Page 1120 – RTO Insider

October 14, 2018

SPP Briefs: Week of Oct. 8, 2018

FERC last week approved SPP’s first seams project with a neighboring utility when it accepted Tariff revisions incorporating a cost-sharing and usage agreement with Associated Electric Cooperative Inc. (AECI).

The Oct. 10 letter order allows SPP and AECI, a Missouri-based collection of six generation and transmission cooperatives, to proceed with the Morgan transformer project. It was the entities’ second attempt to gain FERC approval (ER18-2243, ER18-2245).

SPP says the project is the most efficient, cost-effective solution to economic and reliability issues identified in two separate studies. It also said the project will reduce day-ahead market uplift costs and avoid the cost of a more expensive regional solution, resulting in a regionwide load-ratio-share benefit of more than $17 million.

The RTO included both arguments in its revised filing, after its first attempt failed in 2017. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP has proposed to regionally fund the project, as it will solve congestion issues on its side of the seam. The RTO will cover 82.91% of the $13.75 million engineering and construction cost, while AECI will cover the remainder and is responsible for the project’s construction, operations and maintenance.

SPP FERC m2m settlements aeci — David Kelley | © *RTO Insider*

David Kelley, the RTO’s director of seams and market design, told RTO Insider that FERC’s approval “is evidence it’s possible to share both costs and benefits of new transmission projects across regions.”

“We continue to work with all of our seams partners to enhance our processes to identify and approve mutually beneficial transmission projects,” Kelley said.

The Morgan project comprises a new 345/161-kV transformer at AECI’s Morgan substation and an uprated 161-kV line, both near Springfield, Mo. It was identified during an SPP-AECI 2016 study as outlined by the entities’ joint operating agreement and by the RTO’s 2017 10-year assessment.

“It’s important to SPP and our industry to continue to provide affordable and reliable electricity to our customers, and our success in doing so will depend more and more on our ability to work across regional boundaries to create win-win scenarios,” Kelley said.

SPP said stakeholders, its Board of Directors and state regulators have consistently recommended regionwide cost allocation for the Morgan project.

FERC last year rejected SPP’s first attempt to allocate the project’s costs, ruling it had not shown that the proposed allocation on a regionwide, load-ratio-share basis was “roughly commensurate” with the project’s benefits.

The commission in 2015 also rejected SPP efforts to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)

FERC does not comment beyond an order’s language. A spokesperson would not confirm whether this was the first interregional project the commission has approved on a case-by-case basis.

August M2M Payments Again in MISO’s Favor

Replicating an outcome last seen two years ago, the market-to-market (M2M) process between SPP and MISO resulted in the latter receiving more than $531,000 in payments for August.

MISO last received back-to-back payments in July and August 2016, the beginning of the only three straight months the RTO has seen M2M payments in its favor. SPP has been on the right side of the ledger 19 of the 21 ensuing months.

Temporary flowgates were binding for 327 hours in August, resulting in $788,835.60 in M2M payments to MISO. That was reduced by $257,098.85 for permanent flowgates binding for 127 hours in SPP’s favor.

SPP still has as healthy balance of almost $51.4 million in M2M payments since the process began in March 2015.

— Tom Kleckner

October 14, 2018

ERCOT ‘more than Sufficient’ on Reserves

ERCOT’s current market design “will support more than sufficient reserve margins,” according to a draft report the grid operator filed on Friday with the Texas Public Utility Commission.

The report by The Brattle Group estimates a market equilibrium reserve margin (MERM) of 10.25% under projected 2022 market conditions.

ERCOT puct brattle group reserve margins — PUC Commissioners (left to right) Shelly Botkin, DeAnn Walker and Arthur D’Andrea | *ERCOT*

“This estimate should not be interpreted as a precise forecast for 2022 or any other particular year, but as a reasonable expectation around which actual reserve margins may vary as market conditions fluctuate,” Brattle said. “Low reserve margins cause high energy and ancillary service prices and attract investment in new resources, and investment will continue until high reserve margins result in prices too low to support further investment.

“This is much lower than historical reserve margins, but close to the reserve margins from ERCOT’s latest resource adequacy reports,” the report added. ERCOT’s reserve margin was 10.9% for summer 2018 and is projected at 11% for 2019.

Brattle also calculated a 9% economically optimal reserve margin (EORM), the point at which the marginal costs and marginal benefits of adding capacity are in balance. “The economic optimum occurs at the reserve margin that minimizes societal costs net of all supply costs and the lost value from any disruptions in electric service,” Brattle explained.

The report was submitted as part of the PUC’s review of ERCOT’s reliability standard (Project No. 42302) and its performance during the summer’s tight conditions (Project No. 48551).

The report notes MERM is a relevant measure because ERCOT does not have a resource adequacy reliability standard or reserve margin requirement, unlike other systems in North America. ERCOT’s reserve margin is “ultimately determined by suppliers’ costs and willingness to invest based on market prices, where prices are determined by market fundamentals and by the administratively-determined operating reserve demand curve [ORDC] during tight market conditions,” the report’s authors said.

Brattle worked with Astrapé Consulting to model ERCOT’s wholesale market design and projected system conditions for 2022, simulating “a range of possible reserve margins under a range of weather and other conditions.”

The report noted that the market equilibrium of 10.25% is greater than the economically optimal level by 1.25%. “Based on these results, we conclude that the current market design will support more than sufficient reserve margins from an economic perspective,” Brattle said. “The market equilibrium is higher than the economic optimum because the ORDC as currently designed sets prices higher than the marginal value of energy during scarcity conditions.”

The authors cautioned that “an important uncertainty” in the study is the likelihood of extreme weather. The base case gave all 38 years of historical weather an equal probability of occurring for the 2022 simulation. Assigning 10% weight to each of the last 10 weather years and ignoring the other 28 years would increase the equilibrium reserve level by 1.5% “due to the higher energy prices in these years,” Brattle said. “However, it would increase the number of scarcity events, resulting in similar reliability.”

The report’s results for both the market equilibrium and economically optimal reserve margins were 1.25% lower than found in a 2014 study. Brattle said low gas prices, higher renewable penetration and updated assumptions on generators’ forced outages and weather contributed to the change.

Brattle will present its study results during ERCOT’s Supply Analysis Working Group meeting on Oct. 19. The report will also likely be used in an Oct. 25 PUC workshop on the grid operator’s summer performance.

ERCOT will accept stakeholder comments on the report through Nov. 26.

WETT Faces Full Rate Case

During an abbreviated open meeting Oct. 12, the PUC moved to open a rate case for Wind Energy Transmission Texas (WETT), which staff said earned an excess $16.4 million last year.

The commission’s action gives the company 120 days to file revised rates, although staff is hopeful a settlement agreement can be reached before then (Project 48158).

WETT had a 12.43% return on equity in 2017, above staff’s estimate of 9.60%. WETT reported a year-end 2017 capital structure of 53% debt and 47% equity, while the PUC said a 60/40 mix is appropriate for transmission-only utilities. “If WETT’s actual capital structure were instead 60% debt and 40% equity, its reported level of 2017 return dollars would have generated an even higher ROE of approximately 14.1%,” staff said in a memo.

PUC Approves Cleco Acquisition of Gas Unit

The PUC’s consent agenda included approval of Cleco Cajun’s acquisition of NRG South Central Generating’s 100% interest in Cottonwood Energy. Cottonwood owns a 1,263-MW gas-fired generation facility, interconnected with MISO, along the Louisiana border in Southeast Texas (Docket No. 48266).

The acquisition is part of Cleco’s $1 billion acquisition of NRG’s eight power plants (3,555 MW) and contracts to provide wholesale power to nine Louisiana cooperatives, five municipalities in Arkansas, Louisiana and Texas, and one investor-owned utility. (See NRG Selling Renewables, Other Assets for $2.8 Billion.)

Louisiana-based Cleco would own the Cottonwood facility, but the project will be leased back to NRG, which will have full operational control until May 2025.

Commission to Intervene in MISO FERC Docket

The commissioners agreed during their closed session to intervene in a FERC docket involving MISO’s cost allocation methodology for targeted market efficiency projects with PJM (EL18-2514). (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

The PUC also agreed to have Executive Director J.P. Urban coordinate with the Texas Commission on Environmental Quality in providing comments on EPA’s Affordable Clean Energy rulemaking (EPA-HQ-OAR-2017-0355), its proposal to replace the Obama administration’s Clean Power Plan.

Commissioner Arthur D’Andrea drew laughs when, referring to the EPA’s naming convention, he said, “We should adopt a system like that.”

— Tom Kleckner

October 12, 2018

ERCOT Board Approves $53.3M Economic Tx Project

ERCOT’s Board of Directors on Tuesday unanimously approved the grid operator’s first economic project in three years, a $53.3 million transmission upgrade in West Texas, despite concerns it doesn’t address reliability issues.

ercot bearkat transmission upgrade — Bearkat Area Transmission | *ERCOT*

Staff recommended Wind Energy Transmission Texas’ (WETT) Bearkat area project as the “most cost-effective solution” to address congestion near Odessa. The region’s wind generation has been bottled up by a lack of adequate transmission, resulting in congestion more than half the time, staff said.

Director Clifton Karnei, who represents the cooperative market segment, referenced the state’s Competitive Renewable Energy Zones (CREZ) initiative in expressing his unease about the board making “mini-CREZ” decisions. CREZ resulted in the construction of 2,800 miles of new transmission facilities, delivering West Texas wind energy to the state’s urban centers at a cost of $7 billion.

“We built all the CREZ lines that raised transmission costs. People are concerned about transmission costs being high, yet here, we’re adding another transmission project that’s not needed for reliability,” Karnei said. “We’re doing it because we have all this wind in a constrained area that is being derated. So when we run the production cost model, that’s when it shows the net societal impact. It makes me feel very uncomfortable.”

ERCOT’s analysis found the Bearkat project would produce $400 million in 30-year net savings, based on its economic planning criteria. Staff evaluated nine upgrade alternatives, all of which passed the criteria.

Asked whether the area would require a reliability project in 10 years should the board reject staff’s recommendation, Fred Huang, ERCOT manager of regional planning, said it’s difficult to project future load reliability without doing a study.

“Without this project, we expect to continue to see congestion in this area,” he said. The Bearkat area has 1.5 GW of wind energy already in operation or planned.

Unaffiliated Director Peter Cramton pointed out that building transmission for only reliability reasons would forego potential economic gain.

“It seems like this makes sense for reliability and social economic benefits to be included as a reason to do transmission projects. There aren’t going to be the private incentives for somebody to build this,” he said. “In a first best world, the private incentives would be aligned with the social incentives, and we would just let the market work, but it seems transmission is an area where we can’t completely rely on the market.”

Karnei was able to find comfort in ERCOT’s Protocols and their reliability and economic criteria.

“If we are to follow Protocols, it appears to me we need to endorse this project,” he said.

“This analysis supports the consistent regulatory framework we have in place,” ERCOT Legal Counsel Chad Seely said, reinforcing Karnei’s statement.

ERCOT updated its economic planning criteria in 2012, following the Texas Public Utility Commission’s removal of a consumer benefit test from its economic criteria for certificates of convenience and necessity.

The Bearkat project comprises two new 345-kV bays and a 27-mile, 345-kV single-circuit line on double-circuit-capable structures. ERCOT’s Technical Advisory Committee endorsed the project last month. (See “TAC Endorses $53.3M Economic Project in West Texas,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

October 12, 2018

MISO Monitor Reiterates Call for Capacity Deliverability

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Independent Market Monitor urged the RTO and stakeholders Thursday to require that planning resources have firm transmission to ensure they can deliver their full installed capacity.

In its State of the Market report issued in June, the Monitor said that MISO’s deliverability requirements are too lenient because resources with energy resource interconnection service must only secure firm transmission for its unforced capacity values, which are about 5 to 10% less than their full installed capacity levels. (See 7 New Recommendations from MISO IMM.)

“It’s being relied on but it’s not deliverable,” Potomac Economics’ Michael Chiasson said during an Oct. 11 Resource Adequacy Subcommittee meeting. “It’s clear to us that the [loss-of-load-expectation] study is assuming resources will be deliverable to their installed capacity value.”

Chiasson said MISO’s current practice means as much as 1,400 MW procured in the 2018/19 Planning Resource Auction may not have been deliverable. He also acknowledged that some resource owners may have purchased more firm transmission service than MISO requires.

Chiasson said the rule change can be made with little economic impact to the PRA.

“The concern is more the potential reliability impacts, which could be serious,” Chiasson said.

While roughly half of the about 190 resources contributing to the possible shortfall impact 2 MW or less of capacity, 23 of the resources could each affect 20 MW or more.

Chiasson pointed out that MISO currently requires full deliverability for resources with network resource interconnection service, leading Consumers Energy’s Jeff Beattie to say the RTO was giving unequal treatment to the two groups of generators.

MISO Director of Resource Adequacy Coordination Laura Rauch said that the RTO generally agrees with the recommendation, which could result in a change to how it accredits capacity resources. The RTO is expected to formally respond to the State of the Market report by Oct. 17.

Some stakeholders said that the benefits of the more stringent requirement wouldn’t be significant enough to justify more spending on transmission rights.

But Chiasson said if planning resources decide not to pay for more transmission rights, MISO could simply disqualify the portion of their installed capacity that cannot be guaranteed deliverable.

October 12, 2018

PJM CEO Ott Briefs Senate Committee on Black Start

By Michael Brooks

WASHINGTON — PJM CEO Andy Ott emphasized the importance of fuel diversity for grid resilience to U.S. senators Thursday, but he cautioned against government intervention in the RTO’s markets to bail out specific resources.

grid resilience andy ott pjm fuel diversity black start — PJM CEO Andy Ott | © *RTO Insider*

Appearing before a Senate Energy and Natural Resources Committee hearing on black start capability, Ott acknowledged that the question of whether the grid was becoming too dependent on natural gas was a legitimate one. But, he said, “I do want to clear up some misconceptions about black start resources. Coal and nuclear generators are generally not black start. Black start resources tend to be flexible, smaller units, like gas units or … hydro resources.”

PJM has said the announced retirements of coal and nuclear plants do not pose any short-term threat to reliability, which Ott repeated Thursday. A fuel security study, examining at what point those retirements would cause PJM to violate its reliability requirements, will be released Nov. 1, he said. (See Stakeholders Debate PJM Fuel Security Scope.)

Instead, Ott is more concerned about “a single point of failure”: Some black start resources are only gas-fired, without dual-fuel capability. In July, PJM stakeholders approved an issue charge to work on black start fuel assurance, and Ott told reporters Thursday he expects the RTO to file proposed changes with FERC early next year. (See “Manual Revisions Approved,” PJM MRC/MC Briefs: July 26, 2018.)

“The reality check is it becomes more expensive when you ask for more fuel diversity,” Ott told senators.

But, “as long as you identify the service and don’t fall into the trap of saying ‘I want a specific technology and I want to save a specific type of plant,’ then it becomes a little less expensive.”

grid resilience andy ott pjm fuel diversity — Juan Torres of the National Renewable Energy Laboratory; Utilities Technology Council CEO Joy Ditto; North American Transmission Forum CEO Thomas Galloway Sr.; and Timothy Yardley of the University of Illinois Urbana-Champaign. | © *RTO Insider*

Sen. Joe Manchin (D-W.Va.) nearly paraphrased Ott’s words later, saying he was concerned about the closures of coal plants in his state. Ott repeated that PJM has determined that the units slated for retirement would not impact reliability and pointed to its coming fuel security study.

“And so we’ll be able to say we’ve actually looked at this analytically, looked into the future,” Ott said.

Manchin responded by saying he supported President Trump’s directive to Energy Secretary Rick Perry to order RTOs and ISOs to forestall the closure of a designated list of plants for two years under the Defense Production Act of 1950.

The directive — which Trump issued in June — “makes sure that we keep the best of the best as far as coal-fired plants and nuclear plants that are up to specs and have the latest of technology in operation for at least two years until you can get through this,” Manchin said. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

“Because a lot of analytical [sic] is going on right now,” the senator continued, “and if this all comes down, and these retirements continue at an accelerated rate, I continually believe that the grid is going to be jeopardized and the security of our nation is going to be jeopardized.”

“We do have time, should we find a problem, to take action within our system,” Ott replied. “Instead of the federal government stepping in, allow us to complete our analysis.”

Ott did tell the committee that he would like to see FERC wrap up its work on its resilience docket, which it commenced in January after rejecting the Energy Department’s proposal to compensate plants with 90 days of on-site fuel.

“My desire would be for FERC to get the message that we do need their assistance, and I think any forum I can have that discussion in, I will,” he told reporters after the hearing. “We just really need to move forward.”

On Oct. 5, the Washington Examiner reported that the administration may be backing off the Defense Production Act order, as the White House has been struggling with its legal justification and received pushback from conservative organizations such as the R Street Institute and Heritage Foundation.

October 12, 2018

MISO Offers Storage Proposal, Promises to Exceed Order 841

By Amanda Durish Cook

CARMEL, Ind. — MISO this week offered its detailed energy storage participation proposal for a final round of stakeholder inspection while promising to introduce more new market rules in the future.

miso energy storage ferc order 841 — Kevin Vannoy | © *RTO Insider*

At a special Oct. 10 joint meeting of MISO’s Planning Advisory Committee and Market, Reliability and Resource Adequacy subcommittees, Director of Market Design Kevin Vannoy took the podium with a nod to the RTO’s long-running anecdote likening storage to a can of corn that must be opened and its use decided on.

“We’ve managed to open the can of corn and find that it’s a can of beans,” he joked.

Vannoy said stakeholders were instrumental in MISO crafting a compliance plan that meets the 76 requirements laid out in FERC’s sweeping Order 841.

“We think we have a solid definition of electric storage resources. The input we’ve got from stakeholders definitely helped us define compliance and will help us beyond Order 841. It’s going to help us with this generation of storage resources and the next generation of storage resources,” Vannoy said.

Pavan Addepalle, of MISO’s market engineering group, said the RTO envisions going beyond its current market storage definitions — ESR Type I and ESR Type II — to create third and fourth definitions.

MISO has put out a final call for suggestions on Order 841 compliance and will continue to vet the proposal in November before the Dec. 3 federal filing deadline.

The proposed rules stipulate that storage resources commit to the market through four main modes, including discharging, charging and continuous modes, and an outage status mode. The first three modes carry must-run designations and will be cleared between a resource’s minimum and maximum discharge limits.

MISO said it will also allow for emergency discharging and charging commitment modes, and an “available” status similar to that of an offline generation resource. However, stakeholders at the meeting asked MISO to consider compressing the separate emergency charging and discharging modes into a single commitment mode. The RTO had proposed that emergency charging be used to consume power during minimum generation events while emergency discharging would inject power during maximum emergency events.

For metering purposes, electric storage withdrawals from the grid will be treated as negative generation and categorized as wholesale electric storage withdrawals, while injections will be treated like MISO’s existing energy injections. MISO will also hold storage performance to the new uninstructed deviation threshold due to be filed with FERC later this month. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)

MISO also said that “technically capable” storage is eligible to provide reactive supply and voltage control and black start service. The RTO said it will propose minor Tariff revisions to include references to storage in the wording. Indianapolis Power and Light earlier this month asked FERC to order MISO to include black start service in its current storage participation model (ER17-1376).

The proposal also includes a pro forma agreement for storage connected at the distribution level to participate and a multistep capacity determination process and capacity obligations for storage resources. (See MISO Closing in on Storage Participation Plan.)

What the Proposal Won’t Do

The proposal does not call for MISO to manage the state-of-charge for storage resources or optimize their energy schedules in the day-ahead or real-time markets. (See “No Optimization Yet,” MISO Closing in on Storage Participation Plan.) Instead, market participants will manage state-of-charge through their bid parameters, although MISO will offer real-time hourly offer overrides for storage owners with “valid reasons.” The compliance plan also does not address distributed energy resource aggregation or participation outlines for hybrid storage and generation pairings, an issue that MISO’s Energy Storage Task Force is currently assessing. (See New Direction for MISO’s Energy Storage Task Force.) Vannoy said MISO will likely soon take up a DER participation model in anticipation of a likely FERC order on the issue.

Stakeholders asked if MISO’s Order 841 proposal risked FERC’s rejection because it only provides for making commitments for discharge but not charging.

Vannoy said MISO strongly considered the notion, but it decided that because the owner currently controls the state of charge, and the RTO isn’t yet prepared technologically to optimize energy scheduling for storage, commitment for discharging only was the best route.

“That’s a capability of the resource, not a service we offer. That’s not to say we won’t offer it in the future,” Vannoy said.

DTE Energy’s Nick Griffin suggested that MISO’s FERC filing should include an explanation of its technological limitations to improve its chances of acceptance.

Market Monitoring

After extensive consultation with Potomac Economics, its Independent Market Monitor, MISO decided that storage will be mostly subject to existing Tariff mitigation rules: offers should reflect known capabilities of the resource, revenue sufficiency guarantee eligibility will be revoked when a storage resource is discovered gaming make-whole payment mechanisms and anticompetitive conduct will be met with a Section 205 filing to seek mitigation measures.

MISO added that an electric storage resource “should not manage its state of charge in a manner inconsistent with its physical and operational characteristics.” It also said mitigation measures will not apply when electric storage resources derate to provide capacity, with such behavior not considered physical withholding.

Potomac’s Michael Chiasson said the Monitor doesn’t foresee major mitigation measures unless storage resources contribute to binding transmission constraints.

“I expect a lot of these resources to be relatively small. … They’re not going to have a lot of market power,” Chiasson said. “We don’t want to come down on a half-megawatt. We want to have a hospitable environment for these technologies to enter the market.”

Chiasson added that the Monitor would consider additional mitigation measures if it begins observing manipulation from storage resources.

“We’re hesitant to jump in too tightly. … We don’t want to slow someone down that doesn’t have market power,” Chiasson said. “We’re happy to have the new entrants.”

But Customized Energy Solutions’ John Fernandes said that MISO storage resources might be perceived to be withholding when batteries manage their “state of health” — different than the state of charge — when batteries are stopped to “cool off” after an active period to avoid deteriorating the life of the battery.

“There’s still a lot of gray area when it comes to this physical withholding,” Fernandes said.

Vannoy said a storage facility going unavailable to preserve itself would probably fall under a reasonable motive to stop offering into the market.

October 12, 2018

Western Regionalization ‘No-brainer,’ PJM CEO Says

By Robert Mullin

UNION, Wash. — PJM is leaving the door open to developing an organized market in the Western Interconnection, despite the downfall of its initial partner in the effort, Peak Reliability.

NIPPC caiso western regionalization andy ott peak reliability — PJM’s Andy Ott addressing NIPPC annual meeting attendees. | © *RTO Insider*

And some of the region’s utilities are also interested in continuing the effort, according to PJM CEO Andy Ott.

“We continue to stay interested in the West,” Ott said Monday, speaking at the Northwest & Intermountain Power Producers Coalition’s (NIPPC) annual meeting. “We’re still highly engaged — mostly not in the Northwest these days, but mostly in the Southwest.”

Ott said PJM used Peak to gain an understanding of the issues in the West and get introductions to the region’s market participants.

“But frankly, we feel we do have those introductions and we still are here and having discussions with folks,” he said.

Ott offered that regionalization is a “no-brainer” for the West, and then slipped into what sounded like a not-so-subtle pitch for having his RTO help lead the way in that effort.

“What we are about is to say, ‘Look, markets are a tool.’ Regionalization is a means to create a more efficient utilization of the grid in the West,” Ott said. “Our expertise is in coordinating markets in the East. Essentially, we did it a certain way. We realized [in the West] that it’s not the same scope. You don’t need capacity markets out here. We recognize that. Energy markets, transmission planning, regional operation, market-to-market coordination — those are the kinds of things and expertise we bring.”

Ott acknowledged that the West is already experiencing a fair volume of trading, both through the Western Energy Imbalance Market and bilateral trades. But he said those options seem to be “significantly understating” the value of ramping, flexibility, firm energy and storage — echoing the complaints of Northwest hydroelectric producers who say that CAISO and the EIM undervalue the capabilities of their highly flexible resources.

The CEO said the situation is a failure of price formation.

“Price formation is fundamentally one of the key features of an electricity market. We have to get prices so that people feel they’re being fairly treated,” Ott said. “We came in understanding that we need to get an appreciation of the special cases in the region. We tried to do that. I have folks who’ve spent a fair amount of time to understand the different drivers, because they are different from what we have” in the East.

Ott suggested that Western market participants outside California collaborate to hash out their own approach to price formation — within their own organized market — and then reach out to CAISO and ask: “‘Here’s what we think. What do you think?’

“I don’t think that conversation is happening. At least it’s not happening systematically, but I hope it will,” he said. “If we can be a catalyst to at least provide that conversation, we would love to do that.”

Ott said the idea that Western utilities must choose between developing a new market and engaging with the EIM or CAISO is “a fiction.” A “viable alternative” would be for other parts of the region to stand up a market with its own governance structure and price formation principles and then engage California through market-to-market coordination.

“It looks a lot like EIM, but it’s under different sets of rules,” Ott said. “You still have trading, and in fact you still have very efficient trading. In fact, we do this between PJM and New York; we do it between PJM and MISO. We even do it between PJM and part of the South where they don’t even have organized markets, but we have protocols.”

Clay Norris, power section manager with publicly owned Tacoma Power, asked Ott to elaborate on lack of engagement with the Pacific Northwest.

“I’ve had little interest from parties in the Northwest,” Ott said. “Most of them say, ‘We’re resigned to the fact that we’re headed in a certain direction so we really don’t have time to talk to you.’”

Ott added that Southwest utilities had previously taken the position that they must choose between working with PJM on a new market or committing to the EIM, and they focused on the latter to avoid “creating too many waves.”

“But more recently the conversation has been that [Southwest entities are saying], ‘We’re seeing some things that don’t look so good, so we want to talk to you again,’ and so they reached back out and said, ‘We’re willing to re-engage in the conversation,’” Ott said.

“We are having these conversations. Whether they go anywhere is still an open [question].”

October 11, 2018November 29, 2023

ERCOT Board of Directors Briefs: Oct. 9, 2018

ERCOT’s Board of Directors on Tuesday unanimously approved staff’s determination that no market changes are currently needed to address price formation issues as a result of DC tie flows during emergency events.

The determination was in response to one of the Texas Public Utility Commission’s 14 directives to ERCOT related to the Southern Cross Transmission project. In approving the project, which would create merchant ownership of a DC tie connection to the Southeast, the PUC directed ERCOT to complete a number of tasks before allowing the line to be energized (Project No. 46304).

ERCOT General Counsel Chad Seely assuaged the board’s concerns by noting filing documents and information in the PUC’s compliance docket allows the commissioners to discuss the grid operator’s updates and provide feedback during open meetings. Seely and Compliance Director Matt Mereness both pointed to an existing price mechanism that allows up to 1,250 MW of DC tie imports to contribute to a reliability price adder, as minimizing pricing effects within the Texas grid.

The Technical Advisory Committee endorsed the determination during its September meeting, but not before adding language to make it clear staff recognized “potential price formation issues” and that stakeholder discussions were ongoing. (See “TAC Approves First PUC Directive Related to DC Ties,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

“The determination doesn’t presuppose any type of future outcome,” Seely said. “If a market participant wants to move forward with a NPRR [Nodal Protocol revision request], ERCOT will work with the stakeholders to facilitate those discussions. No one has had an appetite to sponsor an NPRR to try move any of those issues forward, and we’re not sure it’s necessary at this time.”

Citigroup Energy’s Eric Goff, chair of the Qualified Scheduling Entity Managers Working Group, said during the TAC meeting that a market participant plans to file an NPRR related to the issue. Goff did not identify the participant.

Board Vice Chair Judy Walsh, who led Tuesday’s meeting in Chairman Craven Crowell’s absence, asked Seely if ERCOT would reach “a point of no return” where the Southern Cross project is energized and “we haven’t addressed these issues, and we’re behind the curve?”

Seely responded that even if the price formation issue isn’t addressed by stakeholders in some form, there would be no problem from Southern Cross energizing the project.

ERCOT Projects Year-end $25.5M Positive Budget Variance

ERCOT CEO Bill Magness continues to see a positive trend in budget differences, telling directors he expects “likely a significant [variance] at the end of the year.”

The grid operator’s net revenues were $23.3 million over budget as of Aug. 31, thanks to higher-than-expected loads ($6.7 million over) and increased income because of higher investment balances and rates ($6.4 million). Staff are projecting a year-end favorable variance of $25.5 million.

“We’re still managing to the budget,” Magness assured the board during his regular CEO’s report.

ERCOT has now scheduled a Nov. 19 go-live date for the delayed $2.9 million upgrade to the congestion revenue rights system, having seen “substantial progress” since the last board meeting and resolving “vendor-quality issues,” Magness said.

A re-plan is expected in October for a $4.3 million credit monitoring and management system project, a complex process that reaches down to staff PCs and ERCOT’s server racks.

Looking ahead, Magness previewed a pair of security-related NPRRs wending their way through the stakeholder process. NPRR899 looks at whether digital certificates are still state-of-the-art and creates an opt-out provision, while NPRR902 will provide a definition for ERCOT critical energy infrastructure information and a clear line between public and confidential information.

Magness also said NERC’s Accelerated Generation Retirements Special Reliability Assessment report will focus on the PJM and ERCOT systems. The assessment is expected to be discussed during the organization’s November Board of Trustees meeting.

West Texas Heat Could Mean More Wind Energy

Senior Meteorologist Chris Coleman shared an initial analysis of the effect of summer heat on wind generation, which seemed to bear out his hypothesis that more heat equals more wind energy.

“My theory is that hotter-than-normal weather equals greater-than-normal wind generation,” he said.

Coleman’s study came at the request of Director Clifton Karnei, who represents the cooperative segment. It compared June’s average high temperatures in Midland, Texas, with the average daily percentage of installed wind capacity at 5 p.m., dating back to 2014.

Over the past five summers, Midland’s average high temperature peaked at 98.3 degrees Fahrenheit in 2018 during the state’s fifth-hottest summer on record. That coincided with a 39.2% installed wind capacity production mark. Only June 2014’s 42.9% figure, when highs in Midland averaged 95.7 F, was higher.

The other three years saw average highs between 91.7 and 96.9 F, with no average daily wind capacity above 28.9%.

Coleman said there were some exceptions to his theory, but he couldn’t explain why. “I will need to chisel down into a day-by-day look,” he said.

His preliminary winter forecast projects near-normal weather. He cautioned the board that winter is a “different animal” in how it correlates to peak loads.

“If I forecast colder-than-normal weather, it may not mean a higher peak,” he said, noting that last winter’s coldest day in ERCOT since 2011 (Jan. 17) came during the state’s 75th coldest winter. “If I had to adjust [the forecast], I’d adjust it warmer.”

Staff Files Governance Changes with PUC

ERCOT has filed amendments to its Articles of Incorporation (which has been renamed the Certificate of Formation) and to its bylaws with the PUC (Docket No. 48677).

The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership by a Sept. 12 deadline. They had been previously approved by the board in August. (See “Special Membership Meeting to be Set,” ERCOT Board of Directors Briefs: Aug. 7, 2018.)

Assistant General Counsel Vickie Leady said she expects the PUC to confirm the articles and bylaws amendments by its Dec. 20 open meeting.

Board Clears 10 Revision Requests on Consent Agenda

The directors unanimously approved seven NPRRs, a change to the Nodal Operating Guide (NOGRR) and two revisions to the Planning Guide (PGRRs) on their consent agenda:

- - NPRR845: Incorporates numerous revisions to the reliability-must-run process, including standardizing the standby cost in terms of dollars per hour instead of dollars per megawatt; adjusting availability metrics used in settlements to the current operating plan rather than the availability plan; clarifying a resource’s post-RMR status and requiring an entity to submit a resource-notification change no later than 60 days before an agreement’s conclusion; allowing ERCOT to retain a mutually agreeable third party to help evaluate submitted RMR budgets; and modifying the RMR agreement to require detailed budgeted costs with or without capital expenditures.
  - NPRR857: Creates “direct current tie operator (DCTO)” as a market participant role, clarifying the obligations of entities operating DC ties interconnected with the ERCOT system.
  - NPRR869: Requires generators over 1 MW within a private use network (PUN) to provide modeling information to ERCOT if they are not: registered with the PUC as a power generation company; part of a PUN with more than one connection to the ERCOT grid; or registered to provide ancillary services. The change includes a netting exemption for a small qualifying facility that provides energy to a customer behind a single point of interconnection. It also deletes a reference to the now-expired System Benefit Fund.
  - NPRR880: Requires ERCOT to publish shift factors for PUN settlement points for the real-time market, as is currently done in the day-ahead market.
  - NPRR883: Removes the real-time reliability deployment price adder from the real-time settlement point price to avoid double payment when resources have received an ancillary services assignment.
  - NPRR888: Clarifies the four-coincident-peak adjustment methodology implemented in conjunction with NPRR830.
  - NPRR890: Aligns protocol price calculation formulas with ERCOT’s calculation of the real-time LMP at a logical resource node for an online combined cycle generation resource, distinguishing between scenarios in which the unit is online or offline.
  - NOGRR177: Revises the NOG to be consistent with NPRR857’s language on DCTOs.
  - PGRR063: Outlines the process for evaluating the reliability impact of transmission projects 100-kV or above that are expected to be in service before the next Regional Transmission Plan’s completion but that were not included in the current plan, a Regional Planning Group project submission, or a generation interconnection or change-request study.
  - PGRR064: Requires resource entities to verify that dynamic devices used for reliability reflect their operating characteristics.

— Tom Kleckner

October 11, 2018

Tx Path Uncertain for Massive New Mexico Wind Farm

By Hudson Sangree

New Mexico regulators approved construction this month of what could be the Western Hemisphere’s largest wind farm, capable of generating as much power as a mid-sized nuclear power plant. But whether all that energy will have a way to reach the load centers of California and the Southwest remains unclear after the regulators denied approval for new transmission lines meant to link the wind project to urban areas.

On Oct. 3, the New Mexico Public Regulation Commission voted 4-0 to allow Pattern Development’s Corona Wind Projects to move forward. Pattern’s plans call for construction of up to 950 wind turbines with the potential to produce 2,200 MW of electricity. That’s about the same capacity as Pacific Gas and Electric’s Diablo Canyon nuclear power plant, the last in California, which is scheduled to retire by 2025.

SunZia Pattern Energy Wind Farm CAISO — The proposed SunZia Southwest Transmission Project could connect wind farms in eastern New Mexico to end users in California. | *SunZia*

In September, however, the PRC declined to let the SunZia Southwest Transmission Project go ahead, citing unresolved concerns, especially that the developers had “failed to sufficiently define the location of the transmission line route for which it seeks approval.” The commissioners denied the project without prejudice so that SunZia’s developers could firm-up their plan and resubmit it.

“We didn’t have any animus against the project at all,” PRC Vice Chair Cynthia B. Hall said. “They just weren’t ready. Things weren’t coming together in the time frames expected.”

With last-minute changes to SunZia’s submissions, “What was actually being requested became sort of a moving target,” Hall added.

SunZia’s $2 billion transmission project would consist of two bidirectional 500-kV lines with a total rating of 3,000 MW. Its proposed 520-mile path from central New Mexico south across the Rio Grande and the Sonoran Desert in Arizona has met with resistance from federal agencies, the military, environmentalists, community groups and ranchers since it was first proposed in 2008.

Some of those concerns have been resolved, particularly with the U.S. Bureau of Land Management and Defense Department, whose land the lines would cross or abut, but problems with some private landowners persist.

Today SunZia’s fate is linked with the Corona project, which would be the line’s anchor tenant.

On Tuesday, SunZia emailed RTO Insider a statement saying, “The PRC approval of Pattern’s Corona Wind Projects is a very positive development for SunZia and New Mexico.

The huge Corona Wind Projects is proposed for an area of New Mexico with the highest average wind speeds. | *Pattern Energy*

“The Corona Wind Projects are the anchor tenants for SunZia’s first line,” it continued. “This approval paves the way for SunZia to provide the PRC (and the hearing examiner [HE]) with the additional information they need to be able to approve the location of SunZia. We expect to provide this information to the PRC (and HE) in early 2019.”

For its part, Pattern urged the commissioners to weigh each project on its own merits for permitting purposes, despite the close connection between Corona and SunZia.

“They agreed that our permit should stand on its own,” said Crystal Coffman, business development manager for affiliate Pattern Energy Group, based in Houston.

Hall said the commissioners were impressed with Pattern’s compliance and planning efforts. “They had everything nailed down,” she said. And the commissioners also were excited about New Mexico potentially being home to the hemisphere’s largest wind farm. “It sure gives us a sense of pride at the moment,” she said.

Adam Renz, who handles government relations and external affairs for Pattern Energy, said the company was planning to work with SunZia on its next PRC filing to help ensure the transmission line’s approval. A major goal for the West’s biggest wind farm would be to supply energy to California as it seeks to meet its 100% clean-energy target by 2045. (See Can Calif. Go All Green Without a Western RTO?)

The best way of doing that would be through SunZia’s high-voltage lines, sending energy across the Southwest to CAISO’s territory, Renz said.

“SunZia has always been a bit of a dream project that would allow us to deliver electrons into CAISO,” he said. “At the end of the day it’s a direct long-lead line into California.”

October 10, 2018

Coal Group Seeks Reliability Bonus from MISO, SPP

By Tom Kleckner and Amanda Durish Cook

The Lignite Energy Council, a North Dakota coal lobbying group, reportedly plans to approach MISO and SPP in an effort to have them pay more for coal-fired generation.

Lignite Energy Council CEO Jason Bohrer | *Lignite Energy Council*

CEO Jason Bohrer told the group’s Oct. 3 fall meeting he thinks the LEC could show the RTOs that they should pay more for coal-fired power because it provides resilience benefits, The Bismarck Tribune reported.

Bohrer also said the council has applied for membership in MISO, saying its focus on coal energy is “sometimes overlooked in their boardroom and their circles,” according to the report.

The LEC did not respond to a request for comment, and, as of late Tuesday, MISO said it had not heard from the group. If MISO does receive a request, spokesman Mark Brown said it would likely go before the RTO’s stakeholder process for discussion.

“Without having seen a specific request from the council, we can’t speculate on these questions; however, it appears this would be a matter for our stakeholder process,” Brown said.

SPP also hasn’t been contacted. COO Carl Monroe said the RTO is aware “some in the industry” believe “particular resources deserve compensation specifically for their guaranteed availability and role in ensuring reliability.”

“We are currently considering whether and how we might accurately and fairly assess a resource’s ability to meet reliability-related requirements,” Monroe said. “We assume this may lead to modifications to our market rules and capacity requirements and eventually to a market-based solution that values particular resources differently than we do today.”

Bohrer was optimistic when the Department of Energy released its August 2017 study on grid reliability, which recommended supporting out-of-market coal and nuclear plants. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

The CEO said coal “not only ensures reliability for our nation’s electric grid, it also is far less expensive than heavily subsidized renewable fuels.”

The council was disappointed, however, when FERC in January unanimously rejected DOE’s proposal and opened a docket on grid resilience. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

“Currently, regional electricity markets do not properly compensate generators who produce ‘always on’ power or whose power is not susceptible to weather disruptions,” Bohrer said in a statement Jan. 9. “It remains our hope that FERC will ultimately level the playing field when it comes to dispatching energy sources with the long-term goal focused on a resilient grid to serve our homes, businesses and the national economy.”

Williston Basin lignite mine | *North Dakota Studies*

The council aims to maintain the viability of lignite, which is mined at five sites in North Dakota and one in eastern Montana, according to the LEC website. The group’s members include mining companies, generators and service businesses.

By participating in RTOs, Bohrer said at the conference, the LEC would make the case that wholesale markets are skewed by subsidies for renewables. “The market is a competitive market, but it is not a free market,” Bohrer said.