The Organization of PJM States Inc. has adopted a resolution urging the PJM Board of Managers to instruct staff to develop market rules “which optimize the participation and value of demand response” in the wholesale markets.
The resolution, sent to CEO Andy Ott on July 29, notes that 10,348 MW of the 12,000 MW in DR offered into the 2019/20 Base Residual Auction cleared. For the following delivery year, PJM will only purchase Capacity Performance products.
DR, which is mostly seasonal, has been a reliable resource that adds value to competitive markets, OPSI said.
“PJM’s planning process for the Base Residual Auction does not provide explicit recognition of the benefits from demand response except for those megawatts of demand response which clear in a PJM capacity auction,” the resolution said.
PJM’s Seasonal Capacity Resource Senior Task Force, whose charter was approved by the Markets and Reliability Committee in May, is studying rule changes to better allow for the participation of seasonal resources into the market once the base capacity product is eliminated. (See MRC Approves Charter for Seasonal Capacity Effort.)
Those resources now may offer in aggregate, but only one such offer was made during PJM’s transition auctions.
Proposals include allowing aggregate offers across locational delivery areas and permitting a seasonal product.
State consumer advocates pushed the PJM board at the RTO’s annual meeting in May to change Capacity Performance rules to encourage the participation of DR, energy efficiency and solar resources. (See Consumer Advocates, Enviros Press PJM on Seasonal Capacity.)
In order for new rules to be in place for the 2020/21 BRA, held next year, PJM must file them with FERC by late fall.
MISO said last week that it is leaning against the Independent Market Monitor’s proposal to restrict the ability of offline resources to set prices based on the results of a simulation study.
Congcong Wang, market design engineer, told the Market Subcommittee on Aug. 2 that MISO “continues to recognize the value of offline pricing” and is developing alternative solutions to the Monitor’s recommendation in the second phase of the extended LMP rollout.
Using simulations, MISO found that the Monitor’s proposed expansion of price setting doesn’t result in the most efficient prices, Wang said. “It does not mean the recommendation isn’t a good one; it just means that our current software … may not maximize price efficiency,” she added.
In the State of the Market report, the Monitor said offline resources should only set prices when they are economic and can be started quickly to address a shortage.
Monitor David Patton’s ELMP recommendation was two-pronged: He also advised expanding the share of online peaking resources eligible to set prices to include those with start times of one hour or less and minimum run times of two hours or less, regardless of whether they are scheduled in the day-ahead market. (See Monitor’s State of the Market Report Seeks Changes to MISO ELMP.)
Wang said MISO ran four days of simulations: Jan. 18, 2016, with no fast-start resource participation; Jan. 4, 2016, with low participation of fast-start resources; July 17, 2015, with high participation of fast-start resources; and July 12, 2015, with scarcity conditions with offline resource participation and heavy online participation.
MISO found the Monitor’s recommended price-setting expansion resulted in price increases from $1.52/MWh to $9.42/MWh. Expanding ELMP price-setting to units with 30-minute start times resulted in price increases of $0.34/MWh to $3.50/MWh. The Monitor’s recommendation causes price divergence between day-ahead and real-time prices in as much as 85% of intervals, but the 30-minute unit expansion doesn’t affect price convergence, the RTO said.
The recommendation results in online fast-start participation in more than 99% of intervals and the amount of pricing intervals impacted by ELMP rose from 0-7% to 35-74%, according to the RTO.
Patton responded that two of the test days MISO used were already under-scheduled by as much as 6 GW. “The convergence was naturally bad to begin with,” he said.
“I think it’s important to note that this high, it’s true that ELMP will affect more intervals, but many of these intervals are moving by a few cents,” Patton said. “To me, these results suggest that the expansion is necessary.”
Patton said he discovered that offline units setting prices were actually used only 8% of the time, and a diesel unit in Michigan was allowed to set prices 50 to70 times during the period he studied for the State of the Market report without ever being started.
“I’m not sure offline pricing has a strong benefit to begin with,” said Patton, who argued to FERC in the creation of Order 825 that offline pricing can “artificially lower energy prices and obscure shortages.”
Wang pointed out that in Order 825, the commission noted that offline pricing can result in efficient prices.
She said one of the alternatives to dropping offline price setting in ELMP is shortening cost amortization intervals. MISO currently amortizes the commitment costs of offline fast start resources over four real-time intervals, or 20 minutes.
The RTO is planning a September workshop and would come back with more results at the October MSC meeting. Until then, Wang said MISO will continue to run simulations and investigate the impacts of offline price setting. MISO wants to test the second phase of ELMP in the second quarter of next year.
CenterPoint Energy said Friday it is no longer considering transforming itself into a real estate investment trust.
“Given a broad range of assumptions, we have determined that the potential to create long-term shareholder value by forming a REIT is very limited and does not justify exposure to the associated risks,” CEO Scott Prochazka said in a statement. “We continue to focus on increasing shareholder value by investing in our growing utility businesses.”
CenterPoint executives did not elaborate on the decision during their quarterly earnings call. The company had said in February that it was considering the use of a REIT for all or part of its utility business.
The decision may have been influenced by Hunt Consolidated’s unsuccessful plan to use a REIT structure to acquire Oncor. In March, the Public Utility Commission of Texas approved Hunt’s proposal to split Oncor into two companies, one of which would operate as a REIT. But the commission ordered the REIT’s tax savings be shared with Oncor customers, effectively scuttling Hunt’s plan to acquire the utility.
CenterPoint officials spent much of their earnings call discussing plans to divest the company’s stake in Enable Midstream Partners, a gas gathering and processing limited partnership with OGE Energy.
OGE said during its Aug. 4 earnings call that CenterPoint offered to sell OGE its 55.4% stake in Enable. Under the partnership agreement, OGE has the right of first offer and the right of first refusal on any sales of CenterPoint’s share of Enable, which went public in 2014.
“Our options are essentially the same as they’ve been in the past. We’re looking at a sale or a spin,” Prochazka said. “The timing is such [that] we’re continuing to step through the process. Providing notice to OG&E was one part of [the] process.”
Prochazka said Enable’s performance helped weigh down CenterPoint’s second-quarter results. The company reported a loss of $2 million for the quarter ($0.01/share), after registering a $77 million profit ($0.18/share) for the period in 2015. It had operating income of $182 million, compared to $186 million a year ago.
The company said the losses could be attributed to “changes in the fair market value of commodity derivatives.” Investors reacted Friday by sending CenterPoint’s stock down 3.9%, closing at $22.67.
Houston-based CenterPoint serves more than 5 million metered electric and gas customers, mostly in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
A federal judge in Southern California declined to dismiss a lawsuit alleging that CAISO unjustly deprived the Imperial Irrigation District (IID) of its full export rights on a transmission line linking the utility’s balancing authority area (BAA) with the ISO.
U.S. District Court Judge Anthony Battaglia on Monday ruled that IID’s suit had “sufficiently alleged monopolistic conduct that threatens competition” and directed the utility to file an amended claim addressing deficiencies within three weeks.
Salton Sea Source: Imperial Irrigation District
“Specifically, by depriving IID of its expanded [maximum import capability], generators of renewable energy located within IID’s BAA who cannot interconnect directly with the CAISO grid cannot compete with other generators for the business of load-serving entities located in or through the CAISO grid,” Battaglia wrote.
IID’s suit contends that — through a series of memos and public statements from 2011 to 2014 — CAISO “induced” the publicly owned utility to perform $30 million in upgrades to Path 42, one of two transmission lines connecting IID with the ISO. CAISO estimated that the improvements would increase IID’s maximum import capability (MIC) into the ISO from 462 MW to 1,400 MW. The upgrades were put in service in January 2015.
In July 2014, CAISO downgraded IID’s future “expanded MIC” to its previous level, citing the closure of the San Onofre nuclear generating station as the reason for the decision. That move came after IID had already begun work on the upgrades. At the same time, the ISO said that other network additions — although not IID’s upgrades — would restore future flows out of the IID area by up to 1,000 MW, extra capacity that CAISO reserved for itself.
Skeptical of the claim that San Onofre’s closure was the basis for downgrading IID’s MIC, the utility initiated an investigation revealing that CAISO had miscalculated the flows on one of its own transmission lines — a misstep that IID alleges stemmed from the ISO violating its own operating procedures. A correct calculation would have restored the utility’s expanded MIC to 1,400 MW, IID argued.
IID contends that elimination of the expanded MIC prompted renewable energy developers to bypass the utility’s system to directly connect with the ISO, denying IID “significant revenue” from transmission services. IID further alleged that CAISO’s action was part of broader strategy to “further its monopolistic position” by forcing the utility to join the ISO.
While the court dismissed IID’s breach of tariff and federal antitrust claims, it let stand claims against CAISO for breach of contract, conversion, unjust enrichment and restitution.
“The court finds CAISO’s multiple public statements from 2011 through 2013 acknowledging the Path 42 project and the expected increase to IID’s MIC are sufficient to support, at this stage of the litigation, an inference that CAISO implicitly assented to the alleged contract, namely, that CAISO would increase IID’s MIC in exchange for IID’s upgrades to its side of Path 42,” Battaglia wrote.
The court also affirmed its jurisdiction over the proceeding.
“While it is true that transmission of electric energy in interstate commerce is generally a matter of federal concern, FERC simply has no jurisdiction over the transmission facilities at issue here, namely, IID’s facilities, because FERC’s jurisdiction extends only to ‘public utilities,’” Battaglia wrote — noting that, as a municipal utility, IID did not fit the definition of the term.
“IID is pleased that the case against CAISO can now move forward,” IID General Manager Kevin Kelley said. “There is no doubt that the district, its renewable energy generators and ultimately its ratepayers have been harmed by the state’s grid operator in denying transmission access to IID’s balancing area.”
CAISO said it disagreed with the court’s ruling that it has jurisdiction over IID’s remaining claims. “We believe these claims are likewise completely without merit, and we expect that they will be dismissed by the court as further proceedings unfold,” CAISO said in a statement.
Arizona Public Service and Puget Sound Energy have moved a step closer to linking up with CAISO’s Energy Imbalance Market.
The ISO on Aug. 1 commenced the operations testing phase to prepare the companies for full entry into the real-time market this fall. Over the next two months, the two utilities will operate in the market under real conditions, although their transactions will not become financially binding until Oct. 1.
The testing period will enable grid operators, system engineers and market managers to verify that systems are working as planned, CAISO said.
Unlike an RTO, the EIM does not require transmission-owning members to turn over operational control of their balancing authority areas (BAAs). Generator participants are also allowed to bid real-time energy into the market on a voluntary basis; there is no must-offer rule.
A recent CAISO report said the EIM has accrued $88.2 million in benefits to its participants since the market commenced operation in November 2014. (See EIM Report Shows Continued Growth in CAISO Exports.) Berkshire Hathaway Energy’s NV Energy and PacifiCorp are currently the only utilities participating in the market. Portland General Electric is scheduled to join in October 2018, followed by Idaho Power in spring 2019.
“The addition of APS and PSE will create more opportunities to produce additional benefits, including improved integration of renewable energy,” CAISO CEO Steve Berberich said in a statement.
APS serves about 1.2 million customers in Arizona and operates nearly 6,000 miles of transmission. A 2015 EIM benefits study by consulting firm Energy and Environmental Economics (E3) assumed the utility would maintain about 2,500 MW of transfer capacity with CAISO and another 600 MW with the PacifiCorp East BAA. The utility has no direct links with NV Energy.
The E3 study also determined that EIM membership would help APS lower costs by $7 million to $18.1 million, including $1 million to $3.2 million from the reduced need to maintain flexibility reserves — the type of capacity required to quickly firm up variable output from renewable resources. Implementation costs were estimated at $13 million to $19 million.
PSE serves about 1.1 million electricity customers in Washington state and operates about 2,600 miles of transmission, with a 1,600-MW import capability to compensate for a shortage of generation resources.
But the utility also has a surplus of flexible capacity, “which is probably why we’re joining the EIM,” Phillip Popoff, PSE manager of resource planning, told the Infocast California Energy Summit in May. The utility expects to realize annual benefits of $18 million to $30 million, with start-up costs estimated at about $14 million.
EIM start-up costs include metering upgrades to enable generating plants to capture data at five-minute increments, new market software, business process changes and Open Access Transmission Tariff revisions.
Both utilities will additionally incur ongoing costs of $3.5 million to $4 million a year, which includes fees paid to the ISO to manage the market.
Xcel Energy CEO Ben Fowke said last week that executives are sharpening their pencils after the company failed to meet analysts’ second-quarter expectations.
“We have taken action to reduce [operations and maintenance] expenses,” Fowke told analysts Aug. 3. “As a result, we are confident in our ability to deliver ongoing earnings solidly within our 2016 guidance range” of $2.12 to $2.27/share.
Xcel reported second-quarter earnings of $196.8 million ($0.39/share), compared with $197 million ($0.39/share) a year ago. Analysts surveyed by Thomson Reuters were expecting a penny more ($0.40/share).
Sales were $2.5 billion, lower than the $2.53 billion forecast because of what the company called “some unfavorable weather.” Xcel’s sales for the same period last year were $2.52 billion.
Xcel reported several positive regulatory developments in the eight states in which it operates and touted the proposed 600-MW Rush Creek wind farm in Colorado as an affordable step toward decarbonizing its generating fleet.
“You basically are buying wind at a price point less than you can lock in natural gas reserves,” Fowke said. “So, that’s a pretty compelling story for customers and, I think, investors alike.”
According to the American Wind Energy Association, Xcel is the country’s top-ranked utility wind provider, with 6,545 MW of wind capacity owned or under contract as of the end of 2015. The company has reduced coal’s share of its fuel mix from 56% to 43% since 2005, while wind increased from 3% to 17%.
Fowke said the company expects to add more wind.
“MISO is a big footprint and so, I mean, I certainly think from a reliability standpoint … you can handle more wind … and it’s pretty economically compelling right now,” he said, according to a transcript by Seeking Alpha. “In Colorado, where we’re not part of an RTO, we have experienced wind as high as I think 65% of our load in any particular time, and we’ve managed to integrate it very well. And part of that is we’ve developed some of the most sophisticated wind forecasting software in the business, and it’s helping us be more efficient with wind. So [there are] very little curtailments in our wind portfolio; we’re pretty proud of that.”
The company’s shares closed Friday at $42.66, down $1.07 (2.51%) since the earnings announcement.
Minneapolis-based Xcel has operations in the Dakotas, New Mexico, Texas, Wisconsin and Michigan.
MISO promised last week to review a plan that could end the system support resource agreement for White Pine Unit 1 in Michigan’s Upper Peninsula.
American Transmission Co. said MISO could eliminate the need for the 40-MW generator by revising ATC’s system operating guide and making a temporary two-radial reconfiguration of its transmission system, returning it to pre-1998 conditions. ATC said its solution — details of which haven’t yet been made public — could remain in place until either new generation or new transmission are built.
White Pine Source: P.M. Power Group
The Michigan Agency for Energy supported ATC’s plan, saying it would save Upper Peninsula ratepayers $7.3 million annually in SSR payments.
“I applaud the problem-solving that led to this solution. I wished all stakeholders had gotten more warning early on so there would have been time to develop and implement this solution before costs started to go up and litigation was needed,” said Valerie Brader, executive director of the agency.
Brader also sent a letter to MISO, urging that the grid operator accept ATC’s proposal “without delay,” as it would not result in Tariff revisions. Bader also criticized the “poor condition” of White Pine Unit 1 and noted its six- to 12-hour cold start time.
ATC spokeswoman Anne Spaltholz said the company is working with MISO on the details of the proposals. The RTO has committed to reviewing ATC’s plan during the Aug. 9 meeting of the West Technical Study Task Force.
FERC has final say in the termination of SSR agreements. If an alternate solution isn’t identified, the 60-year-old White Pine plant will continue SSR operations until 2020.
ALJ Orders Refunds for Presque Isle SSR
In a related case, FERC Administrative Law Judge Michael Haubner issued a 37-page initial decision on July 25 (ER14-1242-006, et al.) concluding that Michigan ratepayers were overcharged by Wisconsin Electric Power Co. (WEPCo) for SSR payments on the 344-MW Presque Isle coal plant in Marquette, Mich., in 2014 and early 2015. The judge says $17 million in refunds plus interest are in order; final say rests with the commission.
The ruling came three months after FERC decided that the SSR rate schedules for the Presque Isle, Escanaba and White Pines power plants were appropriate. (See FERC Upholds 3 MISO SSR Cost Allocations in Upper Peninsula.) The Presque Isle and Escanaba SSRs were terminated in 2015.
Brader blamed MISO for the overages, saying the RTO failed to perform due diligence. “MISO blindly accepted numbers without reviewing their reasonableness, resulting in the state and other interested parties having to challenge the expenses through costly proceedings at FERC,” she said.
In May, MISO asked FERC for permission to revise its SSR procedure to require generation owners to provide 26 weeks’ notice of plant suspensions or retirements. The RTO also wants to relax some confidentiality provisions around SSR agreements. (See “MISO Planning Confidentiality, Notification Changes to Attachment Y Procedure,” MISO Planning Advisory Committee Briefs.)
Cloverland Electric Cooperative, a Sault Ste. Marie, Mich.-based nonprofit that has the highest Presque Isle surcharge at $11.7 million, welcomed the ruling, but said it doesn’t fix the larger SSR problem.
“The judge proposed a refund, but for Cloverland members, this just reduces the costs we will have to pay over the next several months. The judge’s decision is one positive step in the legal process that allows the case to continue,” Cloverland CEO Dan Dasho said in a statement.
Dasho also criticized a 2008 exemption to Michigan’s 10% retail choice cap that allows Upper Peninsula iron ore mines to choose their power suppliers. The decision by iron ore provider Cliffs to leave the Presque Isle plant for another generator is the reason WEPCo decided to close the plant in 2014. Dasho said if the law is not changed, the mines could “leave again,” leaving Upper Peninsula ratepayers responsible for a new $300 million natural gas cogeneration plant planned by Chicago-based Invenergy on the Cliffs mining site.
“Our senators and representative supports our position on this, but the governor’s administration is refusing to have this exemption removed and finally protect all the ratepayers in the Upper Peninsula,” Dasho said.
CAISO last week provided stakeholders an update on its efforts to address concerns that the Energy Imbalance Market is not properly accounting for the impact of emissions from dispatching out-of-state resources into California — what the state’s Air Resources Board calls “carbon leakage.”
“We are working collaboratively with the ARB to address their identified issues with greenhouse gas accounting in the EIM,” Mark Rothleder, CAISO vice president for market quality and renewable integration, said during an Aug. 4 Regional Issues Forum held at Idaho Power headquarters in Boise.
Leakage occurs when California’s emissions program logs a reduction, despite the fact that no actual decrease in atmospheric GHGs has occurred based on the effects of the secondary dispatch.
The board’s concerns focus on how the EIM’s least-cost dispatch model attributes balancing energy from a low-emitting out-of-state resource to CAISO, while not accounting for the secondary dispatch of another higher-emitting resource that serves external demand that could have been covered by the first resource absent the market.
California’s Air Resources Board (ARB) is seeking to capture the impact of higher-emitting resources being dispatched in the EIM to cover for zero-emissions power dispatched into CAISO. Fort Churchill Generating Station Photo Source: NVEnergy
The cleaner resource is “deemed delivered” to California, and the cap-and-trade system issues an emissions-compliance obligation to the scheduling coordinator for the resource, the ARB has noted.
“However, in certain instances, the full transfers that support balancing load to California are not identified and accounted for in the cap-and-trade program, resulting in emissions leakage,” the board wrote in a recent staff report proposing changes to the state’s cap-and-trade system.
CAISO is considering a range of options to help the ARB account for the emissions stemming from secondary dispatch.
The favored option: calculating the emissions from the secondary dispatch and assigning the GHG obligation to ISO load responsible for imbalances. However, this option could call the ISO’s dispatch decisions into question, Rothleder said.
Other options include requiring a minimum GHG bid for low-emission resources based on a system-emission rate or creating a hurdle rate for EIM transfers into the ISO. Both would put clean out-of-state resources at a disadvantage to equivalent resources inside the ISO.
The ISO also floated the idea of ARB lowering the electricity sector’s emissions caps or retiring GHG allowances by the estimated amount of secondary dispatch effects. Under California’s cap-and trade system, load-serving entities are issued a set amount of allowances each year subject to a declining annual cap.
One unlikely proposal is to have CAISO become a regulated party under cap-and-trade and produce all the emissions-compliance instruments associated with EIM dispatch.
“This is not high on our list as the way to go,” Rothleder said.
He pointed out that any solution would apply only to the EIM, and not to an expanded ISO. Still, the outcome could inform GHG accounting under regionalization.
CAISO seeks to issue a paper on the subject within a month and is targeting a fall meeting for further discussion. Any changes to GHG accounting in the EIM are slated to go into effect in January 2018.
MISO is considering whether the transfer limit of 876 MW between MISO South and MISO North used in this year’s Planning Resource Auction should be adjusted for the 2017/18 capacity auction and if resources supplying the capacity will be delivered on a firm or non-firm basis.
MISO posed several questions to stakeholders at the Aug. 3 Resource Adequacy Subcommittee (RASC) meeting:
Should the starting limit for the sub-regional power balance constraint (SRPBC) prior to accounting for firm transmission service be 2,500 MW or 1,000 MW?
In treating firm transmission service sold across the contract path, should SPP:
Differentiate for firm transmission that is or is not associated with a capacity sale in another market?
Consider the ability of a transmission customer to redirect transmission service (i.e., redirect sink from PJM to MISO North)?
Treat pseudo-tied resources differently?
Under MISO’s settlement with SPP over the use of its transmission system, flows between the North and South regions are considered non-firm. The agreement “explicitly did not provide firm contract path or firm flow entitlements,” according to MISO.
MISO South region represented in orange.
MISO’s 2016/17 PRA enforced a limit of 876 MW for South-to-North transfers. The initial limit of 2,500 MW was downgraded to 876 MW after MISO subtracted firm exporting reservations that had completed a feasibility analysis.
“We’re trying to achieve an efficient but reliable PRA outcome,” explained Kevin Sherd, MISO director of forward operations planning. “If we approve 2,500 MW and can only get 500 MW delivered due to congestion, that’s a problem. The higher the number goes from South to North or Zone 1 to Zone 6,” the higher the risk, he said.
“I’m not arguing one or the other today. I’m teeing this up for a September discussion,” Sherd said.
Currently MISO allows two opportunities for resources to participate in the PRA as firm capacity: as a network resource interconnection service (NRIS) or as an energy resource interconnection service (ERIS) with a firm point-to-point transmission reservation.
MISO Manager of Resource Adequacy Coordination Laura Rauch said the RTO completes an annual deliverability test on NRIS generators to make sure they are able to deliver power to network load. ERIS generators are analyzed via an annual long-term transmission rights feasibility test and through the expansion planning process.
ITC Holdings’ Ray Kershaw suggested that opening up participation for generators without firm rights might allow some non-firm external generators to participate in the PRA. “You’re opening up a whole lot here,” Kershaw said.
Dynegy’s Mark Volpe asked if MISO could use data from this summer to establish anticipated power flow needs to make a more educated decision.
Sherd said multiple days this summer could provide data for an estimated transfer limit and said MISO would bring numbers back to the next RASC meeting.
Other stakeholders asked what the Independent Market Monitor thought of changing the transfer limit.
IMM staffer Michael Chiasson said the Monitor will review MISO’s questions but declined to comment on the transfer limit. The Monitor’s State of the Market report recommended improving the modeling on transfers by introducing a derating factor representing the probability that MISO neighbors will request a reduction from the 2,500-MW transfer limit because of an emergency. (See Monitor’s State of the Market Report Seeks Changes to MISO ELMP.)
Stakeholder input on the matter is requested before the Aug. 31-Sept. 1 RASC meeting. MISO hopes to adopt a solution for the 2017/18 PRA.
MISO Inserting More Deadlines into PRA Timeline
MISO wants more official deadlines for market participants worked into the PRA timeline, Manager of Resource Adequacy John Harmon said.
The RTO is proposing to attach explicit due dates to multiple data submittals made before the auction, including quarterly Generating Availability Data System figures, annual output data for run-of-river and biomass resources, load forecast revisions after Nov. 1 and the unforced capacity value confirmation.
“These [requirements] aren’t new, but we’ve never had definitive dates. No new action is required … but a lot of market participants said, ‘I didn’t know you needed this by this date,’” Harmon said. “We had trouble during the last auction working with folks to make sure deadlines were met.”
The RTO will also attach consequences to missed deadlines, Harmon said, but not before MISO Client Relations reaches out to market participants about delinquent information. After that, MISO will process late submissions in monthly “batches” rather than on an individual basis and could deny requests for late submissions altogether, possibly disqualifying the market participant from offering in the PRA.
SPP and MISO are inching closer to agreement on a second joint transmission study on their seams, though they continue to disagree how “targeted” a targeted study should be.
The two grid operators have agreed to conduct another transmission study this year, using the carbon-constrained scenarios in SPP’s 2017 Integrated Transmission Planning 10-Year Assessment and MISO’s 2016 Transmission Expansion Plan as starting points.
The study, to be completed in the first quarter of 2017, will use the needs identified in the regional studies to develop solutions that benefit both RTOs. It will model the years 2020, 2025 and 2030; SPP will have to create a model for 2030, which is not included in the 2017 ITP10.
MISO prefers limiting the study to the seams between it and the Integrated System, which joined SPP last October, while SPP favors looking at a broader geographic area.
Staff shared the draft scope with the RTOs’ Interregional Planning Stakeholder Advisory Committee on Aug. 2, with SPP’s Seams Steering Committee again taking up the issue Aug. 3.
MISO staff said it preferred to focus on process improvements this year, but it did propose that a set of five needs — three belonging to SPP, two to MISO — be included in the joint study. SPP suggested 10 regional needs, eight in its footprint and two in MISO’s, that it said would “provide the most value to be evaluated” in the Coordinated System Plan study.
Time Best Spent
MISO agreed to a joint study this year only after a May meeting of its Planning Advisory Committee. (See “MISO Rethinks Coordinated Study with SPP,” MISO Planning Advisory Committee Briefs.)
“We have to ask ourselves, where is our collective time best spent?” said MISO’s Eric Thoms, manager of planning coordination and strategy, in arguing against a broader study. “The 2014-15 [study] took three extra months. It took a herculean effort to finish … that’s the most diplomatic way to define it.”
“My impression was [MISO has] already decided what they want to do, and it’s up to us to convince them otherwise. I don’t like that position,” SSC Chair Paul Malone, of the Nebraska Public Power District, said at Wednesday’s meeting.
The IPSAC conference call also left some SPP stakeholders questioning the stakeholder meeting process. The Wind Coalition’s Steve Gaw expressed concern that the decision to use a targeted scope was made prior to the joint stakeholder meeting.
“I thought the [IPSAC] call was about defining the scope,” Gaw said at the SSC meeting. “It confused me that a decision has already been made about [the scope] being targeted.”
David Kelley, SPP’s director of interregional relations, agreed with Gaw. “The way you described it should have been the way to work,” he said. “We bring issues to the table, [and] we decide if they’re enough to warrant a study.”
Staff set an Aug. 24 deadline for stakeholders to submit comments on the draft scope. MISO has another PAC meeting scheduled Aug. 17 that could further clarify the study’s final scope.
The IPSAC has tentatively selected Sept. 7 to finalize the scope with stakeholders.
Task Force to Look at Non-Order 1000 Regional Cost Allocation
In a related matter, the SSC voted 8-5 to create a task force to revise a proposed business practice for regional cost allocation of seams projects outside FERC’s Order 1000 process. The task force will use a white paper that has already been through the stakeholder process to document the policy. The group will be chaired by Oklahoma Gas & Electric’s Jake Langthorn.
