burning tires, which had previously represented 40% of its fuel. The company said the change increased its RPS-eligible generation and reduced harmful emissions.

The petition had won backing from local elected officials who said the plant’s closing would result in the loss of 100 direct and indirect jobs and more than $10 million in local spending. In its mothballed status, the plant has 26 part-time employees.

But the commission was unmoved, saying that Sterling knew of the plant’s shaky finances when it acquired it (03-E-0188).

“The petitioners have requested that the commission provide additional financial incentives that it has twice denied in the past and the commission does not see any significant material differences in this request that compels the reversal of earlier decisions,” the PSC wrote.

“The contract was awarded under a competitive solicitation at a price chosen by NiGen and for the term of years chosen by NiGen. Adjusting NiGen’s RPS benefits would undermine the competitive nature of the solicitation process established by the commission for the main tier.”

Instead, the commission said Sterling should bid its additional renewable capacity into future main tier solicitations.

The plant is permitted to burn coal, tires and various wood-based fuels, but it only receives RPS incentive payments for the amount of generation produced by agricultural residue, wood and other eligible biomass.

May 26, 2015

PJM Markets and Reliability Committee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

A. Manual 36: System Restoration — Annual review. Adds detail about when PJM assumes control and when it returns to normal operation. Also adds guidance on completion of interconnection checklist. Effective: June 15.

B. Manual 03: Transmission Operations — Updates index and operating procedures for PJM RTO operation (nuclear station voltage limits, operation procedures with neighboring systems and operation procedures for AEP, ComEd, Dominion, PPL, UGI, PSEG and PECO.) Effective: June 1.

C. Manual 38: Operations Planning — Makes minor changes due to system upgrades and specifies periodic review of IROL facilities. Updates the study process for transmission reliability analysis procedure. Effective: June 1.

3. TIMING OF DAY-AHEAD MARKET (9:30-9:45)

The committee will be asked to approve a problem statement and issue charge to review options for moving the day-ahead energy market and reliability unit commitment timelines in response to the Federal Energy Regulatory Commission’s final rule on gas schedules. PJM must make a compliance filing in response to the order by July 23. Discussions would take place at the MRC. (See PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order and related story, PJM, IMM Considering Changes to Virtual Trades, Day-Ahead Market.)

4. INTERIM FEE FOR VIRTUAL TRANSACTIONS (INCs/DECs and UTCs) (9:45-10:30)

Members will be asked to approve a proposal by Inertia Power to impose a temporary uplift fee of $0.07/MWh for increment offers, decrement bids and up-to-congestion bids. The proposal would expire in six months or upon FERC approval of an alternative. Transactions placed between September 2014 and the effective date of the filing would not be affected.

The proposal is in response to a Section 206 proceeding ordered by FERC to determine whether PJM is improperly treating UTCs differently from INCs and DECs. Sponsor Noha Sidhom, who announced the proposal at last month’s MRC meeting, has removed a provision limiting the fees to netted transactions. (See Cool Response to 7-Cent Fee on Virtual Transactions.)

— Suzanne Herel

May 26, 2015June 15, 2023

ISO-NE Prices Jumped 13% Last Year

By William Opalka

ISO-NE’s average real-time prices rose 13% to $63.32/MWh in 2014, the RTO’s Market Monitor reported Wednesday.

The 2014 Annual Markets Report said the increase was largely driven by higher fuel costs in the first quarter. Prices of natural gas, which was the marginal fuel for the RTO in 70% of the hours in 2014, rose 15% last year, to $7.99/MMBtu from $6.97/MMBtu in 2013. Electricity usage dropped 2% to 127,138 GWh.

“Overall, 2014 weather was milder compared with 2013, but the extreme cold in January, February and March and the resulting high natural gas and power prices were the main reason for 2014’s higher annual average power price,” Jeffrey McDonald, ISO-NE’s vice president of market monitoring, said in a statement. “Lower oil and natural gas prices, combined with mild summer weather that contributed to lower energy usage, and the implementation of several ISO market enhancements that helped improve both reliability and market efficiency, brought generally lower wholesale electricity prices during the rest of the year.”

The Monitor repeated a recommendation it has made since its 2010 report: that the RTO relieve virtual transactions from energy market payments — also known as real-time net commitment-period compensation (NCPC) charges — that it said is preventing virtuals from improving day-ahead market liquidity.

Last year, the RTO proposed a partial solution that would have excluded positive load deviations from real-time first contingency NCPC charges. The Monitor said the change would strengthen incentives for load-serving entities, exporters and virtual demand bidders to buy energy in the day-ahead market.

The proposal was unable to win stakeholder support and was not submitted to the Federal Energy Regulatory Commission. The RTO plans to start a new stakeholder process to reconsider the issue this year.

Total reliability payments, including NCPC charges, increased 10% to $173.7 million in 2014. About 62% of the payments stemmed from the need to operate more expensive generation during extreme cold weather in the first quarter.

The total value of the region’s wholesale electricity markets, including electric energy, capacity and ancillary services markets, rose about 12%, from about $8.8 billion in 2013 to about $9.9 billion in 2014. Electric energy comprised $8.4 billion of the total in 2014, up from $7.5 billion a year earlier. The cost of ancillary services jumped 50% to about $410 million.