The Sacramento Municipal Utilities District (SMUD) will join the Western Energy Imbalance Market (EIM) in spring 2019 at the earliest, according to the head of the joint powers agency of which the utility is the largest member.
Shetler | United Way
“As you might guess, this is a very intense technical project,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), told RTO Insider.
The four utilities that have joined the EIM to date have required 18 to 24 months to begin operating in the EIM after signing an implementation agreement with CAISO, the market’s operator.
SMUD will likely sign such an agreement early next year, Shetler said. “We’re just starting to meet with the ISO to lay out project plans.”
The utility announced its intention to join the EIM on Oct. 21, citing the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)
SMUD would be a first municipal utility to sign up for the market — a status that could potentially complicate its efforts to join. Municipal utilities are not subject to FERC jurisdiction — but the EIM is. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
“With FERC oversight, we’re trying to understand what that would mean,” Shetler said. “SMUD has an open access transmission tariff that was approved by its board, but not by FERC.”
SMUD already operates under an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
A joint study conducted by BANC and the Western Area Power Administration estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market — a figure that nets out an estimated $6.7 million in implementation fees and $2.6 million in annual operations costs.
Shetler said that SMUD’s annual benefit could increase to about $5 million after five years, once the utility has paid down startup costs.
“It’s a big number, but a small number compared with their energy resource portfolio,” Shetler said. The real value will come in integrating the increased number of variable resources needed to meet California’s 50% by 2030 renewable energy mandate, he noted.
Sacramento Municipal Utility District headquarters | SMUD
SMUD would be breaking ground for possible future EIM participation by BANC’s other municipal utility members, including Modesto Irrigation District and the cities of Redding and Roseville.
Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, Shetler said. Trinity, a “full requirements” customer of WAPA, receives all of its energy from the federal agency.
Could other BANC members piggy-back on SMUD’s efforts and reduce their costs to join the EIM?
“We’re hoping that’s the case,” Shetler said. “We think there is some scale there.
“Not that it would be on the backs of SMUD or its ratepayers,” he added.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas.
BANC contracts with SMUD to perform day-to-day balancing functions.
The BANC-WAPA study spelling out EIM benefits is slated to be released to the public in late November.
COLUMBUS, Ohio — More than 150 regulators, PJM officials and stakeholders gathered for last week’s annual meeting of the Organization of PJM States Inc. Here’s some of what we heard.
American Public Power Association CEO Sue Kelly, who appeared on a panel on PJM’s Capacity Performance model with Independent Market Monitor Joe Bowring and RTO officials, Calpine and two utilities, noted that it was her fourth such appearance before OPSI. As the lone critic of mandatory capacity markets, she joked, she felt like “the token Republican on MSNBC.”
She said the changes going on “at the end of the grid,” such as solar and demand response, are going to make CP “outmoded.” It “does not meet public-policy goals. It wasn’t designed to meet public-policy goals,” she said.
PJM General Counsel Vince Duane said there are “a whole host” of “entirely valid” public-policy goals that PJM must balance in its designs. “So it’s not a question of which policies are more important,” he said. “There’s a lot of evidence out there that we’ve done the design job very well.”
The focus needs to be on developing the flexibility for states to make policy goals while ensuring the viability of CP, he said.
He said it’s a “gross over-reading” of the Supreme Court’s Hughes v. Talen ruling to believe that any state subsidy would interfere with wholesale markets. (See Supreme Court Rejects MD Subsidy for CPV Plant.) “We can’t let the markets be used to obscure and disenfranchise the political process,” he said.
Bowring repeated his concerns that competitive markets are threatened by state-subsidized generation, as proposed in Ohio. “There is a line, and the line has to do with price formation and the integrity of the market,” he said. “To the extent that the line isn’t drawn, then the markets won’t survive.”
Kelly said the Hughes case gives states and public power utilities “a lot of options” for implementing public policies without violating federal jurisdiction. “I don’t think we should just count on that court case to squash all of this. I think it would be much better if we collectively work this out than go back to the Supreme Court three more times,” she said.
Lathrop Craig of Public Service Enterprise Group asked if a market dominated by gas, supported by renewables and experiencing major declines in coal “still makes a lot of sense” and whether a unit’s value to the market should rely on something other than its lack of emissions.
Bowring wasn’t in favor of what he described as subsidizing old units “because you don’t like where the market’s going.”
“I don’t think that’s a good idea,” he said.
Kelly raised concerns about relying too heavily on gas. “It’s kind of like dating your first husband — you have bad memories,” she said. “I have memories of gas at $3.50. I have memories of gas at $14.50. I have memories of having my contract ripped up by FERC and having to go out and replace all that.
“Things are great till they’re not great,” she added, citing concerns that fracking is causing earthquakes in Oklahoma and a rise in demand for LNG could boost gas prices.
In another panel, stakeholders discussed how state renewable portfolio standards are the largest driver of the surge in renewables on the grid. PJM’s Chantal Hendrzak outlined several initiatives the RTO is undertaking, including developing wind and solar forecasts and researching better integration of renewables and battery storage, to ensure that “when renewables come on the system, no matter how they come on the system, that we can reliably integrate them.”
The industry has moved quickly to implement states’ renewable portfolio standards, said Exelon’s Bill Berg. “Some of the lofty goals passed a few years ago now seems within reach,” he said.
As usual, the conference ended with OPSI’s Market Monitoring Advisory Committee’s meeting — an annual check-up on the status of relations between the Monitor and PJM.
Bowring said his “overall” relationship with PJM “is good,” but he noted one exception. He said the “very public” disagreement over how the Monitor interacts with PJM has resulted in “pretty tough filings back and forth on the hourly flexibility proceeding.” (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Virginia State Corporation Commissioner Mark Christie commended Bowring, while noting that “not everyone agrees with” him.
“It is really all about making sure the markets are as efficient as possible, and we’ve always viewed the Independent Market Monitor as critical to that,” Christie said. “We certainly respect his honesty, his talent, his willingness to tell it like it is, like he sees it. Those who disagree can disagree.”
PJM Board Chairman Howard Schneider interjected, “We agree with that 100%.”
Earlier, Schneider had announced board member Susan Riley as the new chair of the Competitive Markets and Governance Committee, which oversees the engagement between PJM and the Monitor. Riley assured the audience that the committee has regular contact with Bowring, and he has unfettered access to bring issues to the board.
“Each issue that he raises is, in fact, researched with PJM, with Joe, with Joe’s staff, and we try to arrive at resolutions we can — more times than not — agree on,” she said. “The working relationship has evolved and grown over the past nine years, and I would say from where I sit that it’s working very well right now.”
Bowring agreed.
American Municipal Power’s Ed Tatum, who asked the only question during the brief meeting, appreciated the collegial tone. “The troubles are over. The waters are more still, and that’s good,” he said.
FERC on Thursday rejected CAISO’s effort to refund $220 million to scheduling coordinators that the ISO said were misallocated payments to generators operating under must-offer obligations.
The decision rendered moot a complaint filed by energy retailers that contended that the refunds were unjustified because they had not been specifically ordered by the commission (EL14-67, et al.).
While the ISO’s refund report did not specify the beneficiaries of the refunds, other documents related to the proceeding indicate that a portion of the payments were likely destined for Southern California Edison customers in light of a previous FERC decision to reallocate must-offer costs associated with a transmission constraint within the utility’s service territory to all load in CAISO’s SP-15 zone.
At issue was a May 2004 Tariff amendment that changed the allocation of minimum load costs — fuel costs associated with keeping a unit running at minimum levels — for must-offer generation to more accurately reflect cost causation.
CAISO sought to issue refunds – in part – because of FERC’s decision to reclassify the benefits of must-offer generation located south of the Lugo substation located within Southern California Edison’s service territory. | California Energy Commission
Under the design, CAISO allocated minimum load compensation costs to load-serving entities based on whether the generators had primarily fulfilled local, zonal or system reliability requirements.
FERC approved most of the amendment two months later, but the cost allocation provision — which had been contested by Pacific Gas and Electric — was subject to modification and rehearing, with a refund date set for July 17, 2004.
In December 2006, the commission mostly affirmed the reasonableness of the allocation provision, but it found that the South of Lugo Transformer Path in Southern California should be classified as a local — rather than regional — constraint. FERC ordered the ISO to allocate must-offer start-up and emission costs in the same manner as minimum load costs and determined that wheel-through transactions should be excluded from the allocation.
Southern California Edison protested the reclassification of the South of Lugo constraint as local, an argument with which the commission later agreed in a 2007 rehearing. The cities of Anaheim, Azusa, Banning, Colton and Riverside, in turn, contested that decision, but the D.C. Circuit Court of Appeals denied their petition for review in 2013.
Later that year, CAISO submitted to FERC a report outlining refunds the ISO intended to issue based on the reallocation of must-offer costs stemming from the prior rulings. Issuing the refunds would require the ISO to levy surcharges on scheduling coordinators that paid too little in order to make whole those that paid too much.
Shell Energy North America and the Alliance for Retail Energy Markets — representing Constellation NewEnergy, Direct Energy and Noble Americas Energy Solutions — contested the surcharges, saying that they were effectively retroactive rate increases not authorized by FERC. They also argued that, when the commission requires refunds, “its normal practice is to expressly order that refunds be made within a specified time and that a refund report be filed,” neither of which occurred. In any case, FERC was not obligated to require refunds in this case, they said.
Those contentions found support in the commission’s decision last week.
“CAISO’s filing of the refund report is not tied to any commission compliance directive in this proceeding,” the commission wrote. “While the commission initially accepted CAISO’s filing subject to refund, at no point did the commission direct CAISO to make refunds or file a refund report.”
The commission also found that the ISO at no time overcharged its customers and that it had appropriately revised its Tariff on compliance so that a just rate was allocated to customers on a going-forward basis.
Furthermore, the commissioners pointed out that none of its prior orders stated that the ISO had failed to follow any directives by not issuing refunds.
Transmission Line Leading to Lugo Substation | Edison International
“Even if it were arguably unclear whether refunds should have been ordered for past periods, we note that neither CAISO nor any other party sought rehearing or clarification of the orders in this proceeding on this issue,” the commission said.
FERC went on to state that “surcharging of market participants was improper for any past periods” and that its power to order refunds is “discretionary” under the Federal Power Act.
The commission said the complaint by the alliance and Shell “has been rendered moot as a result of our rejection of the refund report.”
Electric cooperatives accused FERC on Friday of overstepping its authority by opening proceedings that could force refund obligations on nonpublic utilities, while MISO and SPP asked the commission to let them work out the issue in stakeholder proceedings.
At issue are FERC’s July orders opening Section 206 proceedings in MISO and SPP (EL16-91 and EL16-99). FERC said that it may be unjust and unreasonable for the RTOs to exempt nonpublic transmission owners from the refund requirements it mandates for public utilities. (See FERC: MISO, SPP Need Refund Requirements for Nonpublic Utilities.)
NRECA’s Argument
Tracy Warren, senior communications officer at the National Rural Electric Cooperative Association (NRECA), said the proceedings amount to a “work around” for FERC to regulate electric cooperatives and nonpublic utilities that are not under commission ratemaking authority. “We believe FERC is trying to extend its jurisdiction,” she said.
Rural Electric Cooperative line workers in Oklahoma | Rural Electric Cooperative
In its initial brief in the 206 proceedings, NRECA said a refund requirement could deter nonpublic utilities from joining RTOs. NRECA also acknowledged in its filing what it called FERC’s “legitimate concern” in ensuring that MISO and SPP abide by the Federal Power Act.
“However … NRECA cautions the commission against threatening the progress made in transmission-owning [nonpublic utilities] becoming members of MISO and SPP. … Maintaining their non-jurisdictional status is critical for [nonpublic] cooperative utilities deciding whether to join an RTO,” NRECA wrote.
Although FERC acknowledged in the proceedings that it cannot directly order refunds from nonpublic utility transmission owners that have joined RTOs, it suggested SPP and MISO could indirectly enforce refunds. NRECA, which represents more than 900 nonprofit rural electric utilities, said the measure would force co-ops and municipal utilities to “volunteer” to pay revenue refunds if they want to recover transmission revenue requirements.
“Long-standing interpretations of the Federal Power Act confirm that the majority of our members lie outside FERC’s ratemaking and refund authority; yet with these proceedings, FERC is working to undermine those interpretations,” NRECA CEO Jim Matheson said in a statement. “By pushing to alter the limits of its jurisdiction over rates for services provided under the tariffs of MISO and SPP, FERC actions could have a chilling effect on efforts to encourage market participation by nonpublic utility transmission owners. FERC has long acknowledged co-op and municipal participation as critical to the success of RTOs.”
Matheson said RTOs should work with stakeholders to develop solutions on how to make refunds more equitable. If FERC insists on requiring refund provisions for nonpublic utilities, NRECA said, it should limit the commitments to transmission service costs and leave out revenues from “participation in other markets or services.”
Other nonpublic utilities — Hoosier Energy Rural Electric Cooperative, Sunflower Electric Power, Mid-Kansas Electric, Nebraska Public Power District and Midwest Energy — also filed initial briefs cautioning FERC against mandating refunds.
SPP and MISO: Let Stakeholder Processes Work
In their briefs, MISO and SPP asked FERC to let them seek a consensus solution in their stakeholder processes.
SPP said FERC should avoid “mandating prescriptive revisions,” saying the RTO’s staff and stakeholders are in the best position to address the “complex legal and operational issues” involved.
The RTO admitted that it has struggled with the refund discrepancy. “The disparity in refund obligations between public utility and nonpublic utility transmission owners has presented legal and administrative difficulties for SPP and other RTOs in the past. SPP welcomes the commission’s focus on this issue,” SPP wrote.
MISO similarly asked that its staff and public and nonpublic transmission owners be allowed to revise refund rules on a “consensual basis through an open process.”
The RTO said it could run into legal difficulties if FERC orders a specific Tariff revision, because it is legally bound to not only its Tariff, but also its Transmission Owners Agreement.
“To the extent the commission decides to impose any refund commitment requirements, merely directing MISO to revise its Tariff, without considering corresponding revisions to the Transmission Owners Agreement, could expose MISO to legal challenges or require it to take positions on matters that potentially could fall within the purview of its owners,” MISO said.
The RTO also said any steps FERC takes should protect MISO’s status as a revenue-neutral entity.
COLUMBUS, Ohio — PJM’s Craig Glazer opened a panel on controlling transmission project costs at last week’s annual meeting of the Organization of PJM States Inc. with a tongue-in-cheek game show: “Who Does What?”
The series of multiple-choice questions he presented highlighted the lack of clear authority throughout the transmission-development process, with state regulators, RTOs and FERC all potentially playing a role.
Who decides which of three cost-capped transmission proposals — differing on what costs are covered and what are excluded — is the best for ratepayers? Who enforces the cost cap after an award?
“There are no clear answers,” said Glazer, PJM’s vice president of federal government policy. “This is about one of the fuzziest areas we’ve got.”
That set the stage for a dialogue on transmission planning that spanned two panels and more than three hours of discussion. The first panel tiptoed around the troubled Artificial Island project to debate the advantages and challenges of cost caps. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
The second panel focused on FERC’s recent decision to investigate how supplemental projects are awarded. It pitted incumbent transmission owners against independent transmission developers and the customers who pay to use their networks in debating how receptive TOs should be to outside opinions on how to manage their assets. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
Sharon Segner of LS Power, who sat on both panels, outlined her argument in detail. She started by campaigning for FERC to issue a policy statement defining the elements of cost caps, contrasting it with nonbinding cost estimates.
Segner said cost-containment proposals must be specific about what costs are covered and what are excluded, including legal caveats. And those promises must be incorporated into the designated entity agreement and rate case to ensure enforceability, she said.
“A PowerPoint proposal, in our view, is not a cost-containment proposal. It has to be clear, and the legal language has to be clear as well,” she said. “The selection process should fairly and truly weight the cost-containment proposal.”
Jodi Moskowitz of Public Service Enterprise Group said cost caps make sense in theory but can be challenging in implementation. First, she said, the 45 days PJM has given bidders to respond to solicitations is not enough time to develop accurate cost estimates.
She also raised the issue of permitting delays, citing the Susquehanna-Roseland reliability project that PSEG built with PPL. It took four years to win National Park Service approval for a crossing through the Delaware Water Gap National Recreation Area even though it was completely within an existing right of way, she said.
“The challenges associated with these large, linear projects is intense,” she said, noting that “the cheapest project may not provide the overall best value to customers.”
She pointed out that FERC, in its acceptance of PJM’s Order 1000 compliance filing, rejected a cost-cap proposal, noting that many of the issues involved with project development are out of the developer’s control.
“Competitive transmission — we struggle with that term,” she added, questioning whether competitive developers’ designs are equal to her company’s standards. “We only have one grid.”
Josh Burkholder of Transource Energy, a joint venture of American Electric Power and Great Plains Energy, said proposals that offer both guaranteed cost caps and significant cost savings are “too good to be true.”
“This has me scratching my head, because if risks are truly transferring [from customers to the developer], you would expect there to be an associated risk premium.”
In response to that pressure, his company attempted to share the cost risks with its construction vendors, equipment manufacturers and companies acquiring rights of way.
“That process has been very, very challenging,” he said. “There are risks that our suppliers are just flat-out not interested in taking. They have plenty of work that they can do without assuming a lot of new risks.”
Including its risk premium in its Artificial Island bid made it uncompetitive, he said.
Attorney Robert Weishaar, who represents the PJM Industrial Customer Coalition, said Order 1000 “has yet to deliver tangible benefits.”
“We think FERC needs to redouble its efforts to provide clear directions to RTOs on how … to fully implement Order 1000 and deliver on its promises,” he said.
Weishaar also said FERC should eliminate rate incentives — such as those for RTO participation and independent transmission companies — in Order 1000 projects. “This is competition,” he said. “There are no regulatory incentives in competition.”
In the second panel, Exelon’s Gloria Godson and Bob Bradish of AEP passionately defended transmission owners’ authority to manage their assets without second-guessing.
“I have a good relationship with some of my neighbors. Some of them, I really don’t like the way that their doors look. I think that they should change their doors, but I have never gone over to my neighbor and said, ‘You know what? I’m going to take down your door and change it,’” Godson said. “You just don’t do that to someone else’s assets. It’s just not courteous. It’s not nice!”
“We have a set of standards,” Bradish added. “We’re certainly happy to sit and debate standards, but we don’t want someone’s opinion to substitute for 110 years of doing the work.”
He called suggestions from stakeholders on what specific components to use “not helpful.”
American Municipal Power’s Ed Tatum said the fact that his company is helping to foot the bill is what qualifies him to be part of the decision.
And he said that bill has jumped sharply in recent years. In the earlier panel, he had pointed to a transmission expansion in Jersey Central Power and Light’s territory whose costs ballooned from $22 million to $111 million once estimates had been more “fully refined,” according to the presentation at the Oct. 6 Transmission Expansion Advisory Committee meeting.
“We’re not asking to paint anybody’s door … but what we are concerned about is what’s being built and why. The reason is because we’re paying for it. If we’re paying for it … we should talk about it.”
Segner said her company is concerned the supplemental project process allows incumbent transmission owners to win projects that should be open to competition.
She also voiced concern that the Transmission Replacement Processes Senior Task Force — which has been assigned to develop rules and review processes for “end-of-life” projects — has a flawed mission and no means to repair it.
“The solution is not more PJM slides. It’s not prettier slides,” she said. “There needs to be fundamental reform in the local planning process, and that’s where the transparency needs to be.”
Earlier in the panel, PJM Vice President of Planning Steve Herling explained the RTO’s plans to restructure the TEAC to be more dynamic and communicative.
“We’re going to be putting more and more of the material out, essentially in kind of webcasts well in advance of the TEAC meeting,” he said. “Our goal is to have this material all available before we get to the TEAC or the sub-regional [Regional Transmission Expansion Plan] committees so that you can educate yourself about a particular problem, about a solution option that is out there and then engage in Q&A with PJM or with the transmission owners.”
PJM’s hopes to implement the changes by the beginning of the 2018 RTEP cycle, but enhancements will be rolled out as they are ready.
FERC on Thursday rejected PPL’s request for a finding that it is no longer covered by the commission’s Standards of Conduct rules restricting communications between its transmission and marketing functions (TS16-2).
FERC’s Standards of Conduct require transmission-function employees to operate independently from marketing staff to prevent preferential access to nonpublic transmission, customer or market information.
PPL contended that the rules should no longer apply to its PPL Electric Utilities subsidiary — a transmission owner and load-serving entity in PJM — because it spun off its competitive generation to Talen Energy last year. Thus, it said, it no longer conducts transmission transactions with an affiliate that engages in marketing functions.
But the commission ruled that PPL Electric continues to have a marketing function because it sells excess electricity in its role as provider of last resort for customers who don’t choose a competitive retail supplier.
“The fact that PPL Electric is a ‘price taker’ for the balancing sales to PJM is not relevant to the determination whether sales for resale in interstate commerce are jurisdictional activities under Section 205 of the Federal Power Act,” the commission said.
FERC said that the company could request a waiver from the standards by showing that it does not control its transmission system and has relinquished access to nonpublic transmission information.
But PPL spokesman Joe Nixon said the company will not seek a waiver. “Consequently, we will continue the training and other requirements imposed by FERC’s Standards of Conduct to wall off transmission function information from marketing functions,” he said.
FERC rejected PPL’s contention that its current operations were similar to those of Hudson Transmission Partners, which the commission exempted from the standards in a 2014 order.
Hudson Partners, which owns an 8-mile long transmission line connecting PJM and NYISO, has turned over control of the line to PJM. But unlike PPL, it does not participate in any energy markets and has not obtained authority to make wholesale sales of power, FERC said.
Wind advocates and other stakeholders predicted last week that MISO’s proposed changes to the interconnection queue process will face challenges before FERC.
The stakeholders made their comments at the Oct. 19 Planning Advisory Committee meeting, two days before MISO’s filing Friday.
Omar Martino, director of transmission strategies with EDF Renewable Energy, said the new three-phase queue could make the process even longer.
Great River Energy engineer Michael Steckelberg said the three-phase approach guarantees “built-in restudies.”
Tim Aliff, MISO’s director of reliability planning, said the majority of stakeholders preferred the three-phase queue over a shorter, two-phase queue.
Rhonda Peters, a consultant to Wind on the Wires, said more discussion could have resolved some of her clients’ concerns, such as the timing of the site control deposit. The deposit is required at the queue’s second decision point, roughly 200 days into the queue, and becomes nonrefundable if interconnection customers cannot provide a site map and proof of land-use agreements for the project area.
Aliff noted that the deposit was reduced to $100,000 from the proposed $1 million, but he said MISO would not consider wind advocates’ request to delay the deposit until projects enter the definitive planning phase.
He also said it was an exaggeration that MISO’s entire wind industry opposed the deposit timing — an unexpected response to a claim no one at the meeting had made.
Interconnection Process Task Force Chair Randy Oye pointed out that MISO worked for more than a year on the new rules.
“I think we really worked hard to address the issues,” Oye said. “Site control was a late issue; it came up late.”
Aliff said that while the proposed 460-day queue sounds long, MISO is only now getting to siting projects proposed in August 2015. “We’re already a year behind on the current process,” Aliff said.
MISO Proposes Joint Functional Control Agreement
MISO plans to file a joint functional control agreement with FERC to codify the process that would be used should it award a competitive transmission project to multiple entities in separate RTOs.
The agreement would be signed by all developers and makes clear that MISO will “maintain undivided functional control of all competitive transmission facilities associated with … project[s] once they are placed into service.”
“One RTO couldn’t do 60% of congestion management while the other does 40% control of congestion management,” explained Brian Pedersen, MISO’s senior manager of competitive transmission.
Once accepted by FERC, Pedersen said similar language will be included in MISO’s Tariff. He also said he would return in November to present any adjustments to the agreement based on stakeholder comments. MISO is eyeing a finalized agreement by February or March and said it would be filed with FERC in either the second or third quarter of 2017.
Pedersen said MISO is close to selecting a developer for the Duff-Coleman 345-kV project, its first competitive transmission project. (See 11 Developers Vie for MISO Duff-Coleman Project.)
He said after the project is awarded, he would continue to return to the PAC with project status reports and updated cost estimates. Beyond that, he said MISO would take time in the first few months of 2017 to identify possible improvements to the competitive developer selection process.
“Even though there might not be a competitive project in 2017, there’s a lot to contemplate,” Pedersen said.
After MISO announces the Duff-Coleman winner, Pedersen said he expects there are going to be 10 developers “wanting to know why they weren’t chosen.”
“In January and February, what we’re contemplating is having one-on-one meetings with the 10 entities that were not selected,” Pedersen said.
MISO is already considering changes in the minimum project requirements for competitive transmission projects. The RTO announced at Oct. 18’s Planning Subcommittee meeting that the second version of Business Practices Manual 029, which governs the requirements, will move to the PAC for approval. MISO principal adviser Matt Tackett said the BPM language will be presented and reviewed at the Nov. 16 PAC meeting. He said he anticipates final language by January with the revision implemented next spring.
“I think the general thought among stakeholders was that it was a good starting point,” Tackett said of the first version of BPM 029, which was used for Duff-Coleman. The revision includes a more detailed set of ratings that projects must meet. (See “MISO Releases Minimum Requirements for Competitive Tx Projects,” MISO Planning Subcommittee Briefs.)
PAC Could Hold IPSAC Vote Outside of Interregional Meetings
Eric Thoms, MISO manager of planning coordination and strategy, revisited the PAC to soften his stance on whether the committee sectors’ in the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) can take place outside of the interregional meetings.
Thoms said MISO is proposing holding its end of the IPSAC stakeholder vote through either conference call or email shortly after the IPSAC to give sectors time to huddle up on issues.
“A majority of the stakeholders did not support voting at the SPP-MISO IPSAC. I think people wanted sufficient time to discuss MISO’s own regional details,” Thoms said.
In August, Thoms said the PAC’s seven voting sectors should use MISO-SPP IPSAC meetings to decide the RTO’s nonbinding IPSAC vote on study approvals or whether potential interregional projects should proceed to regional review. (See “MISO to Give PAC More Consideration in Interregional Process; Stakeholders Wary of PAC Vote in IPSAC,” MISO Planning Advisory Committee Briefs.)
Thoms said MISO staff would advise the MISO-SPP Joint Planning Committee on the stakeholder preference to conduct voting outside of the IPSAC.
PAC Chair Bob McKee said voting changes should be memorialized in the committee’s charter.
Thoms added that stakeholders’ IPSAC confusion spawned in large part from FERC’s directives in the Northern Indiana Public Service Co. order (EL13-88), with stakeholders not knowing if they should attend the PAC or the MISO-PJM IPSAC to get the latest details. MISO said it noticed an increase in involvement by its stakeholders at recent MISO-PJM IPSACs.
Stakeholders also asked for increased notice, updates and follow-up on IPSAC items at the PAC and the ability for PAC sectors to present their positions in the IPSACs.
MISO said it is looking for “alternative opportunities to communicate interregional planning status,” including PAC presentations, newsletters and quarterly reports.
Long-Term Tx Study Scoped
MISO has finalized the scope of a study that will determine the RTO’s long-term transmission needs using futures from the 2017 Transmission Expansion Plan. The RTO said in addition to the MTEP 17 futures, the study will include “economic indicators” such as historically congested flowgates.
The first detailed study evaluation will take place in MISO’s Economic Planning Users Group on Nov. 11 at its Eagan, Minn., offices. (See “Long-Term Overlay Study Scoped; MISO Asks for More Responses,” MISO Planning Advisory Committee Briefs.)
Lynn Hecker, MISO manager of expansion planning, said she would revisit the PAC with five separate updates over 2017 until the study is wrapped up in December 2017.
New resources that clear ISO-NE’s Forward Capacity Auction will be able to begin supplying capacity earlier than the usual three-year lead time under a package of Tariff revisions approved by FERC last week (ER16-2451, AD16-26).
The changes are intended to enhance liquidity in the RTO’s capacity market: Resources that are completed prior to the beginning of their commitment periods would not have to sit idle until then. Under the revisions, filed by ISO-NE in August, qualified resources could participate in the RTO’s reconfiguration auctions and begin supplying capacity as soon as four months after they clear the FCA. Imports would be allowed to begin as soon as one year after the FCA.
That last provision did not sit well with NYISO, which had asked FERC to delay the revisions by one year.
The ISO said it did not object to the revisions themselves, but it worried that they would negatively affect capacity prices in its own market because of a single power plant, Castleton Commodities International’s Roseton 1. The 1,242-MW dual-fuel generator, located 43 miles north of New York City in NYISO’s capacity import-constrained G-J locality, is committed to supply about half of its capacity to ISO-NE for the 2018/19 and 2019/20 periods. Under the revisions, Roseton would be able to supply capacity beginning next June for the 2017/18 delivery year.
Roseton | Google
NYISO said this could increase costs to New York consumers by as much as $341 million. Under current ISO rules, when a resource is committed to export capacity, it is treated as if it no longer exists when the ISO runs its own, one-year forward auction. If Roseton decides to participate in ISO-NE’s 2017/18 commitment period, NYISO would procure unnecessary replacement capacity, as Roseton would still be providing reliability services for the G-J zone, the ISO argued.
Market Monitor David Patton identified the problem in his 2015 State of the Market report, recommending that NYISO act quickly to recognize the reliability value of generators in import-constrained zones to avoid a rise in capacity prices. NYISO is currently hammering out Tariff changes and hoped to file them so they were in place before the beginning of the 2018/19 period.
FERC, however, said it was “not persuaded that the potential behavior of New York suppliers provides a sufficient basis to reject ISO-NE’s filing in this case.”
“Deferring the effective date of an otherwise just and reasonable proposal would be inconsistent with the notice provision in Section 205 of the” Federal Power Act, it added.
The commission ordered NYISO to make an informational filing by Nov. 4 addressing its progress in finalizing its Tariff revisions.
FERC last week approved CAISO’s use of a natural gas price index included in temporary Tariff provisions the ISO implemented last spring in response to the closure of the Aliso Canyon storage facility (ER16-1649).
The ISO revised its index rules to ensure gas-fired generators in Southern California accurately reflect their fuel costs in the event that pipeline restrictions imposed following the loss of Aliso Canyon caused market volatility.
The California grid weathered the summer without supplies from the Aliso Canyon gas storage facility, but CAISO hopes to extend its gas restriction response plan for another year. | California Office of Emergency Services
Prior to the revision, the ISO Tariff required gas generators to base the fuel component of their day-ahead unit commitment costs on the previous day’s day-ahead gas index published by the Intercontinental Exchange (ICE).
The updated rule allows those generators to instead use a same-day index produced by ICE by 9 a.m. PT, just before the ISO’s day-ahead market run. ICE’s “official” same-day index is typically posted at 11:30 a.m.
CAISO reasoned that a shorter time lag between the publication of the index and the submission of day-ahead energy bids would reduce the likelihood that generators could lose money under unexpected tight supply conditions by gas price spikes revealed after the market run.
The commission’s June 1 order approving the Aliso Canyon response plan accepted the new index with the qualification that it must be shown to conform to FERC’s policy statement on natural gas price formation, which outlines standards for trade data reporting. (See FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer.)
In August, CAISO asked FERC to extend a previous waiver and allow it to continue using the new index provisions. While the ISO said it could not state that the index conformed with the policy statement, it noted that the volume-weighted average price ICE makes available before 9 a.m. is calculated in the same way as the official index published later in the morning.
In its decision last week, the commission agreed with the ISO’s assessment, pointing out that ICE is a FERC-approved index developer and that the new index meets the minimum threshold for trading volume.
“Based on CAISO’s representations that the volume-weighted average price is generated by ICE between 8:00 a.m. and 9:00 a.m. PT, we expect that the new index, which will include trades between 5:00 a.m. and at least 8:00 a.m. PT, will have sufficient activity to conform to the liquidity requirements of the policy statement,” the commission concluded.
Tariff provisions related to the Aliso Canyon response plan are set to expire at the end of November, but CAISO this month asked the commission to extend most the measures for an additional year. A decision on that request is pending. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)
MISO and PJM will have 65 days to evaluate the impact of generator retirements under joint operating agreement language drafted to comply with a FERC directive.
The subject of a briefing at MISO’s Reliability Subcommittee meeting last week, the JOA language requires the RTOs to notify each other of retirements and exchange the most up-to-date modeling data.
The results of the retirement impact studies and possible transmission upgrades will also be shared. Projects in one RTO that have benefits or impacts in the neighboring RTO will be evaluated by the Joint Regional Planning Committee and the Interregional Planning Stakeholder Advisory Committee (IPSAC).
Alternatives to transmission upgrades will include market-to-market coordination to use external resources, as well as operating guides and procedures involving the adjacent RTO.
| MISO
In response to a complaint by Northern Indiana Public Service Co., FERC required the RTOs to file language coordinating their generator retirement studies and dispatch assumptions by Dec. 15, 2016 (EL 13-88).
The commission cited NIPSCO’s testimony that PJM used unrealistic dispatch assumptions in its study of the retirement of the Crawford and Fisk generating plants in the Commonwealth Edison territory, “which caused PJM to fail to identify required upgrades and masked potential problems within MISO, including overloads on NIPSCO’s system.” (See FERC Orders Changes to MISO-PJM Interregional Planning.)
Joe Reddoch of MISO’s System Support Resource Planning Group said MISO focused on appropriate communication between the RTOs and reviewed its existing retirement process to make sure it was still relevant.
Reddoch commented on the 65-day deadline for evaluating retirements.
“Currently, it’s more or less open-ended. We don’t necessarily have a deadline to get back to them with study results that would factor into their retirement studies,” Reddoch said.
He added that supplying such information would be more vital to PJM, which — unlike MISO — cannot force generators to stay online as must-run resources.
Reddoch said transmission projects the RTOs identify as a result of their analyses might not be detailed or polished.
“Each RTO would conduct a retirement analysis to determine the impacts to their system and possible transmission projects. We won’t necessarily have those projects defined,” he said.
Reddoch said MISO would look to PJM’s information to update its modeling information, but directly involving PJM staff in retirement decisions would be too complex. “They won’t necessarily be involved in study scope discussions,” he said.
In comments to MISO, NIPSCO said it was generally supportive of the proposed changes, but it asked the RTOs to devise a timeline for retirement studies that is similar to MISO’s multistep interconnection queue studies. MISO responded that an interconnection format isn’t feasible because its generator retirement studies are “conducted on an ad hoc basis,” and studies can vary.
NIPSCO also asked MISO for examples of how identified transmission projects become approved under the new process. MISO said the issue would be discussed at a future IPSAC meeting.
Reddoch asked for stakeholder input by Nov. 1 and said MISO would share final JOA language at the Nov. 15 Joint and Common Market meeting with PJM.
