Page 1312 – RTO Insider

March 17, 2017

MISO Changes MTEP Futures Weighting for South

By Amanda Durish Cook

CARMEL, Ind. — The futures assumptions for MISO’s 2017 Transmission Expansion Plan are finalized, with the RTO granting its South region a different future weighting in one study.

MISO will use a 40% weighting for an existing trends future, 40% for policy regulations future and 20% for accelerated alternative technologies when conducting its market congestion planning study, which this year is focused solely on MISO South. The other studies in MTEP 17 will continue to use a 31% weighting for existing trends, 43% for policy regulations and 26% for accelerated alternative technologies.

The RTO revisited the weighting in February in response to a request from stakeholders who noted the Trump administration’s plan to eliminate the EPA Clean Power Plan. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.)

“We went through a presidential election that changed a lot of things,” MISO Director of Policy Studies J.T. Smith said at a March 15 Planning Advisory Committee meeting. “There were some concerns that, given the political climate, maybe the futures — developed in mid-2016 — didn’t quite reflect what the current situation is.”

MTEP MISO market congestion planning study — J. T. Smith | © *RTO Insider*

Smith said the revisions are meant to reflect regional differences within MISO; he pointed out that MISO South transmission owners and the state regulators of southern states all asked for more emphasis on existing trends.

Both the Louisiana Public Service Commission and Arkansas Public Service Commission asked for existing trends to be given 50% consideration while policy regulations and accelerated alternative technologies receive 30% and 20% weighting, respectively. Entergy went a step further to request a 60% likelihood for existing trends, 25% for policy regulations and 15% accelerated alternative technologies.

All other MISO stakeholders that commented on futures weighting — including MISO’s coordinating, environmental and transmission developer sectors, the Iowa Utilities Board, the Indiana Utility Regulatory Commission, the Minnesota Public Utilities Commission, the Minnesota Department of Commerce, Big Rivers Electric, Midwest Power Transmission Arkansas and WPPI Energy — urged MISO to leave weighting as is.

“When we saw that regional separation, we realized that maybe there needs to be a change this year,” Smith explained, adding that the near-term nature of the market congestion planning study can better absorb a change in weighting and not affect other longer-term planning. The study is designed to identify projects to relieve congestion.

Going forward, Smith said he’d like to focus more on the probability that the generating fleet will change regardless of potential federal policy shifts. Development of MTEP 18 futures will begin at the June Planning Advisory Committee meeting, and Smith said it’s unlikely that MISO will allow divergent weightings in the next MTEP cycle.

“I still think we’re going through fleet change,” said Smith, who also admitted that “it’s uncomfortable when you change assumptions halfway through.”

Smith also said MTEP 17 weights would not change in MISO’s footprint diversity study, which is specifically designed to identify alternatives to using SPP’s transmission interface for flows between MISO South and MISO Midwest.

Some stakeholders said that conducting one MTEP study using separate future weighting is inconsistent. Others asked how MISO arrived at the altered weights. Smith said the RTO only considered comments from southern stakeholders when creating the new percentages and did not use any mathematical calculations.

Xcel Energy engineer Drew Siebenaler pointed out that most stakeholders that submitted comments on the futures supported leaving them as is. Noting that all MISO stakeholders pay for the MTEP process, he said MISO South should fund its own study if it wants to handpick assumptions.

Smith said Siebenaler’s concerns were valid and that MISO would work to improve the futures weighting process in the future.

Meanwhile, Arash Ghodsian, of MISO’s economic studies department, said the footprint diversity study and the market congestion planning study continue on track, with project candidates emerging in June. He said stakeholders submitted 58 project ideas for the market congestion planning study.

March 17, 2017

CAPS Hires EnerNOC Alum as Executive Director

By Rory D. Sweeney

The Consumer Advocates of the PJM States (CAPS) has hired former EnerNOC executive Gregory Poulos to replace retiring Executive Director Dan Griffiths. He will transition in as Griffiths, who is expected to depart by the end of the year, leaves.

Poulos had been at EnerNOC since 2010, rising from a manager to the director of regulatory affairs. EnerNOC provides demand response and energy management services for industrial clients. His role focused on demand response and energy-market development in PJM and MISO as well as in the states within the grid operators’ footprints.

Before EnerNOC, Poulos had stints as an assistant consumer counsel in the Office of the Ohio Consumers’ Counsel, and assistant chief of the charitable law section of the Ohio attorney general’s office.

Griffiths had worked for another DR provider, Comverge, before joining CAPS. Before Comverge, he spent seven years in the Pennsylvania Office of Consumer Advocate and 18 years at the state’s Public Utility Commission.

CAPS is made up of all state utility consumer advocate offices in the PJM region, an area spanning all or parts of 13 states and D.C. In his new role, Poulos’ duties will include being a constant presence at PJM stakeholder meetings. (See CAPS Leader Looking to Pass the Torch.)

In a news release distributed Wednesday, CAPS President Robert Mork, of the Indiana Office of Utility Consumer Counselor, cited Poulos’ “strong mix of experience and a deep understanding of the people and processes at PJM” as a major benefit for the organization.

“Dan Griffiths served our organization well as it began formal operations,” Mork said. “Hiring Greg represents the next major step as CAPS works with its members to ensure consumer interests are taken into account at PJM. Bills paid by the region’s consumers include billions of dollars in PJM charges each year, and effective participation in the PJM stakeholder process has become vital to ensuring reasonable prices and reliable power in each of our states.”

Poulos called the opportunity “a great honor” and noted the cooperative nature of the CAPS membership, despite their distance and often disparate interests.

CAPS got its initial funding from a 2012 FERC market manipulation settlement with Constellation Energy. Last year, FERC approved PJM’s creation of a funding mechanism to support the organization through a charge to residential electric customers. (See FERC Approves PJM Funding of Consumer Advocates.)

March 17, 2017

FERC Staff OKs MISO Mitigation Changes; Refunds Possible

By Amanda Durish Cook

With FERC staff’s hesitant nod, MISO will apply a more stringent physical withholding rule and remove demand response and energy efficiency from market monitoring in next month’s Planning Resource Auction.

The commission released a short delegated order March 15 that accepted and suspended MISO’s proposed changes subject to refund (ER17-806).

FERC Director of Electric Power Regulation Penny Murrell, using authority delegated to her in the absence of a FERC quorum, said the commission’s preliminary review had not concluded the changes were just and reasonable and that the tentative approval was subject to further commission order.

The order will allow MISO to apply a 50-MW minimum for physical withholding rules to affiliated market participants collectively, rather than individually to each affiliated company. MISO’s Independent Market Monitor had recommended the change in its 2015 State of the Market Report, saying that as “capacity margins fall in MISO, the market will become more vulnerable to physical withholding.”

FERC MISO physical withholding — | *MISO*

The order also allows MISO to exempt DR, EE and external resources from PRA mitigation measures. The RTO said DR and EE resources are too small to have market power.

The rules will “provide stakeholders with greater certainty, prevent large suppliers from circumventing MISO’s mitigation provisions and encourage the participation of demand resources, energy efficiency resources and external resources” in the capacity auction, the RTO said. (See MISO Plans Additional Capacity Auction Revamps for 2017.)

A third change will allow planning resources to request facility-specific reference levels for the auction.

Reference levels are used to determine a resource’s marginal costs, including risk and opportunity costs and technical characteristics for physical offer parameters.

In its filing, MISO said its Tariff is vague as to the types of resources that can obtain a facility-specific reference level rather than using defaults. The change will permit facility-specific levels for planning resources not otherwise exempted from market mitigation.

March 16, 2017

Opposition to Va. Tx Line May Trigger Unintended Consequences

By Rory D. Sweeney

PJM is responding to permitting delays for a 500-kV transmission line across the James River by instituting a multilayered strategy that could cost ratepayers in Virginia’s middle peninsula.

The Surry-Skiffes Creek line was proposed to maintain grid reliability on the peninsula after Dominion Energy complies on May 1 with an EPA mandate to shutter its two Yorktown coal-fired units. The project’s opponents are concerned the line would ruin the view at Jamestown and other historic sites nearby. A study conducted on behalf of the National Parks Conservation Association concluded Dominion overestimated projected power growth and called for consideration of other alternatives, including underwater lines and converting the Yorktown units to natural gas.

PJM yorktown transmission line — Proposed Yorktown pricing interface, which will expose ratepayers to high LMPs should the regional system threaten voltage collapse. | *PJM*

Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the U.S. Army Corps of Engineers. Dominion representatives have estimated construction of the line would take at least one year after all permits are approved.

Remedial Action Scheme

Opponents have dismissed as a scare tactic Dominion’s warning that failing to build the line could result in blackouts, but the company announced last month it has developed a remedial action scheme for the region that calls for dropping service to approximately 150,000 customers to prevent a potential voltage collapse from N-1-1 contingencies. (See Dominion Says Blackouts the Only Solution for Va. Peninsula.)

At a series of committee meetings last week, PJM staff detailed several other changes for the area that will have consequences protesters likely haven’t imagined.

Paul McGlynn, PJM general manager of system planning, announced at the Transmission Expansion Advisory Committee meeting that the RTO has offered Dominion a reliability-must-run contract on the units starting on April 1 and continuing until either the transmission line is constructed or another reliability solution materializes.

PJM calculated that 44% of the costs for retaining the units would be allocated to Dominion’s Virginia Electric Power and Power Co., with nearly 10% each to American Electric Power’s East zone and Commonwealth Edison.

At the Market Implementation Committee meeting the day before the TEAC meeting, PJM staff presented its new Yorktown pricing interface, which will set real-time LMPs if demand response or other load-management resources are deployed. It would be triggered on a sub-zonal basis when thermal or voltage conditions are encountered that create N-2 or N-1-1 contingencies.

At the meeting, PJM’s Independent Market Monitor Joe Bowring took issue with the plan because it allows DR to set regional prices “well above any level that generation can set it” — potentially as high as $1,800 MWh. Prices in the region are usually around $40/MWh. The interface would only be modeled in the day-ahead market if conditions are known prior to market close, and it won’t be modeled for financial transmission rights auctions.

“It’d be one thing if DR were nodal and were dispatched with the same offer caps,” Bowring said. “In a sense, the core issue is that DR can have a price and set price at $1,800 or more.”

March 16, 2017

In Appreciation of Ted Caddell 1960-2017

By Rich Heidorn Jr.

CARY, N.C. — RTO Insider the publication has lost its wittiest voice. RTO Insider the company has lost its centrifugal force, its welcome wagon, its sage, its ultimate team player and certainly part of its soul.

Ted and his granddaughter, Charlotte in February. His comment on Facebook on the photo: “I have NO idea why this child is crying. Honest!”

Ted Caddell, RTO Insider’s longest-serving staffer — and the voice of our daily emails and frequently our social media postings — passed away overnight Tuesday, hours after helping to cover the ISO Summit here. He was 56.

Ted, who formerly lived in Wilmington, Del., and Charlottesville, Va., moved to Chapel Hill, N.C., about five years ago, following his companion, Leslie. He picked me and RTO Insider co-founder Merry Eisner up from Raleigh-Durham International Airport on Monday night. We then ate dinner with him and Leslie in Chapel Hill, where he told us how he would not eat shrimp that wasn’t North Carolina wild — no farm-raised seafood for him!

I ordered the North Carolina shrimp, and was not disappointed.

On Tuesday, he took photographs and reported on the opening session of the RTO Insider/SAS ISO Summit with PJM CEO Andy Ott, SPP CEO Nick Brown and former FERC Commissioner Tony Clark.

We expected him Wednesday morning for the second day of the summit and were concerned when he did not appear. While I was moderating the first panel of the morning, Merry got a phone call informing us of his passing.

Merry informed me of the news during a break, and I was on stage for a second panel when my phone rang with a call from Charlottesville, where I knew his brother Ray — a bandleader for whom Ted had previously worked as a roadie — lived. I handed the phone to Merry to take the call.

Since the Summit ended, I have been back in my hotel room, letting the tears flow and trying to pull myself together enough to help compose a tribute worthy of the man.

I have known Ted since the late 1990s, when I was covering electric deregulation for The Philadelphia Inquirer, and Ted, a former reporter for The News-Journal in Wilmington, was a spokesman for what was then Conectiv Energy, a Delaware-based subsidiary of Pepco Holdings Inc. There are good, bad and mediocre spokespeople, and Ted was undoubtedly one of the best. Funny, personable, self-deprecating. Even if it wasn’t a big story, I never remember a day that wasn’t better for having talked to Ted.

We hired Ted at RTO Insider in January 2014, less than a year after our launch. But I wouldn’t actually meet Ted in person until about a year later, when he was in Wilmington visiting his daughter Nicole and newborn granddaughter, Charlotte.

Ironically, as we joked over dinner Monday, we had covered the same story for our competing newspapers in 1996: the execution of Billy Bailey in Delaware, the last hanging in the U.S.

At RTO Insider, we have made it a priority to hire reporters near the headquarters of all of the ISOs and RTOs in the U.S. In Chapel Hill, Ted was nowhere near any of them. But he nonetheless made himself immediately indispensable as the first editor of our Briefs columns and as the lead reporter on many breaking news stories. He was particularly knowledgeable about generation, having done public relations for Exelon’s generation unit after leaving Conectiv.

As he wrote for his bio on our About Us page, Ted had an English literature degree from the University of Delaware, “which may explain why he’s also worked as a commercial fisherman, a roofer, landscaper and spent three years as a roadie for a swing band and orchestra.”

Ted the roadie, second from right, with Rat Pack impersonators. | *Photo courtesy Ray Caddell*

In January, when we launched our daily email alerts, he was our voice, and he had an immediate impact. Some people, frankly, did not appreciate his witty “lead-in” and preferred to go right to the summaries of our latest content. A handful of people were offended when he got a bit risqué or political.

They were in a decided minority. More common were comments like these:

I read five or six energy newsletters a day, which are typically quite boring. The daily opening commentary of RTO Insider’s newsletter is incredibly entertaining and I look forward to reading it every day. — Nick Esch, Smart Electric Power Alliance

Ted, thanks for really taking the “readability” factor up a notch! I look forward to your musings every day. — Joe Leingang, fuel & transport superintendent, Basin Electric Power Cooperative.

I just wanted to say that I truly enjoy Ted Caddell’s summary emails each day. I always love the random other news he provides. It’s quite hilarious. — Jen Clements, Xcel Energy

I love the changes that RTO Insider has made this year. I look forward to reading the quips and punchy, but newsworthy, introductions each day. I also enjoy that it’s not always related to our industry — a teaser of sorts before getting into the day’s news. — Tia Elliott, NRG Energy

Hey — I don’t know who comes up with these little nuggets at the beginning of the Insider. But I enjoy them tremendously. Thank you! — Marguerite Wagner, ITC Holdings

And here were the reflections of some of his colleagues:

From Bill Opalka, our former NYISO/ISO-NE correspondent, who just left us for a job with the New York State Energy Research and Development Authority:

Newsrooms are places that are full of characters, and in his day, Ted must surely had been one. He always had a quip at the ready and was full of oddball insights about the world, life and even the news. Although we were based 600 miles apart and never met face-to-face, I felt like I knew him better than most of the colleagues with whom I shared office space. He was that open and had a killer wit that got us through any crisis too.

But underneath the jokester façade, Ted was a serious newsman always looking for the next story and ready to jump in when colleagues were busy chasing other news. He’d often call with the latest scoop: “Did you hear about the Massachusetts pipeline? What’s going on at Indian Point?” And most of the time I’d reply, “Thanks, Ted, I’m already on it,” and he’d seem a little crushed that he couldn’t help.

Ted, you’ll be missed.

From Julie Gromer, our current Briefs editor, who joined us in September 2016:

The impact that Ted had on my life in such a short time period is pretty incredible.

Words cannot express my sadness. When I joined RTO Insider, Ted was the first person to reach out to welcome me to the team — and to offer any assistance that I needed. Over the past seven months, he became my online friend — checking in every day to see how I was doing, sharing news of his family and grandchildren, laughing about world events, and always offering encouragement — both in my professional and personal life.

I feel honored to have known Ted. I will miss his friendship, his “can do” attitude and his unique brand of wit.

From Tom Kleckner, our SPP and ERCOT correspondent, based in Little Rock, Ark.:

I never met Ted in person (though our paths may have crossed at one point), but I felt like I did. That may be all you need to say about Ted.

We did share direct messages and Facebook posts, and had several long phone conversations. I know I would have enjoyed Ted’s company. Check out his Facebook photos. Unless he was acting on stage, he always had a smile on his face — and an unruly head of hair that apparently didn’t get along with caps.

Ted’s writing reveals that same good nature. He was always looking for the off-beat stories that helped show what our world is really about.

From retired account executive Marge Gold:

As I sit here with my eyes swelled up, it is hard to see clearly to even type. But, clearly Ted made me smile every time I saw him on our weekly video calls, with his Starbucks in hand. He was a unique man, that I will not soon forget.

From Michael Brooks, our production/copy editor and D.C. reporter:

Ted was just as friendly as he was funny — and he was hilarious. Unfortunately, I mostly experienced that friendliness online. The Internet enables a company like ours to function even though we live in different parts of the country, but because of that, I was only able to ever meet Ted in-person once. I am truly saddened that I will not be able to have another laugh with him that isn’t online.

Suzanne Herel, our former PJM correspondent, recalled his motto:

“Every day’s a holiday, every meal’s a feast.” I miss you dreadfully, Ted.

From MISO correspondent Amanda Durish Cook:

Whenever I approached Ted with a technical question, he’d make sure to weave some humor into the explanation. He just made it delightful. I always enjoyed collecting news stories to pass to him for the repartee.

From CAISO/WECC correspondent Robert Mullin:

With your co-workers spread across the country, you can miss out on some aspects of easy friendship that can develop with people you happen to share space with seven or eight hours a day. Ted was someone who sought to close that distance. When I started with RTO Insider, he would call just to check in, see how things were going. There was usually nothing specific to talk about, and during those conversations I learned a little about his life, his partner, Leslie, his kids, and his two young granddaughters Mayble and Charlotte — just a bit younger than my own son.

Let me direct my last comments to you, Mayble and Charlotte: your grandfather was sharp-witted, blunt, warm-hearted — irrepressible in his opinions, but thoughtful. Salt of the earth. I wish I could’ve had more time to get to know him better. I wish you could’ve, too. I hope you carry a little bit of him with you into the future.

Ted often returned to Wilmington to visit his daughter, Nicole Wample, and his beloved granddaughters, Mayble, 3, and Charlotte, who turns 2 on Friday. He is also survived by his partner, Leslie Udry; his mother, Sally, of Avon Park, Fla.; his older brother, Ray, of Charlottesville, Va.; and his son, Michael, of Philadelphia.

Memorial arrangements are pending. We will update this story when they are available.

“He loved his job,” said Ray. “It was good for him.”

He was good for all of us too.

March 16, 2017

CAISO Preparing Responses to Spring Oversupply

By Robert Mullin

CAISO market operators are preparing to deal with an inevitable flood of energy oversupply this spring, when unusually high levels of hydroelectric output are expected to compound the impact of growing solar penetration on the California grid.

One likely outcome: forced reductions in self-scheduled power deliveries throughout the season.

The ISO is already experiencing the effects of oversupply — in the form of economic curtailments — months ahead of the spring melt in the Sierra Nevada mountains, where snowpack in some areas stands at more than 175% of normal, according to the California Department of Water Resources.

“Altogether, [we] can see that wind, solar and hydro are making up a lot of generation in the first two months of the year,” Guillermo Bautista Alderete, CAISO director of market analysis and forecasting, said during a March 14 Market Performance and Planning Forum (see graph).

hydro solar spring oversupply CAISO — Hydroelectric output in CAISO this winter has already exceeded that for recent spring periods when California was subject to severe drought conditions. | *CAISO*

“If you just compare against the same profile for one year ago, you can see that we are well over the historical levels [for hydro] — and this is just January and February,” Bautista Alderete said.

And while hydro has so far been the biggest contributor to the mix, solar output will become an increasing factor, with the longer days and more intense periods of sunlight in spring and summer.

“The big story here is the year-over-year change that we’ve seen going back to 2013, when we didn’t have a lot of solar on the system,” said Gabe Murtaugh, a senior analyst with the ISO’s Department of Market Monitoring.

Murtaugh pointed out that 2015 was the first year in which large-scale solar became the most significant source of renewable power on the ISO system — with output last year surging again by 33% to more than 20,000 GWh as installed capacity climbed to about 9 GW.

That capacity figure doesn’t include rooftop installations, which the ISO estimates stand at 5 to 6 GW — or about 12 to 15% of average system load, according to Amber Motley, CAISO’s manager of short-term forecasting.

“Current solar capacity is capable of increasing oversupply risk without factoring in wind and hydro,” Motley noted in her presentation to the forum.

Based on that risk, the excessive solar, wind and hydro output on the horizon will translate into a significant number of curtailments by the ISO this spring. (See High Hydro, Increased Solar Point to Spring Curtailments for CAISO.)

The evidence is already coming in. Curtailments have been on the rise this winter, with about 60,000 MWh of solar output being cut off in February — the largest amount for any month since the beginning of 2016.

Bautista Alderete explained that, under its current staged approach to oversupply, CAISO first exhausts its regulation service, which ramps down output from participating resources, followed by economic curtailment of price takers in the market.

“You keep going through the bid stack to the point until you find the balance of supply and demand,” he said.

Once economic bids are spent, the ISO begins to curtail self-scheduled energy deliveries.

“So you exhaust your regulation before you cut into the self-schedules?” asked Seth Cochran, manager of market affairs and origination at DC Energy.

“This is something we’re going to revisit,” responded Mark Rothleder, CAISO vice president of market quality and renewable integration. “If, for short periods of time, we’re going into the regulation stack, it’s OK. If we’re persistently going into the regulation stack, that’s a problem.”

He said the ISO is considering reducing its reliance on regulation during oversupply periods, a move that would require more frequent curtailment of self-schedules.

Rothleder speculated that on a warm, sunny and breezy weekend day in the spring when hydro is spilling at a high rate, CAISO would move quickly through its bid stack of an estimated 1,500 to 2,000 MW of curtailable renewables and begin to confront reductions in self-schedules.

“The next question is: How far?” he said.

To illustrate the potential scope of reductions, Rothleder highlighted system conditions on the previous Sunday, March 12, when the ISO saw its net load (which represents total system load minus output for variable renewable generation) fall to about 10.9 GW with 15 GW of available generation. With a maximum of 2 GW of economic bids poised for curtailment, the balance, he said, would come from self-schedules.

Bautista Alderete said CAISO is seeking to be “proactive” in alleviating the oversupply problem, pointing to Motley’s work to improve short-term forecasting of oversupply conditions.

Motley has been seeking to discern indicators of potential oversupply in the day-ahead market.

One such indicator: negative pricing in the energy component of the LMP.

Another: a forecast of about 5 GW of renewable generation paired with a load forecast of about 25 GW — an average for this time of year — leaving a net load of 20 GW.

Even with no wind output, the 9 GW of solar on the system has the potential to push the system into oversupply under those load conditions.

Motley said historical hydro schedules, while factored into the forecast, will not be the most reliable indicators of oversupply because of the year-to-year difference in hydro conditions. Hydro operators are likely to have less flexibility to ramp down output this spring with increased flows.

The forecasts might occasionally compel the ISO to reach out to market participants outside normal market channels.

“On days when we go below 20,000 MW [in net load] on average, we may have a phone call [with scheduling coordinators] … to state our oversupply risks,” Motley said. “We don’t want to use those all the time, because some of these factors are going to be there every weekend, but when we see more extremes, we may use that coordination phone call.”

March 15, 2017

Connecticut Moves Closer to Equating Nuclear with Renewables

By Michael Kuser

Connecticut legislators on Tuesday unveiled a bill that would put the state’s only nuclear power generator, Millstone Station, on equal footing with renewable energy resources.

The bill would allow Dominion Energy’s Millstone to bid into the state procurement process now reserved for renewable energy resources such as large-scale hydropower, solar, wind and trash-to-energy facilities. The bill also would increase the share of Class I renewable energy in the state’s total energy production through 2040 by easy-to-remember increments: 20% by 2020, 29% by 2029 and 40% by 2040. It would mandate an additional 3% each year from Class I or Class II renewable resources, i.e., hydropower or trash-to-energy.

The General Assembly’s Joint Committee on Energy and Technology is expected to consider the bill, S.B. 106, on Friday along with related legislation, Raised Bill 7247, which aims to establish a carbon price for fossil fuels sold in the state.

The bill supporting Millstone revives a similar measure that passed the Senate at the end of last year’s legislative session, but which the House of Representatives did not have time to consider.

Connecticut lawmakers are riding a trend, as New York approved zero-emission credits for three upstate nuclear plants and Illinois did the same for two plants.

Three other states, New Jersey, Ohio and Pennsylvania, also are considering plans to subsidize their nuclear power generators, which have seen their profits squeezed by low-cost natural gas and renewable generators.

Millstone is New England’s largest power plant and has been owned by Dominion since 2001. The plant has a total generating capacity of 2,111 MW; Unit 2 at 882.5 MW is licensed to operate through 2035, while Unit 3, with 1,228 MW of generating capacity, is licensed to operate through 2040. Millstone produces more than half of the electric power used in Connecticut and about one-seventh of New England’s electric power.

Kevin Hennessy, Dominion’s director of state policy for New England, has been publishing op-ed pieces throughout Connecticut this year to make the company’s case that the proposed legislation cuts out the “middle man” and represents a good deal for state electric power consumers. In an op-ed in the New Canaan News on March 10, Hennessy said that current regulations result in power to consumers being priced high, despite wholesale prices having dropped notably.

“When oil prices drop, we all expect to pay less at the gas pump,” Hennessy said. “Why should electricity be different?”

The early draft of the legislation said its purpose was to provide a mechanism for zero-carbon electric generating facilities to sell power to electric utilities. Sen. Paul Formica (R), committee co-chair and lead sponsor of the bill, said it creates opportunities for the state to get its energy mix right.

“We’re trying to juggle and balance the pieces in the energy puzzle,” Formica told the Hartford Courant. Formica’s district includes Waterford, where Millstone is located.

Not All in Favor

Testifying on March 13 before the Assembly’s Environment Committee, Dan Hendrick, director of external affairs for NRG Energy, said, “One of the most hotly debated issues before the General Assembly this session is Senate Bill 106, which would create a new clean energy [request for proposals] and allow a large, existing nuclear plant to compete against wind and solar for the first time.”

NRG operates 28 generating plants in Connecticut with a combined capacity of 1,900 MW, of which 925 MW is natural gas and liquid fuel-capable. NRG this year joined Calpine, Dynegy and the Electric Power Supply Association in funding “Stop the Millstone Payout,” a campaign to derail the bill.

Hendrick reminded the committee that policies set in Connecticut will affect the other five states in the ISO-NE wholesale market. The RTO is trying to align the electricity markets and state policy proposals through the NEPOOL Integrating Markets and Public Policy (IMAPP) initiative.

“That being said, the three-state threshold of this bill reaches approximately 80% of the electricity load in ISO-NE,” Hendrick said, referring to a provision in the carbon price bill that requires the enactment of similar legislation in Massachusetts and Rhode Island. “Contrast this approach with Senate Bill 106, which would burden only Connecticut ratepayers with the extra costs of an RFP designed to provide unjustified additional revenues to a single nuclear generator.”

Opponents also question the need for state-sponsored financial aid to Dominion and Millstone.

“Nowhere has [Dominion] claimed that Millstone is not profitable, and the company is too cute by half in its arguments as to why it needs special treatment,” said Tom Swan, executive director of the Connecticut Citizens Action Group, in a March 8 letter to the editor of The Middletown Press. “Connecticut ratepayers should not be asked to subsidize a profitable company and we definitely should not weaken our commitment to a renewable energy future by reclassifying nuclear as ‘clean energy.’”

March 15, 2017

Stakeholders Call for Streamlining Federal Review of Projects

By Wayne Barber

Electric infrastructure projects, even those that promote renewable power, are often stymied by federal regulatory reviews that seem to drag on forever, witnesses told the Senate Committee on Energy and Natural Resources on March 14.

Many speakers called for a single agency to play a lead role in infrastructure permits, that the Energy Department should continue to play the lead role in grid security, rather than the Department of Homeland Security. They also called for more firm deadlines for decisions.

No one witness or senator, however, seemed to offer a silver bullet solution on how to speed up license approvals.

When asked about memorandums of understanding (MOUs) between federal agencies, Jeffrey Leahey, deputy executive director of the National Hydropower Association, indicated they can be helpful, but often the real roadblocks can be found in regional offices, not D.C.

surry-skiffes creek-whealton hydroelectric dams — Murkowski

Currently most hydroelectric dams don’t actively generate electricity, Leahey told Murkowski. While the hydro association supports the FERC MOU to increase the number of power dams, it doesn’t go far enough, he said. (See FERC, Corps Agree to Streamline Nonfederal Hydro Permits.)

Dominion Energy CEO Diane Leopold said some agencies go “pencils down” until another agency finishes work. She said that Dominion has had a slow-go winning approval for the Surry-Skiffes Creek-Whealton transmission project in Virginia.

“The long-term nature of large energy projects and the millions in private dollars required to execute them demand regulatory predictability to proceed,” Leopold said. Surry-Skiffes Creek-Whealton “is a prime example of the costs of delay to our communities and our national security.”

The transmission investment became vital after Dominion determined that retirement was the best course of action for two aging coal units at the Yorktown power station, Leopold said. PJM recently offered the company a reliability-must-run agreement for the units. (See “PJM Offers Four RMR Contracts,” PJM Planning & Transmission Expansion Advisory Committee Briefs.)

Pacific Power CEO Stefan Bird stressed the need for the utility’s Energy Gateway project, which it has been working on since May 2007. Bird also made the case for a strong federal role in tree trimming for grid reliability.

The Senate session marked the first congressional hearing about infrastructure during this session. The Trump administration has promised to present Congress with a major infrastructure plan.

“I am glad that President Trump has made infrastructure a national priority,” Chair Lisa Murkowski (R-Alaska) said. “I look forward to working with him, his administration as well as other members of the Senate to develop a broad infrastructure package,” Murkowski said. “And I certainly hope that package will include provisions that streamline the permitting process for all energy infrastructure projects.”

She added that it should not take 10 years to merely renew a license for an existing hydroelectric power plant.

“As the first two installments of the Department of Energy’s Quadrennial Energy Review have pointed out, we are facing several challenges that threaten to disrupt American’s access to reliable and affordable energy,” ranking member Sen. Maria Cantwell (D-Wash.) said in her opening statement.

“Our hydroelectric dams, power plants, electric transmission lines and pipelines are aging. And the pace of investments has not always been sufficient to keep these facilities in good working order,” she said.

March 14, 2017March 12, 2024

Overheard at the Infocast ERCOT Market Summit 2017

AUSTIN, Texas — Infocast gathered industry experts in the Texas state capital to share their insights on the “challenging times that lie ahead for ERCOT.” Panelists examined changing market rules, the impact of gas prices on generators, how the delivery of new wind and solar power will change market dynamics, and the revamping of ancillary service market rules during the sessions Feb. 27-March 1.

Donna Nelson, chairman of the Public Utility Commission of Texas, said the state’s competitive market has benefited from lessons learned in California, which opened its electric market to choice in 1998, four years before ERCOT did the same. That has helped the PUC, which oversees the Texas grid operator, to prepare for the 28.6 GW of wind capacity sitting in ERCOT’s interconnection queue.

“Right now, I’d say our market is working because we have a healthy reserve margin and we have fossil-fuel generation to cover [wind energy’s] variability,” Nelson said. “Over time, if that [wind] generation is built, we’ll have to look at what it takes to keep the fossil fuels on. There’s a tension between the workings of the competitive market and reliability. We’ve made a lot of adjustments to the market over time — we want to keep the lights on too — but we have to look at reliability from a short-term to long-term perspective. That’s something the commissioners will continue to watch.”

Nelson recalled a time when integrating 10,000 MW of wind power into ERCOT was considered an “iffy” proposition. “So here we are at 18,000 MW,” she said. “That’s a lot of investment, but lest you label me a renewable hater, it’s made because of the [Production Tax Credit]. When you see other forms of fossil fuel generation is not invested, you ask, ‘Why is that the case?’

“The PTC provides an incentive of $23/MWh. When you look at the average price of power in the ERCOT market, you can see an incentive of $23/MWh has the potential to distort the market,” Nelson said, noting the ERCOT market prices energy based on the amount of generation needed. “If wind bids in at a low price at night, that sets prices in the early morning hours. It’s gotten to the point where [the fossil-fuel plants] generate all their revenue in the summer. You’re going to see less and less of that. You’ll see wind lowering the price in the summer, as well.”

Over time, she said, that will lead to further retirements of fossil-fuel plants. “We won’t have the fossil-fuel generation to back up wind’s variability.”

Dealing with Low Gas Prices in the ERCOT Market

Several panelists discussed ERCOT’s low power prices, their effect on the generating fleet, and forecasts for the future. The ISO’s $24.64/MWh average price in 2016 was the lowest since the market opened in 2002. Natural gas accounted for almost 44% of ERCOT’s power last year, with coal accounting for 29%, wind 15% and nuclear 12%.

Bob Helton, Dynegy’s director of market design and policy for Texas, said he doesn’t expect to see much of a rise in natural gas prices any time soon. “We know the administration is not going to stop fracking … take that for a given. We’re going to have low [gas] prices in the future,” he said.

That will put further economic pressure on ERCOT’s coal units, which have been struggling to compete in the market.

“If prices are low, it’s cheaper to buy off the market … than burn our coal plants,” said John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy, which plans to retire 950 of its 2,300 MW of coal capacity in 2018. “We went through 54 days without burning a single lump of coal last year.”

While Bonnin also said “there’s still a place [for coal capacity] in the summer,” Potomac Economics’ Beth Garza, director of the ERCOT Independent Market Monitor, pointed out much of Texas’ coal fleet was built between 1975 and 1980.

“We’re now in 2017. That would seem to be an economically rational life span for many of these assets,” Garza said. “They’re going to run until something big breaks, and it just won’t get fixed.”

Manan Ahuja, senior director of North American power for S&P Global Platts PIRA, said nuclear units are also at risk in the ERCOT market. “Would these potentially be retired?” he said. “These nuclear units have not made money in the last couple of years. Reliability issues apart, we think the economics are certainly under threat, though they are down in the pecking order as compared to some coal and gas-peaking units.”

ERCOT: Not Really that ‘RUCed Up’

Garza’s recent comment that the Monitor considered 2016 to be “all RUCed up” came up again during the week, once by Garza herself. But were ERCOT’s reliability unit commitment activities — a near quadrupling to 269 “unit days” — last year really that egregious? (See “IMM Year in Review: Low Prices, Windy, Lots of RUC,” ERCOT Board of Directors Briefs.)

“I don’t get bent out of shape about the RUC activities,” said ERCOT COO Cheryl Mele. “I think the operators are doing a good job” reducing the impact on market prices.

“A lot of RUC is a sign the market is working very effectively,” said ERCOT’s Resmi Surendran, senior manager of wholesale market operations and analysis. “If we give the [RUC] instructions, we’re looking more holistically at the whole system. The ERCOT market design gives the right incentive to participate in the day-ahead market.”

Surendran said the ISO’s total net make-whole payments for the last five years has been almost $40 million — the same amount as PJM’s monthly make-whole payments. (However, PJM’s energy and capacity market has a peak load of 165 GW, more than double ERCOT’s energy-only 69 GW.)

Last year, $1.2 million in make-whole was paid to entities that were short generation and another $1.4 million clawed back from generators with offers in the day-ahead market.

While the number of RUC events still concerns Garza, she agreed the financials tell a different story. “Even with the [RUC activity] increase, the cost of doing that … seems to tell me that, yeah, we had a bunch of RUC activity, but I don’t think it was all that inefficient,” she said.

Wind Subsidies Distorting the ERCOT Market?

Appearing on a panel addressing “collapsing” power prices, NRG Energy Director of Regulatory Affairs Bill Barnes said ERCOT’s market is “energy-only in theory” and that “subsidized wind generation” is a problem.

“What we have in ERCOT is very different [from energy only]. It’s been released into the wild, and a lot of things are exerting influence over it,” Barnes said. “NRG invests in renewables. We believe in renewables, but those that stand on their own two feet. We’re beginning to see the impact of those subsidies on the market today.”

Hannes Pfeifenberger, a principal with The Brattle Group, argued combined cycle plants with low heat rates and improved technology have done more to depress prices than wind energy.

“We’ve seen technology costs being reduced so quickly that by the time the PTCs expire, these technologies will be in the market no matter what,” he said. “One thing we have to realize is that baseload will be less valuable in the future, no matter whether the PTC expires or not. More flexible plants will be a market outcome. We will see more retirements because gas prices will remain low.”

“There aren’t price signals right now to build [baseload] generation because we have excess reserves. That’s market 101,” said Katie Coleman, a partner with Thompson & Knight. “I agree with Bill that the PTC and the proliferation of wind is a problem. Anytime you introduce subsidies into a market, you have distortions. Potentially assigning some transmission costs to wind, assigning ancillary costs to wind … those are things I think merit further conversations.”

“This market can solve its problems,” said Philip Moore, vice president of development for Lincoln Clean Energy, who linked the low prices to natural gas and wind. “ERCOT has shown an amazing ability to address the oncoming wind and its own transmission problems very efficiently. ERCOT will find ways to accommodate the energy-only market.”

Solar Envy

While a potential flood of new wind energy has grabbed much of the attention, additional solar power is coming over the horizon, too. Charlie Hemmerline, executive director for the Texas Solar Power Association, said 2016 was the solar industry’s best yet, with 14.8 GW of additional installed capacity creating a 42.4-GW total nationally. Texas ranks ninth nationally with 1,215 MW of capacity.

ERCOT, which almost doubled its solar capacity to 556 MW last year, could see another 2 GW come online by 2021. “Twenty other states have significant solar activity, which means there’s heavy competition attracting people to the state of Texas,” Hemmerline said. “We’re in the mix, but we’re not leading the pack. Our real focus as an industry is to make sure we can make that happen. Our legislative ask of folks is to do no harm. Let’s not do anything to stop this investment or remove anything that would harm us along the way.”

Much of Texas’ utility-scale solar can be found in the wide-open spaces of West Texas.

“The thing we like at ERCOT about West Texas solar is it’s a time zone away from our load centers,” said Paul Wattles, the ISO’s senior analyst for market design and development. “If you’re generating in Pecos County at 2 or 3 in the afternoon, it’s serving peak load in Houston,” he said. “I think you will see more intelligent siting. I think you will see them to where they can make a lot of money during the critical part of the day.”

Residential solar is playing an increasingly large role in the market as well. Wattles said Oncor just passed 10,000 rooftops, thanks in part to what he calls “solar envy.”

“I hear Plano is going crazy” with installations, he said, referring to the Dallas suburb. “Those numbers are dwarfed by California, but it’s something that wasn’t there 10 years ago.”

“Solar envy is definitely a thing,” Hemmerline said. “As people see it, they want it too. [Residential solar] has been here a long time as a someday concept, but when you’re seeing more of your neighbors doing it, it’s propagating to where the costs make it a reasonable decision.

ERCOT is paying attention. “Solar is going to start commanding a larger share of the [distributed generation] fleet,” Wattles said. “My group is concentrating on the big stuff right now, but the little stuff is coming really fast.”

CREZ Project has Benefits, but Stability Issues

ERCOT’s Competitive Renewable Energy Zones (CREZ) project resulted in 3,600 miles of transmission carrying 18.5 GW of West Texas and Panhandle wind energy east to urban load centers at a cost of $6.9 billion. The wind industry’s growth also led to $38 billion in investment across 60 Texas counties and almost 23,000 jobs, according to Susan Williams Sloan, vice president of state policy for the American Wind Energy Association.

“It’s a testament that CREZ brought a lot of benefits to the state,” Sloan said, adding it has also yielded $60 million in annual lease payments to rural Texas landowners. “It’s a new crop for landowners, and allows them to have a passive income. Over the years, there’s even been some landowner wind associations formed to attract wind to their community.”

“We don’t have all our wind in West Texas anymore,” said Sharyland Utilities’ Bill Bojorquez. “We have wind in the south, in the Panhandle and coastal. We don’t have wind peaking at the same time of the day.”

Increasingly, that remote wind generation has led to some stability problems on the ERCOT grid.

“Traditionally, we saw thermal issues. That was the main thing we had to operate and plan around,” said Jeff Billo, ERCOT senior manager of transmission planning. Now, he added, “We’re seeing generation that’s more removed, and we’re seeing more asynchronous generation.”

Fossil Fuels Still Viable Alternatives

Golden Spread Electric Cooperative COO J. Jolley Hayden said his company is moving away from power purchase agreements to quick-starting gas units because of market dynamics. “As the markets get more robust, that’s the resource we’re looking at,” he said.

Using aircraft carriers (coal plants) and PT boats (quick starters) as images, Hayden said, “The big aircraft carriers … if they’re in organized markets, they’re struggling right now. They’re running, and they’re out of the money. The PT boats’ flexibility is essential. The more dynamic the market is, the more flexible you have to be to keep your costs low.”

Coal resources still have their supporters, however. Ingmar Sterzing, vice president of power supply and energy services for Pedernales Electric Cooperative, said coal plants “absolutely” still provide a benefit and their potential value is not priced in the market.

“It’s physical fuel that’s available at the plant, with a supply of 45 to 60 days. That’s unlike any other resource in ERCOT except nuclear,” Sterzing said. “If you’re really in a pinch, coal is there and it’s available. It’s very reliable. Once those coal plants are gone, it’s going to be very difficult to bring them back. You try permitting a new coal plant, and it’s eight to 12 years. You’re going to be stuck with a limited set of options.”

Customers More Informed, Still Hard to Move

Mark Bruce, one of the architects of Texas’ competitive market and principal with Cratylus Advisors, said he is “tickled pink” to see his vision become reality. “The stakeholders wanted to empower customers to become more efficient and make their own decisions,” he said.

But challenges remain.

“We’re seeing sluggish [load] growth. Efficiency is creeping in as customers get more information. They are putting their own generation behind the meter, using storage, getting familiar about time of use. There are more bears in the woods. Our old models don’t fit with the way this is going.”

Michele Gregg, director of external relations for Texas’ Office of Public Utility Counsel, reminded attendees not to forget about retail customers. “We need to remember customers want to spend very little time on electricity,” she said.

“We spend a lot of time in industry meetings talking about what innovation they need … what the customers want and reducing load. The average customer has no idea what load is. They get a bill once a month, they know that bill is too high. In the retail market, the [retail electric provider] is the only one they want to do business with.”

The bills may be high, but the customers still tend to stick with their legacy providers. TXU Energy, which dominates north and central Texas, has seen its rate of departing customers drop from 8% in 2010 to 1% in recent years.

Asked how he would crack the TXU and Reliant Energy legacy markets, Andrew Elliott, director of supply and portfolio management for ENGIE Resources, did not have a ready answer.

While the residential market is not his primary focus, Elliott offered up a story involving his mother-in-law. He said he tried to explain to her she had her choice of retail electric providers, but she would have none of it. “‘This is my electric company. I’ve always paid them.’

“We would love to have the rollover customers,” Elliott said, before repeating the original question. “So how do you crack the TXU-Reliant legacy customers? I don’t know.”

Ancillary Services’ Future in ERCOT

Austin Energy’s commitment to participate in ERCOT’s ancillary services market is a challenge because of the ISO’s average prices, said Kahlil Shalabi, the municipality’s vice president of energy market operations and resource planning.

“[ERCOT’s] pricing is … much different than any other market,” Shalabi said. “If you look at the past month here in Austin, the price dips down close to zero in the morning, then goes all the way up to $18 [per MWh] in the afternoon. If you’re lucky, it goes up to $500 once a month for 15 minutes.

“We’re not looking at future ancillary services pricing for future resource decisions,” he said. “We do see price separation between our load zone and the rest of ERCOT. We want to use our generation to protect our customers when those price spikes happen.”

“The robustness you see in Cal-ISO and PJM with advanced technologies and storage is due more to acceptance by those markets, rather than prices,” said John Fernandes, who left RES for Invenergy after the summit as its director of regulatory affairs. “Those ISOs are setting up constructs that draw developers to those markets. When a system operator chooses to modernize the system to play to the strength of advanced technologies, that generates as much interest as price alone.”

That is why Duke Energy Renewables’ Thomas Paff, manager of RTO/ISO coordination, said his company is not yet buying storage in the ERCOT market.

“We do have some battery systems in PJM where it’s totally different than the outlook here,” he said. “We are making money, but it’s really not that much.”

March 14, 2017

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM’s Asanga Perera came to last week’s Market Implementation Committee meeting prepared to seek forgiveness. But instead of mea culpa, his message was: “Help Wanted.”

PJM’s Tariff requires that it post monthly financial transmission rights auction results within five days, but a series of emails to stakeholders made it clear that wasn’t going to happen this month. PJM was eventually able to post the solution on March 1, and all paths were awarded for the full period.

That said, Perera noted this is the second time in as many years that results of the March auction have been late. An analysis found three contributing factors. Bid volumes and transmission outages played a role, he said, but the major issue was overlapping periods.

Every quarter, four auction periods occur simultaneously, stretching PJM staff and resources to their limits. Perera noted that some staff worked throughout the night to make even the relaxed deadlines. In March, the markets for March, April, May and fourth-quarter auctions are available. The other months with four open periods are June, September and December.

Perera solicited stakeholder feedback, noting that the issue may impact approval of residual auction revenue rights.

In other FTR news, PJM said it will file Tariff changes documenting its new FTR forfeiture rules by April 19. The rules will be retroactive to Jan. 19 — the date of FERC’s order finding PJM’s current rules not just and reasonable — once the appropriate tool is built. The new approach will include several tests to determine the FTR’s impact. Additionally, the forfeiture is only for FTR profits. PJM plans to discuss FTR thresholds and review related Tariff and manual changes at the April MIC meeting. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)

PJM will also be bringing for endorsement next month revisions to Manual 6 to conform with FERC’s FTR compliance order in January, along with other compliance directives.

Vitol Accepts Simplified Solution to Spot-In Issues

Vitol’s Joe Wadsworth, who has urged PJM for years to rectify issues with its spot-in transmission service procedures, said he is willing to accept a smaller revision that would better align daily timelines for when the service is granted.

Wadsworth had been campaigning for a much more sophisticated market-based solution that would apply only to the NYISO seam. The Independent Market Monitor objected that any changes to border operations should apply to all seams. (See “Spot-in Transmission Analysis Expanded to all Interfaces,” PJM Market Implementation Committee Briefs.)

“I always hate to surrender, but I don’t think it makes sense to pursue [the more-sophisticated plan], especially if PJM doesn’t support it,” Wadsworth said. “But there’s significant room for improvement there, not just on the issue I’ve raised but on other issues too.”

He said the challenge with stakeholder leadership — in this case, on cross-border issues — is trying to wrangle both grid operators. Although he said the issue deserves a more comprehensive look by NYISO and PJM, PJM wouldn’t support NYISO’s requirement that it distribute any costs it incurs to PJM stakeholders. The grid operators have been unwilling to proactively address the issue without his insistence, Wadsworth said.

PJM agreed that the issue deserves a closer look.

“It’s tough to say there’s not things to improve there,” said PJM’s Adam Keech, who oversees market operations. “To the extent that stakeholders wanted to take a look at the issue, I would probably say we should look at all the interfaces and not just New York.”

Calpine’s David “Scarp” Scarpignato asked about the prudence of making seams changes without acknowledgement from the other grid operator. PJM’s Chris Pacella, who has led the analysis on the spot-in issue, said PJM has changed its internal procedures — deadlines in this case — and not heard back from NYISO about any problems.

Suction Level Revisions Endorsed Despite Stakeholder Reluctance

Stakeholders approved by acclamation amendments brought by the Independent Market Monitor to a problem statement and issue charge to address minimum tank suction level (MTSL) costs. The vote was quick even after NRG Energy’s Neal Fitch pointed out that the issue was likely considered when annual revenue requirements for black start units were initially discussed.

Left to right: PJM’s Asanga Perera, Chrissy Stotesbury, and Chantal Hendrzak | © *RTO Insider*

“I have to believe this topic was discussed then, so why are we discussing it again?” he asked.

PJM’s Tom Hauske explained that, under the current rules, generators can over-recover their costs for keeping the fuel available. (See “PJM Looking to Avoid Lump-Sum Billing on New Black Start Units,” PJM Market Implementation Committee Briefs.)

The Monitor provided an illustration of a generator with a fuel tank capacity of 4 million gallons and an MTSL of 800,000 gallons, 48,000 gallons of which is the black start portion.

PJM’s original method would allow recovery of the carrying costs on the full 800,000 MTSL, while the Monitor would allow recovery of costs for only 48,000 gallons. “The actual incremental amount of MTSL that results from the addition of black start capability is zero,” the Monitor explained.

Hauske also presented an updated issue matrix for the initiative on annual revenue requirements for new black start units. “At this point in time, I think we’re pretty close” to consensus, he said.

NOPR Analysis: Uplift Bad, Fast Start not Good

PJM staff gave the MIC their analyses of recent FERC Notices of Proposed Rulemaking, making clear they have some strong opinions. Regarding the NOPR on uplift, PJM’s Rebecca Stadelmeyer said the RTO doesn’t support it.

Asked if she could explain why, she said: “Absolutely, I’d love to. I thought we might skip right over that.”

FERC’s first proposal would create two categories for real-time uplift costs associated with deviations: systemwide and congestion management, and charge uplift only in accordance with cost-causation principles. Stadelmeyer said it could be done, but that PJM doesn’t support any parts of the NOPR. (See “Members Approve Uplift Proposals,” PJM Markets and Reliability and Members Committees Briefs.)

More important, Stadelmeyer said, was FERC’s second proposal to distinguish between helpful and harmful deviations and allocate uplift only to harmful ones.

“We’ve continuously said that we cannot find a non-subjective way to isolate whether those deviations help or harm the system,” she said.

There was also some disagreement on the intentions of the NOPR. DC Energy’s Bruce Bleiweis said it stated “fairly strongly” that costs should be allocated to load.

“That wasn’t our read,” Keech said. “If they wanted it to be allocated to load, they probably would have said that.”

On the fast-start NOPR, PJM appeared largely indifferent until it came to relaxing the eco-min of fast-start resources. Doing so “will likely create significant over-generation concerns,” PJM wrote in its presentation. The change could exacerbate already complex uplift allocation methods. (See FERC: Let Fast-Start Resources Set Prices.)

“No analysis could be indicative or identify what the tradeoff would be,” PJM’s Lisa Morelli said. “It would not be a wash. There would likely be a difference between the uplift paid to fast start and the [lost opportunity cost] of resources.”

FirstEnergy’s Jim Benchek asked her to guess at which would be higher, but she said she wouldn’t. Citigroup Energy’s Barry Trayers said that it appeared that much of FERC’s opinion came from a “MISO foundation,” along with lessons learned, when other ISOs/RTOs might have more robust and efficient procedures.

The Monitor largely agreed with PJM’s opposition. “[For] those of you who haven’t read our comments, we think the NOPR is a terrible idea,” Bowring said. “We don’t think the solution is to change the definition of fast start. We think the appropriate way to handle this is to think of it as a tradeoff.”

– Rory D. Sweeney