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.
Upstate nuclear power plants will start earning additional revenue for their carbon-free attributes in April as New York becomes the first state in the nation to offer the industry a lifeline.
The zero-emission credit program, adopted Aug. 1, was but one of a dizzying blitz of policy initiatives from New York regulators in 2016.
Nine Mile Point | Constellation Energy Nuclear Group
The nuclear supports were included in the Clean Energy Standard, which mandates 50% renewables by 2030. The Public Service Commission also admitted that the retail electric and gas markets have failed and needs to be revamped. And under the path-breaking Reforming the Energy Vision, the PSC began proceedings to develop a new utility revenue model and ways to value distributed energy resources. With NYISO, the PSC also moved forward on $1 billion in transmission projects.
Those are just a few of the initiatives that will continue into 2017 and beyond, many of them under the very large umbrella of REV.
ZECs
The PSC proposed the ZEC program in February to prevent the closure of nuclear plants whose revenues have suffered under low natural gas prices. The additional revenue was crucial to Exelon’s agreement to purchase Entergy’s James A. FitzPatrick plant, which the company had threatened to retire.
The PSC upheld the ZEC and CES programs on rehearing late last month, but the ZECs still face two court challenges. Opponents say the estimated $7.6 billion over 12 years of payments are merely props to save upstate jobs and that the program interferes with the wholesale market. Others contend the money would be better spent on a faster transition to renewable energy. (See NYPSC Rejects Challenge to Clean Energy Standard, Nuke Subsidy.)
Crackdown on ESCOs
The PSC in 2016 continued a crackdown on energy service companies, culminating in a December decision that the retail-choice market couldn’t be reformed on the margins, instead needing a top-to-bottom overhaul. (See NY Regulators Call for Overhaul or End to Mass-Market Retail Choice.)
The proceeding, which will begin with a procedural conference Jan. 26, is an apparent change in strategy for the PSC, which lost a court challenge to its February order requiring retailers to guarantee savings for most mass-market customers. (See New York ESCO Order Vacated by Court.)
The PSC also banned ESCOs in December from signing up low-income customers, upping the ante from a previous order that set a moratorium on sign-ups. The ECSOs have yet to respond to the latest salvo.
PSC staff also released a report that starts a two-phase process to change the way DER are valued. The move is intended to replace the crude instrument of net metering with more sophisticated, granular metrics for weighing the value rooftop solar and other distributed energy resources provide to the system and the costs they impose. (See NYPSC Vision for DER: From Net Metering to ‘Value Stack’.)
The PSC says DER can improve system efficiency if their value is properly reflected in retail and wholesale markets and if utilities are incented to consider them as alternatives to traditional capital investments. NYISO plans to release a “road map” on integrating these resources into the wholesale markets in early January.
And to more fully integrate renewable energy resources into the New York grid, proceedings are underway for two public policy transmission projects under FERC Order 1000.
One, the Western Energy Connection, will add 1,000 MW of transmission capacity for hydro, gas and renewable generation, including the dam at Niagara Falls. In June, NYISO identified 10 proposed upgrades as finalists, submitting their findings to the PSC. (See NYISO Identifies 10 Public Policy Tx Projects.) The commission in October ordered further review and project selection by NYISO.
A second project will expand transmission corridors in central New York and the Lower Hudson Valley to provide easier power flows from the wind energy areas to the load centers near New York City. The PSC just closed a comment period on whether that project should proceed. (See NY Transco Chief: Tx Buildout ‘A Marathon, not a Sprint’.)
NYISO Strategic Plan
NYISO’s Strategic Plan for 2017-2021, released Dec. 15, says the grid operator will integrate the public policy goals of New York state to switch to cleaner and more DER while adding technological innovations to grid operations.
In addition to maintaining reliability, an important focus will be responding to changes resulting from REV, the ISO said.
In addition to the DER “roadmap,” the ISO will pursue greater fuel assurance through gas and electric coordination; capacity market improvements, including reduced reliance on reliability-must-run agreements; the demand curve reset; and improvements to its real-time commitment/real-time dispatch forward horizon coordination.
After its first full year under new CEO Andy Ott, and the last year of its transition to 100% Capacity Performance, PJM heads into 2017 amid continued ferment over the capacity market and angst over the impact of state subsidies to generators.
When Mike Kormos — Ott’s main challenger to replace former CEO Terry Boston — left PJM in March, Ott quickly restructured his executive staff, eliminating Kormos’ chief operations officer position and elevating deputy Stu Bresler to control of both the Markets and Operations divisions. The move put Bresler in charge of Kormos’ former deputy, Mike Bryson. Ott also expanded the authority of General Counsel Vince Duane. (See Ott Restructures PJM Divisions, Leadership.)
Ott’s reorganized team faced a series of challenges to the competitive electric model that rules in most PJM states. While the 20th anniversary of retail choice was celebrated in Pennsylvania, the competitive model came under attack elsewhere. (See Crafters of Pa.’s Deregulation Law Look Back After 20 Years.)
Public Policy vs. Markets
PJM has long dealt with state mandates and federal tax credits for renewable generation. The newer challenge is subsidies ordered by state policymakers fearful of losing in-state coal and nuclear generation — and their thousands of jobs — that are imperiled by environmental costs and low natural gas prices.
Illinois followed New York’s lead in approving zero-emission credits to support Exelon’s two ailing nuclear plants in the state. (See Illinois Lawmakers Clear Nuke Subsidy.)
“The future of PJM markets is at issue,” Independent Market Monitor Joe Bowring said. “The PJM capacity markets cannot work with significant new subsidies. Subsidies suppress both the capacity price and the energy price. Both capacity market and energy market revenues are essential to providing incentives for new entry and for maintaining existing resources.”
In an interview with RTO Insider last month, Ott said he didn’t see the state initiatives as existential threats to competition. “I don’t see a concern being raised within PJM [about whether] it delivered value,” he said. “There has been a lot of benefit to competition. [It] seems to be more the question: How do we manage the entry and exit to make sure it’s being done in a reliable manner?”
Ott pointed out that between 4,000 and 5,000 MW of new generation has entered each of the past four capacity auctions. It’s “not only a swap in fuel, but a swap in technology,” he said, that is driving down costs and forcing legacy assets to consider retirement.
The tension between state policymakers and federally regulated wholesale markets is but one of the issues of 2016 likely to continue making news in 2017.
Planned transmission upgrades to the Artificial Island nuclear complex were put on hold in August after rising costs and complaints over cost allocation, another frustrating delay in what was to be PJM’s first competitive project under FERC Order 1000. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
Following a technical conference in February, FERC ordered changes to PJM’s rules on financial transmission rights and auction revenue rights and rejected the RTO’s first attempt at a fix. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)
It all sets up for an eventful 2017. Here’s some of the issues likely to dominate PJM stakeholder meetings in the new year:
The Case for Capacity Performance
No issue is likely to consume more stakeholder attention than continued debate over PJM’s new CP rules. After acquiring 80% CP resources in the 2015 and 2016 Base Residual Auctions, PJM will be requiring 100% CP for the 2017 auction, eliminating base capacity.
Ott defends the need for the increased performance requirements and nonperformance penalties under CP, although he conceded that changes to the market — such as what the minimum offer price should be — need to be considered. “[We were] seeing a lot of new units coming in, but not every one of them was coming in with firm fuel,” he said, referring to the previous rules, under which forced outage rates peaked at 25% during the 2014 polar vortex — the event that led to the tougher rules.
A coalition of cooperatives and municipal utilities has been campaigning for several months for a holistic review of the capacity construct, questioning whether the current model is sufficiently flexible to respond to state initiatives. (See “Stakeholders Remain Skeptical of Campaign to Revisit CP,” PJM Markets and Reliability Committee Briefs.)
Others have called for more specific rule changes, including extending the life of base capacity, incorporating seasonal capacity products and relaxing some of the construct’s strict performance rules. (See FERC Wants More Detail on PJM’s Seasonal Capacity Plan.)
Bowring has continued his call to eliminate demand response as a capacity resource, saying PJM should limit its role to the demand side of the capacity calculations.
Security in All its Forms
A major focus for PJM in the coming year will be analyzing its security. It has completed a multiyear effort to develop a security strategy focused on cyber and physical protections, Ott said. “We’re already one of the leaders in the space, but continuous [improvement] is important to provide value to our customers,” he said. (See “Preview of Security Committee Receives Tepid Response,” PJM Markets and Reliability and Members Committees Briefs.)
The transition in fuel sources for generating units is receiving consideration as well. The rapid expansion of gas-fired and retreat of coal-fired generation has made PJM “more diverse than we’ve ever been,” Ott said, but he added, “Is there a point where we become concerned about being over dependent” on gas? The RTO has undertaken a fuel-security study to find out, the results of which are scheduled to be released by the end of the first quarter, Ott said.
Fixing FTRs and ARRs
FERC’s order requiring changes in PJM’s FTR/ARR market design and rejecting the RTO’s proposed correction sent PJM back to devise a new strategy, which it submitted in a Nov. 14 compliance filing (EL16-6, ER16-121). The order called for shifting the costs of balancing congestion onto load and allocating ARRs in a way that doesn’t consider extinct generators.
PJM filed for the changes to be implemented by June 1 while the Monitor requested rehearing, saying the commission erred in requiring load to shoulder the congestion costs. (See Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing.)
Renewed Turf Battle
Last year also saw a renewal of tensions between the Monitor and PJM management as Bowring took exception to the RTO’s attempt to constrain his unit’s role in the review of cost-based offers. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
The disagreement is part of a larger dispute over fuel-cost policies, which Bowring defends as a major part of the Monitor’s role. “Fuel-cost policies are core to defining and evaluating competitive offers, which equal short-run marginal costs,” he said.
FERC approved a CAISO Tariff revision expanding the definition of a “load-serving entity” to include organizations that purchase wholesale electricity to serve their own needs (ER17-218).
The ISO’s rules previously recognized as LSEs only those entities that sell electricity or serve load to end users, a description that covers utilities, federal power marketing agencies and community-choice aggregators.
CAISO’s LSE definition refinement eliminates a subcategory that previously covered California’s State Water Project, which will now fall under the newly expanded definition. | CDWR
The original definition also made a special provision for the State Water Project (SWP), a California agency that directly engages the wholesale market to cover its own energy requirements. The revision eliminates that subcategory, with SWP now covered under the newly expanded definition.
The ISO sought to broaden the definition to accommodate the San Francisco Bay Area Rapid Transit District (BART), which, like the SWP, serves its own load but did not meet the standard definition of an LSE. (See CAISO Issues Revised Proposal to Expand LSE Definition.)
BART’s transmission contract rights on Pacific Gas and Electric’s network, which predate the existence of the ISO, expire at the end of 2016. When those rights automatically convert to CAISO service, the agency will be exposed to congestion charges.
The definition change will permit BART to receive a free congestion revenue rights allocation in the ISO’s annual process in order to hedge the transmission costs of serving its load. The revised Tariff language also makes clear that BART — and any other entity choosing to serve its own load — will be subject to resource adequacy obligations.
| BART
“We find that the revised definition is a reasonable approach to encompass entities, such as BART, that are currently excluded but that nonetheless should be considered a load-serving entity, and avoids the need for CAISO to add carve-outs to the definition, as it initially did for State Water Project,” the commission said in its Dec. 30 ruling.
The revision also alters a provision requiring that any LSE must be authorized to serve load under California state or local law — deleting the reference to California. The change was intended to acknowledge the current membership of Nevada-based Valley Electric Association and to prepare the ISO for additional out-of-state members through regional expansion.
