PJM Transition Auction Means Reprieve for Exelon Nukes

By Suzanne Herel and Rich Heidorn Jr.

VALLEY FORGE, Pa. — Capacity Performance resources cleared at $151.50/MW-day in the transition auction for the 2017/18 delivery year, PJM said Wednesday, calling the results “demonstrably competitive” at nearly $60/MW-day below the RTO’s price cap.

The results meant at least a temporary reprieve for Exelon’s Quad Cities and Byron nuclear plants, which cleared the transition auction after failing to clear in the Base Residual Auction for 2017/18. Exelon said Thursday morning that all of its nuclear plants in PJM cleared in the transition auction and that the company will defer any decisions about the future of Quad Cities and Byron for one year.

PJM held the auction Sept. 3-4 to obtain CP resources for 70% of the updated reliability requirement for 2017/18, procuring its target of about 112,195 MW, said Stu Bresler, senior vice president for markets. The clearing price cap was $210.83/MW-day, or 60% of the net cost of new entry.

Bresler said the results showed “a very steady, very rational progression of clearing prices given the steadily increasing proportion of our reliability requirement that we procured as Capacity Performance for these three delivery years.”

The RTO-wide clearing price was $134/MW-day for the 2016/17 transition auction, which obtained 60% of total requirements as CP. (See PJM 2016/17 Transition Auction Clears at $134/MW-day.)

The transition auction for 2017/18, which cleared $17.50/MW-day higher, procured 70% of total requirements. Neither transition auction had locational restraints.

In the Base Residual Auction for 2018/19, where 80% of resources were CP, most of the RTO cleared at $164.77.

New Generation in COMED, ATSI Zones

Total capacity offered into the 2017/18 transition auction was 133,769 MW. Of the capacity that cleared, 102,178 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price.

About 10,000 MW of the CP that cleared were from resources that did not clear in the Base Residual Auction in 2014, less than 9% of the total.

Bresler said most of the newly cleared generation was in the COMED (almost 4,000 MW) and ATSI (more than 2,300 MW) zones.

“I think it was fairly well publicized after the Base Residual Auction for ’17/18 the resources that did not clear,” he said. “It just speaks to those that were available to do so in this particular auction from those zones. And I think that’s what we saw.”

PJM reported that 4,339 MW of nuclear cleared for the first time in the transition auction.

Exelon confirmed that Byron Units 1 and 2 (2,336 MW) and Quad Cities Units 1 and 2 (1,737 MW) in Illinois, which did not clear the BRA for 2017/18, were among the winners this time around. (See How Exelon Won by Losing.)

The company said Thursday that it will continue operating Quad Cities through at least May 2018. Byron is already obligated to operate through May 2019. It said it will bid all its eligible nuclear plants, including Quad Cities, Byron and Three Mile Island into the 2019/20 BRA next year.

“While Quad Cities and Byron remain economically challenged, we are encouraged by the results of the recent capacity auctions. The new market reforms help to recognize the unique value of always-on nuclear power, while preserving the reliability of our electric system,” Exelon CEO Chris Crane said in a statement. “However, these plants are long-lived assets with decades of useful life left, and today’s decision is only a short-term reprieve. Policy reforms are still needed to level the playing field for all forms of clean energy and best position the state of Illinois to meet [the Environmental Protection Agency’s] new carbon reduction rules.”

The company said it will “continue its dialogue” with Illinois policymakers for state support for the nuclear units.

New Coal Also Clears

Some 4,165 MW of coal-fired generation also cleared for the first time in the transition auction.

In total, coal cleared 37,455 MW; gas 35,298 MW; and nuclear 29,970 MW.

Higher percentages of energy efficiency (almost 28%) and demand response (65%) came from new rather than previously cleared resources. Of 700 MW of DR acquired, 455 MW represented new commitments.

“I can’t really speculate on the drivers there,” Bresler said. “My hypothesis, I guess, would be that these demand response providers have since the Base Residual Auction for ’17-18 found additional resources that could provide the Capacity Performance level of reliability and therefore offered those resources into the auction.”

$1.7 Billion Increase

The Base Residual Auction for 2017/18 — held in 2014, before the introduction of the tougher CP requirements — cleared at $120/MW-day in most of PJM, with the PSEG locational deliverability area at $215. (See Capacity Prices Jump Following Rule Changes.)

The incremental cost of the transition auction was $1.7 billion, below the estimate of $3.1 billion to $4.2 billion PJM and the Market Monitor had predicted, Bresler said.

Independent Market Monitor Joe Bowring declined to comment on the results aside from saying that they were consistent with the rules. He said his office is working on a comprehensive report on all three CP auctions.

Walter Hall, of the Maryland Public Service Commission, said his agency is keeping an eye on how the prices will affect consumers. “Obviously, it’s going to increase prices somewhat,” he said. “That is a negative. It is a problem, but it’s a problem we knew was coming.”

Dan Griffiths, executive director for the Consumer Advocates of PJM States, said he still had to review the numbers.

But, he said, “I don’t think our position has changed, that this was an extremely excessive solution to the problems we faced.”

PJM, he said, “never considered the impact on consumers.”

Higher Risks, Rewards

The Capacity Performance construct allows capacity resources to receive higher prices in exchange for taking on stiffer penalties for non-performance.

The transition auctions, part of a five-year shift leading to 100% CP for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order.

Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.

The RTO’s 2018/19 Base Residual Auction, the first BRA under the CP rules, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.

CP resources were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)

September 1, 2015

Timing of PJM Auction Announcement Sparks Real-Time Debate

By Rich Heidorn Jr.

CAMBRIDIGE, Mass. — PJM’s 2016/17 transition auction results were released shortly after the stock market closed at 4 p.m. Monday — coincidentally during an EUCI conference in Cambridge, Mass., that attracted PJM Market Monitor Joe Bowring, PJM Senior Economic Policy Advisor Paul Sotkiewicz and Jim Wilson, a consultant to consumer advocates in the RTO.

Wilson, a featured speaker, reported — critically — on the results shortly after they were released, sparking a lively debate with Sotkiewicz. Bowring, uncharacteristically, declined to offer an opinion.

“Unfortunately, the way [PJM] ran the auction, instead of paying people $10, $20, maybe $30 [per MW-day] to upgrade their capacity commitment to Capacity Performance, they created a new clearing price of $134/MW-day, paid to everybody,” Wilson said.

“Of the 95,000 MW that cleared, almost all of it was in the RTO region and not in [MAAC], and they were able to go from $60 their previous clearing to $134. They basically get a $60 windfall — or about $1.7 billion,” Wilson said, concluding: “Very inefficient.”

That sparked a response from Sotkiewicz, who had appeared on an earlier panel with Bowring — both of them already aware of the results but sworn to secrecy until their release.

Sotkiewicz said that during the January 2014 polar vortex, “a lot of [the high generator outages were] coal resources in the west, gas generators in the west who were behind the [local distribution company] city gate who had no firm transportation to the city gate. Even if they did, they could be curtailed by the LDC. [They] also didn’t have dual-fuel capability.

“So, quite to the contrary, a lot of the problems that we did see were in the west during January. So to say that [the CP acquired was] in the west and it’s useless I think is disingenuous and incorrect.”

Asked for his opinion on the “efficiency” of the auction after the conference ended, Bowring seemed uncharacteristically tongue-tied, pausing and exchanging glances with Sotkiewicz.

“We’ll be doing a report on it fairly soon and have a detailed analysis,” he said finally. “It’s hard to tell just looking at the prices. We reviewed the outcome. The outcome was consistent with the rules.”

September 1, 2015

PJM Stakeholders Struggle for Consensus on Offer Cap

By Suzanne Herel

WILMINGTON, Del. — Stakeholders will continue to debate changing the $1,000/MWh energy offer cap at a special four-hour Markets and Reliability Committee meeting called for Sept. 9, but few who weighed in on the issue at last week’s meeting were hopeful that consensus would be reached before the RTO’s board makes a unilateral filing with FERC as early as October.

One proposal, presented by Marji Philips of Direct Energy, would raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers — 50% more than the highest offers reported by PJM last winter.

Independent Market Monitor Joe Bowring offered an approach that would allow cost-based offers to exceed $1,000/MWh when short-run marginal costs of a unit top that cap. Market- or price-based offers would have to be less than or equal to such cost-based offers.

“The IMM approach addresses the issue of market power when the overall market is tight,” Bowring said. “That is essential — to address market power — when modifying these rules, which were implemented to address market power concerns.”

Old Dominion Electric Cooperative backed a plan presented in November to the Members Committee that would allow cost-based offers up to $1,800/MWh and permit them to set LMPs.

David “Scarp” Scarpignato of Calpine said a group of suppliers also is drafting a proposal “to help get the discussion going even further” that is expected to be brought to the next Market Implementation Committee.

PJM Backs Proposal

PJM said last month that it would support the Direct Energy proposal. In March, the RTO proposed a $2,700 cap on price-based offers and removing the cap on cost-based offers in a FERC docket on price formation (AD14-14). (See PJM Stakeholders Seek ‘Miracle’ to Break Offer Cap Standoff.)

The effort to raise the cap is intended to ensure that gas-fired generators can recover costs above the cap when fuel prices spike during periods of extreme temperatures, like the polar vortex of 2014. That January, FERC granted a temporary waiver allowing make-whole payments for costs incurred above the $1,000/MWh cap. In January 2015, FERC granted the RTO another waiver that allowed it to compensate generators for offers of up to $1,800/MWh, but PJM made it through the winter without having to invoke it.

PJM’s Board of Managers asked stakeholders to make another attempt to reach consensus after efforts last year fell short.

Philips told the MRC the board wouldn’t wait forever for stakeholders to reach agreement. “The PJM board told stakeholders they were going to file something if we couldn’t get our act together. The last time we did that it was called [Capacity Performance]. As talented as the PJM staff is, we didn’t want them filing for us.”

Philips said the Direct Energy proposal contained “generous” numbers in a “desperate attempt to bring generators on board.”

She said the proposal would create “rational, transparent pricing. … Everyone’s a winner because the market produces the right results.”

Day-Ahead vs. Real-Time

Joe Wadsworth of Vitol said he supported the philosophy of the proposal but was concerned about having different rules for the day-ahead and real-time markets. “I would want to further explore: Does this present a market design issue? … Will having different offer caps have any adverse effects?”

Philips said the difference was justified. “There are very few reasons your gas prices should pop if you are chosen by day-ahead dispatch,” she said. “In real-time we’re willing to have no cost-cap on bids,” as long as everything is reviewed by the Market Monitor, she said.

Susan Bruce, representing the PJM Industrial Customer Coalition, urged caution.

“It is a daunting prospect here to think of two months and redesigning the energy market,” she said. “Our primary concern is market power being exercised during times of high demand. … That has to be addressed in order for us to get comfortable with it.”

John Farber, a staff member of the Delaware Public Service Commission, questioned the benefit to consumers of reducing uplift.

“Uplift serves as a circuit-breaker function for consumers that is worthwhile,” he said. “Bypassing that by putting all the costs in the LMP … the benefit is doubtful to consumers.”

Philips noted that because uplift is not hedgeable, it must be captured in risk premiums.

She also expressed frustration with members saying they appreciated her effort but hadn’t had time to consider the proposal.

“You’ve had over three weeks,” she said. “Coming here today and saying you’ll consider it — that’s a ‘no’ vote. You haven’t had a chance to think about it? We have one month, and you’ve had it for nearly a month.”

‘No Incentive to Compromise’

Gloria Godson of Pepco Holdings Inc. said the board’s intention to make a unilateral filing undermined the stakeholder process.

“The lack of willingness to negotiate is a sad commentary on what happens when the board steps in on issues like this,” she said. “There’s no incentive whatsoever for you to discuss with any other person if you like what the board plans to file. It breaks down the discussion — there is no incentive to compromise.”

Outgoing PJM CEO Terry Boston, ever an outspoken supporter of consensus, urged members to hash out the issue.

“We had this conversation last year, and summer’s almost gone and winter’s coming on,” he said. “We were sitting at this same place last fall, and it is a serious issue.

“I made this comment last year: The California energy crisis was a financial crisis first. … I think we have to get to a point where people know their costs are going to be recovered. It is not something that can just wait on the table, because of the potential of it causing a financial crisis.”

September 1, 2015

Breezy Projections for Wind in MISO — Even Before CPP Blows In

By Chris O’Malley

ST. PAUL, Minn. — Registered wind capacity in MISO is projected to rise 50% by the end of 2019 — and that’s not even counting more turbines likely to sprout due to the Clean Power Plan.

MISO’s wind capacity has grown to about 14,000 MW, from 1,200 MW in 2005. Wind represents about 13% of MISO’s installed generation capacity — higher than the 7.5% for nuclear power but still well below that for coal and natural gas.

By 2019, based on its generation interconnection queue, MISO expects to have about 21,000 MW of wind in service.

“The growth of wind has been really, really steady, actually, over time. Projections continue to show similar growth as we experienced over the last five years,” Joe Gardner, vice president of forward markets and operations services, told the Markets Committee of the Board of Directors last week.

MISO officials said it’s too early to tell how the wind projections will change as a result of the Environmental Protection Agency’s final carbon emission rule, released last month. But “it’s going to be a lot bigger,” CEO John Bear said.

While MISO expects 25 GW of wind will be needed to meet existing state renewable portfolio standards, EPA’s modeling assumes the RTO’s wind portfolio will grow to 40 GW, said Claire Moeller, executive vice president of transmission and technology.

Forecasting Improves

Gardner told the board that staff is continuing efforts to improve its forecasting of wind availability, which he said is already “best in class.”

“On any given day we could have close to zero megawatts of wind … and on other days we can have 11 GW of wind. And from one day to the next you can have a swing of 6 or 7 GW,” Gardner said. “So it’s very important to try to get [the forecast] accurate. The more accurate the forecast is, the better our unit commitment is going to be and the lower our production cost is going to result and the more reliable we’re going to be.”

MISO staff uses an hourly forecast that looks seven days into the future in the reliability unit commitment process and to evaluate outage requests.

A five-minute forecast that extends six hours is used in real-time economic dispatch and look-ahead unit commitment. It also uses wind generators’ own forecasts in economic dispatch, although those are available for only about one-third of wind farms.

Gardner said MISO’s day-ahead wind forecasting accuracy has improved by about 2.5 percentage points since 2009, reducing the error rate to about 5%. The improvement is due in part to the incorporation of weather-prediction modeling; MISO added a fourth weather model in the second quarter.

Gardner said that’s better than the estimated error rate of other grid operators, including PJM’s 4 to 8% error rate, ERCOT (8%) and CAISO (10%).

“Does this forecasting accuracy give you comfort … that we’re not seeing drastic, unexpected shifts in the wind in a short period of time that causes impacts to reliability because of ramping capability in other units in the system?” Board Chair Judy Walsh asked Gardner.

“[It’s] not a huge amount of risk,” Gardner replied. “It’s not so much because of how accurate our forecast is. I think it’s more a result of geographic diversity and where the wind is located.”

He also said MISO plans a number of additional forecasting enhancements, including improved distribution of locational wind forecasts and replacement of vendors whose forecasts have persistent errors.

Solar Outlook Needed

Forecasting also will be needed to accommodate the rise of solar power generation. Gardner said an in-front-of-the-meter solar project is expected in MISO’s footprint in 2017. “So we’re preparing to be able to forecast that and I expect there will be some more [solar] beyond that,” he said.

September 1, 2015April 8, 2025

MISO Seasonal Procurement, Site Auctioning Proposals Face Opposition

By Rich Heidorn Jr.

ST. PAUL, Minn. — MISO officials last week outlined proposals to boost its capacity resources, winning some support for efforts to streamline the generator interconnection process and redraw its zonal boundaries to reflect constraints.

But its proposal to switch from annual to seasonal procurement ran into stiff opposition from the Independent Power Producer and Power Marketers sectors, and states balked at a proposal to replace the interconnection queue with the auctioning of generator sites.

Jeff Bladen, executive director of market design, presented the resource adequacy “straw proposals” — the result of stakeholder meetings that began in February — at a meeting of the Advisory Committee. (See MISO Stakeholders Call for Seasonal Resource Construct; Cool to Mandatory Capacity Market.)

“We don’t have consensus, which shouldn’t surprise everybody, but I think we’re getting very good input,” CEO John Bear said afterward.

Seasonal Procurement Idea Receives Push Back

Bladen said the proposal for seasonal procurement was driven by concerns over the year-round availability of resources such as demand response and generation imports. Bladen said seasonality was one of the top three concerns cited by stakeholders in discussions.

“It goes well beyond demand response. There’s lots of different resource types that have either limitations in terms of the times of year they can offer to commit to MISO or have limitations in terms of the economics of how often they want to be available. Examples might include … imports from other regions that might need to be committed to the other region in some parts of the year.”

Mitch Myhre of Alliant said he was “supportive of what MISO has proposed so far.”

Exelon’s Marka Shaw, of the Power Marketers sector, questioned the need for the change, saying there is a greater need for a long-term price signal to incent generator construction.

“You may have solved a problem with Canada and may have created a problem with PJM because the PJM market doesn’t have a seasonal construct,” she said.

Representing the Independent Power Producer sector, Dynegy’s Mark Volpe agreed, calling PJM MISO’s “most important seam.”

“They’ve got an annual construct there, and [seasonal procurement in MISO] would seem to be at odds with talk of trying to converge capacity products,” he said.

Bladen noted that MISO’s just-in-time capacity procurement is already different from PJM, in which resources commit three years in advance.

“It’s hard to see how that would preclude resources from making the same kinds of decisions in the future that they make today on whether to commit to PJM three years in advance or to think about committing to MISO,” he said. “The perspective we’ve taken so far is having a better price signal that reflects the real loss-of-load expectation in the seasons might actually draw resources to” MISO.

Representing the Public Consumer sector, Nancy Campbell of the Minnesota Department of Commerce backed MISO’s initiative. “We don’t think that the seams issue should [prevent] going forward with the seasonal resources. In fact maybe that’s something we should encourage PJM to do as well.”

NRG Energy’s Tia Elliott, of the IPP sector, questioned why MISO was citing the 2014 polar vortex as justification for the change after saying it was not sufficient for changing the day-ahead energy schedule. “I think that MISO might be talking out of both sides,” she said.

John Moore of the Sustainable FERC Project also supported the effort, saying winter wind should have a higher capacity factor than the year-round 14.7% it is currently assigned.

“In MISO, a 13 to 14% annual capacity factor for wind, and also a relatively low capacity factor for solar, just doesn’t make sense to us. Where wind does very well it’s higher than that. So we think that a seasonal construct would help address that and bring more value to the resources that are out there.”

Calpine’s Brett Kruse said that NYISO and ISO-NE incorporate seasonality in their capacity procurement, with “pros and cons.”

But he said it would do little to make MISO more attractive to generators. “If you honestly think this is going to help with price signals on the capacity side, I got $100 that I’ll bet you right now that it doesn’t do anything,” he said.

The discussion gave Market Monitor David Patton an opportunity to offer a plug for his recommendation that MISO adopt a sloped demand curve similar to that used by PJM and recently adopted by ISO-NE.

Referring to Kruse’s comment in an earlier discussion about the potential for some combustion turbine owners to move them from MISO, Patton said, “It sounds crazy, but it’s not.”

Patton said seasonality wouldn’t necessarily reduce overall capacity costs but could allow efficiencies for owners of some older generators who would like to reduce plant staffing during shoulder months. “Those are good cost savings because they don’t cost other generators money,” he said.

Bladen said the discussion will continue at Thursday’s meeting of the Supply Adequacy Working Group, where stakeholders will discuss how many seasons to consider.

“We haven’t gotten into the details of what the makeup would be: whether it’s a single auction; whether it’s multiple auctions that are prompt; whether it’s two seasons or more than two seasons. We’ve tried to stay a little bit above that at this point, with a recognition that we will need to tackle that,” he said.

State Officials Wary of New Zonal Boundaries

MISO’s proposal to establish local resource zones based on physical constraints also sparked some opposition, even after RTO officials promised any new zones would respect state boundaries.

Michigan Public Service Commissioner Sally Talberg, representing the Organization of MISO States, said OMS favors keeping the existing zones.

Several speakers, including Indiana Utility Regulatory Commissioner Angela Weber, said they feared basing zones on physical limitations would result in “volatility.”

Chris Plante of Wisconsin Public Service Corp. said the Transmission-Dependent Utilities sector does not have “perfect alignment” in their position on the issue. But he said the sector did agree there is a problem in using “snapshot” power flow analyses to determine zones, because new generation, retirements, new transmission and loop flows can impact the results.

“Our concern is if you try to design those zonal boundaries based on those constraints every year, you’re going to have stakeholders coming to you and saying we need to redraw the boundary because something has changed,” he said. “We see already with the [capacity import and export limits and loss-of-load expectations]. They vary from year to year — sometimes dramatically.”

Dynegy’s Volpe said, however, that much of that volatility is due to recent improvements in LOLE analysis, including the lowering of the threshold from 230 kV to 100 kV. “We haven’t had stability in the ground rules around the LOLE study,” he said.

Patton said while the uncertainty caused by continually changing zonal boundaries can be “damaging,” price changes that signal shifts in the supply-demand balance are valuable.

“Defining interfaces that create potential deliverability problems [that] may bind or may not bind … has a huge benefit over a structure like in New York where you’re continually fighting about … whether you’re going to define a new zone.” Failing to define zones consistent with physical transmission limits can result in not purchasing enough capacity on the right side of the constraint, he said. “So you’re exposing yourself to resource adequacy or transmission security problems that would potentially have been easy to avoid if you just quantify how much capacity you have to have on this side of the constraint versus that side of the constraint.”

Patton said creating additional zones to reflect state boundaries is not a problem. “You can’t have too many zones. If you define zones you don’t need, they just don’t bind and the prices equilibrate. The idea that Amite South and WOTAB are not separately recognized as places where we need generation seems really hard to justify.”

Stakeholders Agree on Need to Reduce Interconnection ‘Churn;’ States Oppose Auction of Generator Sites

MISO’s call for reforms to the generator interconnection process drew wide support, but its proposal to replace the interconnection queues with the auctioning of pre-qualified generation sites drew opposition from Indiana’s Weber, who said auctioning might undermine state jurisdiction.

Dehn Stevens of MidAmerican Energy said the Transmission Owners support measures to reduce “churn.”

“There’s nothing more frustrating than to have something like three of every four projects we look at as owners … never actually get built,” he said. “It’s a very inefficient use of our internal resources.”

“If you’re providing cost certainty to a generator that’s interconnecting, but the costs differ [because of other generators dropping out of the queue], you can be basically moving costs onto the transmission owner or its … customers.”

Beth Soholt of Wind on the Wires said she was concerned that MISO proposals to increase the cash at risk for those in the generation interconnection queue could be a barrier to entry.

“In each queue reform process, we have put different mechanisms in place for the different milestones. So we’ve gone from really a portfolio option, or a smorgasbord of options, for interconnection customers on readiness — site control and the whole raft of things they can do to prove readiness to move through the queue — we’ve really gone to [requiring] a large pile of cash at risk.”

Soholt added that wind developers are willing to put more cash at risk if it leads to more certainty about costs of transmission upgrades they would be required to pay. “But that certainty has been elusive through several rounds of queue reform,” she said.

Next Steps

MISO and stakeholders will refine the seasonal and locational proposals in joint meetings of the SAWG and the Loss of Load Expectation Working Group through December with hopes to make changes effective for delivery year 2017/18.

The interconnection changes will be discussed by the Interconnection Process Task Force with a projected implementation in August 2016.

MidAmerican Energy’s Stevens said MISO’s timeline is “very aggressive” for such large changes.

“I would question the supposition that the sky is going to fall in two or three years with the reserve margins. I think we saw in this last update [to the MISO-OMS survey] that the shortfall moved out a year or two. Sure seems like you might see that again in a year that the shortfall is moved out,” he said. “You are going to be better served getting it right and having fewer than 150 people fighting you at FERC.”

September 1, 2015

FERC’s Clark: Energy Markets Need Tweaks, not Overhaul

By Rich Heidorn Jr.

ST. PAUL, Minn. — FERC Commissioner Tony Clark said last week that the commission has “a sense of urgency” to take action on price formation issues after initiating an inquiry into the subject more than a year ago.

“There’s active discussion going on on the 11th floor [of FERC headquarters] right now with regard to different options,” he said during remarks at the MISO Board of Directors meeting.

Clark said the commission could take action to improve price transparency and reduce uplift but that he is skeptical of the need for major change.

“The thing about the energy markets that’s not lost on any of us is they are our best operating markets. They tend to work quite well,” he said. “Personally I don’t think we need to upset the whole apple cart.”

The commission opened a docket to consider rule changes regarding uplift, price caps and related issues as a result of comments made at technical conferences on capacity markets and the grid’s response to the January 2014 polar vortex (AD14-14).

It closed comments in the docket in February, following a technical conference last September. (See PJM Under Scrutiny at FERC Uplift Hearing.)

Queue Reform

Clark said the commission also may open an inquiry on generator interconnection and queue reform.

“In the 15 to 16 years I’ve been on a regulatory commission, this issue never seems to go away,” he said. “But it does seem like it’s an opportune time for the commission to do one of these periodic checkups” to examine best practices.

“I don’t know how dramatic the reform effort will be or what it might take shape as, but it seems like it’s a good time to at least be opening an inquiry as to how things are going,” he continued, adding, “That’s more of a future topic; we’re not at the decision-making stage by any means.” (See related story, MISO Seasonal Procurement, Site Auctioning Proposals Face Opposition.)

September 1, 2015

PJM Members Committee Briefs

WILMINGTON, Del. — Nominations are being accepted for the fall elections that will fill a number of positions on the Members, Finance and Nominating committees.

Representatives from each of the five sectors are being sought to serve one-year terms on the Nominating Committee. The target for identifying nominees is Oct. 1, with a vote scheduled for the Oct. 22 MC meeting.

PJM General Counsel Vince Duane cautioned members that the Nominating Committee positions will involve a heavier workload and travel as the RTO is conducting searches to fill several executive vacancies.

For the remaining posts, the deadline for nominations is Nov. 1, with a vote set for the Nov. 20 MC meeting.

Four seats are expiring on the Finance Committee, one each for the End Use Customer, Generation Owner, Other Supplier and Transmission Owner sectors.

Positions also are available for five sector whips, who serve one-year terms.

Finally, a nominee from the End Use Customer sector is being sought to take on a one-year term as vice-chair.

ODEC FTR/ARR Proposal Falls Short

A last-ditch effort by Old Dominion Electric Cooperative to redesign the financial transmission rights and auction revenue rights processes fell just short of a two-thirds consensus Thursday, garnering 66.08% of the sector-weighted vote.

The proposal was backed by most members of the End Use Customer, Transmission Owner and Electric Distributor sectors but won support of only one-third of the Generation Owner and Other Supplier sectors.

The vote was so close that a single additional ‘yes’ vote from Generation Owners, who voted 5-10 against the motion, would have put it over the top. Three more ‘yes’ votes from Other Suppliers, who voted 18-36, would have done the same.

The proposal was brought to the MC after also failing to win over the Markets and Reliability Committee, where it received 59% support at the July 23 meeting. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)The plan contained three elements.

One, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, would have escalated current ARR results using a zonal load forecast growth rate of +1.5%. The other two elements would have changed the method of reporting the monthly payout ratio so that any negative target allocations would be included as revenue, slightly increasing the reported payout ratio. It also would have treated each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.

The vote included a friendly amendment that would have required a report after no longer than three years of implementation on the effectiveness of the 1.5% factor.

Tariff Changes Approved Unanimously

Members unanimously approved three sets of rule changes:

A Tariff revision instituting previously endorsed fees for proposed transmission projects. Beginning next year, PJM will charge $5,000 to study greenfield or upgrade proposals of between $20 million and $100 million and $30,000 for projects costing more than $100 million. The fees will be implemented on a two-year trial basis. (See “PJM Lowers Proposed Tx Project Study Fee” in PJM Planning Committee Briefs.)
New Tariff language that aims to more accurately reflect how PJM processes requests for merchant network upgrades. The changes address definitions, queue entry, agreements and the capacity market.
The first and second batches of revised definitions in governing documents developed by the Tariff Harmonization Senior Task Force. Also approved was an amended liability provision that clarifies the definition of PJM net assets. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

— Suzanne Herel

September 1, 2015

MISO Proposes $2.4 Billion in Transmission Projects

By Chris O’Malley

ST. PAUL, Minn. — MISO staff will seek board approval in December for about 352 transmission projects totaling $2.4 billion in its 2015 Transmission Expansion Plan.

That’s virtually the same dollar amount as MTEP 14, but this year’s plan includes more baseline reliability projects and what could be the first competitively bid market efficiency project.

The largest of the projects in MTEP 15 is Entergy’s controversial $187 million Lake Charles, La., baseline reliability project to accommodate an industrial upswing in the gulf region. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

The market efficiency project ranks fifth in cost at an estimated $67 million to $72 million. MISO is considering three alternatives to relieve congestion in southern Indiana, with PJM as a potential partner. MISO Vice President for Transmission Jennifer Curran told the Board of Directors’ System Planning Committee last week that a request for proposals could be posted in January, with developer proposals due in July. (See Southern Indiana Transmission Project Keeps Morphing.)

Another significant portion of MTEP 15 is a bundle of 13 transmission upgrades identified in the voltage and local reliability study to reduce costs in MISO South. Estimated at $300 million, the projects should produce $498 million in 20-year net present value benefits by decreasing the need for uneconomic generation in load pockets such as Amite South and WOTAB, MISO executives told the board.

More Baseline Projects

While the total price tag for MTEP 15 is nearly identical to MTEP 14 — a coincidence, RTO officials said — the complexion of projects differs significantly. Proposed in MTEP 15 are 91 baseline reliability projects totaling $1.2 billion, compared to 50 projects totaling $177 million in 2014.

Projects driven by local needs are fewer in MTEP 15: 251 for a total of $1 billion versus 312 projects for $1.6 billion in MTEP 14.

The big difference was the inclusion in MTEP 14 of the $676 million 500-kV Great Northern transmission line, built in response to a long-term transmission service request from the Manitoba border to the Iron Range in Minnesota.

Interregional Planning

Curran also updated the board on the status of interregional planning efforts, which have shown mixed results.

She acknowledged that at least two of three potential MISO-SPP interregional projects earlier touted to offer $235 million in benefits are now “uncertain to unlikely.”

Curran said the two projects now look less attractive in part because of differences in how the two RTOs modeled the impact of the Environmental Protection Agency’s Mercury and Air Toxics Standards. MISO applied MATS retirement assumptions about SPP generation in the MISO model, but SPP did not have the same retirements show up in its model. (See 2 of 3 MISO-SPP Seams Projects Likely Doomed.)

“There are also differences in the amount and type of generation added, leading to a larger net addition of future generation in the interregional models when compared to the MISO regional models,” MISO spokesman Andy Schonert said. “The magnitude, type and location of these future units can lead to increased transfers and resulting differences in congestion levels at seams, which impacts the projected value associated with certain transmission projects.”

Potential interregional projects with PJM also were pared down.

In June, the RTOs narrowed the list of “quick hit” flowgate projects to two, from 39 in March. Among the survivors is the proposed resagging of the Northern Indiana Public Service Co. section of the Michigan City-La Porte 138-kV line.

The nearly $10 million in congestion relief for the finalists is a big reduction from the $408 million in potential congestion relief that the 39 projects initially identified could have brought. However, Curran told the board that MISO officials found that 22 of the flowgates had already been included in other planned or currently in-service projects.

September 1, 2015

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — PJM expects to spend $280 million in 2016, a $3 million increase over 2015, including $36 million on capital projects, according to a preliminary budget presented last week.

The spending plan will result in a composite expense charge of 32.9 cents/MWh, a rate that has remained consistent for the past five years.

About $28 million of the capital projects budget is dedicated to upkeep and enhancement of current applications, systems and infrastructure.

Another $5 million will be spent on new products and services, including the technology to support intraday bidding. The remaining $3 million will go toward interregional coordination, such as coordinated transaction scheduling with MISO.

The Finance Committee is set to consider the budget on Oct. 1 before it goes before the Board of Managers on Oct. 15.

Revisions Will Reveal Closed-Loop Interfaces Earlier

The committee endorsed manual revisions requiring PJM to announce the creation of closed-loop pricing interfaces five days before the close of the next financial transmission rights auction. The rules make an exception for outages of less than 10 days and those setting prices for demand response under current manual and Tariff rules.

PJM uses such interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems. (See “Package Calls for Notice on Pricing Interfaces” in PJM MIC Briefs.)

Changes Pave Way for Transition to Markets Gateway

Members endorsed revisions to the Operating Agreement and Tariff reflecting the transition from the eMarket tool to Markets Gateway. Training on the new tool is expected to be held in the second half of this year.

Change to Manual 37 OK’d

The MRC endorsed changes to Manual 37: Reliability Coordination that modify section 2.4.2 (Change management process), replacing references to the Change Control Review Board with the Enterprise Change Management Standard. The standard ensures that changes to PJM business application systems, programs, data, systems software and hardware are authorized and applied so as not to compromise the stability and security of any information technology component.

They also update the definition of system operating limits (SOL) to make clear that PJM controls to the most conservative limits and that interconnection reliability operating limits (IROL) are an elevated level of SOL, not distinct from them. The changes also clarify what SOLs and IROLs are monitored by the RTO, as well as SOL violations reporting.

— Suzanne Herel

September 1, 2015

Markets Committee Briefs

ST. PAUL, Minn. — MISO, SPP and intervenors in the dispute over MISO’s use of SPP transmission to deliver power between its northern and southern regions have begun circulating drafts of a settlement amid optimism that it will be filed with FERC in October (ER14-1174).

Discussions on how costs paid to SPP will be allocated within MISO will begin in September “on a separate track,” Eric Stephens, deputy general counsel, told members at the MISO Informational Forum last week. Stephens said confidentiality rules on the settlement talks prevented him from discussing specifics of the deal.

But Market Monitor David Patton told the Markets Committee of the Board of Directors later that the settlement will allow MISO to eliminate use of its $9.57/MWh “hurdle rate” in determining whether to allow more than 1,000 MW of power flows between its two regions.

“We need to make sure that’s the case, but I think the team at MISO did a good job of moving the settlement in a direction that allows us to do that,” Patton said.

MidAmerican Energy’s Dehn Stevens told the Board of Directors meeting later that the Transmission Owner sector is “very comfortable with where [the settlement is] at.”

Organization of MISO States President Libby Jacobs told the board that her group is “very optimistic that there’s resolution on the horizon.”

“OMS would encourage that to be rapidly finished so that everyone’s focus can be on other issues,” she said.

In spring 2014, MISO began limiting flows between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contract path.

While seeking to resolve the dispute with SPP, MISO implemented a $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.

Patton: Fear of FTR Gaming over WAPA Integration Hasn’t Materialized

Patton told the Markets Committee that his staff has seen little evidence to confirm fears that SPP’s integration of the Western Area Power Administration (WAPA) could give market participants an opportunity to game the market by buying financial transmission rights from SPP “whose value predictably would change significantly” following the integration.

“We didn’t see a lot of participants engage in strategic FTR purchases the way we had thought they would,” Patton said.

He said his staff is continuing to review how SPP’s dispatch including WAPA affects MISO’s constraints in the FTR market and market-to-market process.

“We don’t have significant concerns, but it is a significant change because WAPA stretches from the Dakotas down to the southern end of SPP. It’s a huge change in their configuration. You can think of it as similar to our integration of MISO South.”

“So, no red flags, just continued vigilance?” asked Director Michael Curran.

“Yes,” Patton replied.

— Rich Heidorn Jr.