Page 1361 – RTO Insider

March 14, 2017

PAR Wars: A Struggle for Power

By Rory D. Sweeney

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

March 14, 2017

MISO Resource Adequacy Subcommittee Briefs

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

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

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

MISO Resource Adequacy Subcommittee — Robinson | *RTO Insider*

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

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

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

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

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

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

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

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

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

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

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

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

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

IMM Offers Own PRA External Zone Design

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

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

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

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

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

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

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

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

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

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

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

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

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

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

MISO Examines Single Year of MISO-SPP Settlement Allocation

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

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

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

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

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

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

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

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

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

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

MISO Wants Deferral Year to Create Queue Withdrawal Penalty

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

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

— Amanda Durish Cook

March 14, 2017

Texas PUC Wary of Using ERS to Avoid Local Blackouts

By Tom Kleckner

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

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

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

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

Price Suppression Concerns

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

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

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

SCED Integration?

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

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

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

RMR Alternatives

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

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

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

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

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

Co-Optimizing

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

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

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

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

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

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

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

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

The PUC also:

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

March 13, 2017

AWEA: Wind to Grow 40% by 2020 Despite Loss of CPP

By Ted Caddell

U.S. wind industry jobs and generating capacity will grow by more than 40% by 2020, despite uncertainty over the Clean Power Plan, according to a study released last week by the American Wind Energy Association.

In fact, said AWEA CEO Tom Kiernan, President Trump’s vow to undo the Obama administration’s bid to cut power plant carbon emissions could be good news for the wind industry in the short run.

AWEA wind production tax credit — Suzion S88 Wind Turbines at Dry Lake Wind Project in Arizona | *AWEA*

“If anything, [the death of the CPP] may accelerate” the pace of wind energy construction over the next few years, as projects attempt to beat the expiration of the production tax credit (PTC), Kiernan said.

Kiernan’s comments came during a news conference Thursday at which AWEA presented a Navigant Consulting study that predicts that wind generators, who ended 2016 with 82 GW of nameplate capacity, will add another 35 GW by 2020.

The study also predicts the number of Americans working for wind companies or in their supply chain will grow from the current 102,500 to 147,000. The number of direct wind energy jobs grew 17% in 2016, according to the study.

A two-thirds reduction in costs since 2009 has helped drive the industry’s growth, AWEA said.

But some of the incentives the industry currently enjoys could be imperiled. The PTC, extended by Congress in 2015, will be phased out over three years, terminating at the end of 2019.

Tax credits drove a lot of the industry’s success, Kiernan acknowledged. “The policy certainty provided by the 2015 production tax credit phase down has allowed the industry to make long-term investments in the American workforce and manufacturing to further bring costs down,” he said.

Navigant said its projections were based on the assumption that the CPP, which also encouraged wind energy growth, would be stricken.

Energy Secretary Rick Perry oversaw a doubling of wind capacity in Texas when he was governor, but it’s unclear how much he could do for the industry in his current role.

Kiernan said land leases associated with wind projects will add up to about $1.2 billion in the next five years, benefiting farmers and ranch owners, making wind “a cash crop.” The average land lease, for two turbines, comes out to about $6,000 a year.

March 13, 2017

Differences Persist over OMS-MISO Survey Improvements

By Amanda Durish Cook

CARMEL, Ind. — MISO will roll a 35% share of the capacity from resources sitting in the definitive planning phase of its interconnection queue into the annual resource adequacy survey conducted with the Organization of MISO States — over the objections of some stakeholders who seek inclusion of a greater portion of capacity.

The survey currently counts only future resources that have already executed a generator interconnection agreement.

Indianapolis Power and Light’s Lin Franks said MISO’s 35% completion estimate is too conservative, especially when considering projects submitted by state-jurisdictional utilities that are obligated to serve load and whose projects might be more reliably completed than other queue entrants. (See Stakeholders, MISO at Odds over Resource Adequacy Survey.)

“You know the damn thing is going to be built — it needs to be included” in the survey, Franks remarked during a March 8 Resource Adequacy Subcommittee meeting.

She also warned of the “self-feeding” problem of developers entering the queue long before they are certain that a resource will be constructed — the product of long queues.

Franks suggested that MISO examine rates of withdrawal based on resource type.

“If you don’t take a look at which resources are withdrawing, you don’t have a transparent picture,” she said. “You’ve got to be more transparent and not convince people that the sky is falling.”

Madison Gas and Electric’s Gary Mathis said he did not see evidence of stakeholder advice in MISO’s proposed improvements.

“This issue has been around for a number of years, and MISO has been aware for a while of the improvements that are needed. … Certain projects in the queue will be realized,” he said. “I’m disappointed that we didn’t come further, and I question whether we were listened to in this process.”

The RTO says it will consider adding more resources in other phases of the queue as it carries out queue reforms.

Darrin Landstrom, MISO’s resource forecasting adviser, said the terms “committed” and “potential” will replace the “high certainty” and “low certainty” descriptors currently used for resources in the queue’s definitive planning phase.

Bonnie Janssen, a Michigan Public Service Commission staffer, said OMS could additionally include a “probable” category. MISO will send out questionnaires by March 31, with detailed results expected to be released in June.

Laura Rauch, manager of resource adequacy coordination, said MISO can provide stakeholders with mockups of survey results at the April RASC meeting.

RASC Chair Chris Plante plans to present MISO and stakeholder differences over the survey’s improvements to the Board of Directors during its March 23 meeting.

March 13, 2017

Report Shows Continued Losses in CAISO CRR Auctions

By Robert Mullin

CAISO last year paid out $47 million more to congestion revenue rights holders than it took in from its auctions, the ISO’s internal Market Monitor has found.

That deficit — a persistent problem since the ISO instituted CRR auctions five years ago — could buttress the Monitor’s call for ending the auctions, which it says allows financial speculators to reap hundreds of millions of dollars at the expense of California electricity ratepayers. (See CAISO Monitor Proposes to End Revenue Rights Auction.)

“The [Department of Market Monitoring] believes that the trend of revenues being transferred from electric ratepayers to other entities warrants reassessing the standard electricity market design assumption that ISOs should auction off these financial instruments on behalf of ratepayers after the congestion revenue right allocations,” the Monitor said in its quarterly market issues and performance report covering the fourth quarter of last year.

The Monitor’s suggestion: Replace the auction with a bilateral or exchange market for contracts-for-differences for pairs of ISO nodes — also known as locational basis price swaps.

Under that arrangement, swaps would be traded among willing counterparties, rather than leaving ratepayers as unwitting parties in a market in which they are outmatched by more sophisticated traders, the Monitor says.

CAISO management has responded to the Monitor’s concerns by agreeing to consider a stakeholder initiative on potential changes to the auction, a move that has been met with mixed reactions from market participants. (See CRR Initiative Elicits Mixed Reviews from CAISO Participants.)

Proposal Unwarranted?

“While I don’t believe DMM’s latest findings warrant their specific proposal to replace the CRR auction with a bilateral market or locational price swaps … I think the CAISO’s study is absolutely an opportunity to make improvements to the current CRR auction and identify practices and transparency issues that may be causing some inefficiency in the CRR auction pricing,” Carrie Bentley, a principal with Resero Consulting, told RTO Insider.

Bentley’s firm frequently works on behalf of the Western Power Trading Forum (WPTF), an energy trader interest group that opposes the suggestion to scrap the auction. It has called the proposed stakeholder initiative a “pet project” of the Monitor.

The Monitor’s most recent findings show that last year’s CRR deficit increased by $1 million over 2015, with auction revenues representing just 68% of CRR payments made to auction participants, compared with 73% during the previous year.

While total payments to auction rights holders declined 15% to $147 million, auction revenues also fell 21% to $99 million year over year.

Financial traders last year took in $33 million from the auctions, paying 63 cents for every dollar made from their CRRs. Their overall take was down 30% from the previous year, but it still represented the largest share of all participants. The Monitor has contended that “purely financial entities” are the main beneficiaries of the auction program.

Power marketers saw their auction profits increase by 43% to $10 million, while generator profits fell by 29% to $5 million.

Load-serving entities, which CAISO provides an annual allocation of CRRs, made about $3 million from rights they sold into the auction, down sharply from $14 million earned the previous year.

CAISO CRR auctions — CAISO’s congestion revenue rights auction revenues have consistently come up short of payments to rights holders, leaving ratepayers to foot the difference. | *Q4 2016 Report on Market Issues and Performance, March 6, 2017; CAISO Department of Market Monitoring*

Transmission congestion dropped last year as drought conditions resulted in decreased electricity use for moving water supplies across California. Transmission usage also was undercut by growth in behind-the-meter rooftop solar.

The fourth quarter saw the resumption of the prevailing pattern of CRR payments outpacing auction revenues, following a short-lived surplus during the third quarter (see chart).

WPTF Comments

In comments filed with CAISO earlier this year, WPTF contended that auction revenues increased as a percentage of payments in the third quarter after the ISO implemented practices that improved transparency into how it represents transmission outages in its market models.

“I think the fourth-quarter results were due to unexpected transmission outages and nomograms [prediction tools] that were not included in the CRR model or known by participants in advance of the auction,” Bentley said.

She cited as evidence the ISO’s own monthly market performance reports for October, November and December, which attributed at least a portion of auction revenue shortfalls each month to unexpected binding constraints on the transmission system.

Unlike other RTOs that have imposed penalties for “late, unnecessary or nonemergency outages that impact the day-ahead market, but were not modeled in the monthly auction,” CAISO has no such policies, Bentley said.

“Therefore, events like this last quarter are frequent, where outages impact CRR shortfalls with no repercussions on those causing the shortfall,” she said.

Bentley added that the ISO may compound the issue by not providing sufficient notice in advance of auctions about nomograms created to account for outages.

“While the majority of nomograms understandably may not be done in advance sufficient to notify market participants, a tightening up of transparency policies would enable better CRR auction outcomes in those cases that the CAISO could have given advance warning,” Bentley said.

Analysis Challenged

Ryan Kurlinski, manager of the Monitor’s analysis and mitigation group, rejected Bentley’s analysis. “There is no evidence to support WPTF’s suggestion that improvements in the ISO’s transmission outage reporting accounted for the reasons that CRR auction revenues exceeded payouts during the third quarter of 2016,” he said.

Kurlinski said the third quarter was “very anomalous” and that lower payments to auction participants stemmed from “unusually low” congestion appearing in the ISO’s day-ahead market during the period.

“During periods of this quarter, virtually no congestion appeared in the day-ahead market,” Kurlinski said. “DMM is working with the ISO to understand factors which might have caused this.” That lack of congestion likely accounts for last year’s overall drop in payouts to CRR holders.

Kurlinski doubted that adjustments to the auction model could ultimately improve outcomes for ratepayers.

“Even if the CRR auction model includes all outages known by CAISO [transmission owners] at the time the model is completed, there will be outages that cannot be adequately modeled,” Kurlinski said. “For instance, if an outage is scheduled for only a few days, this outage cannot be accurately represented in the monthly CRR model.”

March 10, 2017

PJM Monitor Concerned About State Subsidies

By Michael Brooks

WASHINGTON — PJM Independent Market Monitor Joe Bowring on Thursday warned that state plans to subsidize unprofitable generating resources present “a very real threat” to wholesale electricity markets.

The subsidies in question come in the form of zero-emission credits for uneconomic nuclear plants, which were included as part of New York’s Clean Energy Standard and are intended to aid the state’s transition away from fossil fuels and into renewables.

Exelon has been pushing for similar treatment for its nukes in Illinois, while FirstEnergy has said it will seek financial assistance for its Ohio plants.

“I don’t believe that any of the subsidies are being driven initially by state policy,” Bowring said during his PJM 2016 State of the Market Report presentation. “They’re being driven by the specific requests of generation owners about particular units because those units are not profitable. We would not be talking about the units in Illinois or Ohio if the capacity market prices had been higher and those units were profitable.”

state of the market report pjm state subsidies combined cycle units — | *Monitoring Analytics 2016 State of the Market Report*

Social goals — such as the reduction of carbon emissions to reduce the effects of climate change — can be accomplished through market-based solutions, such as a price on carbon, Bowring contended.

“Economists everywhere agree that … the most cost-effective way to do that is have a carbon price,” Bowring said. “It’s certainly not by picking individual power plants that are low carbon.”

To protect the markets from the effects of the subsidies, Bowring advocated for applying PJM’s minimum offer price rule (MOPR) to all existing resources. The rule currently covers only new subsidized gas-fired plants.

“Action is needed to correct the MOPR immediately,” the Monitor said in its report. “An existing unit MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”

Bowring expressed concern that Illinois and Ohio could set a precedent for other states, calling the subsidies “contagious.” The Monitor views the threat as so severe that in January it filed as an intervenor in support of independent power producers opposing New York’s ZEC program.

“The ZEC program is not consistent with the operation of a competitive wholesale electricity market,” the Monitor told the New York Public Service Commission, adding that the program would artificially suppress NYISO, dissuade the construction of new generation and, if extended, “result in a situation where only subsidized units would ever be built.”

Record-low LMPs in PJM

The Monitor found that PJM’s energy, capacity and regulation markets were competitive during 2016. The average real-time, load-weighted LMP was $29.23/MWh, 19.2% below the previous year and the lowest since the competitive wholesale market commenced operation in 1999 — “which is fairly astonishing,” the Monitor noted.

state of the market report combined cycle units pjm state subsidies — | *Monitoring Analytics 2016 State of the Market Report*

Fuel prices were the main drivers: Gas prices were very low, while those for coal remained flat. High output from efficient combined cycle units — despite flat load growth — also played a significant role.

All those factors translated into a competitive market, Bowring said.

“New combined cycles have been added because of competitive markets,” he said. “They’ve been added because of the fact that we have a capacity market. … But for PJM overall markets, we probably would not have seen that level of entry of highly efficient combined cycles.”

As a result, net income for new combustion turbine and combined cycle units were up 21% and 14%, respectively. Meanwhile, profits decreased for new coal (54%), diesel (86%), nuclear (26%), wind (19%) and solar (28%).

Total transmission congestion costs fell by $361.6 million (26.1%), the result of low prices and smaller price differences across constraints.

Capacity Market

Capacity prices were lower last year than in 2015, except in the PSEG zone. Capacity revenue accounted for 43% of total net revenues for new combustion turbine plants, 32% for new combined cycles and 23% for new nuclear.

Total installed capacity last year rose 2.7% to 182,449 MW. As of Dec. 31, 101,474 MW were in the generation interconnection queue, with combined cycle units accounting for 68.3% and wind projects 14.4% of capacity. The Monitor expects gas to surpass coal in installed capacity this year.

Demand Response

Total payments to demand response resources decreased by $163.2 million (20.1%) to $655.7 million. Bowring attributed the decline to low prices, which undercut incentives to reduce power usage.

The capacity market remains the primary source of income for DR, making up 99% of its revenue — something Bowring is still not happy with, as he continues to advocate its removal from the capacity market. He said stakeholders are seriously considering the “best way” to manage those DR resources within the market.

“It’s important to understand our perspective here, which is not anti-DR at all,” Bowring said. “We’re very much pro-DR. We think it’s essential to making markets work. We want more people to have the option … to reduce demand and save capacity revenues.”

March 10, 2017

NYPSC Adopts ‘Value Stack’ Rate Structure for DER

By Michael Kuser and Rich Heidorn Jr.

The New York Public Service Commission on Thursday adopted a new “value stack” pricing mechanism for solar and other distributed energy resources, along with two other orders to transition utilities into “distributed system platforms” and align their incentives with DER providers.

The Value of Distributed Energy Resources order approved March 9 (Case 15-E-0751) begins the transition away from net energy metering and toward an approach that aggregates specific value components. The number of those components will be raised over time to increase the granularity and accuracy of the valuation.

“This order achieves a major milestone in the Reforming the Energy Vision (REV) initiative by beginning the actual transition to a distributed, transactive and integrated electric system,” the commission wrote.

It would replace existing DER business models based on net energy metering, which the commission called “inaccurate mechanisms of the past that operate as blunt instruments to obscure value and are incapable of taking into account locational, environmental and temporal values of projects.”

“By failing to accurately reflect the values provided by and to the DER they compensate, these mechanisms will neither encourage the high level of DER development necessary for developing a clean, distributed grid nor incentivize the location, design and operation of DER in a way that maximizes overall value to all utility customers,” it said.

Continuing NEM, which can overcompensate distributed resources by transferring their share of fixed costs to other customers, would prevent wide-scale DER deployment “as the inherent subsidies reach a level that is oppressive to non-participants,” the order said.

NYPSC value stack rate structure DER — | *New York Public Service Commission Staff Report on Value of DER Proceeding, Oct. 2016*

“The system obeys not the law of contracts, but the laws of physics,” said PSC Chair Audrey Zibelman, in her final commission meeting. “Following those, that’s how you’ll get the best outcome. DER, rather than being a problem, can be a solution to where we want to get to, which is a clean energy future.”

Transition Period

The order initiates a transition period with a VDER Phase One tariff in which projects currently in “advanced stages of development” will receive NEM compensation, but for only their first 20 years.

“While Phase One NEM contains inefficiencies similar to NEM as a compensation methodology, the term limitation will offer some incentives for developers and customers to consider the impacts of the location, design and operation of DER on the electric system,” the commission said.

| *New York Public Service Commission Staff Report on Value of DER Proceeding, Oct. 2016*

The order directs Department of Public Service staff to work with utilities and other stakeholders to develop the new value stack compensation “based on monetary crediting for net hourly injections,” which the commission hopes to act on as early as this summer.

Value stack compensation would include:

Energy value, based on the day-ahead hourly zonal LMPs, including losses;
Capacity value, based on retail capacity rates for intermittent technologies and the capacity tag approach for dispatchable technologies based on performance during the peak hour in the previous year;
Environmental value, based on the higher of the latest Clean Energy Standard Tier 1 renewable energy certificate procurement price or the federal government’s social cost of carbon; and
Demand reduction value and locational system relief value, based largely on utility marginal cost of service studies and performance during 10 peak hours.

Decision Draws Praise from Solar Advocates

Clean energy supporters and solar industry advocates hailed the decision.

“The order will provide a framework for more precisely valuing new clean energy while balancing the need for a predictable price,” said Anne Reynolds, director of the Alliance for Clean Energy New York. “This is the right approach and can serve to support the market for solar and other emerging clean technologies.”

In a blog post, Natural Resources Defense Council attorney Miles Farmer called the order “a bold experiment.”

“Rather than offsetting the retail rate, projects will generate credits according to an estimate of the value they provide to New York customers,” he wrote.

Sean Garren, a regional director for Vote Solar, a nonprofit solar advocacy organization, lauded the “consumer savings, local jobs and a healthier environment” implied in the decision. “While this order has yet to fully expand clean energy access to all New Yorkers, we look forward to doubling down on that commitment to make community solar work throughout the state,” he said.

Incentives for Utilities to Collaborate

The PSC also approved an order (Case 16-M-0411) on utilities’ transition to the distributed system platform combining planning and operations with enabling markets.

The order directs Central Hudson Gas & Electric, Consolidated Edison of New York, New York State Electric and Gas, Niagara Mohawk Power (National Grid), Orange and Rockland Utilities, and Rochester Gas & Electric to submit filings by Oct. 1 documenting that they have completed their analyses of the hosting capacity for all circuits at and above 12 kV and implemented Phase 1 of their online portal for DER developers seeking to access the grid.

The companies also were ordered to submit filings within 60 days describing how the “suitability criteria” — a framework for identifying distribution infrastructure projects most suitable for non-wires alternatives — will be incorporated into their planning procedures and applied to current capital plans.

It set a Dec. 31, 2018, deadline for documenting that each utility has deployed at least two energy storage projects at separate distribution substations or feeders.

Tammy Mitchell, PSC chief for electric distribution systems, said, “The phased approach is right but too slow. This order directs hosting utilities to provide the hosting capacity data needed to manage the variable DER inputs.”

“Today the advanced energy economy industry is worth $200 billion in the U.S.,” Zibelman said. “This order points in the right direction, gives utilities the right incentives, and gives investors the transparency and data they need to put money at risk.”

Helping Utilities See DERs as Customers

In its third and last vote on its regular agenda, the PSC approved an order (Case 16-M-0429) for an interconnection earnings adjustment mechanism, which aims to change the way utilities earn revenues.

The order requires the utilities to build on their previous filings with additional proposals within 60 days on customer service surveys and other metrics that will determine their future compensation.

“This is a good start to change the business model so that DER providers are customers of the utility, which want to attract them and not see them as competitors,” said Zibelman. “Utilities should look at DERs as customers and see how they can exceed customer expectations.”

Department of Public Service Deputy Director Michael Worden said the order “addresses the market in four categories: system efficiency, energy efficiency, consumer engagement and interconnection.”

Depending on how they perform against targets in those categories, said Worden, the PSC will either “reward them with a carrot, or show the stick.”

Zibelman’s Swan Song

Thursday’s meeting marked the end of Zibelman’s more than three-year tenure, as she has accepted an offer to lead the operator of Australia’s largest gas and electricity markets. (See NY REV Won’t Lose Momentum, Departing Zibelman Says.)

Gov. Andrew Cuomo on March 8 appointed Commissioner Gregg C. Sayre as interim chair. The only other commissioner is Diane X. Burman.

Zibelman’s departure, the recent retirement of Commissioner Patricia Acampora and a two-year-long vacancy means the commission now has three openings for new members.

March 9, 2017

Pipeline Foes Like Hobbled FERC Just the Way it is

By Michael Brooks

FERC’s loss of its quorum has members of Congress and the natural gas industry feeling anxious, but anti-fracking activists said Wednesday they will oppose any nominations to the commission in order to keep it paralyzed.

Ted Glick, a founder of Beyond Extreme Energy, said his group and more than 130 others were inspired to act when Chairman Norman Bay resigned Feb. 3 after President Trump named Cheryl LaFleur acting chair. Bay’s departure left the commission with only two members, one short of the minimum needed to approve natural gas pipeline projects.

The commission approved seven natural gas pipelines worth 7 Bcfd before Bay left this year, according to the U.S. Energy Information Administration. The commission approved 17.6 Bcfd of capacity last year.

Besides lobbying senators to vote against nominees, the activists’ efforts will include nonviolent civil disobedience, which his group has used to disrupt the commission’s open meetings, Glick said during a news teleconference. (See Meet the People Making Life for FERC a Little More Difficult this Week.)

ferc fracking pipeline foes — In a March 2016 protest outside FERC headquarters, Beyond Extreme Energy and other activists ate pancakes with the last syrup from Megan Holleran’s maple trees, which were cut down for a pipeline in New Milford, Pa. Holleran, “Gasland” filmmaker Josh Fox and five others were arrested. | *Beyond Extreme Energy*

Beyond Extreme Energy and its allies see FERC as a rogue agency that ignores communities’ input on pipeline projects and is cozy with the industry that it is supposed to regulate. Their opposition is nonpartisan, with the activists yesterday lambasting Democrats for their failure to rein the commission in.

“The appointment of one new commissioner could put that agency back in business and able to inflict incredible and irreparable harm on communities and our environment,” said Maya van Rossum, leader of the Delaware Riverkeeper Network.

Preventing the restoration of FERC’s quorum is virtually impossible, however. Republicans control the Senate 52-48, and Democrats can no longer filibuster the president’s nominations except for the Supreme Court.

“The best outcome right now for the communities being abused by these pipeline projects and these pipeline companies and by FERC is to prevent” a quorum, and give Congress “the breathing room” to holding hearings “investigating the abuses that are happening at the hands of FERC, identifying the needed reforms and putting in place those reforms before a quorum is restored,” van Rossum said. “We get that’s a heavy lift. We totally get that.”

Joining Glick and van Rossum on the call was Todd Larsen, executive co-director of Green America; Josh Fox, director of the Oscar-nominated documentary “Gasland;” and Maggie Henry, a former organic farmer. (See Organic Farmer Turned Fracking Protester.)

“It’s not just that we will oppose the FERC nominees,” Fox said. “Citizens all across this nation are gathering to build protest camps like the one at Dakota Access, and you will see a state of protest against fossil fuel infrastructure unlike anything we’ve ever seen in the United States of America.”

Cantwell, Dems Urge ‘Nonpartisanship’

Sen. Maria Cantwell (D-Wash.), ranking member of the Senate Energy and Natural Resources Committee, has other ideas.

She and 15 other Democrats wrote Trump on Wednesday urging him to respect the commission’s tradition of nonpartisanship, noting that less than 2% of the orders issued in 2016 included a dissenting opinion. “We hope that your nominees will be prepared to continue this tradition, and we intend to review them through that lens during the confirmation process,” the senators wrote.

They also said that both Republican and Democratic presidents have nominated people recommended by the Senate leader of the party that does not hold the presidency — Senate Minority Leader Chuck Schumer (D-N.Y.). “We expect you will honor this long-standing practice in nominating individuals to serve on the commission,” the senators said.

March 8, 2017

CAISO Seeks Reliability Designations for Calpine Peakers

By Robert Mullin

CAISO wants to use an out-of-market measure to keep two Northern California gas-fired peaking plants operating after their long-term contracts expire in December.

The ISO is seeking to designate Calpine’s Yuba City and Feather River plants as reliability-must-run resources after identifying that both 47-MW peakers will be needed to support local grid reliability after they fall off their current contracts with Pacific Gas and Electric, which manages the service territory where the plants are located.

caiso rmr calpine — CAISO is seeking to provide Calpine’s Yuba City and Feather River peaking plants with reliability must-run designations next year after the December 2017 expiration of their contracts with Pacific Gas and Electric. | *Yuba City photo source Calpine*

The issue arose last November when Calpine notified CAISO that expiring operating agreements would require the company to shut down four of its combustion turbine peakers.

Calpine asked CAISO to study whether loss of the units would cause grid reliability problems. The company said that its capital outlay and resource planning requirements required that it learn of any reliability need for the plants before this fall, when the ISO would release its 2018 resource adequacy assessment. Such a determination would make the plants eligible for longer-term resource adequacy payments under CAISO’s capacity procurement mechanism (CPM).

“On that basis, we did do the review that was requested and concluded that there is a reliability need for two of the four generators,” Neil Millar, CAISO executive director of infrastructure development, said during a March 7 call to discuss the issue. Two plants farther to the south, King City and Wolfskill, failed to make the cut.

Pease Area Deficient

Under an RMR arrangement, CAISO has the right to call upon a generator to provide energy, black start services or voltage support to meet reliability needs. The ISO compensates the generator for keeping capacity available for dispatch, with costs allocated to benefitting load-serving entities.

“Without the 47 MW from Yuba City, we would be deficient” in the Pease local capacity requirements sub-area, Millar said.

The ISO performs an annual analysis to determine each local area’s minimum capacity requirement to meet reliability standards. Other generators can provide only 82 of the 100 MW required in Northern California’s Pease sub-area, leaving the Yuba City unit to make up the difference.

Feather River is not needed to supply capacity, but the plant does play a key role in controlling voltage in its surrounding region by absorbing reactive power from the system. Without the unit, 115-kV bus voltages in the area would rise to “significantly beyond” the upper limit of the normal range, CAISO has found.

“We will be looking at longer-term mitigation in that area in future transmission planning process cycles,” Millar said. “We’re working with PG&E, and also recognizing that this is a combination transmission and distribution issue.”

Millar pointed out that a one-year RMR designation would not prevent the plants from entering into longer arrangements with the ISO if the need is identified.

“Just because the units may be designated as reliability-must-run in the spring [of 2018], [that] doesn’t preclude them getting some longer-term resource adequacy contract that would obviate all or parts of the need for an RMR agreement,” he said.

Carrie Bentley, a consultant representing the Western Power Trading Forum, wondered why the two plants wouldn’t be covered under the ISO “risk-of-retirement” CPM.

“I understand that they can’t wait for the annual, but I thought that the risk of retirement didn’t have such timing issues,” Bentley said.

“It’s not totally within the ISO’s ability to direct that,” said Sidney Mannheim, CAISO assistant general counsel. “The CPM is voluntary on the part of the resource owner, where [with] the RMR authority, we literally have the Tariff authority to designate a resource as RMR.”

Impact on Local Capacity Requirements

Erica Brown, senior analyst with PG&E, asked about the impact of the RMR designations on local capacity requirements.

“So, going into our next [resource adequacy] year, if there’s an RMR resource [in a local area], would that subtract from the overall quantity that’s needed for the local area?” Brown asked.

Millar clarified that the Yuba City plant would count toward the area’s capacity requirement because the unit’s RMR designation would be based on a capacity need, while Feather River, which is needed for voltage support, would not.

Michele Kito, a regulatory analyst at the California Public Utilities Commission, asked about Calpine’s need to make investments in the peaking units to keep them online next year. “At what point would there be some independent engineering assessment that those long-term investments need to be made that would justify a long-term RMR agreement?” she asked.

Mannheim clarified that the RMR agreements would only run year-to-year, although they could ultimately cover a multiyear need.

“The RMR process does involve the responsible transmission owner and the PUC to review any proposed capital improvements,” Mannheim said. “That is the process we would undertake following any designation — and the PUC would be involved in that.”

CAISO plans to present the Yuba City and Feather River RMR designations for approval by the Board of Governors on March 16. Upon approval, Calpine would be expected to draw up a cost-of-service proposal, including any capital improvements, for review by PG&E, the ISO and the PUC.