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.
Meeting California’s 50% by 2030 renewable standard could require up to $5 billion or more in transmission upgrades, according to a report released this week by the California Energy Commission.
The report outlines what transmission projects the state must build or upgrade to connect load zones with areas identified as having the potential to provide more than 40,000 MW of new renewable capacity.
The study is a product of the Transmission Technical Input Group (TTIG) convened under the 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.
RETI has determined that California will need an additional 25 to 108 TWh of renewables annually to meet its mandate, depending on growth in vehicle electrification, adoption of behind-the-meter solar and the success of energy efficiency programs.
That translates into 7,000 to 31,000 MW of new capacity, assuming a 40% average capacity factor, or 9,000 to 41,000 MW assuming a 30% capacity factor.
It also estimates building all of the transmission identified would cost more than $5 billion.
The TTIG said the capital costs included in the report are considered “conceptual” or “high-level” estimates that were derived from previous studies, which “should not be considered as reliable for specific resource addition purposes.” Actual costs — including those for meeting the lower-end estimate of new renewables — will depend on a combination of factors, including the cost-effectiveness of developing a specific set of resources and the transmission paths necessary to reach them.
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” — or capable of reaching its load sink without hitting potential constraints.
California rules allow the state’s utilities to count only fully deliverable generation toward their resource adequacy requirements, excluding energy-only resources. For that reason, the TTIG, headed by CAISO Director of Infrastructure Development Neil Millar, assumed that all new renewable resources would require full-capacity interconnections.
CAISO can accommodate an additional 22,000 MW of energy-only resources, the report notes. The ISO is so far the only balancing authority area in the state to have studied the issue, so other BAAs have the potential to contribute additional energy-only capacity.
To perform its analysis, the TTIG broke the state into eight transmission assessment focus areas (TAFAs) where the large quantities of renewables could be developed to meet the state’s 2030 goals.
The Renewable Energy Transmission Initiative report examined the potential for developing renewables in eight California regions — as well as the transmission cost for reaching the resources. | California Energy Commission
“The TAFAs identify a ‘hypothetical’ development potential for wind, solar and, where applicable, geothermal resources,” the report says.
Those hypotheticals show a combined 15,000 MW of potential renewable development — mostly solar — in Southern California’s Imperial Valley, Riverside and Victorville/Barstow areas. To tap some of that potential, load-serving entities could have to foot up to $1 billion to relieve a constraint east of the Miguel substation close to the border with Mexico. A $34 million upgrade to the relatively short 500-kV Lugo-Victorville line could provide 2,000 MW in incremental capability, the report shows.
In the central part of the state, the San Joaquin Valley and Tehachapi TAFAs together have the potential for another 10,000 MW of mostly solar resources. While San Joaquin would require about $400 million in transmission upgrades, Tehachapi would require a negligible amount of work.
The least promising area: all points north of San Francisco and Sacramento, where it would cost $2 billion to $4 billion to tap an estimated 5,450 MW of wind, solar and geothermal resources — the largest share of the $5 billion estimate.
“The bulk transmission system in the region is heavily utilized and would require substantial investment to allow for the delivery of new full capacity resources,” the report says.
The study also evaluated the potential for sourcing additional renewable energy via California’s major interties, including the California-Oregon Intertie in the north (2,000 MW), the Palo Verde-Delaney line to Arizona (3,000 MW) and the Eldorado/Mead/Marketplace (3,000 MW) links with Nevada. All three were found to be subject to the same constraints as the TAFAs with which they interconnect, compounded by the fact that the imported energy would compete with TAFA resources for transmission access.
Entergy reported third-quarter earnings of $2.16/share Tuesday, beating analyst expectations, but its stock continued a months-long decline.
Despite beating Wall Street predictions of $1.95/share, according to Zacks Investment Research, Entergy shares have lost about $2.48/share since Monday’s close, a 3.3% drop. Its fall below $72/share continued its slide since setting a 52-week high of $82.08 in early July.
Nine of 11 analysts tracked by Zacks rate Entergy stock as a hold, with one rating it a strong buy and another a strong sell.
After the earnings report, Morgan Stanley downgraded Entergy to underweight, citing weak sales and risks to earnings from the potential disallowance of nuclear costs. It set a $68 price target.
Logo on Entergy Building in New Orleans, La. | photonews247.com
Entergy has announced it plans to shutter its Vermont Yankee (already being decommissioned) and Pilgrim (in 2019) nuclear plants in New England, and the company is attempting to sell its James A. FitzPatrick unit in New York in Exelon. Costs related to the closures were reflected in the corporation’s 2015 earnings, Entergy CEO Leo Denault said during a conference call with industry analysts Tuesday.
Denault said the company’s Arkansas and New Orleans operating companies have made filings with state regulators seeking approval to deploy advanced metering infrastructure (AMI) as early as 2019. Denault said AMI “will lay the foundation for an integrated energy network.”
Theo Bunting, Entergy’s group president of utility operations, told analysts the corporation has projected its total AMI investment at $900 million “on a system basis,” and includes development of the technology’s backbone.
“As you go through the filings, you will see that there were some costs we’re asking to defer that will get fully incurred prior to the full functionality of the meters themselves,” Bunting said. “We also believe that infrastructure is useful for other systems as well. So I think our perspective is the cost is consistent with what we’ve seen in implementations across the country.”
“We continue to make those modernizing investments that will lower production cost [and] provide significant benefits to our customers,” said Denault, adding that the corporation’s financial outlook reflects “our prudent decision to position the nuclear fleet for sustained operational excellence.”
Denault also told analysts the company has 48 projects “totaling roughly” $480 million up for consideration in MISO’s 2016 Transmission Expansion Plan (MTEP). Entergy has submitted another $700 million of proposed projects for MTEP 2017.
“We will work with MISO on the selection process for those proposals over the course of the next year,” Denault said.
The company says it expects earnings of $6.60 to 7.40/share for the year.
FERC granted a Maryland solar developer’s request to reinstate its position in PJM’s interconnection queue, which the company lost because of delays in obtaining state approval (ER16-2645).
Dan’s Mountain Solar initiated the interconnection review process in 2014 to connect its 18.36-MW project in Allegany County to Potomac Edison’s 138-kV Frostburg-Ridgeley line.
The developer obtained its facilities study from PJM in December 2015, triggering a 60-day countdown for signing the interconnection service agreement (ISA). PJM later extended the ISA deadline to June 2, 2016.
But the developer didn’t receive its Certificate of Public Convenience and Necessity from the Maryland Public Service Commission — a requirement for signing the ISA — until July 11, two-and-a-half months after the state had promised a decision and just more than a month after the project was automatically withdrawn from the PJM queue on June 7.
Because transmission upgrade costs are determined by a unit’s interconnection position, PJM intervened to note that reinstating Dan’s Mountain’s queue position could disadvantage interconnection applications that have been filed in the interim. But in a Sept. 21 email to the developer, PJM acknowledged that as of that date, no other projects would be negatively impacted by its reinstatement.
FERC granted the developer’s request for a waiver of the deadline following an expedited review, saying “it appears this waiver will not harm third parties.”
“Although PJM’s Oct. 6, 2016, comments assert that the potential for harm to third parties increases as time passes, PJM did not indicate that harm is imminent,” the commission said in its Oct. 25 order.
The waiver allows Dan’s Mountain to continue where it left off and avoid restarting the application process.
The Sacramento Municipal Utilities District (SMUD) will join the Western Energy Imbalance Market (EIM) in spring 2019 at the earliest, according to the head of the joint powers agency of which the utility is the largest member.
Shetler | United Way
“As you might guess, this is a very intense technical project,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), told RTO Insider.
The four utilities that have joined the EIM to date have required 18 to 24 months to begin operating in the EIM after signing an implementation agreement with CAISO, the market’s operator.
SMUD will likely sign such an agreement early next year, Shetler said. “We’re just starting to meet with the ISO to lay out project plans.”
The utility announced its intention to join the EIM on Oct. 21, citing the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)
SMUD would be a first municipal utility to sign up for the market — a status that could potentially complicate its efforts to join. Municipal utilities are not subject to FERC jurisdiction — but the EIM is. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
“With FERC oversight, we’re trying to understand what that would mean,” Shetler said. “SMUD has an open access transmission tariff that was approved by its board, but not by FERC.”
SMUD already operates under an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
A joint study conducted by BANC and the Western Area Power Administration estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market — a figure that nets out an estimated $6.7 million in implementation fees and $2.6 million in annual operations costs.
Shetler said that SMUD’s annual benefit could increase to about $5 million after five years, once the utility has paid down startup costs.
“It’s a big number, but a small number compared with their energy resource portfolio,” Shetler said. The real value will come in integrating the increased number of variable resources needed to meet California’s 50% by 2030 renewable energy mandate, he noted.
Sacramento Municipal Utility District headquarters | SMUD
SMUD would be breaking ground for possible future EIM participation by BANC’s other municipal utility members, including Modesto Irrigation District and the cities of Redding and Roseville.
Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, Shetler said. Trinity, a “full requirements” customer of WAPA, receives all of its energy from the federal agency.
Could other BANC members piggy-back on SMUD’s efforts and reduce their costs to join the EIM?
“We’re hoping that’s the case,” Shetler said. “We think there is some scale there.
“Not that it would be on the backs of SMUD or its ratepayers,” he added.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas.
BANC contracts with SMUD to perform day-to-day balancing functions.
The BANC-WAPA study spelling out EIM benefits is slated to be released to the public in late November.
