MISO will keep a system support resource agreement in MISO South intact for another few months while it awaits completion of an area transmission project.
MISO signed the SSR agreement after Cleco announced in 2016 it would retire Teche Unit 3, a 335-MW natural gas-fired generator in Baldwin, La., on April 1, 2017.
The continued operation of the nearly 50-year-old plant mitigates the risk of a cascading trip and voltage instability on a nearby 138-kV line. The reliability issue is set to be resolved by Cleco and Entergy Louisiana’s Terrebonne-to-Bayou Vista 230-kV joint transmission project, still under construction.
Teche load pocket | MISO
During an annual review of the SSR agreement on Feb. 26, MISO staff said they found no changes in study conditions and could not identify an alternative to the agreement while the region waits for the new line.
Tung Nguyen, of MISO’s system planning department, said the RTO will likely need to extend the SSR from April 1 to about June 30 while the companies finish the line, and it may add provisions for early termination.
“MISO and Cleco will continue negotiation of the renewal SSR agreement,” Nguyen told stakeholders during Tuesday’s conference call.
The Terrebonne-Bayou Vista project was slated to be completed in early 2019, but Cleco and Entergy encountered delays in securing permits to build the line. Nguyen said the RTO doesn’t anticipate any further delays.
FERC last week approved an uncontested settlement setting the payment terms for the SSR (ER19-318).
Under the settlement, Cleco will be paid $1.57 million monthly for April 1, 2017, to March 31, 2018, and $890,000 per month under a second agreement running through March 31, 2019. Cleco had initially proposed a monthly payment of $1.69 million for the first contract and $981,000 for the second.
Agreeing to the settlement were MISO; Entergy; Louisiana Energy and Power Authority; NRG Power Marketing; GenOn Energy Management; the Louisiana Public Service Commission; and Lafayette Utilities System.
FERC on Thursday approved changes to CAISO’s Tariff that describe practices already employed by the ISO’s system operators to balance supply and demand in the day-ahead and real-time markets (ER19-538).
The day-ahead market encompasses CAISO’s balancing authority area, primarily in California, while the real-time market extends to seven entities across the West that participate in the ISO’s Western Energy Imbalance Market.
FERC accepted CAISO tariff revisions on load forecasting for its day-ahead and real-time markets. | Jose Huerta
The “load conformance” practices approved by FERC allow CAISO operators to manually adjust for conditions that the ISO’s automated load-forecast system do not anticipate. In addition, a “load conformance limiter” automatically makes sure the operators’ adjustments don’t exceed the ramping capability of generators available at a given time.
FERC noted that the ISO’s system operators balance of supply and demand to maintain system reliability and comply with NERC reliability standards “primarily through CAISO’s market systems.”
At times, however, “the automated load forecast used in clearing supply bids against forecasted load and exports for CAISO’s real-time market does not match actual system conditions” because of load forecast error, significant deviations in predicted wind and solar supply, and “unpredictable events like outages or weather changes,” FERC said.
When operators see a mismatch between the load forecast and actual conditions in the real-time market, they can manually adjust the forecast, before the market runs, in a practice known as load conformance, FERC explained. The CAISO Tariff does not specifically describe load conformance but will include it after the revisions take effect Feb. 27, the commission said.
The revisions will also include a description of CAISO’s load conformance limiter, currently absent from the Tariff. The automated system corrects for manual adjustments that are “often ‘coarse’ in nature because they represent operators’ imprecise approximation of what they perceive to be the system need at the time based on best estimates and judgment,” FERC wrote.
The third Tariff change approved by FERC is similar to the load conformance adjustments in the real-time market but applies to the residual unit commitment process in the day-ahead market.
Commenters generally supported allowing CAISO operators to make adjustments in the real-time and day-ahead markets, FERC noted. However, one commenter, Powerex, argued that frequent load conformance may be “masking” systemwide shortcomings that could impair the efficient operation of CAISO’s real-time markets.
Powerex said CAISO should hold a stakeholder process to identify why the ISO is using load conformances so frequently and develop automated tools that ensure real-time conditions are accurately reflected in market processes.
FERC on Thursday again rejected CAISO’s proposal to change the way generators register their capabilities with the ISO, denying rehearing on a plan the commission said could allow participants to withhold electricity and exercise market power (ER18-1169-002).
CAISO currently requires participants to submit information about the operational and technical constraints of their generating resources in an electronic repository called the Master File.
Last year, the ISO asked FERC to allow resources to register “market values” instead of physical parameters in the Master File. It would allow a resource to register a maximum number of daily start-ups, ramp rates and other parameters that don’t reflect a resource’s design capability.
FERC said generators should register their physical characteristics, not “market values,” with CAISO to avoid withholding.
The ISO said the change would provide “myriad benefits” — encouraging participation by resources without capacity must-offer obligations, reducing the need for exceptional dispatch and reducing wear and tear on resources — that “manifestly outweigh the remote risk of additional market abuses.”
To protect against withholding and gaming behavior, CAISO required generators to state they could start up at least twice daily to meet the ISO’s steep morning and evening ramps. The ISO proposed several other additional restrictions to alleviate concerns about reliability and market manipulation.
In denying rehearing Thursday, the commission said the ISO “has not responded to our specific concern regarding the absence of any mechanism in CAISO’s Tariff that could be used to mitigate a resource’s physical parameters in addition to its energy bid if CAISO finds the potential for market power.”
“Despite the existing safeguards, we again find that CAISO’s market values proposal presents a new opportunity for market participants to exercise market power that CAISO has not sufficiently addressed,” FERC said.
“Absent some form of mitigation,” the commission continued, “we reiterate that allowing market participants to register desired or preferred market values for physical operating parameters may create opportunities to benefit from physical withholding by earning higher uplift payments or raising market prices.
“A market participant could restrict a resource’s daily start-ups or ramp rates to appear less flexible than it actually is, resulting in the market not being able to access the resource’s full capacity,” FERC said.
“Given these shortcomings, we find CAISO’s argument that it crafted the market values proposal carefully to include restrictions that reinforce existing resource adequacy-related rules to be irrelevant,” the commission concluded.
PJM’s Independent Market Monitor asked FERC last week to order changes to the RTO’s Capacity Performance assumptions, saying the current rules allow sellers to exercise market power.
The Monitor said PJM’s default market seller offer cap (MSOC) has been inflated by the “unreasonable and unsupported” expectation of 30 performance assessment hours (PAHs) annually. As a result, the Monitor said, it has been prevented from effective mitigation of market power, able to subject only a small number of very high offers to unit-specific cost review.
“The public cannot rely on … auctions using the current default MSOC to ensure just and reasonable capacity market prices,” the Monitor said in its complaint, filed Thursday (EL19-47).
Unit-specific MSOCs are supposed to be based on avoidable costs and the opportunity cost of taking on a CP obligation, with its expectations of bonus payments or penalties for performance during an emergency. (The time span for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAI) in compliance with FERC Order 825 in 2018.)
“Given that the … the actual expected number of PAH (PAI) in the energy market is a very small number close to zero, the opportunity cost is below the net avoidable cost of most resources, and therefore the competitive offers of most CP resources are not based on the opportunity cost of taking on a capacity performance obligation,” the Monitor said.
Auction ‘not Competitive’
In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 Base Residual Auction because of economic withholding encouraged by the inflated MSOC. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive.’)
In October, the Monitor warned PJM it would “circle back” to the issue after the Members Committee rejected Tariff revisions altering the existing calculation. (See “Market Seller Offer Cap Balancing Ratio,” PJM MRC/MC Briefs: Oct. 25, 2018.) RTO staff said they believed no further investigation of the issue was required.
The rejected proposal was one of four advanced through the stakeholder process after PJM reported its first load shed event since implementing PAIs as part of the CP overhaul in 2015. (See “PAI Fallout,” PJM Market Implementation Committee Briefs: June 6, 2018.)
The incidents occurred May 29 after a transmission line and a transformer at the Jackson Road substation in American Electric Power’s transmission zone tripped out of service. With three other transmission lines offline for maintenance, the outage caused concerns about being able to deliver power in a section of northwestern Indiana.
A PAI is triggered when PJM determines a supply reliability issue exists and provides credits for generators that overperform their capacity commitments and penalties for those who underperform. No credits or penalties were assessed in this incident.
PJM’s Inaction ‘Misses the Point’
During stakeholder discussions, the Monitor suggested using 60 PAIs or five PAHs — compared with the current 360 PAIs/30 PAHs — in calculating a more appropriate seller cap. While other members disagreed with the suggestion, the Monitor is more concerned with PJM’s decision to drop the issue entirely.
The Monitor said “PJM misses the point” in asserting that it has no basis for changing the rule after the failure of the stakeholder vote.
It described the RTO’s opposition as “inconsistent” with existing analysis, noting most resources using the default MSOC offered below that number in BRAs.
“The failure of stakeholders with divergent financial interests to agree on this issue is not evidence supporting the continued use of a number of PAI (PAH) that was excessive when it was introduced and which evidence shows is even more excessive now,” the filing reads. “The failure to act is effectively support for the excessive MSOC.”
NEW ORLEANS — MISO CEO John Bear opened the Gulf Coast Power Association’s MISO South Regional Conference with a recap of the RTO’s strategic initiatives and the five “500-year” storms he said the region has experienced in less than four years.
“I’m not a statistician, but I think that means they’re not 500-year storms anymore. This polar vortex thing … is real, and it’s happening on a more frequent basis. I’ll leave for debate why it’s happening … but we don’t really care. All we know is that it is happening and we have to deal with it.”
Bear also responded to concerns he has heard from state regulators and others that MISO’s costs are rising.
He said the RTO’s administrative charge is still about 38 cents/MWh, “which is right with PJM, which is half [the rate] of the next RTO that’s even close to us because of our scale and our ability to manage costs.”
He acknowledged that MISO’s transmission costs have risen but said the $5.6 billion invested as a result of the RTO’s Transmission Expansion Plan will produce energy cost savings of at least a 3-to-1 ratio. “So, the energy costs are going down while the transmission costs are going up.”
He also said transmission growth is essential to MISO’s efforts to clear its interconnection queue. “If we don’t build more transmission, it’s not going to help. It’s still going to be slow and, I would argue, it’s going to be inefficient.”
North-South Transmission
Bear said any consideration of potential transmission projects to provide more transfer capacity between MISO South and North-Central should be part of a holistic, regionwide analysis.
He said MTEP 19 will consider two different generation portfolio mixes, referring to the accelerated fleet change future and the distributed and emerging technologies scenario. “They look very different than the [portfolio] that we have today. And so, understanding how the transmission system could be optimized to operate that portfolio is the key.
“I think we’ve got to study that,” he added. “If there’s not a benefit, and a pretty significant benefit … then we’re not going to construct the transmission portfolio.”
In MTEP 17, MISO conducted a “footprint diversity study” to identify transmission projects to increase connections between the regions. But the study found that none of the 35 projects considered passed the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits. (See “No Tx Coming for North-South Constraint,” MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.)
Several speakers at the conference offered different perspectives on the North-South bottleneck.
“While it’s important to look at the overall MISO footprint and have solutions that work for the overall MISO footprint, the reality is … that we have an 85,000-MW system in North-Central [and] a 35,000-MW system in the South connected by a 3,000-MW shoestring,” said Jim Dauphinais, managing principal for Brubaker & Associates. “And so therefore, when we have these [emergencies], they tend to be North and Central events or South events because we very quickly hit the transmission limit.”
Paul Jett, vice president of corporate development for GridLiance, said another look is warranted. Regarding the MTEP futures assumptions, he asked: “Do we have the right criteria? Are we measuring the right things? … It seems like we need to take a look at that because I think we’re missing something in the cost-benefit [analysis].”
Marcus Hawkins, executive director of the Organization of MISO States, suggested the RTO should take a new look at the North-South transmission expansion incorporating the “500-year” storms that were not in the initial analysis.
Hawkins said one of his group’s two strategic priorities for the year is whether there is a business case for a holistic “top-down” look at transmission improvements.
“The states want to be involved in developing the assumptions that go into that business case evaluation of bigger picture transmission plans. So, our authority is to be heavily involved in that process: guide what assumptions are made, make sure the appropriate benefits are included in that sort of analysis and that [the] uncertainty of this changing resource mix is captured accurately, because the states have very different views of what the future might look like … and then, at the end of that process, [find] out if transmission is the right answer or not.”
Hawkins said some states are re-evaluating their bans on aggregation of distributed energy resources “because their consumers want to be more actively involved in the MISO market — and they want it now.”
“And this millennial can relate to that,” he said, sparking laughter.
LMRs Under Attack?
MISO officials repeatedly returned to the RTO’s resource availability and need (RAN) initiative during the daylong conference, saying their planners can no longer worry about just meeting the peak load hour of the summer.
“We assumed, and it was correct at the time, that if we had enough generation to meet that one peak summer hour, we’d be fine the rest of the hours of the year,” said Richard Doying, MISO’s executive vice president for market strategy and development. “What we’re finding now is that’s simply not the case. We really have to think about the availability of resources on an hourly basis all year long.”
Indeed, Dauphinais noted that none of the three MISO South maximum generation events since 2017 occurred during the summer. They included one on April 4, 2017, “which is the least likely time of the year you’d expect to be having a problem with deliverability of power to meet load,” he said.
Another occurred on Sept. 15, 2018, a Saturday. “In my 35 years of experience in this industry throughout the country, I can’t remember ever having a capacity emergency declared on a Saturday,” Dauphinais said. “So, we’ve got something unusual going on here.”
Dauphinais attributed the problems to higher planned outages, the lack of quick-start (two hours or less) resources “and, possibly, the retirement of older natural gas steam units.”
Last week, FERC approved one of three sets of proposed rule changes MISO has filed as part of RAN Phase 1, a requirement that load-modifying resources commit to deploying based on the shortest notification time they “can consistently meet.” (See related story, MISO LMR Capacity Rules Get FERC Approval.)
“We call it the best capability requirement, where — like generators — we’re asking LMRs to offer to us whatever their best capability is rather than their minimum capability,” MISO Executive Director of Market Development Jeff Bladen explained.
Dauphinais said industrial customers are concerned that in RAN Phase 3, which may include consideration of a seasonal capacity accreditation, MISO seems “to be … picking on LMRs again.”
“All resources need to be considered. Not [just] LMRs. Long start-time, high minimum-output, high variable-cost generators are not very different than LMRs that have a long lead time,” he said.
“If there need to be changes to the market design and products addressing both reliability and efficiency, you better identify those first — before you start changing how much capacity you’re going to credit the load-modifying resource or any other type of resources,” Dauphinais continued.
“LMRs and other resources should not have their capacity accreditation degraded if they do not provide a new product that MISO needs. Instead … MISO should create a separate market for that product if it’s truly needed and have resources compete to provide that. And that includes demand response. … Demand response is not the cause of the problem here. It is one of the solutions.”
MISO Independent Market Monitor David Patton said most LMRs were unable to help during the April 2017 and January 2018 maximum generation events because their notification times were longer than two hours. He disagreed that new products are needed, calling instead for improving reserve demand curves to ensure effective shortage pricing.
“I haven’t seen any evidence we need any new products. … If you have good shortage pricing, the folks that can start in two hours get paid, and the folks that can’t don’t get paid,” he said. “With all due respect to the LMRs, that 12-hour LMR is almost worthless.”
On the other hand, Patton said, MISO could offer “very attractive prices” for industrial LMRs that can respond to emergencies.
He said many cogeneration units in MISO South “would really be good 30-minute reserve providers. And when we’re short of 30-minute reserves, they would get paid even when we’re not deploying them — which means they wouldn’t even have to cut their load, but they would get paid $500 to $1,000/MW depending on how it’s priced.”
Bladen said improving shortage pricing is one aspect of the RTO’s “all-of-the above solution set.”
“There’s no silver bullet answers. It’s not just addressing outage coordination,” he said. “It’s not just addressing the emergence of emergency LMRs as a major element of our operating fleet. It’s not just addressing scarcity pricing. But it’s really all of the above.”
Bladen challenged Dauphinais’ contention that there is no chance for LMRs to earn additional compensation under the rules approved last week.
“To the extent that there’s a view that there’s a premium product that’s being asked for, certainly nothing stops the LMR resource owners [from offering] to sell at a premium price,” Bladen said.
“We want to adapt our markets to reflect a changing set of requirements. The need for flexibility is different today and likely tomorrow than it was yesterday. And the reason we haven’t addressed it previously is because the need was emerging rather than upon us.”
‘Highest Use’ for Storage?
GridLiance’s Jett said his company thinks MISO’s proposals on storage as a transmission asset (SATA) are a good “first step,” but he wants to ensure cost allocation rules put transmission owners and non-TOs on an “equal platform.” (See MISO Opens Storage Proposals to All Tx Project Types.)
“I’ve been around MISO a long, long, long time and lived through every one of the cost allocation discussions, so I understand all the issues from both sides — three sides, four sides. It’s tough to figure that out,” Jett said.
CEO Bear said that while MISO’s transmission queue has been flooded with wind and solar projects, “one thing we haven’t seen in the queue is storage.”
In addition to participating in stakeholder discussions on SATA rules, MISO staff is working to determine the “best, highest use” for the technology, Bear said.
Batteries might be most valuable as quick-response resources that help MISO operators balance the system around its growing wind and solar generation, rather than “trying to store energy in them,” Bear said.
“MISO’s footprint is so big and so diverse, it actually is the ultimate storage device,” he said. “But as we move forward, that may change as the capabilities and the technologies of storage or batteries change.
“We’ve almost internally forced ourselves as a company to calling them batteries, as opposed to storage, just because we don’t want to presuppose what the best use of them might be.”
Transmission owners told PJM last week that its rules for supplemental projects satisfy the RTO’s obligation as a regional planner, despite protests from dissatisfied load interests.
Executives from a dozen TOs sent a letter to the Board of Managers on Thursday applauding the way staff addressed stakeholder concerns while implementing revisions to Manual 14B: PJM Region Transmission Planning.
The TOs said the current manual language reflects months of compromise by stakeholders and demonstrates PJM’s willingness to increase transparency at every stage of the Attachment M-3 process approved by FERC.
“This has resulted in a process that harmonizes the presentment of baseline and supplemental projects such that there is minimal difference between the two presentments beyond the PJM board’s approval of baseline projects,” the letter reads.
Transmission owners sent a letter to PJM’s Board of Managers supporting how staff implemented revisions to supplemental project planning rules. | Entergy
At January’s Markets and Reliability Committee meeting, PJM rejected two paragraphs in a set of revisions that stakeholders approved for inclusion in Manual 14B. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
The paragraphs came from an American Municipal Power proposal — designed to address load interests’ concerns — that said supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.” AMP cited the transparency principles in FERC Order 890, saying TOs should disclose asset-specific condition assessments and the criteria and models supporting supplemental projects.
PJM staff opted against incorporating the revisions, saying the disputed text is an “overreach” of the RTO’s Regional Transmission Expansion Plan, which is limited to studies of load flows, short circuits and stability.
The TOs backed the RTO’s stance, saying “PJM correctly determined that certain suggested changes went beyond and/or were not consistent with the FERC orders, and that stakeholders were advancing positions through manual changes that FERC had already rejected.
“What must be considered is that PJM and the PJM TOs have the ultimate responsibility for ‘keeping the lights on,’” the letter concludes. “This consideration must be weighed when planning processes are modified.”
In a separate letter to the board Feb. 11, the American Public Power Association and the Transmission Access Policy Study Group said the RTO’s refusal to incorporate AMP’s language lacks “compelling justification.”
NEW ORLEANS — Entergy Louisiana CEO Phillip May says his company’s electric rates are among the lowest in the nation. Attorney Randy Young, who represents a group of industrial customers in the state, says his clients can do better.
Entergy and the Louisiana Energy Users Group (LEUG) will eventually make their competing cases to the Louisiana Public Service Commission. On Thursday, May, Young and others previewed the debate at the Gulf Coast Power Association MISO South Regional Conference.
At issue is Entergy’s proposal to spend $10 billion to $12 billion to address a 7,000-MW capacity deficit Entergy Louisiana forecasts through 2038.
Of the total shortfall, 5,800 MW is from generation deactivations while only 750 MW is from projected load growth. As a result, Young said, costs will increase much faster than sales, which LEUG consultant Brubaker and Associates says would increase base rates by at least 50%.
Young said industrial customers should be given the option of purchasing from the wholesale market or using combined heat and power (CHP) generation to serve their needs, which he said would decrease the shortfall, potentially saving money for Entergy’s remaining captive ratepayers. He’d also like a new tariff that gives industrials the option of choosing interruptible service, real-time pricing and a market-based standby service, under which customers pay for capacity and energy based on MISO clearing prices.
Young’s position was echoed by Devin Hartman, CEO of the Electricity Consumers Resource Council (ELCON), a D.C.-based group that represents large industrial electric consumers nationwide.
Hartman, who joined May in the final panel of the conference, said his members want to take advantage of falling energy prices and flat load growth. “When you have supply-side shifts or demand-side shifts in the electric industry, you’re going to see markets respond very differently than a regulated, cost-of-service process will,” he said. “Overwhelmingly we’ve seen upward pressure [on rates] in most regulated states for end-use consumers across classes, whereas we’ve seen downward pressure for the most part in the market states.”
Failing that, he said, regulators should ensure state procurements for new generation are truly competitive and not gamed by incumbent utilities.
Hartman said industrials’ interest in direct market access is most pronounced in regulated states in an RTO. “MISO is going to be one of the next ground zeroes, I think, for this going forward,” he said.
While some advocates for residential consumers have reservations about retail choice, Hartman said, “You’ve seen [commercial and industrial customers] just say, ‘Give us the markets. We don’t need to have our hands held anymore. We don’t need a paternalistic approach.’”
With generation trending toward low-marginal-cost renewables, “it becomes more and more important to make sure that we’re injecting more accountability mechanisms and competitive forces to drive more efficient procurement and entry [and] exit of resources in the overall electricity sphere,” Hartman said.
Entergy Responds
May responded that “unregulated states are paying substantially more than the regulated states” and that Louisiana has “some of the lowest rates in the country.” According to the Energy Information Administration, Louisiana had the cheapest residential electric rates and sixth-lowest industrial rates in November 2018, the most recent data available. A recent survey by LEUG found Entergy Louisiana’s industrial rates were the eighth-lowest among 30 Southeastern utilities.
May said LEUG’s projection of a 50%-plus increase in rates must be put in context. “If rates go up 50% [though 2038], that’s 2.5 to 3% annually. Base rates for industrial customers are about half [of residential rates], so maybe 1.5% [annually] … which is about the rate of inflation.
“I can tell you we want to provide the lowest-cost electricity we can to those industrial customers because they are competing on a global stage, and we intend to continue to be competitive so we can attract that load and have them continue to be successful.”
With the planned opening of the St. Charles Power Station in June and the Lake Charles Power Station in June 2020, Entergy Louisiana will have replaced about half of its older capacity with more efficient natural gas units since 2004.
LEUG made its proposal in a docket opened by the Louisiana PSC to consider alternatives to integrated resource plans filed by Entergy Louisiana, Entergy Gulf States, Cleco Power and Southwestern Electric Power Co. (S-34426).
The commission held two technical conferences in 2017 and received written comments earlier this month in response to a Dec. 14 staff report on the issue. LPSC spokesman Colby Cook said no timeline has been set for commission action.
A View from Arkansas
Arkansas Public Service Commission Chair Ted Thomas, who appeared on an earlier panel with Young, said he would consider an equivalent to the LEUG proposal in Arkansas, but he would “match it with a … program that gave residential [customers] as much of an opportunity to change their behavior as the commercial people do.”
“We need low rates for our industrial customers to compete and provide jobs. But the area between [New Orleans] and the boot heel of Missouri — if you draw a circle around that [Mississippi] river — is the most protracted area of poverty in this entire country. And we can’t shift costs over to them,” he said.
Thomas said his “end goal” in Arkansas is “a grid that is plug-and-play with respect to all existing and new technologies, that serves as a platform for an apples-to-apples price comparison and provides price visibility for all technologies with respect to capacity, energy and ancillary services. … It’s a challenging goal because then you’d want some way to compare the price of, say, a rooftop solar installation with an interruptible tariff. You want competition across the whole thing.”
To get there, Thomas said, third parties need to have the same access as incumbent utilities to automated meter data “under the right privacy restrictions.”
“If you don’t have data access, you don’t have a level playing field, and if there’s not a level playing field, your entrepreneurs and innovators won’t come and play and there will be no innovation,” he said. “A second key issue is aggregation. If you’re going to have data access and you want to represent customers, you have to put them in a group. If you don’t have data access and aggregation, you’re not going to get the consumer involvement that you need to have a consumer-driven innovation the way that we’ve seen in telecom and other areas.
“There’s only so many utility nerds out there … most of them are probably sitting in this room,” Thomas continued. “We need a killer app to automate demand response, to automate the consumer to have a consumer-driven system.”
Three years ago I wrote skeptical analyses of Big Transmission, microgrids and grid batteries.
I thought it might be interesting to see how those analyses are holding up and add a New York note.
Big Transmission
“The Rise and Fall of Big Transmission”1 gave the reasons why Big Transmission has never made sense. Much of it is pretty basic, such as the fact that energy is transmitted, not electrons. As Scotty said, you can’t change the laws of physics.
Since that article, Clean Line Energy (remember them?) has sold off a couple pieces and seems to be otherwise winding down. Hopefully someone will write that history.
Getting a lot of hype last year was the release of a “study” led by the National Renewable Energy Laboratory claiming that huge interregional transmission projects make economic sense.2 I put “study” in quotes because even though it was reported as a “study,” it actually was a slide deck describing some future real study. A slide deck is essentially a black box because you can’t tell what’s going on with somewhat important stuff like input assumptions, algorithms, etc.
This study is like its predecessors that I debunked in the original article.
One screaming flaw is the study’s claim of an estimated $14 billion cost for an HVDC transmission buildout to transmit 36 GW from west to east.3
Such an HVDC transmission buildout, if ever politically possible, actually would cost at least $50 billion under the least expensive Energy Information Administration estimate of HVDC cost per megawatt-mile of $700.4 This minimum $50 billion cost is more than the study’s claimed benefits.5
For Big Transmission, the song remains the same.
In its 2018 Interconnection Seams Study, the National Renewable Energy Laboratory’s “Design 2b” envisions three HVDC transmission segments built between the Eastern and Western Interconnections, with existing facilities co-optimized with other investments in AC transmission and generation. | NREL
Microgrids
“Microgrids: Where’s the Beef?”6 explained why microgrids are an inherently uneconomic throwback to the utility islands of the 19th century (yes, that century). Amusingly, some microgrid proponents are now talking about the importance of integrating microgrids into the grid,7 which of course is what the grid itself is all about: integration.
Microgrid proposals continue to proliferate but only where subsidized by Other People’s Money, which in utility parlance means utilities get enormous returns on microgrid projects that are paid for by other — non-microgrid — customers.
The acid test should be whether microgrid beneficiaries are willing to pay for the cost of the microgrid themselves. The answer is never — because people aren’t dumb.
One shocking attempted raid of federal taxpayers, and the undermining of our national defense, was a study by a consultancy Noblis for the Pew Charitable Trusts urging that our nation’s military bases replace individual backup generators at critical buildings with base-wide microgrids. I pointed out in a later article8 that because 87% of base outages were cause by on-base distribution system failures that centralizing backup base generation in a microgrid would dramatically increase outage risk for critical buildings. Not to mention that microgrids are inherently vulnerable to cyberattack while individual building backup, typically diesel, is not internet-connected and therefore not vulnerable to such attack.
My favorite factoid remains this: The nation’s “flagship” microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.9
You can’t make this stuff up.
Grid Batteries
“Grid Batteries: Drinking the Electric Kool-Aid”10 debunked this continuing infatuation of our haute couture crowd. The newest shell game is the notion of “value stacking,” which is the equivalent of saying that you can jog around the neighborhood while watching your kids at home. No, not possible.
By the way, batteries increase carbon emissions.11 Two reasons: The generation used to charge batteries tends to be dirtier than the generation displaced when batteries are discharging. And there are losses from converting AC to DC, storing energy and converting back. Batteries ≠ green.
Battery boosters, realizing they can’t make it on the merits,12 have been lobbying regulators and legislators to subsidize them through procurement mandates, direct subsidies, utility rate base and other special treatment.
My favorite is New York arbitrarily deciding that 1,500 MW (oops, now 3,000 MW) of grid batteries sounded like a good, round number and putting up $265 million of Other Peoples’ Money for that.13
Escape from New York
This is the same New York that is forcing the shutdown of the economic Indian Point Nuclear Plant; subsidizing uneconomic upstate nuclear plants; subsidizing 2,400 MW (oops, now 9,000 MW) of uneconomic offshore wind;14 risking electric reliability in New York and New England and curtailing new natural gas home connections by blocking federally certificated natural gas pipelines;15 paying $1,973 per public housing apartment to install LED lighting;16 and stiffing Cheryl LaFleur,17 a dedicated public servant, for another FERC term because Chuck Schumer didn’t like a highly technical, totally correct NYISO decision.18
New York, you are a Green New Deal Mini-Me. Condolences.
Amazon, you got out while the gettin’s good. Congratulations.
4- The cheapest HVDC cost per megawatt-mile is $700 per this EIA study, https://www.eia.gov/analysis/studies/electricity/hvdctransmission/pdf/transmission.pdf (pdf pages 33-34). $700 MW-mile x 12,000 MW each HVDC line x three HVDC lines x 2,000 miles each line = $50 billion. This does not include the enormous AC transmission facilities that would be required to accommodate the HVDC lines (i.e., inject/withdraw 12,000 MW each line from their converter stations in the middle of nowhere).
5- The negative “Total Non-transmission Cost” of $45.16 billion on slide 15 of deck in footnote 3.
9- http://www.eenews.net/stories/1059996047. (“The university’s two 13.5-MW Trident turbines were running full-bore when power from the utility abruptly went dead. With no time to shed their load, the turbines also shut down, and the campus lost electricity.”)
14- https://rtoinsider.com/new-york-renewable-energy-109515/. Gov. Andrew Cuomo claims that the offshore wind would be located in “this state.” No, it would not. It would be located far outside New York’s nautical boundary that is 3 miles from shore.
Both the PJM Markets and Reliability and Members committees held their meetings Thursday via conference call because of a snowstorm that hit the East Coast the day before. The meetings had originally been scheduled to be held in Wilmington, Del.
Markets and Reliability Committee
Transmission Replacement Vote Deferred Until April MRC
The MRC on Thursday agreed to delay a vote on revised transmission planning rules until April by a sector-weighted vote of 3.73 to 1.27, with the Transmission Owners sector opposed.
Sharon Segner of LS Power asked for a deferral to accommodate further discussion on the language her company crafted for Manual 14B: PJM Region Transmission Planning regarding how supplemental projects are added or removed from the Regional Transmission Expansion Plan. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” if it is rejected by a regulatory agency.
The RTO has suggested a review of the entire process at the Planning Committee in response to LS Power’s proposal. Segner told the MRC that the delay would allow extra time for the PC — through regular or special meetings — to discuss the process in detail, including its relation to FERC Orders 890 and 1000. (See “Holistic Review of RTEP Removal Suggested,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
Segner first presented the proposal during the Jan. 24 MRC meeting as a friendly amendment to a proposal from American Municipal Power to increase transparency of supplemental project planning. PJM accepted most of AMP’s proposal, but it rejected one section that it called an overreach of the RTEP. This seemingly rendered LS Power’s amendment moot, but Segner successfully moved to delay any action on it until Thursday’s meeting. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
NextEra Energy offered a friendly amendment to the LS Power proposal that would require PJM to remove supplemental projects with incomplete siting permit applications from the RTEP. If PJM discovers an RTEP project that would eliminate the need for the proposed supplemental, the RTO would inform all applicable committees and regulatory agencies. Segner said the amendment will become part of the PC discussions in March and April.
Stakeholders Urge Slower Timeline on Fuel Security
Stakeholders told PJM their 12-month timeline for addressing potential fuel security threats and accompanying market rule changes is too aggressive.
PJM’s Mike Bryson solicited feedback from the MRC on a first reading of a problem statement and issue charge centered on ensuring grid reliability during times of extreme stress.
In November, PJM released an eight-page summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said. (See PJM Begins Campaign for Fuel Security Payments.)
Bryson said PJM would schedule a vote on the problem statement for the March 21 MRC, with a task force recommendation by September and a FERC filing in December.
“I think it’s prudent for PJM to put a timeline out there,” Bryson said. “I don’t want to go to the opposite extreme and say it’s open ended.”
PJM drafted the problem statement as part of a three-phased approach for ensuring the resilience of its generation portfolio. Staff completed the Phase 1 analysis in December, saying that while no imminent risk currently exists, the RTO should explore proactive, market-based mechanisms for retaining or procuring fuel-secure resources.
A multitude of stakeholders said that while they appreciated PJM’s work on the issue, the timeline Bryson presented was far too short, saying there needed to be more discussions before any recommendation came before the committee.
Paul Sotkiewicz, president of E-Cubed Policy Associates, went further with his criticism.
“What you have done is shown there isn’t an issue here,” said Sotkiewicz, representing Elwood Energy, a 1,350-MW gas-fired generator in Illinois. “I think that’s very important for policymakers to see there is no problem. … We are talking about making market design changes when there is absolutely no evidence that there is a problem with market design.”
He encouraged other stakeholders “not to go down the road” but instead pursue a market-based analysis.
PJM staff gave stakeholders a March 7 deadline for submitting feedback on the problem statement, with an updated draft to be released March 14.
Manual Changes Endorsed
Stakeholders approved the following manual changes:
Manual 14B: Transmission Planning Process: Cover-to-cover periodic review. Includes changes to section 1A on critical energy/electric infrastructure information (CEII).
Manual 14D: Generator Operational Requirements: Added requirements to section 7.1.1 regarding generator real power control associated with FERC Order 842, which requires new generators seeking interconnections to be equipped to provide primary frequency response. The new rules apply to generators that entered the PJM transmission queue on or after Oct. 1, 2018. (See FERC Finalizes Frequency Response Requirement.)
Manual 12: Balancing Operations: Cover-to-cover periodic review with updates to section 3 regarding primary frequency response per FERC Order 842. The changes were endorsed by the Operating Committee on Feb. 5 over the opposition of FirstEnergy and Duke Energy. FirstEnergy challenged the manual’s formula for judging primary frequency response performance. (See “Utilities Question Primary Frequency Response Calculation,” PJM Operating Committee Briefs: Feb. 5, 2019.)
Members Committee
Calculator Vote Placed in ‘Parking Lot’
The MC agreed to postpone a vote on whether to force PJM to accept opportunity costs calculated by the Independent Market Monitor until a member requests it.
Bob O’Connell of Panda Power Funds had proposed Operating Agreement changes last August if PJM refused to accept the Monitor’s calculator in determining generators’ cost-based energy offers.
The proposal passed the MRC in August, which incentivized the RTO and the Monitor to work toward a deal, announced the following month. The MC had postponed a vote at its September meeting to give PJM and the Monitor time to put the new process in effect. (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.) Under the agreement, the Monitor will explain its inputs and logic to PJM to demonstrate that the unit-specific opportunity costs are compliant with the OA.
O’Connell said the unusual motion puts the issue in a “procedural parking lot,” giving members flexibility to bring up the issue on short notice in case PJM suddenly decided the Monitor’s calculator was no longer valid. Stu Bresler, PJM senior vice president of operations and markets, said staff supported the motion.
Stakeholders to Consider Retiring Wilmington as Meeting Site
Members will vote next month on a proposal by Katie Guerry of Enel X to move all MRC and MC meetings to PJM’s Conference and Training Center in Valley Forge, Pa., instead of splitting them between there and The Chase Center on the Riverfront in Wilmington, Del.
PJM had held all its meetings in Wilmington until it opened the center in 2012, where it began holding lower committee meetings and some MRC/MC meetings. The RTO had historically been centered around the I-95 corridor, and the city was deemed a good midpoint, Dave Anders, director of stakeholder relations, explained to the committee.
Guerry said that the Valley Forge location provides stakeholders cost efficiencies, as they have access to PJM staff and resources while they are there.
Virtually all stakeholders who spoke expressed reluctant support for the proposal, saying that while Valley Forge is harder to get to because of a lack of public transit options, the facility provides a far better meeting experience. Several noted that there are often technical difficulties at the Chase Center — the RTO’s meeting site in Wilmington — with unreliable wireless connections causing delays in voting.
Several others noted that ride-sharing services such as Uber have made up for the lack of public transportation in the area.
Stakeholders were prepared to approve the proposal immediately Thursday, but Guerry said she wanted to give PJM meeting planners time to review the RTO’s contract with the Chase Center, as well as give any on-the-fence members time to think about the issue.
Entergy last week reported a fourth-quarter loss of $66 million ($0.36/share), beating analysts’ expectations by 12 cents. That compared favorably with a $479 million loss for the fourth quarter in 2017 ($2.66/share).
Five analysts surveyed by Zacks Investment Research had projected a loss of 48 cents/share.
For the year, Entergy reported earnings of $849 million ($4.63/share), compared to $412 million ($2.28/share) in 2017.
In a Feb. 20 conference call with financial analysts, Entergy CEO Leo Denault said 2018 was “another successful year” and said the company is “on track” to achieve its long-term goals.
The company said its results reflected asset impairments and other expenses related to its decision to exit its Entergy Wholesale Commodities business and its four aging nuclear plants. The New Orleans-based company completed the sale of Vermont Yankee and announced agreements to sell Pilgrim and Palisades. (See Entergy Sees Quicker Exit from Pilgrim, Palisades Nukes.)
Denault said Entergy is making progress on Pilgrim’s sale to Holtec and is “actively working” toward a post shutdown sale of New York’s Indian Point plant. Pilgrim will be shut down no later than May 31.
“We executed on our strategy and met major milestones in our transition to a pure-play utility. We expect 2019 will be no different,” Denault said.
The company’s stock price gained $3.67 after opening at $89.10 on Feb. 20, closing the week at $92.77. Entergy’s stock price is up 7.8% this year through Feb. 22, slightly above the 7.3% gain by the S&P 500 Utilities index.
OGE Earnings Slip, but Beat Expectations
OGE’s quarterly performance nevertheless beat Zacks’ consensus estimate of 24 cents/share. The Oklahoma City-based company reported a fourth-quarter net income of $54.7 million, down from $295 million the year prior when it enjoyed a $198 million windfall, thanks to the 2017 Tax Cuts and Jobs Act.
OGE CEO Sean Trauschke told financial analysts during a Feb. 21 conference call that 2018 “may well be regarded as the best [operational] year in our company’s history.”
Trauschke pointed to strong safety numbers, the addition to its fleet of the 462-MW Mustang Energy Center and its seven gas-fired generators, the commissioning of a 10-MW solar farm, the addition of scrubbers at its two coal-fired Sooner Power Plant units, and the conversion to natural gas of two coal units at its Muskogee Power Plant.
Wall Street reacted favorably to OGE’s report. The company’s share price was up 2.2% following its open Feb. 21, gaining 94 cents to close the week at $42.78.
