Page 1162 – RTO Insider

June 10, 2018

Overheard at the EIA Energy Conference

WASHINGTON — The headlines at the Energy Information Administration’s 2018 Energy Conference were generated backstage, as FERC Chairman Kevin McIntyre and Department of Energy Undersecretary Mark Menezes were questioned by reporters about President Trump’s coal and nuclear bailout after their speeches. (See FERC Blindsided by Half-Baked Trump Order.)

FERC ERCOT EIA GE Power — Kaplan | © *RTO Insider*

But an earlier panel featuring officials from PJM, ERCOT and GE Power also provided some highlights. Stan Kaplan, director of EIA’s Office of Electricity, Renewables and Uranium Statistics, moderated questions from the audience.

Are microgrids a fad?

No, said Eric Gebhardt, chief innovation officer for GE Power.

“In many cases, the microgrids are being installed [for industrial uses] because of higher-cost electricity. … A 10-MW natural gas [reciprocating generator] can produce a [levelized cost of energy] of around 6 cents/kWh, which is extremely competitive.”

Adding cogeneration, “a [combined heat and power] application where you take the heat off that to create steam for your process or you use it for HVAC purposes, it drives the value even further. … With a combined heat and power [application], you could be pushing 90% efficiency in the overall cycle, which is great efficiency.

“The second thing is many customers are looking to decarbonize by putting in solar in conjunction with this. And then you start using energy storage as part of that for peak demand clipping, because many times these microgrids don’t [supply] 100% of the load. They might be 80% of the load, might be 70% of the load … so, there’s many ways it can be economic.”

In contrast, he said, microgrids “trying to be completely off-grid … that’s not always an economic way to operate today, or not necessarily the most economic way to operate today.”

Does a more intelligent, distributed grid increase resilience or make us more vulnerable to cyberattacks?

“Arguably, spreading things out, having distributed resources, microgrids, are in one way maybe increasing the cyber grid [attack surface],” said Craig Glazer, vice president of federal government policy for PJM. “You’re also enabling [resilience]. It’s not like you can attack one substation and take out metropolitan areas. So, I think on balance [there’s] probably more benefit to that.”

The bigger challenge, Glazer said, is that there are no mandatory cybersecurity standards for the natural gas pipeline industry, unlike the electric grid.

“You know who regulates the cybersecurity of the natural gas pipeline industry? The TSA [Transportation Security Administration], the people that check your bags at the airport. …

“There is a very small staff. They’re dedicated people. But it’s a very small staff totally underwater, frankly, in this area.

“If you hit the fuel supply, you’re going to have an impact on the electric grid, yet we somehow have just accepted a vastly different structure: voluntary, suggested standards for the pipelines versus mandatory standards for the electric grid.”

Are the industry’s capabilities keeping pace with the increasingly intelligent, complex grid and the growth of behind-the-meter generation?

“It’s a great question that I don’t know the answer to,” said Beth Garza, director of the ERCOT Independent Market Monitor.

“The interaction of more and more data [with] finer granularity, and then having the systems and tools to process this … to turn it into actionable information, I think is a challenge. I tend to be optimistic on all of that … but I do see it as a challenge.”

Gebhardt agreed. “How do you deal with going from a thousand centralized power plants to hundreds of thousands and hundreds of millions of end nodes that are going to be producing power, as well as being able to curtail power, simultaneously? How does all of that get managed? That’s going to be something that many utilities and technology companies have to deal with.”

Glazer recalled the April 2015 power outage that darkened the White House and much of downtown D.C. NERC said it began with the failure of a 230-kV lightning arrester 40 miles south of the capital. (See Failed Lightning Arrester Caused April Outage.)

FERC ERCOT EIA GE Power Natural Gas Pipeline — | © *RTO Insider*

“The outage was not that big a deal, but the restoration was much more complicated because [PJM], as well as the local utility [Pepco], didn’t have any visibility into which buildings had backup generation and were running them and which ones didn’t.

“So, the [National] Air and Space Museum had backup generation; the Hirshhorn Museum didn’t. But nobody knew that. This happened on a patchwork all through Washington. It made the restoration that much more difficult.”

California’s solar generation has produced the late afternoon duck curve. Why don’t we hear about ramping challenges in ERCOT?

“Part of the challenge in California is that customers don’t use as much electricity as they do in Texas,” Garza said. “It is very much driven by [Texas’] air conditioning load in the summertime. That is supported by solar [generation] but any kind of projection I’ve done that’s grossed up the solar curve on our load curve, I can’t get Texas to look like the California duck curve.”

Will energy storage replace combustion turbine peaking plants?

“That question comes up a lot,” Gebhardt said. “I look at it more as an ‘and’ versus an ‘or’ question, because there’s so many existing peaking plants that are out there right now. Combining them in a hybrid application with energy storage brings tremendous value. … The batteries handle the really fast ramp rates and allow the gas turbine to come on at a slower ramp rate going from a dead stop. … And if you have it there, it also serves other purposes — voltage support, frequency response…

“Certain parts of the U.S. are testing markets, saying we would take either a combined cycle gas turbine or some sort of gas turbine or energy storage. … But for the vast majority, the ‘and’ solution is probably the better one.”

June 10, 2018

MISO Stakeholders to Rank Market Improvement Ideas

By Amanda Durish Cook

CARMEL, Ind. — Over the next month, MISO stakeholders will rank 14 market improvements the RTO might undertake in 2019.

Stakeholders have until July 12 to take MISO’s Market Roadmap candidate ranking survey and organize eight new and six existing improvements by priority. The survey was announced during a June 7 workshop.

In addition to ranking the eight new submissions approved this spring for consideration by the Steering Committee, stakeholders will also consider six currently active initiatives that have already been discussed in stakeholder meetings. (See Steering Committee Advances MISO Market Improvement Ideas.)

The active items under consideration include:

Improving generator modeling so it can depict more combinations of combined cycle units;
Creating a short-term capacity reserve product available to solve capacity shortages within 30 minutes;
Developing a multiday market forecast;
Improving energy storage resource integration beyond what is required for FERC compliance;
Automating dynamic ratings for transmission lines that offer temperature-adjusted and short-term emergency ratings; and
Continuing to develop new market rules and requirements under MISO’s large resource availability and need effort. (See MISO Looks to Address Changing Resource Availability.)

MISO will review survey results at the August Market Subcommittee meeting, and then reconcile its preferred ranking with stakeholders’ prioritization to update a work plan for 2019 to 2023, said Lakisha Johnson, the RTO’s market strategy adviser.

The RTO has already issued a first draft of the roadmap based on internal rankings of the 14 proposals, designating its resource availability and need (RAN) effort, and plan to create a short-term capacity product as top priorities, followed by better modeling of combined cycle generators. Next on the list: creating a look-ahead dispatch tool, improved modeling of all generators and more comprehensive storage resource integration. The RTO ranked all other candidates as low importance.

This year’s ranking features only a partial list of roadmap ideas and doesn’t include improvements relegated to the “parking lot,” the lowest-ranked candidates that MISO and stakeholders predict will be useful sometime in the future. Parking lot items are reintroduced in the ranking for refreshed status every other year.

energy storage resource integration miso pjm market roadmap — Adams | © *RTO Insider*

“Each year, we alternate between doing a fully exhaustive ranking of the parking lot versus only focusing on active and new candidates,” explained MISO Senior Manager of Market Strategy Mia Adams.

However, this year, MISO moved the suggestion for financial incentives for primary frequency response from the parking lot into the Market Roadmap because Indianapolis Power & Light submitted a new version of the suggestion.

Some stakeholders wondered if some improvements should be combined with others.

“There’s some concern if you make something of a Frankenstein roadmap product,” Adams said, adding that MISO may be open to bundling market improvements into portfolios when it makes sense.

Customized Energy Solutions’ Ted Kuhn said he thought the roadmap was meant for more in-depth market improvements than some of the new ones submitted this year, singling out Independent Market Monitor David Patton’s new recommendation to remove transmission charges from coordinated transmission service with PJM.

Patton said the coordinated transactions with PJM are rarely used, and the product has “failed” because MISO levies charges when an offer is made in addition to when an offer is struck.

But Kuhn said the Monitor’s suggestion could be completed “in a weekend” and questioned its consideration in the roadmap.

MISO Executive Director of Market Operations Jeff Bladen said Market Roadmap items represent “a variety of dimensions” and said stakeholders should come with suggestions on which products could be fast-tracked.

Northern Indiana Public Service Co.’s Bill SeDoris said one parking lot item should be considered sooner than next year — creating a compensation process for energy delivered during a system restoration event, an idea currently on hold. The item is timely and fits well into current discussions around resilience, SeDoris said. He added that the issue had been discussed recently in closed session discussions of the Reliable Operations Working Group.

Patton cautioned against focusing too much on the resilience “buzz word” when deciding which improvements to undertake.

SeDoris responded that MISO might appear remiss for not having discussed restoration energy compensation the next time it goes before FERC to discuss resilience. He said he would bring the issue to the Steering Committee’s next meeting in the hopes of reigniting interest in creating a compensation mechanism.

June 10, 2018

Land Rights a Challenge to Mexico Tx Developers

By Tom Kleckner

MEXICO CITY — Bob Smith has enjoyed a long career in transmission planning and development, much of it in the American West where he said federal lands can create “unique problems” for building electric infrastructure.

As vice president of transmission, planning and development for TransCanyon, Smith is responsible for conceptualizing and planning transmission projects for the joint venture between Berkshire Hathaway Energy and Pinnacle West Capital.

BHE is Warren Buffett’s energy holding company that includes PacifiCorp and NV Energy. Pinnacle West’s assets include Arizona Public Service. Together, they offer $90 billion worth of “leverage” to TransCanyon.

Smith told a Gulf Coast Power Association breakfast audience last week that “there’s a clear need for transmission infrastructure” in Mexico, and that the country is “fertile ground for these opportunities.”

So why is TransCanyon going to “watch the process and see what happens” for the time being?

Two words, say veterans of the emerging Mexican market: land rights.

“I’ve gotten the sense it’s every bit as difficult here as it is in the United States,” Smith said during the June 6 breakfast, the seventh in a series. “I get the sense there’s a real value of the long-term commitment to the land and cultural identity.”

Stations of the Cross

Just ask Energia Veleta’s Mannti Cummins, who is working to develop a 50-MW wind farm in Baja California Sur. He filed a social impact study, one of several necessary requirements before construction can begin, with Mexico’s Ministry of Energy (SENER) in July 2016. He received a response back last week.

However, first Cummins had to meet with a SENER representative housed in the ministry’s training facility, a dated, one-story, cement building located in a working-class part of Mexico City. Cummins was told his study was in order, but that he would a receive an electronic copy of SENER’s “opinion letter” later. The document, indicating the Office of Social Impact Studies had the “necessary and sufficient information” to do its own evaluation, arrived in Cummins’ email at 1:10 a.m. He then had to return to the SENER office later that morning to sign a document acknowledging he had received the PDF.

Electronic signatures are not considered official in Mexico, Cummins said.

“They want original, wet signatures. The most mundane business in the U.S. becomes an administrative stations of the cross here in Mexico,” said Cummins, a practicing Catholic.

Fortunately for Cummins, the proposed wind farm is in a desolate area of the state, near the oil-fired generators “that keep the beer cold in Cabo.” He only had two landowners to deal with, and none of the federal lands, social property, conservation areas and indigenous territory that other developers will face. Still, it took a team of six students working 24/7 for six weeks under their former professor to produce baseline studies, conduct interviews and draft the report.

“It would take anyone else six months,” said Cummins, who was facing an investor’s deadline. “And this was for 50,000 acres and two landowners.”

Legacy of Revolution

Mexico Transmission Planning Land Rights — Robinson | © *RTO Insider*

Sebastian Robinson, director general of Punto Focal, a surveying firm that specializes in setting real estate boundaries, says 51% of the country now consists of social property called ejidos, a result of the Mexican Revolution that dragged on from 1910 to 1940. When you discount the urban areas, he said, that percentage jumps into the 60s.

“The problem is, ownership has become muddled,” Robinson said.

Land ownership became an issue in the 1890s, when 20% of the country was owned by foreign interests and rich landowners. By 1910, half the country’s rural population worked on huge estates essentially as slaves, and the pent-up frustration was one of the primary causes of the revolution.

It wasn’t until socialist Lazaro Cardenas was elected president in 1934 that much of the ensuing violence subsided. Cardenas instituted the practice of ejidos, in which peasants within a community were given sub-parcels of former estates or national land — some as large as 120,000 acres — but the land was not necessarily registered, Robinson said. President Carlos Salinas eventually ended the practice in 1992.

Many of the ejidos’ original owners have long since died without transferring the titles, or they have moved into the cities to escape rural poverty. “With maybe 90% of the ejidos, there’s no chain of title,” Robinson said.

And while the government maintains a public registry of social land, Robinson said there’s no legal inventory of land ownership. The problem is magnified by the lack of accurate surveys.

Robinson and Cummins bring all this up in pointing to the potential difficulties facing the first two competitive transmission projects currently out for bids by Mexico’s state-run utility, the Federal Electricity Commission (CFE). Mexico’s energy reform of 2014 opened up the transmission system to private contractors, partly because CFE keeps its retail rates artificially low for political purposes, and it can afford to do little more than keep the lights on, Cummins said.

One of the projects is a $1.2 billion, 870-mile, 500-kV connection between Mexicali in Baja California and Hermosillo, Sonora, in northwestern Mexico. The second is the $1.7 billion Oaxaca project, more than 1,000 miles of 500-kV line between Mexico City and Veracruz, home to the country’s only nuclear plant. Technical bids on the first line are due June 15, and the Oaxaca bids are due in July, but a requirement of HVDC experience will likely limit the field.

Robinson said CFE already owns 89% of the Oaxaca project’s right of way, but that still leaves about 100 miles of line where ownership will have to be determined and dealt with. “That’s a lot of problems,” he said.

Both projects will be built under a build-operate-transfer (BOT) model, in which private companies will build the infrastructure, operate and maintain the system while recovering rates, and then transfer all the rights, licenses, permits, authorizations and property to CFE.

“CFE used to own it all,” Cummins said. “Now, it just administers the network.”

Watch and Wait

Still, developers say Mexico is too big of a market to ignore. SENER says the country’s generating capacity has doubled to more than 73 GW since 2000, and load growth and the retirement of aging, inefficient plants will require another estimated 50 GW of generation over the next 15 years. Mexico hopes to add $10 billion worth of transmission infrastructure in the coming years, including the two competitive projects.

Smith pointed to Mexico’s load growth, broad support for renewable energy and “mature and competent” planning processes as reasons to get involved in the market.

To be fair, Smith said TransCanyon was too late to bid on the Oaxaca project. The company did look at the Hermosillo-Mexicali project, he said, but decided to “monitor progress” of the initial offers “to learn the best way to engage.”

“We decided at this point, between the risk and lack of experience [in Mexico], we decided it wasn’t a wise thing to do,” he said. “We’ll try to learn lessons on best way going forward. There are some tremendous opportunities here. It’s early, very early in the process, but it’ll be interesting to see how it goes.”

June 10, 2018

FERC OKs Reliability Standard on Fault Protections

By Rich Heidorn Jr.

FERC last week gave final approval to NERC reliability standards on training requirements and the coordination of protection systems to detect and isolate faults (Order 847, RM16-22).

Standard PER-006-1 (Specific Training for Personnel) sets training requirements for real-time operations personnel to ensure they understand the purpose and limitations of protection systems schemes. It also adds more precise and auditable requirements, FERC said.

FERC Reliability Standards Fault Protections — | © *RTO Insider*

PRC-027-1 (Coordination of Protection Systems for Performance During Faults) seeks to ensure protection systems operate in the intended sequence. It requires applicable entities to perform a protection system coordination study to determine whether the systems are operating in the proper sequence during faults or compare present fault current values to an established fault current baseline. In the latter case, a coordination study would be required only if there is a 15% or greater deviation in fault current values. The reviews are required every six years.

The commission’s June 7 order also approved new and revised definitions for three terms: protection system coordination study, operational planning analysis and real-time assessment.

FERC, however, rejected a proposal in its Notice of Proposed Rulemaking to modify PRC-027-1 to require an initial protection system coordination study as a baseline, bowing to complaints by NERC and others.

NERC said that although the requirement could help reduce misoperations caused by a lack of coordination, it would be costly and burdensome. The reliability organization said it “expects that many entities will choose to do a full protection system coordination study … for their more impactful [bulk electric system] elements” and that “it is highly likely that the overwhelming majority of entities have already conducted coordination studies for their protection systems.”

FERC said it agreed that applicable entities will conduct studies on their significant facilities even without the requirement.

“We recognize the concern that were the NOPR directive adopted, applicable entities could be required to rerun protection system coordination studies for the sole purpose of generating compliance documentation, even if such entities already performed protection system coordination studies that remain valid but lack documentation to substantiate compliance,” the commission said.

June 10, 2018

Court Backs FERC Reversal on PJM Tx Upgrade

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Friday backed FERC in its revised interpretation of a PJM Tariff provision governing responsibility for transmission upgrades, turning aside a challenge by the owner of a power plant in Marcus Hook, Pa. (ESI Energy v. FERC, 16-1342).

At issue was whether LS Power Associates, the parent of West Deptford Energy, should be liable for transmission upgrades ordered before the developer entered PJM’s interconnection queue. In 2014, the court vacated FERC’s order ruling the company was liable, calling the commission’s decision “the very essence of unreasoned and arbitrary decision-making.” (See Appeals Court Scolds FERC over West Deptford Interconnection Dispute.)

West Deptford (N.J.) energy plant under construction| *MJ Electric*

West Deptford submitted its interconnection request on July 31, 2006, and was later informed it would be assessed $10 million for improvements PJM ordered as a result of two previous projects, FPL Energy Marcus Hook and Liberty Electric.

Tariff Change

Under section 37.7 of the PJM Tariff then in effect, the RTO could seek reimbursement for a previously constructed network upgrade if the new proposed project used the added capacity created by the project or would have required it itself. The reimbursement request only applied if the cost of the upgrade was at least $10 million and it was placed in service no more than five years before the interconnection customer’s queue closing date.

If section 37.7 controlled, West Deptford would have been required to reimburse Marcus Hook and Liberty Electric for the upgrade. (Ninety percent of the upgrade’s cost had initially been assigned to Marcus Hook.)

In 2008, however, while West Deptford’s interconnection request was pending, PJM won approval for an amendment changing the assignment of responsibility for prior upgrades. Section 219 of the revised Tariff allowed PJM to seek reimbursement for previously constructed upgrades for only five years “from the execution date of the interconnection service agreement for the project that initially necessitated” the upgrade.

FERC initially ruled that West Deptford must pay, concluding that the 2006 rules applied. But the court said FERC’s ruling “provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”

FERC Reversal

In response to the remand, FERC in August 2016 reversed its ruling, relieving West Deptford of the reimbursement obligation (ER11-4073). FERC said it based its decision on the “significant skepticism” the D.C. Circuit expressed in the remand order and the “numerous shortcomings” the court identified in the commission’s analysis.

Marcus Hook appealed, saying the old rules should apply to West Deptford and challenging FERC’s interpretation of the five-year trigger under the new rules. (Florida Power & Light subsidiary ESI Energy was later substituted for Marcus Hook as petitioner.)

In siding with FERC, the court said the commission “directly and adequately addressed” Marcus Hook’s challenges to the determination that section 219 applied.

FERC was required to provide a “reasoned explanation” of how applying section 219 comported with the Federal Power Act and commission precedent, the court noted. “Unlike its prior decision, the commission’s decision on remand did both,” it said.

5-Year Trigger

Although section 219 did not specify what action was required within the five-year window to trigger cost responsibility, FERC said the most reasonable interpretation was that the “end date” was that on which West Deptford signed its interconnection agreement.

Marcus Hook argued that section 219 made an interconnection customer liable for an upgrade that entered service during the five years preceding the customer’s queue entry. It said the dispositive date should be either when West Deptford submitted its interconnection request (July 31, 2006) or when PJM determined that the upgrade was required for its interconnection (November 2006).

“Although Marcus Hook’s suggested interpretation is a possible reading of the Tariff provision, it is no more reasonable than the one the commission put forward,” the court ruled. “Accordingly, we find that the commission did not err in its interpretation of section 219 of the revised Tariff.”

June 10, 2018

Overheard at New England Energy Conference and Exposition 2018

By Michael Kuser

FALMOUTH, Mass. — New England is up to the task of managing the tough challenges facing its wholesale market and grid — even if there is no grid in the future, regional energy experts said last week.

NEECE wholesale market ISO-NE — Foy | © *RTO Insider*

“The feds are less important now, and New England used to live by its wits — we never had oil or gas — but now we’ve got offshore wind,” Douglas Foy, president of energy consultancy Serrafix, said Monday at the 25th annual New England Energy Conference and Exposition. The event is hosted jointly by the Northeast Energy and Commerce Association and the Connecticut Power and Energy Society.

Looking back on the era of restructuring electricity markets in the 1980s and 90s, “the most significant feature of those times was a collaboration between government, private industry and environmentalists,” said Foy, formerly both a secretary of commonwealth development in Massachusetts and president of the Conservation Law Foundation. “There were a bunch of very smart players all trying to get to a common goal.”

Political Split

“That’s a remarkable thing and quite a contrast to what we see today,” said David O’Connor, senior vice president for energy and clean technology at ML Strategies. “The way our country is polarized now, it’s harder to imagine collaboration.”

Fletcher School professor Barbara Kates-Garnick, a former Massachusetts undersecretary of energy, said the challenge today is to recreate that collaborative dynamic: “I think it was both trust, collaboration and a recognition of the need to address looming issues that contributed to our willingness to tackle different problems in a collaborative rather than adversarial fashion, as is the mode today.”

“Energy efficiency created an environment where now it’s so successful, so prevalent, we’ve levelized the demand that used to be growing inexorably every year,” O’Connor said.

Paul McCary, of law firm Murtha Cullina, said the financial incentives of wholesale markets helped form the consensus to try something different, which brought lower-cost power.

“But restructuring the electricity market was not done to face the problems we have today,” McCary said, adding that deregulation didn’t address the resource mix.

“There are a couple layers to the challenge — the state/federal split, for example,” McCary said. “Can you tweak and tweak the market until you get there? I question how many ornaments you can hang on the FERC market-structure tree. The 90s were more simple politically — today is a bigger challenge.”

“Screw the feds,” Foy said. “I’ll always bet on New England.”

Laser Grid

Speaking on the second day of the conference, Peter Kelly-Detwiler of Northbridge Energy Partners said the industry can thank the Trump administration for bringing resilience to the fore, both with last fall’s Notice of Proposed Rulemaking and the president’s June 1 order directing the Department of Energy to maintain uneconomic coal and nuclear plants. (See FERC Blindsided by Half-Baked Trump Order.)

“On climate change, irrespective of one’s political beliefs, science is science, and it ain’t going away,” Kelly-Detwiler said. “I used to think that if I put my hands over my eyes, nobody could see me, but I was 3 when I thought that.”

Kelly-Detwiler looked to the future, imagining what the energy space will be in 2050, and said experts are not good at forecasting, as evidenced by looking back to 2001 at anticipated electricity sales, solar penetration or natural gas production.

“Why? Because all our forecasts are based on what we know, not on what we don’t know, and on what trends are accelerating and why they’re accelerating,” he said. “We have to start thinking about what that new dynamic looks like and have that inform our future forecasting.”

NASA for several years has been delivering power to an experimental aircraft via laser. “Let’s fast-forward to a grid in 2050,” he said. “We can send energy to a plane with a laser right now, and we have 32 more years of high-performance computing that’s going to accelerate its ability to solve problems for us. One question that would be worth asking is: Do we have a grid at all?”

Shaping Public Policy

“Even if we transition the electric power sector to zero-carbon electricity today, we still would still not be able to meet even the 2030 goals [40% greenhouse gas reduction],” said Courtney Eichhorst, lead analyst for regulatory strategy at National Grid. “Clearly the challenge is in two sectors: transportation and heating.”

Michael Sloan, managing director of natural gas for energy services company ICF, said public policy should be set with an eye to the future, especially regarding electrification of the residential sector.

“First of all, would residential electrification reduce carbon emissions? It’s not clear. What are the impacts on the grid? What are the impacts on consumers, on voters? We’ve seen policy changes that hurt consumers lead to a change in government in Ontario,” he said.

“Policy-driven residential electrification would be a very expensive approach to reducing greenhouse gas emissions,” Sloan said. “We should look at the most efficient ways to reduce emissions first, and let the market decide how best to meet residential heating load, at least until the less expensive approaches to reducing GHG emissions have been exhausted.”

On the issue of eliminating the internal combustion engine and turning to electric vehicles, Matt Solomon, transportation program manager for the Northeast States for Coordinated Air Use Management, said “there are so many advantages, so many ways that driving electric is a better experience for the consumer,” and people “get it” in one drive.

“States aren’t the best communicators … but Massachusetts is the first state to have actually put money into putting on test-drive events,” Solomon said. After an event targeted at high-earning, tech-savvy people, 68% of participants say they are more likely to buy an EV, he said.

On residential distributed energy resources, Ian Schneider, a Ph.D. candidate at the Massachusetts Institute of Technology, said that tariff design has to match the grid reality.

“If we don’t design the markets correctly, then outdated tariffs will leave this energy revolution to not necessarily benefit all customers,” Schneider said.

DERs are disrupting an already outdated rate design, he said. MIT’s Energy Initiative identified four obvious inefficiencies with current rate designs: They’re neither time-based nor location-based, and “they tend to recover fixed costs volumetrically, so the utility is recovering fixed costs for previous expenses” on a per-kilowatt-hour basis.

As those who can afford solar panels consume less of the utility’s power, lower-income people are forced to pay a higher percentage of those fixed costs, which is inherently unfair, he said.

The fourth inefficiency: that the rates don’t account for capital investments going forward, “so in a world where the marginal cost of producing electricity is very low, but capacity costs, both for the distribution system and for generation, can be very high, it becomes more important to think about coincident peaks and how consumers are driving peak costs on the system,” Schneider said.

New Delivery Model

Daniel Allegretti, Exelon vice president for state government affairs in the East, said there is a continuing tension between the utility and competitive paradigms.

Philip O’Connor, president of energy consultancy PROactive Strategies, said flat load, disruption of traditional generation economics and digital deployment are driving the electricity industry toward a second wave of competitive restructuring.

“We’ve had a decade in this country in which overall electricity consumption, served by the grid, has not increased,” O’Connor said. “The entire business model and the regulatory scheme for the traditional, vertically integrated utility, and for the wires-only company, is predicated on the idea of growth and expansion.”

Digital deployment leads to one big thing — customer sovereignty, he said. “Unfortunately, the structure of the industry, especially the vertically integrated part, stymies that development. So what are we left with? We have rising fixed costs, particularly in the monopoly environment, but flat sales, so you’ve got to keep raising the price.”

Brian Conroy, Avangrid director of network projects, said, “We see ourselves as a platform provider, and our collection of projects will deliver the platform and functionality envisioned for a future marketplace and a future grid operating environment.”

Public policy for reducing greenhouse gases or increasing the use of renewables usually means starting demonstration projects, he said.

“As we plan the future, everything we do … for least-cost planning, we have to look at what are the non-traditional alternatives,” Conroy said. “We see ourselves as a smart integrator, pulling all these diverse things together with a very smart or intelligent platform … to squeeze the value out of the distributed energy resources to get the most for our customers.”

The smart grid might outsmart the customer, according to Harrison Grubbs, director of strategic partnerships at marketing firm KSV. The firm surveyed people on their attitudes on renewable energy and found that utility customers don’t think much about their energy use.

“We wanted to drill down and get an understanding, what exactly customers do know and where those opportunities are,” Grubbs said. “We asked customers where does the majority of their electricity come from. Thirty percent said they don’t know. We also found that 27% of customers in New England believe that the majority of their electricity comes from coal and oil.”

June 10, 2018

FERC OKs Reliability Standard on Fault Protections

By Rich Heidorn Jr.

FERC last week gave final approval to NERC reliability standards on training requirements and the coordination of protection systems to detect and isolate faults (Order 847, RM16-22).

The commission’s June 7 order also approved new and revised definitions for three terms: protection system coordination study, operational planning analysis and real-time assessment.

FERC said it agreed that applicable entities will conduct studies on their significant facilities even without the requirement.

June 8, 2018

FERC Rejects Stay of Presque Isle SSR Surcharges

By Amanda Durish Cook

FERC on Tuesday rejected a Michigan request for a stay of a previous order approving MISO’s refund report related to a system support resource (SSR) on the state’s Upper Peninsula.

The Michigan Public Service Commission joined with multiple load-serving entities in the state to request a stay of the surcharges associated with MISO’s 2017 refund report, arguing that a FERC-ordered reallocation of the SSR costs for the Presque Isle coal plant amounted to retroactive ratemaking.

But FERC determined that the requestors “will not suffer irreparable harm absent a stay” of the reallocation of costs to cover the unprofitable but necessary operation of the plant in 2014 and 2015 (ER 1 4-29 5 2-005).

The PSC and many of the same load-serving entities are also party to an ongoing D.C. Circuit Court of Appeals case challenging FERC’s 2015 order directing MISO to reallocate SSR costs to LSEs that required the SSR for reliability, instead of to all LSEs in the American Transmission Co. pricing zone on a pro rata basis. The groups argue the reallocation requires Upper Peninsula ratepayers to cover a disproportionate 98% share of the SSR costs, which Wisconsin ratepayers should help defray. (See Michigan Groups Contest Presque Isle Cost Alloc a tion.) MISO’s 2017 surcharge report includes cost reductions from a FERC-ordered $24.6 million refund, after the commission decided Presque Isle owner Wisconsin Electric Power Co. overcharged ratepayers for the two SSR agreements.

The Michigan groups contended that, absent a stay, the refund process would become too complex, especially if FERC’s reallocation order is reversed. They also said relocation of customers complicates the refund process.

“ … It would be impossible to ensure that the surcharges imposed by MISO are billed to the retail customers who received service during the surcharge period in 2014, and it would be impossible to ensure that any future refunds received by load-serving entities from MISO are credited to the same customers who paid the surcharges,” they said.

But FERC said overseeing the surcharges after reallocation and refund, while challenging, is not impossible. The commission also said the parties’ “irreparable harm” argument does not hold up, since corrective relief could be ordered by the D.C. Circuit.

“The difficulties alleged by the Michigan parties are typical of the challenges that jurisdictional entities must overcome to implement the commission’s remedial actions,” FERC said. “ … Nothing the Michigan parties have argued has shown that issuing a stay is required by the public interest.”

FERC also said the Michigan parties could not prove the surcharges amounted to retroactive rate increases, noting the commission has “broad equitable discretion in determining whether and how to apply remedies in any particular case.”

June 8, 2018

Pot Industry Blazing a Path in Western Energy Landscape

By Jason Fordney

BOISE, Idaho —The budding efforts to make U.S. marijuana operations more energy efficient will become increasingly critical as the commodity grows into a global market, energy industry experts — including one state utility commissioner — said Monday.

WCPSC marijuana energy efficiency — Smith | © *RTO Insider*

“Cannabis is already a $10 billion industry and is becoming a global marketplace,” Derek Smith, founder and executive director of the Resource Innovation Institute, said Monday at the annual meeting of the Western Conference of Public Service Commissioners (WCPSC). The Portland, Ore.-based non-profit works with utilities and growers to improve energy efficiency and develop standards.

With extensive lighting and HVAC requirements, the marijuana industry currently represents about 1% of electricity demand in the United States. Growing facilities that are not energy efficient can have up to eight times the energy impact of regular buildings.

“The energy impacts are really all over the board, they are broad, and they are pretty large … it is something to keep track of,” Smith said.

Cannabis cultivation is one of the most rapidly changing markets in the world, emerging from the shadows of what was formerly a black market. Growers tend not to trust utilities and the government, he said, as pot is still illegal at the federal level. But a “LEED for weed” certification will eventually be developed, according to Smith.

Marijuana has been legal since 2012 in Washington State, where it is now the third largest agricultural commodity after apples and milk, Washington Utilities and Transportation Commission Chairman Dave Danner said. Sales in the state were $1.4 billion last year, yielding tax revenues of about $312 million.

“It has had quite an impact in our state,” Danner said. “It has required our utilities to take a specific interest in it, and for that reason we are interested in it as well.” Industry participants have expressed concern about the longevity of pot-growing operations, raising the question of whether utilities could end up investing in assets that will later be abandoned, such as substations or feeder lines.

“What we are seeing now is that these companies are pretty stable,” Danner said. “It is going pretty well.”

Another concern: that growing and possessing marijuana is still illegal at the federal level, raising the question of whether the operations might be raided and shut down. Attorney General Jeff Sessions has stated publicly his desire to go after the industry, but so far that has not happened.

State and utility officials have questions about how to extend state energy efficiency programs to marijuana growers in this environment, but many efficiencies could be captured in lighting and HVAC, Danner said. Avista Utilities and Puget Sound Energy have developed incentives and rebates for growers to adopt more efficient lighting, he said. Advanced metering infrastructure will also make it easier to identify illegal growing operations, which still proliferate and use a lot of energy, he said.

“There is also still, in all of your states and mine, an illegal marijuana industry,” Danner told fellow commissioners.

At a separate panel discussion, Linda Gervais, Avista Utilities senior manager of regulatory policy, said dealing with pot growers was something “we didn’t see coming.” Even large growers get paid in cash and don’t bank in traditional ways because of federal illegality. Large growers can have monthly bills of $30,000 to $40,000, and one grower brought his payment in to the utility’s office in plastic garbage bags. The utility has had to buy a cash counter, hire a security guard and hire an armored truck to haul the money.

“It has been a challenge, but I think we have a really good process in place now because we learned how to adapt,” said Gervais.

June 8, 2018

Dems Hit Coal, Nuke Bailout at House Hearing

By Michael Brooks and Rich Heidorn Jr.

WASHINGTON — A senior Department of Energy official told Congress on Thursday his agency has no estimates on the cost of the coal and nuclear power bailout President Trump ordered last week, as Democrats blasted the proposal.

Trump directed Energy Secretary Rick Perry last Friday to force grid operators to provide a lifeline to struggling coal and nuclear plants, saying their retirements threaten national security. Trump’s directive came after the leak of a 40-page draft DOE memorandum that cited the Defense Production Act of 1950 and Section 202c of the Federal Power Act, which allows the energy secretary to issue emergency orders during energy shortages.

The memo proposed creation of a “Strategic Electric Generation Reserve (SEGR) to promote the national defense and maximize domestic energy supplies.”

Rep. Don Beyer (D-Va.) confronted DOE Assistant Secretary Bruce J. Walker over the directive at a hearing of the House Committee on Science, Space, and Technology’s Subcommittee on Energy on Thursday. Walker, head of the Office of Electricity Delivery and Energy Reliability, responded tersely.

Beyer asked Walker about his pledge at DOE’s Electricity Advisory Committee meeting on Feb. 20 that “‘We would never use a 202 to stave off an economic issue. That’s not what it’s for.’”

“And now, FirstEnergy Solutions has recently asked that the department use a 202 to stave off an economic issue,” Beyer continued. “Do we understand that you won’t use a 202 for them?

“The 202 application from FirstEnergy is being reviewed by my department as we speak,” Walker responded poker-faced.

Beyer quoted the president of the Electricity Consumers Resource Council (ELCON), who said the DOE memo’s proposed requirement that RTOs purchase capacity and energy from at-risk plants would “devastate” U.S. manufacturing.

“Have you calculated the costs on American business, specifically American manufacturing?” Beyer asked.

Walker: “I have not.”

The House Committee on Science, Space, and Technology’s Subcommittee on Energy listens to DOE Assistant Secretary Bruce Walker | © *RTO Insider*

Beyer then cited ELCON’s estimate that DOE’s earlier Notice of Proposed Rulemaking to provide cost-of-service payments to plants with on-site fuel — made under Section 403 of the Department of Energy Organization Act — would cost $8 billion annually in PJM alone.

“Now the new plan nationalizes the 403 proposal, so I would expect that $8 billion is going to go up very significantly,” Beyer said. “In putting together this draft plan have you estimated what this will cost the U.S. taxpayer?”

Walker: “I have not.”

“I have to give you wonderful credit for being able to answer these things very, very tightly,” Beyer responded. “I would suggest though … this is something that you and Secretary Perry and others look very seriously at and should have numbers available for. I think it’s within my purview as a member of this committee to ask you to go back and do the elementary research and report back to the committee on those two things please.”

Walker said nothing, his expression unchanged.

Once the hearing had ended, Walker hurriedly left the room and did not make himself available for questions from reporters.

‘False Narrative’

Beyer yesterday sent Perry a letter, co-signed by more than 30 Democrats, asking the Trump administration to “cease the false narrative that bailing out uneconomic energy sources in competitive markets is needed for electrical grid resilience.”

Republican leaders of the committee made no reference to the order at the hearing, the topic of which was grid modernization. Ranking member Marc Veasey’s (D-Texas) opening remarks, however, focused on the bailout order.

“The Trump administration is inventing emergencies to bail out coal and nuclear plants, while ignoring the real problems,” Veasey said. “I’m sure the White House views this legal loophole that surfaced … as an easy way to try to fulfill campaign promises, which is very bad and very unsound when it comes to energy policy. … It would wreak havoc on our energy markets and create a number of misaligned incentives.”

Rep. Paul Tonko (D-N.Y.) noted that he had worked with Walker on deregulating New York’s electricity markets. He acknowledged the markets are not perfect, “but in 2018, the toothpaste is out of the tube, and drastic and unnecessary market interventions under the false pretense of an emergency to bail out uncompetitive generators like ones being discussed by the administration I think are unacceptable.”

Also testifying at the hearing was energy consultant Rob Gramlich, former economic adviser to former FERC Chair Pat Wood III.

Gramlich said the directive ignores coal and nuclear plants’ cyber risks, vulnerability to droughts and lesser ability than wind plants to ride through frequency deviations. “Fifty-year-old plants have outage rates that are typically three times as high as new plants,” he added.

“All technologies …. have their strengths and weaknesses and contribute to reliability and resilience in different ways, but none of them are essential,” he said. “Reliability comes from having reserves. In fact, each region already has a Strategic Generation Reserve. It’s called a reserve margin.”

Retirements Discussed at FERC-NRC Meeting

Nuclear and coal plant retirements also were the subject of a joint meeting Thursday morning of FERC and the Nuclear Regulatory Commission at FERC headquarters.

Bruce Walker Trump DOE Coal Nuclear — FERC and and the Nuclear Regulatory Commission held a joint meeting on Thursday, June 7th | © *RTO Insider*

Mark Lauby, NERC’s senior vice president and chief reliability officer, discussed his organization’s concerns about the loss of “conventional” generation and the increase in renewables and natural gas.

“When you look in certain areas and you’ve got 60 to 70% of their fuels [being procured] on spot [markets], it makes me worried that we have a risk there that we have to start thinking about addressing,” he said.

But he said “firming up” fuel supplies is more important than fuel diversity. “Diversity really is only extremely helpful when you deal with things like Aliso Canyon, Fukushima, coal strikes. Diversity is helpful when you have those kind of unusual type events.”

FERC Commissioner Richard Glick noted that nuclear plants can’t provide frequency response, ramping or load following.

FERC Commissioner Rob Powelson asked if there was any validity to complaints that NRC’s regulations are unduly burdensome and could be contributing to plant retirements. “Is that fake news?” he asked.

NRC Chairwoman Kristine L. Svinicki said for the nuclear retirements to date, “I think we could have radically changed our regulations. It would not have been enough to change the business case and the decisions to shut those units down. … I’ve seen a little bit of the profit and loss statements, and I don’t know what on earth the regulators could have done that could have saved those units.”