Thirteen municipally owned electric systems in Massachusetts have asked FERC to reduce the return on equity earned by New England transmission owners (EL16-64), the fourth such challenge in ISO-NE since 2011.
The Eastern Massachusetts Consumer-Owned Systems, a group of municipal distribution companies that surround Boston, want the base ROE lowered from 10.57% to 8.67%. They also called for reducing the upper end of the zone of reasonableness, which serves as a cap on incentive adders, to no more than 11.24%, from the current 11.74%.
EMCOS said it brought the new complaint for several reasons, including the continuing decline in the cost of equity capital since FERC adopted a two-step discounted cash flow (DCF) model in Opinion 531, the 2014 ruling that resulted from the first of the four recent challenges (EL11-66-001). (See FERC Splits over ROE.)
They also cited “divergent commission rulings” since Opinion 531, noting administrative law judge findings of “anomalous” capital market conditions in cases involving MISO (EL14-12-002) and ISO-NE (EL14-86, EL13-33-002) and a finding that such conditions did not exist in one concerning Entergy Arkansas (ER13-1508, et. al). “This complaint offers an opportunity to reconcile these decisions,” the group said.
It also said it is unclear “the extent to which the commission’s anomalous-conditions rationale in Opinion No. 531 is intended to reflect changes in its long-standing reliance on the DCF methodology, and particularly the DCF midpoint, for determining ROE.”
Commission action is pending on the two other New England dockets cited by the group, following a proposed decision by an administrative law judge in March. The ALJ recommended an ROE for two time periods that was lower than what transmission owners sought but higher than what states and commission trial staff advocated. (See New England ROEs Set in Initial Decision.)
FERC staff last week released a draft environmental impact statement on Atlantic Sunrise Project, finding that the natural gas pipeline expansion would result in “some adverse environmental impacts” but that they would be “less than significant” following mitigation measures (CP15-138).
Atlantic Sunrise Project Map Source: Williams
Williams has proposed expanding its existing Transcontinental Gas Pipe Line (Transco) from the Marcellus Shale area in northern Pennsylvania to its southeastern market. The 198 miles of additional pipeline would deliver an incremental 1.7 million dekatherms/day of year-round firm transportation capacity.
In making its determination, staff considered that about 28%, or 55 miles, of the project would be within or next to existing infrastructure rights of way. Proposed mitigation measures by Williams, along with recommendations by FERC staff, would minimize impacts on natural and cultural resources during construction and beyond, staff said.
The Atlantic Sunrise Project consists of 184 miles of greenfield pipeline and 11.5 miles of looping pipeline in Pennsylvania. Williams would also replace 2.5 miles of pipeline in Virginia.
The project also involves two new compressor stations, two new meter stations and three new regulator stations in Pennsylvania, along with infrastructure improvements that also would affect Maryland, North Carolina and South Carolina.
Williams expects the project to be in service in the second half of 2017. Comments on the draft EIS are due by June 27.
MISO is considering changes to its proposed forward capacity auction for Southern Illinois in the face of opposition from stakeholders and Independent Market Monitor David Patton.
In addition, MISO staff have again postponed a FERC filing seeking approval for seasonal and locational capacity constructs in order to gain more buy-in from market participants.
Patton last week told the Resource Adequacy Subcommittee (RASC) that the auction plan — which would procure Zone 4’s local capacity requirement three years in advance and all other capacity in the prompt-year auction — will fail to optimize procurement or provide accurate pricing and efficient transfers between zones.
“You can’t bifurcate this market and have any hope of establishing an efficient price,” Patton said.
Patton said the plan will result in underprocurement and depressed forward prices in competitive retail areas because the “optimal procurement level in the competitive retail area is likely higher than the minimum requirement.” While Patton thinks the residual prompt auction could be optimized, he said that still would fail to correct prices and procurement volume in the forward auction.
The Monitor had other general criticisms of forward procurement, saying units can’t “intelligently” decide to retire or suspend four years in advance. New resources, meanwhile, are unlikely to enter the auction at competitive prices close to the cost of new entry because clearing guarantees only one year of revenue. As a result, those investing based on expectations of future revenue will offer as price takers, close to zero, and those seeking to maximize the one year will offer much higher than CONE. (See PJM-Type Capacity Auction for MISO Zone 4 Proposed.)
The Monitor recommended that MISO instead introduce a sloped demand curve for the local requirement in the competitive retail areas and jointly optimize the amounts procured inside and outside of the competitive retail areas on a prompt-year basis.
MISO: Auction a ‘Continued Evolution’
Jeff Bladen, MISO executive director of market services, offered possible adjustments to the proposal, telling the RASC that auction design is “a continued evolution.”
MISO staff could alter the plan so that the full forward procurement occurs in a separate auction — or altogether eliminate the forward auction and revert to prompt-only procurement. Under the former scenario, MISO would consider enacting a minimum offer price rule to combat price distortion for competitive retail areas.
Bladen said MISO is “seriously considering” assigning risk of congestion to the buyer, in scenarios in which retail areas are subject to a full forward procurement.
“If you run a forward auction, you need to think about access to the transmission system and congestion costs,” Bladen said.
MISO must also prevent “infeasible procurement” because of high congestion, Bladen said, pointing out that market participants that self-schedule already face risk that congestion will render their procurements unusable. “This is not a new design element to think about,” he added.
Bladen said MISO could either constrain transmission availability through forward-looking modeling or keep the current modeling based on local clearing requirements.
Patton countered that MISO’s option to procure the full planning requirement for the competitive retail area in the forward auction cannot be reasonable because it would “divorce the procurements and prices from MISO’s true reliability needs.”
The Monitor also cautioned against MISO’s ambitious timeline for rolling out the proposal and the resources that will be required: “It took New England years to set up their forward procurement. They virtually worked on nothing else.”
Bladen also said MISO is considering instituting a fixed resource adequacy plan requirement preventing market participants from “opportunistically toggling in and out” of the auction and causing price volatility.
Patton said “it would be best” if auction opt-in and opt-out provisions did not exist so that prices will reflect the true supply and demand in the area.
Mark Volpe, Dynegy senior director of regulatory affairs, said it was “encouraging” to see MISO and the Monitor move away from dependence on a local clearing requirement.
“Dynegy has preferred a forward auction, but that preference has always been predicated on if price formation is right,” Volpe said. “It would be preferable to have a prompt auction where the price is correct, rather than a forward auction where the price is wrong. You have to have that price formation correct before you get into the timing.”
Exelon’s Marka Shaw echoed the Monitor’s timeline concerns, saying more time was needed for discussion. “We’re facing very real and serious decisions … and it’s clear it’s not serious to others,” she said, referring to MISO staff’s insistence that a July filing is still feasible.
Seasonal, Locational Filings Delayed
MISO RASC liaison Renuka Chatterjee said the RTO is willing to postpone its planned May Tariff filing on seasonal and locational capacity constructs and use June to further explore the filings.
“What do you need to get comfortable with the proposal, and what language do you think the proposal lacks?” Chatterjee asked stakeholders.
“We’re looking for time to discuss alternatives to the proposal,” said David Sapper of Customized Energy Solutions. “Frankly, if MISO isn’t willing to discuss material changes, we don’t need that time. I don’t think that you’re offering anything that we’re seeking.”
Chatterjee said MISO has already provided justification for concepts such as using two seasons instead of four. “You might not like our answers, but to the extent that we didn’t answer anything, please let us know,” she said.
Stakeholders also denied a motion from East Texas Electric Cooperative urging MISO to move ahead with a seasonal filing.
ERCOT said last week continued growth in natural gas and renewable energy capacity will help it meet its projected summer peak this year — and demand well into the next decade.
According to its final summer Seasonal Assessment of Resource Adequacy (SARA) released last week, ERCOT has 78,434 MW of generation capacity, more than enough to meet a projected peak demand of 70,588 MW. If reached, the projected peak would break last year’s record peak of 69,877 MW. While last year’s summer was only the 17th hottest on record, Texas’ economic growth has helped boost demand.
The available capacity includes 680 MW of new gas generation expected to begin operating before the peak, which generally occurs in August. Also available will be 410 MW of planned wind and 7 MW of planned grid-level solar capacity. The new capacity more than makes up for the loss of a 371-MW gas unit near Houston. ERCOT said Friday that NRG Texas Power had announced it would mothball the unit indefinitely effective June 27.
“Gas is one of our more efficient and economical generation sources at this time,” said Pete Warnken, ERCOT’s manager of resource adequacy.
ERCOT bases its summer forecast on weather patterns in June to September from the past 13 years. Senior meteorologist Chris Coleman said that while the region is transitioning away from El Niño weather patterns, “we could see some temporary, localized hot periods” in the Rio Grande Valley and West Texas.
The ISO also released its biannual Capacity, Demand and Reserves (CDR) report, a “snapshot” of existing and planned generation and load forecasts for the next 10 years. The report shows planning reserve margins ranging between 15.9% and 25.4%. The ISO has added almost 1,000 MW of new generation since September, but because much of it is renewable energy, it has a peak capacity contribution of about 250 MW.
The CDR report reveals a 1,700-MW drop in generation capacity since December, but based on current planning criteria, ERCOT projects nearly 6,200 MW of new gas-fired generation by summer 2018 and 7,400 MW in new capacity by 2020. Additional unit retirements are not reflected in the planning horizon.
The report also projects about 11,000 MW of planned wind generation by 2019, adding nearly 1,800 MW in expected capacity during summer-peak conditions.
Warren Lasher, ERCOT’s director of system planning, added a note of caution into the otherwise rosy predictions.
“This report also includes generation resources that could be affected by environmental regulations, and future decisions by resource owners may impact these projected planning reserve margins,” he said.
The report does not take into account the proposed 2019 integration of Lubbock Power & Light into the ERCOT system “due to uncertainty regarding the regulatory outcome.”
The Texas grid operator also released its preliminary fall SARA, covering October and November. That assessment foresees 82,737 MW available to meet a normal fall demand of 54,437 MW.
ERCOT staff conducted a market continuity workshop last week as a first step in addressing a “lack of market restart procedures.”
The ISO has black start, business continuity and crisis communication plans in place, but it lacks clear protocols or operating guide language to recover from a market outage, according to ERCOT. Staff has developed draft procedures to address gaps but has been tasked by the Technical Advisory Committee to gather stakeholder input.
The workshop focused primarily on how to best restart the real-time and day-ahead markets following an outage. Stakeholders also discussed how to handle credit policies, financial transactions and retail-transaction processing during interruptions and subsequent restoration periods.
Resmi Surendran, senior manager for wholesale market operations, said ERCOT has protocol language covering security constrained economic dispatch (SCED) or brief market failures. But staff wanted to provide more clarity to language governing more significant market downtime, she said.
“If we go for a month without a market, which is possible, what happens?” Surendran asked. “Will people be able to get their money? How do we pay the generators that must still run?”
ERCOT is proposing to start the real-time market first and then the day-ahead market. “Once we see the real-time market is stable … and we can model the topology and credit correctly, then we can start the day-ahead market,” Surendran said.
Staff will update the TAC in the near future and request guidance on next steps. Feedback and questions can be sent to Karen Farley.
ERCOT Moving to Internet Explorer 11
ERCOT is upgrading its browser to Microsoft’s Internet Explorer 11. Staff says projects that use browser services will be updated to be compatible with IE 11. At the same time, ERCOT is ending its support for older versions of Internet Explorer and will no longer build projects that are backwards compatible to IE 8.
NYISO asked FERC Thursday to approve Tariff revisions that would make it easier for generators to get a place in the transmission queue “class year” (ER16-1627).
The ISO’s large facility interconnection procedures require generators to complete a three-step study process, starting with a high level feasibility study, which evaluates the configuration and local system impacts, followed by a system reliability impact study (SRIS), which evaluates the project’s impact on transfer capability and system reliability.
Finally, the class year study evaluates the cumulative impact of a group of projects that has completed similar milestones. This study identifies the upgrades needed to interconnect the project and maintain reliability.
In order to preserve its place in the transmission queue and enter the class year study, the project must acquire necessary permits from the state within two years of the NYISO Operating Committee deeming its application complete following an SRIS.
The state permitting process for generators over 25 MW “is a relatively new power plant siting process that ‘front loads’ much of the process,” the ISO explained. “As a result, there are concerns that projects may not be able to reach the ‘completed application’ stage in time to enter a desired class year study, despite having an Operating Committee-approved SRIS.”
NYISO cited a recent example in which a generator needed a FERC waiver to enter the class year study. On April 1, FERC granted the 33-MW Dry Lots Wind project in Herkimer County a waiver allowing it to join the study despite lacking a state siting board permit (ER16-1047). In granting the waiver, the commission cited its expectations of the ISO’s pending Tariff filing.
The proposed Tariff changes would extend the deadline for meeting the regulatory milestone requirement to 90 days after the start of the third class year study following the OC’s SRIS approval.
“This gives additional time for the project to meet the regulatory milestone while not permitting the project to remain in the queue indefinitely,” NYISO said. “This revision will help minimize delays to projects that are close to completing their regulatory milestone when a class year study begins. If a project provisionally enters a class year study, it will be withdrawn from the class if its regulatory milestone is still not met after the 90th day.”
NYISO asked for acceptance of the revision by July 5.
CAISO’s Board of Governors last week approved an ISO plan to temporarily alter market operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility.
CAISO is proposing to reserve capacity on the Path 26 transmission line in advance of potential gas restrictions in Southern California. The measure is meant to ensure delivery of energy into the region when constrained fuel supplies threaten to limit output from local gas generators. Source: CAISO
The proposal calls for new market rules to help Southern California’s gas-fired generators better manage their burns to avoid system-balancing penalties expected to go into effect June 1 — just ahead of the state’s peak season for electricity consumption.
Under the new requirements, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s gas-fired generators say the costs could make them unprofitable when ISO dispatch instructions require their units to burn more — or less — gas than planned for on a given operating day.
“We want to ensure the generation can get” into Southern California, Cathleen Colbert, CAISO senior market design and regulatory policy developer, told a Market Surveillance Committee meeting last month. “That’s why deliverability was the focus.”
Thus, CAISO’s plan takes a systemwide response to gas restrictions, although provisions for recovery of penalty costs are included in the proposal.
When gas flows are restricted the ISO would enforce a gas availability market constraint for generators in a constrained region. The constraint would use the day-ahead or real-time market to cap the gas burn in the affected area below system limitations set out by SoCalGas. Any additional generation needed would only be dispatched through out-of-market operations coordinated with the pipeline operator.
The ISO would also implement a protocol to reserve capacity on the Path 26 transmission line in advance of potential gas shortages, a measure intended to leave enough of a buffer to ensure delivery of energy and contingency reserves into the Los Angeles basin when local resources face curtailment. CAISO decided against implementing a similar procedure along the interties into California because of the current low volume of real-time transfers on those lines.
Additional operational measures proposed by the ISO include:
Reducing the amount of ancillary services procured from Southern California resources based on expected gas and electric system conditions;
Deeming selected internal transmission constraints uncompetitive when the proposed gas availability constraint is in effect, thereby freeing up resources to serve the affected region; and
Clarifying CAISO’s authority to suspend virtual bidding when it identifies potential market inefficiencies.
The ISO is also proposing to allow an affected generator to recover increased gas costs by adjusting the gas component of its day-ahead commitment cost bid cap to up to 175% of the gas index price, compared with 125% today. Gas cost caps included in default energy bids used in the real-time market would be increased from 125% to 200% of the index.
CAISO must now seek FERC approval for the plan. All proposals are set to sunset Nov. 30.
PJM is prepared to meet the power needs of its 61 million consumers this summer, when demand is expected to peak at 152,131 MW, the RTO said last week.
There is 183,912 MW of installed generating capacity available, plus 8,700 MW of demand response.
“With continued transmission enhancements, reinforced capacity commitments and slowing forecasted load growth, we’re prepared to meet the region’s needs,” said Mike Bryson, vice president of operations.
The Public Utilities Regulatory Authority approved “near historic” low rates starting July 1 for the standard offers from the state’s two electric utilities, thanks to depressed natural gas prices.
The standard rate for Eversource Energy customers will drop from the current 9.555 cents/kWh to 6.606 cents. United Illuminating customers will see their standard rate decrease from 10.7358/kWh to 8.0224 cents.
Dave Thompson, a utilities examiner with the state Office of Consumer Counsel, said utility industry officials “haven’t seen prices like this since 2003-04.”
The developers of what would be the state’s largest solar energy farm won vital support from the city of Sanford, where it will be built on vacant land at the municipal airport.
The Sanford City Council authorized a lease allowing Ranger Solar to build a 50-MW photovoltaic array on 226 acres. Ranger intends to start construction in 2018. The project will include 176,000 solar panels.
Ranger estimates that the project will add $29 million in taxable investment to the city, as well as millions of dollars in rent if the lease is extended to the maximum 40-year term stipulated in the agreement. The project still requires environmental permitting from the state and an interconnection agreement with ISO-NE.
Bill to Mandate Offshore Wind Purchases Coming Soon
Pacheco
Legislators will introduce a bill as soon as this month that will require utilities to purchase energy from offshore wind farms, according to Bloomberg News.
Wind developers are pushing for a mandate for utilities to buy 2,000 MW over 10 years. Proponents have said such a guaranteed market would spark an offshore wind-building boom. Three wind development companies have secured federal offshore leases near Martha’s Vineyard: DONG Energy, Deepwater Wind and Offshore MW.
“We have the opportunity to create an industry,” Sen. Marc R. Pacheco said. “We have the opportunity to create thousands of jobs and create a whole supply chain.”
Gov. Maggie Hassan recently signed a bill setting a new net metering cap in the state, and the available capacity for larger projects is already nearly consumed.
The law allocates about 40 MW to smaller projects for homes and businesses and 10 MW for larger projects. Eversource Energy, which was allocated 7.8 MW, already has a waiting list of 7.2 MW worth of projects and another 7.8 MW still in development.
For the second time, Gov. Chris Christie has vetoed a bill that would have paved the way for Fishermen’s Energy to build a 25-MW offshore wind farm near Atlantic City.
Although the project received a $47 million grant from the U.S. Department of Energy, Christie and the Board of Public Utilities have criticized the project as too costly for customers, who would help fund the project through bill surcharges. Christie also argued that the bill “would usurp BPU’s authority” and strip its discretion for “managing energy matters.”
Christie signed a bill six years ago mandating offshore wind with a goal of developing 1,000 MW by 2020, but the BPU never created a funding mechanism that would make such projects economically feasible.
Trust Fund Would Stimulate Clean Energy Technology
The Senate is considering a proposal that would provide loans and loan guarantees to stimulate the clean energy sector.
The bill, S-684, would finance a trust fund through raising an existing surcharge on customers’ bills, called the “societal benefits charge.” That has raised concerns with the business community and the Division of Rate Counsel.
The fund would target investments in clean energy research, promote manufacturing for new and existing technologies and support the development of a clean energy curriculum at universities.
Duke Energy Progress is asking state regulators to require opponents of a new power plant near Asheville to put up a $50 million bond if they appeal regulatory approvals. The company said that delays would drive up construction costs by as much as $140 million.
Environmental groups say that amount is just to prevent them from taking appeals to court. “We aren’t asking them to delay anything,” said Jim Warren, executive director of NC WARN. The groups said an appropriate bond would only be $250.
Duke called that “absurd,” saying the company’s customers needed adequate protection from potential construction delays for a $1 billion project. Duke wants to start construction in October.
OG&E Admits Including Legal Fees, Lobbying in Rates
Oklahoma Gas & Electric acknowledged that the company’s customers have been paying the legal fees for shareholders of the utility’s parent company for the past 11 years and agreed to reduce its rate-increase request.
As hearings opened before the Corporation Commission on OG&E’s $92.5 million rate case, a company witness acknowledged the utility had improperly included the legal fees for the OG&E Shareholders Association in customer rates. The issue came to light after an audit by the commission’s public utility division and questions by the attorney general’s office, which represents ratepayers in utility cases.
The utility has agreed to lower its rate request by about $275,000 to reflect the incorrect allocation. It also agreed to reduce it another $20,000 for “legislative activities” that should have been paid by parent OGE Energy instead of ratepayers.
Gov. Tom Wolf has nominated senior adviser David Sweet to serve on the Public Utility Commission.
Sweet, a Democrat, was a state representative from 1977 to 1988 and has advised Wolf on energy and economic development matters since April.
He also has served on the Banking and Securities Commission and as a liaison to the Philadelphia Regional Port Authority. Sweet will need to be confirmed by the Senate.
Majority of Residents Want CPP Compliance Plan Developed
State residents believe their leaders should draw up a plan to shift from coal-fired power to natural gas and renewables, even if the state wins a high-profile battle against the federal Clean Power Plan, according to a new poll.
Two Republican pollsters developed and conducted the survey of more than 800 registered voters on behalf of the Texas Clean Energy Coalition, a group that supports natural gas, solar and wind energy. It offers insight into residents’ views on energy policy and a test of how public opinion compares to the rhetoric of politicians on the issue.
Among the findings, 85% (including 81% of Republicans) believe the state should develop its own comprehensive clean energy plan, regardless of the outcome of a lawsuit over the Clean Power Plan, and 69% believe their leaders should construct a proposal to comply in case the state loses its court battle.
The Senate last week approved a modified version of a bill giving towns more say over renewable energy projects, but action by the House of Representatives is uncertain.
Rep. Tony Klein, a Democrat and chairman of the House Natural Resources and Energy Committee, said he wanted the attorney general’s office to weigh in before agreeing with Senate language on regulating sound from wind towers.
The Senate version of the bill calls for the Public Service Board to issue new rules on noise levels by July 1, 2017.
Appalachian Power Developing 100% Renewable Offering
Appalachian Power has informed the State Corporation Commission that it is developing a pure alternative energy rate for its customers. It said it has seen a higher demand for renewable energy from its customers and is seeking a way to offer a 100% renewable product.
The company said it is seeking more sources of renewable energy to be able to provide a rate that will reflect the use of renewables around the clock.
“We do know that it will be set up as an annual review situation where we’ll look at the cost every year and adjust the cost to the customer every year,” said John Shepelwich, a company spokesman.
Citizen Groups Criticize Mon Power, Potomac Edison IRP
Critics are calling an integrated resource plan put forth by FirstEnergy utilities Mon Power and Potomac Edison “a thinly disguised attempt to pave the way” to buy a coal-fired power plant from an affiliated company, Allegheny Energy.
Two citizen groups are urging the Public Service Commission to force the utilities to rewrite the plan, saying the cost of the purchase would fall to customers.
MISO is seeking stakeholder input on how to revise its energy offer cap rule while awaiting guidance from FERC for developing a final rule.
“If we have some of the groundwork laid out for the final rule, we’ll be in better shape,” said Chuck Hansen, a MISO senior engineer.
The RTO has queried market participants about changing the operating reserve demand curve and whether to remove — or increase — the $3,500/MWh LMP cap.
This winter is likely to see a repeat of the “temporary” solution implemented the past two years, in which the RTO used revenue sufficiency guarantees to cover costs exceeding the offer cap. (See MISO: No Change to Energy Offer Cap this Winter.)
In January, FERC issued a Notice of Proposed Rulemaking that would require offers more than $1,000/MWh be verified before being used to calculate LMPs. Offers not verified in time for market clearing would become eligible for a make-whole payment. (See FERC Proposes Uniform Offer Cap Across RTOs.)
Market participants became concerned about the hard cap in 2014 when natural gas demand spiked during extreme cold. Although inefficient generators were called up, offers more than $1,000 never materialized.
“The MISO market is becoming more and more dependent on natural gas,” Hansen explained. “The problem with this is if we actually clear and commit these units,” their costs would be higher than offers allow.
While MISO generally supports FERC’s proposals, it prefers that administrative caps be gradually relaxed to provide incentives for competitive offers so the need for “artificial, administrative caps” would disappear, Hansen said.
“We thought [FERC’s NOPR] was a reasonable compromise between protecting customers and potential exercise of market power, [and it] sets appropriate prices during periods of high fuel cost,” Hansen said. “Eventually we’d like to see the offer caps be relaxed to the point where they’re not getting in the way of valid offers.”
MISO said that over time, new technologies and new demand response will supplant offer caps with more efficient pricing during scarcity situations.
MISO currently uses a $3,500/MWh LMP cap, which reflects the cost of firm load shedding. Hansen said that amount is adequate — for now.
“The $3,500/MWh works with the current experience, but there’s not a lot of room,” Hansen said.
Hansen said MISO must consider the different verifiable costs among external asynchronous resources, hydro, storage, demand response, imports and virtual supply.
‘Modest’ Price Impacts as Extended LMP Enters Phase 2
Extended locational marginal pricing (ELMP) will enter a second phase of implementation despite its limited effect on energy prices a year after its introduction.
ELMP is intended to improve the way the security economic dispatch (SCED) algorithm calculates LMPs and sets market-clearing prices. The practice was designed to reduce uplift charges by allowing certain fast-start resources that are either offline or scheduled at their limits to set clearing prices.
Clearing prices under SCED often fail to compensate fast-start units for their start-up costs, necessitating use of revenue sufficiency guarantees.
According to MISO market design engineer Congcong Wang, stakeholders generally support roll-out of the second phase, which will allow 30-minute fast-start resources into the program. Currently, only real-time scheduled units with 10-minute start times and an hour or less of minimum runtime are eligible to set real-time energy prices under ELMP.
Wang said the inclusion “captures more fast-start schedules.” Including resources with a 60-minute start time would not make as much of a difference on prices, she said.
Wang noted that stakeholders also want offline units included in the price-setting process if those units “appropriately reflect system conditions.”
In the meantime, MISO is studying cases from last winter to evaluate price impacts and determine if offline fast-start resources are “truly available and economic.” Wang also said MISO will create a “recommendation tool” that lists eligible ELMP offline fast-start resources for operators to manage shortages or congestions.
MISO will present its findings at the August Market Subcommittee meeting.
MISO Independent Market Monitor David Patton said ELMP’s impact on prices has been “modest.” (See MISO Monitor: Extended LMP Changes Minimal Thus Far.) The practice only lifted real-time prices by about a penny per megawatt-hour in spring 2015, and reduced them by almost 8 cents in summer and 3 cents in fall. Day-ahead market impacts were even lower.
That minimal effect was a product of the limited number of units eligible to set prices under ELMP, Patton said. Units with a 10-minute start time account for just 2% of total peaking resources.
Patton advocates expansion of ELMP, saying MISO could capture 90% of peaking units in the real-time market if it expanded the practice to include resources with two-hour minimum runtimes and 30-minute startup times, as well as those committed in the day-ahead market.
“There’s no clear reason for day-ahead units not to contribute to price setting,” Patton said. He said no software changes would be required if MISO allowed 30-minute fast-start resources — representing 12% of peakers — to be eligible in the second phase of ELMP.
However, the Monitor recommended suspending offline price-setting in LMP, saying that although the offline units are economic, “analysis indicates that the units setting prices are rarely utilized.”
Sunset on Financial Transmission Rights Working Group
The MSC approved retirement of the Financial Transmission Rights Working Group and will absorb tasks associated with financial transmission rights and auction revenue rights.
Working group Chair Brad Arnold said the group agrees with a MISO proposal last month to sunset the group.
“The only request was stakeholders continue to have access to FTR reports and continued MISO support,” Arnold said.
Zakaria Joundi, MISO liaison to the working group, said a decrease in agenda items and stable FTR funding prompted the move. He added that MISO will continue to post FTR and ARR reports on a monthly basis as needed.
Joundi also noted that MISO subject matter experts will respond to inquiries about the reports, and that the RTO could always create a task team in the future if a specific FTR issue arises.
The developers of an underwater transmission project that would deliver hydroelectric and wind power into New England filed for permits last week for the New York section of the project (16-T-0260).
Anbaric Transmission and National Grid filed for a certificate of environmental compatibility and public need with the New York Public Service Commission for their Vermont Green Line. The project would connect 400 MW of wind generation to be developed in northern New York to Vermont through buried lines under Lake Champlain. The wind power would be supplemented by hydropower from Quebec, to provide firm power to ISO-NE.
The northern New York-Vermont border runs down the middle of the lake. The HVDC system would run from the New York Power Authority’s Plattsburgh substation in Beekmantown, Clinton County, to Vermont Electric Power Co.’s New Haven substation in Addison County. The New York portion of the project includes 6.7 miles of buried HVDC cable from a converter station to the shoreline of Lake Champlain at Point Au Roche State Park and about 4.9 miles underwater on the New York side of Lake Champlain.
The Vermont section of the project will include 35.2 miles of underwater HVDC cable, a converter station and 13.3 miles of buried line to the New Haven substation.
The project will also need approval from the Vermont Public Service Board. Bryan Sanderson, senior vice president of Anbaric Transmission, told RTO Insider on Wednesday that the companies plan to file with Vermont this summer.
Invenergy is developing the Bull Run Wind Energy Center in Clinton County, pending approval from state regulators. The proposed development would have as many as 140 turbines, with an in-service date projected for 2019.
The overall project, with energy also supplied by Hydro-Quebec, has been dubbed the “wind-hydro response” to the request for proposals solicited by three New England states to procure renewable energy for the region. The proposal is one of about 30 submitted to Connecticut, Massachusetts and Rhode Island now under review. (See State-Sponsored Energy Procurement Moves Ahead in NE.)
The hydro generation would flow into New York via a transmission connection between Hydro-Quebec and NYISO at Chateauguay, Quebec, according to Sanderson.
If the project is selected, the developers would then file with FERC for negotiated rate authority, he added.
“We think the Vermont Green project is well timed to provide the region with a reliable, clean energy source of hydro firming wind,” Sanderson said.
While the wind project is aimed at the New England market, developers say it will provide benefits to New York as well, including meeting the state’s goal to procure 50% of its energy from renewable sources by 2030.
“The project will provide an ‘energy bridge’ that will allow additional development of new wind energy in upstate New York that would otherwise be constrained and uneconomic given the existing infrastructure for delivery to load centers in New York,” according to an economic analysis filed with the NYPSC.
When the hydroelectricity from Canada is more than what is needed to firm the wind energy destined for New England, that excess would be available to the New York market, according to the analysis.
Jeff Bladen, MISO executive director of market services, offered possible adjustments to the proposal, telling the RASC that auction design is “a continued evolution.”
According to its final summer Seasonal Assessment of Resource Adequacy (
The Public Utilities Regulatory Authority approved “near historic” low rates starting July 1 for the standard offers from the state’s two electric utilities, thanks to depressed natural gas prices.
The developers of what would be the state’s largest solar energy farm won vital support from the city of Sanford, where it will be built on vacant land at the municipal airport.
For the second time, Gov. Chris Christie has vetoed a bill that would have paved the way for Fishermen’s Energy to build a 25-MW offshore wind farm near Atlantic City.
Duke Energy Progress is asking state regulators to require opponents of a new power plant near Asheville to put up a $50 million bond if they appeal regulatory approvals. The company said that delays would drive up construction costs by as much as $140 million.
Oklahoma Gas & Electric acknowledged that the company’s customers have been paying the legal fees for shareholders of the utility’s parent company for the past 11 years and agreed to reduce its rate-increase request.
Appalachian Power has informed the State Corporation Commission that it is developing a pure alternative energy rate for its customers. It said it has seen a higher demand for renewable energy from its customers and is seeking a way to offer a 100% renewable product.
Critics are calling an integrated resource plan put forth by FirstEnergy utilities Mon Power and Potomac Edison “a thinly disguised attempt to pave the way” to buy a coal-fired power plant from an affiliated company, Allegheny Energy.
Anbaric Transmission and National Grid filed for a certificate of environmental compatibility and public need with the New York Public Service Commission for their Vermont Green Line. The project would connect 400 MW of wind generation to be developed in northern New York to Vermont through buried lines under Lake Champlain. The wind power would be supplemented by hydropower from Quebec, to provide firm power to ISO-NE.