PJM PC/TEAC Briefs: Jan. 10, 2019

By Rich Heidorn Jr.

PJM Ponders Rules for Offshore Wind Transmission

VALLEY FORGE, Pa. — PJM is considering changing interconnection rules to accommodate transmission serving offshore wind generation.

Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO.

PJM’s Sue Glatz presented the Planning Committee a problem statement to consider allowing merchant transmission developers to request capacity interconnection rights, or equivalents, for non-controllable AC transmission facilities.

Glatz said transmission developers have expressed interest in building AC transmission to accommodate future generation interconnection requests. The developers want to acquire capacity interconnection rights so PJM can identify the necessary network upgrades, she said.

The key difference is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses, Glatz said.

PJM hopes to develop a FERC filing on Phase 1 of the initiative — focusing on rules for a single offshore generator lead line — by July.

Phase 2 will consider networked offshore transmission for connecting multiple wind sites. A FERC filing is targeted for September 2020. “We view this as much further down the road,” Glatz said.

Theodore Paradise, Anbaric | © *RTO Insider*

John Brodbeck of EDP Renewables N.A. asked PJM to offer education on what open-access rights generators will have to the lines.

Theodore Paradise, ISO-NE’s former assistant general counsel for operations and planning, who has joined transmission developer Anbaric as special counsel, asked for a discussion on how HVDC facilities are modeled in PJM.

The committee will be asked to approve the problem statement at its next meeting.

PJM Seeks Fix on Queue Filing Errors

PJM is proposing a one-sentence rule change to help developers avoid being removed from interconnection queues because of minor errors or omissions.

Interconnection customers are generally granted up to 10 business days to resolve deficiencies found by the RTO. But under changes initiated in 2016, requesters must clear all deficiencies by the last day.

The changes were intended to dissuade developers from late submissions. But PJM said requests are not being submitted any earlier and the changes were undermined by FERC rulings reinstating applicants removed for minor errors.

PJM’s Susan McGill presented the PC a proposed problem statement to ensure that all applicants have up to 10 business days to correct deficiencies, whether they enter on Day 1 or the last day of the six-month queue.

“We can’t have another queue where people get bumped out … they go to FERC and get waivers [to return]. It’s very disruptive,” Vice President of Planning Steve Herling said.

Since the AA1 queue opened in May 2014, 50 to 60% of interconnection requests were submitted in the last month of the queue.

Prior to the 2016 changes, which resulted from the Earlier Queue Submission Task Force, about 18% of projects submitted in the last month of the queue were withdrawn for deficiencies. After the EQSTF changes, that withdrawal rate increased to 24%.

PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”

“We’re not looking for reasons to get rid of you,” McGill explained.

PJM’s Dave Anders said Manual 34 allows the first discussion of a problem statement to include a proposed solution if the committee chair determines “the problem presented is sufficiently simple.”

Herling said, “We do have more changes we think need to be made [to interconnection queue rules]. But that will require a more robust conversation.”

PJM Pondering Wind Capacity Measures

Wind generators could see lower capacity credits under rule changes being considered by the RTO.

PJM’s Tom Falin presented the PC with the updated results of the RTO’s analysis of wind and solar resources’ effective load carrying capability (ELCC) — a measure of the additional load that a group of generators can supply without a reduction in reliability.

Effective load carrying capability is a measure of the additional load that a group of generators can supply without a reduction in reliability. | *PJM Renewable Integration Study (2014), General Electric*

The new results use the 2018 reserve requirement study (RRS) capacity model, which shows nameplate capacities for 2022/23 of 14,620 MW of wind and 5,290 MW of solar.

PJM found the average wind ELCC between delivery year 2009/10 and 2017/18 was 11.5%. That suggests the RTO’s current practice of using wind’s average capacity factor of 17.1% overstates wind’s value, Falin said. The median capacity factor over that period was 8%.

“We feel [the median is] a much, much better indicator of the reliability value” of the resources than the average, Falin said.

PJM found the average solar ELCC since 2012/13 is 42.3%, close to the average capacity factor of 42.1% and median capacity factor of 40.9%.

Falin posed two questions to stakeholders: Should PJM continue with its original proposal to change the intermittent resource capacity credit calculation from an average value to a median value? Or should it base the calculation on the ELCC methodology?

He said the advantage of changing from average to median capacity factor is “it’s much less of a black box” than ELCC.

Although the figures represent ELCC values RTO-wide, PJM said the ELCC must be allocated to individual generating units based on individual unit performance.

PJM calculates capacity credits for existing wind resources by multiplying the ELCC by the total nameplate. The RTO has three options for prorating the total capacity credit for existing units:

The average output of an individual unit during a specified number of daily peak hours in each year for which the unit was in-service;
The average output of an individual unit during the daily peak hours in which the loss-of-load expectation (LOLE) is non-zero in each year for which the unit was in-service; or
The average output of an individual unit during hours ending 3, 4, 5 and 6 p.m. during the summer season in each year for which the unit was in service.

Falin said the second option could involve as few as three hours or as many as 12 per year. The last option — PJM’s current method — has the advantage of being based on a lot of data, making it more stable than the other choices. But Falin said it also includes many hours with no LOLE risk.

For new resources, the credit can be calculated by:

multiplying the systemwide ELCC by the nameplate of the new unit (as MISO does);
multiplying an estimated zonal ELCC by the nameplate of the new unit; or
multiplying an estimated unit-type ELCC by the nameplate of the new unit.

RTO-wide ELCC values will be updated each year as part of the installed reserve margin study.

New units will continue to have the option to provide data justifying capacity credits greater than the ELCC value. As under current rules, new units’ actual performance will be rolled in over a three-year period.

PJM wants to develop manual language and request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August.

The changes would be effective June 1, 2022; thus, they would not affect UCAP values from prior auctions.

Transmission Expansion Advisory Committee

Dominion Plans $7.5M Substation Project

Dominion Energy plans to spend $7.5 million on a new substation to accommodate a new data center campus in Fauquier County, Va., with a total load of more than 100 MW.

The company will interconnect a new Lucky Hill substation between the Remington and Gordonsville substations on line #2199, a 230-kV circuit.

The requested in-service date is Sept. 15, 2020.

Supplemental Projects More than Double Baseline Additions in 2018

Transmission owners proposed $5.7 billion in supplemental projects in 2018, more than double the $2.065 billion in baseline projects included in the 2018 Regional Transmission Expansion Plan, PJM’s Aaron Berner told Transmission Expansion Advisory Committee members Thursday.

Most of the supplemental projects were presented by American Electric Power ($2.4 billion) and Public Service Electric and Gas ($1.46 billion).

More than half of the baseline projects were attributed to aging infrastructure.

Transmission owners’ supplemental projects have outpaced baseline projects in all but one year since 2015, totaling almost $15 billion. Baseline projects totaled only $8.1 billion over the same period. | *PJM*

Reliability Window Likely in June

In an update on the assumptions for the 2019 RTEP, Berner said the RTO expects to open a reliability window for proposals in June.

The 2010 RTEP will include 27 locational deliverability areas and Ohio Valley Electric Corp. FERC approved OVEC’s integration into PJM last February.

Generation with executed facilities study agreements (FSAs) will be modeled offline along with associated network upgrades, which will be analyzed separately. Berner said PJM could “turn on” FSA generation and their upgrades if there are many generation retirements but said the RTO does not expect to do so.

Travis Stewart of Gabel Associates said the American Wind Energy Association would like PJM to analyze the consumer benefits of states sharing the costs of transmission to accommodate their renewable portfolio standards. Stewart said AWEA wants more information on projects that could relieve congestion and allow PJM to access higher quality wind in the Midwest. The group may request PJM consider an RPS build-out as an RTEP future, he said.

PJM to Sunset Regional Planning Process Task Force

PJM notified stakeholders Friday that it plans to sunset the Regional Planning Process Task Force on Feb. 1 unless it receives objections from stakeholders within the task force, PC or the Markets and Reliability Committee.

The MRC voted in April 2015 to place the task force on hiatus in case it needed to be reconvened to address FERC Order 1000 or other issues. (See “Regional Planning Process Senior Task Force Placed on Hiatus,” PJM Markets and Reliability Committee & Members Committee Briefs.)

Any comments should be sent to Susan.Snyder@PJM.com.

January 15, 2019

PJM Market Implementation Committee Briefs: Jan. 9, 2019

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — It was one of the shortest Market Implementation Committee meetings in memory Wednesday as stakeholders clocked out in only two and a half hours following discussions of the must-offer exception process, FERC’s energy storage order and PJM’s indemnification rules on bilateral trades of financial transmission rights. (See related story, Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

PJM May Split Rule Changes on Must-offer Exceptions

PJM may seek approval of widely supported changes to the must-offer exception process while having further discussions on revisions that lack consensus, RTO officials told the MIC.

The MIC approved a package of rule changes proposed by PJM MRC Briefs: Dec. 20, 2018.)

The process behind the rule changes was initiated by Exelon to investigate issues including the process for existing capacity resources with a must-offer requirement to become energy-only resources.

The changes with widest support would allow market participants to voluntarily remove a generator from its capacity resource status by making a request to PJM and the Independent Market Monitor. It would also permit participants to request exemptions from multiple auctions in a single exception request. It would allow such changes for new resources that cannot be completed by the start of the delivery year for which it cleared.

There is less consensus on a rule that would require generators to forfeit their capacity injection rights (CIRs) if they are repeatedly approved for CP must-offer exceptions and not offered in capacity auctions for three consecutive delivery years.

Monitor Joe Bowring said the proposed changes failed to strike the right balance.

Bowring said PJM should discourage generators from holding on to CIRs for a long period of time because “they can’t make up their mind” about being a capacity resource.

“If someone has a clear plan, and they’re following it, that’s fine,” Bowring said. “We think this [proposal] allows more than that.”

Carl Johnson, representing the PJM Public Power Coalition, was also critical. “I’m struggling to find anything I like about any of this,” he said. “This doesn’t hang together to me as an effective set of rules.”

Sharon Midgley of Exelon asked PJM to move forward on the parts of the package with wide support, saying the only issue in dispute was over the RTO involuntarily seizing CIRs from generators after three years of successive must-offer exception requests.

PJM stakeholders are still debating a rule change that would require capacity resources to become energy-only after three consecutive years of exemptions from must-offer rules. | *PJM*

But Marji Philips of Direct Energy said her company would not support a “quick fix” based on what has been proposed to date. “The process as proposed is a little bit loose yet,” she said, adding that CIRs are “a very serious barrier to new entry.”

A few stakeholders rekindled an earlier debate over whether CIRs are generators’ “property rights.”

Gary Greiner of Public Service Enterprise Group said stakeholders need PJM’s opinion on the issue. “We’ve kind of danced on the periphery, but we’ve never come at it head on,” he said.

PJM’s Pat Bruno said the RTO may split the issue so it can seek approval of its non-controversial elements. He said the RTO will conduct additional discussions with stakeholders before the next MIC.

Electric Storage Rules Require Manual Changes

PJM’s Laura Walter gave stakeholders an update on the RTO’s implementation of rules opening its markets to e lectric s torage, saying as many as 15 manuals may require revisions.

PJM made two filings to comply with FERC Order 841 on Dec. 3, one covering markets and operations (ER19-469) for which comments are due Feb. 7, and a second governing accounting (ER19-462), for which the comment period closed on Jan. 4. The RTO plans to implement the changes by Dec. 3.

Walter said stakeholders will be asked for feedback on energy storage cost offers at the February MIC meeting. Among the items to be discussed will be whether cost offers should be based on inventory cost (historical weighted average cost of stored energy available for discharge, adjusted for round-trip efficiency); opportunity costs (expected lost net revenue from operating in a given hour); or replacement cost (estimated future weighted average cost of charging energy over the next available operating period).

First drafts of manual revisions will be presented before July, Walter said.

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.

“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.

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

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.