FERC last week conditionally accepted CAISO’s Tariff revisions covering how it calculates opportunity cost adders for use-limited resources, such as small hydroelectric projects.
The commission had ordered CAISO to make the changes in June after finding the way the ISO calculated opportunity costs would produce varying results, instructing it “to address this ambiguity.”
“We find that CAISO’s proposed revisions … largely comply with the commission’s directives,” the commission wrote in its Nov. 19 order (ER18-1169).
The 3-MW New Hogan Dam in Calaveras County, Calif. Small hydro facilities such as Hogan are automatically classified by CAISO as use-limited resources. | U.S. Army Corps of Engineers
However, the commission agreed with NRG Energy’s protest that the RTO needed to specify the gas-price indices it would use to calculate the adders and instructed the ISO to submit another compliance filing within 30 days.
The changes FERC accepted last week were the latest in a series of revisions related to CAISO’s Commitment Costs Enhancements initiative. As part of that initiative, the ISO has tried to revamp the way it compensates resources that have limits on the number of start-ups and runtime hours, or on energy output, over a certain period.
CAISO has contended the changes are needed because of the increase in variable energy resources on its system, making supply more unpredictable and use-limited resources necessary at any given time.
Because the ISO’s market optimization software makes unit commitment decisions only one day ahead, it cannot consider that dispatching a use-limited resource may hinder its ability to run later. As a result, the resources’ opportunity costs are not reflected in their offers. CAISO sought to change that.
However, FERC agreed with NRG’s protest at that time that argued against CAISO’s method for calculating opportunity costs. It ordered the ISO to submit a compliance filing that provided more specificity on calculation methods.
The commission’s Nov. 19 order conditionally approved that compliance filing, with the exception of NRG’s most recent protest.
The Trump administration on Friday quietly released a major report detailing the impact of climate change on the U.S., posing a stark contrast to the president’s rhetoric on the phenomenon and his inaction to address the problem.
The 1,656-page report is the second volume of the latest National Climate Assessment, the fourth released since Congress passed the Global Change Research Act of 1990. It was prepared by the U.S. Global Change Research Program, composed of representatives from 13 federal agencies, including EPA, the Department of Energy and the Department of the Interior. More than 300 experts, from both the public and private sectors, contributed to the report.
Climate change is leading to increasingly severe weather and disasters, including wildfires and flooding. The 2017 Tubbs Fire (left) caused an estimated $1.2 billion in damages and destroyed more than 5,000 structures, including 5% of the housing stock in Santa Rosa, Calif. Hurricane Harvey in 2017 caused widespread flooding and knocked out power to 300,000 customers in the area of Port Arthur, Texas (right). | U.S. Air National Guard
The first volume, released in October last year, focused on how human activity is causing changes to the planet and detailed the scientific evidence for the phenomenon. The second volume focuses on the effects of those changes.
“The impacts of climate change are already being felt in communities across the country,” the report begins. “More frequent and intense extreme weather and climate-related events, as well as changes in average climate conditions, are expected to continue to damage infrastructure, ecosystems and social systems that provide essential benefits to communities.”
Work on the fourth assessment began in the final days of Barack Obama’s presidency. Its release alone is significant in that it directly contradicts President Trump’s stance on climate change. But it also doesn’t appear to have been altered or edited in any way to downplay its findings, as some scientists had feared.
“This report makes it clear that climate change is not some problem in the distant future,” said Brenda Ekwurzel, the director of climate science for the Union of Concerned Scientists and one of the report’s authors. “It’s happening right now in every part of the country. When people say the wildfires, hurricanes and heat waves they’re experiencing are unlike anything they’ve seen before, there’s a reason for that, and it’s called climate change.”
Trump has repeatedly called climate change a hoax. Just two days before the report was released, he tweeted, “Brutal and extended cold blast could shatter ALL RECORDS. Whatever happened to global warming?”
“I’ve seen [the report], I’ve read some of it and it’s fine,” Trump told reporters outside the White House on Monday. “Yeah, I don’t believe it.”
“The report is largely based on the most extreme scenario, which contradicts long-established trends by assuming that, despite strong economic growth that would increase greenhouse gas emissions, there would be limited technology and innovation, and a rapidly expanding population,” White House Deputy Press Secretary Lindsay Walters said in a statement.
The 1990 law required the administration to prepare an assessment every four years. But the first assessment was not released until 2000, and the George W. Bush administration was sued for missing the deadline for the second, which was eventually released in 2009.
Impacts on the Energy Sector
The report consists of 29 chapters and five appendices. Twenty-five chapters focus on climate change’s impacts to a particular sector or region of the U.S.
Chapter 4 is entitled “Energy Supply, Delivery and Demand.”
Extreme weather and climate change can potentially impact all components of the nation’s energy system, from fuel (petroleum, coal and natural gas) production and distribution to electricity generation, transmission and demand. | Fourth National Climate Assessment Vol. 2
The energy sector “is projected to be increasingly threatened by more frequent and longer-lasting power outages affecting critical energy infrastructure and creating fuel availability and demand imbalances,” according to the report.
As with other sectors’ infrastructure, energy facilities across the U.S. are threatened, though in different ways depending on the region. Structures along the country’s coasts are threatened because of rising sea levels. Increased precipitation will lead to flooding in the Northeast and Midwest, while drought in the West will lead to lower snowpack levels and, thus, reduced hydroelectric capacity.
Perhaps the most unique challenge posed by climate change to the electricity industry, however, is a reduction in generation capacity for thermoelectric power plants, which rely on surface water for cooling.
“Most U.S. power plants, regardless of fuel source (for example, coal, natural gas, nuclear, concentrated solar and geothermal), rely on a steady supply of water for cooling, and operations are projected to be threatened when water availability decreases or water temperatures increase,” the report says. Some plants would potentially need to shut down until their water cools enough to comply with federal discharge temperature regulations.
Rising average temperatures and heat waves will also drastically increase electricity demand for cooling, leading to congestion on transmission and distribution lines and reducing their efficiency.
The reports notes that two major trends in the industry — increased reliance on natural gas and increasing penetration of renewables — provide diversity and flexibility. But reduced water availability will also affect fracking capability, as “during droughts, hydraulic fracturing and fuel refining operations will likely need alternative water supplies (such as brackish groundwater) or to shut down temporarily.”
It also notes that while most service interruptions are caused by transmission and distribution line outages, increased fuel supply disruptions could also affect reliability. “Coal facilities typically store enough fuel on-site to last for 30 days or more, but extreme cold can lead to frozen fuel stockpiles and disruptions in train deliveries,” the report says. “Capacity challenges on existing pipelines, combined with the difficulty in some areas of siting and constructing new natural gas pipelines, along with competing uses for natural gas such as for home heating, have created supply constraints in the past.”
County-level median projected increases in energy expenditures for average 2080-2099 impacts relative to no additional change in climate. | Fourth National Climate Assessment Vol. 2
Solutions
The last two chapters of the report are devoted to reducing risks through adaptation and emissions mitigation. Many of the measures spelled out are similar to those recommended by the U.N.’s Intergovernmental Panel on Climate Change in a report released last month, most notably by quickly reducing the use of coal for generation and drastically increasing renewables’ share of the generation mix. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
For the electricity industry, the report says infrastructure will need to be hardened against extreme weather by:
“adding natural or physical barriers to elevate, encapsulate, waterproof or protect equipment vulnerable to flooding;
reinforcing assets vulnerable to wind damage;
adding or improving cooling or ventilation equipment to improve system performance during drought or extreme heat conditions;
adding redundancy to increase a system’s resilience to disruptions; and
deploying distributed generation equipment (such as solar, fuel cells or small combined-heat-and-power generators), energy storage and microgrids with islanding capabilities (the ability to isolate a local, self-sufficient power grid during outages) to protect critical services from widespread outages.”
It also lauds energy efficiency as a means for controlling costs to consumers, which it says will inevitably rise from all the changes.
“The interdependence of critical infrastructure systems increases the importance of electricity resilience, as disruptions to energy services are projected to affect other sectors,” the report says. | Fourth National Climate Assessment Vol. 2
Like the IPCC, the report urges expediency.
“The current pace, scale and scope of efforts to improve energy system resilience are likely to be insufficient to fully meet the challenges presented by a changing climate and energy sector,” it says. “Without substantial and sustained mitigation efforts to reduce global greenhouse gas emissions, the need for adaptation and resilience investments to address the impacts of climate change on the energy sector is expected to increase if the most severe consequences are to be avoided in the long term.”
A new report released by the Wind Solar Alliance last week says full market participation for renewables will require revisions to electricity markets, particularly in MISO and PJM, that were not designed with widespread renewable deployment in mind.
Fenton wind farm near Chandler, Minn.
“We think it’s helpful to have a vision of where we see the market heading, even if we’re not going to get all these market changes right away,” said Rob Gramlich, founder and president of Grid Strategies, the consulting firm that authored the report. “It was gratifying to see the level of consensus between the wind and solar companies. We’ve never really had to opportunity to step back like this with the [number] of companies involved.”
The report says several market reforms aimed at incorporating renewable generation are needed to keep electricity reliable and affordable. Among the more than 30 market changes it recommends are:
Creating multiday forecasts for units;
Compensating reactive power;
Creating primary frequency response markets;
Pricing “inflexibility costs” of conventional generation;
Incentivizing better forecasting from renewable generators;
Allowing flexible resources to bid without market power mitigation; and
Furnishing contingency reserves to cover “abrupt” drops in renewable output.
The paper also calls for grid operators to relax a year-round capacity performance requirement and create seasonal capacity procurements while abandoning fuel security requirements unless they have been demonstrated to improve reliability or efficiency. The study says grid operators should also make sure “conventional generators are not awarded excess credit relative to renewable resources.”
“Many of the current market rules were originally designed and adopted in the 1990s and early 2000s, based on the grid operations protocols from earlier decades when the grid was dominated by large, slow-moving fossil-fired, nuclear and hydroelectric resources. There were few wind and solar generators, independent power producers and non-utility electricity purchasers,” the report said.
Modern grid response needs to be faster and cover more megawatts, and today’s technology is advanced enough to manage it, the report says, concluding that electricity grids need to be flexible, fair, geographically widespread and free of barriers for entry or exit. It also contends that markets should not inhibit the ability of states or other authorities to achieve energy-related policy goals.
Gramlich told RTO Insider there isn’t a specific timeline for implementing the changes, but some are timely because they are part of ongoing discussions about other market revisions. He noted statements of support released by other organizations as examples of “broad agreement” that might signal “some things can move forward relatively quickly.”
While the report did not directly address the current national focus on grid resilience, fuel security and unrecognized benefits of large, “baseload” coal and nuclear plants, Gramlich said that has “sidetracked” the discussion from addressing what needs to be done for the grid to handle the current influx of intermittent, seasonal resources and the additional growth that is coming in the future.
He noted that in MISO, the “renewable community” plans to analyze self-scheduling.
In PJM, recommendations to allow resources to avoid the minimum offer price rule (MOPR) through bilateral contracts and to abandon efforts to add a fuel-security component in the capacity market “are important and very timely,” he said, although he acknowledged they’re “also very controversial right now.”
“If you get the right prices during times of stress, maybe that’s all the compensation you need in order to get the resources the revenue they want,” he said.
Overall, he said RTOs should be “as broad as possible and as seamless as possible” to ensure that renewable generation — which is often sited in remote regions — can be delivered to load where it’s needed, though he noted that PJM and MISO are at the top of the list for geographic scope.
“They do pretty well on the geographic breadth score, but there are some seams issues they could work on,” Gramlich said, specifically noting the seam between MISO and SPP.
MISO: Working on it
MISO said several of the recommendations in the report are already under evaluation by staff and stakeholders.
“MISO is still reviewing the report — so we can’t speak to its conclusions at a detailed level. However, we generally see this report as an affirmation of the major themes we’ve been working on and talking about with stakeholders for over the last decade,” spokesperson Mark Brown said in an email to RTO Insider.
The RTO said it has already rolled out new market designs, including extended LMP, ramping products and a new emergency pricing structure.
“MISO continues to assess new products and designs to get ahead of the evolving needs of the system,” Brown said.
It pointed out that it has already successfully integrated more than 18 GW of wind capacity and more than 300 MW of solar capacity.
“Wind and solar resources make up about 11% of MISO’s total market capacity. Based on the ongoing discussions, MISO plans to publish a long-term market strategy report next year with key recommendations for accommodating these long-term trends,” Brown continued.
MISO is currently in discussions with stakeholders about what market reforms are needed to address the growing mismatch between its changing resource availability and demand. The RTO has decided to separate solutions into the near and long terms, hoping to free up an additional 5 to 10 GW of supply through stricter outage and load-modifying resource rules, giving itself time to come up with bigger solutions. (See MISO Pivots to Near-term Resource Availability Fixes.) The long-term solutions discussion has already included the prospects for a seasonal capacity market and multiday forecasts.
MISO’s ongoing renewable integration impact assessment recently found the system will need significant upgrades at a 40% renewables penetration. (See Study: MISO Grid Needs Work at 40% Renewables.)
Conclusions ‘Consistent’ with PJM goals
In an emailed statement, PJM called the report “thoughtful” and said its conclusions “are consistent with PJM’s priorities.” The RTO pointed to its Extended Resource Carve-out proposal for revising its capacity market as an example of respecting state policy choices “while affording a level playing field where renewables and other competitive resources can thrive.” (See PJM Stakeholders Hold Their Lines in Capacity Battle.)
“PJM shares the alliance’s goals of reducing barriers to entry, properly pricing resources for their reliability and other valued attributes, and allowing the wholesale electricity markets to facilitate competition on a fuel-neutral, technology-agnostic basis,” the RTO said. “We continue to seek refinements of our energy market and ancillary services market rules to properly compensate generation sources for the services they provide.
“PJM looks forward to engaging with the Wind Solar Alliance and other stakeholders, including state regulators, renewable resource owners and consumer advocates, on proposals that will help us to maintain and improve PJM’s wholesale electricity market,” the RTO said. “We believe that the markets can provide far-reaching, regional solutions by pricing attributes and incenting the competition and innovation that have already helped achieve a cleaner, more reliable, less expensive system.”
Some of the recommendations tied in with existing stakeholder processes in PJM. For example, the Primary Frequency Response Senior Task Force has been working on revising primary frequency response requirements and measurement standards, as well as considering whether units should be compensated for the service. (See “Primary Frequency Response Moving Forward,” PJM Operating Committee Briefs: Nov. 6, 2018.)
Gramlich acknowledged that MISO and PJM have made progress toward the recommendations “in some cases,” but said “there are some other areas … where we have some concerns.”
MISO’s reliability is unlikely to be hampered by gas supply issues, as there is only a very small chance a large natural gas pipeline serving the grid could be affected by fuel delivery issues, according to a recent study from the RTO.
MISO said that at any given time it faces up to a 2% probability of a fuel disruption event in any given 1-mile section of an interstate pipeline. Of 35 MISO-area pipelines that have experienced events, about 80% have a 0.2% or less chance of an event occurring in any 1-mile section.
Vector Pipeline | DTE Energy
Gas generation outages stemming from fuel delivery issues would be 915 MW at most in any operating hour, the RTO said. It also found fuel delivery disruptions reported by gas generators are not usually related to unplanned pipeline outages.
The RTO will not publicly release detailed study findings because they identify specific pipelines.
MISO performed the in-depth assessment to determine whether its previous examinations of pipeline infrastructure failed to foresee additional risks because of physical disruption, but it said the study didn’t produce any new concerns.
“Over the past four years, MISO has not found any significant reliability impacts in its assessment of gas-related contingencies. … MISO has found little historical evidence, nor additional contingency risks that are greater than what is currently being evaluated,” the RTO said.
Earlier this year, MISO pushed back on a NERC report that said two areas in the RTO would “experience transmission challenges during an extreme event” involving a disruption of natural gas delivery. The RTO said the study failed to account for gas-fired generators’ access to alternative fuel sources. (See MISO Rebuts NERC Findings on Gas Risks.)
MISO successfully managed an uneventful October that went from unseasonably warm to unusually chilly.
Demand peaked at 96.4 GW on Oct. 3 during an early month heat wave, while average load was 71.5 GW, up from 70 GW a year earlier. However, the average systemwide temperature was 3 degrees Fahrenheit lower than in October 2017. MISO did not call any maximum generation actions during the month.
Executive Director of Market Operations Shawn McFarlane told an Informational Forum on Nov. 15 that the month began with the RTO managing warmer-than-usual weather, though it quickly transitioned to cold weather. He remarked that it seemed like Indianapolis transitioned directly from winter to summer this year and said the inverse appeared to be happening for fall in the Midwest.
Energy prices in MISO averaged $30.67/MWh for the month, up 15% from October 2017’s average of $26.68. Day-ahead and real-time peaks averaged $38.58/MWh and $34.80/MWh, respectively, while off-peak averaged $27.54 and $26.62. The RTO said its natural gas prices increased 16% year over year to about $3.25/MMBtu.
MISO October RT dispatched fuel mix | MISO
In real time, the RTO on average dispatched a fuel mix consisting of 46.6% coal, 23.8% natural gas, 14.5% nuclear and 9.5% wind. The remainder came from dual-fuel units, solar, hydro and waste-to-energy. Wind output peaked at 14.6 GW, higher than last October’s peak of 14.1 GW.
FERC rejected a request to order CAISO to develop a capacity market to ensure traditional independent generators remain financially stable as renewable energy prices continue to fall and drive down wholesale electricity prices.
“As CAISO and several protesters correctly observe, the commission has not required a centralized capacity market as part of a just and reasonable market design,” the commission said in its Nov. 19 order (EL18-177). “Indeed, the commission has consistently rejected a one-size-fits-all approach to resource adequacy in the various RTOs/ISOs due, in large part, to significant differences between each region and also due to the well-established tenet that there can be more than one just and reasonable rate.”
The request was made by CXA La Paloma, the operator of a 1,124-MW gas-fired plant in Kern County, Calif., which began commercial operations in January 2003. It was acquired by its current owner in a bankruptcy proceeding in December 2017. When La Paloma filed for bankruptcy, it cited $524 million in debt and an “inhospitable regulatory environment.” (See CAISO Proposal Would Permit Economic Outages.)
FERC denied a complaint by CXA La Paloma, owner of a natural gas plant in Kern County, alleging CAISO had facilitated an unjust market by failing to develop centralized capacity procurement. | Kern County, California Public Health Services Department
In June 2016, prior to the bankruptcy, the plant’s then-owner, La Paloma Generating Co., filed a complaint with FERC over CAISO’s denial of a request for an outage for economic reasons. The commission rejected the complaint, finding the ISO had administered its Tariff properly when it denied the outage request.
In its complaint filed in June 2018, CXA La Paloma argued “that regulation of the wholesale power market in California is fragmented and compartmentalized, and that in failing to develop centralized capacity procurement, CAISO has facilitated an unduly discriminatory, unjust and unreasonable market design that is harmful to both market participants and ratepayers,” according to FERC.
But the commission cited a recent MISO case in which they rejected a mandatory centralized capacity market, “despite low capacity prices and concerns that the existing construct was failing to ensure the availability of generation needed for reliability.”
“The commission also recently accepted a proposal for a resource adequacy construct in SPP based on bilateral contracting,” it noted.
“While the commission has opined on the benefits of specific features of the eastern RTO/ISO centralized capacity markets within the context of those specific regions and market designs, the commission has not imposed a centralized capacity market in an RTO/ISO or found that it is the only just and reasonable resource adequacy construct to attract and retain sufficient capacity. With respect to the eastern RTOs, the capacity markets originated through Section 205 filings or developed through settlements.
“Thus, we find that CXA La Paloma’s reliance on commission precedent pertaining to the eastern centralized capacity markets is inapt here.”
Dominion Energy has inched closer to the finish line in a two-year marathon to win state-subsidized energy contracts for its Millstone nuclear plant in Connecticut.
The state’s Public Utilities Regulatory Authority issued a draft decision Nov. 16 (Case 18-05-04) categorizing the 2,111-MW plant as “an existing resource at risk for retirement” without ratepayer support, which would allow it to qualify for special consideration in the state’s solicitation for up to 12 million MWh of zero-carbon electric power. Resources deemed to be at risk have their bids considered in terms of environmental and grid reliability benefits, as well as price.
Millstone’s retirement would not trigger need for new capacity in Connecticut, but it would for new generation capacity in New England as a whole. | Dominion Energy
The PURA said it will accept comments on the draft decision until Nov. 27, hear oral arguments at its headquarters on Dec. 21 and likely issue a final decision Jan. 2, 2019. The plant in Waterford, on Long Island Sound, supplies approximately 45% of the state’s electricity.
ClearView Energy Partners estimates a 75% probability that state regulators will include Millstone’s capacity in its zero-carbon procurements, likely limiting the award to no more than half the plant’s annual generation.
Ken Holt, Millstone’s communications manager, told RTO Insider that the PURA had been given access to the company’s confidential information, done its own analysis and concluded that Millstone is at risk. He said Dominion is now focused on the zero-carbon procurement by the state’s Department of Energy and Environmental Protection.
“We made numerous offers that would both ensure Millstone’s continued operations and provide benefits to Connecticut ratepayers ranging from the hundreds of millions of dollars to billions of dollars,” Holt said.
Gimme Shelter
Dominion has been following the lead of Exelon, which secured state subsidies for its nuclear plants in Illinois and New York after their profit margins started slipping in competition against low-priced natural gas.
Last year Dominion sought similar legislation in Connecticut, but the General Assembly failed to pass it, prompting Gov. Dannel Malloy that year to order both the DEEP and PURA to assess the viability of the Millstone plant and determine whether the state should provide financial support.
The agencies in January issued a report on the current and projected economic viability of Millstone and signaled support for state procurement of its output under a program reserved for renewable resources such as large-scale hydropower, wind and solar. (See Conn. Regulators Signal Support for Millstone.)
Given the record of opposition to that move by consumer groups and non-renewable resource owners, it is not clear what new information the PURA expects to hear between now and January to justify its decision.
Millstone reactor unit | Dominion Energy
The DEEP last month issued its final determination on six projects selected for its January request for proposals for Class I renewable energy sources, including one offshore wind project, one anaerobic digestion project, three fuel cell projects and one fuel cell project with combined heat and power.
According to the department, the selected projects total 254 MW and 1,285,360 MWh/year, equal to 4.7% of the state’s load, with a levelized 2018 constant dollar load-weighted average price of $80.04/MWh for energy plus renewable energy credits.
Winners among the approximately 100 projects that responded to Connecticut’s zero-carbon RFP must enter power purchase agreements with either of the state’s two leading utilities, Eversource Energy and United Illuminating.
Class Act
In written comments filed with the PURA last year, Eversource contended that Millstone is neither a Class I, II nor III renewable resource and “cannot simultaneously be a competitive merchant generator and receive state-sponsored financial support.” The utility argued that any financial remedy “should be based on cost-of-service principles with correspondingly limited returns on equity to reflect the reduction in risk resulting from Millstone’s receipt of state financial support that is unavailable to other non-renewable merchant generators.”
Under Connecticut’s renewable portfolio standard, Class I represents resources such as solar, wind, geothermal, biogas, sustainable biomass, and wave or tidal power, as well as run-of-river hydropower facilities not exceeding 30 MW in capacity. Class II resources include trash-to-energy facilities that have obtained required permits, while Class III covers customer-side CHP systems, electricity conservation and load management programs, and systems that recover waste heat or pressure from commercial and industrial processes.
Emissions Costs
The DEEP’s analysis showed that while Millstone’s retirement would not trigger a need for new capacity in Connecticut specifically, it would for new generation capacity in New England as a whole. Replacement capacity procured through ISO-NE would likely be gas-fired, exacerbating security and system reliability issues because of the region’s heavy reliance on gas for power generation.
If Millstone’s two units stopped operating, CO2 emissions for the entire New England electric sector would increase by 80 million short tons, or 25%, through 2035, according to the department. Replacing at least 25% of Millstone’s output with hydropower, demand reduction, energy storage and zero-emission renewable energy would be necessary for Connecticut to achieve its statutory greenhouse gas emissions-reduction targets, costing the state’s ratepayers an estimated $1.8 billion, the department said.
Even with that investment, regional emissions would increase by 20%. Replacing 100% of Millstone’s output with zero-carbon resources would cost Connecticut ratepayers approximately $5.5 billion, the DEEP said.
CARMEL, Ind. — MISO’s membership has elected to keep Directors Phyllis Currie and Mark Johnson while also approving the somewhat controversial installment of current Minnesota Public Utilities Commission Chair Nancy Lange.
MISO Senior Vice President and Board Secretary Stephen Kozey announced the Board of Directors elections results at a Nov. 15 Informational Forum. Voting opened Sept. 27 and concluded Nov. 2.
Each candidate received a majority of membership votes, the RTO revealed. Kozey said the eballot performed “soundly” with no outages from election vendor VoteNet.
“It was not hacked,” Kozey joked, a tongue-in-cheek reference to the recent fear of cyberattacks on the midterm elections.
Kozey said 96 of 139 members voted, well above the 35-member quorum required.
Members voted Lange to the board despite concern by some stakeholders over a sitting commissioner being appointed to the oversight body. Stakeholders said MISO should consider requiring the same one-year moratorium for regulators in the RTO’s states that it requires of directors coming from member companies. MISO’s bylaws require a yearlong cooling period for “directors, officers or employees of a member, user or an affiliate of a member or user.” (See MISO Members Uneasy over Board Nomination.)
This is the first time the RTO has elected either a sitting commissioner or a commissioner from one of the states in its footprint to the board.
Stakeholders noted that Lange made decisions about the grid on behalf of Minnesota customers and utilities up until her election.
Lange will fill the seat vacated by retiring Director Michael Curran, who has served on MISO’s board since 2007. The trio will begin their three-year terms on Jan. 1. Lange’s term at the Minnesota commission doesn’t expire until Jan. 7. Kozey has said Lange will avoid overlap by resigning her post at the regulatory agency early.
Kozey said MISO has requested that its board address whether the moratorium should apply to regulators.
“Because of the issue raised by stakeholders, we’ve asked the Corporate Governance and Strategic Planning Committee [of the Board of Directors] that the applicability of the stay-out be an item that they address,” Kozey said.
The RTO’s Advisory Committee will also discuss the issue at its Dec. 6 meeting during Board Week.
In a release, CEO John Bear said MISO is “fortunate to have an exceptional depth of experience across our Board of Directors.”
After reporting on election results, Kozey announced that he would be retiring from MISO by the end of the year.
“Thank you for putting up with me and my attempts at humor over the years,” Kozey said, choking up. Kozey was one of the RTO’s 21 original employees in 2000. (See “MISO Looks Back at 15,” MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.) Kozey founded the RTO’s legal department 18 years ago and served as chief legal officer until 2016.
“We have accomplished so much together, and we are now at a good point for me to transition to retirement. I will miss MISO, the people and working with all of our members, but after a fulfilling and satisfying career, it is time to think about the next stage of my life. I can leave the RTO without hesitation that we have the right leadership in place to take this organization into the future,” Kozey said later in a press release.
MISO said it has a succession plan in place and will announce Kozey’s successor later.
ORLANDO, Fla. — The National Association of Regulatory Utility Commissioners’ annual meeting attracted about 1,000 regulators, industry representatives, consumer advocates and other stakeholders.
Attendees participated in discussions on the energy-water nexus, physical and cyber challenges to the nation’s critical infrastructure and EPA’s Affordable Clean Energy Rule proposed in August.
PJM CEO Andy Ott referred to his RTO as a “referee,” balancing resource adequacy requirements with other states’ integrated resource plans.
“Somebody has to step up and say there’s a cost shift here, and unfortunately, now that seems to fall on us,” Ott said. “The big debate is when you start to have competitive states take action to preserve competitive generation or favor certain generation, the crowd on the other side says, ‘Hey, I’m putting my money at risk. It’s unfair.’
“One of the big disappointments of the past year was our proposal to accommodate states and still have competition and integrity in the market. Folks are taking that proposal as being against green, anti-environmental, which is absolutely not the case. We’ve got to create a balance and make sure states’ interests are accommodated or respected.”
“We’re policy takers, not policymakers,” MISO COO Clair Moeller said. “All of the states maintain their statutory obligation to resource adequacy.”
Moeller said MISO’s problems are different from PJM’s because MISO’s residual capacity market is less volatile.
“The economics are between the asset owner and the regulator, predominantly,” he said. “The policy of whether we retire this coal plant or don’t is policy-driven. The predictability of those retirements is better because of that regulatory compact. It’s less volatile on the capacity side because the states maintain that obligation. Our obligation is to maintain the assets people bring to the market.”
Kathleen Spees, a principal with The Brattle Group, said she saw another mission for grid operators: help the states achieve their policy objectives.
“First and foremost is a carbon-free policy. Every decision the markets make helps or doesn’t help the state meet those goals,” Spees said, referring to Moeller’s comment on RTOs being policy takers. “I didn’t hear a solution for how you guys can use the markets to achieve the states’ objectives. Markets have proven to be really effective in achieving reliability.”
“We had a successful tranche of transmission construction to accommodate renewable portfolio standards,” Moeller said. “No one should confuse the construction to achieve those standards with what got built. What got built was to achieve the economic goals of those states. We’re charged with doing things in the public interest. It’s not up to us to pick between generation owners and the states. It’s up to us to decide this is the best path forward in the consumers’ interest.”
“We’ve tried to ensure we’re not putting up barriers to what state policies are trying to achieve,” said Anne George, ISO-NE’s vice president of external affairs. “The states have seen a lot of their environmental policies achieve what they were hoping to achieve. Because they had success, now we’re looking at more aggressive targets. They’re taking actions to move forward. Our job is to look at the marketplace and see how we have the market facilitate what the states are looking to achieve, and to see that others’ part of that regulatory compact have the revenues to provide reliability to the region.”
In the end, Ott said, maintaining confidence in the markets is the best way to ensure open competition.
“If we can’t have a viable market, then Plan B is to flip back to something like competitive procurement, where it’s almost like a synthetic reregulation at a regional level,” he said.
Panel: Flexible Resources not Being Fully Used
Speaking on a panel on flexible resources, Grid Strategies Vice President Michael Goggin said grid operators are not benefiting from all the capabilities renewable energy and distributed generation offer. Were RTOs to remove barriers to full market participation, he said, flexible resources would be able to provide ancillary services and operating reserves.
“All U.S. ISOs have rules that are either directly or indirectly preventing wind and solar from providing services they never thought they were capable of doing,” Goggin said. “Capacity markets are not ideal for bringing out the best of these resources. They’re focused on megawatts, not procuring flexibility. Real-time incentives, through operating reserves and ancillary services and energy markets, provide a much better way of procuring that service when it’s needed. Self-scheduled resources aren’t fully participating in the centralized dispatch, an impediment to bringing about the full capability of these resources.”
David Nemtzow, director of the Department of Energy’s Building Technologies Office, suggested buildings provide another resource that can be tapped. He noted there are 124 million buildings, 118 million of which are homes, in the U.S. They account for 40% of the country’s energy usage, at a cost of $380 billion per year.
“Buildings are an integral part of the electric system. The challenge is to make them flexible without any degradation of the services they provide,” Nemtzow said. In addition to reducing demand through LED lighting and sophisticated sensors that adapt cooling/heating systems and lighting to the number of people present, buildings can be “interoperable, integrated systems … that are grid-responsive,” he said.
“Buildings can signal the utilities, so when the system is stressed or needs resources, a signal can be sent to the building owner or operator and they can make voluntary decisions and participate with the grid,” Nemtzow said.
Ric O’Connell, executive director of GridLab, said the two most significant trends he sees in the industry are the adoption of large, central renewable generation by utilities and policymakers, and the adoption of distributed energy resources by customers.
“The real question is, how do these two major changes interact?” he said. “Do they complement each other, or do they frustrate each other?”
Answering his own question, O’Connell cited a paper he recently published that found the two trends do complement each other. “Part of that is because DERs add flexibility to the grid and enable the addition of more renewables,” he said.
“On a utility-scale system, think of wind and solar as must-take. Sometimes, the rest of the system needs to be there for them. DERs are that thing your system operators are constantly grumbling about. This technology isn’t actually that new. We’re just allowing these resources to expose these characteristics.”
O’Connell referred to Minnesota, where he said modeling revealed that DERs’ flexibility is key to unlocking higher renewable penetrations, and that limiting DERs would dramatically increase the cost to decarbonize the system. “We have to start thinking about how we connect these new technologies,” he said.
Minnesota Public Utilities Commission Chair Nancy Lange, speaking on a separate panel, said the state is doing just that.
Quoting Wayne Gretzky’s strategy of skating to where the puck will be, not where it’s been, Lange said that in distribution planning, the commission thinks it knows where the puck is going.
“We have 4,500 [electric vehicles] in Minnesota. Are we going to have 10,000 in a year, or 7,000 in a year, or 20,000?” she asked. “Those are some of the skate-to-where-the-puck-is-going questions.”
Commissioners Share Their Market Concerns
During an Electricity Committee devoted to market issues, Western regulators shared with their peers the latest developments in the Western Interconnection: CAISO’s expansion of its real-time balancing market; CAISO’s and SPP’s offerings of reliability coordination services as Peak Reliability enters its last year of business; and SPP’s life-support effort to integrate some of the Mountain West Transmission Group.
Utah Public Service Commissioner David Clark quoted NERC CEO Jim Robb, the former Western Electricity Coordinating Council CEO: “The transition that will occur in reliability coordination services in the West is the single most important reliability coordination effort facing the U.S. in the next two years. We have our eye carefully on this transition process.”
Clark said Western states outside of California are concerned about CAISO’s “further extension” of market services.
“The principal challenge for many is the area of governance,” he said. “In Utah, we have a great desire to retain our self-determination, with respect to our energy policy. If we ever become involved in a market being served by vertically integrated utilities, we would want a voice in the government. We would want the operations of that market to be transparent.”
“There’s still skepticism with states and utilities in the West when it comes to take that step to join an RTO,” New Mexico Public Regulation Commissioner Cynthia Hall said. “There’s a growing concern relative to the problems created by seams issues. There’s a reticence to becoming a[n RTO] member. The reasons are multiple, not the least of which is if they have to pay to play — they would have to pay a greenhouse gas adder in California.”
Illinois Commerce Commissioner John Rosales discussed his problems with PJM’s capacity market construct, which he said has succeeded in lowering wholesale prices and the cost of operating reserves.
“What’s been somewhat contentious are the parts that don’t work well, which is pretty much everything else,” he said. “For me, it’s inherently flawed and extremely complex. The capacity construct is constantly being revised. … There have been well over 30 revisions, which becomes very frustrating for the states. We don’t call it a market, because there are so many features that are administratively determined … price caps, the cost of new energy fluctuates, performance requirements. Most of us agree that generally, this construct fails to send the proper price signals to ensure the proper fuel mix.”
Competitive markets have a supporter in Michigan Public Service Commission Chair Sally Talberg, who said, “Whether deregulated or fully regulated or something in between … at the end of the day, we want affordable, reliable service. We all have a common goal in fostering those competitive environments. I feel like we’re dancing around with a patchwork of dos and don’ts at the state level, and that creates uncertainty.”
Indiana Utility Regulatory Commissioner Sarah Freeman said her concern is with a rapidly changing fuel mix. She said her state expects four coal-fired units to retire by 2023, and she noted there are no new builds on the horizon.
“If it’s happening in Indiana, it’s happening bigger and faster somewhere else,” she said. “Once RTOs become involved, we need to maximize our cooperation and avoid any protectionist tendencies we have.”
Seams issues topped Illinois Commissioner Sadzi Oliva’s lists of concerns. She said market inefficiencies show up on the seam, “typically as a result of incompatible market rules.”
“This increases the ultimate cost to the ratepayers,” Oliva said. “The seam between MISO and SPP will be the concern for the majority of us. Illinois’ concern is receiving an unwarranted cost allocation.”
Amid an uptick in spending on transmission infrastructure that has attracted increased scrutiny from those paying the bills, customers and developers met Thursday for a workshop on how to get to the grid of the future.
The Department of Energy convened the daylong session at the National Rural Electric Cooperative Association’s conference center in Arlington, Va., to gather information for the department’s 2019 electric transmission congestion study.
Tatum wasn’t alone in his call for transparency. Traci Bone, an attorney with the California Public Utilities Commission, took issue with transmission projects that receive little or no RTO review. Known as supplemental projects in PJM, they are usually developed by incumbent transmission owners within their own zones to address their own planning criteria. (See FERC Upholds PJM TOs’ Supplemental Project Rules.)
She noted FERC’s rejection in September of a complaint by the CPUC and others who argued that Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
It’s “very concerning” that FERC has taken “such divergent views” from ratepayers, she said.
During audience questions following Bone’s panel, Exelon’s David Weaver criticized it as “a very one-sided panel” and said the decision to spend on resilience and security upgrades is not as straightforward as addressing reliability criteria.
“I think it can be perceived that wrong investments are being made,” he said.
“Not so much that they’re making the wrong investments, but we don’t know what investments they’re making,” Bone responded. “We need to have a say in that.”
LS Power’s Sharon Segner, who was also on the panel, argued for increased competition for transmission projects. Following a stakeholder campaign led in part by Segner earlier this year, PJM has begun considering developers’ cost-containment guarantees as part of its analysis of competitive transmission proposals. (See Cost Containment Clears MC Vote Despite PJM Plea.)
Segner noted that eight states — North Dakota, South Dakota, Minnesota, Oklahoma, Nebraska, Alabama, North Carolina and Indiana — have passed right of first refusal laws “to thwart Order 1000” and FERC’s efforts to introduce competition. Order 1000 eliminated ROFRs from FERC-approved tariffs and agreements, but the commission says it is powerless to block states from enacting such laws to protect incumbents’ monopolies.
Public Engagement
The workshop also looked at the importance of public engagement in getting large interregional projects completed. Dan Belin, of engineering firm Ecology & Environment, compared the permitting processes of the Great Northern Transmission Line — to link Minnesota with Manitoba’s hydro resources — and Northern Pass, which would have delivered Quebec hydropower into New England.
Great Northern “had a very robust public-involvement program” that included engagement with the Minnesota Department of Commerce prior to submitting its application, Belin said. The project was approved within the state Public Utilities Commission’s statutory 15-month timeline.
Northern Pass held no meetings prior to submitting its application. The filing attracted 9,000 public comments, and the seven-year review eventually ended in rejection by New Hampshire.
“That significantly draws out the process,” Belin said. “The public involvement piece was a big differentiator between the two projects.”
“What we saw in Minnesota is not typical and it should be more typical,” said Rich Sedano, president of the Regulatory Assistance Project.
He described transmission development as “a public process that is largely shielded from the public” and advocated for improving transparency and public engagement. The process should also remain within state authority, and the industry should “accept the stress it’s going to cause,” he said.
Bess Gorman, assistant general counsel with National Grid, suggested involving the public in the tangible benefits of projects, such as finding ways to include them in benefiting from cost savings.
“As much as you can do,” she said of the need for public engagement. “That’s how you’re going to get the project through.”
Rob Gramlich, president of consulting firm Grid Strategies, credited transmission expansions such as MISO’s multi-value projects, highway/byway projects in SPP and ERCOT’s Competitive Renewable Energy Zones with precipitating the growth in renewables.
“I don’t think we would have half of the wind industry that we have without these plans in the middle of the country,” he said.
Culture Change
Others discussed difficulties winning approval for interregional projects. EDF Renewables’ Omar Martino described a “quadruple hurdle” for one project that required satisfying individual criteria of MISO and SPP and their mutual criteria in addition to securing local approval. The host utility vetoed the project, he said, because it preferred to use an operating guide.
“Something is just not right,” he said. “There’s a gap that needs to be fixed.”
He and others called for culture changes at decisional bodies throughout the process.
“You have to create these programs … inside utilities, inside the RTOs. You also have to have the right culture, the right leadership, the right guidance,” he said.
Gramlich said “the concepts are generally in Order 1000” for interregional planning, “but it didn’t get the job done,” and decisions since then have “weakened” it.
“Nobody wants to pay for something they don’t benefit from, so there’s a healthy skepticism in the RTO process,” he said.
On Nov. 9, the Governors’ Wind and Solar Energy Coalition wrote a letter to FERC advocating for unifying the Eastern, Western and Texas interconnections via ultra-high-voltage lines. The coalition, which includes 19 state governors, compared the proposal to creating the nation’s interstate highway system 60 years ago and the $315 billion grid China is building today.
The coalition cited a study by Iowa State University that estimated the impact of two transmission expansion scenarios: a $40 billion investment in transmission that could allow renewable penetration to rise to 40% nationwide, and an $80 billion investment that could push renewables to 50%.
Cost Allocation
Determining how much transmission is needed and who’s going to pay for it are also obstacles to such ambitious proposals.
In the first morning panel, PJM’s Ken Seiler said that reliability has vastly increased from earlier in his career when “we were hanging on by our fingertips” daily during late-afternoon summer peaks.
Tatum, who shared the panel with Seiler, agreed that there’s no clear measure to “know if we’re over- or under-building” the grid. But he said that it is clear that developers are now making up for a “dearth of investment” in previous years. He noted that PJM is on track to add $7 billion to its Regional Transmission Expansion Plan this year, which would be the biggest addition in the plan’s history.
And then there’s the question of who picks up what portion of the tab.
“Everything goes really, really well until you get in to the concept of cost allocation,” Seiler said. “Once you start talking about money … that’s when the discussion gets really, really tough.”
Participants and audience members cited several examples of cost allocation fights, notably the ongoing debate over the Artificial Island project, PJM’s first competitive project under Order 1000. (See Del. Group Seeks to Block Artificial Island Project.)
“It’s really all about the cost allocation, but if you can solve that, the rest of this stuff is easier,” Gramlich said.
He advocated for broad, beneficiary-pays allocations in which many stakeholders shoulder smaller portions of the bill. Still, that won’t solve everything.
“There is no perfect solution for cost allocation except [to] pay a lot of lawyers for a lot of litigation,” Exelon’s Steve Naumann said.
