SPP and MISO staff and stakeholders recommended performing a coordinated system plan in 2019-20 that will study six possible sites for interregional transmission projects.
The RTOs announced the recommendation during their Feb. 26 Interregional Planning Stakeholder Advisory Committee meeting, which served as their annual review of congestion issues.
MISO Expansion Planning Engineer Ben Stearney said both “staffs are fully in support” of the study, which was approved by stakeholders on the conference call.
| SPP
The recommendation still needs approval from the MISO-SPP Joint Planning Committee, which is composed of planning staff from both RTOs. The committee will meet sometime in March to hold the vote. If the JPC approves, the RTOs will begin working on building the scope of the CSP.
The study could result in a first-ever interregional transmission project for the RTOs, which conducted CSP and regional reviews in 2014 and 2016 but were unable to reach an agreement on any projects.
So far, the RTOs’ studies show that they may need transmission projects along multiple spots near their southern seam in addition to a location on the South Dakota-Iowa border.
The six possibilities for joint economic projects are:
The Neosho-Riverton 161-kV line on the Kansas-Missouri border, which also appeared in the RTOs’ 2016-17 CSP study;
A circuit on the Kerr-Maid 161-kV double-circuit line in northeast Oklahoma, needed for west-to-east bulk transfers;
The 138-kV South Shreveport-Wallace Lake line in northwest Louisiana, where the area is experiencing load growth;
The 345-kV Hugo-Valliant line in southern Oklahoma, the loss of which causes overloads on the nearby 138-kV system;
A 230-kV line in Sioux City, where MISO predicts that growing wind generation in South Dakota will drive up north-to-south flows; and
The 115-kV Marshall-Smittyville line in northern Kansas, needed as a generation corridor.
If approved, the CSP would be the first in which MISO and SPP rely on their individual regional processes instead of a joint model to evaluate potential transmission projects.
Some stakeholders asked MISO and SPP for a special study of the seam’s most expensive flowgates to see if the RTOs could identify needs that the separate regional processes might be missing. A few said some of the most costly flowgates don’t seem to be captured in the models.
But MISO and SPP staff said a special joint study would introduce more hurdles and negate last year’s decision that the joint model was too cumbersome and ineffective at identifying projects. “To me that was part of the decision-making in 2018 that led to where we are … that we won’t do anything separate and one-off,” SPP’s Adam Bell said.
“I support the study, but I disagree with what we’re looking at,” said Omaha Public Power District’s Josh Verzal, one of the stakeholders who criticized the RTOs for not taking stakeholder-submitted project needs seriously enough.
The RTOs plan to make a FERC filing soon seeking approval for interregional process changes they agreed to last year. In addition to doing away with the joint model, they also agreed to eliminate a $5 million cost threshold for projects, add avoided costs and adjusted production cost benefits to project evaluation, and make CSP studies a more regular occurrence.
Last month, the RTOs said stakeholders and staff support an annual joint study of interregional transmission projects. Currently, their CSP is not mandated annually. (See MISO, SPP Pushing for Annual Joint Studies.)
FERC on Monday accepted rule changes broadening energy storage resources’ ability to provide capacity, energy and ancillary services in ISO-NE’s markets, effective April 1 (ER19-84).
The commission said the Tariff revisions, which were largely backed by the Energy Storage Association and include a new section devoted to electric storage, “enhance competition.”
The commission declined to respond to ESA’s complaints regarding how ISO-NE’s plans to assign reserves to storage, saying it would deal with the issue in responding to the RTO’s compliance filing with Order 841 (ER19-470).
Storage resources could face tougher requirements in some regions than in others under proposed tariff revisions filed by RTOs and ISOs in their Order 841 compliance filings in December. (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
Issued last February, Order 841 set a Dec. 3, 2019, compliance deadline.
FirstLight Power Resources owns the largest pumped-storage hydroelectric plant in New England, the 1,143-MW Northfield Mountain Project on the Connecticut River in Massachusetts. | FirstLight Power Resources
Storage Old and New
ISO-NE says it has 19 MW of battery storage already participating in its markets, with more than 800 MW in its interconnection queue and another 170 MW of proposed battery storage in the queue that would be co-located with wind and solar power projects.
On-site storage | ESA
The RTO noted that while it has limited experience with electric battery storage, the region has been home since the 1970s to nearly 2,000 MW of pumped-storage hydroelectric units. Pumped storage has participated in the region’s wholesale electricity markets as two distinct asset types: a dispatchable generator asset that submits offers to supply energy and regulation, and a dispatchable asset-related demand (DARD) asset that submits bids to consume energy.
“The defining physical and operational characteristic of an electric storage resource is its ability to transition between consuming and injecting electric energy,” the RTO said in its filing.
The new Tariff section (III.1.10.6) defines electric storage facilities as one of two types:
Binary storage facility: a pumped-storage hydro unit that offers both its generator asset and DARD in the energy market as rapid response pricing assets.
Continuous storage facility, which the RTO explained in its Order 841 compliance filing “can transition seamlessly between charging and discharging.” It must be registered as both a dispatchable generator asset and a DARD, with each registration representing the same equipment. It also may provide regulation and must be registered as an alternative technology regulation resource (ATRR). The ATRR construct, ISO-NE explained, allows continuous storage facilities to “provide regulation in a manner that permits them to take full advantage of their ability to follow a regulation signal that traverses all or part of their negative-to-positive range nearly instantaneously.”
Sustainable for 1 Hour
The Northeast Power Coordinating Council mandates reserves be sustainable for at least one hour from the time of activation, which the RTO said can be met by traditional generators but can constrain limited energy resources such as continuous storage.
To comply with this standard, the RTO said it will automatically reduce the economic maximum limit of a continuous storage facility’s generator asset when the facility has less than one hour of available energy remaining. If such a unit were at risk of running out of energy in less than one hour, ISO-NE’s software will automatically adjust the unit’s economic maximum limit to an output level that can be sustained for the hour.
ESA asserted that “the operational impact of the proposed Tariff implementation” is unjust and unreasonable because it prevents some electric storage from providing all the energy service of which it is technically capable.
ISO-NE includes as reserve providers those generators that have dispatchable “headroom” above their current dispatch point and maximum output level and offline generators able to start up within 30 minutes.
| ESA
The RTO said its Tariff revisions do not become unjust and unreasonable “simply because they may not facilitate a participant’s efforts to maximize its revenues, as ESA suggests.”
It also said ESA exaggerated the extent to which revenues would be impacted by redeclaration. The grid operator said it would not issue a dispatch instruction unless it could be followed for at least 15 minutes, and therefore “the figures that ESA provides are not entirely accurate.”
The commission said ESA’s concerns regarding the assignment of reserves were beyond the scope of the proceeding, noting that “what ESA describes as the ‘automatic redeclaration process'” was referenced only in ISO-NE’s transmittal letter and not the Tariff changes. It added the Tariff “already requires resources to update their operating limits in real time.”
“To the extent that the practices described in ISO-NE’s transmittal letter relate more generally to compliance with Order No. 841, we decline to address their merits in this proceeding,” the commission said. “ESA has filed a motion to intervene and submitted comments addressing automatic redeclaration in [the Order 841] proceeding, which will be addressed there.”
Pennsylvania lawmakers may create a new tier within the state’s alternative energy program for nuclear power, according to a draft proposal leaked Monday.
The plan would carve out subsidies intended to save two of the state’s five nuclear plants from decommissioning as the deadline for government intervention looms. (See Exelon: Need Pa. Action by May to Save TMI.)
The bill would revise the 2004 Alternative Energy Portfolio Standards Act (AEPS), which mandates electricity distributors boost usage of renewable or alternative energy sources to 18% by 2021. It could hit the legislature March 7, according to prime sponsor Rep. Thomas Mehaffie (R).
Supporting lawmakers say the legislation will thwart a projected $4.6 billion annual cost to taxpayers should the state’s five nuclear facilities deactivate — including $788 million in increased electricity rates, a $2 billion GDP loss, $1.6 billion in carbon emissions-related increases and $260 million lost to managing harmful criteria air pollutants.
“I wouldn’t introduce the bill if I didn’t think it would pass,” Mehaffie said Tuesday, describing it as one the most important proposals to be vetted in the last 25 years. “I’m really confident we can get something completed” before May.
State Sen. Ryan Aument (R) will introduce a similar bill in the Senate next week, according to his chief of staff, Ryan Boop.
“The leaked draft that is being circulated is not a draft that Sen. Aument’s office drafted,” he said. “I can verify that we are working on language with a number of other legislators that will create a new Tier 3 within the AEPS, and we hope to have that language introduced in the next week or so.”
Nuclear Carve-out
Nuclear generation supplied about 42% of Pennsylvania’s net generation in 2017, compared with 4.5% for renewables, according to the Energy Information Administration. In the draft bill, lawmakers would create a third tier of resources in the portfolio from which companies must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower, with a few exceptions. The first two tiers include many of the same resources — plus fuel cells, municipal solid waste, biomass energy and biologically derived methane gas — with targets of 8% and 10%, respectively.
Analysts with ClearView Energy Partners suggest the qualifying language found in the third tier — such as rules excluding renewable resources that receive other tax credits and exemptions — is designed to solely benefit nuclear energy.
That’s a big problem for Citizens Against Nuclear Bailouts, a coalition of natural gas industry advocates opposed to saving Three Mile Island Unit 1 near Harrisburg before Exelon shuts it down in September.
“It’s still unclear to us what exactly the problem is that legislators are trying to solve,” said Steve Kratz, spokesperson for the group, in an email Tuesday. “Three Mile Island is the only facility in Pennsylvania that isn’t profitable, and regulators at all levels, including FERC and PJM Interconnection, have been very clear that Three Mile Island can close as planned with no impact to grid reliability or ratepayers.”
In a 2017 filing with the U.S. Securities and Exchange Commission, Exelon said TMI had lost money for the last five years as a result of “prolonged periods of low wholesale power prices,” its failure to clear the last three PJM capacity auctions and “the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution while contributing to grid reliability.” The company, manager of the largest nuclear fleet in the country, announced similar closures in New York and Illinois before lawmakers approved zero-emission credits in both states. (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)
“While we can’t comment until we see legislation introduced, the principles outlined in the recent co-sponsorship memo represent an important next step toward valuing the carbon-free energy that nuclear energy provides Pennsylvania,” said Dave Marcheskie, senior site communications manager at TMI. “The loss of these plants would cost the commonwealth $4.6 billion annually in the form of increased pollution, higher electricity prices to consumers, lost jobs and reduced economic activity.”
Other proponents say nuclear energy deserves inclusion in the AEPS because it provides 93% of the state’s zero-carbon electricity. Rescuing the state’s aging generators from decommissioning could likewise preserve up to 16,000 full-time jobs and $69 million in state tax revenues, they contend.
Martin Williams, business manager for Boilermakers Local 13 in Philadelphia and co-chair of Nuclear Powers PA, described the draft as “pleasing” and said the group “eagerly” awaits the final bill language.
“We have known for some time that changes to the AEPS law could be one of the common-sense mechanisms for treating carbon-free nuclear energy like the other 16 forms of environmentally friendly forms of energy currently included in the AEPS,” he said. “Pennsylvanians want clean, safe and reliable energy and [want] to keep energy prices in check. This type of approach would allow that to happen.”
Fixed Resource Requirement
Last June, a FERC order concluded that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the minimum offer price rule (MOPR) to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits and ZECs for nuclear plants. The MOPR currently covers only new gas-fired units. (See Little Common Ground in PJM Capacity Revamp Filings.)
FERC suggested modifications to PJM’s fixed resource requirement (FRR) option to allow the removal of state-subsidized resources and corresponding amounts of load from the capacity market. The first round of filings in the commission’s “paper hearing” on the issue were filed in October (EL18-178).
ClearView suggested the leaked draft would allow AEPS payments to be rolled into an FRR, though it’s unclear how far the bill will get before May. Pushback from free-market conservatives and the natural gas industry could derail Mehaffie’s and Aument’s tight timelines.
“It’s a work in progress,” Mehaffie said. “We’re working extremely hard with our colleagues and others in explaining what this bill does and how important it is to Pennsylvania.”
FERC has ended its enforcement action against the operators of the Salem Harbor Power Station, dropping allegations that plant operators made ISO-NE supply offers they could not meet because of insufficient fuel.
The commission’s Feb. 25 order approved the Office of Enforcement’s recommendation last summer that FERC withdraw its Order to Show Cause against plant owner Footprint Power (IN18-7). (See FERC Walks Back Salem Harbor Manipulation Case.)
Salem Harbor Power Plant | Tetra Tech
OE had sought to force Footprint Power to disgorge more than $2 million in capacity payments Salem Harbor Unit 4 received for a period in June and July 2013 during which the commission said the plant’s fuel supply prevented it from operating at its offered capacity. OE also had sought $4.2 million in civil penalties.
Enforcement staff recommended dropping the matter based on Footprint’s arguments that FERC had failed to consider the 17.5 hours it took Salem Unit 4 to reach full output from a cold start.
The company made its argument in its response to the Order to Show Cause, saying: “The commission should terminate this misguided investigation, just as it terminated the 200-plus other referrals the ISO-NE Internal Market Monitor made during this same time frame.”
OE staff told the commission they still believed that Footprint violated ISO-NE Tariff provisions and regulations in its day-ahead limited energy generator (LEG) offers from July 18 to July 25, 2013. But they recommended the commission vacate the Order to Show Cause and not assess a penalty because the reduced scope of the violations lessened the impact on the market.
In Footprint’s Sept. 26 reply to OE’s concession, the company denied OE’s allegations regarding the July offers.
“In light of the submissions made by Footprint and OE litigation staff, as well as OE litigation staff’s recommendation not to pursue the remaining alleged violations, we terminate the proceeding in this docket,” the commission said in ending the case. “In doing so, the commission makes no findings of fact or conclusions of law concerning the merits of any issues in the proceeding, either procedural or substantive.”
Footprint’s lead attorney, John N. Estes III of Skadden, Arps, Slate, Meagher & Flom, declined to comment Tuesday.
“Our policy is not to comment on FERC investigations,” ISO-NE spokeswoman Marcia Blomberg said.
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.
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.
