Page 1063 – RTO Insider

March 22, 2019

New Task Team to Review MISO Board Rules

By Amanda Durish Cook

NEW ORLEANS — MISO’s Advisory Committee on Wednesday created a task team to continue exploring whether to extend a one-year “cooling-off” period to state regulators before they apply to serve on the RTO’s Board of Directors.

The new team will also examine other aspects of the board’s makeup and required qualifications, including whether the yearlong moratorium — currently applicable to industry participants appointed to the board — should be scrapped altogether.

Advisory Committee Chair Audrey Penner said the committee could recommend that the board amend its bylaws in MISO’s Transmission Owners Agreement to adopt any improvements identified by the team. FERC must ultimately approve any bylaws changes and neither MISO nor its board is under any obligation to act on Advisory Committee recommendations.

The committee has been discussing the issues since last fall, when Nancy Lange, then chair of the Minnesota Public Utilities Commission, was nominated to fill a seat on the board. RTO stakeholders ultimately elected Lange, though some said they would have been more comfortable if she had observed the one-year moratorium required of other company executives. At the time, some pointed out that Lange had been making decisions about the grid in a MISO state that overlapped with her board member training. (See Board Cooling-off Period Still Under Debate at MISO.)

“Welcome to our dysfunctional family,” Penner joked to Lange in opening the Wednesday meeting.

MISO Director Nancy Lange listens at the Advisory Committee meeting March 20. | © *RTO Insider*

Lange now sits on the board’s System Planning Committee, which is charged with overseeing MISO’s annual transmission planning processes and spending.

“I’ve been on the other end of the MTEP [MISO Transmission Expansion Plan] in a way. I’ve seen the tussles … dreams that go into MTEP,” Lange said before a March 19 introductory presentation on the plan.

At the Wednesday meeting, Penner said there remains a “divergence of opinion” on whether the cooling-off period should apply to regulators. Some committee members have gone so far as to say the moratorium is no longer necessary.

Not all are sold on that idea.

“You could have a regulator denying a rate case on a Friday, and then deciding their transmission package on a Monday,” said Transmission Dependent Utilities sector representative Kevin Van Oirschot, of Consumers Energy.

But Wisconsin Public Service Commissioner Mike Huebsch said he stepped into that very situation as he switched from state representative to state regulator without a significant break in between roles. As a state representative, Huebsch said he argued passionately against the Badger Coulee high-voltage transmission line. By the time he was a Wisconsin regulator, he voted in favor of the line.

“It ended up going through my dad’s backyard, and I had to sign an affidavit saying I hadn’t talked to him about it over Thanksgiving,” Huebsch laughed, making the point that industry disagreements don’t have to follow individuals into new professional roles.

Huebsch said today’s transparency, especially in social media, means that the cooling-off period is an “archaic idea that’s no longer necessary.” He said any whiff of impropriety can now be widely shared on Twitter within minutes.

C-suite vs. Engineers

Some committee members also contend the board could benefit from more members with technical industry expertise. MISO bylaws currently dictate that six directors have corporate leadership experience in either board governance, finance, accounting, engineering or utility laws and regulation; another should have transmission system operation experience; another, transmission planning experience; and the final, experience in commercial markets and trading.

Missouri PSC Commissioner Daniel Hall (left) and Wisconsin PSC Commissioner Mike Huebsch | © *RTO Insider*

“You could fill this with six C-suite people and three engineers,” Huebsch observed.

Power Marketers sector representative Barry Trayers, of Sempra Energy Trading, said it seems that part of each quarterly in-person Advisory Committee meeting in front of the board is spent explaining MISO operations to new board members unfamiliar with the workings of the RTO.

Penner also said she’s heard concerns that only two stakeholders are permitted on MISO’s Nominating Committee, which vets and selects board candidates for stakeholder voting. The group is currently composed of two stakeholder seats and three director seats.

Missouri Public Service Commissioner Daniel Hall, who served on last year’s Nominating Committee, said he would have found value in “at least one more” Advisory Committee member contributing to the group’s decisions.

Independent Power Producers sector representative Mark Volpe, of the Coalition of Midwest Power Producers, said the Nominating Committee is an anomaly among entities with boards of directors because directors outnumber stakeholders and could in theory decide a candidate’s fate by themselves.

The Advisory Committee does not yet have volunteers to serve on the board process task team. Although task team membership would be voluntary, Penner said she would likely limit sectors to one representative apiece.

Meanwhile, the Advisory Committee appointed Minnesota Public Utilities Commissioner Matt Schuerger and Transmission Owners sector representative Jeff Dodd, Ameren’s director of transmission policy, to sit on this year’s Nominating Committee.

March 21, 2019

Calif. Lawmakers Reveal Growing Divisions over CCAs

By Hudson Sangree

A California State Senate hearing illustrated the rift over community choice aggregators, with some lawmakers warning of blackouts and one lashing the top state regulator for his alleged “hostility” toward the groups.

“Frankly, with all respect, Mr. Picker, your comments here today further bolster my belief that I don’t want to see the CPUC having a greater role [regulating CCAs],” Sen. Scott Wiener told Public Utilities Commission President Michael Picker at the March 19 hearing of the Energy, Utilities and Communications Committee. “I think the CPUC would pretty quickly move to kill off CCAs. I’m just being super blunt.”

Wiener said he thought the PUC was attempting to “double down on this hyper-centralized model that has not worked well for California” and had displayed hostility toward CCAs and distributed energy resources such as solar power.

The San Francisco Democrat next took aim at Picker’s testimony in a recent State Assembly hearing, where he said the commission had received 11 resource adequacy (RA) waiver requests last year from CCAs and electricity service providers (ESPs), when in fact 10 of the waivers were from ESPs, which provide electricity directly to commercial and industrial customers, and another was from one of the state’s large investor-owned utilities. (See Calif. CCAs, Decarbonization Provide Reliability C hallenges.)

Picker responded during the testy exchange with Wiener by saying, “I will apologize for the way I characterized the problem, but I will not say there’s not a problem.”

During his Senate testimony, and in his earlier Assembly testimony, Picker expressed concern that CCAs may be unable to meet the state’s local RA requirements. Some serve areas with limited transmission capacity to import electricity, he said, and might not be able to compete for electricity from generators within their load pockets during times of high demand.

Michael Picker | *California State Senate*

Picker said it may be necessary to designate an entity to serve as a central buyer of electricity to backstop CCAs and other load-serving entities. That entity could be an IOU, such as Southern California Edison, or an independent agency created by lawmakers. A bill, AB 5 6, to establish a central procurement entity was introduced in December.

Picker’s sentiments were echoed by several lawmakers who expressed concerns about a repeat of the state’s 2000/01 energy crisis, when rolling blackouts afflicted California.

Sen. Robert Hertzberg (D) this year introduced a bill, SB 5 20, that would authorize the PUC to develop threshold attributes for an LSE to serve as a provider of last resort if other LSEs fail to deliver electricity to retail customers. It would also instruct the commission to develop a method, such as an auction, for selecting the provider of last resort and to determine how that entity would benefit from its role.

“If the perfect storm happens, there has to be a backup plan,” Hertzberg told the committee.

The state’s IOUs are currently the de facto providers of last resort, but as customers migrate away from IOUs and the utilities become poles-and-wires companies, they may be unable to fulfill that function, he said.

Robert Hertzberg | *California State Senate*

Hertzberg, a veteran state lawmaker who served as Assembly speaker during the energy crisis, said lawmakers created CCAs in the early 2000s as an interim step to deliver renewable energy to local communities.

The state’s first, Marin Clean Energy, launched in 2010. There are now 19 CCAs, primarily in wealthy coastal California, with a dozen more under c onsideration by city and county governments statewide. CCAs are expected to serve more than 10 million customers, or about a quarter of California’s population, this year, according to the California Community Choice Association.

Hertzberg said the shift away from IOUs, the proliferation of renewable energy and other seismic shifts represent a “new world order” in terms of electricity delivery and reliability that still must be sorted out by policymakers.

“They’ll continue to survive,” Hertzberg said of CCAs, “but I think we’re all in for a significant change to make sure we have reliability for the people of California.”

March 21, 2019

FERC Approves MISO Pseudo-tie Proposal

By Robert Mullin

FERC on Tuesday approved Tariff revisions intended to relieve costs for MISO resources pseudo-tying into PJM despite criticism the changes don’t go far enough in easing their financial burdens (ER1 9 -34).

The new MISO Tariff provisions are the second phase of a joint MISO-PJM effort to facilitate the flow of pseudo-tie transactions between the RTOs by relieving redundant congestion costs. The need for the rule changes arose as a growing number of MISO generators sought to meet PJM’s requirement that external resources establish a pseudo-tie to participate in its capacity market.

Last July, FERC approved amendments to the MISO-PJM Joint Operating Agreement that eliminated most overlapping congestion charges applied to pseudo-tie transactions by improving alignment of the RTOs’ market-to-market settlement procedures and increasing day-ahead coordination (ER18-136-003, ER18-1 3 7-003). The commission also approved PJM’s Phase 2 revisions, which modified its Tariff to provide rebates for deviations from day-ahead commitments and removed the remaining overlapping congestion charges not addressed by Phase 1 (ER18-1 7 30). (See FERC OKs MISO-PJM Doubl e Charge Fix for Pseudo-ties.)

MISO’s Phase 2 revisions update the RTO’s Tariff to include pseudo-tie transactions in “the types of interchange schedules that a market participant must report on and coordinate with the transmission provider.” They also add “language that allows pseudo-tie transactions to utilize day-ahead virtual transactions to align the transmission usage charges and available congestion hedges” — that is, financial transmission rights. MISO said the revisions clarify that participants with pseudo-tied resources can use the day-ahead market to hedge against real-time congestion.

Another provision ensures that pseudo-tied resources out of MISO are charged for administrative costs in the same manner that market participants with physical transactions are charged by altering the billing formula underpinning those costs.

In approving the Tariff revisions, the commission noted Tilton Energy and other stakeholders have argued that MISO’s assessment of any administrative fees for pseudo-tie transactions violates the RTO’s Tariff, an issue being contested in other FERC proceedings (EL16-108; EL17-29 and EL17-54 against MISO; and EL17-31 and EL17-37 against PJM).

“Our finding here is that the reduction of the administrative charges is just and reasonable, and the question of whether MISO is authorized under its Tariff to assess these administrative charges will be addressed in the orders on the MISO/PJM pseudo-tie congestion complaints against MISO,” the commission wrote.

The commission said those proceedings also were the appropriate venue for addressing American Municipal Power and Dynegy’s objection to MISO’s continued practice of subjecting pseudo-tied resources to transmission usage charges.

“Whether the commission ultimately determines that the MISO’s assessment of transmission usage charges on pseudo-tied resources is unauthorized under the MISO Tariff does not affect the currently existing right of market participants with pseudo-tie transactions to use virtual transactions,” the commission said.

FERC also rebuffed Tilton and AMP’s contention that MISO should implement a rebate mechanism similar to that of PJM in order to ensure all overlapping congestion charges are eliminated.

“Based on PJM’s and MISO’s representations in their Phase 1 revisions and Phase 2 revisions proceedings, and the absence of evidence to the contrary, the RTOs have demonstrated that the congestion overlap has been eliminated,” FERC found.

The commission did direct MISO to amend its proposed revisions to clarify that pseudo-tie transactions are not technically included in interchange schedules, despite using language indicating they should be treated as such with respect to coordination with MISO.

March 21, 2019

FERC Rejects MISO Plan to Strengthen Queue Requirements

By Amanda Durish Cook

FERC on Tuesday rejected MISO’s proposal to impose more stringent site control requirements and increase the milestone payments for interconnection customers, while saying it could also be persuaded to accept the plan with certain revisions.

The commission found MISO didn’t adequately demonstrate its proposals were reasonable and not unduly discriminatory, even though it agreed more stringent site control requirements and higher milestones could help reduce speculative and duplicative projects. Still, the commissioners did offer guidance on how a reworked proposal might gain approval (ER19-637).

“We recognize that the filing represents a significant undertaking by MISO and its stakeholders to accomplish the important objective of preventing a large volume of speculative, non-ready projects from entering [phase one of the definitive planning phase] and subsequently withdrawing from the queue, creating adverse effects for other interconnection customers,” the commission said.

MISO had proposed interconnection customers follow one of two courses. They could either demonstrate 100% site control 90 days prior to the start of entering the definitive planning phase (DPP) of the interconnection queue or provide supporting documents and a $10,000/MW cash deposit (capped between $500,000 and $2 million) only if “regulatory limitations prohibit the procurement of site control.” (See MISO to File Queue Changes Before Year-end.) The DPP is the last three-part stage of studies, cost impacts and assessments that generation projects must scale before being granted interconnection.

MISO currently requires interconnection customers to either demonstrate 75% site control or provide a $100,000 cash deposit in lieu of demonstrating site control at the time of queue application. RTO staff have long characterized the requirements as too lax to deter non-ready projects, instead using the early DPP to “test multiple interconnection project concepts.”

MISO also proposed to change the first milestone payment from a $4,000/MW fee to 10% of the average network upgrade cost from the last three DPP cycles. MISO said the averages would be footprint-wide.

The RTO has said the proposal would speed up the queue by encouraging stalled projects to withdraw earlier in the process. The queue currently takes a little more than 500 days to complete, which MISO says is due to a “marked increase in the number and volume of interconnection requests … over the past two years.”

The Shortcomings

FERC said MISO’s proposed language that project owners demonstrate “exclusive use” site control conflicts with a Tariff section that allows interconnection customers to submit “multiple interconnection requests for a single site” and a policy that requires customers to submit separate requests for generating units that use multiple fuel sources. FERC pointed out the two-application policy applies to co-located generating facilities paired with a storage device.

“We find it unclear from MISO’s filing how interconnection customers would be able to meet MISO’s ‘exclusive use’ standard for such a generating facility. … It appears that these provisions are in conflict,” FERC said, suggesting MISO clear up how it interprets exclusive use site control for facilities that operate with multiple primary fuel sources.

FERC also said MISO didn’t describe what it expects from third-party analysis provided by an interconnection customer that wants to secure less land than MISO requires. The RTO’s acres-per-megawatt requirement differs based on fuel type, and it proposed that deviations from the land limits would have to be supported with a third-party analysis.

The commission also said MISO did not justify “the variable nature and calculation” of its proposed milestone payment on several fronts. It said the inconsistent payment average diminishes accounting certainty for interconnection customers, unfairly burdens projects in sub-regions where network upgrade costs are traditionally lower, ignores the fact that upgrade costs can vary widely across each study cycle and unfairly relies on using the costs of only preliminary network upgrades “that may not actually be built.”

Finally, the commission said MISO’s plan to shorten the window for withdrawing projects to get full refunds on the two subsequent milestone payments wasn’t appropriate when considering its proposed increase to the first milestone payment. FERC also said MISO didn’t consider that its recent removal of the first affected system analysis in the first phase of the DPP keeps interconnection customers in the dark a little longer on network upgrade costs. (See MISO Plan to Reduce Queue Studies Gets FERC Nod.)

“MISO’s proposal would require interconnection customers to post at-risk milestone payments without knowledge of potential affected system impacts that may alter their network upgrade cost estimates,” FERC said.

FERC added it might find a shortened refund window reasonable “under the appropriate circumstances.”

MISO’s queue proposal is linked with another, newer proposal to further accelerate the DPP by cutting the respective number of days throughout the three phases. (See “Measures to Accelerate Existing DPP” in MISO Details Fast-track Queue Options.) MISO staff this month had said they were relying on the increasing site control deposits and milestone fees to make for less complicated DPP modeling due to fewer late project dropouts, thus cutting the number of days other projects spend in the queue.

March 21, 2019

MISO Planning Committee to Reconsider Non-TO Storage as Tx

By Amanda Durish Cook

NEW ORLEANS — MISO’s somewhat befuddled Steering Committee on Wednesday instructed the Planning Advisory Committee to revisit the possibility of non-transmission owners operating storage-as-transmission assets (SATA).

In developing draft SATA rules, MISO had decided only registered transmission owners should own first-generation SATA to avoid introducing complexities around cost recovery. (See “No non-TO Authorization” in MISO Floats Dr a ft Storage-as-Tx Rules.) MISO’s Planning Advisory Committee decided to route DTE Energy’s February proposal that non-TOs be able to own and operate SATA to the Steering Committee, where it would be reassigned as a new stakeholder issue.

Speaking at a March 20 Steering Committee meeting, DTE Energy’s Nick Griffin said his company doesn’t believe MISO’s proposal as written is fair to non-TO entities that own storage that could become non-transmission alternatives. He said MISO is requiring non-TOs to take storage through the interconnection queue while TOs can simply submit their projects to MISO’s Transmission Expansion Plan (MTEP) study process – two different treatments for the same assets that will serve the same function.

“DTE is simply looking for equitable treatment in storage as a transmission asset,” Griffin said.

“Our feeling on this is that the DTE proposal is a much greater question that has to be answered for storage as transmission,” said MISO Director of Planning Jeff Webb. “This deals with cost recovery questions under the Tariff for assets that are neither transmission nor market assets. It’s a rather different question than fitting storage into existing transmission rules under the Tariff.”

Webb said MISO’s proposal is aimed at a scalable solution that can soon address SATA. He said the RTO has no objections to addressing DTE’s proposal, provided it’s handled separately from near-term development of SATA rules.

While the Steering Committee sent the topic back to the PAC, Steering Committee members debated whether the new issue submission would have gone before them at all if MISO’s stakeholder process was properly followed. Some criticized MISO PAC leadership for deciding to discontinue discussion and deem DTE’s request as out-of-scope without taking a vote from PAC members.

Steering Committee Chair Tia Elliott said the rejection and reroute of the topic was a “gray area.” She was surprised the topic came from the PAC only for reassignment to the same committee as a separate issue.

Webb said MISO and stakeholders agreed before drafting the SATA rules they would not address non-transmission alternatives nor create an entirely new cost allocation as a part of the SATA policy development.

“What we’re trying to do is squeeze batteries under the existing Tariff structure,” Webb said. “This seems a bit like a collateral attack on the scope of this, and it’s a little late in the game. Since it seeks a new form of cost treatment, it felt like a largely different issue … We know how to recover transmission assets; we don’t know how to recover non-transmission alternatives that are not in the market.”

As it stands, discussion on how non-TOs might recover transmission rates for their storage assets will be taken up in future PAC meetings.

March 20, 2019

Counterflow: Big Transmission is Still Dead

By Steve Huntoon

Apologies to anyone awaiting my take on the Green New Deal, but I haven’t figured out how to reduce a five-minute scream to writing.¹

Please accept instead this diatribe on something only a little less preposterous – a newly announced HVDC transmission line from Mason City in northern Iowa to the ComEd zone in northern Illinois.²

Yes, just after I declared Big Transmission still dead last month,³ along comes this 349-mile, 2,100-MW line that would be built underground in an existing railroad corridor at an estimated cost of $2.5 billion.

The business case is based on bringing wind generation from MISO to PJM. “We’re going to beat all of PJM with cheap renewable power prices,” according to the president of the independent development company proposing the merchant project.⁴

OK, where do we start? Well, let’s see. Last year, the average real-time LMP at the Minnesota Hub in MISO was $26.76/MWh.⁵ The average real-time LMP for the ComEd zone in PJM was $28.59/MWh.⁶ The difference is $1.83/MWh. We’ll come back to that number.

The all-in (pre-tax) cost of capital is estimated by Brattle/PJM for a new merchant generation project at 10%.⁷ Let’s use that cost of capital as a proxy for a merchant transmission project like this one.

A $2.5 billion capital cost times 10% is $250 million per year. Add annual depreciation of $50 million for a 50-year life. Generously assume transmission losses, O&M and management costs are zero. Divide the $300 million (annual cost of capital plus depreciation) by 2,100 MW times 8,760 hours in the year times a generous 50% capacity factor (9,198,000). You get $32.62/MWh.

Proposed SOO Green Renewable Rail project | *Direct Connect Development Co.*

So here’s the rub. There’s a $1.83/MWh difference between MISO and PJM LMPs, but the project needs an additional $30.79/MWh ($32.62/MWh minus $1.83/MWh) in order to be viable.

Why? Because no sane wind developer is going to commit to a long-term contract to pay this project $32.62/MWh for transmission service to ComEd/PJM when it can only make an additional $1.83/MWh relative to what it can get for its wind generation in MISO.

And that’s just the beginning of the rub. We haven’t included the costs of the “collector systems” to get 2,100 MW from wind projects scattered across Minnesota, Iowa, etc. to an HVDC converter station in Mason City, Iowa. We haven’t included the costs of upgrading ComEd/PJM transmission lines in northern Illinois to absorb the 2,100 MW to be delivered by converter stations at Byron, Ill., and Plano, Ill.

Oh, and on this last item we know the costs would be staggering because PJM did feasibility studies for 2,000-MW merchant transmission projects at Byron and Plano sinks in 2016. Many 345-kV lines would be overloaded and need to be upgraded.⁸ Not cheap. The project might elect not to upgrade the overloaded lines and take its chances on what would flow on an “energy-only” basis, but think about how the bottled-up energy at the converter stations would crater LMPs at those sinks. Yikes.

Big Transmission, like Generalissimo Francisco Franco, is still dead.

1-My prior take on some of that in the context of the Jacobson-Clack debate can be found here: http://energy-counsel.com/docs/Alternative-Facts-and-Global-Warming.pdf

2-http://www.soogreenrr.com

3-http://energy-counsel.com/docs/The-Test-of-Time.pdf

4-Utility Dive is playing its usual role of gee whiz cheerleader: https://www.utilitydive.com/news/independent-developer-proposes-25b-underground-transmission-line-adding/550399/

5-Averages for the months, and the peak and off-peak periods, in the MISO monthly reports can be found here: https://www.misoenergy.org/markets-and-operations/#nt=%2Fmarketsandopstype%3AMarket%20Analysis%2Fmarketanalysistype%3AMonthly%20Market%20Operations%20Reports&t=10&p=0&s=FileName&sd=desc

6-http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018-som-pjm-sec3.pdf (page 81)

7-https://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=15069666 (page 200, “Effective Charge Rate”)

8-https://www.pjm.com/pub/planning/project-queues/merch-feas_docs/ab1121_fea.pdf; https://www.pjm.com/pub/planning/project-queues/merch-feas_docs/aa2108_fea.pdf

March 20, 2019

Report: U.S. Renewable Generation Doubled Since 2008

By Christen Smith

U.S. renewable electricity generation nearly doubled over the last decade, the Energy Information Administration repo r ted Tuesday.

Solar, wind and hydroelectric resources provided 742 million MWh of electricity in 2018, up from 382 million MWh produced a decade earlier. Wind and solar generation accounted for 90% of the increase, the agency said.

Wind generation grew 80% between 2008 and 2018 to 275 million MWh, accounting for 6.5% of total electricity generation. Solar, meanwhile, exploded from just 2 million MWh to 96 million MWh, composing 2.3% of total generation last year. Utility-scale installations accounted for 69% of last year’s solar output, with small-scale rooftop, customer-sited resources contributing the rest.

Solar, wind and hydroelectric power provided 742 million MWh of electricity in 2018, up from 382 MWh produced a decade earlier. | *Energy Information Administration*

Wind capacity jumped from 25 GW to 94 GW over the decade, while solar capacity surged from less than 1 GW to 51 GW. Conventional hydroelectric capacity increased just 2%, although output varied widely over the period based on water conditions.

EIA attributed the growth in renewables to federal policies (such as the production and investment tax credits), state-level programs (such as renewable portfolio standards) and declining costs.

“As more wind and solar projects have come online, economies of scale have led to more efficient project development and financing mechanisms, which has led to continued cost declines,” the agency said.

Tuesday’s figures came on the heels of a March 11 EIA re p ort showing that Texas, Iowa and Oklahoma added 4,000 MW of wind capacity last year, composing 60% of the new units brought online in 2018. California, Florida and North Carolina built a majority of the 4,900 MW of solar photovoltaic generation added in 2018, according to the report.

Solar and wind accounted for 90% of the increase in renewable generation between 2008 and 2018. | *Energy Information Administration*

Pennsylvania Dominates New Gas Capacity

Meanwhile, natural gas-fired generators dominated new U.S. capacity additions last year, with nearly a quarter of the 19.3 GW of new units coming online in Pennsylvania alone. Maryland, Florida and Virginia combined accounted for an additional 30% of the new gas-fired resources, the EIA found. Nearly 90% of all new gas units were combined cycle, the agency said.

EIA said the U.S. added a total of 31,300 MWh of generation and retired 18,700 MWh in 2018. Inefficient coal plants and natural gas steam and combustion turbine units accounted for the majority of the retirements, with just one nuclear plant – Oyster Creek in New Jersey – shutting down.

The U.S. added 31,300 MWh of capacity in 2018. | *Energy Information Administration*

The results underscore the continuing struggle of coal plants to maintain market share as state policies push developers toward cleaner, more efficient technologies. Gas-fired energy output exceeded coal for the first time in PJM, the Independent Market Monitor said on Thursday. (See Monitor Says PJM’s Capacity Mar k et Not Competitive.)

In December, EPA relaxed regulations on newer coal-fired plants as nationwide consumption hit its lowest point in 39 years. (See EPA Eases Rules for N ew Coal Generation.) Coal retirements for the year came in as the second most on record, according to EIA, with another 4,000 MW of capacity scheduled for retirement by the end of 2019.

The U.S. retired 18,700 MWh of capacity, mostly coal plants, in 2018. | *Energy Information Administration*

March 18, 2019

Green ‘Moon Shot’ not Possible, Physicist Tells NERC Forum

By Rich Heidorn Jr.

WASHINGTON — Physicist Mark P. Mills gave the NERC Reliability Leadership Summit a blistering and entertaining critique of green tech punditry, saying forecasts of a rapid shift away from hydrocarbons are delusional.

Mills, senior fellow at the conservative think tank the Manhattan Institute, said the big challenge for green technology is the scale of hydrocarbon use — 80% of world energy — and its superior energy density.

“If all of the hydrocarbons that we consume were actually in the form of oil … and we divide them up into barrels, those barrels would go from here in D.C. to [Los Angeles],” he said in a keynote speech. “And the barrels would grow in height at the rate we consume it by one Washington Monument every week. That by itself demonstrates how fatuous it is to talk about ‘moon shots’ to change a system like this. Putting a few people on the moon a few times is an amazing engineering achievement. [But] it’s not a transformation of anything. Transforming and changing how society uses energy is like putting all of humanity on the moon — permanently.”

Mills said those who predict Moore’s Law-scale performance improvements in renewables are making a “category error” in conflating energy technology with digital technology. He cited as an example an International Monetary Fund working paper, “Riding the Energy Transition,” on the potential of electric vehicles to cut oil consumption, which stated “Smartphone substitution seemed no more imminent in the early 2000s than large-scale energy substitution seems today.”

“The biggest energy revolution in terms of how we use energy is unequivocally what we’ve done in computing. Nothing like this has every happened in the history of humanity,” Mills said. “If today’s iPhone had 1980s energy efficiency, that iPhone would be taking the electricity of a Manhattan office building. If a single data center operated at 1980 energy efficiency, one data center would require the entire output of the U.S. on the grid.

“But analogizing information-producing technology with energy-producing technology is a fundamental category error. It’s much worse than comparing apples to oranges. It’s even worse than comparing apples to ball bearings. The difference in the physics between information-producing and energy-producing is deeply profound. If energy systems could scale like computing systems, a single postage-stamp size solar array could power the Empire State Building.”

“That … will … never … happen,” he said, pausing for emphasis with every word. “It happens in comic books. It’s science fiction.”

Mills said the aspirational targets of green tech supporters is based on the notion that wind, solar and battery technologies can make 10-fold gains in efficacy.

“The last few decades, we have seen 10-fold gains in the fundamental efficacy of wind, solar and batteries. But another 10-fold [improvement] is not going to happen. Solar technologies are now approaching underlying physics limits.”

Wind turbines are also closing in on Betz’s law, which states that no turbine can capture more than about 60% of the kinetic energy in wind. “The best wind turbines are now pushing 45% efficiency. … It’s a hell of an achievement,” Mills said. “There’s no 10x left. We’re done.”

Batteries have more headroom for improvements but still face fundamental limits, Mills said.

“There is 1,500% more energy available in a pound of oil than in the best pound of battery chemistry. That’s a big gap. There’s no physics known to close that gap. If you want hydrocarbon class energy density, you would invent oil.

“Now the electrochemistry of batteries is going to get a lot better. There’s a lot of cool stuff on the horizon.”

But the cheapest batteries are currently six times the cost per kilowatt of natural gas generation, Mills said. Even if they reach the “aspirational goal” of two to three times gas-fired generation, batteries won’t be able to replace gas-fired generation on cost.

Mills said there is actually more room for efficiency improvements in shale gas extraction, which he called “under-engineered” despite improvements in horizontal drilling and fracking. Mills has put his money where his mouth is: He is a strategic partner with energy-tech venture fund Cottonwood Venture Partners, whose portfolio consists entirely of companies serving the oil and gas industries.

He did not say whether he still holds to the views of the Greening Earth Society, a now-defunct petroleum industry-backed organization that opposed EPA’s regulation of CO₂ as a pollutant, insisting it was “one of nature’s most fundamental building blocks.” Mills was among the group’s scientific advisers.

Mills said policymakers concerned about climate change should support funding of basic science that can result in breakthroughs rather than looking for incremental improvements to existing technologies. “You didn’t get the car by subsidizing the railroads,” he said.

“The world has spent $2.5 trillion in 20 years on nonhydrocarbon energy forms. And the world has reduced its use of hydrocarbons as a percentage of consumption by 1.5 percentage points. And we use 150% more hydrocarbon than 20 years ago.

“My policy recommendation is … take most of the money that we’re using to subsidize yesterday’s stuff — and I mean wind turbines, yesterday’s batteries — and put half of it back in the Treasury for deficit reduction and the other half give to basic science, because that would be a 10-fold increase for basic research.”

March 18, 2019

NERC CCC Briefs: March 12, 2019

WASHINGTON — After 12 years as the FERC-delegated Electric Reliability Organization, it’s time for NERC to reconsider its approach, General Counsel Charles Berardesco told the Compliance and Certification Committee (CCC) last week.

About 50 utility and RTO officials and NERC staff attended the Compliance and Certification Committee meeting at Edison Electric Institute headquarters in D.C. last week. | © *RTO Insider*

“The way the grid operates is dramatically different from the way we thought about it. … We have to look at the changing nature of the industry and think about being more proactive about those changes,” he said. “So, does everything go to a standard? … Is there another approach? Are assessments enough? Is it enough for NERC to just raise its hand and say, ‘Whoa! Here’s the issue. You should be worrying about this’? Do we need to do something in between?”

About 50 committee members and NERC staff attended the March 12 meeting at Edison Electric Institute (EEI) headquarters on Pennsylvania Avenue. (See related story, NERC Survey Highlights Alignment, Transparency Concerns.)

In addition to the routine “blocking and tackling” of consistently implementing its risk-based Compliance Monitoring and Enforcement Program (CMEP), Berardesco said, “We need to continue to enhance our expertise on assessing the grid’s overall reliability. We need to continue to build better data streams and build analytic capabilities inside of NERC [with] the industry.”

Berardesco noted that NERC’s Regional Entities will be reduced from seven to six effective July 1 when the Florida Reliability Coordinating Council (FRCC) is scheduled to be merged into SERC Reliability.

“Those regions, for the first time, will be about the same size and the same scope. We also have some new leadership in the regions. So, I think it’s an opportunity, a moment in time, to think about roles and responsibilities in a different way at the ERO to ensure we’re actually using our resources most effectively and efficiently and focusing our efforts on reliability, not just process,” he said. “I think what it means is thinking about the ERO as one organization, not seven different entities. And that’s a lot of the work that’s going to be going on in the next couple years at NERC.”

Delivering an update on the Reliability Issues Steering Committee (RISC), RISC member Patti Metro also called for a re-evaluation, saying the committee is planning to “streamline and fine tune” its activities.

“We are under the impression it’s time to step back and [review the effectiveness] and efficiencies when it comes to RISC,” said Metro, senior grid operations and reliability director of the National Rural Electric Cooperative Association. “Is it time to step back and say, ‘How much value is that exercise [providing? Should we be] continuing to do that type of report?’”

Self-reports accounted for more than three-quarters of noncompliance with NERC rules in 2018. | *NERC*

She noted that NERC’s Reliability Leadership Summit, held March 14, “is very similar to the tech nical conf erence that the FERC does every summer. We hear the same topics, the same conversations, a lot of the same speakers speak in both of those events. And so, our [question] is, should we regroup, and do we have to continue doing that type of event?” (See related story, Changing Grid Calls for New Models, Mindset, Officials Say.)

The RISC will present a report on its plans at the NERC Board of Trustees’ August meeting.

Berardesco said he had one message for members to take back to their companies.

“Security is a lot more important than compliance. We [NERC] can never do anything bad enough to you as would happen if there’s an actual breach in security. … NERC is not your problem. Security is your problem, and I would just urge all of you to think about that in the context of how you interrelate with NERC. The sharing of information, which is so critical to making this system work better, should not be withheld because you’re worried about a compliance risk.”

EEI Security Chief Warns Against Complacency

Scott Aaronson, EEI’s vice president of security and preparedness, also warned against becoming complacent with achieving compliance. “If I put a 10-foot fence around everything … the adversary just brings a 12-foot ladder,” he said. “So, let’s not pretend that standards themselves equate to security.”

“If we’re not preparing for failure, we’re going to fail. That is a sign, I like to believe, of maturity in this sector: That we are willing to talk about — not just all the things we are doing to prevent bad things from happening — but our effectiveness at response and recovery when the bad things come.

“Not if, but when: cyber, physical, storms, acts of war, acts of God. Zombie apocalypse. [We] don’t care why: The power’s out. What are we going to do about it?”

“We have a sense of urgency, both here at EEI and through the [Electricity Subsector Coordinating Council] to do more, do more, do more. Because we know that a war used to be started with a ballistic [missile] being fired downrange. It is far more likely today that a war is going to be started with strokes of a keyboard and attacks on critical infrastructure,” he said. “We know we’re a target.”

Serious critical infrastructure protection violations have dropped since peaking in 2014-16. | *NERC*

Subcommittees to Merge

CCC Chair Jennifer Flandermeyer, of Kansas City Power and Light, said members are moving forward with plans to eliminate the Compliance Processes and Procedures Subcommittee (CPPS) and merge its functions into the ERO Monitoring Subcommittee (EROMS).

“There are a number of reasons for [the merger] but primarily because the workloads tend to complement each other,” Flandermeyer said. “The expertise needed for both of those subcommittees is similar, if not the same, and what CPPS was seeing in their work was feeding the ERO Monitoring Subcommittee, and what EROMS was seeing was actually providing input that was helpful to CPPS. So, there was a natural synergy there.”

EROMS Chair Ted Hobson, of Florida cooperative JEA, will serve as chair until the FRCC seat is dissolved. Lisa Milanes of CAISO will be the vice chair.

“Our expectation is that we would have an approved scope document [for the combined committee] that’s operational before the June [CCC] meeting,” said CPPS Chair Matt Goldberg, of ISO-NE.

[Editor’s Note: An earlier version of this article incorrectly described NRECA’s Patti Metro as the chair of the Reliability Issues Steering Committee (RISC). The RISC chair is Nelson Peeler, chief transmission officer for Duke Energy.]

— Rich Heidorn Jr.

March 18, 2019

Texas Public Utility Commission Briefs: March 13, 2019

The Public Utility Commission of Texas last week formally approved Rayburn Country Electric Cooperative’s request to move 96 MW, or about 12% of its load, and associated transmission facilities from SPP into the ERCOT system. The commission set an integration date of Jan. 1, 2020, during its March 13 open meeting (Docket 48400).

At the same time, the PUC denied Rayburn and Lone Star Transmission’s request to transfer ownership of a 10-mile, 138-kV transmission line and associated rights from Rayburn to Lone Star.

The PUC put off a final decision during its Feb. 7 open meeting. (See “PUC Puts off Final Decision on Rayburn Country,” Texas Public Utility Commission Briefs: Feb. 7, 2019.)

ERCOT’s integration of Rayburn Country Electric Cooperative | *ERCOT*

Rayburn owns and operates 367 miles of transmission lines in Texas, 207 miles of which are in ERCOT. The cooperative will integrate 130 miles of 138-kV lines into ERCOT, with a remaining 30-mile 138-kV circuit staying in SPP.

The co-op late last year reached an unopposed settlement with commission staff, Oncor and Texas Industrial Energy Consumers that approved the transfer. The agreement also denied the Lone Star purchase of the transmission line.

Southwestern Electric Power Co. has served Rayburn’s SPP load through a power supply agreement with the co-op since the 1990s. The contract with SWEPCO will terminate at the end of 2019.

ERCOT has estimated it will cost $31.7 million to integrate Rayburn’s load with the other 88% (approximately 710 MW in 2017) that is already part of the grid operator’s system. Rayburn will make annual hold-harmless payments of $4.5 million for five years to ERCOT wholesale transmission customers through a wholesale transmission service credit rider.

PUC to Intervene in FERC Dockets

Left to right: Texas PUC Commissioners Shelly Botkin, Chair DeAnn Walker and Arthur D’Andrea.

Following an executive session, the commission agreed to intervene in four FERC dockets:

ER19-1 1 24 and ER19-1125, both related to MISO’s Tariff modifications expanding, modifying and clarifying the identification and cost allocation of transmission facilities providing regional and local economic benefits within the RTO’s footprint.

ER19-1156, which adds to MISO’s Tariff a cost allocation methodology for the RTO’s share of certain interregional economic projects with PJM or SPP.

The Louisiana Public Service Commission’s complaint against Entergy and its operating companies that alleges the company’s joint account sales of energy to third-party power marketers and other nonmembers of the Entergy System Agreement from Entergy Arkansas’ Grand Gulf Retained Share violated the agreement (EL19-50).

— Tom Kleckner