Page 1081 – RTO Insider

January 15, 2019

PJM Operating Committee Briefs: Jan. 8, 2019

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — During an Operating Committee presentation last Tuesday on changes to Manual 12, Carl Johnson of the PJM Public Power Coalition said he was “stunned” by reports of generators’ poor performance in providing primary frequency response (PFR).

Operating Committee Chair Dave Sauder and Secretary Dan Wallin lead the Jan. 8 meeting. | © *RTO Insider*

In October, PJM reported on an analysis of 454 generating units’ responses to 13 events between December 2017 and April 2018. It found that 36% failed to respond or responded in the wrong direction, while only 42% provided 75% or more of the response required.

“It seems to me you would be having more problems than you are if performance was as poor as it appeared,” Johnson said. “Are we measuring the right thing?”

Johnson’s comments came as PJM’s Danielle Croop gave a first read of an updated Manual 12 that includes a new section to describe how the RTO will measure PFR and respond to poor performers.

In 2012, NERC reported that only 30% of units online provide PFR — automatic adjustments that begin within seconds of detecting frequency variations — and only 10% of units online sustain it. FERC cited the data when it issued new PFR requirements in Order 842 last February.

The Markets and Reliability Committee agreed to continue monitoring units’ PFR performance during 2019 after suspending the Primary Frequency Response Senior Task Force, which failed to come to consensus on any proposals to require existing units to provide the service. (See “PFR Task Force on Hiatus,” PJM MRC Briefs: Dec. 20, 2018.)

The task force was put on hiatus after stakeholders soundly rejected PJM proposals to enforce PFR requirements beyond those in Order 842.

The order requires all newly interconnecting generation be capable of providing PFR. But the commission declined to order existing generators to retrofit their facilities to provide the service, saying it would be “prohibitively expensive” for some. (See FERC Finalizes Frequency Response Requirement.) PJM incorporated FERC’s requirement into its interconnection service agreements in October.

With some generators already providing sufficient frequency response, stakeholders said it was unnecessary to force all units to spend money to install the equipment needed to provide the service.

The manual changes detail calculations for high- and low-frequency events, explain when a resource will be evaluated for PFR and how the RTO will respond to resources that fail to perform. PJM will work with generation owners to identify whether the poor performance is because of telemetry, operating scenarios, generator hold points or malfunctioning governors.

Brock Ondayko of American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. “To put forward parts of that concept [after the stakeholder rejection] is a bit interesting,” he said.

The manual is scheduled to be brought to an OC endorsement vote at the Feb. 5 meeting.

Unit-specific Parameter Updates due Feb. 28

PJM reminded stakeholders that generating units unable to meet proxy parameters because of operating constraints must submit an adjustment request to unitspecifcpls@pjm.com by Feb. 28.

Unit-specific parameters will be applied to all Capacity Performance, base and fixed resource requirement resources effective June 1, the beginning of delivery year 2019/20.

Approved parameters remain in place unless PJM is notified of a change. Parameters approved and implemented in previous years do not have to be resubmitted.

Parameters affected include turn down ratio, minimum and maximum down time, maximum daily and weekly starts. Adjustment requests will be evaluated by April 15.

Cold Weather Generation Testing Continues to Shrink

Citigroup’s Barry Trayers kidded PJM’s Chris Pilong, above, about his new beard, asking him if its thickness could be read as a “wooly caterpillar” predictor of winter weather. Pilong good naturedly said it was. | © *RTO Insider*

PJM will spend only $162,000 to test the winter capabilities of 21 generators totaling 477 MW in 2018.

That’s a fraction of what it spent when it launched the program following the 2014 polar vortex, when up to 22% of the RTO’s generation was unable to operate.

PJM spent $4.9 million to test 168 units representing 9,900 MW before winter 2015. Last year, it paid $1.6 million to test 39 units (3,935 MW).

PJM’s Ray Lee said the decline is a reflection of the transition to CP resources, which are not eligible for testing. All capacity resources will be required to meet CP requirements beginning with delivery year 2020/21.

Lee said it’s unclear whether PJM will continue the program for energy-only generators in the future.

PJM will spend only $162,000 to test the winter capabilities of 21 generators in 2018, a fraction of what it spent when it launched the program following the 2014 polar vortex. | *PJM*

Black Start Fuel Requirements

The OC held its first meeting last Tuesday on an initiative to develop fuel assurance requirements for black start units.

Members approved a problem statement creating the initiative in July, noting that only 50% of black start units were able to demonstrate fuel assurance through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.

Although fuel supply capabilities are among the criteria PJM uses in evaluating black start proposals, there is no fuel assurance requirement except that units have enough for 16 hours of run time.

The opening session featured a series of educational presentations by PJM staff and Independent Market Monitor Joe Bowring. The OC will return to the issue following its regular meeting Feb. 5.

January 13, 2019

ERCOT Briefs: Week of Jan. 7, 2019

By Tom Kleckner

The Texas State Capitol, home to the 86 Texas Legislature.

As part of its 2019 Scope of Competition in Electric Markets report to the Texas Legislature, the Public Utility Commission is asking legislators to help provide clarity on whether transmission and distribution utilities (TDUs) can own and operate energy storage devices (Project 48017).

The PUC said that the ownership and deployment of electricity from battery storage devices “has emerged as an issue that would benefit from legislative clarity.”

“I don’t want the state to get behind on the development of batteries into our system,” Commission Chair DeAnn Walker said during an open meeting last month.

The PUC opened a rulemaking on the issue (48023) in January 2018, shortly after it rejected AEP Texas’ request to connect two battery storage facilities in West Texas to the ERCOT grid. (See “PUC Opens Rulemaking on Distributed Battery Storage,” LP&L Finalizing Agreements in ERCOT Move.)

The commission has received 63 responses to its request for comments. The TDUs argued the state’s Public Utilities Regulatory Act permits their ownership or operation of energy storage devices as long as the TDUs don’t sell electricity or participate in the market for electricity (except as a customer). The generators asserted that PURA requires an owner or operator of storage facilities or equipment to register as a power generating company, and that a TDU can’t legally be a utility and a generator.

PUC Chair DeAnn Walker | © *RTO Insider*

“One side says PURA is clear, that TDUs can’t own [battery storage]. The other side said PURA is clear, that TDUs can own it,” Walker said during the December open meeting. “I think that speaks to whether PURA is clear.”

The commission appears to be just as divided. Walker found herself siding with some of AEP’s arguments last January, while Commissioner Arthur D’Andrea expressed his concerns over regulated utilities “playing in [the generators’] space.”

The PUC is scheduled to take up the rulemaking during its Jan. 17 open meeting.

The commission’s report will be filed with the 86th Legislature on Monday. The Legislature went into its biennial session Jan. 8 and will finish May 27.

In the report, the commission recommends that the threshold for reviewing mergers and acquisitions of power generation companies be changed from 1% to 10% of installed generation capacity in ERCOT. It doesn’t recommend changing the 20% ownership limit of installed generation capacity.

Other recommendations include:

Requiring retail electric brokers to register with the PUC in a manner similar to retail electric aggregators;
Establishing a collaborative cybersecurity outreach program with utilities; and
Considering a person in default if they don’t respond to a commission’s notice of violation within 20 days.

Energy Consumption Exceeds Expectations

The ERCOT market consumed more than 376 million MWh of power in 2018, a 5.3% increase over the year before, according to the grid operator’s year-end Demand and Energy report.

The final total of 376,357,477 MWh was almost 5 million above the forecast of 370,619,525.

Combined cycle gas units accounted for 38.19% of the energy consumed, with coal-fired generation at 24.78%, wind at 18.55% and nuclear at 10.93%.

ERCOT’s energy use was a dramatic increase from the previous two years, a sign of the state’s booming economy. The market consumed 357,408,316 MWh in 2017 and 351,559,301 MWh in 2016.

Texas added 365,000 jobs in the 12 months that ended in November, and its 3.7% unemployment rate is the lowest on record, according to the Labor Department.

January 13, 2019

Counterflow: Electric Cars – Once More With Feeling

By Steve Huntoon

Two years ago I wrote a column: “Electric Cars: Three Ugly Facts.”¹

The column showed that electric cars are:

Uneconomic relative to gasoline cars;
Contribute more to global warming than gasoline cars; and
Cause more death and disability than gasoline cars.

All still true today. I included a photo of a 1922 electric car (reprised here) to make the point that electric cars died about a hundred years ago, and they ain’t coming back any time soon (except as niche Veblen goods like Tesla).²

1922 Detroit Model 90 | *Detroit Electric*

I sent my column to The Wall Street Journal car columnist Dan Neil, who even then was an electric car devotee. No acknowledgement or response. Not that I expected one.

The Band Plays On

It’s timely to reprise this subject because Neil just wrote another fawning piece for electric cars where he claims — without any support whatsoever — that a gasoline car is more expensive than an electric car over a 10-year ownership horizon.³ And that within “the reasonable service life of any vehicle I buy today,” the demand for gasoline cars will be zero. And he trashes the amazing technological improvements of gasoline cars as feeling “junky and compromising.” (I suppose every iPhone enhancement could get such a dissing.)

Irony abounds here because the very next day the WSJ itself ran an editorial arguing that electric cars are very expensive, and the electric car tax credit subsidy is very regressive.⁴ And that electric cars lose money for their makers and are being made only because of federal and state mandates.

General Motors loses $9,000 on every Chevrolet Bolt. When you lose $9,000 on every electric car, you can’t make it up in volume, especially not on gasoline cars that Neil claims won’t exist anymore.

Paris Agreement

Neil writes that after the Paris climate talks, “most nations of the world have put the IC [internal combustion] vehicle under a death sentence.” This is profoundly false. A mere handful of nations have adopted future — very future — limitations on gasoline cars, and most of those are purely aspirational.⁵

The reality is this: No nation is going to commit economic harakiri by mandating uneconomic cars for its citizens. Well, except maybe the nation of California.

Piece de Resistance

Now the piece de resistance. Not about electric cars, but electric trucks. Neil extolls a future pickup truck from a company called Rivian that supposedly in two years will be producing an electric pickup with 400-plus miles of range, that will make the gasoline pickup a financial albatross, and that will provide “a wading depth of 3 feet” with which you can go “through the river to grandmother’s house.”

OMG. For starters, Rivian is a company with demonstrated success only in selling investors. Its Wikipedia listing is enlightening.⁶ Multiple name changes, initial product to be a high MPG (gasoline) car, then autonomous electric vehicles, and now electric pickups.

Rivian R1T (left) and Ford F-150 | *Richard Truesdell (left) and Jesus David Piña*

The pickup per Rivian’s promotion would provide 400 miles of range at the $100,000 price range.⁷ In the base model, providing 230 (not 400) miles of range, the promoted base price is $69,000.

Here’s a true-false question for those of you playing the electric vehicle game at home.

The base price of the base Rivian is $30,000 more than the price of a similarly configured Ford F-150:

True.
False.

The correct answer is True. The base Rivian, with 230 miles of range and a base price of $69,000, is $30,000 more than the price of a similarly configured Ford F-150 (same truck bed, four doors, 4×4) of $39,050.

Did I mention that the truck bed length of the Rivian is said to be 55 inches, while the standard truck bed of the F-150 is 78 inches? Last time I checked, pickup owners cared about how much stuff their pickup could carry.

Now, as for the financial albatross assertion about gasoline pickups, it is true that electricity generally costs less on an MPG-equivalent basis than gasoline. But let’s do a little math.

The Ford F-150 gets 20 MPG. The average annual miles for a pickup is 12,000 miles.⁸ At the current annual average cost of gas, that’s $1,350 for gas per year (12,000 miles divided by 20 MPG times $2.25/gallon).

Neil talks about a 10-year ownership horizon of a purchase. So that’s $1,350/year for gas times 10 years equals $13,500. Let’s see. That’s $13,500 for gas plus the price of the similar Ford F-150 of $39,050 for a total of $52,550.

Compare the F-150 price plus gasoline of $52,550 with the base price of the range-limited Rivian of $69,000, and assume that electricity for the Rivian is free.⁹

Any questions on the economics — or practicality? Which — just guessing here — matter big time to pickup buyers.

Finally, there’s Neil’s gushing about a future Rivian’s 3-foot wading depth in rivers. Here’s the term for anyone “wading,” aka “floating,”¹⁰ in 3 feet of river water: Foolish. Very foolish.

1- http://www.energy-counsel.com/docs/Electric-Cars-Three-Ugly-Facts-2017-02-14-RTO-Insider-Individual-Column.pdf.

2- Of course there could be a breakthrough in battery technology/cost, but nothing is on the near-term horizon. https://www.bloomberg.com/news/articles/2019-01-06/before-the-electric-car-takes-over-someone-needs-to-reinvent-the-battery.

3- https://www.wsj.com/articles/think-electric-vehicles-are-great-now-just-wait-11545838139.

4- https://www.wsj.com/articles/the-electric-kool-aid-subsidy-test-11546201813.

5- https://qz.com/1341155/nine-countries-say-they-will-ban-internal-combustion-engines-none-have-a-law-to-do-so/.

6- https://en.wikipedia.org/wiki/Rivian.

7- https://www.theverge.com/2018/11/26/18111782/rivian-r1t-electric-pickup-price-specs-la-auto-show-2018.

8- https://afdc.energy.gov/data/10309.

9- BTW, on top of the regressive income tax subsidy, electric vehicles enjoy tax avoidance from not contributing toward our interstate highway system through the gas tax. Another subsidy.

10- https://weather.com/safety/floods/news/flash-flooding-vehicle-danger-20140717.

January 13, 2019October 31, 2023

Mass. Looks to Double Down on OSW, Clean Goals

By Michael Kuser

BOSTON — Massachusetts is seeking to broaden its already ambitious goals for procuring clean energy and reducing emissions, state officials said last week.

Topping the agenda: The state is considering to solicit an additional 1,600 MW of offshore wind energy even as it is barely halfway through a procurement process for the same volume as authorized by 2016 legislation.

“We’re launching an offshore wind study to look at … whether we can get an additional 1,600 MW,” Massachusetts Department of Energy Resources Commissioner Judith Judson said Wednesday at a meeting of the Environmental Business Council of New England.

The Environmental Business Council of New England sponsored a briefing by DOER officials at the law office of Prince Lobel in Boston on Jan. 9. | © RTO Insider

Massachusetts last May awarded Vineyard Wind an 800-MW offshore wind contract that runs 20 years and has two 400-MW tranches. The first tranche starts at $74/MWh and the second at $65/MWh, with the prices increasing by 2.5% per year. Partially redacted contract summaries from the state’s Department of Public Utilities show an average nominal price of $64.97/MWh in 2017 dollars.

Judith Judson | © RTO Insider

“We’re excited to be jump-starting the offshore wind industry,” Judson said. “Because of the way we set that up, with a long-term, revenue-fixed contract … we were able to get that at a price that no one believed was possible. I know when we opened the bids, we were like, ‘Whoa’; we were surprised. I think everyone was surprised.”

John Rogers, an energy analyst with the Union of Concerned Scientists, wrote in a September blog post that the “price wasn’t just impressive; it caught us really off-guard. I had been expecting a price about twice as high.”

“We’re still in the midst of procuring our first 1,600 MW, and we will be issuing our next solicitation for offshore wind in the near term as well,” Judson said.

The young industry came of age in December, when the eighth federal lease auction brought in $405 million for three wind energy sites offshore Massachusetts — about six times the revenue from all previous auctions combined. (See Mass. Offshore Lease Auction Nets Record $405 Million.)

Regional Benefits

Judson outlined what the DOER has done in the four years since Gov. Charlie Baker was first elected (he won a second term in November) and said the state is a national leader in energy efficiency and solar energy.

In November, the state launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. The DOER is now in the final steps of developing its next three-year plan to submit to the DPU, she said.

She also pointed out the state’s utilities have contracted with the proposed New England Clean Energy Connect project designed to bring Canadian hydro energy to Massachusetts through Maine.

“One thing I’ll note about that, at about 5.9 cents[/kWh], if you look at that in total [compared] to what we pay for energy, capacity and ancillary services as well as renewable energy attributes, it’s a very cost-effective price; in fact [it’s] lowering bills,” Judson said. “But it doesn’t just lower bills in Massachusetts. When that project comes into the regional wholesale market, it provides those cost savings to every consumer in New England.”

The Maine Public Utilities Commission is holding hearings this month (Docket No. 2017-00232) on a certificate of public convenience and necessity for NECEC, a project of Avangrid subsidiary Central Maine Power and Hydro-Quebec. The project has drawn opposition from environmentalists, fossil fuel generators and renewable energy advocates who want more local solutions that don’t rely on hydro. (See Maine PUC Move Poses Hurdle for NECEC.)

Left to right: DOER division directors Michael Judge, Eric Friedman and Nick Connors. | © RTO Insider

Clean Peak and Leading by Example

DOER division directors briefed meeting participants on their activities. Michael Judge, head of renewable and alternative energy, explained the state’s new Clean Peak Minimum Standard, which was recently set to zero for 2019 while the agency works out the details of the program. (See Mass. Inaugurates Clean Peak Standard.)

Michael Judge | © RTO Insider

“This is a big piece of legislation that was passed as part of last year’s energy bill [H4857] and sets a portfolio standard for resources that can deliver clean energy during peak periods,” Judge said. “The RPS doesn’t actually focus the delivery of that renewable energy to align with peak periods when you have the highest cost and the highest emissions on the grid.”

Judge referred to the solar “duck curve,” which demonstrates how output from solar resources tends to be highest at mid-day during periods of modest demand.

“Trying to shift that generation so that it’s actually addressing the peaks to flatten the load, that’s one of the big objectives, but also addressing seasonal peak issues,” Judge said. He said DOER will develop the clean peak regulations over 2019, and that there will be a higher standard in 2020.

The state Comprehensive Energy Plan (CEP) published last month says increased electrification in the transportation and thermal sectors may increase electric load — and peak load, depending on the timing of energy use, especially the charging of energy storage and electric vehicles.

Nick Connors | © RTO Insider

DOER Director of Green Communities Nick Connors said the state has granted more than $100 million in the 10 years of the program to support towns in such things as speeding up their permitting process.

Eric Friedman | © RTO Insider

Eric Friedman, head of the Leading by Example Office, said his team had “put a lot of effort into moving away from heavy fuel oil,” with the use of about 18 million gallons avoided over the past decade and some 200 million kWh reductions in energy use. The state has 80 million square feet of building space, consumes more than 1 billion kWh and emits 1 million tons of greenhouse gases.

Even small steps add up, Friedman said. The state has moved to reduce mowing on its properties, as well as the use of gasoline-powered landscaping equipment, increasing pollinator habitat by letting the grass grow.

Storage and Energy Efficiency

Transportation’s share in emissions has been going up as the power and building sectors improve, so electric vehicles are going to be at the center of change in the next few years, said Will Lauwers, DOER director of emerging technology.

Will Lauwers | © RTO Insider

“EVs move with people, so load, consumers and EVs are in the same location, and that’s an opportunity for synergy,” Lauwers said. “Energy storage and dispatchable load such as EVs will enable continued greening of the grid.”

The state now has 380 MWh of energy storage capacity, but storage interconnection is becoming increasingly more challenging, as it is not addressed in utility tariffs, Judge said.

“In many cases what ends up happening is a utility will say, ‘Now you have 2 MW of storage here, you also have a 2-MW solar array, so you’re 4 MW; you can put 4 MW on our system,’ which is not necessarily how the system is designed to operate,” Judge said.

Maggie McCarey | © RTO Insider

Director of Energy Efficiency Maggie McCarey said her office is focusing on developing and implementing the next three-year strategic plan for 2019 to 2021.

The expiring strategic plan — in effect through this month until the DPU approves the new one — had the highest EE goals in the country, while the new one is expected to deliver approximately $8 billion in savings to consumers, McCarey said.

January 11, 2019

Judge, Gov., CPUC and Protesters Weigh in on PG&E Mess

By Hudson Sangree

The California Public Utilities Commission began the process of implementing wildfire cost recovery provisions Thursday, as protesters argued against any effort to bailout Pacific Gas and Electric for the deadly wildfires of 2017 and 2018.

Protesters chant, with some wearing masks, at Thursday’s PUC meeting in San Francisco. | *CPUC*

The day before, a federal judge proposed ordering PG&E to reinspect its entire grid before the start of the 2019 fire season and fix any problems it finds as a new condition of its probation in the San Bruno gas line explosion.

And earlier this week, California’s new governor, Gavin Newsom, said he had been talking with PG&E executives to address the utility’s dire financial situation.

The moves are the latest developments in the quickly evolving PG&E meltdown in the wake of November’s Camp Fire, which killed 86 people. The utility’s possible culpability for that blaze and other massive wildfires has raised the specter of bankruptcy, caused PG&E’s stock price to plummet and led to speculation about whether the company might sell major assets, including its gas division. (See PG&E’s Troubles Mount After Camp Fire; PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status.)

Dealing with PG&E’s safety problems is “like repairing a jetliner while it’s in flight,” CPUC President Michael Picker said in a December news release. “Crashing a plane to make it safer isn’t good for the passengers.”

In its meeting Thursday, the CPUC unanimously approved an order instituting rulemaking to begin putting in place the provisions of last year’s landmark wildfire bill, SB 901, to allow for cost recovery by electric utilities. (See California Wildfire Bill Goes to Governor.)

The new law “describes how the commission will review applications by electrical corporations that request recovery of costs and expenses from wildfires in 2017 … and requires the commission to ‘determine the maximum amount the corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service,’” the commission said.

“In undertaking the adoption of criteria and a methodology to determine the maximum amount the corporation can pay, the commission is mindful of both the finite resources of ratepayers in California and the importance of maintaining financially viable utilities to provide safe and reliable service,” it said.

The order laid out a series of questions to help determine the criteria and methodology the PUC will use to evaluate applications by utilities for cost recovery, and established a schedule for the proceeding, with opening comments due Feb. 11.

Protesters with the Democratic Socialists of America were among those who argued against a bailout for PG&E on Thursday. | *CPUC*

Identify and Fix

At least a dozen protesters occupied the PUC hearing room in San Francisco on Thursday, chanting and speaking beyond the one-minute time limit Picker allowed. Some continued over the president’s repeated objections.

“Ma’am, can you finish it up?” Picker said to one public speaker as she shouted at him from the lectern. “You’re repeating yourself.”

CPUC President Michael Picker listens Thursday to speakers protesting any move to relieve PG&E of liability for deadly wildfires. | *CPUC*

The speakers, including members of the Democratic Socialists of America’s San Francisco chapter, argued that the state should not provide cost recovery to utilities responsible for wildfire deaths.

“You need to be in jail. You need to stop getting money from the public,” one speaker said regarding PG&E.

Another speaker read aloud the names of dozens of fire victims.

On Wednesday, U.S. District Judge William Alsup in San Francisco said that unless he was convinced otherwise, he would impose new probation conditions on PG&E in the 2010 San Bruno gas line explosion case, which killed eight people and resulted in the utility being convicted of six felonies for knowingly violating federal safety rules and obstructing a federal investigation.

Those new conditions would include requiring the utility to reinspect its entire grid in the coming months and to remove any trees or branches that could contact power lines. In addition, he said PG&E would have to “identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions.” The utility “shall identify and fix damaged or weakened poles, transformers, fuses and other connectors; and shall identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,” Alsup wrote.

“These conditions of probation are intended to reduce to zero the number of wildfires caused by PG&E in the 2019 wildfire season. This will likely mean having to interrupt service during high-wind events (and possibly at other times), but that inconvenience, irritating as it will be, will pale by comparison to the death and destruction that otherwise might result from PG&E-inflicted wildfires,” the judge wrote.

He gave the parties until Jan. 23 to show why he shouldn’t impose the new conditions and scheduled a hearing for Jan. 30.

January 11, 2019

ISO-NE, NEPOOL Answer Generators on FCM Test Price

By Michael Kuser

ISO-NE on Wednesday urged FERC to reject a pr o test filed by the New England Power Generators Association over the RTO’s proposed “test price” mechanism to be applied to resources seeking to retire capacity through the RTO’s substitution auction (ER19-444).

The complaint stems from the Nov. 30 joint filing by ISO-NE and the New England Power Pool proposing several Tariff changes to help implement the RTO’s Competitive Auctions with Sponsored Policy Resources (CASPR). FERC approved the RTO’s two-stage capacity auction designed to accommodate state renewable energy procurements last March. (See Split FERC Approves ISO-NE CASPR Plan.)

As part of the proposed changes, ISO-NE is seeking to introduce the concept of a test price that approximates a resource’s competitive price to acquire a capacity supply obligation.

“Without some mechanism to assure competitive bidding, stakeholders worried that a participant would have incentive to reduce its primary auction delist bid below competitive levels in order to clear the primary auction and, as a result, qualify for ‘severance’ payments in the substitution auction,” NEPOOL explained in a separate answer to NEPGA’s protest filed Jan 7.

The test price would “serve as a screen for competitive behavior in the primary auction to determine whether an existing capacity resource’s demand bid can enter the CASPR substitution auction,” according to the RTO. It is intended “to thwart uneconomic bidding behavior in the primary auction of the Forward Capacity Market that, if unchecked, could reduce the primary auction clearing price below its competitively based level.”

ISO-NE noted that its Tariff currently requires its Internal Market Monitor to make two annual filings with FERC showing various inputs for the Forward Capacity Auction slated for the following year. One of those filings, submitted each July, covers retirement delist bids from participants that intend to retire a resource.

“Since the CASPR test price is an auction input that is established as part of the IMM’s review of retirement bids (and uses largely the same formula specified in the current Tariff for calculating retirement delist bids), the CASPR-related changes contemplate the filing of the test price values as part of the July filing of the retirement bids,” the RTO explained.

While NEPGA does not oppose the filing of the test prices, it does contend that the IMM should be required to file participant-submitted test price values — not the values determined by the IMM.

NEPGA argued that prioritizing the IMM’s values would usurp a market participant’s sole right under the Federal Power Act to file a retirement delist bid as its rate for acceptance by the commission and that “the test price likewise is a rate, term or condition” of the participation in the FCA.

ISO-NE countered that NEPGA’s argument is an “abbreviated repeat” of arguments the organization made in a protest of the previous Tariff revisions related to market rules for retirement of resources.

“In that proceeding, NEPGA argued that the proposed Tariff changes denied market participants their Section 205 filing rights to seek a determination of their own rates by requiring the IMM to file, in the July retirements filing, the IMM-determined delist bid price for a retiring resource, rather than the delist bid price submitted to the IMM by the market participant,” ISO-NE said. “The commission squarely rejected NEPGA’s contention.”

The RTO said Section 205 rights are not at issue in the proceeding, “as the test price — like many other inputs into the auction — is not a rate, term or condition.”

NEPOOL contended that instead of “unnecessarily” disrupting the stakeholder process, NEPGA should have “appropriately presented an amendment to the test price mechanism” at stakeholder meetings, in which case “NEPOOL may have supported an alternative approach that could have assuaged NEPGA’s concern.”

While it participated in the stakeholder meetings, neither NEPGA nor any other stakeholder suggested this alternative proposal, NEPOOL said. Stakeholders considered and debated the entire package of CASPR-related changes over last summer before a final vote at the Participants Committee in November, it said.

Resolving the Mystery

In the same filing, the RTO also answered NEPGA’s Jan. 8 mot i on to lodge a Dec. 28 decision by the D.C. Circuit Court of Appeals (Exelon v. FERC, 17-1275) into the test price proceeding.

In the decision, the court remanded back to FERC its order accepting ISO-NE’s retirement delist bid mechanism in the FCA, based on the commission’s own explanation at oral argument that a market participant — and not ISO-NE or the Monitor — has the right to show that its filed rate is just and reasonable and will be entered into an auction regardless of the Monitor’s proposed offer price. (See FERC OKs Lower Delist Threshold in ISO-NE.)

“We see no way to skirt the question Exelon tees up: Under ISO-NE’s new Tariff rules, does a supplier’s rate enter the auction so long as it convinces the commission that the rate is just and reasonable, over contrary claims of the Market Monitor?” the court said.

It remanded the case to FERC “to resolve the mystery,” saying the commission “should issue its clarification expeditiously, and in no event later than Feb. 1, 2019.”

“NEPGA agrees with commission counsel that it is the market participant’s right and obligation to make that showing, and as it explained in its limited protest in this proceeding, the law likewise applies to the test price market participants will be required to file for acceptance by the commission if the commission accepts the test price design in this proceeding,” NEPGA said.

The RTO reiterated its contention that NEPGA’s assertions are an “abbreviated” recycling of prior arguments rejected by FERC and that “NEPGA has made no attempt in its protest to explain why the same assertions do not similarly fail when aimed at the test price mechanism.”

In addition, the RTO said the D.C. Circuit’s remand “decides nothing regarding the issues in contention here regarding the test price” and that “at this stage, therefore, there is nothing of relevance to be gleaned from the D.C. Circuit’s opinion.”

January 11, 2019

EPSA Asks Supreme Court to Review ZEC Rulings

By Michael Kuser

Several power producers joined the Electric Power Supply Association on Monday in petitioning the U.S. Supreme Court to review appellate court rulings upholding the New York and Illinois zero-emission credit programs.

Last September, both the 2nd and 7th U.S. Circuit Courts of Appeals rejected claims by EPSA and others that New York’s and Illinois’ ZECs, respectively, intrude on FERC jurisdiction. (See Appeals Court Upholds NY Nuclear Subsidies and 7th Circ u it Upholds Ill. ZEC Program.)

EPSA on Jan. 7 petitioned the Supreme Court for writs of certiorari to review both decisions. The group was joined on the 2nd Circuit petition by NRG Energy, with the New York Public Service Commission and Exelon — and its three New York nuclear plants — named as defendants. Calpine joined the 7th Circuit petition in the case against the Illinois Power Agency, the Illinois Commerce Commission and Exelon.

Exelon’s Byron Generating Station’s two nuclear reactors in Illinois produce more than 2,300 MW of electricity.

Enough Percolation

The New York PSC created the ZEC program in August 2016 as part of its Clean Energy Standard, which set a goal of reducing greenhouse gas emissions by 40% by 2030.

The PSC said it designed the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)

The 2nd Circuit said that ZECs, like renewable energy credits, are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field pre-emption under the” Federal Power Act.

The court noted that the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.

But EPSA attacked ZECs from a different angle in its petitions.

“The question presented is whether the FPA pre-empts only state subsidies that explicitly require a wholesale generator to sell its output in FERC-approved auctions, or whether the FPA also pre-empts state subsidies that lack such an express requirement but that, by design, subsidize only generators that sell their entire output via such auctions, thereby achieving the same effect,” both petitions said.

“This is not a situation in which further percolation in the courts of appeals is warranted. Indeed, delay risks long-term distortion of the energy markets,” the petitioners said. “The programs already in place are causing multibillion-dollar distortions and skewing decisions about long-term investment in energy generation.”

In addition, the petition on the Illinois ruling said the 7th Circuit’s “decision also rests on an erroneous understanding of the structure and operation of the Illinois ZEC program,” and that while “these factual and procedural errors were addressed in a rehearing petition, the court took no corrective action.”

Old Wine in New Bottles

Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, said, “These arguments about the text of the FPA and the court’s 2016 Hughes decision largely repeat the generators’ briefs filed at the 2nd and 7th Circuits. In rejecting these arguments, the 2nd Circuit panel found it ‘telling that [the generators] cannot persuasively explain why FERC’s holding [disclaiming jurisdiction over RECs] does not apply equally to ZECs.’”

Peskoe pointed out that amicus briefs filed at the appellate courts explain that “a decision endorsing petitioners’ sweeping view of FERC’s authority over all payments received by generators would threaten existing renewable energy programs and deny FERC the opportunity to harmonize its market regulation with state programs.”

The 7th Circuit’s opinion cited the Hughes ruling, in which the Supreme Court said it did not intend “to foreclose [states] from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”

“And that’s what Illinois has done,” the 7th Circuit said. “To receive a credit, a firm must generate power, but how it sells that power is up to it. It can sell the power in an interstate auction but need not do so. It may choose instead to sell power through bilateral contracts with users (such as industrial plants) or local distribution companies that transmit the power to residences.”

EPSA had contended that Illinois’ ZEC program infringed on FERC’s jurisdiction by indirectly regulating interstate energy markets by using average auction prices as a component in a formula that affects the cost of the ZECs. But the 7th Circuit found the value of ZECs does not depend on the generators’ auction offers.

January 10, 2019

McNamee Declines to Commit to Resilience Docket Recusal

By Michael Brooks

FERC Commissioner Bernard McNamee on Monday informed Senate Democrats that ethics advisers told him he was not required to recuse himself from the commission’s ongoing inquiry into RTO/ISO grid resilience (AD18-7).

In a letter to Sen. Catherine Cortez Masto (D-Nev.) dated Jan. 7, McNamee attached a Jan. 2 memo to him written by Charles Beamon, FERC associate general counsel. In the memo, Beamon described his Dec. 12 meeting with McNamee, saying he advised the commissioner that he did “not view your prior position and statements as demonstrative of an unalterably closed mind as to” the proceeding.

Beamon, however, cautioned that “we must exercise continued oversight to ensure that Docket No. AD18-7 does not develop in such a way as to replicate or closely resemble” the Energy Department’s Notice of Proposed Rulemaking for FERC to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel (RM18-1).

FERC Chief of Staff Anthony Pugliese, left, and Bernard McNamee, center, head of DOE’s Office of Policy, made the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance on the sidelines of the NARUC Annual Meeting in Baltimore in November 2017. Michael Whatley, right, CEA’s executive vice president, moderated. | © *RTO Insider*

McNamee helped draft the NOPR, unanimously rejected by FERC, as the department’s deputy general counsel for energy policy. In response to Democrats at his Senate Energy and Natural Resources Committee confirmation hearing in November, McNamee said he “clearly” would have to recuse himself from the NOPR docket, which Beamon reiterated in his memo. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)

But Beamon said that although the dockets are related, “I advised you that I do not view the relationship as requiring your recusal.” He said he also emphasized the dockets were different proceedings and noted that the resilience docket “is an administrative inquiry in which the commission received over 200 comments suggesting various outcomes.”

After he was confirmed 50-49 in early December, 17 Senate Democrats wrote to McNamee on Dec. 12 — coincidentally the same day he met with Beamon — requesting he update them on what guidance he received. Along with his work on the NOPR, they also questioned his impartiality based on a leaked video of a speech he gave while working for the Texas Public Policy Forum in June. (See Senate Confirms McNamee to FERC.)

In the speech, McNamee criticized environmental groups and renewable energy resources, describing the efforts of his group to change public opinion on fossil fuels as a “constant battle between liberty and tyranny.”

Beamon’s memo quoted case law saying that parties cannot challenge the presumption of an agency official’s impartiality “by merely showing that an official has ‘taken a public position, or has expressed strong views, or holds an underlying philosophy with respect to an issue in dispute.’”

As an example, Beamon cited former Commissioner Philip Moeller’s comments in 2011 on a bill in New Jersey, which he said would “crater the capacity market” in PJM. The Maryland Public Service Commission had cited these comments in its request for rehearing of FERC’s acceptance of the RTO’s revisions to its minimum offer price rule (MOPR) (ER11-2875).

The court unanimously decided that Moeller’s comments “did not show that he ‘had made up his mind regarding two as-yet-to-be filed proceedings concerning a related, but very separate matter — the specific, regionwide operation of PJM’s MOPR,’” Beamon said.

Beamon concluded his memo by saying he “advised you to seek my guidance on any matter related to your past statements, positions, work or any other concerns that you may have.”

January 10, 2019

FERC OKs PJM Tx Constraint Penalty Factor Changes

By Robert Mullin

FERC on Tuesday approved PJM Tariff changes designed to bring the RTO into compliance with Order 844 by improving market participants’ insight into the use of transmission constraint penalty factors.

“The proposed revisions will provide transparency regarding PJM’s transmission constraint penalty factor procedures and also produce more transparent and appropriate pricing and investment signals that correspond to an underlying transmission constraint,” the commission said in its ruling (ER19-323).

Transmission constraint penalty factors are the values at which security-constrained economic dispatch (SCED) will relax the flow-based limit on a transmission line in order to relieve a constraint rather than redispatch a costly resource.

Issued last April, Order 844 said that a lack of transparency prevents market participants from understanding how the factors influence LMPs. (See FERC Orders RTOs to Shine Light on Uplift Data.)

In its compliance filing, PJM explained that its current logic for relaxing constraints prevents the penalty factor from setting the marginal value of a transmission constraint, thereby understating the severity of the constraint and producing LMPs that fail to send appropriate price signals to inform generation and transmission investment decisions.

FERC approved PJM’s proposal to remove the constraint relaxation logic from its market operations and allow the penalty factor to set the marginal value for a constraint when SCED “cannot produce a solution that manages the flow on a transmission constraint within the limits of the transmission constraint.”

The commission also found PJM’s Tariff revisions adequately describe how the penalty factor will be reflected in LMPs. The RTO had clarified that the marginal value for a constraint is used as an input for determining LMPs’ congestion component.

PJM also explained it will allow the penalty factor to set the marginal value for a constraint in market-to-market transactions, although it retains the ability to use the constraint relaxation logic at the request of an adjacent RTO.

“PJM states that it expects to use constraint relaxation logic for market-to-market congestion management with Midcontinent Independent System Operator Inc. until the second quarter of 2019, when MISO will update its market clearing engine to allow transmission constraint penalty factors to set the marginal value of the transmission constraint in its markets,” the commission noted.

PJM’s default transmission constraint penalty factor will be $2,000/MWh for real-time transactions within its own boundaries and $1,000/MWh for M2M coordinated transmission constraints on its side of a seam.

FERC also approved PJM’s plan to revise penalty factor values “to reflect persistent system operational or reliability needs, changes in the costs of resources available to relieve congestion, changes to operating practices for managing market-to-market coordinated constraints, and the unique attributes of certain transmission facilities.”

The commission additionally accepted the RTO’s proposal to post adjustments to penalty factor values “as soon as practicable” rather than setting a hard deadline, “in the event that an unforeseen circumstance arises that prevents modified values from being posted within such a deadline.” In doing so, it dismissed the Independent Market Monitor’s argument in favor of a deadline.

FERC also disagreed with the Monitor’s contentions that PJM should not retain the ability to apply its constraint relaxation logic for M2M constraints, as well as its assertion that penalty factor values take into account other system constraints, include RTO-wide reserve penalty factors.

“Establishing the default transmission constraint penalty factor values based on historical evidence, as PJM proposes, ensures that the SCED application considers all physically available dispatch options and available units to resolve binding transmission constraints,” the commission said.

The Tariff revisions take effect Feb. 1.

January 10, 2019

SPP Staff Outline Seams Strategy to SSC

By Tom Kleckner

SPP’s interregional relations staff on Wednesday shared with the Seams Steering Committee their strategic vision for seams efforts through 2021.

The vision is heavy on improving transmission planning across the seams and offering reliability coordination services in the Western Interconnection. Staff referred to the seams strategy as a “living, breathing document” that will eventually be posted on the committee’s website.

The goals include implementing improvements to the SPP-MISO Coordinated System Plan by the end of the first quarter, a process that will begin with a Jan. 31 meeting between RTO staffs and stakeholders.

SPP and MISO have revised their joint operating agreement’s planning criteria in the hopes of agreeing on a first interregional project between the two. Legal staff are currently drafting language for a MISO, SPP Tweak Interregional Criteria.)

The RTOs also plan to begin a new study this year, using the new criteria.

Other strategic goals include:

Implementing agreements between the SPP RC in the West and neighboring RCs;
Developing RC coordination agreements with neighboring western RCs;
Devising a cost-allocation Tariff mechanism for seams projects not driven by FERC Order 1000; and
Defining the coordination of grid-switchable resources with ERCOT during emergency conditions.

Clint Savoy, the RTO’s senior interregional coordinator, told the SSC that staff have begun reaching out to neighbors to evaluate the potential value and benefits of sharing operating reserve responsibilities with other balancing authorities.

The committee also welcomed ITC Holdings’ David Mindham and Corn Belt Power Cooperative’s Kevin Bornhoft as new members.

November M2M Payments Flow SPP’s Way

The MISO-SPP market-to-market (M2M) process resulted in more than $148,000 in SPP’s favor in November, the fourth straight month incurred payments have failed to reach $1 million.

Permanent flowgates accounted for the financial difference, binding for 53 hours. Temporary flowgates were binding for 592 hours but resulted in a $60.11 amount due to MISO.

SPP has amassed $51.8 million in distributions since the RTOs began the M2M process in March 2015, with payments flowing in its direction 21 of the last 26 months.