MISO told stakeholders last week that its own data set might have been partly to blame for generators not responding efficiently to dispatch instructions.
Steve Swan, MISO senior manager of dispatch and scheduling, said part of the problem was the timing of the RTO’s unit dispatch system, which previously captured generator output measurements prior to the end of a five-minute settlement interval in order to inform the next dispatch. Swan said MISO moved the timing forward about 40 seconds — but still prior to the end of the five-minute period — to ensure that results contain the most up-to-date dispatch information to avoid improperly restricting generator movement.
The RTO hopes the new timing will reduce the likelihood that a generator mistakenly appears to be lagging based on a dispatch estimate that lacks the most up-to-date information. The change took place Dec. 15.
“I don’t know if it’s going to solve all of the problems, but at least now when they see a generator not moving at the offered ramp rate, it’ll not be because of MISO instructions,” Swan said during the Jan. 5 Reliability Subcommittee meeting.
MISO currently marks generators off-control — online but not dispatchable — if they fail to follow set point instructions and do not move on their offered ramp rate.
Swan said MISO will compare data before and after the change to determine whether any lags remain and the RTO needs to pursue the issue further.
Independent Market Monitor staff member Michael Wander said that — even after the change — there will be some degree of lag that will be “practically impossible” to eliminate. Still, he thinks the change will bring an improvement.
The Monitor’s 2012 State of the Market Report suggested that MISO develop better tools to identify units that are derated or not following dispatch so that they may be placed off-control. That suggestion was included among other recommendations for improving thresholds for uninstructed deviations. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)
MISO Reports Successful November
MISO reported a smooth November in its latest monthly operations roundup, with markets performing as expected.
Above-average temperatures during the month contributed to an average 68 GW of load and a peak load of 81.9 GW on Nov. 21. November gas prices averaged $2.44/MMBtu, down 16.2% from October.
The month was free from any minimum or maximum generation events or warnings, but MISO on Nov. 12 earned the lowest unit commitment performance rating for the month, with committed but unnecessary resources remaining online to meet minimum run-times.
The RTO on Nov. 28 hit a new 13.3-GW wind production record, which was surpassed Dec. 7 when output reached 13.7 GW.
FERC Liaison: No Commission Disruptions
Chris Miller, FERC liaison to MISO, told stakeholders that the commission will continue to operate as a three-person panel in the near term.
“They all work very well together and have gotten a lot of work done,” Miller said of commissioners Norman Bay, Colette Honorable and Cheryl LaFleur.
Honorable’s term ends in June, but she is eligible to serve until the end of the year under a grace period if the Senate is unable to confirm a replacement, Miller noted. He said FERC staff are prepared for the impending leadership change, and as direction changes are the norm at the commission, the agency expects no delays in work output. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
The embattled Indian Point nuclear plant will close by 2021, owner Entergy and New York Gov. Andrew Cuomo said Monday morning.
An agreement between the governor’s office and Entergy calls for the company to shorten its pending license renewal applications to six years, with both sides ending litigation they have filed against each other as part of the deal. The state reserved the right to begin new litigation if necessary.
Unit 2 would shut down in April 2020, followed a year later by the closure of Unit 3.
“For 15 years, I have been deeply concerned by the continuing safety violations at Indian Point, especially given its location in the largest and most densely populated metropolitan region in the country,” Cuomo said in a statement. “I am proud to have secured this agreement with Entergy to responsibly close the facility 14 years ahead of schedule to protect the safety of all New Yorkers.”
Cuomo said that his administration has been “aggressively pursuing and incentivizing the development of clean, reliable energy” and that the state is “fully prepared” to replace Indian Point’s output at a “negligible cost” to ratepayers.
An agreement to close the two units — which combined have more than 2,000 MW in generating capacity — was first reported by TheNew York Times on Friday.
Entergy said energy economics driven by low natural gas prices forced the closure, which will mark the company’s exit from the merchant power generation business.
“Key considerations in our decision to shut down Indian Point ahead of schedule include sustained low current and projected wholesale energy prices that have reduced revenues, as well as increased operating costs,” Bill Mohl, president of Entergy Wholesale Commodities, said in a statement. “In addition, we foresee continuing costs for license renewal beyond the more than $200 million and 10 years we have already invested.”
Mohl noted that regional power prices have fallen by about 45% over the past 10 years to an average of $28/MWh, largely the product of record low gas prices stemming from increased supply out of the Marcellus Shale formation.
“A $10/MWh drop in power prices reduces annual revenues by approximately $160 million for nuclear power plants such as Indian Point,” Mohl said.
The agreement would allow the plants to operate for two additional two-year increments — with final closure slated for 2025 — if an emergency affected reliability in the New York City area.
Both units, whose permits expired in 2013 and 2015, have applied for 20-year license extensions from the Nuclear Regulatory Commission, which has granted the extensions pending review. Under the agreement, Entergy will instead apply for a six-year license renewal.
The plant has had a series of mishaps in recent years, intensifying pressure from state officials.
“Shutting down the Indian Point power plant is a major victory for the health and safety of millions of New Yorkers and will help kick-start the state’s clean energy future,” Attorney General Eric T. Schneiderman said.
Among the many challenges he has filed against the facility, Schneiderman has sought to deny Indian Point state water quality permits. (See Loss on Water Permit a Setback for Indian Point Extension.) New York will issue a coastal zone certificate and water quality permit for the plant as part of the settlement.
Schneiderman and environmental group Riverkeeper were also parties to the settlement.
“This agreement is a win for the safety of our communities and the health of the Hudson River, and it will pay big dividends in new sustainable energy sources and the well-paying jobs that come with them,” Riverkeeper President Paul Gallay said in a statement.
Other aspects of the agreement include:
Annual safety inspections by the state, along with the transfer of used fuel to protective storage in dry casks, the preferred method of safely storing spent fuel;
A commitment by Entergy to offer plant employees new jobs at other facilities, while the state will offer employment assistance and worker retraining, including for new skills needed for employment in the renewable energy sector; and
A requirement that Entergy establish a new emergency operations center in nearby Dutchess County, as well as create a $15 million fund for environmental projects.
Entergy’s previous agreements to make payments in lieu of taxes to local government entities and school districts will continue through 2021. Those agreements will persist before being gradually stepped down at a negotiated level following shutdown. The state will also work with local communities to address potential revenue shortfalls, enacting programs similar to those implemented for other communities affected by plant closures through the existing fossil fuel plant retirement fund.
New York has committed to a 50% renewable energy power mandate by 2030, with nuclear power seen as a bridge until clean power sources can be built at sufficient scale.
“With the news that the Indian Point nuclear power plant will close by 2021, New York should look to wind power, solar power and offshore wind to meet electricity needs, rather than relying more on natural gas,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “New York essentially has five years to get new renewable energy online to meet this demand, and the renewable energy industry is more than ready.”
The state Public Service Commission has said the closure will have minimal impact on customer bills, with adequate resources expected to be online by 2021. Transmission upgrades and energy efficiency measures totaling 700 MW are already in place, officials said. (See FERC OKs Settlement for NY TOTS Projects.)
“The NYISO is required to perform an electric system reliability impact analysis after receiving an official retirement notice for any bulk system generation asset,” NYISO spokesman David Flanagan told RTO Insider. “Additionally, the NYISO’s Comprehensive Reliability Plan, to be issued in July 2017, will consider future grid reliability needs and generation capacity margins over a 10-year time horizon under expected system conditions.”
Indian Point’s closure will mark Entergy’s exit from the merchant power business. In little more than two years, the company has shuttered the Vermont Yankee nuclear plant in Vermont and announced the closures of two other nukes, including Pilgrim in Massachusetts and Palisades in Michigan. The sale of New York’s James A. FitzPatrick nuclear plant to Exelon is pending. The company has also sold a natural gas-fired power plant in Rhode Island.
Entergy said it will record a non-cash impairment charge of approximately $2.4 billion pre-tax and $1.5 billion after-tax in the fourth quarter of 2016. It also expects additional charges totaling about $180 million for severance and employee retention costs by the end of 2021.
The company said it has invested $1.3 billion in Indian Point in the 15 years it has owned the plant.
Mountain West Transmission Group has said it will enter discussions with SPP to explore the possibility of joining the RTO.
The announcement comes eight months after Mountain West issued a request for information to CAISO, MISO, PJM and SPP regarding tariff administration and market operator services to support a new — and independent — organized market for the region. (See Mountain West RTO Could Pose Competition for CAISO.)
“By exploring membership with an existing RTO, the Mountain West participants would have the advantage of an existing electricity market design,” the group said in a statement issued Friday.
“We have enjoyed working with the Mountain West Transmission Group on preliminary analysis and look forward to the next phase of more detailed discussions on specific terms of membership in the SPP organization,” SPP CEO Nick Brown said.
An independent effort would put Mountain West in direct competition with CAISO’s plans to expand into the interior West through the possible inclusion of PacifiCorp as a member. SPP’s westward movement could have a similar impact on CAISO’s expansion.
Mountain West — a partnership consisting of seven different transmission-owning entities within the Western Interconnection, including the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage Project — has been investigating the benefits of implementing a common transmission tariff across multiple states and developing an organized market.
Mountain West’s footprint covers most of Colorado and Wyoming, along with smaller areas of Arizona, Montana, New Mexico and Utah. WAPA operates nearly 5,000 miles of transmission lines within the area.
Other members of the group include Basin Electric Power Cooperative, Black Hills Energy, Colorado Springs Utilities, Xcel Energy’s Public Service Company of Colorado, Platte River Power Authority, and Tri-State Generation and Transmission, which together control about 11,000 miles of transmission.
“Participation in a regional market can provide operational efficiencies through economies of scale and increased opportunities to bring lower-cost renewables into our system,” Platte River CEO Jason Frisbie said.
“Like our decision to join SPP for our east-side power supply, this announcement reflects years of diligent work and analysis by our employees and the Mountain West team,” said Paul Sukut, CEO of Basin Electric.
Steve Beuning, Xcel’s director of market operations, said the discussions will be a “crucial step in evaluating the potential benefits of a regional energy market.” Xcel has been a strong advocate for an organized market in the interior West to improve integration of its generation portfolio heavy in wind resources.
Mountain West expects to reach a decision whether to join SPP by midyear and is targeting 2019 for market implementation, subject to stakeholder input and necessary approvals.
“While Mountain West is optimistic that an RTO may benefit its entire membership, each Mountain West participant will ultimately need to evaluate for itself whether potential membership makes sense,” the group said.
In the event that negotiations with SPP are unsuccessful, Mountain West could pursue similar discussions with MISO and PJM, the group said.
SPP has filed an application with the Department of Energy seeking permission to transmit electricity from the U.S. into Canada, using member Basin Electric Power Cooperative’s existing transmission facilities in North Dakota.
SPP’s proposed exports to Canada would be transmitted via a North Dakota transmission line owned by Basin Electric Power Cooperative, which has previously been granted export authorization. | Basin Electric
The RTO wants to supply power on an emergency basis for five years, exporting surplus energy in excess of SPP’s load requirements. According to the filing, Basin Electric’s facilities were previously authorized by a presidential executive order and “are appropriate for open access transmission by third parties.”
SPP said Thursday that it wants to “address emergency assistance transactions,” but that it doesn’t normally purchase or sell power to or from “such external entities.” In December 2015, it completed its first — and only — international transaction when it imported power from Canadian electric utility SaskPower during an emergency situation in North Dakota. (See SPP, SaskPower Make First International Trade.)
SPP made the filing Nov. 14 pursuant to Section 202(e) of the Federal Power Act. It was published in the Federal Register on Jan. 4.
The Energy Department will evaluate environmental impacts and determine whether the proposed action will negatively affect U.S. electric supplies or reliability before issuing a final opinion. International energy transactions fall within the department’s jurisdiction.
In March, FERC approved the RTO’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)
SPP gained an interconnection with Canada when Basin Electric became a member in October 2015 as part of the Integrated System.
SPP stakeholders agreed on Wednesday to amend a two-year-old policy paper and clarify when FERC approval would be needed to allocate costs for some seams projects between 100 kV and 300 kV.
The Seams Steering Committee voted 6-1 in favor of the change.
The change clarifies that the RTO will recover costs for seams projects greater than 300 kV under its regionwide highway cost allocation methodology. Costs for projects lower than 300 kV would also be allocated under highway funding unless the project meets certain criteria. In those cases, the Regional State Committee or Markets and Operations Policy Committee could recommend costs be allocated using SPP’s highway/byway methodology.
The highway/byway methodology considers facilities of 300 kV or above as highway facilities, with their costs allocated on a regionwide, postage stamp basis. Facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide. Projects below 100 kV are allocated entirely to the host zone.
Under the revised language, projects or tie lines of 100 kV or higher within a seams partner area could be allocated regionwide. Alternatively, based on the results of a seams project study, the RSC and the MOPC may recommend the Board of Directors approve cost allocation under the highway/byway cost allocation methodology, with the byway costs assigned to a zone expected to receive at least 60% of the project’s benefits. If the board approves such cost allocation, it would seek FERC approval on a project-by-project basis.
Within SPP, projects and tie lines of 100 kV or higher could also be allocated regionwide subject to FERC approval on a project-by-project basis, potentially expanding the number of projects that can be funded through the highway/byway methodology. FERC approval would be required only if the Tariff does not already allow such cost allocation.
Otherwise, based on the seams project study, the MOPC and/or the RSC can recommend the board approve highway/byway cost allocation if a single zone will receive at least 60% of the benefits. No FERC approval would be required.
SPP defines seams projects as non-interregional projects of 100 kV and above that benefit the RTO and one or more neighbors with a minimum cost of $5 million, and usually require a benefit-cost ratio of at least 1.0. SPP and the seams partner must agree to cost sharing.
ITC Holdings’ Marguerite Wagner cast the lone dissenting vote. Wagner and ITC contended the revisions would carve out seams projects from FERC’s Order 1000 process “without justification.”
Wagner expressed a preference for FERC-enforceable joint operating agreements to determine project cost allocation. David Kelley, SPP’s director of interregional relations, noted that would require the negotiation of a series of JOAs with multiple seams partners.
“I don’t know whether there’s a one-size-fits-all formula we can put down,” he said.
Two other committee members, the Northeast Texas Electric Cooperative and Xcel Energy, abstained.
The FERC filings would be necessary because the SPP Tariff does not currently allow highway/byway cost allocation of seams projects.
The policy changes reflect input from the board and RSC since the paper was originally approved in 2014. Staff said the paper will remain separate from SPP’s business practices and other governing documents and not require a revision request.
The revisions struck previous language that would have required seams projects greater than 300 kV to be recovered according to the highway/byway methodology. Those projects below the 300-kV threshold would have been recovered regionally through highway funding.
The committee will now send the policy paper to the Cost Allocation Working Group for its review. It hopes to have a finalized document for approval by the April meetings of the board, MOPC and RSC.
SPP-AECI Joint Study Recommends Two Projects
SPP and Associated Electric Cooperative Inc. staff are proposing two joint projects addressing thermal overloads and high-voltage issues along their seam in southern Missouri, according to a draft version of the biennial SPP-AECI Joint and Coordinated System Plan report released Friday.
The report identified a reactor in and/or around SPP’s 345-kV substation in the Brookline area and a new 345/161-kV transformer at AECI’s Morgan substation, along with an uprate of the 161-kV line between Brookline and Morgan, as being “mutually beneficial” to both entities.
Kelley told the committee the Morgan portion of the projects is “effectively” on the AECI system and will still have to undergo a regional review.
SPP and AECI evaluated 56 different potential transmission solutions to address the Brookline area’s needs. Staff looked at five targeted areas in all but determined one was no longer an issue and agreed the other three could be managed without joint projects.
Any final solutions will be coordinated with the SPP 2017 Integrated Transmission Planning’s 10-year assessment.
The joint study focused on predetermined target areas “to concentrate study resources on the geographic areas along the SPP-AECI seam most likely to benefit from mutually beneficial transmission projects.” Those areas were determined by historical analysis, operational experience, recent regional planning efforts and stakeholder feedback.
The SPP-AECI joint operating agreement requires a joint study be conducted every two years to ensure “reliable, efficient and effective operation[s]” along the seam.
Stakeholder comments on the report are due to SPP’s Adam Bell or AECI’s James Vermillion by Friday. That feedback will be incorporated in the final version of the joint study, which will be posted on SPP’s website.
Based in Springfield, Mo., AECI is owned by six regional generation and transmission cooperatives.
MISO M2M Payments Total $1.2M in November
Staff’s monthly market-to-market update once again showed a large flow of dollars from MISO to SPP, primarily attributed to temporary flowgates between the two RTOs. MISO sent $1.15 million to SPP in November, with $879,305 coming from temporary flowgates, and it has now compensated its seams neighbor more than $12.4 million for M2M since March 2015.
Temporary flowgates incurred 265 hours of binding M2M, with permanent flowgates accounting for 92 hours binding.
MISO is seeking stakeholder input on how to address declining frequency response capability within the RTO.
“Frequency response has deteriorated in the Eastern Interconnection over the years,” Michael McMullen, MISO director of regional operations, said at the Jan. 5 Reliability Subcommittee meeting. “It’s currently adequate, but we want to make sure it doesn’t get any worse.”
System operators must maintain the grid at a frequency of 60 Hz in order to maintain network stability. An uncontrolled drop in frequency increases the threat of cascading blackouts.
The RTO says it needs better modeling and is considering more in-depth data collection to support its efforts to improve response to frequency disturbances.
“There is something in the model that isn’t right,” McMullen said, adding that stakeholder involvement is “critical” to more accurate modeling.
McMullen said that MISO’s current post-disturbance modeling is too conservative in estimating the occurrence and length of frequency dips because of its reliance on inaccurate inertia parameters, which factor in the collective ability of generators to automatically respond to frequency changes based on the pull of load. Simulations show the system recovering too quickly when compared with real events, indicating “a need to fix overall governor parameters,” McMullen said.
MISO currently measures the frequency response of every generator within its system at 24 seconds and 60 seconds following a deviation by polling a megawatt change in output per 0.1 Hz of a frequency deviation. McMullen said the RTO could collect more measurements, including collecting frequency values themselves in addition to megawatt output, gathering data more frequently at two- to four-second intervals and cataloging local balancing authority and MISO frequency response events in order to identify trends.
Hwikwon Ham, a staffer with the Minnesota Public Utilities Commission, asked if the effort would require major software changes, or if the RTO simply needs to capture more data for better frequency response modeling.
Gathering more data is the first step in determining whether program improvements are needed, McMullen said.
“It’s getting enough data to be able to talk with entities,” he said.
MISO is also exploring incorporating its phasor measurement units — devices installed across the Eastern Interconnection to measure the electrical waves on the grid at a specific point in time — in the effort. Those devices can isolate a frequency event and identify specific responses by generators, although their use for model validation is currently in the “embryonic” stage.
The RTO is continuing its efforts to capture data and correlate the numbers to a disturbance, McMullen said. It must also work on providing phasor measurement unit data to member companies.
MISO agrees with FERC’s recently proposed rule mandating that all new resources connecting with the grid have frequency response capability as a precondition for interconnection, McMullen said (RM16-6). (See FERC: Renewables Must Provide Frequency Response.) However, he noted that the new rule is not tailored to an energy market and does not propose any compensation mechanisms for providing frequency response.
MISO Consulting Advisor Terry Bilke said MISO consistently performs above NERC’s frequency response standard (BAL-003-1).
“We don’t anticipate any frequency problems as long as there’s not a change in fleet,” Bilke said. “The [Notice of Proposed Rulemaking] requiring new interconnection agreements to [have a governor] will ensure there’s no backsliding.”
Responding to a request by RSC Chair Tony Jankowski that MISO release its 2016 frequency response data, McMullen said the RTO must first determine what information can be shared publicly.
In 2015, MISO met NERC’s frequency response requirement at an average of -475 MW/0.1 Hz, more than doubling the NERC obligation of -211 MW/0.1 Hz. Still, the results were not as good as in 2014. (See “MISO Frequency Response Doubles NERC Requirements,” MISO Reliability Subcommittee Briefs.)
McMullen said he would update the subcommittee on MISO’s progress on the matter in April.
Sponsors of a bill to increase Maryland’s renewable portfolio standard joined environmental advocates Jan. 5 in calling for the General Assembly to override Gov. Larry Hogan’s veto.
Hogan | Official Website of the Governor of Maryland
Rallying on the steps of the Maryland State House, Sen. Brian Feldman and Delegate Bill Frick, both Democrats representing Montgomery County, attempted to link Hogan’s veto of the measure — dubbed the Clean Energy Jobs Act — to the anti-environmental sentiment of President-elect Donald Trump.
“We’re here because the administration decided to play politics,” Frick said.
Hogan vetoed the bill last year because it would increase rates to cover the costs of additional wind and solar generation.
The legislature returns next week for its annual 90-day session and could consider the measure then. The bill would increase Maryland’s RPS requirements from 20% by 2022 to 25% by 2020, improve access to capital for small, minority and women-owned renewable energy businesses, and commission an industry workforce-needs study.
Frick said the bill has 70% public support.
Renewable industry representatives were supportive as well. Kevin Sheen, spokesman for Empower, promised the wind and solar company would continue investing in the state and said increasing the RPS was “imperative.”
Dana Sleeper, executive director of the Maryland/D.C./Virginia chapter of the Solar Energy Industries Association, said there are about 4,000 solar industry workers in Maryland making an average of $21/hour. It’s important to have such low-skill jobs in the state, Sleeper said.
FERC approved MISO’s second attempt at new interconnection queue rules, conditioned on the RTO allowing refunds for “significant” changes in upgrade costs and providing more detail on late-stage restudy scenarios.
MISO’s new queue process is designed to last 460 days and meant to reduce multiple unscheduled restudies by including mandatory restudies in each stage of the new three-part definitive planning phase. FERC said the design should minimize the backlogs that dogged the old queue by studying project withdrawals “on a more structured basis.”
FERC’s Jan. 3 order said that while the new queue proposed a longer official timeline than the old process, “the proposal is an improvement compared with MISO’s current study process that can take nearly two years due to unscheduled, ad hoc restudies.” MISO said the old queue process averaged 589 days. The changes formally took effect Jan. 4 (ER17-156).
In its transition plan, MISO plans to grandfather some late-stage interconnection requests. FERC said MISO’s transition “avoids the creation of an unwieldy study group.”
Two ‘Off Ramps’
The new queue creates two designated off-ramps for interconnection customers to withdraw projects; smaller but more frequent milestone payments that can be applied to an initial payment for the interconnection agreement; and a restriction on restudies after a generator interconnection agreement is executed. If a project is unexpectedly withdrawn, MISO can use milestone payments to fund network upgrades that would have otherwise been needed, lessening the financial burden on other projects that rely on the upgrades. After an initial $4,000/MW initial payment, the two subsequent milestone payments are based on a percentage of upgrade costs. (See MISO: Stakeholders Behind 2nd Queue Reform Attempt.) The changes also preserve the ability for MISO to enter provisional GIAs with customers for limited operation “at any time in the interconnection process.”
FERC had rejected MISO’s first queue proposal in March, saying the higher milestone payments could create barriers to entry and that the RTO placed too much blame for the queue’s gridlock on “speculative projects.”
“We find that MISO’s proposed changes to the Tariff address the commission’s previous concerns by implementing more transparent timing and cost information to enhance accountability in preparing timely interconnection studies, providing for more involvement of the interconnection customer in the study process and providing for earlier coordination with affected systems,” the commission wrote.
FERC also agreed with MISO that it should weigh stakeholders’ feedback before considering a provision that allows projects to withdraw penalty-free if substantial queue delays occur in the future.
Refunds for ‘Significant’ Changes
The commission ordered MISO to create a provision allowing refunds of milestone payments if “significant change” affects cumulative network upgrade costs while the project is in the queue’s definitive planning phase. It told the RTO to define the degree of change needed to trigger the refund and address the risk of “cascading withdrawals” that penalty-free exits could cause when crafting the provision. MISO’s revised filing proposed refund of milestone payments only if the network upgrade cost estimates increase 25% or more between the queue’s system impact study and the facilities study of the definitive planning phase.
Additionally, MISO must provide FERC semi-annual informational reports for two years describing the number and types of customers that experience changes in cost estimates for network upgrades greater than 25%. FERC also told MISO to clarify that the RTO does not intend to separately bill withdrawing interconnection customers for another interconnection customer’s restudies.
The commission gave MISO 60 days to clarify what events could initiate a restudy for customers with GIAs. FERC said the RTO did not maintain the “existing language regarding restudies related to other types of upgrades or contingencies and has not explained why such existing language is no longer necessary.” The commission rejected the argument of MISO’s generation developers, who said restudies after an executed agreement should be banned altogether.
Per FERC’s order, MISO also has 60 days to add language to make scoping meetings mandatory for transmission owners. The RTO had only proposed mandatory scoping meetings for interconnection customers. FERC said transmission owner attendance is “essential to the purpose of that meeting, which is to discuss alternative interconnection options, to exchange information including any transmission data that would reasonably be expected to impact such interconnection options, to analyze such information and to determine the potential feasible points of interconnection.”
FERC OKs New Rule on Milestone Payments
In a related order also issued Jan. 3, FERC accepted MISO’s revised plan that applies the M2 milestone payment across all classes of interconnection customer, including external customers (ER16-1817-001).
“The Tariff changes will ensure comparable treatment for all customers, external or internal, existing or new,” FERC said.
After revising a service agreement last spring for the Louisiana Energy and Power Authority, MISO proposed that external customers should be exempted from interconnection milestone payments because the fees serve to deter speculative projects, and such generators are either in-service, under construction or have an executed interconnection agreement with the transmission provider to which they directly interconnect. MISO also pointed out that the fee is refunded once a generator begins commercial operations. FERC rejected MISO’s stance in October, saying it amounted to preferential treatment. (See FERC Orders MISO to Levy Interconnection Fees Equally.)
MISO said the new queue rules makes it “clear that the M2 milestone payment assessed to any customer is not zero.”
California will require improved transmission access to a diverse set of renewable resources throughout the state and the broader West to cost-effectively meet its renewable energy and greenhouse gas reduction targets, according to a report released by the state’s Energy Commission.
Increasing solar generation will lead to rising costs stemming from the need to curtail surpluses during periods of high output and shore up system, and flexible, capacity during other times of the day, the report found.
A technologically and geographically balanced portfolio of resources would help offset the technical risks of California’s growing reliance on in-state solar generation, while the upgraded transmission required to access those resources could enable the state to export surplus solar outside the state.
The study was conducted on behalf of the multiagency Renewable Energy Transmission Initiative (RETI), a collaboration that includes CAISO, the state’s major municipal and investor-owned utilities, the Western Area Power Administration and the California Natural Resources Agency.
The outcome of a yearlong effort, the RETI report provided a “high-level visioning process about what it might take” for California to meet its 2030 mandates for generating 50% of the state’s electricity from renewable resources and reducing GHG emissions to 40% below 1990 levels, RETI project director Brian Turner said during a Jan. 4 call to discuss the report.
Turner was careful to point out that the report did not represent “a projection or goal for any total quantity of renewable energy statewide or in any specific areas” or advocate for any specific transmission or generation projects.
And while the study focuses on the potential for utility-scale renewable development in California and the rest of the West, Turner noted that it is not intended to express a preference for utility-scale energy over other strategies to help the state meet its goals.
“The overall flavor — objective — here is really one big, ‘What if?’” Turner told RTO Insider.
The RETI project poses a set of interrelated questions: “To meet [the state mandates], what might it require in terms of renewables? And, if it requires [a certain] level of renewables, what transmission might be required? And if that transmission were required, what cost, environmental and land-use implications might it entail?”
The report is the most comprehensive effort to date to draw on available information to scope out the most cost-effective transmission solutions for meeting California’s goals. It relies on information about the most promising areas for renewable development, environmental and local land-use policies within California and the potential for collaboration with the wider West.
“One of the questions to ask is: ‘Did we get the synthesis right?’” Turner said during the Jan. 4 CEC call, soliciting feedback from industry participants.
The study assumes that for California to meet its 50% renewable portfolio standard, the state will need to tap an additional 25 to 53 TWh of renewable energy between 2020 and 2030. Based on a 30% capacity factor, that translates into a need for 9.4 to 20.3 GW of new renewable capacity. That figure spikes to 76 TWh (29 GW) under a scenario of accelerated vehicle electrification in the state.
While low-cost utility-scale solar is already cost-competitive throughout California, its continued growth will become costly without the integration of other types of renewable resources to balance out the generation profile for solar.
“Without integration solutions, continued growth in solar PV resources will lead to increased costs from a surplus of generation during high solar periods and a shortage of system and flexible capacity at other times,” the report said. CAISO late last year incorporated into its real-time market a mechanism for procuring upward and downward flexible ramping capability in order to respond to variability from renewable sources, the costs for which are borne by load-serving entities and ultimately ratepayers. (See FERC OKs Ramping Product for CAISO, EIM.)
To counter that effect, California will require access to low-cost renewable resources both inside and outside the state, “especially wind and geothermal resources with generation profiles complementary to California solar generation.” The state’s power producers will also need access to energy markets outside California to offload excess generation and reduce ratepayer costs, the study said.
While California has a “substantial amount” of non-firm capacity to interconnect new generators as “energy-only” resources subject to curtailment, the state falls short in the availability of full-capacity interconnections equipped to ensure that output is “fully deliverable” — capable of reaching its load sink without hitting potential constraints.
That distinction is important because under California Public Utilities Commission rules, only fully deliverable resources can be counted toward a utility’s resource adequacy requirements.
The distinction also underlies the RETI report’s assumptions about the hypothetical potential for development of wind, solar and geothermal development in eight transmission assessment focus areas (TAFAs) where large quantities of resources could be constructed to meet the state’s goals.
The Renewable Energy Transmission Initiative report examined the potential for developing renewables in eight California regions — as well as in areas around major import-export points. | Renewable Energy Transmission Initiative
In most of the TAFAs, full deliverability of new resources would require a significant investment in transmission upgrades in order to relieve constraints. (See Price Tag on Tx Needed to Meet California 50% RPS: $5B?) Development in other TAFAs could be constrained by environmental restrictions or land-use rules.
The Imperial Valley TAFA shows some of the strongest potential for development based on a “hypothetical study range” (HSR) of an additional 3,500 MW of solar and 1,000 MW of geothermal and the existence of favorable land-use planning. New transmission would be necessary to achieve full deliverability.
Development of 4,000 MW of new solar in the Riverside East TAFA would be feasible because of extensive planning on U.S. Bureau of Land Management land through the Desert Renewable Energy Conservation Plan. (See Interior Dept. Approves First Phase of California Desert Renewable Plan.) Constructing 500 to 1,000 MW of wind would be less likely because of environmental and land-use restrictions.
While existing transmission in both the Imperial Valley and Riverside East areas could accommodate the lower end of new renewable development estimates, build-out at the high end of the HSR could require up to $1 billion in transmission upgrades to relieve the so-called “Desert Area Constraint” east of the Miguel substation.
The sprawling San Joaquin Valley TAFA shows potential for 5,000 MW of new solar development, in part through the reuse of “degraded” — or disused industrial — land, but development could require “substantial” investment in upgrading the region’s low-voltage network.
Full development of Northern California’s renewable potential is considered less likely because of a lack of environmental and land-use planning, as well as limited transmission availability. Tapping an estimated 5,450 MW of wind, solar and geothermal resources could cost between $2 billion and $4 billion in new transmission.
The possibilities for development along import-export paths is a mixed bag, according to the report.
Importing an additional 2,000 MW via the California-Oregon Intertie (COI), a major import point from the Pacific Northwest, is not considered feasible without construction of a new 500-kV line from the Oregon border to Tracy, Calif. Still, new transmission built elsewhere in the West and the possibility of dynamic line ratings could result in increased capacity on the line.
Also, the largely underutilized northbound segment of the COI could transmit 3,000 MW worth of solar exports from California.
“Being in the Northwest, we’re very interested in what are the implications for us,” said Fred Heutte, senior policy associate with the Northwest Energy Coalition, an alliance including environmental organizations, utilities and businesses in Oregon, Washington, Idaho, Montana and British Columbia.
Path 46 out of Arizona has the capacity to accommodate an additional 3,000 MW of imports, although substantial resource development could eventually trigger the Desert Area Constraint, the report said.
“This is quite an impressive bit of work in quite a compressed timeline,” Carl Zichella, director of western transmission for the Natural Resources Defense Council, said of the RETI report. “This is very, very useful work.”
The CEC is seeking comments on the draft final report by Jan. 10. A final study is expected to be issued by the end of this month.
PJM’s Independent Market Monitor urged FERC to address longstanding concerns over demand response providers and others selling “paper capacity” to arbitrage price differences between the Base Residual and Incremental auctions.
The Monitor made its request in a Dec. 30 filing that was accompanied by a report analyzing the use of replacement capacity since 2007 (ER14-1461, EL14-48).
PJM’s Independent Market Monitor says demand response providers disproportionately replace commitments from Base Residual Auctions compared with sellers of other resource types. External generation and internal generation not in service also had high rates of replacement in some years.
“The lack of a specific requirement that all capacity resources be demonstrably physical assets when offered into PJM capacity auctions continues to provide strong incentives to offer speculative paper capacity,” the report concludes. “The pattern of IA prices being substantially lower than BRA prices, exacerbated by PJM’s preannounced sales of capacity at low prices in IAs, continues. The pattern of consistently extraordinarily high levels of replacement by DR providers and very high levels of replacement by capacity imports and planned internal generation continues.”
PJM attempted to address the issue in 2014, but FERC rejected its proposed rule changes to curb speculation in the auction, saying it created undue barriers to entry. The commission said PJM’s proposed arbitrage fix — which the RTO proposed unilaterally after failing to obtain stakeholder consensus — “will simultaneously increase risk to suppliers and costs to load, without guaranteeing equally offsetting benefits to the PJM grid as a whole.” (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
Instead, the commission said it would convene a technical conference to find a solution. But FERC has not scheduled the conference, the Monitor noted, because of PJM’s request to defer action pending implementation of Capacity Performance.
The Monitor’s Dec. 30 filing asked the commission to “proceed without further delay towards solutions to the issues.”
“Sellers of demand resources in [Reliability Pricing Model] auctions disproportionately replace those commitments on a consistent basis compared to sellers of other resource types,” the Monitor said in its report. “The risks to the markets associated with the sale of DR without any supporting information on the plausibility of the underlying assets [mean] … the system is less reliable than it might otherwise be because the full amount of DR that cleared the RPM auction is not actually available, the price to other capacity resources has been suppressed by the sale of the speculative DR, new entry of other capacity resources could have been forestalled by the sale of speculative DR and there may not be adequate replacement resources available with short notice prior to the delivery year.”
“There is no reason for further delay on this matter,” says the analysis, which updates reports from 2012 and 2013. “The evidence has been and continues to be quite clear.”
The filing comes just weeks after the Monitor teamed with PJM to reinstate capacity-replacement rules that had been stripped away in November through a stakeholder initiative to reduce the accounting reconciliation time for Incremental Auction capacity transactions. (See “PJM, IMM Win Approval for Reinstatement of Capacity-Replacement Rules,” PJM Markets and Reliability Committee Briefs.)
Both PJM and the Monitor had opposed the stakeholder proposal, and the Monitor filed a complaint with FERC that caused some stakeholders who had supported the proposal to reconsider their positions. The complaint was withdrawn after the PJM/IMM proposal was approved.
At issue was a rule implemented in May that could allow what the Monitor describes as “speculative” capacity offers to clear at BRAs and then be replaced without justification at lower prices with capacity in subsequent Incremental Auctions. The rule — meant to help participants avoid Capacity Performance penalties when legitimate bids into the BRA from participants like DR providers unexpectedly become unable to deliver — had been superseded by a pre-existing rule that required justification for replacement.
However, PJM stakeholders who provide financial services find it onerous because it requires them in certain situations to maintain collateral for positions they have sold out of, a situation Citigroup Energy’s Barry Trayers termed “double counting.”
Monitor Joe Bowring stated at the time that reinstating the rule wasn’t “optimal,” but it was better than allowing capacity replacements without justification.
