The average real-time price of wholesale power in New England fell by more than a third last year, according to the 2015 Annual Markets Report by the Internal Market Monitor of ISO-NE.
Prices dropped more than $22/MWh to $41, as the average price of natural gas fell 41% to $4.73/MMBtu in 2015, from $7.99/MMBtu in 2014.
The report by the Monitor said the wholesale power markets operated competitively last year. The prices of both natural gas and wholesale power were the lowest since 2012, with natural gas generating 49% of the electricity produced in the region.
“Natural gas prices fell last year with increased domestic production, above-average storage levels nationally and mild weather that moderated demand for natural gas for heating and power generation for most of the year,” said Jeffrey McDonald, ISO-NE’s vice president of market monitoring. “Because of the moderate demand, there was sufficient space in the region’s natural gas pipeline infrastructure to deliver low-priced natural gas to the region’s generators. The New England markets were competitive in 2015, as demonstrated by the close linkage between natural gas and wholesale power prices.”
The Monitor also reported that total costs — including energy, capacity, ancillary services and transmission — fell about 25%, from about $12.4 billion in 2014 to about $9.3 billion in 2015.
At 126,833 GWh, total electricity usage in New England was 0.3% lower in 2015 than in 2014.
Delaware Gov. Jack Markell, the state’s congressional delegation and LS Power are among those asking FERC to revisit its April 22 ruling approving solution-based distribution factor (DFAX) cost allocation for the Artificial Island and Bergen-Linden Corridor projects.
Salem Nuclear Generating Station Source: Wikimedia
A request for rehearing was filed by the public service commissions of Delaware and Maryland, whose electricity customers will pay for the bulk of the work to upgrade the New Jersey complex that houses the Salem and Hope Creek nuclear reactors. That’s because the Delmarva peninsula is the sink point for the new transmission line that will link Artificial Island with the Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines in Delaware, and thus the target of the DFAX methodology.
In its 3-1 ruling, with Commissioner Cheryl LaFleur dissenting, FERC said it “found that where a cost allocation method is accurate in a very high percentage of circumstances to which it applies, then it is a strong indicator that the cost allocation method is just and reasonable” (EL15-95, ER15-2563). (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)
No Free Pass
The complainants said that’s not good enough.
“The Federal Power Act does not provide the commission with a free pass on its obligation to ensure just and reasonable rates for the ratepayers in Delaware and Maryland simply because the commission previously approved a cost allocation methodology that works for other projects and other ratepayers,” said LS Power, one of the developers of the Artificial Island stability fix.
“The presence of the facility ensures reliable delivery of power and alleviates future reliability concerns and violations that could have otherwise caused operational issues equally, or in fact more so, to a large segment of the grid beyond Delaware and Maryland, and those beneficiaries are not identified by solution-based DFAX and therefore are not paying their appropriate share for the reliability benefits received,” LS Power said.
Since FERC’s order, the estimated cost of the Artificial Island project has ballooned, with Public Service Electric and Gas nearly doubling the cost of its work from $137 million to $272 million. (See Cost Estimate of PSE&G Portion of Artificial Island Fix Doubles to $272M.) LS Power has stood by its cost cap of $146 million.
In addition to the requests for rehearing, the Delaware Division of the Public Advocate wrote to the PJM Board of Managers asking it to cancel the project.
“The DPA exhorts the PJM board to re-evaluate its approval of the project in light of the staggering increase in the cost of the PSE&G portion of the project,” wrote Public Advocate David Bonar. He said the updated cost estimates more than double the Delmarva zone’s share with an increase of $107.4 million.
Commercial electricity consumers could see their bills increase by $50,000 per month, he said, while residents would see about a $13 hike.
“The DPA is not asking PJM to do something it has never done before,” he said. “After reconsideration, PJM canceled the Mid-Atlantic Power Pathway and the Pennsylvania-Allegheny Transmission Highway projects.”
The PSCs’ filing was submitted also on behalf of the Delaware Division of Public Advocate, the Maryland Office of People’s Counsel, Old Dominion Electric Cooperative and the Delaware Municipal Electric Corp.
The parties challenged FERC’s factual findings and legal conclusions and said the DFAX cost allocation would violate precedent and produce unjust and unreasonable rates.
In a letter supporting the filing, Markell said, “The commission’s order will have a significant direct negative impact on customers in the Delmarva zone and on the economy of the region. Several manufacturing facilities have already expressed concerns about the impact the added costs will have on their operations.”
U.S. Sens. Tom Carper and Chris Coons and Rep. John Carney also wrote to FERC in support of a rehearing.
“The current cost allocation results in over 90% of project costs being borne by Delmarva zone customers in exchange for just a small portion of the project benefits,” they said. “This cost distribution is not sustainable for Delaware users and could seriously impact the state’s ability to recruit and retain industry.”
The issue of cost allocation for the Artificial Island stability fix and Bergen-Linden Corridor transmission project was the topic of a January FERC technical conference, called after the commission determined the DFAX method may be unjust and unreasonable in some cases. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?)
As with the Artificial Island project, the factors surrounding the project have changed since FERC’s ruling.
Consolidated Edison, to which PJM assigned $629 million of the costs of PSEG’s $1.2 billion upgrade, recently decided to stop using the “wheel” by which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)
“The order states that the purpose of the Bergen-Linden Corridor project is to facilitate the Con Edison wheeling arrangement,” Hudson Transmission Partners wrote. “The Con Edison wheeling arrangement has been terminated. Moreover, Linden VFT, HTP and others brought this likelihood to the commission’s attention on the record in this proceeding, but the commission entirely ignored these facts.
“It is now a reality. Therefore, the very basis upon which the Bergen-Linden Corridor project was founded … and presumably the basis for allocating most of the project’s costs to Con Edison (as, presumably, the beneficiary), has fundamentally changed. Initial analyses by PJM, which were also presented to the commission, indicate that most of the costs previously allocated to Con Edison will now be shifted to HTP.”
The NYPA wrote that it expects its cost allocation associated with the BLC project to increase from about $100 million to more than $600 million.
“The BLC project costs that will be allocated to NYPA following termination of the Con Edison wheel are so grossly disproportionate to the total value of NYPA’s firm export rights on the HTP line that NYPA will be forced to pursue all of its options, which may include termination of the [firm transmission withdrawal rights] it has contractually acquired from HTP, if it cannot mitigate its exposure to [Regional Transmission Expansion Plan] costs in some other way,” it said.
“Given the significant cost of the BLC project, the economic stakes are high,” the NYPA said. “Further ramifications should be expected if rehearing is not granted.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee endorsed the Wholesale Market Subcommittee’s recommendation to increase the fuel adder factor for coal- and lignite-fired resources to $1.10/MMBtu from $0.50/MMBtu. The committee added a sunset date of June 1, 2018, and directed the subcommittee to continue developing a permanent solution to address changing coal prices.
“Given the ongoing pressures in the coal markets, we’d like to see additional work on getting an indexed price for coal, like we have for gas,” Austin Energy’s Barksdale English said. “We’d like to get something a little more dynamic that reflects ongoing changes in the market.”
Citigroup Energy’s Eric Goff said any “hard-coded dollar amount[s]” included in ERCOT’s protocols should be handled “with great caution.”
“If we hard-code that amount, we should make sure it expires,” Goff said. “We’re talking about costs, but not costs we get from market prices. It’s important generators can recover their costs.”
The recommendation was one of two verifiable cost manual revision requests (VCMRRs) brought to the TAC by the WMS. VCMRR 009 was also endorsed, with one abstention; it clarifies the calculation of the minimum requirements fee assessed to qualified scheduling entities based on the total amount of fuel purchased and transported.
TAC Sends 12 Revision Requests on to Board
The TAC unanimously endorsed a nodal protocol revision request providing improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. The committee, however, asked that more information on the matter be brought back to the committee.
NPRR 758 would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes. Determining who develops the outage list and who reviews it will be part of the “homework” that TAC Chair Randa Stephenson, of the Lower Colorado River Authority (LCRA), asked to be brought back to the committee.
“I’m expecting the primary focus of this to be transparency … not to make it more difficult for me to get the transmission I need,” American Electric Power’s Richard Ross said during the discussion.
“The idea is you may not have as much visibility of the problems you create in the market,” said Morgan Stanley’s Clayton Greer. “LCRA may have a 169-kV switch causing millions in congestion, but the wires side has no concept. You’re taking outages, but Oncor may be taking outages at the same time. That could cause major market disruptions.”
The NPRR was developed following a year of work by a task force focused on outage-coordination improvements. It has an estimated cost impact to ERCOT of between $300,000 to $400,000, but the spending won’t happen until 2017, when improvements to the Outage Scheduler system are expected to be completed.
The TAC also briefly discussed NPRR 766 before giving it a unanimous endorsement. The revision request aligns ERCOT’s systemwide discount factor with a proposed operational adjustment to the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation, ensuring consistency with a proposed timeline for changes to the RDF. (See “Reserve Discount Factor Proposal,” ERCOT Technical Advisory Committee Briefs.)
The committee changed the effective date from July 1 to Oct. 1, giving staff additional time to analyze the results of this summer’s RDFs. The PRC used a 2% discount factor last year; ERCOT has proposed a 1% factor.
The committee unanimously endorsed seven other NPRRs, a pair of revision requests to the Commercial Operations Market Guide and a revision to the Nodal Operating Guide, and a system change request:
Nodal Protocol Revision Requests
NPRR 709: modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
NPRR 754: revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
NPRR 761: clarifies that a resource will not be eligible for make-whole payment start-up cost compensation in the day-ahead market when the market considers the resource as not having a start-up cost.
NPRR 762: removes references to the provision of responsive reserves across DC ties.
NPRR 763: corrects the formula for calculating qualified scheduling entities’ load-allocated monthly block load transfer amount to reflect a charge, rather than a payment.
NPRR 764: changes calculations for charges to entities short their capacity obligations in the reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
NPRR 765: eliminates publisher names for various fuel prices and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
COPMGRR 041: updates to reflect current ERCOT and market participant practices for market notices.
COPMGRR 042: updates to reflect the Market Data Working Group’s creation and the Profiling Working Group’s responsibilities.
Nodal Operating Guide Revision Request
NOGRR 050: removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.
System Change Request
SCR 790: adds an additional level of geographical granularity — the Panhandle/North area — to existing reports for wind energy production and forecasts.
The TAC once again tabled, this time for two months, whether to consider an appeal of NOGRR 149. The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission-operator services from a third-party provider if their annual peak is less than 25 MW.
The Reliability and Operations Subcommittee rejected the NOGRR in March.
Transmission Reports Endorsed
ERCOT staff shared two reviews of planning projects designed to address reliability and import issues in the high-growth Rio Grande Valley region along the Texas-Mexico border. The TAC endorsed both reviews, though each received a pair of abstentions.
Jeff Billo, ERCOT’s senior manager of transmission planning, said staff’s voltage and transient stability review of the Valley Import Regional Planning Group project narrowed 10 solutions down to a preferred option: a $91 million project to add two static VAR compensators capable of handling an additional 2,800 MW of summer peak load.
The project review was driven by competing project proposals from AEP and Sharyland Utilities-CPS Energy, designed to meet a 2011 report that identified upgrades needed in the region by 2020. Direct Energy’s 2014 announcement that it would disconnect from ERCOT and begin dispatching its 524-MW Frontera combined cycle plant to the Mexican market only increased the urgency.
ERCOT’s review assumed six LNG plants proposed for the Port of Brownsville would add 2,400 MW of load but that a 780-MW generation project would also be built.
“We recognize that if the additional generation doesn’t show up, we may be back asking for additional upgrades,” Billo said.
Staff also reviewed AEP’s proposed project to address reliability needs in the North McAllen-Edinburg area. ERCOT’s planning group is recommending an option that will add two new 345-kV lines, a 345-kV double-circuit line, two 345/138-kV transformers and various other improvements at an estimated cost of $51.5 million.
ERCOT’s analysis did not account for the roughly 50 MW of distributed generation in the valley because “DGs are not dispatchable by ERCOT,” Billo said. “They’re not price-sensitive to the LMPs.”
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.
CAMBRIDGE, Md. — State consumer advocates last week pressed the PJM Board of Managers to change Capacity Performance rules to allow more participation by seasonal resources.
At the annual meeting between the board, consumer advocates and environmental groups, the advocates and environmentalists joined in calling for PJM to consider a seasonal capacity construct that would allow more participation by demand response, energy efficiency and solar resources.
The meeting filled a large ballroom at the PJM Annual Meeting. Increased funding for the Consumer Advocates of PJM States (CAPS) allowed more representatives to participate, with 11 of PJM’s 13 states and D.C. attending. (See FERC Approves PJM Funding of Consumer Advocates.) The meeting was also marked by an impassioned plea from Delaware officials for relief from the cost allocation for the Artificial Island transmission project.
The Capacity Performance rules include the option to aggregate summer and winter resources into a single capacity offer. But no aggregated offers were submitted in the first Base Residual Auction with CP last year, for delivery year 2018/19. Base capacity resources, which permitted summer-only DR, will be eliminated with next year’s auction for 2020/21.
“Aggregation can work for an owner that has both ends of the seasonal resource,” CAPS Executive Director Dan Griffiths said. “But when you have different owners, you have liability issues and allocation issues that are just frightening. So we have to admit that we do need seasonal resources.”
Brian Lipman, litigation manager for the New Jersey Division of Rate Counsel, said PJM must “find a way to work these resources into the mix so that we’re not paying for the next [generation] unit that’s not only higher in price but more likely more damaging to the environment.”
Speaking for the Public Interest and Environmental Organization User Group, Jennifer Chen, of the Sustainable FERC Project, praised PJM for its new load forecasting methodology but also called for capacity rule changes, noting that only 13% of cleared DR in last year’s auction qualified as CP.
The Seasonal Capacity Resources Senior Task Force has been meeting since early April to discuss the issues. (See “Seasonal Resources in the Capacity Market to be Studied,” MRC & Members Committee Briefs.)
The task force’s problem statement said the inquiry was necessary because of the elimination of base capacity and changes to measurement and verification for non-summer CP demand resources. “Through these two changes, demand resources, energy efficiency, solar and other resources that are either exclusively or primarily available in the summer season may no longer be able to meaningfully participate in PJM’s capacity market,” it said.
PJM CEO Andy Ott said creating separate summer and winter capacity products would require changes to how capacity costs are allocated, which is currently based on five coincident peaks. Changing the methodology, he said, would concern industrial customers and other loads.
But Ott said he has asked staff to consider “where the rules need to evolve for demand response. There has been at least a two-year period of significant uncertainty.” That ended with the Supreme Court’s ruling in January upholding FERC jurisdiction over DR in wholesale markets. (See Supreme Court Upholds FERC Jurisdiction over DR.)
Pairing up Resources
Ott said PJM also is considering modifying the aggregation rules in a way that would not force summer or winter resources to enter into contracts and share risks. “Some type of mechanism where we pair them up and assign their value,” he explained.
At a later “Year in Review” session, Independent Market Monitor Joe Bowring said PJM could consider a seasonal or even monthly capacity product. But, he cautioned, “if it’s going to be done it should be done comprehensively — not for a single product.”
At the same session, Stu Bresler, senior vice president for market operations expressed concern that a two-season construct could “undermine long-term price signals.”
That brought a retort from Marji Philips of Direct Energy: “Come on, New York is a month, guys!” — a reference to NYISO’s monthly capacity auctions.
At the earlier session, New Jersey’s Lipman also expressed concern over the handling of external capacity resources, saying that consumer representatives supported tightened rules knowing it would likely increase prices. “At this time, we now understand that MISO is not going along with the plan [the way] we thought they would,” he said. “We hope both regions will come together and find a way to resolve this issue.” (See “Ready for Pseudo-Tie Switchover,” MISO/PJM Joint and Common Market Meeting Briefs.)
Jackie Roberts, director of the West Virginia Public Service Commission’s Consumer Advocate Division, said PJM could help consensus-building efforts by appointing formal facilitators independent of the RTO and with no stake in the outcome of deliberations.
“The PJM folks who are trying to facilitate in the stakeholder process do have a stake in the outcome, so that makes it very difficult,” she said. “Traditionally what people do is those that like PJM’s proposal all line up with PJM to talk about options, and those that don’t don’t have anyone to talk to.”
Delaware Public Advocate David Bonar and Deputy Advocate Ruth Ann Price called on PJM to provide their state — PJM’s smallest — relief from the more than $100 million bill it faces from the Artificial Island stability project. A PJM study found that the Delmarva Peninsula — Delaware and the eastern shores of Maryland and Virginia — would pay about 89% of the project’s costs while receiving little more than 10% of the annual load payment savings from the upgrade.
“It’s vitally important to our state that this project be as inexpensive as it possibly can,” Bonar said. “Some of my ratepayers are looking at 30% increases in their rates and that to me is unconscionable.”
The costs “are on the verge of devastating,” Price said.
“As I keep telling my CAPS members, there’s a transmission project coming to you and it may also affect you in the same way,” she said. “None of us want to see a headline that says ‘PJM Bankrupts Delaware.’”
PJM Chairman Howard Schneider responded that “we’re not trying to build a gold-plated grid. We’re trying to get a grid that is reliable and responsive at the least possible cost — and we are cognizant of those costs,” he said.
Prices dropped more than $22/MWh to $41, as the average price of natural gas fell 41% to $4.73/MMBtu in 2015, from $7.99/MMBtu in 2014.
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.
