WESTBOROUGH, Mass. — ISO-NE is working to adopt clustering methodology, already used by every other ISO/RTO in the country, to speed the development of new transmission capacity, particularly to help free wind power trapped in Maine.
Transmission bottlenecks that prevent Maine’s wind generation from reaching load centers in Massachusetts and Connecticut could be relieved by allowing large and small generators to pool their interconnection requests, Al McBride, director of system planning, told the Planning Advisory Committee on Wednesday.
Mars Hill Wind Farm in Maine
McBride presented a Maine Resource Integration Study that showed how generators in the western and northern parts of the state could combine their interconnection applications and thus share costs on required upgrades. The grid operator could also analyze the combined interconnection requests in the same system impact study (SIS).
Interconnection Queue Backlog
ISO-NE has experienced a persistent backlog of interconnection requests in Northern and Western Maine, where several thousand megawatts of proposed resources have requested interconnection. In March, the RTO said it would not issue a competitive solicitation for the proposed Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. (See ISO-NE Nixes Keene Road Tx Upgrade.)
The proposed clustering methodology comprises two phases. In the first phase, the RTO will identify the initial designs of cluster-enabling transmission upgrades (CETU) in the regional system planning process. In the second phase, the RTO will conduct the cluster SIS to study the interconnection of the individual projects, together with the identified CETU.
New England is going to be looking at applying the clustering methodology to both AC and HVDC solutions. One speaker expressed concern that having two options would mean neither would reach critical mass, saying, “Sounds like you could have two undersubscribed” solutions.
Driven by the Wind
Wind resources looking to be included in such a cluster will have to join the transmission interconnection queue by about August. The study proposes that transmission owners prepare cost estimates by the PAC meeting in June, after which ISO-NE will calculate cost allocations and issue a draft report for comment.
As is currently the case, none of the shared or individual interconnection transmission upgrade and facility costs will be incorporated into regional transmission rates.
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In June 2015, the American Wind Energy Association petitioned FERC to initiate a rulemaking process to address “complex, time-consuming technical disputes” in the interconnection queue process that “undermine the ability of new generators to compete.”
In response, FERC last December issued a Notice of Proposed Rulemaking that would change the pro forma large generator interconnection rules to increase certainty and transparency for new resources (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
New Circuits
The Maine Resource Integration Study assesses new 345-kV AC transmission circuits that could connect to the areas with the largest number of interconnection requests. Evaluations include interconnecting with, or bypassing, existing lines and substations.
The New England Power Pool Participants Committee in February supported Tariff changes for the proposed interconnection clustering methodology. Two or more interconnection requests requiring common new transmission infrastructure would trigger the clustering methodology.
Participants in a cluster would be allocated a percentage of costs for shared upgrades and assume sole responsibility for facilities needed solely for their project.
WESTBOROUGH, Mass. — New England will have only enough natural gas capacity to supply about half of its gas-fired generation in winters 2025 and 2030 in most scenarios, according to an analysis presented to the ISO-NE Planning Advisory Committee on Thursday.
Mark Babula, ISO-NE system planning manager for resource adequacy, said the study showed the region will have sufficient pipeline and LNG capacity to supply all the gas generation with capacity obligations during the summer. But in the winter — when generators must defer to firm gas heating customers — the region won’t have sufficient capacity under most circumstances to run all the gas generation that could be economically dispatched.
“When we’re talking about dispatch, what we’re looking at from the natural gas system perspective is meeting the contractual requirements to the [local distribution companies],” said Michael Henderson, ISO-NE director of regional planning and coordination. “That then gives you some extra gas available that can potentially serve natural gas-fired generation. It’s just different looks at how much natural gas-fired generation can be brought on.”
The ISO-NE study considered six natural gas system topologies and six “resource expansion” scenarios to determine whether there is sufficient “spare” gas for electric generation after meeting all firm customers’ needs:
Installed Capacity: All gas-fired generation with capacity supply obligations — a summer focus that represents the upper band of gas consumption by the electric sector. Even under the minimum gas infrastructure case, there is enough spare gas to fuel all gas-fired generation in the summers of 2025 and 2030, but there is only enough spare gas in the winters to serve about half of the gas-fired installed capacity.
Dispatched Capacity: Gas-fired dispatched capacity requirements on the winter peak gas day, when only a portion of installed gas capacity is needed to serve electric demand.
Energy Generation: Whether there is enough gas to satisfy the maximum hourly electric energy production by gas-fired generation on the summer and winter peak gas-days. The analysis found sufficient gas for all summer generation needs. For winter 2025, however, there would be sufficient gas for only 6.8 to 9.6 GW of generation, representing 42 to 59% of the projected installed capacity. By winter 2030, the gas could run between 5.3 and 10.1 GW — as little as one-third of the installed capacity.
Only one of six resource expansion scenarios (“Renewables Plus”) meets the dispatched capacity and energy generation requirements for winters 2025 and 2030, even assuming the “maximum gas infrastructure” — reflecting pipeline expansions, increased peak shaving by LDC, and LNG from offshore and ENGIE’s Distrigas terminal in Everett, Mass.
“In the summertime, we’re good. There’s actually leftover gas: We could actually run another 12,000 to 15,000 MW, there’s so much excess pipe available,” Babula said. “When you get into those polar vortex sort of days, we often hear from generators that have just been called by the gas pipe to get back on their ratable take and shut off the valve.”
Babula pointed out that the analysis studied only winter and summer peak days. ISO-NE is also conducting a Fuel Security Analysis that will quantify the operational risks of insufficient fuel for the entire 90-day winter period. ISO-NE on May 22 published a summary of the analysis, which is expected to be completed this fall.
While the RTO’s analysis looks at the system’s maximum, short-term capability, the ISO-NE study will determine how often the system likely to be stressed during the winter under different scenarios.
LNG’s Role
LNG from Distrigas, the Canaport terminal in Saint John, New Brunswick, and offshore floating storage regasification units are critical for meeting the peak gas-day requirements of the electric sector, according to the study. Without these gas supply sources, approximately ~1.5 Bcfd (~214,300 MWh/d) would be taken out the market.
Management consultant Richard Levitan asked whether the floating storage wouldn’t better be classified as a commodity, considering how inflexible the arrival of LNG carriers can be. Babula said that in the past couple years there have been “ships at the buoy” on most peak gas days, so they included them in the study.
[EDITOR’S NOTE: An earlier version of this article mistakenly said the analysis was conducted by the New England Power Pool. It was conducted by ISO-NE.]
Six Resource Expansion Scenarios
The resource expansion scenarios were:
S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.
MISO and PJM are evaluating eight proposed interregional market efficiency projects, but a supplemental project by American Electric Power could undermine most of the proposals.
MISO and PJM received three upgrade and five greenfield proposals for three congested flowgates ranging from $1 million to $198 million.
Proposals were due at the end of February on interregional projects for constraints MISO and PJM previously identified. (See “2017 MEP Identification Underway,” FERC Signals Bulk of NIPSCO Order Work Complete.)
MISO and PJM will evaluate the proposals’ benefits based on the first 15 years of service, benefit-cost ratios and the cost split between RTOs, Eric Thoms, MISO manager of planning coordination, said at a May 23 Joint and Common Market meeting. AEP-Exelon, NextEra, Northern Indiana Public Service Co., AEP-NIPSCO, WPPI Energy and Northeast Transmission Development submitted proposals, most offering 138-kV projects and a few submitting 345-kV solutions.
All but two of the project proposals focus on the Olive–Bosserman constraint near the western Indiana-Michigan border. Transource Energy also submitted an interregional proposal to correct congestion along the southern Indiana-Ohio border with a new 138/345-kV substation and lines, and NIPSCO presented a new 138-kV line proposal to relieve congestion along the northern Illinois-Indiana border.
Complicating matters, AEP also announced plans for a supplemental project — a project type funded wholly by the transmission owner and therefore not requiring PJM approval — that diminishes the severity of the Olive–Bosserman constraint.
AEP would increase voltage and reroute nearby PJM circuits dating back to the 1930s, with two new 138/120-kV distribution stations to replace lower-voltage stations. The project is still in conceptual stages, AEP said.
PJM staff said the AEP project would relieve some of the congestion on Olive–Bosserman but that the interregional proposals could still provide benefits. MISO and PJM have yet to study the effects of the supplemental project on the six interregional proposals.
At a May 26 Interregional Planning Stakeholder Advisory Committee conference call, NIPSCO’s Miles Taylor asked if the supplemental project would be included in the RTOs’ evaluations of the interregional proposals. PJM interregional planning manager Chuck Liebold said PJM will put the project into a base case scenario if AEP decides to pursue the project. Stakeholders reminded RTO staff at the meeting that developers spent a lot of time and money on the interregional proposals, expressing concern that they could be negated by AEP’s project.
“This [supplemental] project is happening to get attention now because of its impact on interregional projects. We get many, many supplemental projects all the time,” said Liebold, adding that RTO staff has no control over which are built.
The RTOs hope to have preliminary benefit numbers on the interregional projects by the end of June.
Project evaluation will continue for each RTO individually and in the IPSAC through the end of September. Selection of the interregional projects is expected to begin in the fall.
Thoms said that if any projects arise out of the two-year interregional process, they will be sent before the RTOs’ boards for approval by December.
Meanwhile, MISO has asked FERC for an 18-month extension to settle on an internal cost allocation approach under the commission’s directive last year that the RTO allow interregional market efficiency projects as low as 100 kV (ER16-1969). Stemming from a 2013 NIPSCO complaint, FERC’s order also directed MISO to remove its $5 million cost floor for interregional projects with PJM. (See FERC Signals Bulk of NIPSCO Order Work Complete.)
VALLEY FORGE, Pa. — PJM’s Planning Committee on Wednesday held its first special session on cost caps and other cost-containment provisions for competitive transmission bids. The RTO expects that any recommended procedure changes that are identified by the sessions will be incorporated in the new Manual 14F: Competitive Planning Process, which received its third “first” reading at the Markets and Reliability Committee meeting last week.
At the initial meeting, PJM provided several examples of cost-recovery and cost-containment mechanisms that have been proposed. Stakeholders indicated an interest in a standardized lexicon for cost-containment descriptions to aid in comparing project proposals.
Ruth Ann Price of the Delaware consumer advocate’s office urged keeping the process simple and argued for allowing very few exemptions to cost caps.
Sharon Segner of LS Power suggested that there’s a role in the discussion not only for FERC, whose Order 1000 opened up transmission development to competition, but also for the regional planning organizations to encourage cost containment proposals.
Following a technical conference in June reviewing the first five years under the order, the commission asked for comments in response to a series of questions on cost-containment provisions (AD16-18). (See FERC Calls for Post-Conference Comments on Order 1000.)
FERC asked for information on how transmission providers compare proposals with and without cost-containment provisions; whether it should provide guidance or requirements on the use of such provisions; suggestions for ensuring the transparency of evaluations; and whether there should be standardization of cost-containment provisions or exclusions of certain costs to facilitate comparison of proposals with differing containment provisions. The commission also asked what types of performance-based rates it could accept to reduce “asymmetrical risk.”
The next big question for PJM’s initiative is to determine if the focus should be on capital costs or annual revenue requirements. Stakeholders noted that PJM’s focus has historically been on capital costs.
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Through PJM’s 13 competitive windows since 2013, about 18% of 650 proposals included cost-containment provisions. Of those, two projects were selected.
Cost caps have been more common in other regions. Of 12 competitive windows including CAISO, SPP and MISO, 54% of the 56 proposed projects and 55% of the selected projects included cost-containment provisions.
The committee’s next special session is scheduled for July 18.
ANCHORAGE, Alaska — A nearly 40-year-old federal law enacted to spur competition in the power industry is badly outdated and in need of reforms to reflect the current markets, critics of the law said during a panel at the annual Western Conference of Public Service Commissioners last week.
“I kind of feel like I was invited to lunch only to find out that I am the lunch,” joked Jan Smutny-Jones, CEO of the Independent Energy Producers Association, and the lone defender of the Public Utility Regulatory Policies Act on the panel.
The discussion was moderated by Idaho regulator Kristine Raper, whose commission has been an outspoken opponent of PURPA because of its impact on Idaho Power, which has faced mandatory purchase obligations equal to half its load. (SeeFERC Conference Debates PURPA Costs, Purchase Obligations.)
Before setting out his case against PURPA, Jonathan Weisgall, vice president of government relations at Berkshire Hathaway Energy, provided a brief history of the act.
Congress passed PURPA in 1978 in response to the mid-70s energy crisis, Weisgall pointed out. The law was designed to promote energy conservation and increased use of domestic energy resources, including cogeneration and renewables. It mandated that all electric utilities — including municipals and cooperatives — purchase electricity from “qualifying facilities” at the utility’s “avoided cost.” QFs were defined as cogenerating plants and small power producers — under 80 MW.
But the energy sector has “changed completely” in the 40 years since PURPA’s passage, according to Weisgall, and the law — including FERC’s regulations implementing it — have not kept up.
He recounted a litany of complaints over the law: Utilities are required to buy power that is neither necessary nor cheap, and they have no control over where QF projects are integrated into the system. PURPA contracts can be lengthy and are not subject to the same resource planning and cost scrutiny as other utility decisions, undermining state integrated resource planning and processes. QFs are not subject to the same curtailment procedures as other generators, yielding an unfair advantage.
“And, lastly, since QFs are not subject to resource planning … significant additions of unplanned renewable QFs can cause reliability issues if they don’t provide planned-for ancillary services,” Weisgall said. “So PURPA is simply outdated.”
Former FERC Commissioner Philip Moeller, now a senior vice president with Edison Electric Institute, concurred with Weisgall, calling PURPA “a relic of another era” and saying the country’s generation fleet has achieved the diversity envisioned by the act.
In 1978, Moeller pointed out, the U.S. produced more than 16% of its electricity from oil. “Now it’s down to 1%. The resource mix has changed dramatically.”
Both Moeller and Weisgall pointed to the 1992 Energy Policy Act as being the driver in transforming the market for generation in recent decades.
“FERC’s requirement of open access to transmission and standardized interconnection rules and procedures for smaller facilities have removed structural barriers to entry and opened up opportunities for new entrants, including QFs, to supply wholesale energy to distant markets whether a utility is a member of an RTO or not,” Weisgall contended.
“We now have better markets. We didn’t have RTOs then, or an EIM,” Moeller said, referring to the CAISO-run Western Energy Imbalance Market.
“Talking about EIM as a competitive alternative — QFs don’t participate in that market,” Smutny-Jones countered. “The reality is that I seriously doubt that there’s any utility in the West that would come to [a utility commission] and say, ‘Don’t worry about it, I’m going to cover the cost of my power plant in the EIM market.’ This isn’t going to happen.”
Smutny-Jones, whose organization represents independent power marketers and generators in California, agreed that “PURPA has been with us for a while.” Like other energy rules, it could be “fine-tuned from time to time.”
“But I think it has usefulness, I think it will continue to have usefulness to push where we don’t have some competitive pressure on vertically integrated utilities,” he said.
Moeller pointed to another reason to roll back PURPA’s purchase obligations: the success of energy efficiency measures.
“We have flat to declining load growth in electricity, something that was unfathomable for decades and decades and decades,” he said. “Modern reality comes down to … in many cases, utilities are required to buy power they just don’t need in a flat or declining demand situation.”
On top of that, Moeller argued, utilities are often paying above-market prices.
“When you add to the cost of power and customers have to pick that up, it has a reverse impact [on efficiency]. Take a look at the Northwest: The No. 1 resource for the Northwest Power Pool for 25 years has been efficiency. That is their first choice,” he said.
Smutny-Jones questioned the premise that declining load should be cited as a reason to roll back PURPA.
“If I heard my colleagues correctly, you should all be seeing [integrated resource plans] coming before you that show no new builds ever in the West. I don’t think that’s true,” he said. “I don’t pretend to have read the IRPs in 13 western states, but I guess that there will be a significant amount of build-out of different kinds of generation over the next 10 years or so, and that should be subject to pressure from PURPA.”
‘More Tools, not more Constraints’
Weisgall laid out a series of recommended changes.
Among them: Congress should modify the purchase obligation to clarify that states that utilize IRPs have the authority to decide whether their utilities are obligated to purchase from QFs. In addition, Congress should reduce the size of QFs to “well below” 80 MW and modify FERC’s “1-mile rule” in order to prevent suppliers from disaggregating their projects “to essentially game the system.”
The 80-MW threshold applies to all generating facilities at the “same site” — which FERC has defined as all facilities within 1 mile of the facility seeking QF status. Weisgall said Congress should redefine “comparable markets” to relieve utilities participating in voluntary auction-based and energy imbalance markets from the mandatory purchase obligation.
Weisgall also thinks state commissions should exercise more discretion on the length of PURPA contracts and avoided-cost calculations to ensure those costs are no higher than competitive wholesale market prices — citing LMPs and auctions as potential proxies.
“States need more tools, not more constraints,” he said.
Smutny-Jones acknowledged that his state of California made some mistakes early on in its adoption of PURPA when it set avoided costs based on oil at about $100 a barrel.
“We learned from that,” he said, adding that in the early 1990s California created a system in which utilities put out a hypothetical generating resource that suppliers could bid against.
“And it was hugely successful,” Smutny-Jones said. “The prices were significantly lower than what the utilities had suggested they would be.”
“There’s a lot of power in the states to try to modify PURPA in ways that can work for you,” he said, addressing regulators in the audience.
Smutny-Jones noted that the avoided-cost formulation falls to state regulators.
“So you can either count on the market to give you that number and have people compete against each other, or you can try to come up with a complicated formula,” he said. “I would have to caution you about that latter [option] because you’ll get it wrong,” he said.
Why ‘Avoided’ Costs?
Weisgall said Smutny-Jones had raised “an interesting point of history.”
“Why did PURPA use the term ‘avoided costs?’ Because there were no market prices. There were no markets as such, so that was the formula, and today of course there are market prices, but we have still have to worry about what avoided cost means, which has kept generations of lawyers employed.”
Weisgall posed a question about states that allow third-party suppliers “complete access” to the transmission system.
“Why do they need PURPA if you’ve got a solar farm and it’s a great one and its [cost is] below what the utility could build? We’re already seeing with our NV Energy utility in Nevada that we are losing some major customers — casinos — where they are finding third-party providers. Well why do we need PURPA under those circumstances?”
Smutny-Jones acknowledged that PURPA is no longer an issue in California because the state’s aggressive renewable portfolio standard has created a strong market for third-party generation. “My phone hasn’t rung off the hook about PURPA for a very, very long time because people have other places to go with their resources,” he said.
Moeller wrapped up the discussion with a call to arms directed at his former agency rather than the state commissioners in attendance.
“I don’t think I’m overstating a full-blown crisis when a utility in Idaho that’s guaranteed [to be] long power until at least 2035 is being required to buy at the cost of … $3.1 billion over the next the next 20 years … for power they don’t need.
“That’s pretty serious. So I think a newly rebooted FERC will have to address this.”
WESTBOROUGH, Mass. — ISO-NE’s 2017 Economic Study will reflect the same basic assumptions and use the same profiles as those in the 2016 study, while representing some incremental changes to the former study’s third scenario. Marianne Perben, manager of resource adequacy and technical studies, outlined the 2017 study’s scope of work to the Planning Advisory Committee on Thursday, saying it will produce metrics similar to those in the 2016 report being completed now.
The 2017 study will include analysis that the Conservation Law Foundation requested at the April PAC meeting. The CLF wants the grid operator to determine whether there are viable system topologies other than those analyzed in Scenario 3 of the 2016 study with similar total system emissions but a lower relative annual resource cost.
Strong Mass. Economy Nudges up 2017 CELT Load Forecast
The 2017 Capacity, Energy, Loads and Transmission Report shows a reduced RTO load forecast from 2016 but predicts an increase in load for the Southeast New England area because the Massachusetts economy is growing faster than those in other New England states.
ISO-NE system planner Manasa Kotha on Wednesday presented a report on future capacity requirements, which credited some of the increase to changes in the operating company distribution of the load to the buses, and some to the Massachusetts economy, which is expected to grow at a compound annual growth rate of 2.1% through the forecast horizon.
The report covers net installed capacity requirements (ICR) for capacity commitment periods 2022/23 through 2026/27, ranging from 34,300 MW in the first cycle covered to 35,700 MW in the last.
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The load forecast is net of behind-the-meter solar PV resources. Energy efficiency is treated separately — modeled as a supply-side capacity resource in the ICR calculations.
For additional background, Kotha referred participants to a Reliability Committee presentation on the ICR Values for CCP 2020/21 covered by Forward Capacity Auction 11.
Locational Reserves Good in Key Load Centers
Salem Harbor Generating Station
Generation and transmission additions expected to be completed by 2019 will ensure sufficient operating reserves in Greater Boston, Greater Connecticut and Greater Southwest Connecticut through 2021, according to a report on reserve needs for major import areas.
Forward reserve requirements for the Northeast Massachusetts/Boston zone have ranged from 300 to 500 MW for the last three summers, and 0 MW for the winters. The report calls for 279 MW this summer and 200 to 650 MW for 2018, dropping to 0 to 50 MW after the addition of the 674-MW Footprint Power quick-start combined cycle plant at Salem Harbor, which is expected online by the end of the year.
ISO-NE resource adequacy planner Fei Zeng, who presented the report to the PAC on Wednesday, said that fast-start resources near those major load centers provide flexibility to the grid.
WESTBOROUGH, Mass. — A substantial increase in new clean resources would lower Forward Capacity Auction prices, “crowding out” many existing resources — but their ability to do so will depend on the level of offer mitigation, according to an analysis commissioned by ISO-NE.
ISO-NE last year asked Analysis Group to assess outcomes in the Forward Capacity Market under six resource expansion scenarios evaluated in the second part of the 2016 Economic Study. (See scenario descriptions below.)
Todd Schatzki of Analysis Group briefed the Planning Advisory Committee on Thursday on the study, which assumes all current market rules. The study assumes retirements of 2,457 MW by 2025 and 4,668 MW by 2030. Absent retirements, Schatzki said, there’s limited need for new resources.
“Given low load growth, given what’s going on behind the meter and given that there is not necessarily a lot in the queue that is coming in, absent some market price signal, you’re not going to get new resources coming in,” said Schatzki, who prepared the report with colleague Christopher Llop. “You’re not going to get prices raising back up towards the cost of new entry unless some new resources get in the system.”
Capacity and Energy Market Implications
Total Forward Capacity Market payments in 2025 are projected to range between $2.1 billion in Scenario 3 (“Renewables Plus”) to $3.8 billion in Scenarios 2 (“ISO Queue”) and 6 (“RPS + Geodiverse Renewables”), with energy market revenues projected between $7.7 billion and $8.8 billion.
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Scenarios with renewable additions would require additional revenue streams from outside the ISO-NE markets because they have a higher cost of new entry, the study says. Substantial expansion of clean resources as in Scenario 3 “would lower FCA prices, crowding out existing resources.”
“As the quantity of new clean resources added to the system increases, the cost (per MWh or MW) of supporting clean resources increases. The gap in revenue requirement (for new entry) needs to be filled by other sources because of decreases in revenues from both the FCM and energy markets.”
These impacts would depend on what portion of new renewables participate in the capacity auction and the extent of offer mitigation under the minimum offer price rule. The study assumes continuation of the current 200 MW/year renewable exemption, evaluating mitigation levels through sensitivity analyses.
Under four of the scenarios (1, 2, 5 and 6), the combination of energy, ancillary services and capacity revenue is sufficient to support the entry of new gas-fired combustion turbines. But market revenues are insufficient to incent the development of all other new resources assumed to enter the market in each scenario and none of the scenarios provides sufficient revenues for new combined cycle plants.
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“Clean” resources — including offshore wind, hydro imports, battery storage and behind-the-meter solar, — would require other revenues, such as state renewable portfolio standards. “Needed revenues increase with the expansion of clean resources, as these resources reduce prices in both the energy and capacity markets,” the study says.
Total payments in the ISO-NE markets range from $9.7 billion to $15.6 billion, excluding ancillary service payments. The total payments do not include the costs associated with state policies.
ISO-NE completed Phase I of the Economic Study earlier this year and in June will issue the final part.
Robert Ethier, vice president of market operations, outlined the scope of work and for background information referred participants to a study on Forward Capacity Auction results published in December 2016.
Six Resource Expansion Scenarios
The resource expansion scenarios were:
S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.
AUSTIN, Texas — ERCOT stakeholders last week unanimously endorsed Oncor and American Electric Power’s 345-kV Far West Texas Project that addresses continued load growth southwest of Odessa, Texas.
Since 2010, the area has seen annual load growth of about 8%, driven by increases in the region’s oil and natural gas production. While demand growth projections have tapered off recently — only 2.4% through 2020 — Oncor predicts annual load growths as high as 11% within portions of the area over the next five years. More than 1,600 MW of solar resources are expected to come online during that time frame.
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Oncor and AEP’s original request to ERCOT’s Regional Planning Group last April estimated the project’s price tag at $423 million.
However, a staff review of 40 different alternatives lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place — substation expansions and other transmission elements. One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second, 68-mile 345-kV line would run from the Solstice switching station to the Bakersfield switch station. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”
Two of the other options would have closed the 345-kV loop between the two lines, while a third would operate the transmission lines at 138 kV on double-circuit structures. The costs ranged between $446 million and $501 million.
“My only concern is it keeps a tight bandwidth on future growth,” Oncor’s Collin Martin said during Thursday’s Technical Advisory Committee meeting.
Staff admitted the loop could be completed but said its recommended option would provide the best reliability solution while “augment[ing] the load-serving capability … as the outlook for greater load and generation resources in this region becomes more certain.”
The project has been proposed to go in service by 2022. Oncor, AEP and the Lower Colorado River Authority would be responsible for the parts of the project within their service territories.
The project still needs approval from the ISO’s Board of Directors and a certificate of convenience and necessity from the Public Utility Commission of Texas.
Rayburn Country Integration
Staff also updated the TAC on the potential integration of the 20% of Rayburn Country Electric Cooperative load that sits in the Eastern Interconnection. The East Texas co-op is considering connecting the load — approximately 190 MW — to ERCOT as early as December 2019. The ISO already serves the other 80%.
A study has identified a least-cost option of $38 million, primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines.
Southern Cross HVDC Project
TAC Chair Adrienne Brandt, of San Antonio’s CPS Energy, asked the Reliability and Operations Subcommittee (ROS) to schedule a joint workshop with the Wholesale Market Subcommittee to resolve issues arising from the PUC’s final scoping order related to an HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.
“This will ensure everyone has transparency between what the other group is talking about and make sure there are no conflicts,” Brandt said.
The PUC has directed ERCOT to complete a number of tasks before it allows the city of Garland to energize an approved 38-mile, 345-kV line that would interconnect the Texas grid to the Southern Cross DC tie in Louisiana. The tasks identified in the commission’s final order include determining Southern Cross Transmission’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and resolving price-formation issues (Docket 45624).
ERCOT’s effort to increase visibility into distributed energy resources will begin at the subcommittee level after the TAC declined to get into an in-depth discussion of the growing challenge posed by small generation sources.
Saying she did not want to have the discussion at the TAC “just yet,” Brandt proposed starting it at the ROS. She did not receive any pushback.
ERCOT has proposed a collaborative process involving transmission and distribution service providers (TDSPs), “in which the locations of large DERs or large clusters of small DERs are mapped to their appropriate modeled transmission loads.”
The ISO has published a white paper, in which it proposes working with TDSPs to develop “a standardized method of providing and collecting appropriate data for mapping current and future registered DER units” to their common information model (CIM) loads. Staff said they will also work with stakeholders to develop a process for DSPs in competitive choice regions and non-opt-in entities (NOIE) “to monitor the accumulation of clusters of unregistered (less than 1 MW) DER units connected to specific CIM loads.”
Based on annual reports filed at the PUC, staff estimates nearly 900 MW of distributed generation were interconnected as of Dec. 31, 2015, along with more than an estimated 200 MW deployed in NOIE territories. (The reports use the terms DG and DER interchangeably.) Staff has added 20 new registered DER since November, giving ERCOT a total of 99 registered DER as of May 1.
The ISO suggests working with the TDSPs to jointly develop thresholds for “accumulations” of DER, reporting those that exceed the threshold and mapping clusters that exceed the threshold to a CIM load.
ERCOT defines DER as generation, storage technology or a combination of the two that is interconnected at or below 60 kV and operates in parallel with the distribution system. DER does not currently include demand response.
Woody Rickerson, ERCOT’s vice president of grid planning and operations, told the TAC the white paper builds on the Distributed Resource Energy Ancillaries Market (DREAM) task force’s work, which ended last year. (See “DREAM Task Force’s Work Now Ready for Stakeholder Process,” ERCOT Tech Advisory Committee Briefs.)
He said staff wants to produce annual reports so the grid operator knows how many DER are in its footprint and “what makes sense with aggregation.” Staff will insert the resources into the network model as it maps them to their CIM load points, improving the control room’s situational awareness.
ERCOT Reports Software Issue, Schedules Meeting on Outages
COO Cheryl Mele alerted the TAC to a market notice reporting on a May 22 incident in which a vendor’s issue-tracking system briefly allowed its software clients to view tickets from any other client, including ERCOT. Upon being notified by a non-ERCOT market participant and stakeholder, the ISO asked the vendor to shut down access to the system.
In the market notice, the ISO said it has been told a forensics team “has not found any evidence to suggest that information from ERCOT’s tracking system has been viewed by other software clients.” It is also conducting an internal investigation to evaluate the types of information in the tracking system and to try and determine who accessed or could have accessed the ISO’s information.
Mele also told the committee the Texas grid operator will host a June 15 WebEx on extended 345-kV outages in Northwest Texas this summer. Electric Transmission Texas (ETT) notified ERCOT on May 19 it would be inspecting a number of transmission lines ETT built as part of the Competitive Renewable Energy Zone and, if necessary, replacing components as a part of a warranty claim.
The outages are expected to last through November 2018.
Revision Requests Pass Easily
Confronted with 19 revision requests, the TAC separated onto a consent agenda those requests that had reached the committee unopposed or had impact assessments of more than $10,000.
The only nodal protocol revision request (NPRR) to receive an opposing vote was NPRR831, which also received one abstention, relating to private-use networks — networks connected to the ERCOT grid that contain load that is typically netted with internal generation and not directly metered by ERCOT. The change updates market systems to calculate a net load value for each private-use network that will be included in the load zone price for all markets, when the load is a net consumer from the ERCOT grid.
The NPRR was given urgent status to address instances in which LMPs do not reflect congestion. Kenan Ögelman, ERCOT’s vice president of commercial operations, said from a system perspective, “This is the quickest way to do this accurately.”
The committee passed NPRR827, which bars the ISO from awarding point-to-point (PTP) obligations in the day-ahead market when the corresponding clearing price is greater than the bid price by 25 cents/MWh or more, passed with one abstention.
ERCOT’s Carrie Bivens, manager of forward markets, said there is a market-design problem in the way PTP obligations are currently cleared in the day-ahead market. “We’re contemplating a different design choice for a long-term solution,” she said.
The committee unanimously approved NPRR830, which has an impact assessment of $120,000 to $160,000 and revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC-tie flows.
Members approved editing the business case to say the NPRR will “avoid rebilling costs resulting from the assignment of the 4-CP to an incorrect interval” and that it is consistent with direction from the PUC.
A pair of revisions to the Planning Guide (PGRRs) sailed through individual votes without opposition, but PGRR058, which clarifies specific generation to be included in the guide, was sent back to the Protocol Revision Subcommittee.
PGRR056: Accounts for potential subsynchronous resonance (SSR) vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR and removing its definition from the guides. SSR is a potentially harmful phenomenon involving coincident oscillation between two or more transmission elements or generation resources at frequencies lower than the ERCOT system’s normal operating frequency (60 Hz). The change aligns the Planning Guide with ERCOT comments to NPRR562, which was also approved. NPRR562 clarifies responsibilities for affected entities and creates new requirements for the identification, study, mitigation of and protection against SSR. The ERCOT system has become more vulnerable to SSR because of the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and/or resources and lead to cascading outages. The NPRR was first introduced four years ago.
PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
The consent agenda included three additional NPRRs, three changes to the Retail Market Guide (RMGRR), a change to the Verifiable Cost Manual (VCMRR), and revisions to the Commercial Operations Market Guide, Load Profiling Guide, Nodal Operating Guide and the Resource Registration Glossary. The guide and glossary changes expand the list of revision requests requiring ERCOT board approval and would first consider those revisions at the voting subcommittee level.
NPRR796: Specifies that character set validations are available within each Texas standard electronic transaction (TX SET) implementation guide, which recognizes all characters within the basic character set.
NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts (EEA) and real power balancing control performance.
RMGRR145: Provides the format for transmission or distribution service providers, municipally owned utilities and cooperatives to use a mass customer list to inform market participants of all customers in its service territories when entering competition or expanding its service territory.
RMGRR146: Expands the list of RMGRRs requiring board approval and provides additional clarifications to the RMGRR process.
RMGRR147: Updates protocol language by providing the option of generating a standalone invoice for meter tampering charges when there is no change in usage consumption.
VCMRR018: Aligns the manual’s revision process with the Protocols and market guides by changing the length of the comment period for newly submitted VCMRRs from seven to 14 days; requires review of all VCMRR impact analyses by the Wholesale Market Subcommittee; aligns the process for submission and review of urgent VCMRRs with other revision-request types; expands the list of VCMRRs requiring board approval; and provides additional revisions to mirror the Protocols and market guides.
ANCHORAGE, Alaska — Organized electricity markets could provide significant benefits for the West, but state regulators should approach their development with a critical eye, market leaders said last week.
“There is value in markets, and as a result, I’d encourage you to get educated about the benefits of them, and seeing also how it may get to change how you regulate utilities,” SPP General Counsel Paul Suskie said during a panel discussion entitled “Energy Imbalance Market or the Wild West Interconnect” at the annual meeting of the Western Conference of Public Service Commissioners.
‘Healthy Skepticism’
“Have a healthy skepticism. That’s what I used to be required to do,” the former Arkansas Public Service Commission chairman added.
EIM Governing Body member Carl Linvill, formerly a Nevada commissioner, recounted how his career path has imbued him with a dose of skepticism about markets. A former economics professor, Linvill moved to Nevada two decades ago to help build a market monitoring framework for the state’s proposed retail deregulation. In the wake of the Western Energy Crisis of 2000-01, the governor handed him the responsibility for unwinding the experiment in restructuring.
“My interest in coming out to Nevada for the job was [that] I was little bit concerned about over-optimism in the markets,” Linvill said. “I like markets, I think markets can be very beneficial, but I think that you have to have the right … legal structure [and] context for markets to work well.”
Linvill noted that each of the Governing Body’s five members is an outsider to CAISO, which operates the market. Members value the expertise of the ISO, as well as its state-of-the art operations, he said.
“But, also, having been outsiders and knowing that we need to be critical, we also take it as part of our job to question and challenge [ISO] staff and to try to push them to understand the perspective [from] our former roles,” Linvill said.
Linvill described to the audience of mostly commissioners and their staff how the Governing Body maintains independence from the ISO and exercises oversight over the market.
After originally being selected by a stakeholder nominating committee and approved by the CAISO Board of Governors, the body now approves its own members. The body — not the board — exercises “primary authority” over any ISO initiatives that wouldn’t have arisen without the existence of the EIM, meaning it can vote to recommend an EIM-related proposal.
“The Board of Governors can accept or reject, but they cannot amend or alter the proposal,” Linvill said.
Suskie touted the benefits of SPP’s own energy imbalance market — the precursor to the RTO’s current market — which saved members $1.1 billion between 2008 and 2013, far exceeding projections of $600 million.
“The higher the gas prices, the better the benefits of trading,” Suskie said, pointing out that the greatest savings occurred during the market’s early years when natural gas prices exceeded $7/MMBtu.
SPP’s incorporation of the day-ahead market in 2014 yielded another $1 billion in benefits, Suskie said.
While comparatively modest, the Western EIM’s benefits have grown consistently with the addition of new participants. The market now encompasses more than 50% of the region’s load, according to Stacey Crowley, vice president of regional and federal affairs at CAISO.
Crowley said the EIM has saved nearly $174 million since its inception in November 2014, including $31 million in the last quarter — an all-time high. (See CAISO EIM Exports Rise with Spring, Report Shows.)
Other benefits include the reduced curtailment of renewable generation, which can be offloaded into neighboring balancing authority areas, and sharing, which has reduced the need for EIM participants to carry flexible ramping reserves.
“The benefits continue to accrue,” Crowley said. “It really comes down to more efficient dispatch. It’s both interregional and intraregional. So we optimize within the balancing authority and between balancing authorities to really take best advantage of the resources that the Western utilities have.”
Qualitative Benefits
Linvill highlighted the importance of the qualitative benefits issuing from the EIM’s approach to dispatch.
“I think that a side benefit of this is that there’s much greater visibility within the utilities and within the [EIM] footprint region on what’s actually going on and what resources are available, what their capabilities are, [and] what the transmission system capabilities are. I think there’s much better information about that now then there was” before the market, he said.
Those qualitative benefits were enough to swing Arizona’s Salt River Project to join the market after determining that membership would be a financial “wash” for the publicly owned utility, Linvill said.
“I asked them, ‘How important were the non-quantified benefits, these other benefits?’ And they said, ‘Those were the driving benefits. We see this as an essential step to modernize our operations now so we can keep up as things evolve,’” he said.
Linvill said he has respect for markets that work well but recognizes that they can go awry.
“So, job one is to protect these benefits that have been created, to take this step-by-step, to add entities to the footprint, to potentially add services at some point. But we’re not rushing to that or even discussing that at this point,” he said. “Really, we want to make sure that we establish a market that has stability and robustness and continues to produce these benefits.”
Patrick Lyons of the New Mexico Public Regulation Commission questioned Crowley about whether EIM participants face exit fees.
“There is no exit fee. Entities can choose not to participate by just not bidding in resources or they can leave altogether, so that’s a nice benefit as well,” Crowley responded.
“So if a company wants to get out, and you’re counting on them being in there, how does that work? It doesn’t seem very stable,” Lyons said.
“I think that the benefit is that we’re not counting on them,” Crowley said. “This is above-and-beyond optimization that we do normally every day, so we’re going to continue to balance the load and resources based on what resources are available to the market.”
AUSTIN, Texas — ERCOT staff said its preliminary analysis of Lubbock Power & Light’s integration into the Texas grid reveals as much as a $66 million increase in production costs to serve the additional 430 MW of load.
| ERCOT
However, those costs will be offset to some degree by unlocking wind generation currently trapped in the Texas Panhandle. Integrating the LP&L system would require 141 miles of new 345-kV transmission lines — at a cost of $364 million — according to a separate ERCOT study completed last June.
Jeff Billo, ERCOT’s senior manager of transmission planning, said staff evaluated the years 2020 and 2025 with and without LP&L’s load. The analysis indicated an increase of $66 million and $60 million, respectively, in fuel costs to serve the additional load.
Billo said the final report will look at SPP’s production costs to determine the overall financial impact to the ISO. He declined repeated requests from Technical Advisory Committee representatives to discuss SPP’s preliminary numbers, saying only that the RTO’s production costs would decrease.
“Their decrease is less than our increase. That kind of makes sense, because we see an increase in the Panhandle’s export capability,” Billo said, referring to the transmission necessary to connect LP&L to ERCOT.
“We see more Panhandle wind getting to market with the Lubbock system integrated. The full cost of serving the load is somewhat offset by production-cost savings of [the] Panhandle wind,” he said.
| ERCOT
The integration would require ERCOT to update its systems and documentation to accommodate LP&L’s 115-kV facilities. The additional infrastructure will strengthen the Panhandle system and increase transient and voltage stability and reduce congestion. The LP&L load will also contribute to ancillary services’ costs.
Left undetermined is whether the load will be in its own transmission zone or absorbed into another, which would affect the congestion revenue rights process.
Final and more detailed information will be available in the report staff presents to the ERCOT board June 13 before a filing with the PUC.
Billo said SPP is working on a parallel timeline with ERCOT and will file its own report separately. SPP said Tuesday that filing will take place with the PUC in late June.
LP&L announced in 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. The PUC last summer asked the grid operators to conduct coordinated studies on the move, focused on a cost-benefit analysis for ratepayers. (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)
