Staff of the New York Public Service Commission released a report on Thursday recommending a transition from net energy metering (NEM) to a compensation scheme that provides more accurate, granular values for distributed energy resources (15-E-0751).
“With a more accurate, market-based approach to compensate consumers for the value of their distributed clean energy investments, we will continue to take positive steps towards making these clean resources a core part of our energy system,” PSC Chair Audrey Zibelman said in a statement. “Under this cutting-edge framework, consumers, utilities and energy developers will be rewarded for investment decisions based on the full value that clean energy and other distributed energy resources provide to our electric system.”
Phase One of the transition will seek to apply values “that were able to be considered and discerned with currently available data,” the report says.
The mechanism will compensate customers using a tariff based on calculations of specific value sources. These value sources — including energy, capacity, reduced environmental impacts, demand reduction, locational system relief and distribution voltage support — would comprise a “value stack.”
Phase One will apply to all projects and technologies eligible for NEM under current rules, including solar photovoltaic generation, wind and micro hydroelectric generation, where the operator has no ability to control the facility’s output.
Also included would be dispatchable technologies such as fuel cells, farm waste generators and micro combined heat and power and energy storage paired with eligible generation facilities.
The report acknowledges that establishing these values will evolve and that utilities will need time to develop tools to calculate the impact of a resource’s location, the services it provides and its time of use to fully compensate homeowners.
Staff is proposing interim measures for community distributed generation (CDG) projects — sometimes called shared renewables — that are in the advanced stage of development. The interim rules would allow a specific number of projects to be compensated under current net metering rules for 90 business days. After that period, future CDG projects would be valued under the new methodology.
| The New York Public Service Commission
The report also envisions “virtual generation portfolios” codeveloped by utilities and DER providers.
Existing rooftop solar facilities would be paid at net metering rates for 20 years from the date of their installation. Since 2012, solar facilities in the state have grown from a little more than 78 MW to the current 669 MW, the PSC says. Owners of the systems would have the option to drop net metering and sign up for updated compensation plans.
Public comment will be accepted on the report, part of the state’s Reforming the Energy Vision initiative, until Dec. 5. Initial PSC action is expected in January.
Phase Two of the process, which would further refine the development of DER metrics, is slated to begin with a collaborative later this month. A final order is anticipated by the end of 2018.
Net Metering’s Shortfalls
The report said that while it “has been an important and effective tool in fostering the growth of” DER, “when combined with traditional volumetric rate structures, NEM provides an imprecise and incomplete signal of the full value and costs of DERs.”
“NEM therefore provides insufficient information on which to base informed investment and usage decisions that could benefit both the system and customers under REV,” the report continues. “As a result, investment in new DER capacity is often made without regard to how the design, siting and operation of those resources can maximize benefits to the electricity system overall.”
Failing to properly identify and compensate DERs for their value limits incentives for adding technologies such as smart inverters.
“At low levels of DER penetration, the economic inefficiencies resulting from the incomplete price signals embedded in NEM are less consequential, but as adoption increases, these potential misalignments — and the uneconomic effects associated with them — will increase,” the report said.
The LMP applied in the wholesale markets does not separate ancillary services, load shifting and environmental and performance benefits “that are essential design features of a fully optimized bidirectional power system and decarbonized network,” it said.
Collaborative
A collaborative effort involving utilities, consumer advocates, environmentalists, solar and DER providers that started last December was the first step in providing input for the new market framework. The report also builds on several REV-related efforts including the development of a benefit-cost analysis framework and utility distributed system implementation plans.
“Today, the customer side of the grid represents an enormous and largely untapped resource to optimize value throughout the electricity system. REV will establish markets so that customers and third parties can be active participants, to achieve dynamic energy management on a systemwide scale, resulting in a more efficient and secure electric system, including better utilization of bulk generation and transmission resources,” the report says.
CARMEL, Ind. — MISO presented a different perspective at its Oct. 25 Informational Forum, inviting cultural anthropologist Gretchen Bakke to talk about shifting attitudes toward electrical infrastructure.
Bakke | McGill University
Bakke, assistant professor of anthropology at McGill University in Montreal and author of “The Grid: The Fraying Wires Between Americans and Our Energy Future,” has studied failing systems in Cuba, the Soviet Union and Yugoslavia. She said the grid is as much of a cultural creation as a technical one. “As such, it moves with us. We think of it as solid and rebar, [towers] and copper, but the truth is it grows with us.”
The current grid is a poor fit for a new generation of customers who want carbon-free electricity, Bakke said. The grid’s reliability becomes more “fragile” with increasing investment in intermittent renewables, and Bakke calls for “a serious reimagination of the grid” beyond simply repairing aging infrastructure.
“People right now are moving against the grid,” Bakke said. She pointed to the development of phones with ultra-low power transistors that can function for years without a battery, Elon Musk’s self-driving cars, Iceland digging a 3-mile hole into magma to tap geothermal power and Democratic presidential candidate Hillary Clinton’s push for 500 million solar panels in the U.S.
Bakke said regulators have made electricity so reliable and so cheap that consumers can “unwittingly” ignore it. Consumers tend to think that energy storage is a panacea, forgetting that producing batteries causes pollution and batteries cannot be charged by renewable power alone, she said.
“The way that solar PV has been presented is as this free power source that you can get money back on. And that contributes to this 21st century [attitude],” Bakke said.
Customers’ desire for more local distributed energy resources are at odds with their preference for renewable generation, which often requires tapping remote sources via transmission.
“All of these dreams rely on a deep ignorance of infrastructure,” Bakke said. “It’s this upswing in wanting to eat food grown from a local farmer,” Bakke explained. “Iowa wind is fine to power the Twin Cities.”
Bakke said MISO stakeholders are the edge of the consumer “push and pull,” but she said resource owners should nevertheless pay attention to what consumers are demanding.
LITTLE ROCK, Ark. — Mike Wise, Golden Spread Electric Cooperative’s senior vice president of commercial operations and transmission, once again argued against a revision request funneled through the SPP Market Working Group that replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.”
Wise told the Board of Directors and Members Committee that with MRR173, part of a compliance package responding to FERC Order 825, procuring rampable capacity through the reliability unit commitment (RUC) process “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”
“We’re RUCing them left, we’re RUCing them right, we’re RUCing them all the time. [That] dampens prices and dampens the market,” Wise said. “It’s just an advanced form of an [energy imbalance service] because of all the RUCing that’s going on.
“There are so many new resources … that are rapidly coming on that make appropriate price signals even more important. Our main goal should be to allow resources to clear based on market offers, not cost, in the dispatch model itself. The process needs to be improved substantially.”
Not so fast, said American Electric Power’s Richard Ross, the MWG’s chair. He said the claim that SPP is “RUCing things as they see fit couldn’t be further from the truth.”
“We could change the rules and say we don’t even need the reserves, but we’d have more scarcity events,” Ross said. “Being a balancing authority comes with obligations. It is unacceptable to go into real-time operations; not only unacceptable, but it’s not compliant to go in short. This revision is clarifying exactly what staff should be doing.”
Ross said MRR173 and MRR175, which seeks to comply with Order 825 by using shortage pricing for any interval in which energy or operating reserves are short, would address Wise’s concerns. Both revisions are necessary for SPP to make a planned FERC compliance filing in January.
A third revision, MRR188, gives staff the option to include as much as 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market. The revision is a protocol change, so it did not need board approval.
The three revisions “are all tied together,” Ross said. “What’s happening with this change, and the change in 188, is to move that procurement into the day-ahead market. It’s an improvement. We don’t want scarcity events. We want right pricing.”
“I don’t believe there are any cost implications at all. I believe it’s a practice we have to live with at SPP,” said COO Carl Monroe, pointing to the Price Formation Task Force as another group addressing the ramping issue. The task force is expected to wind down its work by year-end and then hand it over to the MWG.
“The entire MWG is sympathetic to you,” Ross said to Wise. “I absolutely feel you should recover all costs for generating energy out of those [quick-start] resources. The answer is to set prices at the cap, frequently, in order to allow that to happen. We think shortages happen and are being priced appropriately, but this is a first step. We need to … be in position to comply with the FERC order and after that, we can improve on it.”
Wise said he was encouraged by Ross’ comments.
“To the extent we can eliminate RUCs, I really want us to get there,” Wise said. “It’s not an issue that’s going away. We should be procuring through the market and the bid-stacking process.”
Still, Wise wound up casting the lone opposing vote against MRR173. He was joined in opposing MRR175 by Dogwood Energy’s Rob Janssen, who said he objected to staff inserting language the week before October’s Markets and Operations Policy Committee meeting calling for a $5,000 spike in the operating reserve demand curve (ORDC) during a scarcity event.
“I look at pricing to have the right price at the right time for the right reason,” Janssen said, paraphrasing an SPP motto. “Going straight to $5,000 in an event like this is unnecessary. The single highest price we’ve seen at our node is $2,000. It’s an excessive change, in my opinion. If we can have further discussion about reducing the number, I’d appreciate that.”
Richard Dillon, SPP’s director of market design, responded that the ORDC will go straight to $5,000 “because it’s a demand curve, and we have run out of ramp at that point.”
“We set it at $5,000 so we don’t choose to do other things and cause reliability issues,” he said. “If we’re short all the reserves in the [load zones] and the region, the prices have the potential to be at $3,400, so we needed this one to be higher than that value.”
The MWG “will make the language as appropriately flexible as we can,” Ross said. “We have some implementation time before the compliance filing is put into effect.”
The board also approved two other revision requests brought forth by the MWG:
RR183, which updates the violation-relaxation limits’ operating constraint to allow additional redispatch to solve cases with fewer violations, passed with two opposing votes.
RR193, which adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. The revision received two abstentions.
Brown Says Cybersecurity Biggest Challenge
SPP CEO Nick Brown said during his president’s report that cybersecurity issues will be SPP’s — and the industry’s — biggest challenge in 2017.
“Our ability to rely on the Internet of things is being challenged,” he said. “That makes us rethink how we operate our businesses and how we rely on the Internet going forward.”
Brown said SPP’s organizational groups will all spend time at their next meetings gathering feedback “to decide the appropriate level of cybersecurity for this organization.”
“Our systems are there to serve you,” he said, “but the cost to comply … goes up.”
Brown also talked about several other initiatives. He reminded members and the board that he had labeled 2016 as “The Year of the Audit” back in January. He said SPP completed SERC Reliability compliance and FERC financial audits without findings, and he hopes a Critical Infrastructure Protection Version 3 audit begun in 2013 will be completed soon.
An internal initiative to reward employees for finding disparities between SPP’s 5,275-page Tariff and actual operating practices resulted in 10 self-reports to FERC, Brown said. He said the commission took no action on the reports.
FERC’s recommendations to “improve the appearance of independence” of the Market Monitoring Unit have been “implemented or are in the process of being implemented,” he said. The commission issued an audit report of the MMU in July, saying SPP executives had “inappropriate” involvement in the MMU’s oversight and called on the RTO to “strengthen its independence.” (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
The Integrated System’s first year of SPP membership resulted in $67 million in net savings to the RTO’s footprint, including $27 million to original members “that otherwise would not have been there.”
Finally, Brown said revenues are down 3.9% because of low loads. SPP budgeted the 2016 administrative fee using 2015 coincident peak loads, which were projected at 407 million MWh. The peak load forecast is now 394 million MWh.
Directors, Trustees, Members Re-elected
Members and directors re-elected several incumbents to the board, Regional Entity trustees and Members Committee during SPP’s Annual Meeting of Members.
Stuart Solomon (AEP) and Kelly Harrison (Westar Energy) were re-elected to represent the investor-owned sector; Stuart Lowry (Sunflower Electric Power) and Mike Risan (Basin Electric Power Cooperative), cooperative sector; Jeff Knottek (City Utilities of Springfield), municipal sector; Janssen, independent power producer/marketer sector; and Brett Leopold (ITC Great Plains), independent transmission companies.
Directors Julian Brix and Phyllis Bernard were re-elected to new three-year terms on the board. Bernard was first elected to the board in 2003 and Brix in 2008.
Stephen Whitley was elected to an additional three-year term as an RE trustee. Whitley completed former trustee John Meyer’s unexpired term following the latter’s resignation in March over a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where Meyer is vice chair.
Ross Forgoes Razor for Charity
Ross, an often outspoken presence at SPP and ERCOT stakeholder meetings, has made himself even more noticeable with the recent addition of facial hair.
Ross began growing his beard following SPP’s board and MOPC meetings in July. There, he issued a challenge to his fellow stakeholders: If they contribute more than $1,000 to the United Way organizations of Tulsa, Okla., and Little Rock, he would not shave until Thanksgiving.
“And if you contribute more than $2,000, I will go full Duck Commander,” Ross said, referring to the popular “Duck Dynasty” television program.
Ross was unable to meet the higher goal, but his neatly groomed beard attests to what he was able to raise.
Consent Agenda Adds Working Group, Approves IEP Panel
The unanimously approved consent agenda included chartering the Supply Adequacy Working Group, which will take on tasks from the Generation Working Group and Capacity Margin Task Force; adding the Nebraska Public Power District’s Traci Bender to the Strategic Planning Committee; expanding the Oversight Committee to five independent directors; and accepting the Oversight Committee’s 11 candidates for the Industry Expert Pool that will evaluate and recommend competitive-upgrade projects.
The board and members also accepted the SPC’s recommendations to improve the competitive transmission process, the Project Cost Working Group’s recommendation to reset the baseline for an AEP 345-kV project in southeastern Oklahoma and staff’s recommendations to accelerate one project and withdraw the notice-to-construct for another. (See SPP Panel OKs Changes to Competitive Transmission Process, “AEP Project’s 41% Overrun Approved” and “Members Vote to Cancel 69-kV line in West Texas,” SPP Markets and Operations Policy Committee Briefs.)
Other rule changes approved by MOPC were:
MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex post
MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) to ensure long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with the Western Electricity Coordinating Council.
RTWG-RR164: Updates Tariff Attachment O to correctly reflect the current near-term planning process schedule, which is now conducted in the April-March timeframe.
RTWG-RR174: Revises Attachment AQ of the Tariff to eliminate a requirement that transmission customers submit a request for changes in delivery point facilities when there is no corresponding change in load.
RTWG-RR176: Corrects and clarifies responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with WECC.
MISO said it generally agrees with the recommendations its Independent Marker Monitor laid out in its 2015 State of the Market report, but the RTO won’t implement a few recommendations and wants additional analysis on some others.
On a conference call of the Market Committee of the Board of Directors on Oct. 24, MISO said there is only a “minority of problems identified where [it] believes additional analysis is necessary to confirm [the] problem or to identify alternative solutions.”
Under their Tariff, the RTO has 120 days to respond to the Monitor’s recommendations.
Software Changes Required
MISO Executive Director of Market Design Jeff Bladen said the RTO is working on expanding eligibility for online units to set prices in extended locational marginal pricing (ELMP), but changes to the software would be difficult and it wanted to focus on other Market Roadmap projects first. However, MISO still breaks with the Monitor on suspending offline pricing in ELMP. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
Bladen said implementing the Monitor’s full suggestion would require a complex software modification. “There are no simple code changes to the software at this point. It certainly isn’t a one-day change,” he said.
Market Monitor David Patton said the difficult software change stems from software vendors “hard coding” software where it cannot be opened later to expand design parameters.
Bladen said although it agrees with the Monitor that it should implement firm capacity delivery procedures with PJM, MISO has been unable to move the solution through the two-party approval process because of resistance from PJM earlier this year and has put its proposed solution on hold. (See “Ready for Pseudo-Tie Switchover,” MISO/PJM Joint and Common Market Meeting Briefs.)
“It’s PJM that requires resources external to PJM to be pseudo-tied,” Patton agreed. He said he and MISO are considering asking FERC to open a Section 206 proceeding against PJM to force a change in its Tariff.
‘Weaponizing’ FERC Filing
MISO Director Michael Curran said he would rather not build a relationship with PJM by “provoking” them with a 206 proceeding and cautioned against “weaponizing” FERC filings. CEO John Bear said MISO is developing alternatives to firm capacity procedures to present to PJM.
Bladen said the Monitor’s advice to improve the modeling of transmission constraints in the Planning Resource Auction was not prioritized by stakeholders as a key concern, but MISO would work on scoping a study.
The RTO also said it agreed with the expansion of temperature-adjusted and short-term emergency ratings for transmission facilities and will work with its transmission owners on improvements.
However, MISO is unlikely to increase physical withholding mitigation measures in the PRA by addressing uneconomic retirements. The RTO said the concept of uneconomic retirements itself is a problematic, as such instances would be difficult to determine.
Patton countered that the problem could crop up when a large generator clearly retires to give affiliates a higher clearing price. Bladen said the threat of an entity’s permanent loss of injection rights if it is found to be gaming the market is “sufficient deterrent” to such retirements. He said the RTO is working on a suggestion from 2013 to subject suspended resources to withholding rules, but he didn’t see the need to include retiring generation.
However, MISO has committed to expanding withholding mitigation in the PRA by recognizing affiliates’ connections. Bladen said MISO and Patton will discuss the issue with stakeholders. “We think it’s important to look at the affiliate nature of resources and examine them for physical withholding,” Bladen said.
On the other hand, MISO sees gray areas around a few of Patton’s recommendations. MISO says it is awaiting further details from the Monitor on how to improve the modeling of transmission constraints in the PRA and is looking for changes that can be achieved in the near term.
Transfer Constraint
MISO took a similar wait-and-see stance on Patton’s suggestion to increase the transfer constraint between the RTO’s South and North regions in the PRA. The RTO said it is holding stakeholder discussions and has support for a study to examine the benefits of developing its own transmission to link the interfaces, as an alternative to SPP’s transmission. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
The study will be rolled into other analyses as part of MISO’s 2017 Transmission Expansion Plan. MISO said the annual cost to maintain constraints under the SPP settlement can be as much as $38 million.
The RTO also has mixed feelings about modeling its voltage and local reliability requirements in the day-ahead market, saying it already models the requirement but doesn’t include it in the day-ahead market. However, it said it would discuss potential advantages of an automated market process with the Monitor
Bladen said it will take five to seven years to implement all of the 2015 solutions MISO agrees with, calling the timeframe in line with the RTO’s “robust stakeholder process.”
Bladen also said all recommendations made prior to 2011 have been resolved. It takes MISO an average of 2.3 years to close out suggestions, according to the RTO.
Patton said implementation of software fixes for his recommendations are sometimes slowed by difficulty scheduling work with MISO’s software vendors or getting the attention of RTO executives responsible for multiple market improvements.
RENSSELAER, N.Y. — Over objections by generators, the NYISO Management Committee on Wednesday approved a temporary rule change to partially insulate consumers from sharply higher capacity prices as a result of exports from constrained zones.
NYISO Zone Map | NYISO
The committee approved its interim solution with 63% of the vote.
FERC’s ruling allows Castleton Commodities International’s 1,242-MW Roseton 1 generator, located 43 miles north of New York City in NYISO’s capacity import-constrained G-J locality, to supply 511 MW of its capacity to ISO-NE beginning next June for the 2017/18 delivery year.
Current New York rules treat exported capacity the same as if the plant supplying it had been retired or mothballed.
“The NYISO’s objective in formulating our proposed market design has been to eliminate inefficient pricing outcomes due to exports from import-constrained localities,” Emilie Nelson, vice president of market operations, said at the meeting. “Our overarching goal is to send effective short- and long-term market signals that incent investment and retain resources where they are needed without imposing undue consumer impacts.”
Generators at the meeting complained that the changes endorsed by the committee — particularly an amendment offered by transmission owners — cap capacity prices without justification. In an amended motion approved by the committee, those payments have been capped at 20% of what the generators would be paid under a formula devised by NYISO staff.
“I see this just as a vote for lower prices because I see no technological background behind it,” said Mark Younger, who represents several generators.
Supporters of the interim rule change did not challenge that characterization. “While this is not a perfect solution, this gets us to where we need to be in the short term,” said Kevin Hunt, who represents large industrial customers and New York City.
ISO officials said they will promise in their Section 205 filing seeking FERC approval of the rule change to continue work on the issue in its stakeholder groups.
Under a complex formula by NYISO staff based on power flow analysis, for each megawatt committed to New England, capacity prices in the constrained zones in the Lower Hudson Valley would go up by almost 48%.
The “locality exchange factor” incorporates base case data from the most recent reliability planning process to determine the amount of generation from the “Rest of State” areas outside of the constrained Hudson Valley that can be brought into the constraint area. The LE factors will be calculated annually.
The LE factor for the coming year is 47.8%, which means a price signal to replace 52.2% of the exports to ISO-NE is efficient, NYISO says. In other words, 52.2% of the exports can be replaced by resources from within the same locality, but 47.8% must be replaced by capacity resources from the Rest of State.
Under the amendment offered by TOs, the capacity cost increase borne by consumers would be capped at only 20% of the cost the LE factor would have imposed.
NYISO estimates that while prices will still rise for in-state customers because of the exports, the rule change will reduce the increase by at least $144 million.
Independent Market Monitor David Patton had identified the problem in his 2015 State of the Market report, recommending that NYISO act quickly to recognize the reliability value of generators in import-constrained zones to avoid a rise in capacity prices.
A technical conference that convened at FERC headquarters last week to explore external resource participation in the Energy Imbalance Market (EIM) began on a contentious note but concluded with parties on both sides of the issue admitting to a better understanding of the others’ perspectives (ER16-1518).
The commission ordered the staff-led conference in June when it rejectedCAISO’s proposal to prohibit EIM members from implementing economic bidding at the market’s interties until the ISO could develop “appropriate rules” to manage the transactions. (See FERC Order Prods CAISO to Allow EIM Intertie Bidding.)
The ISO’s Tariff stipulates that each balancing authority area (BAA) that joins the EIM can determine for itself whether to allow resources located outside the market to submit economic bids at the BAA’s transmission seams. Two factors prompted the ISO to seek to undo the provision.
First, EIM participants PacifiCorp and NV Energy had expressed concerns that implementing the practice would add complexity to their initial participation in the market. Second, the ISO said its own experience with low liquidity in 15-minute bidding at its own seams suggested that the benefits of allowing such bidding was “questionable.”
Power Marketers Weigh In
Rothleder | Linkedin
The Western Power Trading Forum (WPTF), a group of power marketers, filed the only protest against the proposal, saying the amendment was an “attempt to codify” an “effective roadblock to market evolution” that discriminated against third-party participation in the EIM.
That argument found support with FERC, which called for further discussion on the issue.
CAISO laid out its perspective in its opening remarks at the conference.
“We must be careful not to impose requirements that degrade the fundamental design elements of the Energy Imbalance Market that could ultimately unravel the benefits the Western market is experiencing,” said Mark Rothleder, the ISO’s vice president of market quality and renewable integration.
The position staked by WPTF and other stakeholders created that risk, Rothleder said. He added that there is a “misperception that there is an easy plug-and-play format” for intertie bidding that EIM entities can adopt.
“That is because the EIM addresses a set of necessary but complicated and interrelated issues, such as resource sufficiency, transmission utilization and compensation, resource flexibility, market power mitigation, greenhouse gas accounting, feasibility of flows across the network, feasibility of the resource dispatches and performance monitoring,” Rothleder said.
New market design elements cannot be imposed without considering all of those factors, Rothleder contended.
CAISO Pans ‘Generic’ Bidding
“Generic” intertie bidding — bids by unspecified resources on a system neighboring the EIM — is “not consistent with the principles of the EIM,” Rothleder said.
In August, the ISO began work on a plan that would require external participating resources to have characteristics comparable to those already participating in the EIM. These “specified resources” would have 15-minute scheduling and five-minute dispatch capability. They would also have to meet data exchange, settlements and metering requirements in order to verify delivery. (See CAISO Charts Course for External Resource Participation.)
Rothleder added that there is no evidence that the absence of generic bidding is imposing hardship on the West’s bilateral markets.
“Moreover, we cannot waste ISO and stakeholder time and resources [on efforts] that are not wanted by other market participants as a whole,” Rothleder said.
Wolfe | CAISO
Ellen Wolfe, a consultant representing the WPTF, challenged Rothleder, contending that the Western marketplace has in fact “lost some functionality with the advent of the EIM.” Within the EIM area, she explained, market members and a “small number” of third-party participants can bid into the EIM’s 15- and five-minute markets on an economic basis.
However, participants outside the market’s boundary cannot bid into an EIM member’s balancing area during those intervals; instead they are forced to bid an hour in advance — a byproduct of the need for an EIM member to come into each hour fully balanced.
The process exposes outside resources to unknown congestion charges and forces them to become price-takers of the market’s intra-hour adjustments, Wolfe said.
Before the EIM, a party holding system energy — energy from an unspecified resource — could schedule through a utility area and make changes up to 20 minutes before delivery with no price impact. Currently, schedule changes with an EIM member now incur an unpredictable fee for nonperformance within the hour — even for power being wheeled through the member’s balancing area.
Under WPTF’s counterproposal, offers from resources outside the EIM would be bid into the market on a 15-minute basis. CAISO could fold those bids into its EIM runs and dispatch with other market resources “with little or no burden on the EIM entity,” Wolfe said.
External offers would have the same performance obligations as those originating internally and would be subject to the same imbalance energy risks, Wolfe said. The resulting solution would provide the increased efficiency of a deeper bid stack, which could relieve concerns about market power in certain areas of the EIM, she said.
‘Not Bullish’ on Stakeholder Process
Wolfe was skeptical of CAISO’s contention that the issue could best be resolved by stakeholders, saying that she was “not particularly bullish on that process” based on past experience. Issues related to open access are not “appropriately left for a process that depends on a popular vote,” she said.
“Rather, issues of open access seem of the category of right versus wrong — and sometimes right is not the most popular,” Wolfe said.
Edmonds | Linkedin
Speaking on behalf of the EIM’s present utility members, Sara Edmonds, general counsel for PacifiCorp Transmission, pointed out that each member allows for external participation through pseudo-ties or dynamic schedules.
Edmonds also spoke about the three “critical elements” needed for “effective EIM diversity”: generating resources, load and transmission.
“Alternatives — or derivatives — to full participation which deviate from these fundamentals could threaten the long-term success of the EIM, as well as its continued growth,” Edmonds said, citing concerns about the shifting of costs and risks to EIM members.
No Desire to be Market Operator
One risk is that EIM BAAs will become responsible for balancing multiple remote sources of external generation at multiple intertie points.
“We signed up to be a market participant, but not a market operator,” said Justin Thompson, director of resource operations and trading at Arizona Public Service. “If we go with intertie bidding, we’re going to turn into a quasi-market operator.”
Thompson also voiced concern about the potential for “free riders” on the EIM system, noting that some of APS’s neighboring utilities are considering market membership.
“Instead of joining the full market, they can just intertie bid at our boundary and take up all our transmission that we’re using for EIM participation,” Thompson said.
Hampton | Public Generating Pool
Therese Hampton, executive director for the Public Generating Pool (PGP), which represents 10 municipal utilities in Oregon and Washington, voiced the perspective of small organizations that don’t have the financial means to join the EIM but could still benefit from — and provide benefits to — the market.
Hampton said that EIM members with diverse resource portfolios stand to benefit the most from joining the market. However, PGP’s members own mostly hydroelectric resources, control little transmission and deal with limited load and congestion.
Given the limited financial upside of joining, the EIM’s upfront costs are a difficult sell for ratepayers, Hampton said. “We believe there should be another option.”
Not ‘Free Riders’
While PGP is open to market rules that require specific information from external resources, the group also wants the ISO to consider allowing resource aggregation, just as it does for internal resources.
Leaburg Dam | Eugene Water & Electric Board/Public Generating Pool
“We’ve never intended or want to be free riders,” Hampton said, acknowledging that PGP recognizes that participation could come with “appropriate” administrative costs.
PGP’s resources have the surplus capacity and flexibility to participate in the market on the five-minute basis, Hampton said. She also added that the EIM’s rules for external participation should be developed by CAISO and not be relegated to individual BAAs, as the Tariff currently stipulates.
Rothleder pointed out that CAISO had no experience with 15-minute bidding at its own interties when it was designing the EIM. At the time, it thought the determination for allowing intertie bidding was best left to each EIM member as the entity most familiar with its own transmission capabilities.
“It is not the same thing as the ISO’s intertie bids at the border,” Rothleder said. He pointed out that EIM members have to contend with other protocols related to transmission allocation that overlay their own participation in the market —something not applicable to the ISO as a central market operator.
Lateef | LinkedIn
Shahzad Lateef, director of transmission and distribution system operations at NV Energy, described the complexity of participating in the EIM, which entails responding to intertie bids administered by the ISO while maintaining reliability within its own BAA.
“Every resource that CAISO dispatches higher, we have to look at all our congestion elements,” Lateef said, explaining the utility’s need to know exactly what sink a dispatched resource is intended to serve, even in neighboring EIM BAAs.
“The complexity continues to increase when you think there’s the potential of 35 tie points with so many potential bidders that will all be moved up or down based on their bid value by someone other than NV Energy,” Lateef said.
Davis | LinkedIn
Robb Davis, energy policy advisor for Chelan County Public Utility District, noted that his utility sells a large slice of its hydroelectric output to EIM member Puget Sound Energy, which pseudo-ties the resource into its own BAA. While the utility is reluctant to take on the cost of EIM membership, as a holder of surplus generation, it does sell additional slices of its output to other marketers and utilities that want access to the market.
Davis noted that Chelan’s resources are situated in an area already modeled by the ISO — and the telemetry is already in place to monitor performance.
“It shouldn’t be an impediment to their participation that we as a balancing authority area don’t want to incur those costs for our customers in our county,” Davis said.
BPA’s Intent
Suzanne Cooper, vice president of bulk marketing at Bonneville Power Administration, said that while her agency isn’t preparing to join the market now, it might consider doing so in the future.
Cooper | BPA
“Whatever principles we apply for external resources to participate in the market should be the same whether we’re in the market or we’re not.”
Mike MacDougall, director of trade policy at Powerex, conceded that generic external bidding at the interties might not be the best solution for facilitating external participation. But he said that BPA, PGP and Powerex would be willing to work with the EIM to develop a participation model that addresses issues such as free riders and transmission usage.
“That’s premised on the fact that there are benefits that arise from that broader participation and liquidity and production costs savings,” MacDougall said.
Rosenblatt | LinkedIn
“I do appreciate Ms. Hampton trying to tease out and separate the issues of smaller BAs who want to come and be part of the [EIM’s] optimization process,” said Lauren Rosenblatt, an attorney with NV Energy. “And if there are barriers to entry for smaller BAs to join the EIM, then — listening to my colleagues who are all EIM entities over the last nine months — we all embrace addressing that.”
Rosenblatt said existing EIM members are excited about Sacramento Municipal Utility District’s recent announcement that it intends to join the market because the utility brings the “trifecta” of load, resources and transmission. (See related story, SMUD to Join EIM in Spring 2019 at the Earliest.)
To Be Continued
Conference participants wrapped up the day on a conciliatory note.
CAISO Assistant General Counsel Anna McKenna encouraged parties outside the EIM to participate in the processes developed to address West-wide issues, particularly the ISO’s Regional Issues Forum and EIM governing body meetings.
“We have a lot of ways for these issues to be vetted or get more attention,” McKenna said. “What would be really helpful is to continue this dialog and focus in a little better on resolving specific issues.”
Wolfe said hearing “the other parties’ concerns was very beneficial.” She also lauded “the amount of brainstorming” that came out of the FERC session, saying it suggested that the ISO might already have the functionality to solve some of the problems related to external participation.
“I wonder if there might be a way to sort of continue that without taking on these big “I” initiatives,” Wolfe said, adding that the ISO’s forums could serve as venues for more discussion.
Cromwell | LinkedIn
Robert Cromwell, director of power contracts and resource acquisition at Seattle City Light, offered a “concrete suggestion” to CAISO: “Perhaps having the ISO articulate specifically the technical requirements for an external resource participant — consistent with current market design — might help inform those prospective participants and be a foundation for further dialogue and discussion.”
CAISO’s Rothleder called the conference “enormously helpful” in furthering the discussion, adding that current EIM participants might have to consent to removing some of the current barriers to entry in order to foster expansion of the market.
“I hope we can all come to the table with an open mind,” Rothleder said.
MISO predicts a 28.4 to 37.5% reserve margin for the winter, about double its minimum of 15.2%.
Regardless of the ample supply, the RTO will continue providing monthly tests and workshops for stakeholders to prepare for “all winter can dish out this year,” MISO Executive Director of Strategy Shawn McFarlane said at the Oct. 24 Markets Committee of the Board of Directors meeting.
McFarlane said abundant supplies are the result of increased North-South transfer limits obtained in the RTO’s settlement with SPP; the rollout of its ramp product; and improved emergency pricing after the introduction of emergency pricing floors in July.
He also pointed to MISO’s improved gas-electric coordination, prompting Director Baljit Dail to ask how the RTO would respond in a repeat of 2014’s polar vortex.
| MISO
Todd Ramey, vice president of system operations and market services, said the RTO now has better communication with pipeline operators, and its control room operators can now see when pipes are constrained through reports and map displays. “We have a better understanding about fuel supply impacts to generators in the footprint,” Ramey said.
Senior Director of Regional Operations David Zwergel told the Informational Forum on Oct. 25 that MISO is prepared to handle forced generation outages and fuel limitations. “We will continue to proactively prepare for any extreme conditions that may arise,” Zwergel said.
MISO is following National Oceanic and Atmospheric Administration forecasts, which predict a warmer- and drier-than-usual winter in MISO South and colder-than-usual temperatures in MISO North.
Jeff Bladen, executive director of market services, said the RTO filed a waiver with FERC on Sept. 28 to allow generators to recover verifiable offers in excess of the $1,000/MWh price cap. The filing marks the third year MISO has used the temporary waiver approach while it waits on a permanent offer cap rule from FERC. (See “3rd Run for Energy Offer Cap Interim Solution,” MISO Market Subcommittee Briefs.)
Bladen also said there was an increase in planned outages last month in preparation for the winter season, averaging 12.5 GW in September compared to 5.1 GW in August.
MISO membership voting results confirmed three new Board of Directors members.
The new directors, announced at the RTO’s Oct. 25 Informational Forum, are former ERCOT CEO H.B. “Trip” Doggett, former Calvert Investments CEO Barbara Krumsiek and Todd Raba, who is leaving Twenty First Century Utilities and has served as CEO of both GridPoint and Berkshire Hathaway’s Johns Manville. The three were selected by MISO’s Nominating Committee in September from a pool of about 30 applicants. (See “MISO Membership Voting on 3 New Board Members,” MISO Board of Directors Briefs.) The trio begin three-year terms Jan. 1, after Board Chair Judy Walsh and directors Michael Evans and Paul Feldman reach MISO’s term limit.
New board members left to right: Doggett, Krumsiek and Raba | left to right: ERCOT, Arabesque-Asset-Management, Grid Point
Director Michael Curran welcomed the new members in a press release. “We are pleased to have their experience on the board to help ensure MISO remains nimble and on the forefront of the ever-evolving energy industry.”
MISO Deputy General Counsel Eric Stephens said 35% of the RTO’s members cast votes in the election, which was held from Sept. 16 to Oct. 24; a 25% participation rate was needed to reach a quorum. Stephens said MISO had the election independently certified to verify the results.
MISO CEO John Bear said the RTO’s entirely electronic voting platform, implemented a few years ago, ensured a smoother voting process.
MISO Incentive Plan up for Stakeholder Inspection
Meanwhile, MISO and its current board posted a first draft of its short-term incentive plan for stakeholder review through Nov. 21. The plan, revealed at the Oct. 25 Human Resources Committee of the Board of Directors, outlines the board’s discretionary bonus for the RTO’s staff based on nine weighted performance metrics.
Among the targets staff must meet to qualify for the incentive pay are:
Keeping spending within 2.5% of the annual operating budget and 8% of the capital budget;
At least 94% “market funding efficiency,” a measure of the alignment between financial transmission rights and the day-ahead and real-time energy markets that indicates whether transmission capacity was oversold or undersold in the forward markets;
Information technology availability: no more than eight unplanned incidents exceeding one hour of service per year;
94% unit commitment efficiency, a measure of how effectively MISO commits generation in its forward and intra-day processes to meet demand and mitigate constraints; and
Minimal FERC and NERC reliability violations.
“One of the reasons I think this has worked is because we’re pretty hard graders on ourselves,” Bear said.
Developers of six renewable projects totaling about 460 MW will start contract negotiations with New England states in the next phase of a multistate effort to procure clean energy.
Four of the projects will negotiate with three states: Connecticut, Rhode Island and Massachusetts; two projects will proceed with only Rhode Island and Massachusetts. The solicitation generated 24 responses from 30 developers, some in teams.
“Not all projects selected to advance to contract negotiation at this stage will necessarily obtain approved contracts, which may affect the total contracted megawatts resulting from this” request for proposals, the states said in announcing the selections.
The states said they expect to negotiate better power prices in combination than they would have if they acted alone.
Most of the generation would come from solar projects. The selected bidders are:
Ranger Solar, with five solar projects totaling 220 MW in Connecticut, Maine and New Hampshire;
Deepwater Wind’s 26-MW solar facility in Connecticut;
Ameresco’s 20-MW solar project, also in Connecticut;
Antrim Wind’s 26-MW wind project in New Hampshire;
EverPower’s 126-MW Cassadaga wind project in Chautauqua County in western New York; and
Two 20-MW solar projects from RES Americas, one in Connecticut and one in Rhode Island.
Solar Farm | SEBANE
In an updated timeline, the states want electric distribution utilities to enter contracts with the bidders by Jan. 15, which would be filed with the states’ regulators by March 1.
The states ended up focusing on renewable generation projects and bypassed transmission. Two high-profile projects that would have imported Canadian hydropower did not make the cut: Eversource Energy’s Northern Pass, which is planned to run through New Hampshire; and Anbaric Transmission’s Vermont Green Line, which would have connected wind power in New York, combined with Canadian hydropower, and be buried under Lake Champlain and underground in Vermont.
Several transmission projects that would move wind power from Maine to load centers farther south were also rejected in the RFP. Eversource’s 600-MW Clean Energy Connect between Massachusetts and New York did not advance.
“We are pleased with the key approvals the project continues to receive and look forward to participating in the April solicitation for large-scale hydroelectricity,” Bill Quinlan, president of Eversource New Hampshire Operations, said in a statement. “The region’s energy landscape is shifting quickly. Northern Pass, with its 1,090 MW of clean hydropower, and permitting well underway on both sides of the border, is in a strong position to play an important role in helping the region achieve a cleaner energy future.”
LITTLE ROCK, Ark. — SPP celebrated its 75th anniversary this week with a gala featuring political and regulatory figures, an orchestral piece, a commemorative video and a coffee-table book.
The gala, held Monday night in downtown Little Rock, attracted more than 300 attendees, including Arkansas Gov. Asa Hutchinson and other state officials, FERC Commissioner Colette Honorable — former chair of the state Public Service Commission — board members, stakeholders and community leaders.
Left to right: Asa Hutchinson, Susan and Nick Brown, Colette Honorable | SPP
They were treated to the Arkansas Symphony Orchestra Brass Quintet’s rendition of “Heralding Light,” which was composed for the occasion.
SPP also marked the occasion by releasing a 20-minute video and a history book, both called “The Power of Relationships.” The book spent a year in development, with former SPP executive Les Dillahunty providing much of the preliminary work, and features comments from previous and current members and officers.
“SPP has long distinguished itself through our relationship-based approach to doing business,” SPP CEO Nick Brown and Board Chair Jim Eckelberger wrote in the book’s foreword. “SPP exists because of its shareholders. Period. Without their support — logistically, financially, politically and often even emotionally — we would not be where we are today, if we were anywhere at all.”
SPP was created by 11 regional power companies just nine days after the Japanese attack on Pearl Harbor in 1941 to ensure reliable energy for an aluminum plant supporting the wartime effort. The RTO now serves 18 million people across 14 states.
Ten things you may not have known about SPP (from “The Power of Relationships”):
SPP’s first computer had two memory cards “the size of a pizza box,” each with less than a megabyte of memory. “My iPhone now has more power in it,” says Malinda See, vice president of corporate services. One of SPP’s 14 original employees, See said she would take the reel-to-reel backup tapes home for safekeeping.
SPP’s operating budget, less than $53,000 in 1969, didn’t exceed $1 million until 1990. It’s currently $210 million.
Back when the fledgling organization had 14 employees, it nonetheless kept a strict accounting of the few fixed assets it had. “If they had to buy a chair,” CFO Tom Dunn recalls, “they had utility members ask, ‘Why do you need more chairs? What happened to the old chair?’”
Dillahunty | SPP
SPP’s original 11 members were future Entergy operating companies Arkansas Power and Light, Louisiana Power and Light and Mississippi Power and Light; future American Electric Power subsidiaries Public Service Company of Oklahoma (PSO) and Southwestern Gas and Electric (now Southwestern Electric Power Co.); Southwestern Light and Power (later acquired by PSO); Empire District Electric; Kansas Gas and Electric (now Westar Energy); Nebraska Power (Nebraska Public Power District); Oklahoma Gas & Electric; and Texas Power and Light (Luminant, Oncor and TXU Energy).
Dillahunty and Jay Caspary, now director of research, development and Tariff studies, were recognized by the Kansas House of Representatives as honorary citizens in 2006 for the amount of time they had spent in the Sunflower State working on transmission-expansion development.
Board Chair Jim Eckelberger, a retired U.S. Navy rear admiral, and Director Harry Skilton have been with SPP since before it gained RTO status in 2003. They were both part of an independent board seated in 2000 as a precursor to RTO status.
It took three attempts and three years before SPP was approved by FERC as an RTO. In the interim, SPP also tried to merge twice with MISO, calling the effort off for good in March 2003.
Former CEO John Marschewski once accidentally locked himself out of SPP’s offices in the days before identification badges. Marschewski waited for another tenant to let him in the building, then removed drop ceiling tiles and climbed over the wall to get into his office from the hallway.
CFO Tom Dunn dressed as Superman for a company-wide function several years ago. Unfortunately, his superpowers failed him when he tried to fly off the stage. He broke one foot and bruised the other upon landing.
The largest outage in SPP’s history came in July 1993 when sagging power lines tripped after coming into contact with trees and resulted in the loss or reduction of more than 300 MW of load. The interruption was centered on the four-state border area of Arkansas, Kansas, Missouri and Oklahoma.
