FERC last week moved to investigate PJM’s regulation market, rejecting the RTO’s most recent proposal for compensating the systemwide service (ER18-87) and ordering a technical conference on larger concerns identified by stakeholders (EL17-64).
The commission denied PJM’s most recent proposal, filed in October, for the same reasons it had on previous attempts, which date back to the RTO’s efforts to comply with Order 755. The technical conference comes in response to complaints filed in that docket by the Energy Storage Association, Renewable Energy Systems Americas (RESA) and Invenergy Storage Development. They argue that operational changes PJM has made in relation to its filing have had significant negative impacts on battery storage and are “a symptom of the broader problem that the RTO misuses regulation resources to reduce generation on its system for sustained periods of time.”
PJM’s updated regulation rules changed requirements from on- and off-peak to on- and off-ramp | PJM
FERC granted a portion of the complaints but deferred any action until after the conference and set a refund effective date of April 14, 2017.
Regulation Issues
PJM maintains two regulation signals: RegA dispatches slower, sustained-output resources such as steam and combustion resources, while RegD dispatches faster, dynamic resources, such as battery storage. The RTO uses a “benefits factor” curve to reflect the operational relationship between the signals and establish the tradeoff between their capabilities so that the market’s clearing engine can accurately compare their expected performance.
In its original filing on Order 755, PJM had proposed using the benefits factor instead of a unit’s actual “mileage” — the amount of regulation work a unit provides — in determining its payment, but FERC rejected that in November 2012 because the order required accounting for a unit’s mileage. PJM’s January 2013 compliance filing eliminated use of the benefits factor but warned it would create an “unsustainable market structure.”
PJM returned to the issue, arguing that its prediction came true and FERC’s requirements resulted in over-procurement of RegD and incorrectly signaled for additional entry into the market, which exacerbated the problem. The requirement to unconditionally respect RegD resources’ power balance also worked against overall system balance at times, the RTO said.
PJM’s new regulation signal has helped improve its area control error (ACE) control | PJM
The RTO redesigned its regulation signals to work together to manage area control error (ACE) and revised the RegD signal to be neutral over 30 minutes rather than 15, it told the commission. It filed for approval of a four-part plan that would substitute the mileage ratio for a new “regulation rate of technical substitution curve” and adjust calculations for performance scoring, settlements and lost opportunity costs. (See PJM Regulation Compensation Changes Cleared over Opposition.)
Decision
Stakeholders were mixed in their comments to FERC, with several noting the plan was vetted through the stakeholder process and others calling it discriminatory. The commission disagreed with PJM’s contention that the proposal meets its requirements because the market clearing process accounts for the “dollar per mile” cost of RegD resources. It also rejected PJM’s argument that accounting for mileage in the settlement equation double-counts it.
In its December order to RTOs on fast-start resources, FERC noted PJM’s dispatch process doesn’t respect the “power balance constraint” and thus “unnecessarily increases the cost of serving load and puts stress on the frequency regulation resources that are necessary for maintaining system reliability.” (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
FERC last week granted approval for Linden VFT to contract potentially all of its transmission capacity through long-term “anchor customers” rather than its current recurring auction process (ER18-730).
Linden owns a merchant transmission line and three 105-MW variable-frequency transformers between the Public Service Electric and Gas system in New Jersey and Consolidated Edison on Staten Island, which began operation under PJM’s control in 2009. The company has rights to 330 MW of firm point-to-point transmission service from within PJM, 315 MW of export capability from NYISO and 315 MW of delivery into either PJM or NYISO.
Linden VFT’s exterior | Joseph Jingoli & Son
Linden has held five “open season” auctions, through which it receives all of its revenue, since 2007. It told FERC there has been a “declining number and diversity of participants and qualified bidders, resulting in shorter-term contracts” and signaling reduced interest in its transmission scheduling rights.
PSEG Energy Resources & Trade will hold all those scheduling rights as of June, but Linden told the commission it has been approached by new customers seeking “longer-term, more tailored arrangements” and that “the ability to subscribe up to all of [its] transmission capability through such longer-term arrangements with anchor customers will allow it to explore more sustainable, alternative business models and allocate its transmission scheduling rights to the market participants who value them the most.”
FERC approved Linden’s request to amend its existing authorization so it can contract for service and negotiate rates, payment arrangements and agreement lengths and sell any remaining capacity at market-based rates through open solicitations. The company committed to filing a report within 30 days of a solicitation detailing its open-access characteristics, which allowed the proposal to pass the commission’s four-part analysis. Because it had changed its policies on reviewing negotiated-rate proposals since Linden’s project was originally approved, FERC decided to conduct a de novo analysis.
In December, Linden and Hudson Transmission Partners — another owner of merchant transmission between northern New Jersey and New York City — were approved to convert their lines from firm to non-firm service and avoid being saddled with hundreds of millions of dollars in cost allocations under PJM’s Regional Transmission Expansion Plan. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
VALLEY FORGE, Pa. — After nearly two years of intractability, FERC’s order last month on supplemental transmission projects — and PJM’s subsequent compliance filing — have reshuffled the deck in the RTO’s Transmission Replacement Process Senior Task Force (TRPSTF).
The order and filing require transmission owners to change how they plan and represent supplemental projects but also give them greater control over defining that process. They forced stakeholders at last week’s TRPSTF meeting — the first since submitting the compliance filing — to reconsider how they approach topics that have remained largely unchanged since the task force was proposed in January 2016.
PJM’s Steve Herling reviewed the process changes proposed in the filing, which delineate a structure for stakeholder engagement on supplementals and define deadlines for input. Developed internally by TOs through their “local” transmission plans, supplementals are not driven by PJM criteria. They’re included with baseline and market efficiency projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval. All stakeholders are supposed to have opportunities to provide “meaningful” input on them, and FERC’s order determined that TO procedures weren’t allowing that. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
Is Anything Ever Final?
Herling said projects tend to be submitted in “bunches” near the beginning and end of the year.
“I don’t know that PJM would be able to second-guess the timing of those decisions,” he said when asked to explain the reason for the bunches. He said the focus is to “get the solutions accepted, lock them down and move on so we don’t have surprises in the RTEP process.”
The deadlines in the compliance filing drew criticism from American Municipal Power’s Ed Tatum, who said they might not provide enough time to fully vet projects and receive answers. He asked when local plans are finalized so that stakeholders can comment on them in their entirety.
“The only way I can answer that is to refer to the RTEP. The RTEP is never finalized,” Herling said. “I don’t know what it means for the RTEP to be finalized, so I would suggest that I also don’t know what it means for the local plan to be finalized. … I don’t have a problem with putting a flag in the ground and saying, ‘We’re done.’ … I don’t know what the significance is from a planning perspective because every year we finish an RTEP, we start another one.”
Mark Ringhausen with Old Dominion Electric Cooperative said it seems like “there really isn’t a local plan; there’s just approval of supplemental projects.”
Resolving the Task Force’s Work
The TRPSTF went on a 10-month hiatus in response to FERC’s show-cause order on the issue, and TOs remained reticent to engage even after the task force resumed meeting late last year at the urging of load-side interests, citing the lack of FERC direction. The order and compliance filing clear the way for resolving the task force’s assignments, but how that’s accomplished remains to be seen. PJM is hoping the details contained in the order and filing can be accepted by everyone and set aside from debate on the remaining components, but AMP isn’t convinced.
“All we’re suggesting is we leave the parts that were filed on the table assuming they’ll be approved,” Herling said.
Tatum suggested having stakeholders propose solution packages and voting on them at an upcoming meeting as is common in other task forces.
“We have been doing nothing for 16 months. … We’re still getting ready to try to see if anyone is willing to have a discussion with us,” he said. “We’ve got to finish this group. We’ve got to stop meeting like this.”
Exelon’s Gary Guy questioned an all-inclusive approach.
“We’re not debating the pros and cons of a commission-issued order,” he said. “Once the commission has issued an order, we don’t have anything to debate.”
While the order undoubtedly has an impact on the task force, the question remains how much. The order is specific to TOs’ implementation of Order 890 regarding supplementals, but the TRPSTF is charged with addressing the processes for determining and replacing infrastructure that has reached the end of its usable life. The task force’s problem statement, issue charge and charter make no mention of Order 890. PJM’s Fran Barrett, the TRPSTF administrator, said he will research any potential overlap.
Stakeholders have proposed components that they believe are necessary for any solution, and Barrett asked if PJM staff could analyze them to pull out the parts that have been addressed by the order and filing.
“Could we clean up the past without throwing it away?” he asked.
TOs didn’t object to the plan, which would have PJM present an interpretation of what is explicitly addressed by the FERC order, but PPL’s Frank “Chip” Richardson pointed out that TOs remain in litigation on some of the TRPSTF’s topics and are unable to negotiate on them. Tatum and AMP’s Lisa McAlister said they want to maintain the right to go through their proposal and make their own modification interpretations. They didn’t see any benefit to PJM’s interpretation.
“We’re pretty good with what’s in the order and the compliance filing,” McAlister said. “I’m not sure it’s that helpful.”
Guy said he would object to any proposed alternatives to what’s in the commission order and said PJM should rule them out of the bounds of the discussion.
“That would be running amok here in complete disregard of what just took place at the commission,” he said.
“Discussion is one thing,” said Ruth Ann Price, who represents the Delaware Division of the Public Advocate. “Implementation is another. … I’m not sure you have any ability to stop us, the rest of the stakeholder body, going forward.”
“Just because we put it out there, doesn’t mean there’s an affirmation on this,” Barrett explained.
He attempted to point to improvements that have been made to the process since the task force began, but Tatum wasn’t convinced.
“We are not encouraged by the changes that have been made. We see some progress, but we also see a lot of pullback,” he said. “There are certain things that PJM doesn’t think about regarding end-of-life projects … so we’re going to seek to have those things addressed, as we already have. … There’s a lot of things we need to work on. We’re very serious about it.”
Barrett said subregional RTEP meetings have evolved in response to the task force’s work.
“They’re not the same calls they used to be,” he said.
The TRPSTF’s next meeting is scheduled for April 30. Tatum said he hoped that proposed solution packages could be finalized and ready to be voted on by then.
Peak Reliability and PJM Connext have entered the “commitment phase” for their proposed Western energy market, refining their pitch to convince potential participants to finally embrace an organized market for the region.
The organizations on Friday issued a three-page abstract of their new business plan to potential members and has also set up a public comments page on a partnership for what could possibly lead to a Western RTO, an effort that has previously been stymied by difficulties in developing a governance process acceptable to all the states involved.
“It is envisaged that these services will expand over time, evolving towards a full RTO offering. Whether and when this occurs will be a matter for the market’s participants to determine,” the abstract says. The full business plan remains confidential and will require interested parties to enter nondisclosure agreements.
In response to the proposed market plan, CAISO has filed to depart Peak as its reliability coordinator (RC) and developed a rival plan to offer RC services across the West to Peak’s existing customers. (See Multiple Entities, Markets Now Beckon in West.)
Peak said it continues to receive notices from utilities intending to withdraw from its reliability services but is not making public the number that have filed. The organization has noted that market participants are highly likely to receive RC services and market services from the same source.
An outline of the Peak Reliability/PJM Connext reliability and market services offering | Peak Reliability, PJM Connext
“I can say we have not received notices from all of our funding parties,” Peak spokeswoman Rachel Sherrard told RTO Insider. “I would note that, with the exception of one entity, all notices received so far are revocable.” The non-revocable notice is from CAISO, which will leave Peak on Sept. 2, according to organization documents.
The Peak/PJM commitment phase will consist of confidential meetings with interested parties “to review more details on the plan’s assumptions, market size scenarios, expected transactional cost ranges, projected aggregate efficiency savings and proposed services within the business plan,” the organizations said.
They envision the market will initially roll out with a day-ahead and real-time market using LMP and forward transmission rights for hedging. A full RTO would then be developed at the behest of market participants. (See Peak Touts ‘Independent’ Western Market Plan.) Existing RC services would be offered as well as balancing authority services, transmission operation, real-time grid monitoring and control, and interregional congestion management. A NERC-certified RC is needed to comply with the reliability organization’s standards.
Peak has highlighted its knowledge of the Western grid as an RC, while PJM brings its experience in market design and operation. (See PJM Chief Confident on Western Market Proposal.) The real-time market would include spot energy, synchronous and nonsynchronous reserves, and frequency regulation. The day-ahead offering would include a virtual energy market, while the FTR offering would allow a forward hedge price differential between nodal and aggregate locational pairs.
Peak says its funding level will remain flat through 2019. It has scheduled an April 11 conference call on its market initiative.
CAISO says it will “shadow” Peak RC services and then launch its own RC offering by spring of 2019.
Unilever, which sells Breyers ice cream, Dove soap and hundreds of other consumer products, plans to eliminate coal from its energy mix by 2020. It hopes to become “carbon positive” by 2030, by supporting the generation of more renewable energy than it consumes.
Thus far, the company has used onsite solar and power purchase agreements for Texas wind power. But the company has been frustrated in its inability to do more. “If we’re buying wind in Texas and trying to get it to my plant in Virginia, in Tennessee, in Missouri … right now we’re just not able to do that,” Stefani Millie Grant, the company’s senior manager for external affairs and sustainability, said last week.
“If we’re going to actually get [renewables] … actually running our facilities, instead of just being out there buying the [renewable energy credits], we’ve got to really focus on transmission.”
| David Gardiner and Associates for the Wind Energy Foundation
Even as President Trump has moved to undo the Obama administration’s climate initiatives, large corporate energy buyers such as Unilever have accelerated their commitments to purchase carbon-free electricity. But their efforts may be frustrated because of insufficient transmission to move Midwest wind power to load centers, according to a study released by the Wind Energy Foundation. The study was the subject of a webinar last week by Americans for a Clean Energy Grid (ACEG), a coalition whose members include the Natural Resources Defense Council, WIRES, ITC Holdings and American Electric Power.
15 States Hold Most Onshore Wind
The study concluded that transmission expansions currently planned will likely be insufficient to support large corporate energy buyers’ renewable energy goals because most of the solar and wind power potential is in 15 Midwestern states, far from load centers. The 15 states hold 88% of the country’s wind technical potential and 56% of its utility-scale solar photovoltaic potential, but they are home to only 30% of projected 2050 electricity demand.
15 Midwestern states have 88% of the U.S.’s total onshore wind potential and 56% of its utility-scale solar PV potential. But they are far from load centers and will consume only 30% of projected electricity sales in 2050. | David Gardiner and Associates for the Wind Energy Foundation
This is based on the Renewable Energy Buyers Alliance (REBA) goal of obtaining 60 GW of new renewables by 2025 and the 52 GW of new transmission capacity planned in 14 near-term projects in advanced development in MISO, SPP, PJM and NYISO (see table).
In three of the four scenarios studied, transmission would be insufficient to meet corporate renewable demand. With 9 GW of renewables procured by corporate purchasers since 2013, about 51 GW remain to meet the goal. If RTOs build 90% of the capacity in the 14 projects, only 70% of the corporate demand would be filled, the study said. If corporate procurements fall short at only 20 GW, the transmission projects would meet the corporate needs, the study said.
| David Gardiner and Associates for the Wind Energy Foundation
According to the study, one of the biggest obstacles to bringing more renewable energy online is “the absence of transmission planning across RTOs and other regional planning authorities.”
Not Counting All the Benefits
“I think that current [transmission] planning process doesn’t do an adequate job of really counting up all of the benefits, and then it doesn’t think about it … in a … broader geographic scale,” said David Gardiner, president of David Gardiner and Associates, which conducted the study for the foundation.
“We’ve built the interstate highway system in this country not because the highway system went from point A to point B, and the people along point A and point B paid for it, but because we recognized that it provides national benefits, and therefore everybody contributed nationally. We need to be thinking about how we assess the benefits and think about how we want to pay for things more along those lines than we currently are.”
The study recommends that corporate and institutional energy buyers participate in regional and interregional transmission planning and urges FERC and RTOs to improve interregional planning under Order 1000. It said RTOs should incorporate voluntary, large customer demand in transmission planning.
“While we highlight a few examples in the report of companies like Stefani’s that have engaged in some of the planning for transmission lines, it’s been limited, and we’re going to need to step up the kinds of engagement in the transmission planning process as we go forward,” Gardiner said.
Gardiner’s study found that while transmission planners “in rare instances” account for voluntary goals, such as statements by governors, they do not account for growing voluntary demand from large corporate purchasers. “Instead, RTOs typically only focus on mandatory renewable energy requirements prescribed by [renewable portfolio standards].
“If a governor issues a voluntary goal to develop 1 GW of renewable energy in the state, some RTOs would typically include assumptions to meet that 1-GW target in transmission planning models. Although the goal may not be a mandate … other RTOs do only what FERC requires, which is to ‘consider’ public policy and may ultimately opt not to include state RPSs or other policies in their plans.”
RTOs Respond
Officials of MISO, PJM and SPP told RTO Insider last week they are adding transmission for renewables as best they can under FERC transmission planning and cost allocation rules.
“Lack of transmission expansion to facilitate renewable deliveries across regions is not due to inadequate transmission planning between the regions,” said SPP Vice President of Engineering Lanny Nickell in a statement. “Rather, the lack of expansion primarily derives from the difficulty in achieving agreement among multiple groups of customers as to who receives the benefits and, thus, who should pay for transmission upgrades.”
Nickell noted that SPP and other RTOs consider varying amounts of renewable transfers between regions in their interregional transmission planning studies. “RTOs have largely addressed this issue within their regions due to FERC-approved cost allocation mechanisms for service contained in their areas. However, customers in other regions are sometimes challenged to deliver renewable energy from regions like SPP’s because they are unwilling to bear the costs of required infrastructure upgrades or because it is difficult to find other customers willing to share the costs of those upgrades that they don’t believe benefits them,” he said.
“We believe our transmission planning process does adequately address large customers’ increased demand for renewable energy,” said Eli Massey, MISO’s senior adviser for policy studies, in a statement. “MISO’s top-down transmission planning examines regional economics, and its bottom-up planning examines local load growth and reliability issues in order to optimize the transmission system. MISO’s transmission planning process already facilitates the study’s recommendation that large customers engage in the transmission planning process through the industry sector mechanism of the Planning Advisory Committee.”
PJM spokesman Ray Dotter said the RTO accounts for transmission for renewables through its markets and interconnection process.
“We do not plan or build transmission lines on speculation alone,” he said “The developers of new generation of any type are required to pay for the transmission upgrades necessary to deliver the output of their projects. The principle has been that consumers should not pay for transmission required because of generation developers.”
He noted that PJM’s state agreement approach allows states to take responsibility for the costs of transmission expansions addressing their public policy requirements. FERC approved the state agreement approach in a 2015 ruling as part of the RTO’s plan to integrate multi-driver projects into the Regional Transmission Expansion Plan (ER14-2864). (See PJM Wins OK on Multi-Driver Tx Projects.) PJM said the multi-driver concept could lower the cost of states’ public policy transmission projects by incorporating them in upgrades that address market efficiency or reliability.
Nickell said SPP considers voluntary and mandatory renewable goals in its planning assumptions. “If a wholesale customer, under the SPP Tariff, desires to buy from a new or existing renewable resource to supply the needs or goals of its customers and submits a request for transmission service from SPP, we are obligated to plan the system to accommodate the requested service, as long as the customer agrees to fund any requisite upgrades. SPP will consider any and all requests for transmission service made to deliver energy from existing or future renewable resources to prospective buyers and will direct construction of transmission upgrades on the SPP system needed to accommodate those requests in accordance with the respective customers’ service agreements.”
RPSs — which currently represent 10% of MISO’s load — are considered the base level of renewable penetration in its transmission planning modeling futures. “Large customer demand for renewable energy is included in alternative modeling futures on an additive basis that range up to 30% penetration of MISO system load,” Massey said. “We believe that level of penetration fully captures the stated goals of large customers and still leaves room for additional growth.”
Massey, who also spoke at the webinar, said it is the scheduling of transmission to deliver power under a PPA that signals load growth to MISO.
The RTO also learns of PPAs from stakeholders. “But because MISO is not a signatory to the power purchase agreement, we don’t always know about these power purchase agreements, so it’s difficult to plan in that context.”
ACEG Executive Director John Jimison, who moderated the webinar, noted that “it only takes a couple of years” to bring a wind farm or central solar plant into operation, shorter than the timeline for developing new transmission. “How do you anticipate the need for transmission so that you don’t expect people to put up a wind farm and then wait five years before they can actually transmit the power?” he asked.
Massey said MISO accounts for that disparity through its multi-value projects (MVPs). He cited the wind-rich Buffalo Ridge area of southwest Minnesota, northwest Iowa and eastern South Dakota. “We know that there’s a tremendous amount of wind capacity there, and in the current incentives regime with the production tax credit … and because the cost of wind generators is coming down rapidly, we know that there’s going to be wind locating there.”
MISO has about 37 GW of wind and 21 GW of solar in its interconnection queue. “The good news is that it takes a long time for even those plants to get through the generator interconnection process, and this gives us a little bit of lead time in the transmission planning process to identify projects that we’re going to need on a regional basis, that we can predict based on what the wind capacity is and where we know the load is,” Massey said.
Order 1000
Although Order 1000 requires RTOs to jointly plan transmission with their neighbors — and to “consider” whether needs identified in local and regional transmission plans could be addressed more cost-effectively through joint projects with a neighboring region — it does not require them to build anything.
The commission will conduct a technical conference beginning Tuesday on how RTOs coordinate generator interconnection studies on projects near their seams, saying their practices may not be just and reasonable (EL18-26, AD18-8).
FERC called the conference to address issues raised in EDF Renewable Energy’s complaint against PJM, MISO and SPP last year, which contends that inconsistencies and a lack of clarity in the RTOs’ rules for “affected systems” interferes with developers’ ability to judge the commercial viability of proposed projects. An affected system is one that may be impacted by an interconnection in a neighboring “host” system.
MISO and PJM will decide by May 18 whether to undertake a coordinated system plan study this year, the RTOs said last week.
The decision could be announced at the next Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on May 11. Staff from both RTOs confirmed the timeline at last week’s IPSAC meeting, which included the issues review required as part of the process of determining whether a study is required.
“We don’t anticipate taking that long,” PJM’s Alex Worcester explained, referring to the May 18 deadline. He later added that PJM is “likely supportive” of a study.
The RTOs will provide justification for their decision, MISO’s Adam Solomon said. It will be based on whether there are projects that “make sense,” addressing reliability issues on either side of the border that are close to each other.
PJM and MISO in January jointly reviewed their separate regional issues, newly approved projects near their border, coordinated interconnection requests and historical market-to-market congestion, which RTO representatives said would form the basis of the study, if it’s undertaken. The results were presented at last week’s meeting, along with analysis of stakeholderfeedback.
RTOs’ Review
Worcester reviewed projects approved through PJM’s monthly Transmission Expansion Advisory Committee analysis, including 27 baseline reliability projects near the RTOs’ shared border, six market efficiency projects and another six supplemental projects.
All reliability issues identified for 2022 are being addressed through a single proposal window open last summer. Market efficiency projects are addressed on a 24-month cycle that last identified issues in October 2016, but an addendum window to address thermal constraints on the Tanners Creek-Dearborn 345-kV line was closed in February. Supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. They’re included with baseline and market efficiency projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval.
Solomon reviewed the 2018 MISO Transmission Expansion Plan, which began in June 2017 and is scheduled to culminate in December 2018 with approval from the Board of Directors for recommended projects. He highlighted 52 approved projects near the RTO border that might spur interregional projects if there are needs nearby in PJM’s territory. They are all TO-submitted ‘bottom-up’ projects.
MISO is also reviewing 15 of its most congested north/central flowgates, which will be included in its Market Congestion Planning Study this year to potentially identify market efficiency projects, he said. Nearby PJM economic issues could drive the need for an interregional project. He also noted 21 congestion flowgates that were eligible for the MCPS but were excluded for individual reasons.
Stakeholder Issues
The RTOs also reviewed issues identified by stakeholders. Ameren submitted four issues, while three issues Northern Indiana Public Service Co. highlighted were included in Solomon’s presentation.
“We will look at those as appropriate and as they show up in the interregional process,” Worcester said.
NIPSCO’s final concern involved PJM’s finding of 10 facilities with infeasible auction revenue right paths. ARRs are rights to the revenue from congestion charges allocated to firm network and point-to-point customers because they fund the embedded costs of the transmission system. MISO and PJM are each addressing one of the infeasible ties with approved internal projects. Three others have projects under consideration, and two others will be included in a future proposal window. The three remaining infeasible paths are pseudo-tie flowgates. (See “ARR Analysis IDs Constraints,” PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017.)
Worcester said MISO has no process comparable to PJM’s ARRs, so “if it’s outside of PJM, it’s unclear how it would move through the [RTOs’ joint operating agreement] with the competitive transmission process,” he said. PJM will investigate internally ways to address the issues and engage with MISO on any potential solutions, he said.
Wind on the Wires and EDF Renewable Energy asked that the RTOs re-evaluate previously considered targeted market efficiency projects (TMEPs) that did not qualify last year if congestion has continued.
“We certainly agree with that in principle,” Worcester said. He said the RTOs aren’t planning on reconsidering the Thayer-Morrison project, which Wind of the Wires had specifically requested.
JOA Changes
Seven stakeholders provided feedback on three potential JOA changes, which informed the RTOs’ decision-making on the issues. References to joint economic models will be removed.
“NIPSCO prefers a joint model,” the company’s Clark Gloyeske said, noting past differences between the regional models in wind-unit profiles. “More coordination between the regional models to fix some of these modeling issues would be really helpful.”
The RTOs have decided against changing the number of benefit years, fixed charges and discount rates used in analyses, Solomon said. While changes were recommended, they were “wildly varying” on what the correct number of years should be.
“Considering all the feedback, the RTOs think this should be a regional discussion,” he said. “We think the regional processes are working … and that we shouldn’t be deviating from the regional criteria.”
“I understand the simplicity of working just within the regions … but if the number of years the benefits are calculated over are significantly different … I think there’s a risk of coming up against significant stakeholder or state concern about another region not paying its fair share because they haven’t calculated the same level of benefits over the same years,” said Natalie McIntire of Wind on the Wires.
Solomon acknowledged the “valid concern” but said it had to be weighed against “regional differences.”
“Each region has its own definition of how benefits should be calculated, and that’s in line with what we do with our regional projects,” he said. “Deviating from that for an interregional project would be difficult, but certainly, your point is taken.”
The generation-to-load distribution factor test will be removed, Solomon said, and the RTOs will rely on their own regional materiality tests. This removes a “triple-hurdle concern” that would require projects to pass tests for each region as well as an interregional review, Worcester explained. PJM will develop its test through its recently formed Market Efficiency Process Enhancement Task Force, while MISO is still considering where it will address the question.
“The Tariff is silent on how projects qualify materiality-wise,” Solomon said.
Ameren’s Adam Weber asked that the regions’ materiality tests be delineated in the JOA so stakeholders aren’t surprised by a project not clearing both tests. RTO staff hesitated to endorse that proposal but were aligned on addressing Weber’s concern.
An analysis of site location compared to benefits of interregional projects between MISO and PJM shows that there are nine potential cost-allocation categories into which a project could fit. | MISO, PJM
The grid operators will replace the distribution factor (DFAX) cost allocation method with an approach that allocates costs to the RTO with the reliability need, with split projects allocated based on the ratio of avoided costs. Cross-border baseline reliability projects will be replaced with interregional reliability projects because no scenario exists where the baseline projects would be used. An RTO will be obligated to construct projects that benefit the other RTO, but the benefiting RTO will cover the costs.
“There’s not going to be a scenario where there’s a new project developed and we would need to come up with a new cost allocation methodology,” Solomon said.
The RTOs said they “don’t see a need for” EDF’s request to add benefit metrics for projects, but a second request to broaden the JOA’s definition of a flowgate will be forwarded to the Congestion Management Process Working Group, which has representatives from most RTOs.
The RTOs hope to have the JOA changes in place for the next interregional market efficiency project window, which opens around Nov. 1.
“We’re thinking that a filing should be made by July to allow for the FERC process to go through,” Solomon said.
AUSTIN, Texas — The Public Utility Commission’s open meeting last week was the last for Commissioner Brandy Marty Marquez, who announced March 8 that she is resigning from the commission after five years of service.
PUC Chair DeAnn Walker, who has known Marquez for many years, opened the meeting with words of praise for her good friend. Walker cited her loyalty, wit, tenacity and compassion. And her tears.
“She joked about it, maybe having a tear here and there on some cases,” Walker said of Marquez. “Some people saw that as a weakness, but I saw that as one of her strengths. She was compassionate, but she always ruled on laws and facts.”
“They make fun of me for being a crier over here,” Marquez said during an interview earlier, in which she noted the differences between the political arena, where she spent 17 years, and the regulatory world. Marquez frequently referred to “here” and “there,” nodding over her shoulder to the Texas State Capitol visible through her office window.
“Over at the Capitol, I think I got choked up twice,” Marquez said. “I think I’ve grown a heart over here, which is probably difficult for people who are not in this industry to understand. But when you’re dealing with the kinds of things we deal with here, it’s pretty cool to be a part of it.”
The senior member of the commission, Marquez said she was resigning to return to the private sector. (See Marquez to Depart Texas PUC.) Two weeks later, she said she doesn’t “exactly know what’s next yet.”
Marquez said she’s “led a very blessed life” in that she chooses a path and “something will go horribly wrong.”
“Then I kind of throw it up in the air, and then something I never would have dreamed could happen to me will happen to me. This is kind of a reoccurring theme in my life.”
Such was the case in 2013, when Marquez was Gov. Rick Perry’s chief of staff as the state’s legislative session came to an end.
“I’m a believer that when you feel the whisper of, ‘It’s time to think about doing something else,’ you should honor it, because the whispers eventually become a shout and then a yell,” Marquez said. “I knew I needed to leave Gov. Perry’s office. I had worked for him for several years, but I had no idea what I wanted to do.”
Unexpectedly, Perry asked Marquez if she would serve on the PUC. She agreed.
“It was perfect,” she recalled of the switch. “It’s been wonderful.”
Marquez first had to acclimate herself to the regulatory pace. At the Capitol, she said, “You have five minutes to make a decision. Things are happening so quickly over there. This bill is up. Does it do this? What’s the answer?
“In the regulatory world … you take your time to get more information,” Marquez said. “If you’re unsure, it’s OK. There’ll be more time. Over there, you’re constantly thinking about the political angle. They don’t want you to be political here. They want you to just look at the problem and solve it.”
At the Capitol, the political crowd is always looking for a “seam,” Marquez said. If a lawmaker’s bill gets shot down, they look for someone else’s bill that might work. If that bill doesn’t work, they look for another.
“In the regulatory world, there are no seams. There are well-plotted streets and sidewalks, and maybe if you want to get crazy, you can get off the street and get on the sidewalk. You have to have that very prescribed predictability, because you can’t ask people to invest billions and not know the rules of the game.”
A San Antonio native, Marquez earned her undergraduate degree from the University of Texas at Austin and her law degree from St. Mary’s University in her hometown. She calls herself a “child of chaos” who grew up in the Capitol, working first as an intern while also going through law school. Marquez served in numerous leadership positions on Perry’s staff, including as his budget director, his policy director during his successful 2010 gubernatorial campaign and as his chief of staff during Texas’ 83rd legislative session.
Marquez joined the PUC during the summer of 2013, reuniting with fellow Perry administration veterans Donna Nelson and Ken Anderson. It was a turbulent time, Marquez said, with a severe drought driving concerns over ERCOT’s resource adequacy.
Within a year, Energy Future Holdings, a group of private equity firms that acquired Texas energy firm TXU in a 2007 leveraged buyout, declared bankruptcy. The PUC would be consumed with protecting the state’s ratepayers from EFH’s financial travails during attempts by several companies to acquire its Oncor utility. California’s Sempra Energy finally earned the golden ring earlier this year. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
A similar concern for ratepayers drove the PUC to push Oncor and Sharyland Utilities to swap customers and assets, relieving Sharyland’s ratepayers of some of the highest rates in the state. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
Marquez singles out both Oncor proceedings as the proudest accomplishments during her tenure at the commission.
“[Sharyland’s] ratepayers were in a lot of pain out there. It became very important for me to find some kind of resolution, so people weren’t having to live in fear of their utility bill,” she said.
Marquez said she gained a deep appreciation for utility workers after visiting South Texas to see the restoration efforts following Harvey’s devastating blow to the Texas Gulf Coast last August.
“It’s an industry where when the rain is pouring down, [the workers] go out. In Houston, they wade in water up to their waist, and in South Texas, they’re in mud up to their knees. It’s very inspiring what these folks do to ensure we have the quality of life we have in this country.”
Marquez also had praise for the “problem-solvers” at the PUC — the staff, which she said provides a soft landing spot as the governor’s appointees cycle through. “They tell you, ‘Here’s what’s going on here. Don’t be afraid, we’ve got you,’” Marquez said. “We have a very good continuity plan, because we have a very good staff here.”
During last week’s open meeting, Walker noted that for the first time since 2008, official portraits of the current commissioners hang underneath the PUC’s logo on the meeting room’s wall. (Nelson did not allow her picture to be hung until just before she left last May).
“We’ll have three pictures up for one week. It’s your fault that we’re going back to two,” Walker said, teasingly.
Asked if she has any regrets about her decision, Marquez told RTO Insider that she leaves the PUC in good hands with Walker and Arthur D’Andrea, who replaced Nelson and Anderson, respectively, last fall.
“It’s a natural conclusion of a lot of things. It was the new energy of people who I could not think more highly of,” she said. “I just feel like it’s in a good spot, it’s an OK time for me to spring forward and see what kind of chaos I can get into.”
NEW ORLEANS — While MISO’s various sectors last week voiced differences in their views of what constitutes grid resilience, they could agree on one thing: Its specific attributes are still difficult to pin down.
Resilience was in the spotlight after MISO stakeholders selected the subject as their quarterly “hot topic” industry discussion held before the RTO’s Board of Directors on March 28.
Meeting participants offered a mixed bag of suggestions.
Minnesota Public Utilities Commissioner Matt Schuerger agreed with FERC’s definition of resilience as the “ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
But Schuerger said he sees a lot of overlap between reliability and resilience, making the latter largely covered by NERC’s portfolio of standards.
Otter Tail Power’s Stacie Hebert said some of MISO’s transmission-owning members viewed resilience more narrowly as the ability of the system to recover from a failed state.
MISO’s Environmental sector is concerned about double-counting resilience as resource adequacy and reliability, said sector representative John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project. He argued instead that there are degrees between “fragile reliability” and “resilient reliability.”
“So much of what MISO already does in planning relates to resilience indirectly or directly,” Moore said.
Coal- and oil-fired generators became comparatively economic during early January’s cold snap because they had not been regularly run until emergency conditions nudged them “higher in the dispatch stack,” he said. “They were the most expensive resources in the system until we needed all resources.”
North Dakota Public Service Commissioner Julie Fedorchak said states may have to increasingly turn to MISO’s markets to fulfill generation requirements as uneconomic units retire.
Alliant Energy’s Mitchell Myhre said his Transmission-Dependent Utilities sector was trying to avoid being “too prescriptive” in defining resilience, a concept he called “hard to define.”
Still, others saw a clearer distinction between resilience and reliability.
“My kids will never know what it’s like to sit around with candles playing war games during a thunderstorm because the power is out. That just doesn’t happen anymore. That’s reliability,” Wisconsin Public Service Commissioner Mike Huebsch said. Resilience goes further than that, entailing better communication between grid operators, utilities and customers when disruptions occur, he said.
MISO Already Managing Resilience
Multiple members said MISO already has processes in place to tackle resilience.
“We think MISO is resilient. It’s always been part of our base business, even if we didn’t call it resilience,” said MISO Vice President of System Planning Jennifer Curran.
In response to FERC’s call for RTO/ISO comments on resilience in early March, MISO reported no “imminent or immediate” concerns in its footprint and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” (See “MISO: Work Already in Progress,” RTO Resilience Filings Seek Time, More Gas Coordination.)
“The resilience issue is broader than the transmission grid, and we all have a role to play in ensuring resilience,” Curran told stakeholders.
Director Baljit Dail asked sectors what the RTO should do incrementally beyond what it already does.
“It seems to me that the bulk of the resilience issue is not at the MISO-level, but the distribution level, and that’s not MISO’s purview, but all of you sitting around this table,” he told members.
Moore said MISO could expand cybersecurity measures, with which Dail agreed.
Kevin Murray, representing the Coalition of Midwest Transmission Customers and MISO’s End-User Customers sector, pointed out that much of the RTO’s cybersecurity efforts can only be discussed in closed-session meetings to avoid release of sensitive information.
“I think one of the things that will be a challenge for us is sharing as much of that information as we can,” board Chair Michael Curran agreed.
Director Todd Raba said it seems the distinctions between transmission and distribution systems are becoming increasingly blurred. He rhetorically asked if MISO and its members have to reorganize the metrics placed on each system.
Schueguer said it will be a state-by-state choice to develop mandates to “harden” the distribution system.
‘Accidental’ Resilience
Independent Power Producers sector leader Barry Trayers said he thought MISO is heading toward resilience “almost accidentally” with increased distributed energy resources and a more diverse fuel mix.
“This movement towards DER should bolster the system because there’s less risk of a single large contingency,” said Director Thomas Rainwater.
The difference between the electrical recoveries from Hurricane Harvey in Texas and Hurricane Maria in Puerto Rico last year should help MISO and stakeholders define resilience attributes, Rainwater said. He pointed out that parts of Puerto Rico still don’t have power six months after the storm.
Murray pointed out that during hurricanes last year in Florida, bucket trucks and lineman were already queuing up before they hit, readying restoration efforts.
Director Mark Johnson said MISO and its members will at some point have to identify a list of the likely low-probability, high-impact events that could occur in the 15 states in its footprint, as well as the Canadian province of Manitoba.
“The actions that need to be taken will be very much event-specific,” Johnson said.
“There comes a point where maybe we put pen to paper or steel to ground,” agreed Advisory Committee Chair Audrey Penner.
Studying Weather Events
End-Use Customers sector representative and Louisiana Public Service Commission counsel Katherine King said a better understanding of resilience will require MISO to conduct an in-depth investigation into its South region’s two most recent maximum generation events: one last April after heavy outages and high temperatures, and another in mid-January triggered by extreme cold. (See “Several Factors in Spring MISO South Maximum Generation Event,” Louisiana Regulators Question MISO South Max Gen Event.)
“I think it’s very important to go back in after these events occur and ask what caused them and what we can do better,” King said.
The Louisiana PSC is opening a docket and scheduling a technical conference to investigate the January maximum generation event, King added.
Mississippi Public Service Commissioner Brandon Presley said the RTO should also study contingency impacts on the 3,000-MW contract path connecting MISO Midwest and South.
“Everybody has an interest in that connection and woe be it on us if we ignore that,” Presley said.
Rainwater said any changes made in the name of resilience must be cost-effective.
“At the end of the day, the end-use customers will have to pay for whatever resiliency measures we deem necessary, and we have to keep that in mind. We cannot build the system to protect it from … interruptions of any kind,” Rainwater said.
NEW ORLEANS — A seasonal post-mortem at MISO’s Board Week provided stakeholders with insight into the RTO’s market performance during the near past, near future — and beyond.
MISO and its Independent Market Monitor agreed that markets generally performed well during a challenging winter, and the RTO predicts more operational efficiency throughout spring. But it foresees considerable market changes over the next decade.
The RTO said the sustained cold snap that opened the year was “managed nearly routinely by MISO and members.”
Executive Director of Strategy Shawn McFarlane said the RTO’s $31/MWh December-February average energy price was about 10% higher than last winter.
MISO’s winter peak of 106.1 GW, set on Jan. 17, was 3.2 GW lower than its all-time winter peak set in January 2014. Loads exceeded 100 GW for the first five days of 2018, with forced and planned outages reaching 36 GW. (See MISO Breaks down Recent Cold Snap.)
“While it wasn’t routine, it was handled quite routinely — not a lot of excitement,” McFarlane said during a March 27 meeting of the Markets Committee of the Board of Directors.
MISO committed one unnecessary unit on Jan. 1, an inefficient outcome in what was an otherwise more efficient performance when compared to 2014’s polar vortex weather event.
However, the RTO said a brief mid-January cold spell concentrated in MISO South “proved more challenging, but reliability maintained.” During his quarterly report, Monitor David Patton agreed that mid-January generation patterns “were more fascinating.”
In that instance, another round of arctic air pushed loads above 106 GW over Jan. 17-18, and MISO South set a new winter peak of 32.1 GW in the face of record low temperatures in the region. (See Louisiana Regulators Question MISO South Max Gen Event.) MISO was forced to call a maximum generation event in the South region Jan. 17 after outages there hit 17 GW.
McFarlane said MISO South’s icy weather froze the region’s water and air lines, which are not nearly as insulated as in MISO Midwest. The RTO compensated for South’s shortfall with generation from Midwest, at one point flowing just over 3,000 MW — the maximum allowed by the MISO-SPP agreement — along the contract path between the regions.
“The [South] generators just aren’t as prepared for freezing temperatures,” Patton said. “Part of the reason we were in such bad shape is because the forced outages kept growing and growing. … This is about the most stressful situation I can imagine for MISO South.”
Patton said if the RTO had not made emergency power purchases for the South on Jan. 17, regional supply would have dipped below load for about three to four hours. He referred to the “lights going out in MISO South.”
But Director Michael Curran immediately rebuked Patton’s use of such dramatic language, while also responding that MISO should “burn down” SPP’s transmission on the contract path before it allows MISO South to shed load.
Patton said the situation highlights the need to create a regional capacity reserve product that can be delivered within 30 minutes, a recommendation he repeated from last year’s State of the Market report. He also said MISO’s emergency prices are still too low because its extended locational marginal pricing (ELMP) does not properly account for regional dispatch transfer flows. Accounting for such flows in ELMP would be an easy fix, he added.
Spring
Executive Director of System Operations Renuka Chatterjee reiterated a previous report of MISO’s spring preparedness but noted that volatile spring weather can “break load patterns.”
MISO staff said earlier in March that the RTO faces a small possibility of spring emergency conditions if either loads or forced outages are higher than normal. (See Outages Small Risk for MISO Spring Operations.)
Director Thomas Rainwater asked if the outage risk comes from large, thermal units whose loss “MISO has to scramble to replace.”
“Yes, it’s obviously the 1,000-MW units,” Chatterjee replied.
She said as little as an additional 2 GW in forced outages over forecasted load could force the RTO to call upon reserves this spring.
“We’ve seen a chance in the last couple of years of tight operating conditions in the shoulder seasons,” Chatterjee said. “[Reserves] are the end of our stack, and we’ll get into those if we have to.”
However, Chatterjee reassured the board that MISO faces a very slim chance of spring load shedding.
Patton said he now recommends that some generators take planned outages during winter rather than spring to lessen the impacts of mass outages in shoulder periods.
Beyond
With winter and spring covered, a MISO executive outlined a rough to-do list to design a market for a future grid that includes renewables, storage and smart devices.
Richard Doying, now head of future market design, delivered to the board the first report of his exploratory-style role. (See “MISO Shuffles Leadership,” MISO Informational Forum Briefs: Jan. 23, 2018.)
“MISO will be operating transmission with very different assets in the future,” he said.
Doying and MISO staff are evaluating what changes are needed to incorporate renewables, distributed energy supply and storage, and digital flow control devices such as smart appliances and thermostats. The RTO will complete an analysis of market, operational and planning impacts, and prepare a report by the first quarter of 2019, he said.
“Software cycle time really drives digitalization. When you think about an app on your phone that you can install today that wasn’t available yesterday — that took just a few weeks for someone to develop,” Doying said.
Digitalization will affect the grid much more than owners and operators may realize. “Although we can’t see when the changes will arrive, we know that they are coming,” he said. “Waiting until they arrive is a problem and will be imprudent.”
MISO must address, for instance, windy nights when LMPs fall to negative values, a situation that becomes unworkable for non-wind generators serving load. He also said the RTO’s market team will investigate how to properly value essential reliability services.
Director Baljit Dail asked what the RTO’s version of California’s “duck curve” may look like.
Doying responded that MISO is investigating a “double up” of its renewable sources in the next 10 to 15 years, as indicated by new entrants to the queue, but he didn’t elaborate on specific demand curve shapes.
“This is an exciting, but scary, pallet of issues,” said Director Barbara Krumsiek.
Rainwater asked how MISO will begin to value other attributes in a system designed around cost-based ratemaking.
Doying did not get into specifics, but he said that “pricing will be a critical element of any reforms.”
NEW ORLEANS — MISO’s dedicated market platform replacement team will work this year to ensure the RTO’s existing system can stay afloat during the time it will take to build the new one, staff told stakeholders last week.
While MISO is slated to begin naming specific requirements and assembling the new platform next year, this year’s efforts will focus on “standing up” the existing platform for day-to-day operations with software patches, Executive Director of Market Development Jeff Bladen told the Technology Committee of the Board of Directors on March 27.
The RTO has so far filled 18 of the 30 positions it has planned for this year, including market engineers and a software architect, Bladen said.
In 2017, MISO completed an assessment on the capability of its existing market platform and began early design of the new, more adaptable modular system. The RTO is poised to spend $130 million by 2024 to replace the aging system. It expects to begin migrating to the new system in 2020, keeping the current one in operation at least until 2021. (See MISO Makes Case for $130M Market Platform Upgrade.)
“This will be one of the largest undertakings in our history,” Bladen said.
“We’re making sure we build the right kind of system, not just an enhanced version of the current system,” MISO Director of Forward Operations Planning Kevin Sherd told stakeholders at a March Market Subcommittee meeting.
‘No BS’
With such a complex project, MISO’s directors urged that executives deliver clearer reports that do not minimize any future hitches or budget overflows.
“What I want to hear from you is clear, candid communication. No BS. No flowery language. … That’s the kind of stuff that I need to hear,” Director Thomas Rainwater told MISO executives.
“That’s what we need: full transparency and candor. We’re not going to rip your heads off,” Director Baljit Dail added.
Earlier in March, Bladen said the RTO’s new platform will be equipped to handle expanded energy storage participation under FERC’s Order 841, but the legacy system may struggle to accommodate the directives.
Meanwhile, MISO’s separate, settlements platform replacement is ready for the launch of five-minute settlements, officials said, although the RTO is continuing to test the new system while it waits for generation owners to adapt their own software and reporting systems to a five-minute schedule. MISO has twice obtained FERC approval to defer the five-minute settlements roll-out until July. (See MISO Wins Delay on 5-Minute Settlement Roll-Out.)
