SPP staff told stakeholders last week that the RTO will not conduct a joint transmission planning study with Associated Electric Cooperative Inc. this year, saying they were unable to find any “reasonable projects on either side of line.”
“The next shot will be in 2020,” said SPP’s Clint Savoy during a June 21 conference call of the SPP-AECI Interregional Planning Stakeholder Advisory Committee. “We will have plenty of time to get our hands around what we want to look at in the next study.”
A needs assessment along the seams identified more than 200 violations, but most were eliminated through model corrections or system adjustments, or because they were invalid contingencies. Most AECI violations were voltage issues, SPP said.
The RTO is proposing that one identified project, a 161-kV transmission line, be included in its 2018 near-term assessment.
A final report will be published at the end of July.
SPP and AECI have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. Their only success was in 2016, when their study identified two projects near Springfield, Mo.: a new 345/161-kV transformer at AECI’s Morgan Substation and uprate to an existing 161-kV Morgan-to-Brookline transmission line, and installation of a new 345-kV 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation.
SPP would have been responsible for $17.1 million of the projects’ estimated $18.75 million cost, but FERC last year rejected the proposed cost allocation for both projects. The Brookline reactor project is now being addressed through the RTO’s regional planning process as part of the 2018 near-term assessment, and the Morgan transformer project is being prepared for another filing at FERC.
AECI, based in Springfield, is owned by and provides wholesale power to six regional generation and transmission cooperatives.
President Trump’s nominee to head the Department of Energy’s Energy Efficiency and Renewable Energy (EERE) program sidestepped controversy in his confirmation hearing Tuesday but was unable to answer several senators’ questions about key legislation and programs.
Assistant Secretary nominee Daniel Simmons, who has been running EERE on an acting basis for the last year, told the Senate Energy and Natural Resources Committee that his work at DOE is much different than his previous roles at the Institute for Energy Research (IER) and American Energy Alliance — groups backed by the conservative Koch brothers that have supported fossil fuel use and called for Congress to “eliminate” EERE. Simmons also previously worked at the American Legislative Exchange Council, which also backed fossil fuels.
Simmons | Senate Energy and Natural Resources Committee
In his opening statement, Simmons said his parents’ decision to build “a passive solar double envelope home” sparked his lifelong interest in energy efficiency and renewables. “Since [joining DOE], I have approached this job with an open mind and an eagerness to learn and have focused on following congressional direction while advancing the administration’s priorities,” he said.
Later, Simmons discussed meeting with solar and wind industry representatives in his new role, acknowledging that “we’ve had policy differences in the past.”
Ranking member Sen. Maria Cantwell (D-Wash.) asked Simmons whether he would aid her in convincing the House of Representatives to back Senate legislation increasing energy efficiency standards for buildings and appliances. (See House, Senate Conferees Begin Work to Narrow Differences on Energy Bill.)
“I’m not familiar enough with that disagreement to really comment on it; I’m sorry,” Simmons responded.
“O-kayyy … ” Cantwell said incredulously. “This will be a key part of your job, so maybe before we vote on you, you could take a look at that.”
Cantwell also complained that DOE had repeatedly missed deadlines for completing EE regulations. “We had seen a slow walking by some on this, and I’m telling you it’s wrongheaded,” she continued. “ … Our nation is going to be in the manufacturing base very, very competitive on an international basis if we can drive down electricity costs. So, that should be our mantra, and I hope that you will lead that charge.”
“I will … I will not slow walk any of those regulations,” Simmons promised.
Nominees, left to right: Teri L. Donaldson, nominee for inspector general; Karen S. Evans, assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response; Christopher Fall, director of the Office of Science; and Daniel Simmons, assistant secretary of the Energy Efficiency and Renewable Energy (EERE) program. | Senate Energy and Natural Resources Committee
In response to a question from Sen. Tina Smith (D-Minn.), Simmons also distanced himself from his comments during a 2013 podcast in which he argued that “wind and solar is more expensive and will increase the price of electricity.”
He noted that solar PV costs have dropped sharply in the last five years. “That’s one of the things that [has] changed since I made that statement,” he said.
But Simmons stumbled again under questioning from Sen. Rob Portman (R-Ohio), who with Sen. Jeanne Shaheen (D-N.H.) has led the — mostly unsuccessful — effort to win Congressional approval for tougher EE standards.
Portman asked Simmons his opinion of DOE’s “Tenant Star” program, the result of narrower EE legislation approved in 2015.
“The Tenant Star program, I’m not familiar enough with that to comment on it. But I will look into it,” Simmons said.
The senator asked whether there were more DOE should be doing on EE without Portman and Shaheen’s larger EE bill. “I’m not familiar enough with the legislation to add on to it,” Simmons responded.
Simmons was the only one of four DOE nominees testifying Tuesday to receive pointed questions from the senators. Also testifying were Teri L. Donaldson, nominee to be DOE’s inspector general; Christopher Fall, named as director of the Office of Science; and Karen S. Evans, who would become assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response.
MISO’s markets performed competitively last year, but the RTO should implement several new recommendations to improve market functions, the Independent Market Monitor’s 2017 State of the Market report concluded.
MISO IMM David Patton said energy prices averaged $29.46/MWh in 2017, an 11% increase over 2016 but in line with rising prices for natural gas and other fuels.
“The markets continued to perform competitively, although we have areas of concentration with local market power,” Patton said during a June 26 conference call held by the Markets Committee of the MISO Board of Directors.
But market performance could be made more efficient, Patton said, offering seven new market recommendations in combination with past State of the Market suggestions.
Fast-Track Ideas
Patton said two of his new recommendations could be fast-tracked and not require a slot on MISO’s Market Roadmap process, which is traditionally reserved for more complex improvements.
The first: to improve market power mitigation rules. Patton said his proposed changes are “modest in scope and impact” but would help in the effectiveness of market power mitigation provisions.
“Every year, MISO makes a cleanup filing of [mitigation rules], and we collaborate with them on it,” Patton explained. This year he has recommended that MISO adjust its impact test and sanctions rules to include the impact of negative prices; make the price impact threshold for ancillary services better reflect prevailing clearing prices; and create a better generation shift factor cutoff on mitigation for broad constrained areas, a type of congested transmission area. Including negative prices in mitigation measures will allow the Monitor to “effectively mitigate conduct whose effect is to lower prices at locations and aggravate transmission constraints,” Patton said.
Patton’s second fast-track suggestion would remove transmission charges from coordinated transaction scheduling (CTS) transfers with PJM. MISO and PJM launched CTS last October to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because MISO has been applying transmission charges to the transactions both when they are offered and scheduled, Patton said.
“We had advised that the RTOs not apply transmission charges or allocate costs to these transactions because they do not cause any of these costs,” said Patton, who estimates the charges average $6.24/MWh on MISO imports and $2.57/MWh on exports. He urged MISO to “unilaterally eliminate” all charges from CTS transactions.
“Although MISO should encourage PJM to do the same, there is no reason to wait for PJM to agree to eliminate its charges,” Patton said. “We could change these relatively quickly … This is a very discreet change,” he told MISO board members.
Quick Fix to Make-Whole Payments
Patton said another “relatively simple” market change could help MISO distribute make-whole payments more accurately: improve commitment classifications and create a process to correct classification errors.
Patton said his team has observed MISO operators misclassifying “a fair number” of resource commitments needed to manage transmission constraints as capacity commitments. The RTO assigns a classification code to any resource it commits to either satisfy capacity needs or manage transmission constraints, which determines whether the resource is eligible for make-whole payments through its revenue sufficiency guarantee (RSG), how the RSG payment will be allocated and whether the payment will be subject to mitigation. Patton said the misclassification of code assignments can have “significant” implications on revenue sufficiency guarantee allocations and market mitigation.
“ … It is imperative that MISO have a robust process for reviewing and correcting commitment classifications as needed,” Patton said. He added that he also understood some commitments can address multiple issues and constraints and called on MISO to create clearer procedures for determining a classification based on “cost-causation” principles.
Operator Accountability
Another recommendation would place more accountability on MISO operators in the control room by improving operator logging tools to better describe operator decisions and actions. Patton said MISO operators often inconsistently log or describe manual adjustments, making them difficult to evaluate later.
Operators can make several system adjustments, including changes in generating units’ operating status, real-time adjustments to forecasted load, manual redispatch of resources for system needs, alterations of real-time limits for transmission constraints, real-time adjustments to the transmission constraint demand curve and requests for market-to-market constraint tests and activations.
“Because these actions can have significant cost and market performance implications, we recommend that MISO upgrade its systems and procedures to allow these and other operator actions to be logged in a more complete and detailed manner,” Paton said, adding that MISO could include new logging tools in its effort to replace its market platform.
Day-Ahead Market Change
Patton also proposed MISO’s platform replacement effort could provide MISO the chance to evaluate the feasibility of solving the day-ahead market with 15-minute — rather than hourly — scheduling intervals. Patton said when MISO first created its markets, the day-ahead software wasn’t sophisticated enough to be more time-specific.
“By producing hourly schedules based on 60-minutes of ramp capability and hourly load forecasts, the day-ahead schedules cannot track the expected changes in real-time system needs, particularly during ramping periods. It also regularly results in generator schedule changes from hour to hour that are not feasible, which results in substantial make-whole payments,” he said.
But advances in technology might permit 15-minute day-ahead market schedules, which could improve market response times and reduce uplift costs.
Auction Improvements
Patton’s two final recommendations involve MISO’s annual Planning Resource Auction (PRA).
The first suggestion would require that installed capacity of planning resources be deliverable over the transmission network. While the Tariff already requires all resources to be deliverable to load to qualify as capacity resources, Patton says that, in one instance, MISO’s deliverability requirements are too relaxed because resources with Energy Resource Interconnection Service (ERIS) must only secure firm transmission for its unforced capacity values, which tend to be about 5% to 10% less than their full installed capacity levels.
But Patton said resources with ERIS should be required to procure firm transmission service to the full level of their installed capacity.
“The requirements imposed by MISO on ERIS resources is not consistent with the intent of the Tariff. We recommend that MISO determine deliverability for all resources based on the entire [installed capacity] of applicable planning resources,” Patton said.
Such a move will improve the accuracy of MISO’s loss-of-load studies since they are conducted with the assumption that resources will perform up to their installed capacity when available, he noted.
The Monitor also recommended MISO establish unique capacity credits in the PRA for emergency-only resources that better reflect their availability. While those resources can be compensated through the PRA, they are only required to deploy during emergencies when called on by MISO. If they “are not available to mitigate capacity shortages that usually occur early in the emergency events, then they are not providing the reliability value assumed in the planning studies and for which they are compensated,” Patton said.
An increased volume of emergency-only resources cleared in this year’s PRA. (See MISO Clearsat $10/MW-day in 2018/19 Capacity Auction.) Patton pointed out that some of the resources have lead times up to 12 hours that “render them essentially unavailable in an emergency.” He said emergency-only and load-modifying resources should only receive full PRA capacity credit if “they are expected to be reasonably available in an emergency” and can respond to a benchmark not yet established by MISO.
Patton pointed out that other generation is subject to capacity-selling requirements, including qualifications based on past forced outage performance, day-ahead must-offer rules and reduced capacity credits for intermittent resources. He recommended MISO quantify emergency-only capacity credits based on factors such as expected availability, historical performance and curtailment ability.
Executive Director of Market Development Jeff Bladen said MISO will provide a formal response to this year’s report within 120 days, per its Tariff.
Bladen reminded the board that MISO’s ability to take on new market improvements will continue to be “constrained” by MISO’s technology capabilities as the RTO replaces its outdated market system platform. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
A bill that would allow CAISO’s transformation into an RTO passed another key California State Senate committee on Tuesday after supporters were grilled on how the legislation could compromise the state’s control over its energy sector.
The Senate Judiciary Committee voted 4-1 to advance AB 813 to the Appropriations Committee, typically the final step ahead of a full floor vote. Committee Chair Hannah-Beth Jackson (D) cast the sole vote in opposition.
Holden | California State Senate
Speaking to the committee, State Assemblyman Chris Holden (D), the bill’s sponsor, touted the potential benefits of regionalizing the ISO, a three-year effort pushed by Gov. Jerry Brown that has failed to gain traction in the legislature out of concerns about yielding control over the state’s grid and the loss of energy-related jobs.
“Expanding CAISO’s participating transmission owners will allow electricity to be treated more efficiently across the West through CAISO’s markets as more of [the West’s] 37 balancing authorities join, and without layering of multiple transmission charges,” Holden said. “This will facilitate transactions such as exporting unused renewable power, like solar, throughout the region and importing power in the evening to meet California’s steep ramp as the sun goes down.”
AB 813 passed the Assembly in June 2017 but failed to come up for a vote in the Senate and was carried over to the current session. The Senate’s Energy, Utilities and Communications Committee approved the bill June 19 on a 6-1 vote. (See Senate Committee Advances CAISO Regionalization Bill.)
Loss of Oversight?
Cavanagh | California State Senate
Testifying with Holden was Ralph Cavanagh, a senior attorney with the Natural Resource Defense Council’s Climate and Clean Energy Program, who told the senators that California is already part of an integrated grid with its Western neighbors. The NRDC has been a strong proponent of regionalization.
“We’re involved in multistate grid planning now; we’re just doing it very inefficiently and at an unnecessary cost,” Cavanagh said.
He explained that while the bill would be authorizing the transition of CAISO’s state-appointed Board of Governors to a fully independent board, it would not be establishing the terms under which regionalization would proceed.
That prompted Jackson to ask: “We would lose our oversight. Is that right?”
“You have the decision to make as whether to authorize a transition to a fully independent board, and then you can pull the utilities out, senator, if for some reason you’re dissatisfied with the way the system operates,” Cavanagh said.
Stern | California State Senate
“But there’s a dispute as to whether we could pull them out or not,” Jackson said, referring to lingering questions about the process for removing the state’s utilities from the new RTO after they’ve joined.
Sen. Henry Stern (D) asked whether FERC would have to approve a utility’s withdrawal from the RTO.
“It’s an administrative sign-off,” Holden said.
Anderson | California State Senate
Sen. Joel Anderson (R) expressed confusion about how the RTO’s board would be appointed and who would fill its seats.
“What the statute establishes is that a future board would be fully independent, would have no connection to any market participant,” Cavanagh said. “It would not be a board of political appointees. It would be a board of diverse experts, which is how the other boards of the independent system operators elsewhere in North America operate.”
“But where would they come from? So, they just walk in and say, ‘I’m on the board?’” Anderson asked.
Crowley | California State Senate
Stacey Crowley, CAISO vice president of regional and federal affairs, explained that the process for selecting the board would be determined through a “public stakeholder initiative.” She noted the ISO had held workshops in 2015 and 2016 with the California Energy Commission that resulted in a proposal to create a nominating committee consisting of stakeholder representatives.
“This is not finalized, and we would go through a public process to determine that,” Crowley said.
“So the answer’s, ‘We don’t know yet,’” Jackson said.
Exporting Power, Jobs
Stern sought more information about the potential loss of California jobs if CAISO’s expansion allowed out-of-state renewables to qualify as in-state — or Bucket 1 — resources under the state’s renewable portfolio standard.
Holden acknowledged that the International Brotherhood of Electrical Workers has expressed concern about the impact of regionalization on the RPS buckets.
“We put in language to address the buckets, and in doing so, we lost a good deal of support for this bill from out-of-state wind and from others,” Holden said. “To go as far as labor would like us to go would basically end the bill.”
Joseph | California State Senate
Representing the Coalition of California Utility Employees, Mark Joseph told the committee that the ISO’s own study shows regionalization would result in the loss of 10,500 California solar construction jobs each year from 2020 to 2030.
“What the ISO has told us is that it will assume all renewable generation outside of the current footprint will be assumed to be delivered into California and therefore qualify as Bucket 1, up to the physical constraints of the transmission system, which they have told us is 12,000 MW,” Joseph said. “So the next 12,000 MW of generation — you can kiss it goodbye.”
Moorlach | California State Senate
Sen. John Moorlach (R) asked whether load in other states was paying for California’s surplus solar energy, or whether the state’s generators were being charged to send it elsewhere.
“Senator, you’re identifying a problem with the current fragmentation, which is that sometimes we can’t use all the renewable energy that we’re producing in California and we can’t push it out to the rest of the West,” Cavanagh said. “It’s worse than paying — we have to turn off solar plants at the height of the sunshine, and one of the reasons to do [regionalization] is we’ll have access to a much bigger market. Having access to the market means more revenue for California.”
“Are you sure these states will cooperate?” Moorlach asked.
“Senator, basically they’re being offered a chance to reduce their costs,” Cavanagh said. “Almost everyone cooperates in order to do that.”
The California Public Utilities Commission on Thursday denied a request to build a new natural gas pipeline after questioning Southern California Gas about why other major pipelines have been sitting out of service.
The commission rejected an application by San Diego Gas & Electric and SoCalGas to build a $639 million pipeline that would have stretched from Rainbow Station to Miramar, replacing the current Line 1600 built in 1949.
“The CPUC determined that the utilities’ most recent natural gas supply forecast and the CPUC’s reliability standard for gas planning do not demonstrate that there is a need for the proposed pipeline,” the commission said as it approved its proposed decision.
The commission directed SDG&E and SoCalGas to pursue other supply options for smaller amounts and for shorter periods of time than would have been provided by the proposed pipeline near San Diego. It also directed the utilities to ensure the safe continuing operation of Line 1600.
The applicants had said the sole purpose of the line was not to meet any short-term supply deficits but for emergency situations such as unplanned outages on Line 3010 or at the Moreno substation. They had also proposed derating Line 1600 from transmission service to distribution service.
The commission last week asked SoCalGas why it had not restored to service two pipelines, Line 3000 and Line 235-2. Line 3000 went out of service on July 29, 2016, and Line 235-2 ruptured and exploded on Oct. 1, 2017.
“Though such outages are to be expected periodically, the significant volumes associated with these facilities and the fact they have been out for lengthy periods during peak demand periods — nearly two years for one and over eight months for another — are causes for concern,” CPUC Energy Division Director Edward Randolph told SoCalGas President Bret Lane in a June 18 letter. Randolph questioned whether rates should be reduced if the lines are not providing benefits to ratepayers.
The Energy Division also issued a new report that cited the pipeline outages as a main reason it is recommending an increase in the allowed storage level at the Aliso Canyon facility from 24.6 Bcf to 34 Bcf. Comments on the proposal were due Monday.
SPP staff told stakeholders last week that the RTO will not conduct a joint transmission planning study with Associated Electric Cooperative Inc. this year, saying they were unable to find any “reasonable projects on either side of line.”
“The next shot will be in 2020,” said SPP’s Clint Savoy during a June 21 conference call of the SPP-AECI Interregional Planning Stakeholder Advisory Committee. “We will have plenty of time to get our hands around what we want to look at in the next study.”
A needs assessment along the seams identified more than 200 violations, but most were eliminated through model corrections or system adjustments, or because they were invalid contingencies. Most AECI violations were voltage issues, SPP said.
The RTO is proposing that one identified project, a 161-kV transmission line, be included in its 2018 near-term assessment.
A final report will be published at the end of July.
SPP and AECI have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. Their only success was in 2016, when their study identified two projects near Springfield, Mo.: a new 345/161-kV transformer at AECI’s Morgan Substation and uprate to an existing 161-kV Morgan-to-Brookline transmission line, and installation of a new 345-kV 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation.
New Madrid Power Plant transmission lines | AECI
SPP would have been responsible for $17.1 million of the projects’ estimated $18.75 million cost, but FERC last year rejected the proposed cost allocation for both projects. The Brookline reactor project is now being addressed through the RTO’s regional planning process as part of the 2018 near-term assessment, and the Morgan transformer project is being prepared for another filing at FERC.
| SWEC
AECI, based in Springfield, is owned by and provides wholesale power to six regional generation and transmission cooperatives.
RENSSELAER, N.Y. — NYISO power prices dropped in May but are up 37% year-to-date, Nicole Bouchez, ISO principal economist, told the Business Issues Committee on Wednesday.
Prices averaged $28.78/MWh in May, lower than $35/MWh in April and $31.74/MWh the same month a year ago.
Year-to-date monthly energy prices averaged $50.20/MWh through May, up from $36.54/MWh a year earlier. May’s average sendout was 397 GWh/day, compared with 390 GWh/day in April and 383 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $2.55/MMBtu for the month, down 9.4% compared with last month and 8.8% year-over-year.
Distillate prices gained 6.4% compared to the previous month but were up 49.7% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.96/MMBtu and $15.92/MMBtu, respectively.
| NYISO
Total uplift costs and uplift per megawatt-hour rose from April with the ISO’s local reliability share 22 cents/MWh in May, up from 12 cents/MWh the previous month, while the statewide share climbed from -57 cents/MWh to -17 cents/MWh.
ISO Reviewing Rules on PJM Imports
Reviewing the Broader Regional Markets report, Bouchez described the ISO’s work on item 26, an effort to clarify the minimum deliverability requirements for capacity from PJM, the subject of three joint meetings of the Installed Capacity (ICAP) Working Group and Market Issues Working Group since February.
The ISO has prepared a detailed overview of the supplemental resource evaluation (SRE) process for external resources, the existing nonperformance penalties for external ICAP suppliers, and a draft proposal regarding SRE process improvements for external capacity resources.
Bouchez also reviewed item 28, a complaint filed with FERC in December by the New Jersey Board of Public Utilities challenging PJM’s and NYISO’s implementation of the mutual benefits provisions of their joint operating agreement and requesting amendments to the JOA.
FERC rejected the complaint on May 24 (EL18-54). The commission found that because the Bergen-Linden Corridor Project was planned by PJM, and without a voluntary commitment to share cost responsibility by NYISO, “it is just and reasonable for the costs of the project to be allocated solely within PJM.” (See PSE&G on the Hook for Bergen-Linden Costs.)
Proposal to Extend TCCs Advances
The BIC voted to recommend that the Management Committee approve Tariff revisions to provide extensions of historic fixed-price transmission congestion contracts (HFPTCCs), following a presentation by Gregory R. Williams, manager for TCC market operations.
FERC Order 681 requires that long-term firm transmission rights be made available to allow load-serving entities to support long-term power supply arrangements.
The HFPTCCs initiated by NYISO in 2008 allow LSEs to obtain such contracts for up to 10 years, with some service grandfathered for up to 12 years; 1,748 MW of HFPTCCs are currently active. Those offered in 2008 are now approaching the end of their 10-year term and will expire after Oct. 31.
As part of developing the HFPTCCs, the ISO had committed to explore an option to renew the contracts after the initial term.
Contract extensions would be made available to LSEs that convert existing transmission agreements to HFPTCCs and continued to purchase them throughout the entire 10- or 12-year term.
The ISO is required to make all transmission capacity not used to support existing TCCs available for sale in its centralized TCC auctions. The bidding and offering period for the first round of the fall 2018 centralized TCC auction is expected to begin in mid-August.
Assuming the current proposal is accepted by FERC, the ISO would need to seek a waiver for permission to reserve 256 MW of transmission capacity from the upcoming auction to support the potential award of HFPTCC extensions that would begin on Nov. 1, 2018, and ensure feasibility issues do not arise from offering such extensions to qualifying LSEs.
Competitive Power Ventures must provide additional information to prove it adequately mitigated market power to continue making market-based sales at its newly opened Towantic Energy Center, FERC ruled Thursday (ER13-343-008, et al.).
FERC’s ruling came in response to CPV’s triennial market power update, which it filed on June 30, 2017, for Towantic, a 785-MW generator in Oxford, Ct., and three other gas-fired plants in CPV’s Northeast region.
CPV Towantic Energy Center in early May, with construction nearly complete. | CPV
The commission’s market-based rate rules require applicants to provide information regarding affiliates and upstream ownership. It considers as affiliates any entity that owns at least 10% of the outstanding voting securities of the applicant.
Two pension funds indirectly own more than 10% of Towantic, but CPV argued that they are only allowed to vote 9% of their shares in an upstream entity. FERC said that doesn’t account for their entire ownership.
“Because the pension funds are included among the stockholders whose votes determine how the votes of the excess shares will be allocated, the sum of votes by the pension funds of their 9% of the shares plus the proportional vote of their excess shares gives the pension funds an effective vote greater than 10%,” the commission said.
It instructed the applicants to update their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production. FERC gave them 30 days to comply.
The other plants are the 725-MW CPV Woodbridge Energy Center in Keasbey, N.J., and the 725-MW CPV St. Charles Energy Center in Waldorf, Md., which were granted MBRA in February 2013 (ER13-342, ER13-343).
[Editor’s Note: An earlier version of this story incorrectly stated that FERC was questioning the ownership of all four CPV plants and that they did not already have MBRA.]
FERC on Thursday identified 13 additional transmission owners it said should change accounting practices that could inflate rates by underestimating tax credits.
The commission ordered a Section 206 proceeding investigating the companies’ use of a double averaging formula to calculate accumulated deferred income taxes (ADIT) (EL18-155, et al.). The utilities include two Ameren subsidiaries, American Transmission Co., GridLiance West Transco, ITC Midwest, Northern States Power, Public Service Company of Colorado, Southern California Edison, TransCanyon DCR, Southwestern Public Service and Virginia Electric and Power Co.
In April, FERC opened a similar investigation of five MISO TOs after rejecting proposed formula rate template revisions that would have applied the two-step averaging methodology in annual true-up calculations of ADIT balances.
The commission signaled it would probe whether the practice makes deferred income tax credits appear lower than they should be, possibly raising rates (ER18-224, EL18-138). The filers were ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas and Electric Co.
The commission said that the TOs’ practice of averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.”
“Because most companies tend to continuously make investments in plant[s], which in turn generates ADIT, plant and ADIT balances typically increase throughout the year,” the commission said.
MISO TOs Offer New Formula
On June 4, the five MISO TOs submitted revisions to remove the proposed double averaging and instead apply the IRS’ proration methodology in calculating the annual transmission formula rate true-up.
In last week’s order, FERC suggested that the 13 newly identified utilities would need to similarly revise their rates.
“Upon initial review, the concerns we identify might be addressed by revising respondents’ transmission formula rates to eliminate the use of the two-step averaging methodology to determine ADIT balances,” FERC said. “In particular, respondents could modify their transmission formula rates to apply the first step of the two-step averaging methodology to generate a prorated ADIT value for the year, without taking the second step of averaging the prorated value for the year with the beginning-of-year balance.”
Change of Heart
FERC noted that, in previous proceedings, it had allowed TOs to use the two-step methodology “based on the understanding that this methodology was necessary to comply” with the IRS’ normalization rules, an accounting system the Department of Treasury uses for regulated public utilities to reconcile accelerated depreciation of their public utility assets or investment tax credits with regulatory treatment.
However, FERC said in April that its opinion on the matter has since changed, guided by private letter rulings from the IRS. FERC said it now interprets updated IRS rules to “not require that any averaging convention applied to other elements of rate base also apply to taxpayer’s prorated [ADIT] balance.”
“We conclude that if the IRS’ proration methodology is applied to calculate ADIT balances in forward-looking formula rates — such as the Attachment O formula rate templates of certain MISO TOs — then the additional averaging step need not also be applied in order to comply,” FERC said.
RENSSELAER, N.Y. — NYISO stakeholders last week backed joint proposals by North America Transmission (NAT) and the New York Power Authority to build two 345-kV transmission projects while several losing bidders cried foul.
In an advisory vote, the Business Issues Committee urged the Management Committee on Wednesday to recommend the Board of Directors approve the ISO’s draft AC Transmission Public Policy Transmission Planning Report. Dawei Fan, manager for public policy and interregional planning, said the report contains analysis of seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface.
NYISO staff analyzed seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface, and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. | NY PSC
Advised by consultant Substation Engineering Co. (SECO), ISO staff recommended two 345-kV transmission projects proposed jointly by NAT and NYPA. The BIC voted 76.33% in favor of the report and its recommendations.
Project T027 is a double-circuit 345-kV line from Edic to New Scotland for Segment A. Project T029 for Segment B is a standard 345-kV line from Knickerbocker to Pleasant Valley.
NYISO’s analysis was driven by a December 2015 order by the New York Public Service Commission on “Finding Transmission Needs Driven by Public Policy Requirements.”
T027 had higher costs than other Segment A proposals, but staff determined them warranted by benefits provided by the double-circuit design, including “significant increase in Central East voltage transfer capability, increased production cost savings, and excellent operability and expandability.”
T029 provides similar transfer incremental and production cost savings with the second-lowest cost, and demonstrates excellent operability, staff said. More important, the report said, “T029 poses the lowest siting risk due to the low structure height increase and more than 50% of its new structures with reduced height.”
Staff also said that T027 and T029 would result in cost savings when being built by the same developer simultaneously.
The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency. T029 is estimated at $324 million to $422 million. Staff projected the in-service date for the selected projects in April 2023, “assuming the developer will start the Article VII preparation immediately following the approval of this report by the NYISO board.”
Challenges to Planning Process
Stakeholders abstaining or opposing the motion June 20 included utilities, transmission owners and other developers whose proposals were not selected for recommendation. Several of them submitted comments to the BIC or read statements.
John Borchert, senior director of energy policy and transmission development for Central Hudson Gas & Electric, which abstained, said his company wanted the benefits of improved transmission capability for its service area but was “dissatisfied with the NYISO’s work and its project evaluation.”
He said “the lack of transparency, the way that the aspects of the projects were treated during the evaluation, effectively disqualified projects, and the way that the local TO upgrades were handled during the process have led to frustration and confusion for both those developing projects and for those interconnecting transmission owners.”
Consolidated Edison and its subsidiary Orange and Rockland Utilities voted against the motion, and O&R submitted written comments.
“We don’t feel confident that the recommended selection for Segment B is in the customer’s best interest due to a lack of transparency in the selection process, and deficiencies in evaluation,” said Jane Quin, director of Con Ed’s energy markets policy group. “We are concerned that … NYISO has not considered the full costs associated with the proposed Middletown upgrades, which are local upgrades on the Orange and Rockland system … and could cost as much as 20% of the Segment B project cost.”
The ISO “failed to make clear the technologies and project attributes it would or would not consider, and the reasons for such decisions, and it did not consider stakeholder input on the matter,” Quin said.
Fan responded that the Middletown transformer “is just one of the distinguishing factors for Segment B projects … [for which] the major drivers are the magnitude of the power delivery and the structure design.” He said SECO had included $16 million for the Middletown transformer costs, which it deemed adequate.
Fan said the ISO had already had two meetings with developers and six meetings with the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee to consider comments from stakeholders.
Looking for Fatal Flaws
Zach Smith, NYISO vice president for system and resource planning, noted that “any project recommended for selection does go through our interconnection process … there has been a system impact study that’s been done that’s up at [the Operations Committee] tomorrow for consideration.”
The next step after that is a facilities study, and “what’s key here to our evaluation is to understand whether there are any fatal flaws in our assessment,” Smith said.
Borchert said, “There was no reason why an interconnecting transmission owner should not be consulted if these solutions are talking about equipment that’s going to be installed in their service territory. And the process needs to be done if it’s part of the overall selection and it has an impact on the selection, and it needs to be done prior to the selection being made.”
Carl Patka, the ISO’s assistant general counsel, said, “When we designed the overall planning process, we did not require, and FERC did not approve requiring, a complete interconnection-level analysis for proposed projects. That was proposed during the Order 1000 process, it was proposed during the stakeholder process, and it was rejected. And the reason for that is people did not want to create a barrier to entry and proposal of new projects based upon information that competing developers could not have from the incumbent utility.”
Brian Duncan of NextEra Energy Transmission NY (NEETNY) made a presentation arguing that NYISO was picking winners for a $1 billion project “despite a virtual tie on project benefits” among competing projects, which included NEETNY’s T022 in Segment B.
The ISO “did not provide analysis on cost-contained pricing … and three other project combinations that are virtually identical, provide all the quantifiable and quantitative benefits [and] are within 1 to 5% of the cost estimate using SECO’s numbers,” Duncan said. He also questioned why NYISO made tower height a big issue in its selection when its solicitation made no mention of the factor.
Patka said the PSC order did not mandate the ISO to use cost-contained pricing but required developers to provide two sets of costs, “one based on raw construction costs and one on 80%/20% cost overrun/cost underrun language. … They said they hoped that FERC will adopt cost containment when they address the rate issue, but their words were exactly, ‘The NYISO should evaluate the costs based on raw construction costs.’”
Patka also said that tower heights were considered by NYISO as a risk of project delay and to project completion, as visual impact is a key environmental impact of transmission, and that the ISO had reviewed its analysis with New York Department of Public Service staff.
Duncan also took issue with the concrete pole installation cost estimates, saying that SECO used a metric of dollars per pound on the weight of the pole rather than a more logical figure of total costs, including labor. He also said the ISO’s estimate of 5% in synergy savings on the combined projects by one developer was “overstated.”
“If those issues are addressed, project T022 would be the lowest-cost project by millions of dollars, probably tens of millions of dollars,” Duncan said.
SECO Vice President Joe Allen said he agreed “there would be no synergy” between the two upgrades.
Smith said NYISO could “take that back, but it won’t affect the ranking at all.”
Kathleen Carrigan, New York Transco general counsel, read comments the company jointly submitted with National Grid.
Losing bidders cried foul last week over NYISO’s selection of North America Transmission and the New York Power Authority to build two 345-kV transmission projects to address public policy needs identified by the New York Public Service Commission. | NYISO
The two companies submitted proposal T019 for Segment B, including “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings.”
Carrigan said series compensation technology is widely used across the U.S., and she submitted a study showing no detrimental system impacts from it. NYISO and SECO “considered proposal T019 as too risky due to the inclusion of the series compensation, despite no technical analysis in support of their conclusion,” she said.
Smith said that while the ISO does not oppose the use of series compensation as a technology, it did see potential problems with its application in the National Grid/NY Transco project. In a FAQ document posted with the BIC meeting materials, the ISO cited potential subsynchronous resonance and damage to generators as the major risk of series compensation technology.
Carrigan said NYISO’s own metrics show the National Grid/NY Transco proposal paired with T029 produces consistently better performance results than the ISO’s favored project.
For example, when combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW. “This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325,” she told RTO Insider after the meeting.
“Projects T027 + T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029 (40,089 GWh vs. 27,524 GWh); and finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.
