FERC last week rejected the New York Public Service Commission’s request to rehear a November 2017 decision granting NextEra Energy Transmission New York (NEET NY) a 50-basis-point adder for participating in NYISO.
The ISO in October selected the company’s Empire State Line proposal to address a need for new transmission in western New York.
Empire State Transmission Line | NextEra Energy Transmission
FERC’s Feb. 28 order dismissed the PSC’s argument that a participation adder — or membership incentive — was unnecessary because NYISO selected NextEra as part of its transmission planning process, leaving the company no choice but to turn over operational control of its transmission to the ISO (ER16-2719).
The federal commission countered that the incentive recognizes the consumer benefits, including reliability and cost benefits, that flow from ISO membership.
Section 219 of the Federal Power Act provides for incentives to each transmitting utility or electric utility that joins an RTO/ISO, and incentive-based rate treatments benefit consumers by ensuring reliability and reducing the cost of delivered power, FERC said.
Empire State Transmission Line | NextEra Energy Transmission
“We consider an inducement for utilities to join, and remain in, transmission organizations to be entirely consistent with those purposes … and the best way to ensure those benefits are spread to as many consumers as possible is to provide an incentive that is widely available to member utilities … and is effective for the entire duration of a utility’s membership in the transmission organization,” FERC said.
FERC granted NEET NY’s request subject to the return on equity with the adder being within the zone of reasonableness, it noted.
SAN DIEGO — A joint effort between Peak Reliability and PJM offers Western industry players a chance to design their own market, one that will operate with more transparency than CAISO, PJM CEO Andy Ott said last week.
“The whole key here is the ability of the West to build up its own rules,” Ott said.
The CEO added that PJM’s expertise in coordinating markets and dealing with regional differences in the East will be a major asset in developing a Western market in partnership with Peak.
Having traveled west last week to attend a meeting of the Western Power Trading Forum, Ott sat down with RTO Insider to discuss the new Peak Reliability/PJM Connext market proposal. (See Peak Touts ‘Independent’ Western Market Plan.)
The partnership is galvanizing interest across the industry around a new Western market, but it comes amidst several other major recent developments shaking up the region.
Among them: competing efforts by CAISO to provide reliability coordinator (RC) services and extend its day-ahead capability into the Energy Imbalance Market (EIM). (See CAISO Plan Extends Day-Ahead Market to EIM.)
PJM’s executive spoke frankly about the shortcomings he sees in CAISO, including what he characterized as a relatively closed-door process for addressing market issues, compared with the more stakeholder-driven approach he envisions for the Peak market.
In California, “they have a discussion about a specific issue they are going to change, then they go in a room and make a decision, and they come out and they have a decision,” Ott said. “It’s not done that way everywhere.”
Ott touted PJM’s experience in operating a 13-state, multibillion-dollar energy market in the East. The RTO brings that experience to the effort, while Peak has the real-time reliability model of its territory already completed, he said.
Aside from the market proposals, Peak and CAISO are competing to provide NERC-certified RC services. Shortly after Peak and PJM announced their effort, CAISO dropped Peak as its RC and announced it would offer Western utilities RC services at a lower cost.
Peak CEO Marie Jordan, who also attended the WPTF event, noted that the only non-revocable notice of departure that the organization has received so far is from CAISO. Several Peak customers have announced they will leave, after CAISO issued its notice of withdrawal at the beginning of the year.
Late last month, the Bonneville Power Administration and Western Area Power Administration separately announced they have signed nonbinding notices signaling their intent to depart Peak by the end of 2019. BPA said it is exploring receiving RC services from CAISO, while WAPA is considering SPP and CAISO for some of its balancing authorities.
A business plan for the Peak Reliability/PJM Connext proposal is due at the end of March
Ott noted that the EIM was designed with the specific purpose of giving California a way to export renewable generation and get services back. The market benefits California customers, and he called outside regional participants “guests” in the market.
“I see the EIM, frankly, as a stopgap,” Ott said. “It was created to solve a problem.”
Ott said the business case for the market is being studied and is due to be issued March 30. Peak executives have publicly discussed the potential for the effort to evolve into a full RTO, something Ott says will depend on input from market participants.
“Our mindset is that if we put the PJM name on something, it’s not going to fail. We cannot afford to let it fail,” Ott said.
PJM and its transmission owners released a joint proposal last week to address FERC’s decision last month that the TOs are not in compliance with Order 890 (EL16-71, ER17-179).
The commission ruled that the TOs were failing to provide stakeholders with adequate notification, information and enough opportunities to engage on “supplemental” projects —transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. The projects are part of PJM’s Regional Transmission Expansion Plan but not subject to staff’s oversight and approval. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
FERC ordered the TOs to define nine time-period minimums that were previously vague. In response, TOs have proposed there be a minimum of 25 days between meetings on the three parts of project planning: assumptions, needs and solutions. They also offered to post information to be discussed at that meeting 10 days ahead of time and allow 10 days after meetings to receive comments. Finally, they proposed a 10-day waiting period to consider written comments before incorporating their local transmission plans into the RTEP.
“The minimum time periods proposed are designed to complete the consideration of supplemental projects in time for the PJM board meeting to approve the Regional Transmission Expansion Plan in July and in subsequent RTEP approval cycles throughout the year,” PJM and the TOs wrote in the joint proposal.
PJM is giving stakeholders until March 9 to comment on the proposal. But some have already said they aren’t yet ready to sign off.
“We are carefully reviewing the filing with a view of the current planning process as well as the language in the order,” said American Municipal Power’s Ed Tatum, who has been a vocal critic of the process. “Absent discussion with the TOs, PJM and other stakeholders, it is difficult to determine if the time frames and process proposed will yield any improvement to the current process.”
NEW CASTLE, N.H. — More than 100 people gathered with ISO-NE’s Consumer Liaison Group (CLG) at the historic Wentworth by the Sea hotel to discuss the rapid changes overtaking New England’s electricity market.
The CLG holds quarterly meetings around the region to provide a chance for residents, state officials and energy experts to learn more about the grid operator.
CLG Chair Rebecca Tepper, chief of the energy and telecommunications division in the Massachusetts attorney general’s office, said the group is “thinking about additional opportunities for members of the CLG to talk directly to ISO New England professionals and staff, just so there’s more direct communication available.”
Here’s more of what we heard at the CLG’s most recent meeting.
New Hampshire Public Utilities Commissioner Michael Giaimo said that New England’s market restructuring has benefited consumers.
“No longer can a utility build a generation facility solely on the backs of ratepayers,” Giaimo said. “The system of captive ratepayers being susceptible to stranded costs has been replaced by developers and their shareholders bearing the risks and the rewards associated with building, operating and maintaining a generation facility.”
Anne George, ISO-NE vice president for external affairs, said the RTO’s 2017 average wholesale energy prices were the second lowest since 2003, while last month’s Forward Capacity Auction 12 marked the third consecutive decline in clearing prices. (See ISO-NE Capacity Prices Hit 5-Year Low.)
George reiterated the RTO’s concerns about fuel security, a challenge brought home during two bitter cold weeks around New Year’s Day when New England generators burned through nearly 2 million barrels of oil, more than twice the amount used by the region’s power plants during all of 2016. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
Giaimo noted that the cold snap saw the value of the region’s energy transactions surge to about $1.1 billion during the first three weeks of January, equal to 25% of the entire energy market value in 2015. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
Markets Misalignment
Jonathan Peress, director of energy market policy at the Environmental Defense Fund, said the Northeastern power price spike observed Jan. 5 was not driven by New England gas pipeline constraints but by New York City power demand, which was symptomatic of a misalignment between gas and electric pricing.
“Very high LNG sendout kept Algonquin [gas hub] prices lower than would otherwise have been the case on Jan. 5,” Peress said. “LNG was the key resource that allowed consistent access to gas.”
The value of gas supply and pipeline delivery service fluctuates over the course of the day, but the gas market primarily relies on a single daily index price. Non-ratable takes are valuable to generators, but the variable flow and pipeline flexibility service is not priced, he said.
“It’s really not good to be relying on 50-year-old oil steam boilers for our reliability in New England,” Peress said. “I used to manage some of them — not pretty.”
New Hampshire Sen. Andy Sanborn (R) said “virtually every woe you have, when it comes to your ability to run your company and energy policy, actually solely starts at the legislature.”
The legislature controls the energy conversation, and discussion ends up being a debate between left and right, Sanborn said, when the region has systemic problems.
“It is specifically the legislature that determines whether we’re going to let that market run freely, all the way from our ability to sign off on long-term plan purchase contracts … to what percentage of our business needs to be renewable or non-renewable, and whether or not we are allowing companies to bring gas in or bring power down,” Sanborn said.
Market-Based Solutions
Carl Gustin, a communications strategist with consultancy Salient Point, brought a historical perspective to the discussion by recalling how the 1978 Power Plant and Industrial Fuel Use Act banned the use of natural gas by power plants.
The first energy-efficiency measures elicited disbelief among utility executives who could not envision “un-selling” their product.
“We called it conservation back then,” Gustin said.
But now: “You’ve got renewables coming up and coming on quickly and you’ve got to manage that system both for voltage and for reliability,” Gustin said. “You’ve got a big problem in front of you.”
Tanya Bodell, executive director of consultancy Energyzt, said that, coming from the Chicago school of economics, she always favors market-based solutions.
“Right now, there’s not an incentive through the price signal for most customers to adjust their consumption, so we’re really not tapping into the demand response,” Bodell said. “And customers can make money — those who are able to make those adjustments. I would say that’s a market solution.”
Pricing carbon is another market-based solution, she said.
“If you put a price on carbon, the cost of the oil-fueled units will become more expensive and other alternatives, LNG for example, can come in and help to solve that. We saw LNG flowing into New York. If the price signal is there, it will come.”
FERC on Wednesday approved the proposed $14 billion merger between Great Plains Energy and Westar Energy, ruling that it would not have an adverse impact on market competition or rates in SPP.
The deal is still subject to approval by Kansas and Missouri regulators.
Missouri-based Great Plains owns Kansas City Power & Light, and Kansas-based Westar owns Kansas Gas and Electric. Kansas regulators last year pushed back on Great Plains’ original plan to buy out Westar, spurring the companies to recast the transaction as a “merger of equals.”
Under a revised plan filed with the Kansas Corporation Commission in late August, Great Plains proposed that the two companies would combine under a $14 billion holding company operating in both Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER). The companies have pledged that the holding company will maintain separate debt and capital structures for each subsidiary. (See Great Plains, Westar File Revised Merger Plan.)
The deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.
In approving the deal, FERC made clear that a five-year hold-harmless commitment agreed to by the two companies would not cover any costs related to Great Plains’ failed bid to buy out Westar (EC17-171). Under that commitment, Great Plains and Westar have agreed not to seek to recover any costs related to integrating the companies unless they can demonstrate, through a Section 205 filing, that a merger activity yielded savings in excess of costs incurred.
| Great Plains and Westar
But the commission clarified that because Great Plains’ original acquisition strategy was “pursued but never completed,” costs related to the transaction “should not be included as part of the hold-harmless commitment and cannot be recovered from ratepayers pursuant to it. The costs related to the 2016 transaction are instead subject to the commission’s ordinary ratemaking principles under [Federal Power Act] Sections 205 and 206.”
Additionally, FERC said it was not persuaded by a protest by Kansas Electric Power Cooperative, which asked the commission to apply an equally strong hold-harmless commitment to wholesale customers as it would for retail customers, using pre-merger common equity levels to calculate rates, shielding the co-op from merger-based rate impacts. It also asked that all hold-harmless commitments be indefinite.
FERC said ordering extra hold-harmless protections without evidence would be “speculative” and noted that it doesn’t require merger plans to include hold-harmless commitments for market-based wholesale power sales.
The commission also declined the co-op’s request that Great Plains and Westar provide it with a detailed list of all merger-related costs through a new compliance filing.
The proposed merger is still in prehearing stages at the KCC until March 19, when the first evidentiary hearing is scheduled. A public comment period on the merger ends March 29.
The Missouri Public Service Commission is also reviewing the proposed merger and will hold evidentiary hearings March 12 to 16 (EM-2018-0012).
ERCOT said Thursday it expects the recent retirement of coal-fired and aging units to result in tight operating reserves this summer — an unnerving proposition for some observers when the ISO is also projecting record-breaking peaks during the summer heat.
According to ERCOT’s preliminary seasonal assessment of resource adequacy (SARA) for the summer (June-September), the grid operator expects a total resource capacity of 77.7 GW. That doesn’t leave much wiggle room when the report also forecasts a summer peak load of almost 73 GW, which would break the 2016 record of 71.1 GW.
“The name of the game is performance,” ERCOT Manager of Resource Adequacy Pete Warnken said during a media call, repeating a message CEO Bill Magness delivered to the ISO’s Board of Directors last week. “We need to make sure all our resources are available and that we have situational awareness. If everyone is diligent about doing their job, we should be fine.”
Warnken highlighted ERCOT’s operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves, as one of several pricing mechanisms available for use this summer. He said the ISO will be “centrally testing” the ORDC for the first time this summer.
Dan Woodfin, ERCOT’s senior director of system operations, joined with Warnken in explaining to anxious Texas media how emergency response and other ancillary services, demand response, the 1.2 GW of emergency capacity available over five DC ties, and the availability of generators that can switch between neighboring grids will help prevent rolling blackouts in a worst-case scenario.
“We certainly have the tools and processes in place,” said Warnken, who also dismissed the likelihood of blackouts.
“In general, the whole market is set up in such a way that it encourages all generators to be online and resources to be available,” Woodfin said. “During these tight conditions, when prices are higher, there are lots of economic incentives to reduce demand or produce power.”
ERCOT said in its SARA announcement that the wholesale market provides “strong financial incentives” for generators to be available when demand rises and for retail electric providers to prepare for price fluctuations. It also raised the possibility of voluntary load reductions and injections of energy into the market by industrial facilities during peak demand.
In a somewhat unusual move, the Public Utility Commission of Texas, which oversees ERCOT, issued a statement following the SARA release, saying it continues to “closely monitor” this summer’s supply and demand forecasts. It noted generation owners’ decisions to retire large coal-fired power plants have “significantly reduced the excess supply of electricity” ERCOT has “enjoyed over the past five years.”
“It is important to note that the ERCOT market is designed with a number of mechanisms and tools to incentivize increases in supply or temporary reductions in demand to maintain the reliability of the system,” PUC spokesman Mike Hoke said, referring to the many different tools at the ISO’s disposal.
ERCOT attributed the tightening operating reserves to increased load from the state’s strong economy and the recent retirements. In a statement, Magness noted a series of monthly, winter and all-time peak demand records during recent years “as Texas’ economy continues to grow at record pace.”
“We expect high demand will continue this summer,” he said.
The ISO’s year-end Capacity, Demand and Reserves (CDR) report projected a 9.3% planning reserve margin for 2018, half of what it was in May and 4 percentage points below a 13.75% target ERCOT established for itself in 2010, following the wave of plant retirements last year. (See ERCOT: Tightening Reserve Margins no Cause for Concern.)
ERCOT said 3,800 MW in new generation resources began operating in 2017 and more than 14,000 MW of resources are planned to be in service by 2020.
The ISO also released its final assessment for the spring season (March-May), adjusting its spring peak forecast to 59.5 GW. It said it has sufficient generation on hand to meet demand.
NRG Energy said Thursday that its board has authorized the company to spend $1 billion to repurchase its own shares.
The company also said it has agreed to sell its Boston Energy Trading and Marketing subsidiary to Mitsubishi’s Diamond Generating unit for $70 million.
The moves are the latest in a series of steps NRG has taken to boost its share price in response to pressure from Elliott Management, a hedge fund run by billionaire Paul Singer, and Bluescape Energy Partners, a private investment firm, which announced in January 2017 that they had taken a 9.4% stake in the company.
NRG last July announced a transformation plan that it said would improve its recurring costs and margins by $1.1 billion; raise from $2.5 billion to $4 billion in cash through asset sales; and remove $13 billion in debt from its balance sheet. The company took major steps to execute that plan last month when it agreed to sell its renewables business, its stake in NRG Yield and its South Central Generating subsidiary in transactions that will bring it $2.8 billion in cash and take $7 billion in debt off its books.
The company also said last month that it expects to announce more sales this year and has revised its total asset sales cash proceeds target under the transformation plan to $3.2 billion. (See NRG Selling Renewables, Other Assets for $2.8 Billion.) With the announcement of the Boston Energy sale, the company has reported sales totaling more than $3 billion, all of which are on track to close by the end of the year, CEO Mauricio Gutierrez said during the company’s earnings call Thursday. As the closings progress and NRG completes the initial $500 million portion of its share repurchase program, it will look to kick off the second $500 million round of buybacks, he said.
Gutierrez also said NRG’s GenOn Energy subsidiary, which is operating under bankruptcy protection, could transition to becoming a standalone company as early as September. GenOn’s reorganization plan was approved by the U.S. Bankruptcy Court in Delaware in December, and its financial results are no longer included in NRG’s. On Tuesday, Platinum Equity said it has agreed to buy an 810-MW combined cycle gas-fired plant in Gettysburg, Pa., from GenOn for $520 million.
NRG posted a loss of $1.67 billion from continuing operations on revenue of $2.46 billion in the fourth quarter of 2017, compared to a loss of $891 million on revenue of $2.48 billion in the same quarter of 2016.
MISO on Wednesday secured another four months to implement mandatory five-minute market settlements, providing its staff more time to roll out new software designed to manage the process.
FERC granted MISO’s request to delay implementation from March 1 to July 1 after the RTO said it requires “more time to develop and test the software, after which market participants need a minimum of three months to make corresponding adjustments to their own software and reporting systems” (ER18-314).
MISO’s Carmel. Indiana Control Room in 2013 | MISO
The decision marks the second time the commission has extended the deadline for instituting five-minute settlements, required under FERC Order 825. MISO last May won an initial extension from Jan. 11 to March 1, but late last year multiple stakeholders noted that delays in replacing the RTO’s overall settlements system would result in members rushing to adapt their own systems to accommodate the new process. (See “MISO Asks for 5-Minute Settlement Delay,” 8 Projects Set for 2018 MISO Market Roadmap.)
FERC determined that MISO’s request for more time was made in good faith and was necessary for software testing.
“We find that good cause exists to grant this extension because of the importance of ensuring that software and testing requirements are met for both MISO and its market participants. … This extension will facilitate a smoother and more effective implementation of five-minute settlements in MISO,” the commission said.
In February, MISO staff said the RTO is still on track for fully functional testing with stakeholders beginning April 1, with the new settlements computer system fully implemented by April 16.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved proposed rule revisions that would allocate day-ahead market congestion rent shortfalls and surpluses stemming from changes in transmission availability to the responsible transmission owner.
The measure, which would revise Attachment N of the ISO’s Tariff, will go to the Board of Directors for approval before a filing with FERC. The Business Issues Committee (BIC) recommended the proposal to the MC. (See “Day-Ahead Market Congestion Settlements,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)
At the Feb. 28 MC meeting, Operations Analysis and Services Supervisor Tolu Dina explained that the ISO’s proposed cost allocation methodology employs a de minimis threshold to determine when TOs are not allocated costs. The threshold applies to day-ahead constraint residuals less than $5,000, provided the sum of all such residuals falling below the threshold is not more than $250,000 or 5% of the sum of all day-ahead constraint residuals for the month.
Alternative Methods for Determining LCRs
The MC approved Tariff revisions to establish an alternative method for calculating locational minimum installed capacity requirements.
The revisions incorporate incremental changes recommended by stakeholders at the Feb. 6 Installed Capacity Working Group/Market Issues Working Group meeting, said Zachary Stines, NYISO associate market design specialist. (See “Alternative Methods for Determining LCRs,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)
Stines presented the new method for determining locational capacity requirements (LCRs) for localities, designed to minimize the total cost of capacity at the level of excess condition while meeting reliability criterion, maintain the installed reserve margin approved by the New York State Reliability Council and not exceed transmission security limits.
| NYISO
The ISO plan evaluates net energy and ancillary services revenue at different levels of installed capacity using data from the most recent of either the capability year after a quadrennial “demand curve reset” or the annual installed capacity update.
The Long Island Power Authority, NRG Energy and other stakeholders recommended sending the measure back to a working group for additional analysis. But other market participants countered that while a case can always be made for more analysis in a big project, the proposal — while imperfect — represents an improved approach for estimating requirements.
MC Rejects On Ramp/Off Ramp Changes
The MC rejected a market design proposal and related Tariff revisions that would have eliminated localities and revised the existing on ramp/off ramp rules to create a new locality.
Zach T. Smith, NYISO manager of capacity market design, told the MC the proposed methodology is based on reliability planning principles developed to determine whether to create and eliminate localities.
The unique geographic nature of Zones J and K, encompassing New York City and Long Island, makes it difficult to site generation in those areas, which also confront distinct environmental issues, Smith said.
Mark Younger of Hudson Energy Economics reiterated the objections he made at the BIC meeting earlier in the month, calling the market design proposal — and NYISO’s review process — “flawed.”
BIC Chair Erin Hogan said NYISO received about 10 letters of support for the capacity market design from members of the public, the first time she recalled such a response. The letters will be posted on the ISO’s website.
MISO and SPP are ready to reform their interregional planning process to improve their shot at producing their first cross-border transmission project, but they plan to wait a year before launching a joint study to identify such a project, the RTOs said Tuesday.
At a Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting, the RTOs admitted that criteria spelled out in their joint operating agreement might be preventing beneficial interregional projects from gaining approval. They said they are ready to work with stakeholders through the summer to ease some restrictions.
SPP Interregional Coordinator Adam Bell said the RTOs’ latest coordinated system plan study, concluded in 2017, showed they are still inconsistent in how they calculate adjusted production costs, develop regional models and review regional project proposals. Before being approved, proposed interregional projects must clear separate regional reviews by each RTO in addition to passing a joint review.
“We’ve learned a lot in both coordinated plans we’ve done,” Bell said. “Both SPP and MISO are interested in doing meaningful planning between our systems, and we want stakeholders to have faith in the process and feel good entering these studies. … Both RTOs support … designing a new study process that has stakeholder confidence. We’ve done this twice. Let’s fix this thing.”
Davey Lopez, MISO adviser of planning coordination and strategy, said the RTOs plan to collect stakeholder suggestions and do more research before returning to the IPSAC in May with recommendations on how to improve their joint planning. The RTOs plan to work with stakeholders through September to prepare a FERC filing to alter their JOA by the end of the year.
Comprising planning staff from both RTOs, the Joint Planning Committee will vote later this year on whether to pursue another coordinated system plan.
Staff from both RTOs cautioned that they were unlikely to develop a 2018/19 study because planners are inclined to concentrate fully on process improvements, but stakeholders will be provided a non-binding IPSAC vote on where planners should concentrate their efforts.
$5 Million Obstacle
SPP and MISO said a major piece of the overhaul would be lowering the RTOs’ $5 million cost threshold for interregional projects.
“Hopefully, we can remove some of these hurdles on the coordinated system plan,” Lopez said.
In response to a question by Entergy’s Yarrow Etheredge, MISO and SPP staff declined to identify any specific project they would have liked to see pass but for the RTOs’ stringent criteria, although Lopez noted a few instances in which lowering the $5 million threshold would have improved a project’s chances in the last coordinated system plan.
“We really finished one study and started another, so we didn’t have time to implement these improvements we identified,” Bell said, referring to the short gap between the 2014/15 and 2016/17 studies. At the time, MISO recommended awaiting a second coordinated study while the RTOs worked out differences between their planning processes, but MISO eventually abandoned the idea in favor of starting another study.
Bell said it’s imperative for the RTOs to align their adjusted production costs and more accurately model each other’s systems. He suggested removing MISO and SPP’s joint modeling efforts altogether in favor of working on more identical regional models. Several stakeholders objected to that idea, claiming it could complicate cost allocation between the RTOs. Bell pointed out that MISO and SPP would still have a joint study under his plan, just not a joint model.
The RTOs are additionally contemplating allowing for adjustments in modeling cost allocation to determine if the benefits of a project are amplified.
SPP also continues to support cost allocation for sub-345-kV interregional projects with MISO, Bell said, a subject that MISO continues to discuss, according to Lopez. MISO has proposed cost allocation changes for its market efficiency projects, including a sub-345-kV cost allocation and elimination of a footprint-wide postage stamp rate. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)
Entergy Critical of MISO-SPP TMEP
Entergy engineer Kyle Watson said the MISO-SPP seam does not yet have a structured enough coordination process to develop smaller interregional projects, such as those eligible to qualify under the new MISO-PJM targeted market efficiency project (TMEP) category, which relies on historical congestion to identify small transmission projects. MISO and PJM approved a $20 million, five-project TMEP portfolio late last year, representing the first interregional transmission projects between the two RTOs, and some stakeholders have called for a similar process on the MISO-SPP seam. (See MISO Board Approves $2.6B Transmission Spending Package.)
Entergy’s Matt Brown said there isn’t sufficient operational data since the integration of the company into MISO and the Western Area Power Administration into SPP to build a case for congestion-relieving projects. But SPP Director of Seams and Market Design David Kelley disagreed, saying MISO and SPP have already collected enough historical congestion data to justify projects that are less costly than continuing to pay market-to-market congestion charges.
“The day-ahead and real-time congestion is persisting,” agreed Lopez.
During the IPSAC meeting, the RTOs pointed out that one congested flowgate on the Oklahoma-Kansas border has been responsible for nearly $20 million M2M payments since February 2017.
Wind on the Wires’ Natalie McIntire and WPPI Energy’s Steve Leovy said their organizations are displeased that the RTOs are not inclined to begin another coordinated system plan this year, given that the 2016/17 plan focused narrowly on needs along SPP’s Integrated System in North Dakota, South Dakota and Iowa, and the larger SPP-MISO seam has areas of congestion.
“There’s a lot of consumers bearing costs because we’re not fixing these issues,” Leovy said. “There’s need for a major interregional study.”
“We’re not happy, but we recognize there’s general consensus beyond us,” McIntire said.
