MISO’s Steering Committee concluded last week that the Resource Adequacy Subcommittee acted properly when it retired the Competitive Retail Solution Task Team on May 5 without a vote or motion.
MISO already displays a real-time wind generation in a graph on their website. A pending data request asks the RTO to break down wind output data by North, South and Central regions. MISO says that my not be possible.
But in its meeting Wednesday, the committee discussed whether the RTO’s stakeholder governance guide should be updated to outline a process for retiring a task team. To retire the CRSTT — which was established last October to develop capacity auction improvements — the RASC relied on written comments and discussion with stakeholders.
RASC Chair Gary Mathis said the issue was presented to the Steering Committee after questions were raised about the procedure the RASC used.
“I don’t think we need to formalize this process,” Steering Committee Chair Tia Elliott said.
But Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., said it may be helpful for committee charters to state that task teams can be closed out “entirely at the discretion of committee leadership.”
Indianapolis Power & Light’s Lin Franks also recommended that the Steering Committee produce a non-enforceable guideline document on the creation and dissolution of task teams.
In lieu of task teams, Kent Feliks of American Electric Power suggested MISO could hold special meetings on topics, as PJM does.
Elliott said further discussion on the issue will be taken up at the July Steering Committee meeting.
IMM Makes Recommendation in Data Request
Two pending data requests must be adjusted before being implemented by MISO, RTO staff and the Independent Market Monitor said.
The Monitor cautioned against fully granting a stakeholder request to post commercial limits for binding constraints in the real-time and day-ahead markets. It recommended rejecting the release of day-ahead values “but is still considering the possibility of real-time values on a week delay,” according to MISO. The RTO’s Tom Welch said staff plan to postpone a decision until July, when the Monitor’s final recommendation becomes available.
Foreknowledge of the constraints creates concerns about market manipulation, Welch explained.
The RTO is also putting the brakes on an early May request to break down wind output data by North, South and Central regions in both real-time and day-ahead forecasts. (See “MISO Grants 2 Data Requests, Denies Another,” MISO Steering Committee Briefs.)
Welch said the request is still under review, noting that when the first wind units open in MISO South, wind output reports would inadvertently “expose their unit-specific information.” To protect nonpublic information, MISO said the data posting might not be prudent until at least three wind units are installed in the region.
“We can break down the northern regions,” Welch said.
Financial Transmission Rights Working Group Retired
MISO’s Financial Transmission Rights Working Group was retired as a result of a Steering Committee decision. Duties associated with financial transmission rights and auction revenue rights have been transferred to the Market Subcommittee.
The move was approved by consent with little discussion.
Environmental groups are appealing the Public Utilities Commission’s approval of a 558-MW natural gas-fired power plant in the seaside town of Carlsbad on the grounds that power could be supplied more cleanly and cheaply by renewable resources.
A state appellate court will soon decide whether to hear the appeal of the commission’s decision. The plant would supply energy to San Diego Gas & Electric under a long-term agreement.
A decision in favor of judicial review could call into question a number of similar plants proposed in the state. SDG&E insists that gas-fired generation must remain part of the region’s resource mix.
The Senate Energy and Technology Committee passed a pair of bills that would phase out the state’s energy efficiency program and put restrictions on alternative energy suppliers.
SB 438 would establish a 35% clean energy goal by 2025 and expands the definition of renewable energy to include incineration. The bill would also phase out the state’s current energy efficiency program by 2021 and maintain the current 10% renewable portfolio standard. Proposed amendments to increase the RPS to 15% and 20%, and to extend the energy efficiency program to 2025, were defeated.
SB 437 maintains the state’s 10% cap on participation in electric choice and requires alternative energy suppliers to prove their ability to serve customers. The bill passed 6-1, with one Republican saying the provision would effectively kill the state’s retail choice program.
The Public Service Commission approved a request from Ameren Missouri to increase its Energy Efficiency Investment Charge. The line item that appears on electricity customers’ bills will increase by about $2.22/month beginning in June.
The company said the increase was needed to align the costs of its three-year energy efficiency plan, approved by the PSC in February.
The charge, part of the Missouri Energy Efficiency Investment Act, is intended to encourage utilities to implement demand-side and energy efficiency programs.
Renewable Groups, City Launch Clean Energy Campaign
Representatives of the renewable energy industry and Bozeman city officials joined forces last week to launch a campaign pushing the state to tap into its potential for wind and solar production.
Renewable Northwest and the Montana Renewable Energy Association launched a website to educate people about the opportunities for renewable energy and to advocate for the industry in a time when consumers are turning away from coal-fired power.
According to the campaign, the state’s energy economy is in crisis because of the expected demise of coal-fired generation.
Las Vegas casinos are bankrolling a proposed ballot initiative to end NV Energy’s monopoly over most of the state’s electricity supply and creating a competitive market in the state, according to financial disclosures.
Las Vegas Sands has contributed $500,000 to the Energy Choice Initiative, which seeks to put retail choice on the ballot. Initiative organizers must get 55,000 signatures by June 21. MGM Resorts International has also donated $10,000 to the effort.
Sands considered breaking with the utility and purchasing power on the open market, but changed course after the state’s Public Utility Commission said the move would entail a $24 million exit fee. MGM has said it would pay $87 million to drop NV Energy in October.
A dozen lawmakers have introduced legislation to codify Gov. Andrew Cuomo’s goal of completely eliminating the state’s greenhouse gas emissions by 2050.
The bill would direct the Department of Environmental Conservation to issue regulations within a year that would require reporting of annual emissions from major sources. It would also be required to establish a registry and reporting system measured in tons of carbon dioxide equivalents.
The department would determine the 1990s emissions levels, then require statewide reductions to that same level by 2020, followed by deeper periodic reductions over the next 30 years.
McCrory Threatens to Veto Coal Ash Commission Bill
Gov. Pat McCrory says he would veto a proposed bill to restart a commission to oversee the cleanup of the state’s coal ash pits. McCrory, a former Duke Energy executive, dissolved a previous commission to regulate the utility’s efforts to clean up the dozens of coal ash impound pits and dumps, saying lawmakers were influencing the panel’s work.
The effort to reform the commission would still give the governor the ability to fill five of the seven positions, subject to General Assembly confirmation. The commission would guide the Department of Environmental Quality’s cleanup efforts. The bill would also give Duke until 2024 to clean up all of the coal ash pits.
Environmentalists say the measure still allows Duke too much leeway in cleanup efforts.
The state will once again fall short of its poultry waste-fired generation target, after Duke Energy told regulators that it won’t be able to meet its requirement under the state’s renewable portfolio standard.
The statewide requirement for poultry power rose to 700 GWh from 170 GWh this year. Duke initially said it expected to be able to meet the requirement, but that was before one poultry project delayed its opening until later in the year. Another plant, owned by Prestage AgEnergy, was scheduled to open in spring but also had to be delayed because it would not have been able to meet environmental standards.
Turkey and chicken droppings are currently used by five state incinerators to produce electricity.
After withdrawing its request for a power purchase agreement that would have provided guaranteed income for 3,100 MW of its generation in Ohio, AEP Ohio will get a hearing on a smaller proposal covering 440 MW it controls as part of the Ohio Valley Electric Corp.
The Public Utilities Commission granted the hearing request without discussion during newly installed Chairman Asim Haque’s first meeting last week.
PUCO has also said it would hear a revised plan from FirstEnergy. The hearings are not yet scheduled.
The Federal Aviation Administration has certified more than two dozen private airports in the state this year, giving landowners some leverage to keep new wind turbines at a distance.
The sudden popularity of private airports, which wind industry representatives deride privately as “shamports,” was triggered by a state law that went into effect in November that requires new turbines to be at least 1.5 nautical miles — 9,1000 feet — from a school, hospital or airport.
Most of the airports registered with FAA are turf runways mowed out of a pasture. “I don’t even like to fly,” said Jerry Condit, who registered Rooster Barn Regional and Condit Regional Airport on properties in Garvin County. “I’ve only ever been in an airplane but one time.”
Pipeline Developers to Face Project-Specific Regulations
The state Department of Environmental Quality instructed the builders of two proposed natural gas pipelines that they will need to meet erosion and sedimentation standards set specifically for their projects.
“The basic point here is we want to make sure that if we do end up with pipeline construction, that appropriate steps are taken to protect the environment around the commonwealth,” department spokesman Bill Hayden said. EQT, developers of the Mountain Valley Pipeline project, and Dominion, construction partner of the Atlantic Coast Pipeline, indicated they are willing to work under the conditions.
Both projects await FERC approval, and both are battling community opposition.
Wisconsin Power and Light has proposed a $12.9 million rate increase that includes a two-step boost to consumers’ monthly fixed-rate charge, from $7.67 to $18/month in 2018.
Under the plan filed with the Public Service Commission, the utility would boost residential rates by 4.7%, or an additional $4/month. Business customers’ rates would drop by an average 4%, and industrial customers would experience a 1.5% rate decrease.
WPL spokeswoman Annemarie Newman said the increase would fund environmental control projects at the Portage and Sheboygan power plants in addition to other investments. Newman said the filing is Alliant’s first residential rate increase request in six years. She said WPL’s residential customers pay the lowest bills in the state.
Xcel Energy has begun to replace about 25,000 old-fashioned city streetlights with more efficient LED technology.
Xcel’s Mike Herro said some 100-W streetlights are at least 30 years old, and LEDs provide better lighting at a lower wattage. “They don’t degrade in light quality, so at the end of their useful light quality, they’re still fairly bright,” he said.
The Public Service Commission approved the plan last year.
Xcel Energy has upped the ante in Lubbock Power & Light’s bid to disconnect from SPP and join ERCOT in 2019, asking FERC for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan.
The Minnesota-based company filed a request with FERC on May 24, asking the commission to approve the switching fee by Sept. 21 (ER16-1772).
Xcel made the filing on behalf of its Southwestern Public Service subsidiary, which serves LP&L’s load. It told FERC it was requesting the fee “to mitigate the impact of the LP&L disconnection on SPS’ other transmission customers” and recover the costs of transmission infrastructure built in the Lubbock area since the 1980s.
“If LP&L leaves the SPP regional grid, the costs of infrastructure installed to serve LP&L would be shifted to Xcel Energy’s remaining retail and wholesale customers,” Xcel said in a statement. It said LP&L’s move “will increase their rates unless the interconnection switching fee is implemented.”
LP&L is the third-largest municipal load-serving entity in Texas, providing electricity to the City of Lubbock in West Texas. It is interconnected to the SPS transmission system in SPP and announced last year it planned to join ERCOT in 2019, a move it said would reduce its annual energy and capacity costs by $60 million. (See Integrated System to Join SPP Market Oct. 1; Lubbock Looking at ERCOT.)
LP&L plans to take about 72% of its 605-MW peak load to ERCOT; about 172 MW would remain within SPP through SPS.
Xcel told FERC the load migration “would result in a shift of approximately $13.8 million of zonally allocated ‘sunk’ transmission costs per year to other wholesale and retail customers in the SPS zone of SPP” and “$4.5 million of regionally allocated costs per year to customers throughout the entire SPP region.”
The fee, Xcel said, would “obligate LP&L to hold the remaining wholesale and retail customers in the SPS zone harmless from sunk costs incurred to provide transmission service to LP&L’s load.”
Xcel is basing part of its argument on the exit fee paid to SPP by departing members. It told the commission the RTO does not “provide a mechanism for recovering such costs from wholesale customers or load-serving entities such as LP&L if they withdraw their loads from [SPP], even though the financial impact of such a withdrawal can be similar to that resulting from the withdrawal of an SPP member.”
The filing also said SPP has considered an addition to its Tariff that would have imposed a “network service termination costs” charge on customers withdrawing a portion of their load if it is not later served by another service agreement within the RTO. SPP said Friday the Tariff revision has never been approved by any of its organizational groups nor formally considered.
LP&L said it “is not currently, nor has it ever been, a member of” SPP, and noted it is “merely a customer” of Xcel.
The utility “does not believe that Lubbock ratepayers should be responsible for investments made by Xcel Energy or its subsidiary company beyond the conclusion of the current power agreement,” it said.
LP&L’s contract with Xcel expires in May 2019, at which point it said it will have “fully honored all contractual obligations.” The utility has also said it will continue to honor a 25-year power supply agreement beginning June 2019 for 172 MW.
The utility is currently completing an ERCOT interconnection feasibility study that would need to be approved by the Public Utility Commission of Texas. It said its board and the Lubbock City Council have determined joining the ERCOT market “was in the best long-term interest of the LP&L ratepayers.”
ERCOT Staff IDs Preferred LP&L Integration Option
Meanwhile, ERCOT staff Thursday shared a draft of its LP&L integration study that identified transmission facilities that would be required to connect the utility’s load and system, a 115/69-kV network with about 20 substations. The study will be filed with the PUC after it is first presented to ERCOT’s Board of Directors on June 14.
The analysis looked at more than 40 options, before settling on one of three preferred alternatives that staff said would “minimize societal costs.”
“The selection really came down to economics, capital costs and production costs,” Jeff Billo, ERCOT’s senior manager of transmission planning, told the Technical Advisory Committee.
Staff recommended “option 4ow” as the most efficient alternative, saying it aligned with a 2014 roadmap for future upgrades to accommodate the Panhandle’s vast wind energy resources.
The three alternatives cost between $312 million and $364 million, involving the construction of as much as 141 miles of 345-kV transmission lines. They would also allow up to more than 4,200 MW of energy to be exported from the Panhandle.
Dynegy announced Thursday that it would propose legislation with the Illinois General Assembly that would transition the entire state into PJM.
If passed, the Illinois Electric Generation Reliability Act would move the Commonwealth Edison and Ameren service areas in Central and Southern Illinois from MISO Zone 4 into the PJM power market. ComEd, an Exelon subsidiary, also serves load in the Chicago area, which is part of PJM.
Dynegy claims the bill would “provide economic benefits to consumers and help Illinois preserve vital, high-paying power generation jobs.” The company said cost-effective plants in MISO-controlled Southern Illinois “sit idle, or shut down, as they don’t receive any compensation to cover operating costs from MISO.”
Dynegy’s Baldwin Energy Complex in Illinois
Dynegy CEO Robert Flexon said a comparison of PJM’s recent Base Residual Auction outcomes alongside MISO’s Planning Resource Auction results in April illustrates the need to combine all of Illinois with PJM, even as two of Exelon’s nuclear generators in PJM failed to clear. (See PJM Capacity Prices Fall Sharply.)
“Illinois legislators have a great opportunity to take control of an issue that is debilitating communities across the state while at the same time bring lower power prices to consumers through a more efficient market design that can exist throughout the state,” Flexon said.
Illinois is the only state in MISO’s territory that fully offers retail choice. (Michigan currently allows 10% of its load to choose their suppliers.) The bifurcated nature of the state has caused controversy.
Zone 4’s high prices in last year’s capacity auction led to accusations by Illinois officials and stakeholders of market manipulation against Dynegy, which serves most of the load in the zone. Dynegy’s proposed legislation comes three months after the company responded to MISO’s request for auction reform suggestions by proposing a separate, PJM-style three-year forward auction for Zone 4. MISO is currently in the thick of contentious debate over this proposal. (See MISO Board Orders Negotiation in Longtime Auction Disagreement.)
According to Dynegy, Illinois legislators and labor leaders, including Senate Majority Leader James Clayborne and two Illinois branches of the International Brotherhood of Electrical Workers (IBEW), support the transition.
Clayborne pointed to MISO’s unpredictable results in the last two annual capacity auctions and said the legislation would remedy the “huge gap” in how generators in different regions of the state are compensated.
The disparity, he said, “is leading to the shutdown of generation in Southern Illinois, which is threatening electric reliability, jobs, taxes and related economic development. This legislation is designed to address this gap, level the playing field and ensure electric generation reliability, jobs and the economy are protected.”
Clayborne said that bringing downstate Illinois into the deregulated fold will bring congruity to the state.
Spokesmen from IBEW 702 and IBEW 51 said the bill would protect customers from high scarcity pricing, uphold statewide electric reliability and preserve jobs by stopping premature plant closures.
Exelon, Illinois’ other power-producing giant, also is seeking relief from state lawmakers. The utility is seeking low-carbon-emissions subsidies for nuclear generators in order to keep its cash-strapped Quad Cities plant operational through 2032, when the plant’s license expires.
The General Assembly’s legislative session ends May 31.
PJM’s second auction under Capacity Performance rules saw prices drop sharply as new gas-fired generation flooded the market. Exelon’s Quad Cities and Three Mile Island nuclear plants were among the plants that failed to clear, leaving them without any capacity revenue for delivery year 2019/20.
Capacity Performance prices fell in most of PJM by $65/MW-day, or 39%, to $100/MW-day compared with last year.
Prices in Eastern MAAC fell by nearly $106/MW-day, or 47%, to $119.77. Only the ComEd zone held its own, dropping just $12/MW-day, or 6%, to $202.77. Base capacity, limited to 20% of the RTO’s needs, came in at a $20/MW-day discount to CP. There were no locational constraints on base.
The auction will cost load a total of $6.9 billion in 2019/20, compared with $11 billion for last year’s auction for 2018/19.
Prices were depressed by new generation and a 1,200-MW reduction in load requirements as a result of a revised load forecast, said Stu Bresler, PJM senior vice president of markets.
The auction acquired 167,306 MW for delivery year 2019/20. That gives the RTO a 22.4% reserve margin, well above the target of 16.5%.
“Prices were lower than some analysts had expected and lower than last year’s auction results simply because of market fundamentals — changes in supply and demand,” Bresler said. “The load forecast is lower, and there was a large amount of new gas-fired combined cycle generation clearing for the first time in the auction.”
New Generation
In total, 6,543.5 MW (UCAP) of new generation offered into the auction including uprates. About 5,529 MW of the new generation cleared, mostly natural gas combined cycle and combustion turbines.
Based on prior experience most of the cleared new generators will meet their in-service dates. For example, 87% of the 4,575 MW of large, combined cycle units that cleared in the Reliability Pricing Model for 2015/16 are in service and the remainder are expected to be in service by mid-2017.
Cleared external generation dropped by 812 MW to 3,876 MW, a 17% reduction, while internal generation rose 1%. About 71% of the external generation was CP.
Like CP generation, base capacity generation is expected to be available throughout the delivery year, but unlike CP it is subject to nonperformance penalties only during the summer.
About 13,000 MW of new entry was granted an exception to the minimum offer price rule (MOPR), Bresler told the Markets and Reliability Committee on Thursday. No new entry was held to the MOPR.
Quad Cities, TMI Shut Out
Bresler called the results “extremely competitive.” He noted that fewer coal-fired and nuclear resources cleared the auction. Coal was down about 2,600 MW, and nuclear was down more than 1,500 MW, he said.
Exelon said all of its nuclear plants that offered cleared the auction except for Quad Cities, Three Mile Island and a portion of the Byron plant. Oyster Creek, which is scheduled to retire in 2019, did not participate in the auction.
Despite the news, the company said Byron is committed to operate through May 2020. The company has said it would close Quad Cities and the Clinton nuclear plant if it did not win financial support from the Illinois legislature before its session ends May 31. Exelon says the two plants have lost $800 million over the past seven years despite strong operating records.
Although Clinton cleared in MISO’s recent capacity auction, the company said its revenues will not be sufficient to earn a profit.
The company noted this was the second consecutive year that TMI Unit 1 failed to clear the PJM auction. “Although the plant is committed to operate through May 2018, the plant faces continued economic challenges and Exelon is exploring all options to return it to profitability,” the company said.
“The capacity market alone can’t preserve zero-carbon emitting nuclear plants that are facing the lowest wholesale energy prices in 15 years,” CEO Chris Crane said in a statement. “Without passage of comprehensive energy legislation that recognizes nuclear energy for its economic, reliability and environmental benefits to Illinois, we will be forced to close Quad Cities and Clinton.”
Dynegy, meanwhile, said it cleared a total of 9,804 MW at a weighted average price of $134/MW-day, worth $481 million for 2019/20. Dynegy’s PJM fleet cleared 9,187 MW at $137/MW-day and its Illinois Power Holdings will export 617 MW to PJM at $92/MW-day.
FirstEnergy declined to comment on how its plants fared in the auction. American Electric Power also made no announcements.
The two companies have been trying to win above-market purchase power agreements to support their struggling merchant fleets.
In its analysis of the auction results, UBS Securities said the depressed clearing price could spell trouble for generators looking for financial assistance. “As we have noted previously, lower capacity revenues place increased reliance on extra revenues from local customers under [FirstEnergy’s] revised PPA proposal, which could put the plan at higher risk of rejection. Similarly, we expect increased scrutiny of costs in Illinois as the legislature there continues to debate a clean energy credit for [Exelon’s] nukes.”
Demand Response, Energy Efficiency
Cleared demand response dropped to 10,348 MW, down about 7%, while energy efficiency soared almost 22%.
About 70% of the energy efficiency cleared as CP, with the remainder as summer-only base capacity. Only 6% of the DR resources qualified as CP, which must be available year-round.
DY 2019/20 will see a net increase of 84 MW of DR over 2018/19 and 312 MW of EE.
The low percentage of DR that cleared as CP should not be taken as a sign that the resource will struggle to participate in the auction when it moves to all CP in the 2020/21 delivery year, Bresler said Thursday.
“About 4,700 MW was offered that could be CP; it just didn’t clear that way economically,” he said. “I don’t think we should take these results as demand response can’t be CP.”
Renewables
Of the 969 MW of cleared wind resources, 89.4 MW cleared as CP (9%). The 969 MW represents 7,453.8 MW of nameplate capacity based on its 13% capacity factor.
About 335 MW of solar capacity cleared, compared to 184 MW last year, with only 0.4 MW clearing as CP (one-tenth of 1%). Based on its 38% capacity factor, the 335 MW represents 882 MW of nameplate solar. A total of 6,328 MW of new generation will be added in 2019/20, offset by the loss of 2,923 MW for a net increase of 3,405 MW.
Bresler noted that for the first time, one aggregated resource of renewable power offered into the auction, but he didn’t know if it cleared. Because there was only one, he wouldn’t identify it except to say it was in the renewable category, “and that’s bigger than wind and solar, it includes hydro.”
Analysts Predicted Price Drop
Analysts had predicted lower clearing prices for the auction, which began May 18.
Julien Dumoulin-Smith of UBS reduced his forecast CP price from $140/MW-day to $125/MW-day. He predicted higher prices in EMAAC, DPL-S, PS-N and PSEG at $200/MW-day and ComEd at $225/MW-day.
Morningstar’s model predicted that Exelon’s Quad Cities nuclear plant would not clear the auction.
The price cap was $448.95/MW-day, compared with $450.86/MW-day for the 2018/19 auction.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage. RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM Manuals (9:40-10:10)
Members will be asked to endorse the following manual changes:
Manual 11: Energy and Ancillary Services Market Operations. Resources that cannot reliably provide day-ahead scheduling reserve obligations in real time would be excluded from the process. They include nuclear units, dynamic transfers, run-of-river and self-scheduled pumped hydro units, wind units, solar units and non-energy resources. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)
Manual 14E: Merchant Transmission Specific Requirements. Reorganizes and updates the manual to reflect changes to the merchant network upgrade process approved in July 2015 by the MRC. Adds a new Section 2 that provides an overview of transmission interconnection customers proposing merchant transmission facilities upgrade projects.
Manual 36: System Restoration. Amendments incorporate lessons learned from the annual restoration drill as well as changes from a periodic review.
This problem statement and issue charge proposes to study the challenges associated with resources subject to pseudo-tie requirements that participate in the Capacity Performance market. (See “Study of Pseudo-Tie Standards for External CP Deferred,” PJM Markets and Reliability Committee Briefs.)
4. Real-Time Values (10:30-10:45)
Proposed changes to Manual 11: Energy and Ancillary Services Market Operations incorporate real-time values. Updates allow market seller to communicate unit’s actual operating parameters to PJM before and after the day-ahead market closes when the unit cannot operate. Stipulates that real-time values may be used to modify turn-down ratio, minimum run time, minimum down time, maximum run time, start-up time and notification time, and they can be made whole due to an actual constraint.
5. Transmission Replacement Processes Senior Task Force (10:45-11:00)
Members will be asked to approve the proposed charter for the Transmission Replacement Processes Senior Task Force, previously called the End of Life Senior Task Force.
6. Energy Market Uplift Senior Task Force (11:00-11:15)
Revisions to the Energy Market Uplift Senior Task Force charter incorporate a problem statement and issue charge regarding the review of virtual transaction rules.
7. Earlier Queue Submittal Task Force (11:15-11:30)
Members will be asked to approve the recommendations of the Earlier Queue Submittal Task Force. (See “New Project Submittal Process to Require Earlier Filing of Documents,” PJM Planning Committee and TEAC Briefs.)
8. Replacement Resources (11:30-11:45)
The committee will be asked to endorse a proposal by Barry Trayers of Citigroup Energy to add an acceptable reason for early capacity replacement.
9. Seasonal Capacity Resources Senior Task Force (11:45-12:00)
Members may be asked to approve clarifications to the previously approved distributed energy resources problem statement. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM Markets and Reliability Briefs.)
11. Joint-owned Resource Communication Model (1:00-1:15)
Members will be asked to approve revisions to Manual 14D Attachment L.
BOSTON — The New England Electricity Restructuring Roundtable met for the 150th time on Wednesday to celebrate some successes and discuss ways to continue moving the nation to a low-carbon future.
The meeting has grown from the small group of stakeholders that met in 1995 in the early days of electric industry restructuring. Last week’s session, organized by Raab Associates, filled a hotel ballroom with about 300 attendees.
Among the successes of the last 20 years: the growth of energy and capacity markets and an increasing reliance on clean energy sources and energy efficiency.
Attendees also expressed disappointment over challenges they thought would now be in the rearview mirror.
“We need to put a meaningful price on carbon. We can’t do anything unless we do that and it has to show up on” bills, said Susan Tierney, senior advisor at Analysis Group.
John Howe, senior advisor to Poseidon Water and former chairman of the Massachusetts Department of Public Utilities, agreed. “The single biggest failure was not to put a price on carbon,” he said.
While New England has cut emissions through the Regional Greenhouse Gas Initiative, the record is mixed.
“RGGI is a signal accomplishment,” said Richard Cowart, director of European programs for the Regulatory Assistance Project. “This is something that will be a lesson for the world — that carbon revenue is just as important as carbon pricing,” because it can be a source of investments to lower carbon emissions through energy efficiency programs and clean energy technologies.
RGGI’s trading prices have been far below EPA’s estimated “social cost of carbon,” however, and revenues from the program have been used to fill state budget shortfalls — not solely to support lower emissions.
Even if prices were higher, RGGI would be only a piecemeal solution, said William Hogan, the Raymond Plank professor of global energy policy at the Harvard Kennedy School.
“The scope of the [climate change] problem is enormous. And it’s worldwide. If you’re not doing it everywhere, you’re wasting your time,” he said. While the recent Paris Agreement shows some global movement, enacting a carbon tax in the U.S. to further its goals is “politically impossible,” he said.
But Hogan sees hope in some movement for more comprehensive tax reform in Washington. “On that day, they’re going to be doing 50 things that are politically impossible, individually, and I want to make sure a carbon tax is one of the 50.”
Despite some frustrations, Peter Fox-Penner, professor in the Questrom School of Management and director of Boston University’s Institute for Sustainable Energy, said there is promise in the future. “New England’s emphasis on renewable energy and energy efficiency shows industry is poised to meet the challenge of decarbonizing the sector while retaining reliability and affordability.”
But the role of natural gas as a “bridge” fuel to that future is a question, as carbon emissions in New England have ceased to fall. The potential loss of the region’s nuclear power fleet also could harm efforts to arrest climate change.
“The dash to gas was appropriate at the time … but the time is at hand to cross that bridge and now is the time to get to cleaner and more sustainable solutions,” Howe said.
But given the low price of gas and wide availability, political and cultural shifts may be needed to resist that temptation.
“The discipline to keep the natural gas in the ground is going to be one of the great challenges of the next generation,” Cowart said.
Below is a summary of rulings issued by FERC last week.
FERC Finalizes Hold-Harmless Rules
FERC issued a policy statement finalizing rules regarding the use of hold-harmless commitments to protect customers from rate increases resulting from utility mergers (PL15-3).
The commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under Section 203 of the Federal Power Act, but the commission hadn’t defined the costs with specificity, leading to inconsistencies.
The commission:
Clarified the scope and definition of the costs that should be subject to hold-harmless commitments;
Identified the types of controls and procedures that applicants offering hold-harmless commitments must implement to track the costs involved;
Clarified that an applicant may be able to demonstrate that the transaction will not have an adverse effect on rates without making any hold-harmless commitment; and
FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to approve NERC reliability standard BAL-002-2 (Disturbance Control Standard — Contingency Reserve for Recovery from a Balancing Contingency Event). The rule requires applicable entities to balance resources and demand, and return their area control error (ACE) to defined values following a disturbance. The commission required NERC to modify the standard to address concerns over extensions or delay of the periods for ACE recovery and contingency reserve restoration. It also directed NERC to address a reliability gap regarding power losses above the most severe single contingency (RM16-7).
Constellation’s Reactive Payments Cut Due to Retirements
The commission accepted a petition from Constellation Power Source Generation to reduce its revenue requirement for reactive supply and voltage control service by almost $225,000 as a result of the retirements of Riverside Unit CT 6 (June 1, 2014), Perryman Unit CT 2 (Feb. 1, 2016) and Riverside Unit 4 (planned for June 1, 2016). The commission also ordered hearing and settlement judge procedures to determine whether the company’s reactive power rate for its remaining fleet in the Baltimore Gas and Electric zones should be reduced further (ER16-746-001, et al.). (See Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants.)
SoCalEd Can Recover Abandoned Tx Project Costs
FERC ruled that Southern California Edison may recover abandoned plant costs for the canceled Coolwater-Lugo transmission project but set settlement and hearing judge procedures to determine how much of the $37 million claimed by the company was prudently incurred. The project was no longer needed after the retirement of NRG Energy’s 636-MW Coolwater Generating Station and three other generators. The Los Angeles Department of Water and Power and the M-S-R Public Power Agency challenged the $8.51 million in overhead costs that SoCalEd included in its claim, saying the company provided little documentation for how overhead costs were allocated to the project (ER16-1025).
Settlement on SSR Units OK’d
The commission approved an uncontested settlement reached among several Illinois companies and MISO that changes Illinois Power Holdings’ annual revenue requirement for the operation of Edwards Unit 1, a 90-MW coal-fired steam boiler in Peoria, Ill., designated as a MISO system support resource. The new annual revenue requirements will be $7 million for 2013, $11.1 million for 2014 and $6.5 million for 2015 (ER14-2619-004, et al.).
Rehearings Denied
The commission also:
Denied rehearing but granted clarification of its October 2015 ruling in Order 816, which amended its regulations governing market-based rate authorizations (MBRA). (See FERC Refines Market-Based Rate Rules.)
The commission clarified that qualifying facilities in RTOs and ISOs are exempt from reporting requirements on long-term firm energy and capacity purchases. The commission also said that it did not intend to change the definition of long-term firm transmission reservations: those longer than 28 days. It also offered clarifications regarding the definition of a seller’s relevant geographic market and said MBRA applicants and sellers will not have to comply with the corporate organizational chart requirement until the commission issues an order at a later date (RM14-14-001).
Denied rehearing of its October ruling exempting American Transmission Systems Inc. and Duke Energy companies in Ohio and Kentucky from certain MISO multi-value project (MVP) transmission charges. MISO and MISO’s Transmission Owners sought rehearing to assign a usage fee to ATSI and Duke for MVPs approved before the companies moved from MISO to PJM in 2011. In the rehearing denial, FERC pointed out that MISO’s MVP cost allocation on withdrawing members was instituted in 2012 and said charging the companies would violate its rule against retroactive ratemaking. The commission also rejected arguments that MISO’s Tariff at the time of ATSI’s and Duke’s exits could be interpreted to allow for MVP-related financial obligations (ER12-715-004).
Denied El Paso Electric’s request for rehearing of a November 2015 order that required prior approval for utilities to engage in simultaneous exchange transactions involving their marketing affiliate and its affiliated transmission provider’s system (EL10-71-002).
Denied rehearing of a September 2015 order allowing future affiliates of Kanstar Transmission to use the same formula rate and incentives approved for Kanstar (ER15-2237-002).
CAMBRIDGE, Md. — Two aides from the Senate Committee on Energy and Natural Resources gave PJM Annual Meeting attendees a behind-the-scenes look at the making of the Energy Policy Modernization Act of 2016 (S.2102), the Senate’s first major energy bill in nearly 10 years.
Patrick McCormick, chief counsel to Chairman Lisa Murkowski (R-Alaska), and Spencer Gray, an aide to ranking member Maria Cantwell (D-Wash.), were the featured guests in the second half of PJM’s general session. Moderator Craig Glazer, PJM vice president for federal government policy, promised the session would be “a cross between a high school civics lesson and ‘House of Cards.’”
Not ‘Revolutionary’
The bill passed the Senate on April 21 with a bipartisan vote of 85-12. To become law, however, it must be reconciled with a House bill that cleared in December with support from only three Democrats. (See U.S. Senate EnergyBill Faces Tight Calendar, Partisan Divide.)
Gray acknowledged the Senate bill didn’t contain the “revolutionary” changes of the 1992 Energy Policy Act, which mandated open transmission access and opened the industry to retail choice, or EPACT 2005, which created mandatory reliability standards.
But he and McCormick said it was nonetheless a victory over partisan gridlock — the product of weekly lunch and breakfast meetings between Murkowski and Cantwell, followed by several committee hearings and six weeks of bipartisan negotiations. It ended with a three-day markup at which some 90 amendments were considered. The final bill cleared the committee 18-4.
“I do think personal relationships matter,” Gray said. “The polarization in Congress … reflects, whether precisely or not, some level of polarization in the country. So it’s more difficult now I think to develop those relationships. And our bosses have worked hard at that.”
Section 4302 of the bill requires RTOs and ISOs to report to FERC on their reliability, capacity resources, wholesale electricity prices and generation diversity.
McCormick said the provision resulted from Murkowski’s concern over the loss of baseload and intermediate generation, an issue he said was brought to her attention by former FERC Commissioner Philip Moeller.
McCormick and Gray said the reporting requirement was a compromise between members who sought more prescriptive language and those opposed to federal mandates. (Separately, Murkowski and House Energy and Commerce Chairman Fred Upton (R-Mich.) also have asked FERC to study price formation. And the Government Accountability Office has begun a study at Congress’ direction to compare capacity markets in the Northeast to those in the Midwest.)
The aides noted that the 22-member committee — more than one-fifth of the Senate — is shifting from predominantly Western states but still dominated by members in regions without organized electricity markets.
‘Soft Touch’ or Not?
“We’re not well positioned to second guess individual provisions of market design, whether it’s capacity markets or energy markets or other provisions that RTOs and ISOs are considering,” Gray said. “So the approach that the committee’s taken on an issue like this has been a fairly soft touch.
“Members [of Congress] are very wary about having solutions from a particular region pushed, let alone forced on their region,” he added.
In a question-and-answer session, Marji Philips of Direct Energy took issue with the aides’ characterization of the reporting provision.
“It’s pretty widely admitted that that bill is the ‘Save the Nuclear and Coal Plant Bill,’” she said. “The language mirrors very closely PJM’s Capacity Performance requirements. And it’s great that it’s been turned from a mandate to a report, but … the report gets everybody abuzz almost as much as a mandate. So if MISO isn’t doing this or New York isn’t doing this — they all look at this and say, ‘I’m not going to be the one to report to Congress that we’re not meeting this Capacity Performance requirement.’ You actually really are in some ways imposing PJM on other regions through this legislation.”
Philips asked the aides to broaden the language in conference with the House to ensure a role for demand response, “so it doesn’t read that you must have … hard steel [in the ground] that runs baseload.”
The Planning Advisory Committee approved a recommendation that the RTO participate in a study identifying joint transmission needs along MISO’s seam with SPP’s Integrated System in North Dakota, South Dakota and Iowa.
The committee will vote on the motion via email, with results tallied at its June 15 meeting.
MISO staff last month recommended forgoing a coordinated study and focusing instead on improving the study process. SPP’s Seams Steering Committee voted in favor of embarking on a study. (See MISO, SPP Disagree on 2016 Joint Study.)
Eric Thoms, MISO manager of planning coordination and strategy, said the RTO has since adjusted its views, adding that a study focused on one target area would be more helpful than an all-encompassing study.
MISO PAC liaison Jeff Webb said the change resulted from stakeholder requests for some form of study with SPP despite the views of RTO staff.
MISO stakeholders recommended the RTO participate in a study identifying joint transmission needs along its seam with SPP’s Integrated System in North Dakota, South Dakota and Iowa. Map source: MISO
“It’s not a matter of us being tired of doing studies,” he said. “That’s what we’re here for.”
MISO is also open to a coordinated Clean Power Plan-related study in 2017 after regional needs are identified in MTEP 17.
Interregional process improvements will continue regardless of the study decision, Thoms said.
The committee rejected another motion submitted by the Transmission Developers sector that recommended that MISO perform a broader coordinated study to evaluate the “impact of higher renewable penetration [and] alternative transfer scenarios on interregional reliability needs and historical high congestion along the MISO North/Central and SPP seam.”
MTEP 17 Futures Finalized
MISO has narrowed its 2017 Transmission Expansion Planning (MTEP 17) to three futures, eliminating a limited carbon emission scenario determined to be too similar to an existing fleet future. (See MISO Proposes 3 New MTEP 17 Futures.)
MISO adjusted the existing fleet scenario after stakeholders pointed out that low natural gas prices increase activity in the industrial corridor of Zone 9 along the Gulf Coast. Additionally, no scenarios will assume the renewable tax credit extends beyond 2022, which stakeholders pointed out was an uncertainty.
The futures went through three rounds of formal review and “reflect a balance of stakeholder feedback [while] bookending uncertainty,” said Matt Ellis, a MISO policy studies engineer.
“Even if the [Clean Power Plan] stay is overturned, these three futures still make sense,” Ellis added.
The PAC will further discuss the MTEP 17 futures during its June and July meetings. Planning wraps up in September with a presentation of a finalized regional resource forecast.
MISO Releases EPA Air Pollution Rule Study and CPP Paper
While MISO states will be compliant with EPA’s updated Cross State Air Pollution Rule (CSAPR) in 2017 even without NOx emission trading, RTO staff say a regional trading arrangement would be the least expensive path to compliance.
That finding was the result of MISO’s own CSAPR study, according to Jordan Bakke, senior policy studies engineer for the RTO.
MISO studied three scenarios: a business-as-usual case; a no-trading scenario in which states strive for compliance individually; and seasonal NOx trading among MISO states from May to September.
Bakke noted that 11 of the 23 states affected by the CSAPR rule are in MISO.
MISO states can meet their 2017 seasonal NOx budget through a redispatch of natural gas for coal, but they would emit right up to their caps.
With no trading, MISO states emit up to their seasonal NOx emissions budgets. Under trading, several MISO states purchase allowances to emit over their budgets.
Under seasonal NOx allowance trading, MISO production costs increase $31 million compared with a business-as-usual case without rule compliance.
If MISO states fail to adopt trading, overall costs rise, with Arkansas carrying the brunt at nearly $200 million in production, interchange and emission costs to achieve 2017 compliance. With emissions trading, Iowa carries the largest cost, at less than $25 million.
MISO used its 2015 Transmission Expansion Plan and 2017 forecast data to inform modeling, which included 2017 retirements and a projected $2.64/MMBtu Henry Hub price for natural gas. Current emissions-control technology was assumed to remain in place, with CSAPR compliance achieved only through energy and emission trading.
Footprint Diversity Study Timeline Accelerated
Stakeholders say MISO’s proposed footprint diversity study should begin sooner than the RTO first suggested. The study would examine the benefits of expanding flows on the constrained transmission interface linking the RTO’s North/Central and South regions, including exploring the option of building new transmission. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
MISO Director of Policy Studies J.T. Smith said the RTO will scope out a study process beginning in the fall, with a study targeted to begin in 2017. The Economic Planning Users Group will evaluate scope development.
The Public Service Commission approved a request from Ameren Missouri to increase its Energy Efficiency Investment Charge. The line item that appears on electricity customers’ bills will increase by about $2.22/month beginning in June.
Representatives of the renewable energy industry and Bozeman city officials joined forces last week to launch a campaign pushing the state to tap into its potential for wind and solar production.
A dozen lawmakers have introduced legislation to codify Gov. Andrew Cuomo’s goal of completely eliminating the state’s greenhouse gas emissions by 2050.
After withdrawing its request for a power purchase agreement that would have provided guaranteed income for 3,100 MW of its generation in Ohio, AEP Ohio will get a hearing on a smaller proposal covering 440 MW it controls as part of the Ohio Valley Electric Corp.
The Federal Aviation Administration has certified more than two dozen private airports in the state this year, giving landowners some leverage to keep new wind turbines at a distance.
The state Department of Environmental Quality instructed the builders of two proposed natural gas pipelines that they will need to meet erosion and sedimentation standards set specifically for their projects.
Xcel Energy has begun to replace about 25,000 old-fashioned city streetlights with more efficient LED technology.
