CARMEL, Ind. — MISO is beginning a study to assess its frequency response performance and identify needed improvements.
In the first half of 2017, MISO will compile system data from major generation loss events for evaluation. The RTO’s initial sample of generation loss events are spread evenly across the footprint, although it said data may not be available for some locations.
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MISO’s frequency response continues to “decline year after year” and while not a pressing problem yet, it is “concerning,” Durgesh Manjure, MISO resource adequacy manager, said at an April 6 Reliability Subcommittee (RSC) meeting.
In January, the RTO’s staff asked for stakeholder input on how to address the declining frequency response capability, presenting preliminary simulations showing the system recovering too quickly when compared with real events — an indication of the need to fix governor parameters, officials said. (See MISO Aims for Improved Frequency Response Modeling.)
In the latter half of 2017, MISO will run simulations based on collected data and compare results to the actual events. By early 2018, the RTO will use stakeholder input to refine the study models.
Although MISO originally planned to use data from its SCADA system, it now says those measurements “seem inadequate for model validation” because the data are not detailed enough and not synchronized across locations, creating a potential time lag.
Data collected from phasor measurement units (PMUs) might be the better option, because their measurements are detailed and synchronized in real time across the grid, the RTO said.
However, Manjure said PMU data may not be available for all of the large generating units. In addition, PMU data is deleted after one year. It “remains to be seen how useful” the PMU data will be, Manjure said.
“Just being able to leverage the PMU data is a work stream in itself,” Manjure said. “We’re not quite sure which things are going to work … as we start peeling the onion.”
RSC Chair Tony Jankowski said he preferred MISO get the most detailed data to begin improving modeling.
Manjure said MISO would present more information on the study at the June RSC meeting.
MISO’s Independent Market Monitor last week filed a complaint over PJM’s pseudo-tie procedure, the latest volley in an increasingly complex debate over the future of the pseudo-tie concept.
Spurred by a recent PJM bid to tighten its pseudo-tie rules, Monitor David Patton filed a Section 206 complaint April 6, claiming that the increasing use of pseudo-ties degrades reliability, hinders efficient dispatch and raises costs. He asked FERC to eliminate PJM’s existing pseudo-tie definition (EL17-62).
“PJM has asserted that it has a very broad right to impose requirements on external generators to ensure that their capacity can be delivered reliably and efficiently, but the PJM pseudo-tie practices exceed all reasonable bounds,” wrote Patton, whose Potomac Economics firm provides monitoring for MISO and NYISO.
NYISO also took issue with PJM’s March 9 FERC filing seeking approval to apply more stringent requirements on external capacity resources serving the RTO’s load. PJM wants the new rules to be effective in time for its May 10 Base Residual Auction (ER17-1138). (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)
In a March 31 protest, the ISO said PJM’s proposal — which would allow PJM to commit and dispatch generators directly interconnected to the New York Control Area — “could threaten the reliable operation of the NYCA and disrupt the NYISO-administered markets.”
Patton said PJM provides only “scant support” for its new, “arbitrary parameters,” and that the filing makes it “impossible for any supplier in MISO that does not currently have a unit pseudo-tied to PJM to meet these requirements to offer capacity in the [Reliability Pricing Model] forward auctions.”
If the new rules are implemented, PJM’s customers could experience annual capacity cost increases of $500 million to $4 billion, Patton said. The complaint suggested that FERC consider replacing pseudo-ties with a firm capacity delivery procedure, a collaborative approach that Patton and MISO presented last year. (See PJM Filing Renews MISO Monitor’s Call for Pseudo-Tie Elimination.)
PJM Cries Foul over MISO Pro Forma
Meanwhile, PJM and MISO are attempting to settle a disagreement over the Midwestern RTO’s stricter pseudo-tie pro forma agreement.
The two RTOs are considering adding coordinated pseudo-tie policies to their joint operating agreement “in lieu of MISO being a signatory to PJM’s agreement,” MISO Senior Director of Regional Operations David Zwergel said during an April 6 Reliability Subcommittee meeting.
Zwergel said the discussions are the result of PJM’s March 21 protest of MISO’s pro forma filing (ER17-1061).
“MISO made this filing without the opportunity for PJM to review, leaving PJM no choice but to file this protest and seek revisions to this agreement through the commission,” PJM wrote. It asked FERC to require MISO to “revise any provision of the proposed agreement to the extent it gives MISO unilateral authority to control the implementation, operation, suspension and/or termination of the impacted pseudo-tie, or is inconsistent with the coordinated implementation and operation of pseudo-ties as between MISO and PJM.”
PJM said it sought MISO input on the development of its own pro forma pseudo-tie agreement but was not granted the same courtesy.
Work Continues on Double-Counting Congestion
In a related matter, the two RTOs last week presented an update to their proposal for eliminating overlapping measurements of congestion related to pseudo-ties.
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During an April 7 Joint and Common Market Initiative meeting, the RTOs proposed a revised solution that involves exchanging more congestion information in the day-ahead market and refunding or charging pseudo-tie owners for deviations between day-ahead predictions and real-time numbers.
“The RTOs will coordinate pseudo-tie firm flow entitlement impacts before the day-ahead run so that the congestion and the day-ahead LMPs for the pseudo-tie resources will better reflect actual congestion,” the RTOs said.
“We’d be aligning our firm flow entitlement impacts in the day-ahead to reflect what we think the settlement will be in real time,” said Kevin Vannoy, MISO director of forward operations planning.
PJM Interregional Coordination Manager Tim Horger said the solution solves the double-counting issue “as best we can” with prices more reflective of the real-time market. “It’s not going completely solve congestion, but we’re measuring that pseudo-tie impact on every coordinated market-to-market flowgate,” he said.
Horger said that the impacts will be brought “in front” of LMPs and pare down “excess congestion” that is usually folded into the pricing, reducing the need for refunds.
PJM and MISO staff have not yet determined which Tariff or JOA changes might be necessary, but Horger said pseudo-tied resources will not have to make any changes. Vannoy said MISO and PJM hope to adjust the market-to-market settlement process in time for a June 1 implementation.
A future phase of MISO and PJM’s solution will allow for optional scheduling and settlement of pseudo-tie transactions in the native balancing authority’s day-ahead market. In February, MISO and PJM said they would provide congestion rebates in the near term while developing a way to incorporate pseudo-ties in the day-ahead scheduling process by 2018. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.)
WASHINGTON — More than three years and thousands of pages of analysis later, there is no consensus on how the electric industry should respond to the January 2014 cold snap that revealed weaknesses in the Eastern Interconnection.
The differences of opinion were on display during a panel discussion on gas-electric coordination at the Energy Bar Association’s annual conference on Monday.
Macdara Nash of National Grid and Todd Piczak of Kinder Morgan advocated for additional pipelines in the Northeast U.S., saying they would ensure sufficient gas supplies for generators on high-demand days. David Ismay of the Conservation Law Foundation called for peak shaving and increased gas storage, saying additional pipeline capacity would reduce utilization of existing infrastructure most of the time.
One thing all the panelists agreed on is that natural gas has a place in the region’s energy future and that action needs to be taken to better gird the grid against unforeseen events like the polar vortex.
“The region should be thinking about what are solutions, what can we do,” Nash said. “We think that natural gas is key.”
He cautioned that pipelines require an extensive lead time, “so if you believe in the problem [of potential pipeline capacity shortages], the time to act is sooner than later.”
Piczak said FERC has made progress on one half of the problem — ordering increased coordination between gas pipelines and gas-fired generators — but hasn’t done much to facilitate the other half, which is adding capacity. A major issue, he said, is the need for the commission to develop criteria other than long-term contracts to support a finding of public convenience and necessity.
Piczak’s company operates the Tennessee Gas Pipeline, one of the nation’s most critical natural gas conduits because it runs from Houston to Boston and crosses two prolific shale gas plays, the Utica and Marcellus in the region of Ohio, Pennsylvania and West Virginia.
Not a Capacity Problem
“This is fundamentally a regulatory problem,” he said. “There’s not enough gas for the generators when they need it. … It’s an important problem, and it’s a growing problem.”
Ismay said the issue isn’t the availability of gas — he said gas was never unavailable, even during the polar vortex — but that constraints and high demand make it prohibitively expensive. A new pipeline would, on average, be about half full half of the year and wouldn’t justify the installation costs, he said.
“Instead of a capacity problem … it’s a temporal, location-based problem of getting a certain amount of gas to a certain location … on the pipeline system at time of year,” he said. “We [will] always have days above the peak, even if we build a new pipeline.”
LNG storage has been and should be the solution, he said, along with demand response and energy efficiency to shave peak demand. He pointed out that while Massachusetts’ electricity rates are the fifth highest in the country, customers’ bills are the 31st lowest on average.
A study of future energy needs in the Bay State, conducted by Analysis Group for the state attorney general, found that, in a business-as-usual scenario, there will be no reliability concerns out to 2030, he said. Moving forward, energy storage, increased pipeline compression, additional pipeline loops and developing targeted markets will address remaining issues.
“If we understand the problem of temporal availability, let’s create a market for it,” Ismay said. “There is a role for natural gas in 2050, but it’s not very big. … It doesn’t run very much in the future.”
With natural gas already occupying 40% of installed generation and providing 50% of the electrons in New England, “our bridge is built” to a low-carbon future, Ismay said.
Discussion attendees pushed back on some of Ismay’s arguments, noting the Massachusetts study assumed best-case, “blue skies” scenarios and that adding localized LNG storage to gas-fired units raises their bid prices to levels comparable with coal-fired units.
“Another important thing to recognize about LNG solutions is you still have to get the gas from the LNG facility to where it’s needed,” Piczak said. “It’s not as easy as just to say, ‘Let’s put some LNG in a tank,’ and it’s going to be available.”
NRDC, J.P. Morgan Skeptical of Pipeline Need
At the EBA’s general session on Tuesday, J.P. Morgan’s Ian C. Connor, and David Doniger of the Natural Resources Defense Council, also expressed skepticism over the need for additional pipelines.
Connor, global co-head of J.P. Morgan’s power & utility group, noted that renewables are supplanting a lot of retired coal capacity.
“I think you’re going to see significantly less gas [generation] build than people believe,” he said. “These [combined cycle gas turbines]: Yes there are a few being built between now and 2020. After 2020, right now no one really thinks any more CCGTs are getting built. So how many more pipelines are you really going to need to build? I think it’s a lot less.”
Doniger, director of NRDC’s Climate & Clean Air program, said the rise of renewables and flat electric demand should prompt FERC to look more skeptically at the need for new pipelines.
“Are we building gas pipelines in order to stimulate the development of new gas power plants or is there really a need?” Doniger asked. “If you look at the system more systematically … efficiency, renewables and some of the other options can [replace] extensions of the gas pipelines and the natural gas infrastructure. The FERC process for evaluating new pipeline applications doesn’t ask all those questions and [it] should.”
CAISO management is proposing to amend the Western Energy Imbalance Market (EIM) charter to explicitly provide the market’s Governing Body with a voice in any future governance changes.
Other charter changes currently under review would give the Governing Body the first — and, in most cases, the last — word on its relationship with two increasingly important stakeholder groups.
The proposed changes were drafted at the request of Governing Body Chair Kristine Schmidt, who wanted more clarity on the body’s role in modifying the charter.
Originally approved by CAISO’s Board of Governors, the EIM’s charter sets out the mission of the Governing Body and details the authority delegated to it by the board over EIM market rules and administration.
The charter currently stipulates that any “substantive changes” to the charter must be approved by the board, as required under the CAISO Tariff. “The role of the EIM Governing Body in considering proposed changes, however, is not specifically addressed,” Roger Collanton, the ISO’s general counsel, noted in a memo addressed to the Governing Body.
Under the proposed revisions, any substantive modifications to the charter would first be presented to the Governing Body for its “advisory” input — similar to the role body members play with respect to ISO market rule changes that also affect the EIM. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)
CAISO management also seeks to extend the authority of the Governing Body over sections of the charter dealing with the EIM’s Body of State Regulators (BOSR) and Regional Issues Forum (RIF), two West-wide groups established by the ISO to monitor and provide feedback on the EIM’s activities.
The proposal would allow the Governing Body to initiate any modifications to those areas of the charter. Approved changes would then be placed on the consent agenda of the board, translating into “a decisional process similar to the one that is used for proposed tariff amendments that fall within the primary authority of the EIM Governing Body,” Collanton’s memo said.
The board would reserve the right to consider — and reject — any proposed changes outside its consent agenda, but “this full consideration will occur only if the board affirmatively decides to take up the issue,” according to the memo.
Other proposed amendments to the charter detail how ISO staff will support the work of the BOSR and RIF, including coordination of meetings, assistance with stakeholder communication and reimbursing state regulators’ staff for travel to attend meetings. RIF members expressed a need for staff support during a Feb. 28 joint meeting with the Governing Body. (See Western Stakeholders Support Continuing Regional EIM Forum.)
CAISO will seek Governing Body endorsement for the charter amendments at a future meeting of the body.
PJM’s Board of Managers on Thursday ordered a resumption of the Artificial Island transmission upgrades but directed the development of alternative cost allocations to address Delmarva peninsula stakeholders who argue they’re unfairly on the hook for the vast majority of the $280 million project.
The board suspended work on the controversial project last August following years of stakeholder complaints about how the project was scoped, awarded and had its costs allocated, ordering staff to perform a comprehensive analysis. At a special session of the Transmission Expansion Advisory Committee in March, staff announced some modifications to the scope of the project, but remained supportive of the proposal the board had approved in 2015. (See PJM Sticks with LS Power on Artificial Island Project.)
PJM says the DFAX cost-allocation methodology can produce “”anomalous”” results in some projects, such as Artificial Island, in which it assigned 93% of the cost to Delmarva Power & Light ratepayers. All other transmission zones would pay less than 1% each. | PJM Transmission Expansion Advisory Committee, 3/3/17
Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate (EL15-95, ER15-2563). Under the DFAX method, 93% of the costs would be borne by Delmarva Power & Light ratepayers, with all other transmission zones paying less than 1% each.
PJM’s signal last month that it would move forward with the project prompted renewed complaints to the board from 12 stakeholders — including the governors of Maryland and Delaware — upset over the cost allocation.
In a letter to stakeholders on Thursday, PJM CEO Andy Ott acknowledged the dispute and called on PJM’s transmission owners to come up with a compromise.
“PJM has stated in past Federal Energy Regulatory Commission proceedings and at a Jan. 12, 2016, FERC technical conference that a solution-based power flow formula (the ‘DFAX methodology’) works fairly and reasonably to identify project beneficiaries for cost allocation purposes in the overwhelming majority of lower-voltage transmission projects considered by the board,” Ott wrote. “But we also noted that application of the DFAX methodology can result in cost allocations that seem anomalous in cases where the engineering rationale or need for the particular project is not one driven by power flows. Indeed, PJM has suggested that the Artificial Island project is unique in nature and that application of the DFAX methodology to a stability or short-circuit problem may not yield clear beneficiaries.”
TOs, not PJM, Responsible for Cost Allocation
Ott said the Federal Power Act makes the PJM TOs responsible for proposing cost allocation methods and prevents the RTO from imposing alternatives. But he also acknowledged that the cost allocation dispute “is so polarized [that] it threatens to impede PJM in discharging its reliability responsibilities.”
As a result, he said, PJM staff “will analyze project beneficiaries from alternate perspectives, including identifying load and the extent of service interruption that could be expected in the case of an uncontrolled stability event at Artificial Island.”
“Importantly, we anticipate this information will still demonstrate the logic supporting an allocation of project costs to beneficiaries located in the Delmarva region, along with beneficiaries in one or more neighboring states,” he added.
He said the analyses will be available “shortly” and will be referenced in its FERC filing on the project.
The board also used in its decision a whitepaper produced by PJM, which stakeholders have complained was not made available for comment and response prior to the board’s decision. Ott said in his letter that the “whitepaper is anticipated for public release in the near future and will offer additional transparency to stakeholders.”
In a news release, the board said it directed staff to publish the alternative allocations because it believes “this data could offer insight to, and a basis for, those states, transmission owners and customers that derive benefit from this project to devise a different cost allocation proposal for stability projects such as Artificial Island.”
At the special TEAC meeting last month, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem nuclear plant to the Hope Creek plant. The analysis also eliminated as unnecessary a static VAR compensator and optical groundwire upgrades.
Salem Nuclear Generating Station on Artificial Island
The revised project assigned $146 million of the project work to LS Power, $132 million to Public Service Electric and Gas, and $2 million to Delmarva Power & Light.
PacifiCorp has released a 20-year plan that commits the utility to increased investment in renewable resources and energy efficiency while sharply reducing reliance on the coal-fired generation that currently produces more than half the company’s electricity output.
The 2017 Integrated Resource Plan — filed this week with utility commissions in PacifiCorp’s six-state territory — spells out $3.5 billion in capital spending focused on new renewables, upgrades to the company’s existing wind fleet and the construction of a 140-mile segment of the Gateway West transmission project in Wyoming.
The 500-kV line, slated to be in service by the end of 2020, would advance the company’s strategy for tapping new wind development in Wyoming. While the first segment is intended to serve PacifiCorp ratepayers, other portions of Gateway West are designed to facilitate the flow of wind energy into California, where utilities are required to serve 50% of their load with renewables by 2030.
Under the IRP, PacifiCorp would complete construction of 1,100 MW of new wind generation, mostly in Wyoming, by 2020 to take advantage of federal production tax credits. The company would also squeeze out an additional 905 MW of renewable capacity by upgrading its existing wind fleet with larger blades and new technology.
PacifiCorp currently owns or contracts for more than 2,300 MW of wind resources.
Between 2028 and 2036, the company plans to add another 859 MW of wind and build 1,040 MW of new solar capacity.
“These investments will significantly increase the amount of clean renewable energy serving customers and reduce costs at the same time,” Stefan Bird, president and CEO of Pacific Power, the PacifiCorp subsidiary that serves Oregon, Washington and California, said in a statement.
The plan calls for retiring 3,650 MW in coal-fired capacity by 2036 to avoid spending on equipment to comply with EPA’s Regional Haze rules. An Oregon law passed last year that will prohibit the state’s utilities from importing coal-fired power by 2030 also was a factor in the early retirements of the Craig, Jim Bridger, Hayden, Huntington and Naughton coal units located in the inland West. A rollback of EPA’s Clean Power Plan is unlikely to affect the company’s plans, it said.
“This early closure assumption was considered in PacifiCorp’s Regional Haze compliance analysis to account for changes in market conditions, characterized by reduced loads and wholesale power prices,” the IRP said.
By the end of the planning horizon, coal would represent 31% of the company’s resource portfolio, compared with almost 60% today.
The plan foresees the company building 1,313 MW of new natural gas-fired capacity, down 1,540 MW from the 2015 IRP estimate.
“Reduced loads, ongoing investment in energy efficiency programs and increased renewables reduce the need for new natural gas resources in the 2017 IRP,” the company said.
PacifiCorp expects energy efficiency to offset 88% of forecasted load growth over the next 10 years.
Stagnant loads and energy efficiency programs also caused the company to reduce its projections for wholesale power purchases through 2027 relative to a 2015 IRP update released last year, despite relatively low forward prices. Wholesale market purchases are expected to increase in 2028 in concert with the company’s coal retirements.
PacifiCorp said it developed the 2017 IRP through a process that included input from “an active and diverse group of stakeholders, including advocacy groups, regulatory staff and other interested parties.” The company completed the plan after meeting with stakeholders in five states and hosting seven public meetings.
The company delivers power to about 1.8 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming through its Pacific Power and Rocky Mountain Power subsidiaries. The company was the first utility in the West to join CAISO’s Energy Imbalance Market and in 2015 signed a memorandum of understanding to explore becoming a full member of the ISO.
WASHINGTON — They couldn’t agree on much except for this: today’s electricity markets don’t handle environmental externalities well because they’re not designed to.
That was the rare moment of consensus during an otherwise fractious discussion about the growing pressures of state policy initiatives on FERC-regulated markets at the Energy Bar Association’s annual conference Monday.
Kathleen Spees of The Brattle Group said that state and provincial actions — such as Ontario’s goal of reducing CO2 emissions by 80% below 1990 levels by 2050 — will “fundamentally change the nature of our resource mix, how plants are built [and] how they’re operated.”
“Markets today on their own won’t achieve that, and so that’s why we’re seeing states basically taking different policy measures to achieve those objectives,” she said. “But my question is, ‘Can the markets help to support and achieve those ends?’ And I think the answer is, ‘they can.’ I think it will be hard to get there.”
Spees clarified that her perspective was based on economics, rather than the legal issues on which much of the discussion at the two-day conference focused.
Competing with a concurrent session on gas-electric coordination, the panel attracted the majority of attendees, requiring the addition of several rows of extra chairs in the back of the room.
Moderator Jeffrey Dennis, senior counsel with Akin Gump Strauss Hauer & Feld, teed up the discussion by noting that the Supreme Court has ruled that retail and wholesale markets are so intertwined that a state can impact the wholesale market without violating federal jurisdiction. “These markets are not hermetically sealed,” he said.
Nick Martin, a manager of environmental policies with Xcel Energy, opened the discussion by explaining how Minnesota requires his company’s integrated resource plan to factor in two carbon dioxide externality values: one that represents the potential future impact of carbon regulations on Xcel’s system and another that represents the potential future damages from climate change. The first ensures the utility isn’t making infrastructure investments without considering the potential impacts to customers of future regulatory costs, while the second takes a broader view.
“Sometimes, those are divergent,” Martin said. “These are both values used in planning. Neither of them represents a carbon price that would go directly into wholesale markets at the RTO level.”
Xcel is currently seeking regulatory approval to update those externality values, Martin said, but the 2007 regulatory commission order under which the utility operates values carbon emissions between $9 and $34 per short ton. The valuations help determine which planning alternatives are the best fit for Xcel’s 15-year outlook.
He contended that the valuations aren’t like the zero-emissions credits recently approved in Illinois and New York because they don’t impact FERC-regulated electricity markets.
“They won’t directly pay a higher price to our nuclear plants, but they will strengthen the rationale for retaining nuclear, retiring coal plants [and] adding renewables,” he said.
Exelon’s David Dardis later argued on the panel that ZECs also don’t impact RTO markets. He pointed to FERC’s 2012 ruling regarding the Western Systems Power Pool, which concluded that stated renewable energy credits are separate commodities from capacity and energy (ER12-1144).
“So long as the REC is unbundled or sold independent of wholesale electric energy, the RECs are not payments in connection with wholesale sales and therefore fall under state jurisdiction,” Dardis said. “ZECs are clearly sold independent of energy and capacity.”
NRG Energy’s Abe Silverman disagreed, arguing that the credits intrinsically intrude on FERC’s jurisdiction over wholesale energy sales. He noted that 95% of the time, all the units needed for wholesale dispatch are receiving a state-promulgated rate different from the FERC-regulated market. NRG has joined in lawsuit challenging the legality of the ZECs. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.)
“The fact that the state was trying to engage in the most noble of causes, in this case fighting climate change, does not — at least in my view — escape pre-emption,” he said. “What does it mean for FERC to regulate wholesale rates if states take increasingly large amounts of generation out of the market?”
Spees said Ontario is a prime example of what happens when the market is marginalized. The Canadian province has reduced its carbon by more than 6% below 1990 levels through resource- and technology-specific out-of-market contracts — and closing all of the province’s coal-fired generation — but Spees said the costs are now escalating.
“It’s really turned into a big challenge,” she said. “Those do tend to be higher cost. They don’t enable that competition and innovation that we really probably want in the system. … [Markets] become much less important to the system and much less valuable in terms of achieving some of these benefits that you can get through competition and innovation.”
They can also have unintended consequences of suppressing prices, which can squeeze out other clean technologies. As a result, the province faces a major redesign of its system to re-engage the power of the market, she said.
Silverman said New York’s and Illinois’ ZECs were an ill-conceived and potentially expensive means of limiting carbon emissions.
“Nobody would remodel their kitchen without getting a couple of bids. Here we have $10 billion of ratepayer capital committed to two states without ever testing it to see if it was actually the least-cost source of carbon abatement,” he said. “If all we’re doing is relying on ratepayer capital, we’ll never get it done. We need that shareholder private capital to come into the market as well.
“If you are terrified of backsliding in year 1, 2 or 3, then … nuclear is probably the best way to go,” he said. “But if you’re looking at a lifecycle analysis and really thinking about 2050, we need to go not just from coal to gas — which is probably what would happen if the nukes retire — but we need to go from coal to clean, which means FERC really needs to step up and create the kind of markets and really get markets to address the carbon problem.”
MISO is recommending the addition of a fourth future to its 2018 transmission planning to reflect localized carbon reduction efforts and battery storage.
In addition to futures for “limited,” “continued” and “accelerated” fleet change, the RTO is proposing a distributed and emerging technologies scenario to inform its 2018 Transmission Expansion Plan.
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Under the new distributed and emerging technology future, fleet evolution is driven by local and state policies and the adoption of emerging technology. Renewable additions are economically propelled by technological advancements and state renewable portfolio standards. Renewables, which are expected to provide 15% of total MISO energy by 2032, are sited within state jurisdictions for local energy use.
The future also predicts commercial mass production of energy storage devices. MISO envisions that natural gas reliance increases with more electric vehicles on the road, the need to support intermittent renewables and to replace retiring capacity. Natural gas prices stay consistent with long-term forecasts, with the RTO using the NYMEX for the first two years to forecast prices and an average of the U.S. Energy Information Administration and Wood Mackenzie forecasts for the remaining years. MISO also expects a surge in demand-side management programs.
MISO’s 2017 futures include an existing fleet future, policy regulations future and an accelerated alternative technologies future. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.) Using stakeholder feedback, the RTO will now use MTEP 17 definitions as “outlines” for MTEP 18, “but completely refresh forecasts.”
“Given trends, low gas price forecasts, member-stated plans and renewable potential, MISO feels it is necessary to consider fleet changes beyond those in the MTEP 17 policy regulation future,” the RTO said.
In addition to distributed technology scenario, the 15-year futures for 2018 are:
A limited fleet change future assumes 8 GW of age-driven coal fleet retirements by 2032. Low demand and low prices for both natural gas and energy curb new energy generation technologies and keep renewable additions limited to current renewable portfolio standards, making up 10% of MISO resources by 2032. The low natural gas prices, however, drive an increase in industrial production along the Gulf Coast in MISO Zone 9.
A continued fleet change future presumes the rate of fleet evolution remains as it has since about 2005. The assumed 16 GW of coal retirements is based on plant shutdowns at age 55-60, with natural gas additions largely replacing them. New renewable resources continue to exceed RPS requirements and serve 15% of MISO energy by 2032 because of continuing public interest, economics and future policy regulation.
An accelerated fleet change hinges on a “robust” economy that drives demand and energy production. Natural gas prices rise as a result of demand, and carbon regulations aiming for a 20% reduction from current emissions levels are introduced. Coal retirements would surpass the “continued” future’s 16 GW, with natural gas sources stepping up to replace the lost capacity and provide a steady backup to renewable resources, which exceed RPS targets and make up 26% of MISO resources. High gas prices hinder industrial production along the Gulf Coast.
“It’s still very early” in the planning process, MISO engineer Stuart Hansen reminded stakeholders at an April 4 special workshop. “I think we’ve incorporated what makes sense, but we want to hear your ideas.”
Hansen said MISO will still model a future federal carbon emissions policy for the 2018 batch of transmission projects in the accelerated fleet change future by modeling 20% additional emissions reductions by 2030. “We know that the [Clean Power Plan] is no longer a hot topic, but to provide an adequate bookend … we’ll continue to model federal policy in the accelerated fleet change future.”
Some stakeholders expressed appreciation for the fourth future, saying even with the CPP no longer relevant in the near term, MISO will still need to capture a decreasing carbon trend led by economics, local efforts, state policy and corporate initiatives rather than federal policy.
Richard Seide of Apex Clean Energy asked if MISO planned to model utilities’ green tariffs and corporate purchasing of renewable power. Ann Benson, of MISO’s policy studies group, said the RTO could include renewable types and prices into the futures’ expected renewable portfolios.
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Sean Brady of Wind on the Wires asked MISO to consider modeling future nuclear plant closings, especially in Illinois. In all MTEP 18 futures, nuclear units are assumed to remain online through their current operating licenses. The RTO also assumes 16 GW of natural gas and oil unit retirements by 2032 across all four futures.
More discussion on MTEP 18 futures development will take place at MISO’s monthly Planning Advisory Committee meetings through August.
The Millstone nuclear power plant has earned at least $3 billion in profits for Dominion Energy since the company bought it and will likely earn an additional $2.2 billion in after-tax income from now through 2030, according to a study released Wednesday by opponents of legislation that could boost the plant’s finances.
Millstone Nuclear Power Plant | NRC
The Stop the Millstone Payout coalition commissioned consulting firm Energyzt to analyze the finances of Millstone, for which Dominion does not release profit or loss figures.
The coalition’s sponsors include competing New England generators Calpine, Dynegy and NRG Energy, as well as the Electric Power Supply Association, all of whom oppose Connecticut legislation that would allow Millstone to bid into the state procurement process now reserved for renewable energy resources.
Dominion indicated last month that the plant will compete in ISO-NE’s Forward Capacity Auction next year, meaning the company expects it to continue operations into at least 2022. Dominion purchased the 2,111-MW facility in 2001 for $1.28 billion. (See Millstone to Enter FCA 12; No Closure Likely Before 2022.)
Tanya Bodell, executive director of Energyzt, said that if Senate Bill 106 is enacted, “Connecticut ratepayers will be on the hook for $330 million per year, or a 15% increase in their electric rates.”
Bodell said that Dominion bought Millstone at an “opportune time” because high natural gas prices increased power prices in New England, enabling the company to earn back the purchase price in five years. The report estimated that Millstone has generated at least a 25% return on equity for Dominion’s shareholders.
| Energyzt
The analysis used Chicago Mercantile Exchange monthly futures prices to establish base-case energy prices in assessing the financial situation of Millstone through 2021. For the nine years after 2021, she based long-term energy prices on ISO-NE’s recent FERC filing for Forward Capacity Market parameters. Under these projections, the report said Millstone can be “anticipated to earn close to $400 million in after-tax income over the next five years, or $80 million per year. Thereafter, ISO-NE’s … price projection results in closer to $200 million per year in after-tax income through 2030.”
‘Gross Assumptions and Preposterous Claims’
The legislation would make Millstone the only eligible nuclear generator in Connecticut’s competitive bidding process and award it a five-year contract if its bid is lower than competing renewable resources. The bill sets an annual limit on nuclear energy purchases at 8.3 million MWh, equivalent to half of Millstone’s output.
Dominion spokesman Ken Holt blasted the Energyzt report as “loaded with gross assumptions and preposterous claims, with no real data. They say the cost under S.B. 106 would be $85/MW, but the standard offer now is $81. Why would we bid higher when four regulators oversee the bidding, none of them with any incentive to see consumers pay higher rates?”
The study assumed a contract price of $85/MWh based on the cost of large-scale renewables procured in 2016 and estimated Millstone needs to earn $40 to $45/MWh to cover its operating costs and debt payments.
Holt added that Millstone is more expensive to operate than other two-unit nuclear plants because its two units are of different designs. “That means that an operator on one unit cannot work on the other, and that we need to have two separate training programs,” he said. “The others can benefit from economies of scale.”
EPSA said in a statement on Wednesday that the Energyzt report shows that the “intent and effect of these [legislative efforts are] to distort wholesale markets for all other power suppliers needed to provide reliable, competitively priced electricity.”
MISO and the Organization of MISO States have begun distributing their annual joint resource adequacy survey with a new calculation method some stakeholders believe is overly conservative.
In addition to counting as available capacity all generation projects with signed interconnection agreements — as in the past — this year’s survey will also count 35% of those in the definitive planning phase of the queue, Darrin Landstrom, MISO resource forecasting adviser, said during an April 5 workshop on the survey.
The surveys, which were sent to load-serving entities on March 31, will ask for the queue project number as well as status. Responses are due April 30.
Some MISO stakeholders maintain the 35% estimate is too conservative, resulting in unnecessarily alarming results and exaggerating a possible capacity shortfall. Last month, Resource Adequacy Subcommittee Chair Chris Plante notified the RTO’s Board of Directors of the disagreement. (See Differences Persist over OMS-MISO Survey Improvements and “OMS-MISO Survey Dispute Revisited,” MISO Advisory Committee Briefs.)
The surveys continue to use the “high-” and “low-certainty” descriptors, although MISO said it will convert those terms to “committed” and “potential” when the RTO and OMS present results in June.
