CAISO and Pacific Gas and Electric have asked FERC to reconsider its decision last month to approve only some of the utility’s requested transmission rate incentives related to more than $1 billion in planned grid improvements.
The ISO and the utility on Sept. 25 filed separate requests for FERC to rehear a determination that PG&E had not justified all of its proposed “abandoned cost” recovery, which allows it to recover from its customers the costs of abandoning construction for reasons beyond its control. (See FERC Approves PG&E Transmission Cost Recovery.)
Timeline and cost of PG&E’s proposed projects | PG&E
PG&E in its rehearing request called the incentive request “narrowly tailored” and said it faces significant challenges in developing the greenfield projects that are not in an existing right of way (EL16-47). The utility had requested 100% recovery of costs for any of the eight projects if they are abandoned, but FERC approved incentives for only three of them. The utility said it has already invested $68 million in construction and that the projects face risks, including environmental permitting, siting authority and potential impacts of from California’s renewable energy goals.
“Consequently, under a rigid application of the effective-date limitation imposed in the orders under review, PG&E now faces an unexpected risk of loss equal to 50% of that initial $68 million investment,” the company said, adding that “if allowed to stand, this outcome will create a disincentive for PG&E to make similar investments in the future.”
PG&E said that while the requested incentives would allocate to ratepayers 100% of the risk of abandonment for reasons beyond a utility’s control, “FERC’s orders here shift 50% of that risk for a defined period (before the issuance of a project specific declaratory order) to the utility and its shareholders. This reallocation makes investment in new transmission projects riskier and less attractive.”
CAISO’s filing contended that each project meets FERC’s standard because it was approved by the ISO as part of a regional planning process and that “CAISO approved these specific projects to meet identified reliability needs on the CAISO system.” Project sponsors such as PG&E have an obligation to obtain approvals and rights if the projects are approved as part of the ISO’s annual transmission planning process.
CAISO said it has canceled other projects approved in annual plans and that it is currently assessing whether to cancel other previously approved projects, so “the risk of abandonment is not hypothetical.” When developing its 2015-2016 plan, the ISO canceled 13 PG&E low-voltage transmission projects it had previously approved.
Southern California Edison on April 7 filed a similar request for abandoned cost recovery upon which the commission has yet to rule (EL17-63). The petition requested approval of incentives for a package of transmission improvements totaling about $1.3 billion, approximately $903 million of which are recoverable in transmission rates.
While the California Public Utilities Commission had objected to PG&E’s incentive rate request, FERC rejected the state regulators’ arguments about PG&E’s transparency and cost control.
Earlier this month, FERC in a different proceeding also rejected a protest from the PUC over incentive rate adders the commission had approved for PG&E in 2016. (See FERC Upholds PG&E ISO Incentive Adder, Rebuffs CPUC.)
ST. PAUL, Minn. — Representatives of MISO sectors gathered Wednesday to discuss how a greater number of distributed energy resources could interact with the grid. Topics ranged from the gig economy to state jurisdiction to the socioeconomic barriers preventing some from obtaining those resources.
Vice President of System Operations Todd Ramey said DER “such as rooftop solar systems and microturbines” are not as widely used in MISO as in other RTOs.
“However, the MISO region could see a substantially higher penetration of distributed energy going forward as the costs of the resources continue to decline and if cities, states and the federal government continue to adopt policies that encourage their use,” Ramey said.
By 2030, installed photovoltaic resources could top 17 GW, while demand response and energy efficiency deployments could exceed 6 GW and 8 GW, respectively.
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, kicked off the discussion by engaging stakeholders, MISO staff and board members in a sing-along of Fleetwood Mac’s “Don’t Stop.”
“‘Don’t stop thinking about tomorrow.’ That’s the trend. There hasn’t been much DER activity so far, but we plan for it,” Johnson said.
Defining DER
MISO presented a draft definition describing DER as power generation, storage or load-modifying resources connected either through a utility’s distribution system or behind the meter. DER can include photovoltaics, combined heat and power, cogeneration systems, reciprocating engines, combustion turbines, microturbines, wind turbines, back-up generators, energy storage and even DR and energy efficiency, according to the definition.
Most sectors, including the Organization of MISO States, agreed with MISO’s take. OMS organized an early August workshop in which state regulators and industry officials similarly explored DER topics, and has since formed a temporary work group to consider how to incorporate the resources into the grid. (See Stakeholders Hash out Future of DER at OMS Workshop.)
“Consumers [are] moving to being customers of the grid,” said John Moore, attorney for the Natural Resources Defense Council, who likened the energy customer transition to that of licensed drivers and the rise of Uber’s ride-share program.
Director Baljit Dail seized on the Uber analogy. “There may be a whole new player that comes into the mix and provides a platform for people with DER to sell,” Dail said.
Entergy’s Matt Brown said there will probably be a future need to designate a minimum megawatt participation limit on DER to include them in whatever market definition the RTO eventually settles on. “MISO might not be the appropriated entity to draw those lines,” Brown added.
“The advantage that we have here is that we really have some time to make some really elegant solutions,” Northern Indiana Public Service Co.’s Paul Kelley said.
“Let’s not lose sight of [the fact] that getting paid within MISO is not a trivial matter,” Dynegy’s Mark Volpe said. He said suppliers must go through the process of creating commercial pricing notes, signing agreements with MISO and posting collateral to get set up on the wholesale distribution level — none of which is an easy task.
State Jurisdiction
Minnesota Public Utilities Commissioner Matt Schuerger said that while DER rules will fall under state jurisdiction for resource adequacy, MISO, industry leaders and generation and transmission operators will play a vital role in coordinating and planning. “I think state regulators will need information from MISO to help make decisions,” he said.
Arkansas Public Service Commission Chairman Ted Thomas reiterated a warning issued by former FERC Commissioner Tony Clark at the OMS DER workshop, saying states will get rules mandated to them by FERC if they fail to write their own.
“States can [wait to] act and wait for FERC to act, and what we’ll get is a velvet glove around an iron fist — one size fits all,” he said.
Wind on the Wires’ Beth Soholt pointed out that many Midwest manufacturing plants are already beginning to alter their energy supply mix to meet renewable goals. “You’re going to continue to see this trend ripple through large energy customers,” she said. Soholt said MISO planning might need to look past demand, including at customer preference. She said as long as demand growth remains the single most important factor in transmission planning, MISO will not have a complete picture of the future.
“I think people think, ‘demand is going down, so we don’t need to plan as much transmission or generation. Customers want a particular kind of mix. … I worry about that if we just look at demand in and of itself, that’s not capturing all the value that these resources have to offer,” she said.
At a Sept. 21 Board of Directors meeting, Executive Vice President of Operations Clair Moeller told board members that MISO is overall moving to a “less peak, more load served” model with the contributing factor of electric vehicles.
Missouri Public Service Commission economist Adam McKinnie agreed that the “haircut of load growth” has been an obstacle in recent transmission planning studies by consulting firm Applied Energy Group.
McKinnie said some states, including his own, collect rooftop solar data, and those numbers could be passed on to MISO planners.
“This could be an example of how the states could gather and provide MISO with information, so MISO doesn’t have to guess,” he said.
Dail urged stakeholders to give MISO guidance on DER market rules. “You didn’t want a MISO that picked winners and loser in regards to technology,” he reminded them.
Moore said MISO must avoid “siloing,” referring to the tendency for DER information to remain in just one database.
“Is there siloing occurring at the distribution level that prevents a complete picture of how much distributed energy is bubbling up?” he asked.
Socioeconomic Differences
Brown said MISO and industry leaders must also pay attention to distributed energy trends in wealthy communities versus poverty-stricken areas, contrasting the incomes in the toney Twin Cities suburb of Maple Grove with those of Flint, Mich., both in the MISO footprint.
“It’s easy to lose sight of how large our footprint is. It’s easy to make sweeping statements like ‘customers want this’ or ‘customers want that,’ but we have to remember the range of customers we have,” Brown said.
Director Thomas Rainwater thanked Brown for bringing up the socioeconomic disparity across the footprint.
“I happen to live within 40 minutes from Flint,” Rainwater said. “One of the great inventions of the last 100 years is the electrification of households and the health and economic benefits that it brings … but there are those that have been left behind. I think that we can all agree that while solar is great and wind is great, the early [residential] adopters are in the upper strata. We need to not lose sight of that.”
Director Todd Raba said regulators and industry officials have an “ethical” obligation to pay attention to keeping costs low for their poorest customers.
CAISO this week will gather feedback on its proposal for reliability payments to keep Calpine’s Metcalf gas-fired plant from going offline, a decision drawing scrutiny amid a larger conversation about local resource adequacy (RA) planning.
The ISO relies on reliability-must-run (RMR) contracts to keep resources online that are slated for retirement but are still needed for reliability. It has a stakeholder call scheduled for Sept. 26 to gather feedback on its recent proposal to designate Metcalf as an RMR resource.
CAISO is Considering an RMR Contract for Calpine’s Metcalf Energy Center | Calpine
The contract is slated for a vote by the CAISO Board of Governors in early November, leading some to complain about a quick decision timeline. The board also faced some scrutiny in March when it designated Calpine’s Yuba City and Feather River gas-fired plants as RMR contractual facilities. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Calpine in June told CAISO that it intends to take the Metcalf plant offline at the end of this year. The company’s request that the ISO study the reliability impact came back in the plant’s favor. “Analysis has indicated that Metcalf Energy Center is in fact required in order to meet the relevant criteria for reliable system operation,” the ISO said in a notice for the call.
At its most recent meeting Sept. 19, the board voted unanimously to extend the current reliability RMR contract for three 55-MW oil-fired units at Dynegy’s Oakland facility. CAISO says it will not renew a contract with AES for the synchronous condensers at its Huntington Beach plant, and those units are expected to shut down.
At the board meeting, Pacific Gas and Electric Director of ISO Relations Eric Eisenman said “these continuing RMR designations show that the market is changing,” pointing to new solar and other resources. He added that “the RA process, especially the local process, needs improvement.”
The RMR contract for Metcalf will put tens of millions of dollars of costs onto ratepayers, he said, asking the board to work with regulators “to improve the local RA paradigm sooner, not later.” He expects more RMR designations for 2019, which will almost certainly raise customer costs.
Noting that CAISO informed stakeholders of the possible RMR designation for Metcalf in early September ahead of the Nov. 1 vote, he said: “We are feeling kind of jammed when it’s tens of millions of dollars.”
Local RA Adjustments Planned
Part of the problem is the way the RA for load-serving entities is measured, CAISO Vice President of Market and Infrastructure Development Keith Casey said at the meeting. RA is currently measured across a broad area, but individual capacity areas within that territory might have inadequate resources.
“We cannot operate being short in a specific area, and I think Metcalf is probably indicative of that deficiency in design,” Casey said. The ISO is working with the California Public Utilities Commission on the problem, and “I am optimistic we will have a proceeding soon to take on some of the deficiencies around the local RA design.” In a Sept. 12 memorandum to the board, Casey said “reliability-must-run contracts remain an important backstop instrument to ensure reliability when other alternatives are not viable.”
RMR contracts are pursued when an LSE does not purchase sufficient capacity to meet local reliability criteria, or when CAISO needs reliability service such as voltage support, black start or dual-fuel capability. RMR can also be used to address local market power or protect availability of a given resource that could retire in the absence of a contract. LSEs are required to provide the RA showing by Sept. 15 of each year and have until Oct. 31 to submit their final year-ahead RA showings. CAISO must notify a potential RMR unit by Oct. 1 of each year whether it will extend an RMR contract.
The number of facilities under RMR contracts has dropped significantly since the implementation of the RA program and the addition of other types of resources. In 2006, CAISO had 9,963 MW under RMR, which dropped steeply to 3,995 MW in 2007. Today, in addition to the Oakland units under RMR, CAISO has about 1,500 MW under black start contracts and about 160 MW under dual-fuel extension status.
CAISO Says Puente Plant Needed
Reliability needs have also led CAISO to conclude that a new gas-fired plant on the California coast cannot affordably be replaced with other alternatives. CAISO on Aug. 16 released its study on the 260-MW Puente Power Project, but NRG Energy has run into heavy opposition to its proposal to build the plant on an existing site in Oxnard to replace its retiring Mandalay and Ormond Beach plants.
Puente Power Project viewed from beach | California Energy Commission
The California Public Utilities Commission authorized Southern California Edison to enter into a long-term RA contract with NRG for the plant’s capacity, and the California Energy Commission is reviewing the construction and operating permit for the facility. The project was approved because 2,000 MW of generation in the area is due to retire by 2020 because of once-through-cooling regulations.
As part of its review process, the CEC accepted CAISO’s offer to study whether demand response, energy efficiency, renewable generation and combined heat and power could offset the need for the Puente project. CAISO last month issued its findings in the Moorpark Sub-Area Local Capacity Alternative Study, after gathering comments from market participants.
After examining three scenarios, the ISO concluded that Puente would be the cheapest alternative at a cost of $299 million. The most expensive scenario was “incremental distributed resources plus grid-connected battery storage (if the Ellwood Generating Station is retired)” at $1.1 billion, more than triple the cost of Puente.
CAISO Determined the Puente natural gas plant was the cheapest option to meet local reliability needs. | CAISO
RMR revenue helps keep natural gas a player in the CAISO market as environmental opposition toward fossil fuels is on the uptick. Gas remains the largest component of CAISO’s fuel mix, making up about 54% of its installed capacity of 71,400 MW, followed by renewables at 29%, large hydro at 12% and nuclear at 3%. Oil, coal and “other” comprise about 2%.
However, conventional generation such as natural gas makes up only 9% of CAISO’s interconnection queue of 325 projects totaling 58,000 MW, while 68% are renewable projects and 20% are energy storage devices.
Aside from RMR, CAISO also has a risk-of-retirement program called the Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) initiative, which is generally regarded as a better alternative to RMR. (See CAISO Finalizes Risk-of-Retirement Program Changes.) That package of market rules is also due for a vote from the board at its November meeting.
ST. PAUL, Minn. — MISO revealed three new candidates for its Board of Directors and reported on an expected budget overrun during the quarterly board meeting on Thursday.
Board Chairman Michael Curran opened the meeting with a moment of silence for the victims of Hurricane Maria in the Caribbean and Puerto Rico. “It underscores the importance of what we do,” Curran said.
Curran announced incumbents Baljit Dail and Thomas Rainwater and newcomer Theresa Wise, former chief information officer for Delta Air Lines, are the candidates for three new terms beginning in January.
If any of the three fails to receive a majority vote, stakeholders will consider alternates John “Jeb” Bachman, former partner at PricewaterhouseCoopers, and Wolfgang Richter, former chief information officer at PricewaterhouseCoopers. In MISO board voting, alternates would only rotate into the election for a second membership vote if any of the candidates in the first vote did not receive a majority of the vote.
The slate was prepared with help from search firm Russell Reynolds. In June, Dail — who by the end of the year will reach MISO’s three, three-year term limit — was granted a one-time waiver to stand for this year’s election. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)
Senior Vice President of Compliance Services Stephen Kozey said electronic voting will be open for 39 days — “not a short amount of time” — and 25% of MISO’s 138 voting members will need to cast ballots to reach an election quorum.
“We’ve been lucky in the past to have voting participation over 60%,” Kozey said.
Noticeably absent from the roster was current Director Paul Bonavia, who had been seeking re-election as of the last board meeting.
Bonavia said that when he announced in summer that he would stand for re-election, he fully intended to do so, but since that time, unforeseen “personal and family matters totally unrelated” to MISO have arisen.
“It’s been a pleasure to be part of the MISO board, and we still have a lot of work to do this year, and I promise to stay fully engaged. I also would like to congratulate MISO on a wonderful roster of candidates,” Bonavia said.
Small Budget Overrun
To date, MISO is $1.8 million under its annual budget, but Chief Financial Officer Melissa Brown said the RTO will likely spend $240.4 million by year-end, exceeding its $239.1 million budget by $1.3 million (0.5%).
Forecast expenses of $240.4M results in being over budget by $1.3M or 0.5% | MISO
As of the end of July, MISO was under budget by 1.3%, having spent $138.7 million of the $140.5 million allotted for the first six months.
In June, Brown prepared the board for a possible 1.2% budget overrun, due in part to MISO’s lower-than-expected employee vacancy rate. (See “MISO Reports Likely Year-End Overage; Board Urges Staff Stick to Budget,” MISO BoD Briefs: June 22, 2017.) The low rate persists, Brown said, but MISO has since shifted some project spending around.
Brown said that while employee retention and spending on employee medical benefits is the biggest cause of the overrun, it’s a sign that MISO’s recent programs aimed at retaining talent are working.
MISO’s capital spending in 2017 is similarly expected to go over budget. Brown said MISO will probably spend $30.2 million instead of its assigned $29.9 million on capital projects (1%).
So far this year, capital spending is $20.1 million, under budget by $600,000 (2.9%).
Dail said stakeholders can expect MISO’s other capital spending to shrink over the next few years to make room for MISO’s multiyear, $130 million project to replace its market system computer platform.
The replacement took more of a share of this year’s overall budget than originally anticipated. The program began with a $1.7 million spend in 2017, but MISO won board approval to increase it to $5.2 million so that staff could start early on vendor evaluation and gathering bids. (See MISO Makes Case for $130M Market Platform Upgrade.)
“It was never easier for me to vote for a budget increase,” Director Barbara Krumsiek said. “It means you’re moving at such a pace” that early spending is needed. “I’d like to thank you for asking for the increase.”
Brown said MISO offset some of the extra platform spending by not having to spend money developing a separate, three-year forward capacity auction for competitive retail areas — a proposal that FERC rejected.
ST. PAUL, Minn. — While MISO “generally” agrees with all nine market improvement recommendations raised by its Independent Market Monitor in its 2016 State of the Market report, the RTO says it must first consult with stakeholders on any proposed market changes.
“There are a number of them where we agree, both on the notion behind them and the recommended approach,” MISO Executive Director of Market Design Jeff Bladen said during a Sept. 19 meeting of the Markets Committee of the Board of Directors.
The RTO said it agrees with the Monitor’s idea of representing the value of lost load with a more sloped contingency reserve demand curve. Patton recommended a curve capped at almost $12,000/MWh, rather than MISO’s proposed $3,500/MWh cap, which the RTO filed in May to comply with FERC Order 831 (ER17-1571).
MISO’s flatter proposed curve generally hovers at $2,100/MWh, unless the market clears less than 8% or more than 96% of its requirement. The current curve is largely priced at $1,100/MWh.
“It seems like a fairly simple question: Why don’t we do this?” Director Paul Bonavia asked regarding the Monitor’s proposed curve.
Executive Vice President of Operations Richard Doying said that while MISO agrees with the more steeply sloped curve, the process for changing “isn’t as simple as filing” a new curve. The RTO must first put the change before its stakeholder community and gather consensus before turning to FERC with a proposal.
“We’ll get to a change. We’re not sure what the shape of the curve will look like, but [a change] is beneficial,” Doying said.
MISO officials are in the midst of developing a plan to transfer control of market-to-market (M2M) flowgates to neighboring RTOs. Bladen said MISO and SPP plan to begin swapping flowgate control soon — a goal first outlined in a June memorandum of understanding between the two RTOs — while MISO will look improve its control transfer process with PJM. (See MISO Interregional Plans with SPP Echo PJM Efforts.) The Monitor wants the three RTOs to become more active in transferring monitoring of constraints when the non-monitoring RTO has all of the transmission loading relief on a flowgate.
Generation Outages
MISO is also aware that it needs a greater say in the scheduling of planned generation outages, Bladen said. In his report, Patton asked the RTO to file changes with FERC to give itself increased authority to approve generation and transmission outages and the ability to coordinate outage schedules in order to lower costs.
“We think that generation outages will somehow be changed. That, I think, is not a question,” Bladen said. “How it’s going to be implemented, that’s an area where stakeholders, the Market Monitor and MISO will have to work together.”
About 16,000 MW of generation was offline for planned outages despite unseasonably warm forecasted temperatures during emergency conditions in MISO on April 4, and the Monitor maintains that the planned outages exacerbated the situation.
During a Sept. 20 Advisory Committee meeting, Citigroup Energy’s Barry Trayers said generators planning the outages should possibly bear some of the related congestion costs.
“By nature of our names, we are transmission-dependent utilities,” Wisconsin Public Service’s Chris Plante said. “What we found out real quickly when working with our transmission providers is that we have to coordinate heavily to align outages.”
“The consumers are bearing the burden of these costs. I still carry the concern of the ratepayer,” NRG Energy’s Tia Elliott said. “We have to consider the economics of these outages — and not the economics of filling our own pockets, but the economics of who bears these costs — because we can’t get the planning and the coordination down right. And maybe we can’t get it perfect, but there needs to be some coordination here.”
Entergy’s Matt Brown said he personally opposes scheduling wintertime outages for the sake of staggering planned outages in the interest of community safety.
“It’s one thing not to have air conditioning in April when it’s 70 degrees. It’s another thing not to have heat in December,” Brown explained.
Reliability Subcommittee Chair Tony Jankowski pointed out that MISO is not charged with evaluating outages based on cost. “If you want MISO to put a price on that outage, that’s a whole different thing. That’s not in MISO Tariff,” he said.
Two Separate Reserves?
Like the generation outage issue, Bladen said MISO faces a similar stakeholder process to create separate regional reserve requirements and cost allocation for its North and South regions, another Monitor recommendation. He pointed out that MISO is currently conducting a multiyear regional transmission overlay study that could identify a transmission solution for the RTO’s constrained interface between the two regions. Neither the Market Congestion Planning Study nor footprint diversity study, both conducted this year, have been successful in identifying a project that could meet cost-benefit requirements.
Other Recommendations Get a Look
The Monitor’s remaining recommendations also must undergo more review, according to Bladen.
State of the Market recommendations take an average of 2.2 years to resolve | MISO
A recommendation to improve the accuracy of MISO’s look-ahead commitment tool by modeling system conditions for a three-hour time frame could be folded into the RTO’s market platform replacement if the Monitor has provided compelling enough evidence for doing so, he said.
Officials also agree with the Monitor that the RTO could tighten qualification guidelines for day-ahead margin assurance and real-time offer revenue sufficiency guarantee payments in order to improve performance incentives and reduce gaming opportunities. Bladen said MISO plans to begin stakeholder discussions about the issue next month.
MISO may be willing to improve forecasting incentives for its wind operators by changing dispatch deviation thresholds and settlement rules, but it must first evaluate how other RTOs have handled wind forecasting, Bladen said.
“There’s a quote by Pablo Picasso: ‘Good artists copy and great artists steal.’ The concept of stealing as he was describing is building on what others have done. That’s what we want to do here; we want to build on and improve,” he said. (Whether Picasso actually said this is disputed.)
Bladen also said MISO still faces a full technical review in front if it undertakes a recommendation to disqualify from the Planning Resource Auction any resources expected to be unavailable during peak conditions. “We’ll be working through with our stakeholders to figure out how to do this,” he said.
Now What?
The Monitor’s recommendations are included for consideration in the current and upcoming Market Roadmap project lists. Patton’s recommendation to create regional reserve requirements was the only one to earn a “top 10” stakeholder ranking among 34 market modification proposals in the RTO’s annual Market Roadmap process. MISO has yet to provide its own staff weightings alongside the stakeholder scoring results to determine what market projects the RTO will eventually undertake. (See “Stakeholders Give Energy Storage Top Spot in Roadmap,” MISO Market Subcommittee Briefs: Aug. 10, 2017.) MISO will unveil a final project prioritization by December.
MISO said it plans to spend about $53 million in Market Roadmap market revisions over the next five years.
Director Michael Curran said that roadmap efforts are a sizeable endeavor when combined with the RTO’s day-to-day operations and multiyear effort to entirely replace its market platform.
“This is a big lift,” agreed Director Baljit Dail.
ST. PAUL, Minn. — MISO’s Steering Committee will reopen nominations for vice chair of its newly formed Energy Storage Task Force after initiating what stakeholders are calling a confusing elections process.
The move has opened discussions that could have implications for how the RTO nominates and elects individuals to fill stakeholder group leadership positions in the future.
In selecting leaders for the task force, MISO’s Steering Committee deviated from standard practice by administering separate elections for the positions of chair and vice chair. While votes for the chair are already in (with results still unannounced), the election of the vice chair is still pending.
Steering Committee Chair Tia Elliott said that both candidates for chair expressed an interest in running for vice chair if they weren’t picked for the top position. As a result, a nomination for vice chair was submitted after the deadline, leaving the Steering Committee to decide whether to include the late submission for voting.
During a Sept. 20 Steering Committee meeting, Vice Chair Audrey Penner suggested reopening the nomination process but including all previous nominations, a motion committee members backed by consent.
“That’s the only way I see getting around this confusion,” Penner said.
In explaining the reason for the split elections, Elliott said the Steering Committee is under pressure to produce stakeholder leadership for the task force so the group can begin work on pressing energy storage issues. MISO has already assigned Chief Compliance Officer Joseph Gardner to serve as liaison to the group, and stakeholder input is needed as the RTO begins to craft market rules and definitions to manage storage participation in the market. (See Progress Builds for MISO Energy Storage Effort.)
“There’s a push to get this off the ground,” Elliott said.
Some Steering Committee members asked who had the authority to separate the voting in the first place. Others said moving deadlines for late nominations could result in increased confusion during elections for other stakeholder committees.
Elliott said MISO staff and Steering Committee leaders decided to split the election, as the RTO’s Stakeholder Governance Guide is silent on the issue of moving election dates.
“That’s stepping way outside the governance guide. I’m concerned a decision like that has been made,” said Northern Indiana Public Service Co.’s Bill SeDoris.
“I made the decision. I will not apologize for that,” Elliott said, pointing to the scarcity of volunteers within the MISO stakeholder community to take on leadership positions.
“If we have a deadline, in fairness to the process, we need to stick by that date,” Penner said of the possibility of allowing a late nomination.
In response to a question by Ameren’s Ray McCausland about why the Steering Committee didn’t simultaneously solicit nominations for chair and vice chair, Elliott said nominations were held in conjunction, but elections were held separately.
“The way this ended up is a bit cumbersome,” McCausland said.
Elections for chair and vice chair for all MISO stakeholder committees and groups are held via electronic ballot among MISO members with voting rights.
The Steering Committee will next month explore possibly amending elections provisions in the Stakeholder Governance Guide, Elliott said. She asked stakeholders to email MISO’s stakeholder relations team with opinions on the subject. The committee will consider revising elections rules after reviewing responses and holding a discussion on the topic.
As I walk the halls of National Association of Utility Regulatory Commissioners meetings, I hear a lot about the “grid of the future” or “grid modernization.”
Thomas
According to the North Carolina Clean Energy Technology Center’s “The 50 States of Grid Modernization” report, more than 30 states are exploring “grid modernization” to various degrees. New York is knee-deep in Reforming the Energy Vision, Ohio is doing “Power Forward” and Illinois is pursuing “NextGrid.” These are all terrific initiatives, and these state’s utility commissions should be applauded for their efforts to proactively realize that the traditional electric utility service business model is changing and unless utilities and regulators get in front of certain issues, consumers will ultimately pay the price later.
These grid modernization efforts are driven by several factors that stem from technological innovations changing consumer needs for electricity in the face of aging infrastructure. While different states have different dynamics and different solutions, they are fundamentally addressing the same challenge. Fortunately, these challenging circumstances are leading to creative thinking and solutions that are more than just throwing money at the problem.
Changing Dynamics
Similar to these state-led efforts that focus on the retail electric delivery system, a parallel re-examination of our wholesale energy markets is long overdue. For a variety of reasons, the dynamics in our wholesale markets are changing. Flat peak consumer demand year over year, low-cost natural gas-fired generation, the proliferation of subsidized intermittent resources (with no fuel costs) and an increasingly flat supply stack, combined with market rules that have not kept pace, have all contributed to a wholesale power market in which units that produce relatively inexpensive power and are needed for reliability are in significant financial stress and at risk for closure.
Just last month, Energy Secretary Rick Perry recognized that the power industry “has experienced massive change in recent years, and government has failed to keep pace.” The much anticipated Department of Energy “Staff Report to the Secretary on Electricity Markets and Reliability” called for FERC and RTOs to reform market rules in order to promote grid resilience and proper energy price formation. In many respects, the DOE report recognizes that if certain low-cost plants do not receive proper price support in the current market, those plants will likely retire, leading to higher costs to consumers over the long term.
Energy price formation is not a new issue, and FERC has taken positive steps to improve it over the last several years. FERC, through Order 825, has made significant changes to the settlement of energy transactions and the triggers for scarcity pricing. PJM and the other RTOs are in the middle of implementing these reforms. While their impacts have yet to be realized, they nonetheless offer great promise.
Energy Price Formation 2.0
While the reforms to date have been important, it is time for the next step — Energy Price Formation 2.0, if you will. As a result of technological advances and current market conditions, PJM has a glut of units that participate in the market at roughly the same low price. LMP was developed based on a supply stack and a sloped supply curve, but today’s supply “stack” looks more like a flat piece of glass. In today’s market, new natural gas combined cycle plants, baseload coal plants and most nuclear plants can produce power at prices that by historical standards would be considered a bargain.
The fact that there is a bounty of low-cost resources available to meet demand means that prices will be less volatile and costs to consumers of electricity will be lower over time. The last two summers in PJM bear witness to the fact that high temperatures and higher-than-normal demand did not lead to significant upward pressure on electricity prices in PJM (see chart below).
| PJM
As a result of these current market conditions, it takes longer for those higher-cost peaking plants to be dispatched and set the energy price. While good for consumers at the present moment, if market rules are not altered, consumers will lose the benefits associated with the plethora of low-cost resources, as those resources will be forced out of the market because of insufficient revenues. In such a scenario, higher-cost resources will move closer to the front of the supply stack, run more often, set the clearing price at a higher level and cost consumers more over time.
Clock is Ticking
PJM has suggested a series of energy market reforms to allow consumers to continue to benefit from this abundance of low-cost resources. PJM has proposed that energy prices should be set by the units that are running to serve consumer needs and unit flexibility should be rewarded, not punished. The current rules do not do this and instead rely on out-of- market payments to specific operationally constrained, low-cost units that must run for reliability purposes. Ultimately, such a regulatory paradigm does not send the appropriate price signal to either the flexible or inflexible unit. While such a market design may have worked against an actual supply stack with material differences in price among resources, it falls short in the current “flat” market.
The wholesale power market of today is not that same as the wholesale power market of 10 years ago. To date, wholesale markets have delivered enormous value to consumers. In order for the value to continue for the next 10 years, regulators, consumers and other stakeholders need to recognize and respond to the changes that are already here. The clock is ticking. We all need to get to work.
Glen Thomas is president of PJM Power Providers Group (P3), which represents independent power producers.
AUSTIN, Texas — Renewable energy developers, energy providers, end users, renewable manufacturers and others gathered last week for the Infocast Texas Renewable Energy Summit, where attendees heard discussions on the challenges ERCOT faces in building transmission, adding renewable resources and ensuring grid reliability. Here’s some of the highlights.
No CREZ in Sight for Permian Basin’s Energy Production
A rebound in oil and gas production in West Texas’ Permian Basin has prompted a call for more transmission, but Texas is unlikely to repeat the $7 billion Competitive Renewable Energy Zone (CREZ) transmission investment, speakers said.
Midstream load has “come alive again” in the Permian, said Brad Schwarz, Hunt Power’s director of system planning. He said that has led to producers wanting to access the grid with “a significant amount of load” — 15 to 20 MW — within about a year.
“In an area that is typically not meant to serve that amount of load, just getting through ERCOT’s approval process will take that 12 to 18 months,” Schwarz said.
“Let’s say it does take 18 months [to plan a transmission line]. Those … companies can’t wait, so they’ll self-generate just to” be able to process and ship their output, said GridLiance’s Brian Gedrich, vice president for the independent transmission company’s South Central Region. “Once they’re self-sufficient, what’s the justification for building transmission? Building transmission may be the best answer, but is it the best answer for consumers when they’re already generating?”
Cratylus Advisors’ Mark Bruce, who is working with Pattern Development on its Southern Cross Transmission Project, noted the inconsistency between the legislative push behind the CREZ initiative and a similar effort to address the Permian Basin. The years-long CREZ effort resulted in the construction of 3,600 miles of transmission with capacity to deliver 18.5 GW of wind power across the state.
“The thing about CREZ that made it so special is the government said, ‘We will build it, and you will come.’ It provided a mechanism for parties that all had risk but couldn’t solve for that risk,” Bruce said.
“I find it interesting in Texas, where policymakers are allowed to make market judgements, the [Public Utility Commission] is tying its own hands to say we’re done with this CREZ stuff. There are mechanisms in place to address those timeline issues. If there were to be a planning process to serve this future generation in an economically viable way, to maximize [solar] generation and also benefit the oil and gas industry in the process, why wouldn’t you build it all?”
Bruce and Jeff Billo, ERCOT’s senior manager of transmission planning, agreed that with or without another CREZ-like development, ERCOT will continue to see growth in its solar power. The ISO currently has almost 1 GW of solar capacity, and the interconnection queue has more than 200 MW of planned capacity with signed agreements.
“The economics [for] solar transmission additions are much better than for wind,” Billo said. “There are a couple of reasons for that. Every day the sun is shining, it’ll be at its nameplate capacity. The dollars for congestion … add up quickly [for solar]. If you have a solar plant that’s constrained, it’s constrained every single day during peak demand. From a planning perspective, it’s easier to justify transmission for solar than wind.”
“Solar is going to start finding its way, as the economics are there,” Bruce said. “The real challenge is the market fundamentals aren’t moving, unless the gas price moves. If the fundamentals of the [generation] stack doesn’t shift, you’re going to see policymakers putting their thumbs on the market over the next six to eight months.”
Bruce said he was referring to efforts by NRG Energy and Calpine to persuade Texas regulators to “ratchet up” the effect of the operating reserve demand curve to push prices higher. Regulators could also adjust marginal loss calculations to harm remote wind and solar generation and help generation in load pockets, such as gas plants in the Houston area, he said.
Genscape’s Hudson Gilmer said RTOs are making a mistake by continuing to address new intermittent generation with traditional transmission solutions.
“It’s not an accident we continue to build transmission the way we have for the last 75 years. The planning process and the stakeholder process are designed to build more transmission,” he said. “The transmission planning hasn’t evolved [along with generation]. We’ve got to get smarter in planning for system growth. Other solutions, like dynamic line rates or convertors, are so much more effective than building CREZ like we did years ago.”
Billo said things are better than 2011 and 2012, when the fracking boom “sort of took everyone by surprise.”
“There are fundamental differences now in the time frame it takes to build transmission,” Billo said. “I give a lot of credit to the [transmission and distribution providers] out there. What we see today that we didn’t see five years ago is they have a lot better relationship with their customers that fosters communications that helps the planners and utilities … we’re a lot better off than we were.”
Texas PUC Commissioner Brandy Marty Marquez recalled when wind generation was limited to barren West Texas and the state legislature set a wind capacity goal of 2 GW.
“Looking back at the original goal … you might call it adorable,” Marquez said in her keynote address.
However, thanks to the CREZ and Texas’ insatiable demand for energy, ERCOT has almost 20 GW of wind energy at its disposal, some of which can now be found along the Gulf Coast.
“We’ve exceeded the capacity found in any other state, and almost every other country,” Marquez said. “It was a labor of love for our state.”
Marquez noted the transmission buildout has led to other benefits as well, pointing to more than 24,000 jobs the Department of Energy says the wind industry has created and $85 million in annual revenue to ranchers and farmers for turbine leases.
She said the PUC, like ERCOT, will remain fuel-neutral, however. “The market will drive the agenda and be the ultimate arbiter of fuel use,” Marquez said.
Garza: No ‘Price Collapse’ in ERCOT’s Market
Although ERCOT averaged real-time prices of only $24.62/MWh in 2016 — an 8% drop from the year before and the lowest since the nodal market’s implementation in 2010 — it’s incorrect to call it a “price collapse,” said Potomac Economics’ Beth Garza, who leads the ISO’s Independent Market Monitor. (See “IMM Offers Additional Suggestions to Improve Markets,” ERCOT Briefs.)
“I don’t believe [price collapse] is a fair and accurate assessment,” Garza said. “Prices are lower, but price collapse says they were unsupported at high levels somehow. It’s more a reflection of the conditions we have, [with] very low natural gas prices and the changing composition of the energy being produced.”
Garza noted wind energy accounted for 15% of ERCOT’s generation mix last year, a number that has jumped to 21% in the first half of 2017. The extra capacity and low prices masked the fact that ERCOT set a record for peak demand last summer. That was unlike 2011, when record heat led to large price spikes.
“Since 2011, we’ve seen over 17 GW [of new energy] come into the market, and with very few [fossil fuel] retirements,” said Filsinger Energy Partners’ Tim Wang said. “Last year, we had record heat and record peak demand, but prices stayed flat. That’s the state of the market right now. There’s plenty of capacity.”
That has caused problems for owners of uneconomic units, such as Dynegy. Though Tudor, Pickering, Holt & Co. analyst Neel Mitra has told investors he regards the company as one of the country’s top independent power producers, Dynegy has had problems selling its assets.
“Everything in ERCOT is up for sale right now,” Dynegy’s Bob Helton said.
“What’s your price, Bob?” Garza asked Helton.
“Apparently, it’s pretty high,” he responded with a laugh.
Helton said those economics are pushing owners of some aging plants to save money by reducing maintenance expenses. “You’re going to run it until it fails,” he said. “Do you announce a retirement before that happens, or do you have a major tube leak or something that requires a high-dollar investment?”
“A large amount of that [recent plant] construction took place at the turn of the century,” Garza said. “A lot of those units are about 15 years old. That’s half their expected life.”
“How do you get more money to the market?” Wang asked. “After 2011, there was a lot of conversation around resource adequacy and a capacity market. As the new capacity has come on, the market has responded with those low prices, and all that conversation has died down. To a certain extent, you have to be proactive. If it gets to the point where you have retirements, demand spikes and prices go up again, will the market respond to a one-year price cycle? Or will it return to its senses and say, ‘We did this before. We’re not going to do it again.’”
Conventional Generation Playing ‘Chicken,’ Trying to Hang on
With economic headwinds making it difficult to build conventional generation, Chad Blevins, a senior consultant for The Butler Firm, said owners of existing plants are holding on as long as they can. He pointed out that unless one works for the generation owners, it’s difficult to determine what their cash positions are.
“There’s a lot of games of chicken going on here between these utilities,” he said. “‘As long as we lose money while the other guys lose money, we’re good. If he goes under first, that will help lift up the market just enough so I’ll be good.’ They want to hang on as long as they can, so they have that physical option until the other guy pulls out of the market and they’re clearing at a better price.”
NRG’s Mark Walker, speaking on the same panel discussing investments in traditional generation, said there’s still a need in ERCOT for flexible resources that can supplement intermittent renewables. “Several projects are being delayed, but if we’re going to make some [market design] changes, now is a good time before we get to a crisis situation,” he said.
Walker also said that if ERCOT had a local reserve product, expensive efforts like the $590 million Houston Import Project might be avoidable.
“Right now, ERCOT only has one tool in its toolbox [to address local reliability], and that is building transmission,” he said. “Had we had a local reserve requirement in the Houston area, we might have had enough to avoid a project the size of that one.”
Technological Improvements Leading to more Efficient Renewables
A panel of wind energy developers discussing the forces driving their market agreed that the recent influx of wind has been driven by larger and more efficient turbines. Technological advances will continue their influence going forward, they said.
“Technology has definitely played a big role, and it’s going to play a larger role in opening up new areas,” said Phil Moore, vice president of development for Lincoln Clean Energy. “We’ve had a huge amount of transmission buildout in the last decade, but it’s going to be tougher going forward. Technology is going to have to bridge that gap in opening up less-than optimal areas.”
“The projects I’m seeing starting construction are in areas I never would have dreamed as being economical in ERCOT,” said Ward Marshall, Pattern Development’s senior director of business development. “Texas has been an unbelievable dumping ground of [federal tax credits]. A lot of projects have been built from that standpoint, but now we’re flooded with immense amounts of low-cost, cheap power.”
Marshall took the opportunity to plug Pattern’s Southern Cross project, saying it “will have some effect on draining the swamp.”
ERCOT’s Paul Wattles and the Sierra Club’s Cyrus Reed looked at demand growth in Texas through different lens colors during a discussion on behind-the-meter energy resources.
“Per capita load growth is flat, like it is everywhere,” said Wattles, the ISO’s senior analyst of market design. “Our growth is coming from the industrial sector and oil and gas growth in West Texas and the Gulf Coast. We’re going to continue to see load growth in ERCOT, but not necessarily [per capita growth] because — like the rest of world — we’re becoming more efficient.”
“We continue to get people moving in here, we continue to have housing starts of 100,000/year,” Reed said. “Sierra Club is pushing that building codes be solar friendly at the local level, so even if rate cases go the wrong way, there will be opportunity for growth.”
Of course, distributed energy resources present their own challenges. Wattles reminded attendees that ERCOT is continuing to map DER on the distribution system, so it can gain a better understanding of where they are.
“When you start seeing solar and storage together, you’re seeing a DER that can be dispatched,” he said. “We’re still a way away from that. The critical mass just isn’t there yet, but I think we have to be ready for it.”
“We’re in the early stages in Texas … of allowing distributed resources to get on the grid and grow, so we can have them available and start using them,” Sunrun’s Amy Heart said. “We’ve certainly seen Texas is not out of the ordinary. Let’s not stop a market in its tracks just when it’s getting its feet under it.”
Look no further than Ontario’s Independent Electricity System Operator (IESO), which has about 35 MW of DER connected to its grid. The ISO’s manager of generation procurement operations, Rob Sinclair, said because much of those DER are the result of power purchase agreements, it gives the Canadian grid operator more insight than its brethren.
“The advantage we have, because we contracted with a vast majority of these facilities, we know where they are and how they’re operating,” Sinclair said. “That gives us a bunch of insight, but there are still things we’re not fully aware of. We’re trying to understand how to modernize our tools to integrate those resources. We’re moving from a PPA framework to a net metering framework, so we’re just about to learn how net metering will work in our market.”
California’s scorching heat and soaring load pushed CAISO day-ahead energy prices to record highs in the second quarter after the ISO’s market mitigation measures unexpectedly failed.
CAISO’s Department of Market Monitoring (DMM) said it will investigate some of last quarter’s day-ahead market outcomes that may be rooted in a misalignment between software systems.
The Monitor raised concerns in its second-quarter report because energy prices increased even after undergoing mitigation. At one point in the midst of the heat wave, day-ahead prices exceeded $200/MWh during a five-hour period and pushed past $600/MWh in one hour.
“DMM expects that prices should generally not be significantly higher in the final market run than in the market power mitigation run,” the report says. “Both DMM and the ISO will continue to investigate this issue.”
On June 21, “the total bid in cost of energy in the binding pricing interval run was about $1 million higher than the as-bid cost before market power mitigation,” the Monitor said. “However, energy revenues were almost $25 million greater in the binding integrated forward market than in the market power mitigation run due to the magnified impact that higher prices have on the total market.”
One possible cause, which has been raised previously in stakeholder discussions: software differences between the market mitigation and the integrated forward market (IFM) runs, the latter of which is a fundamental CAISO market process that establishes exactly what generators will be needed to meet demand forecasts.
The two processes run independently of each other and produce separate results, or solutions, based on differing inputs, specifically because the mitigation run relies on mitigated bids that can produce a different dispatch order from the IFM.
“If it is determined that a software error resulted in erroneously high prices, DMM requests that the software error be resolved and that the ISO consider the possibility of price corrections,” the Monitor said in the report.
According to the report, CAISO has proposed two explanations for the deviation between the mitigation and IFM runs: differences in unit commitment due to the reduction in available bids (due to lower prices) in the market power mitigation run; and differences in the solution stemming from the independence of the market runs and solution error tolerance.
In the report, the Monitor recommends that the ISO study revisions to solution time and tolerances in the day-ahead market “given the substantial settlement impacts of this case.”
“DMM’s analysis indicates it is unlikely the differences are due to the impact of bid mitigation,” CAISO spokesman Steven Greenlee told RTO Insider. “DMM is asking the ISO to continue investigating the cause further in the event it is caused by a software or other issue that may have a significant impact on market results in the future.”
Greenlee also said that CAISO currently has no plans to issue price corrections until there is “conclusive” evidence of an error, noting that the ISO is “significantly beyond” the price corrections window.
As for the $25 million discrepancy, “DMM has not concluded this is an overpayment but believes the magnitude of this impact highlights the need to further investigate the cause of significantly higher prices in the market run compared to the market power mitigation run,” Greenlee said.
Hot Weather Drives Up Prices
Average day-ahead and 15-minute prices increased during every month in the second quarter, the report showed. Monthly average day-ahead prices rose from less than $23/MWh in March to about $34/MWh in June, caused by high temperatures and loads.
Aside from weather and load, congestion was high on the Path 26 transmission line, which links the Southern California Edison and Pacific Gas and Electric service areas. Price spikes — as high as $250/MWh in the five-minute market and a $750/MWh in the 15-minute market — also increased as a result of weather and the line restrictions. North-south congestion on Path 26 drove real-time congestion to its highest level since the 15-minute market became binding in 2014.
Solar output hit a new record in the second quarter, but higher system loads reduced the instances of negative pricing that accompanied solar surpluses in the first quarter. Real-time prices went negative during 15% of intervals during April, falling to under 6% in June, compared with about 22% of intervals in March.
| CAISO
Solar generation continued to grow on the system, reaching a record peak output of 9,914 MW on June 17. There were reduced curtailments in the second quarter despite a reduction in the power balance constraint tool for oversupply from 300 MW to 30 MW, effective April 11.
“During nearly all of the intervals in the second quarter when prices were negative, there were sufficient dispatchable market bids to resolve oversupply and the software did not have to relax the power balance constraint or curtail self-scheduled generation,” the report said.
EIM Members Fail Sufficiency Tests
In the Energy Imbalance Market (EIM) region comprising PacifiCorp East, NV Energy and Arizona Public Service, prices were often similar because of large transfer capacity and little congestion. There was some price separation in these balancing authority areas because one or more failed the flexible ramping sufficiency test, which limited transfers among them. EIM balancing areas continued to fail the upward and downward sufficiency tests “regularly” in the second quarter, the report said. “In particular, Puget Sound Energy failed the downward sufficiency test more frequently, during about 13% of hours, up from about 3% of hours in the previous quarter.”
EIM participants have discussed what they see as problems with the market’s resource sufficiency test stemming from shifting CAISO load forecasts. (See EIM Participants Seek Resource Test Tweaks.)
The ISO and PacifiCorp were exporters in the EIM during the quarter, while the other areas were mostly net importers, with the ISO’s largest exports occurring during solar-heavy hours.
The quarter also saw relatively high “bid cost recovery payments,” which ensure that resources scheduled in the market recover costs when the market does not provide sufficient revenues. Excessively high bid cost recovery payments can indicate that unit commitment or dispatch is inefficient, and the costs of the payments are allocated to market participants through uplift costs.
Those payments were estimated at about $28 million during the quarter, the highest since 2013, with much of that covering during several days in May. On May 3, the ISO declared a system emergency for the first time in nearly 10 years, and many committed units received payments higher than $50,000, the report said.
MISO will release results from its regional transmission overlay study by December — nearly two years ahead of schedule.
The RTO finished the overlay analysis earlier than the slated 2019 finish, citing the collapse of the Clean Power Plan as a factor in speeding up the process.
“Originally, we set aside three years,” said Lynn Hecker, MISO manager of expansion planning.
Hecker said MISO “no longer has the urgency of the Clean Power Plan,” so the more specific planning work of the study would become more protracted, broken up over MISO’s usual annual planning Transmission Expansion Plan studies. Furthermore, transmission issues gleaned from the overlays could inform specialized, targeted studies in the MTEP 18 planning cycle, she said.
MISO will generally “shift away” from studies that run three years to focus on one-year studies in order to provide detailed transmission needs instead of a “macro look,” Hecker said. However, the RTO learned “valuable” economic and reliability lessons from the overlay study, which was originally meant to inform long-term transmission planning as the resource mix shifts. The study created a possible transmission map — or overlay — for each of the three future scenarios in MTEP 17. (See MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’.)
A second round of preliminary overlay results using an existing fleet projection shows several 345-kV line additions in MISO Midwest, as well as a handful of 500-KV lines in — and one leading into — MISO South. The “policy regulations” future shows a bigger network of 345-kV lines in the Midwest region and multiple 500-kV lines in MISO South. One DC line would link South and Midwest while another would stretch from Arkansas to Iowa.
The “accelerated alternative technologies” future depicts a large network of 765-kV lines in the Central region, including two 765-kV paths connecting with South, and a DC line across North Dakota and Minnesota, in addition to the proliferation of lines in Midwest and South.
“Now that we’ve closed the books on the regional transmission overlay process, it’s time to take a closer look … to address targeted studies further and answer stakeholder questions,” Hecker said.
She said future targeted studies could be themed, focusing on transmission issues across seams, generation retirement impacts, increased distributed energy resources, grid stability in Minnesota and Wisconsin, renewable integration impacts and potential transmission to support “resilient” resources — a concept handed down by the recent Energy Department grid study and yet to be explored by MISO.
Several stakeholders balked at MISO’s mention of studies based on “resiliency,” but MISO Director of Policy Studies J.T. Smith assured attendees that the RTO and its stakeholders would together set out to define the concept in later public meetings.
“In the meantime, MISO will continue on the complicated process to improve the alignment of the project costs and benefits,” Hecker promised stakeholders during a Sept. 25 special conference call of MISO’s Economic Planning Users Group.
Some stakeholders asked why MISO did not consult its own generator interconnection queue to inform the overlays.
| MISO
Hecker said the RTO took “a much more forward-looking” approach, examining congestion 20 years out amid MISO’s shifting resource mix.
“We did a best guess of where generators will be sited in the future,” she said.
The study will not be used to justify projects in future MTEP cycles, which will still require the usual rigorous MTEP studies.
The overlays “will help us look at if what is needed in the short-term will be compatible with long-term needs,” Hecker said. “They’re multiple, long-term views of what transmission may be needed.”
Wind on the Wires’ Natalie McIntire noted that there are “several” lines that appear in all three preliminary overlays. She asked if MISO planned to use the recurring lines as part of a “no regrets” lineup of projects.
Hecker acknowledged the “commonalities” between overlays, but she said that MISO would not guarantee it would include the lines in a future list of recommended projects, despite their possible recurrence in future MTEP planning cycles.
