Transmission owners will be required to reduce their rates to reflect reduced corporate income taxes under a Notice of Proposed Rulemaking approved by FERC Thursday (RM19-5).
The NOPR is a response to the December 2017 Tax Cuts and Jobs Act, which cut maximum corporate income tax rates to 21% from 35%.
Senate Majority Leader Mitch McConnell, House Speaker Paul Ryan and Vice President Mike Pence celebrated the passage of the corporate tax cut with President Trump in November 2017. | The White House
It would require public utility transmission providers with rates under an Open Access Transmission Tariff, a transmission owner tariff or a rate schedule to modify the accumulated deferred income taxes (ADIT) incorporated in their rates. ADIT is used to account for timing differences between the computation of taxable income for reporting to the IRS and that used for regulatory accounting and ratemaking.
TOs with formula rates would be required to deduct excess ADIT from their rate bases and complete a new worksheet annually to track ADIT. Utilities with stated rates would be required to return any excess ADIT to customers.
In related actions, FERC also:
Issued a policy statement providing guidance on how other FERC-jurisdictional public utilities, natural gas pipelines and oil pipelines handle the accounting and ratemaking treatment of ADIT (PL19-2).
Approved Edison Electric Institute’s request for accounting guidance on recording a reclassification of any stranded tax effects from the law (AC18-59).
Acted on 46 of the Federal Power Act Section 206 show-cause investigations initiated in March, when the commission directed utilities whose transmission tariffs reference tax rates of 35% to reduce the rates to 21% or show why they did not need to do so.
Accepted three interstate natural gas pipeline rate reductions and one settlement in response to Order 849, which requires pipelines to provide a one-time report estimating their returns on equity before and after the new tax law and changes to the commission’s tax allowance policies. The rate reductions involved Millennium Pipeline Co. (RP19-65), North Baja Pipeline (RP19-71) and Vector Pipeline (RP19-60).
Commissioner Richard Glick said he was troubled by a clause in the settlement with Kern River Gas Transmission (RP19-55) that would undo its rate reduction if FERC initiates a rate proceeding in the future under Section 5 of the Natural Gas Act.
“In my opinion, Kern River in this settlement is essentially holding the commission hostage,” Glick said. “What I think this really highlights is the fact that the Natural Gas Act doesn’t have a refund provision like the Federal Power Act does. So, again, I want to call on Congress to add a refund provision to the Natural Gas Act which mirrors the refund provision in the Federal Power Act so that we can ensure that consumers are protected.”
Comments on the NOPR will be due 30 days after date of publication in the Federal Register.
FERC on Thursday approved NERC’s revised geomagnetic disturbance reliability standard, which broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions (RM18-8, RM15-11-003).
NERC created Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) in response to FERC’s directives to improve how its initial GMD standard, approved in 2016, addressed the risks from “locally enhanced” events. (See FERC Pushes NERC Further on GMD Rules.)
Thursday’s order (Order 851) directed NERC to revise the standard further to require the implementation of corrective action plans for responding to vulnerabilities to “supplemental” GMD events and to authorize case-by-case extensions of deadlines on corrective action plans. The commission also accepted NERC’s revised GMD research work plan.
‘Supplemental’ GMD Events
GMDs occur when the sun ejects charged particles that cause changes in Earth’s magnetic fields, potentially causing geomagnetically induced currents (GIC) that can cause voltage instability or collapse, damaging connected equipment.
NERC’s original standard required applicable entities — planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher — to assess the vulnerability of their transmission systems to a “benchmark GMD event.” The benchmark was defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity.
Entities that fail to meet certain performance requirements based on the results of the benchmark assessment must implement corrective action plans.
The new standard addresses FERC’s directive to revise the benchmark GMD event definition so that it is not based solely on the averaging of magnetometer readings over a geographic area. Going forward, entities will have to conduct vulnerability and thermal impact assessments on “supplemental” events.
NERC defined the supplemental GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability. The supplemental GMD event definition contains a higher, non-spatially averaged reference peak geoelectric field amplitude component than the benchmark event definition (12 V/km versus 8 V/km).
The new rule also requires the collection of GIC monitoring and magnetometer data and adds a one-year deadline for the completion of corrective action plans and two- and four-year deadlines for completing mitigation involving non-hardware and hardware, respectively.
GMD storm in Fairbanks, Alaska, April 2011 | NASA
Case-by-Case Review
NERC had proposed allowing entities to exceed deadlines for corrective actions when “situations beyond the control of the responsible entity [arise],” which FERC said was inconsistent with its prior directive that extensions be considered on a case-by-case basis.
“While we generally agree with the standard of review that NERC states it will use to assess the merits of extension requests, we conclude that such assessments should be made before any time extensions are permitted,” the commission said. “By requiring prior approval of extension requests, the modified reliability standard will limit the potential for unwarranted delays in implementing corrective action plans while also providing NERC with an advance and more holistic understanding of where, to whom and for how long extensions are granted.”
Additional Directives
FERC said NERC did not go far enough in the revised standard, which requires entities to assess supplemental GMD event vulnerabilities but not to implement corrective action plans to address them. NERC would have required entities only to make “an evaluation of possible actions to reduce the likelihood or mitigate the consequences and adverse impacts of the events if a supplemental GMD event is assessed to result in cascading.”
FERC disagreed with commenters who said requiring corrective action plans is premature. “We see no basis, technical or otherwise, for not requiring corrective action plans for assessed supplemental GMD event vulnerabilities,” the commission said.
The rule is effective 60 days after publication in the Federal Register.
CAISO cleared a big hurdle in its nearly yearlong sprint to become the primary reliability coordinator (RC) in the Western Interconnection as FERC approved a set of Tariff revisions covering the ISO’s new services.
“Today we’ve got some good news from FERC in terms of our ability to move forward,” CAISO Regional Integration Director Phil Pettingill told a meeting of the ISO’s Board of Governors after the order was issued Wednesday.
Pettingill said the FERC order will allow the ISO to start signing binding agreements to provide RC services with two dozen entities across the Western Interconnection. About 72% of the region’s load is now poised to sign on with CAISO, compared with 12% for SPP. BC Hydro is proceeding with plans to stand up RC services for its own territory in British Columbia, representing about 7% of load in the area overseen by the Western Electricity Coordinating Council. (See CAISO RC Wins Most of the West.)
The Tariff revisons approved by FERC create a new section containing CAISO’s RC provisions while also providing a pro forma service agreement and designating a rate schedule to implement service charges (ER18-2366). The commission’s approval of the service agreement means CAISO can begin onboarding RC customers starting Thursday.
CAISO’s filing spelled out the functions applicable to an RC under NERC reliability standards, including providing outage coordination; performing operations planning analyses; conducting real-time assessments; monitoring and wide-area situational awareness; administering a system operating limit methodology; approving system restoration plans and facilitating system restoration drills; and issuing operating instructions to RC customers regarding their monitored facilities.
CAISO will also offer optional services such as hosted advanced network applications for a one-time charge of $35,000 to $70,000 (depending on the number of takers) and physical security reviews.
CAISO will shadow Peak Reliability as it readies to take over RC services in much of the West by the end of 2019. | CAISO
In approving CAISO’s RC provisions, FERC rejected protests by some market participants over the ISO’s proposal to assess volumetric service charges on generation-only balancing authorities.
The protesters, which include Avangrid, Calpine and Gridforce Energy Management, contended that the ISO’s charge, which will be based on annual net generation (NG) rather than net energy for load (NEL), deviates from commission precedent for allocating reliability-associated costs. They argue that an NG-based methodology is unjust and unreasonable because it double charges end users for energy produced in generation-only balancing areas. Peak Reliability currently charges such BAs based on NEL, which translates into minimum assessment rather than a volumetric charge.
“In effect, protesters argue that CAISO will assess a transaction that is sourced from a generation-only balancing authority reliability costs both for its exports from a generation-only balancing authority and its imports to a traditional balancing authority,” the commission noted.
The protesters further contended the NG methodology violates cost-causation principles because generation-only BAs require less RC service than BAs with load. They said CAISO had performed no analysis on the relative level of oversight costs for either type of BA.
But FERC sided with CAISO on the issue, saying neither the Federal Power Act nor commission precedent dictate a just and reasonable rate methodology for RC service. The commission also determined that CAISO’s proposed allocation methodology will not result in double-charging.
The commission also rejected the contention the ISO’s approach violates cost-causation principles, noting that none of the protesters argued that generation-only BAs do not require or benefit from RC services.
“Rather, protesters assert that CAISO has not justified charging them a rate that they assert will be significantly higher than the rate charged by Peak Reliability,” the commission wrote. “Moreover, protesters argue that the RC services required for generation-only balancing authorities are substantially less burdensome as compared to those of a traditional balancing authority with load. CAISO, however, specifically identifies core services that an RC provides and explains that traditional balancing authorities and generation-only balancing authorities all use the vast majority of these core services.”
While FERC’s decision is significant, CAISO’s RC effort is still subject to WECC and NERC certification next year. Still, CAISO is poised to lead the way in effort to fill the void being left by Peak.
Pettingill told Wednesday’s board meeting that the ISO had been holding roundtable meetings with SPP, the Alberta Electric System Operator, BC Hydro and Peak to coordinate the transition to a post-Peak West. When the question arose as to who will manage the Western system model, he said, roundtable participants decided it should be CAISO.
The ISO also intends to hold a series of public meetings to address concerns, either quarterly or “as many as needed,” he said.
FERC has accepted CAISO’s revised proposal to protect electricity ratepayers from funding shortfalls in the ISO’s congestion revenue rights market.
CRR holders will be paid for their entitlements “only to the extent the CAISO collects sufficient revenue through day-ahead market congestion revenues and other sources to fund those entitlements,” the commission said in its Nov. 9 decision (ER19-26).
“We agree with CAISO that the proposal reasonably distributes the burden resulting from congestion revenue insufficiency and will help improve the revenue insufficiency and auction revenue shortfall,” FERC said. “Rather than relying solely on LSEs to make whole CRR holders in the event those obligations are revenue insufficient, CAISO’s proposal distributes the burden to all CRR holders.”
CAISO filed its proposed revisions Oct. 1 after FERC rejected an earlier plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges. In rejecting the earlier plan, the commission objected to how the ISO would treat counterflow and prevailing-flow CRRs differently (ER18-2034). (See CAISO Modifies CRR Plan, Seeks Quick Approval.)
The ISO acknowledged that its revised proposal relies on “essentially the same methodology” found in its prior proposal, with one “important” modification: a provision to net CRRs with both prevailing-flow and counterflow CRRs within a holder’s portfolio before scaling the payment to that holder.
CAISO said the trend of CRR revenue insufficiency has persisted into this year despite a recent uptick in congestion rents because of unusually high flow patterns. | CAISO
CAISO also noted in its revised filing that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019. The ISO’s Department of Market Monitoring has estimated that the shortfalls — which are allocated based on power consumption — cost California ratepayers about $100 million a year.
In ruling for CAISO, the commission rejected protests by the Western Power Trading Forum, which argued that the ISO’s stakeholder process on the revisions had been rushed and that they did not fully address FERC’s concerns on symmetry.
The commission also found that CAISO’s plan would curtail a commonly used strategy to exploit market loopholes.
“CAISO’s constraint-specific approach … discourages strategies that attempt to exploit differences between the CRR model and the day-ahead market,” it said. “Under CAISO’s current CRR process, congestion revenue insufficiency and the auction revenue shortfall can be driven by market participants purchasing CRRs over constraints that appear to be nonbinding in the CRR auction but are actually binding in the day-ahead market.
“According to CAISO’s analysis, this practice has been a driver of both revenue insufficiency and the auction revenue shortfall. Under CAISO’s proposal here, if there is a substantial difference between the CRR model and the day-ahead market such that the payments due to CRR holders vastly outstrip the available congestion revenues, then payments to CRRs will be scaled, making the strategy potentially less viable.”
FERC clarified Tuesday that rehearing requests on its April 19 order revising its pro forma large generator interconnection procedures did not affect transmission operators’ compliance obligations spelled out in the order (RM17-8-002).
The order required transmission providers to submit compliance filings adopting the rule’s requirements as revisions to their large generator interconnection procedures (LGIP) and large generator interconnection agreements (LGIA) within 90 days of the publication.
Blue Canyon wind farm | EDP Renewables
On June 18, however, the commission issued a procedural order giving itself more time to consider about 20 rehearing requests on the rulemaking. On Oct. 3, the Office of the Secretary issued a notice granting a motion by the Edison Electric Institute to delay the compliance filings until 90 days after the commission rules on rehearing.
The American Wind Energy Association challenged the secretary’s notice, arguing that extending the deadline for compliance filings was a departure from commission precedent that rehearing requests do not stay commission orders. AWEA said the extension notice effectively stays Order 845 “indefinitely until a rehearing request is issued.”
But the commission said the extension notice “does not change or stay Order No. 845’s effective date, but simply extends the date that compliance filings are due.”
Order 845 adopted all but four of 14 potential rule changes in the commission’s December 2016 Notice of Proposed Rulemaking revising the pro forma LGIP and LGIA. The rulemaking, which was prompted by AWEA’s complaint over backlogs in interconnection queues, applies to generators larger than 20 MW.
Pinnacle West Capital is poised to move forward with its own clean energy plans after Arizona voters rejected Proposition 127, the company’s CEO said during a third-quarter earnings call.
The ballot measure, backed by California billionaire Tom Steyer, would have required the state’s power providers to generate at least half their annual sales of electricity from renewable resources by 2030.
Pinnacle and its subsidiary Arizona Public Service, the state’s largest utility, fought the measure. The opposing sides spent a combined total of more than $50 million in the race. In the end, state voters rejected Proposition 127 by roughly 70% to 30% of votes cast. (See High Failure Rate for Western Ballot Measures.)
“The residents of Arizona voted overwhelmingly to defeat Proposition 127, ensuring the energy policy in Arizona will continue to evolve in a thoughtful and constructive manner,” Pinnacle CEO Don Brandt told analysts on the Nov. 8 call. “With Proposition 127 behind us, we can now work with stakeholders to establish forward-thinking energy policies that move towards an increasingly clean energy mix.”
The Palo Verde nuclear plant in the Arizona desert is partly owned by Pinnacle West subsidiary Arizona Public Service. | Nuclear Regulatory Commission.
Those plans include taking advantage of Arizona’s ample sunlight for solar power, he said, and continuing to champion the carbon-free electricity produced by the Palo Verde Generating Station in the Arizona desert, the nation’s largest nuclear plant.
“Arizona is number three nationally in solar energy installed, and our APS energy mix is already 50% clean,” Brandt said. “We’re on the cutting-edge of advanced battery storage technology. Arizona is uniquely positioned to achieve a cleaner energy mix with our abundant solar resource, leadership in advanced technologies and Palo Verde generating station, the largest clean energy generator in the nation.”
The company reported third-quarter 2018 earnings of $315 million ($2.80/share), compared with 2017 Q3 earnings of $276 million ($2.46/share).
In a news release, the company said the increased earnings were driven largely by the second-hottest summer on record in Arizona and a corresponding increase in retail sales.
“The average high temperature for this year’s third quarter was 105.3 degrees — 1.6% higher than last year’s quarter and 1.2% greater than normal based on a rolling 10-year average. The resulting impact in the 2018 third quarter was that residential cooling degree-days (a measure of the effects of weather) were 13% higher than in the same 2017 period and 5.4% above 10-year historical averages,” the company said in its statement.
ORLANDO, Fla. — MISO, SPP and their stakeholders have been flummoxed in recent years by market coordination, interregional planning and other issues across the grid operators’ seam. Now, the regulators are stepping in.
On Sunday, state regulators from MISO’s Organization of MISO States and SPP’s Regional State Committee met with staff from both RTOs and other interested stakeholders on the sidelines of the annual meeting of the National Association of Regulatory Utility Commissioners.
Two of the more interested participants were FERC Commissioner Cheryl LaFleur and Iowa Utilities Board Member Nick Wagner, NARUC’s newly installed president.
FERC’s Cheryl LaFleur, Missouri’s Daniel Hall and Kansas’ Shari Feist Albrecht | FERC Commissioner Cheryl LaFleur
“This is a terrific opportunity to spend time face to face, talking about these things, given the length and complexity of the seam between the two,” LaFleur said. “It’s a tremendous opportunity to do things better in both respective market operations, as well as transmission and reliability operations on the seam, all to the benefit of the customers.”
LaFleur praised the two committees and their engagement with their RTOs. “It’s only logical these would be the two groups best to engage and put your heads together on the issues between the seams,” she said.
Wagner, whose state falls within MISO, told RTO Insider he was looking out for Iowa consumers and wants to ensure inefficiencies on the seam “are not costing consumers more than they should be.”
“We’ve seen issues on other seams. It’s not a novel issue,” Wagner said, referring to the PJM-MISO seam.
MISO and SPP have been unable to agree on a single interregional project, and their market-to-market (M2M) process has resulted in more than $51 million in payments from MISO to SPP since March 2015, compensation for overloaded transmission elements. In January and September of this year, extreme weather events created emergency situations on MISO’s side of the seam. (See 3-Degree Forecast Error Triggered MISO September Emergency.)
Missouri Public Service Commissioner Daniel Hall, who chaired the OMS-RSC liaison committee meeting, told MISO and SPP staff, “Anytime we can get the two of you working together, that’s a good thing.”
Hall represents the OMS on the committee along with Louisiana’s Lambert Boissiere, North Dakota’s Julie Fedorchak and Minnesota’s Matt Schuerger. Kansas’ Shari Feist Albrecht, South Dakota’s Kristie Fiegen, Arkansas’ Kim O’Guinn and Texas’ DeAnn Walker represent the RSC. Wagner is an ex officio member.
“There’s value in shining a light on these seams issues and ongoing efforts to address them,” Hall said. “This is an excellent forum where we can identify issues [and] work collaboratively with MISO and SPP and other stakeholders to find solutions and track the progress.”
“I know there’s a role for FERC,” LaFleur said. “I do think there is some comparability between what’s happening on the SPP-MISO seam and what happened between PJM and MISO 20 years ago. Though it’s a lovefest now, it was very contentious at one point.”
The liaison committee — “or task force, or whatever we’re calling ourselves,” Hall said — reviewed a draft white paper it had requested from MISO and SPP staff. Working with regulatory staffers, the grid operators were to identify barriers to more efficient seams operations and transmission planning, offering solutions whenever possible.
Calling the white paper a “foundational document,” Hall said he expects to request additional information from MISO and SPP and solicit stakeholder comments.
The white paper itself will eventually be made public, although the committee is uncertain how it will do so. Both the OMS and RSC have created web pages for the group.
Adam McKinnie, a Missouri PSC economist who works with both committees, framed the white paper as a means of better understanding the dynamics of issues on the seam. He said its strength was in discussing the history behind previous interregional planning efforts, improvements to the M2M process, contract path capacity sharing and flowgate allocation.
Citing the complexity involved, McKinnie said the white paper doesn’t address pancake rates, conditional generator interconnection agreements and the grid operators’ 2015 settlement agreement on MISO’s North-South flows. (See FERC OKs MISO-SPP Transmission Settlement.)
Smoke Signal
Asked whether the M2M payments are a symptom of inefficiency, McKinnie said, “These payments are definitely smoke. They are sending signals that there are issues in the area.”
The M2M process determines which party has exceeded its allowed usage of an overloaded transmission element. The grid operator over its allotment is required to find a solution that relieves the congestion.
“If MISO is paying SPP, it’s because it’s cheaper than a transmission solution,” McKinnie said.
The usage allotment is based on metrics that date back to 2004. Staff agreed the process needs to be updated, but the RTOs continue to negotiate how to revise the allotment.
The grid operators also face a 2020 renegotiation of their joint operating agreement, in place since 2004. The JOA has been amended “many times” since then, McKinnie said, including implementation of the M2M payments and a FERC Order 1000 compliance filing. The grid operators also have a memorandum of understanding that guides the M2M process.
Noting MISO and SPP take different positions on fundamental ideas and Tariff and contract interpretations, McKinnie told Hall he thinks the RTOs are “doing a decent job of being focused on the right issues.”
“There seems to be some talking past each other,” Schuerger pointed out.
“We have worked to close the gap,” said Melissa Seymour, MISO’s executive director of customer and state affairs for the Central region.
Seymour pointed to the “significant amount of time” MISO staff have spent with SPP in preventing another occurrence of the January event, when severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers across SPP’s system between its northern and southern footprints.
When MISO was forced to declare a maximum generation alert in September, the grid operators agreed communications across the seams was improved.
“We’ve been meeting on a monthly, sometimes weekly, basis with SPP,” Seymour said. “I think camaraderie is better as a result of that September event.”
“They don’t do a good job of telling their story,” McKinnie said.
SPP Director of Regulatory Policy Sam Loudenslager agreed. “We don’t publicize the positive events like we probably could.”
Sempra Energy is on track to sell its renewable energy assets and invest the funds elsewhere, including in liquefied natural gas projects, the company said in its third-quarter earnings call.
“LNG is a key component of Sempra’s vision of becoming North America’s premier energy infrastructure company,” Sempra said during its slide presentation accompanying the earnings call Nov. 7.
Sempra, headquartered in San Diego, reported third-quarter earnings of $274 million ($0.99/share), up from $57 million ($0.22/share) in the third quarter of 2017. The company’s Q3 2017 earnings were hobbled by the wildfire costs of its subsidiary San Diego Gas & Electric. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.)
Sempra has been moving away from commodities and putting its money into infrastructure.
In September, the company announced it was selling its interest in 980 MW of resources — 11 solar assets across the Southwest, solar and battery storage development projects and a wind facility in Nebraska — to Consolidated Edison.
Sempra is also investing in transmission and distribution infrastructure in Texas.
In October, Sempra said its Oncor utility subsidiary would acquire transmission owner InfraREIT, while Sempra will buy a 50% stake in Sharyland Utilities. (See Sempra, Oncor Deals Target Texas Transmission.)
“Our agreement to sell our U.S. solar assets is important. We expect to utilize capital from our solar asset sales to significantly expand our regulated Texas utility platform through Oncor’s acquisition of InfraREIT and our acquisition of a 50-percent interest in Sharyland,” Martin said in a Q3 earnings news release.
“We also have made significant progress toward our goal of becoming a market leader in North American liquefied natural gas (LNG) exports, recently securing preliminary commercial agreements for development of several LNG export projects.”
MISO officials say they will follow through on most recommendations in its Independent Market Monitor’s 2017 State of the Market report, although a few suggestions will require more investigation before the RTO can commit to solutions.
“At the highest level, MISO generally agrees with the issues laid out in the report … but we do believe there’s additional evaluation required on three of the recommendations,” Executive Director of Market Development Jeff Bladen told the Market Subcommittee during its Nov. 8 meeting.
Issued in June, Monitor David Patton’s report called for MISO to make seven improvements to its markets. (See 7 New Recommendations from MISO IMM.)
MISO will provide a more detailed presentation of its response to its Board of Directors on Dec. 4.
In an October memo to the board’s Markets Committee, MISO said it plans to work with the Monitor to include the impact of negative prices in its market power mitigation rules next year. The RTO also noted that it agrees that it should design clearer commitment classifications for operators and create a process to correct classification errors in determining make-whole payments, though it said that project is low-priority and might get a budget line in 2020.
Two recommendations — a 15-minute day-ahead market and better operator logging tools to describe decisions and actions — could possibly be added to the scope of MISO’s market platform replacement.
“MISO agrees that a more granular day-ahead market would likely deliver some reliability and efficiency benefits through improved unit commitment and scheduling, reduced uplift, and more effective procurement of required system capabilities including ramping,” MISO said, noting that the evaluation of intra-hour day-ahead market is included in a draft of business requirements for the new platform.
Bladen said that some of this year’s State of the Market recommendations are “intrinsically tied” to the new platform.
MISO-PJM CTS
The Monitor also recommended that MISO remove transmission charges from coordinated transaction scheduling (CTS) transfers with PJM, but MISO thinks a more comprehensive reworking of CTS might yield better results.
Dustin Grethen of MISO’s market design team said the RTO is currently investigating its own price forecasting and other fees before simply adopting the Monitor’s solution.
MISO and PJM launched CTS last October to allow market participants to schedule economic transmission transactions based on forecasted energy prices. While CTS had the potential to lower the cost of serving load in both regions, it has rarely been used since mid-February because MISO has been applying transmission reservation fees to the transactions both when they are offered and scheduled — a double charge.
On Thursday, MISO acknowledged that “CTS isn’t producing material benefits and is unlikely to do so without significant changes.”
Grethen said CTS activity peaked last November, averaging 5 MW per 15-minute interval.
“It’s trailed off to basically zero,” Grethen said. “There really aren’t benefits being realized from the CTS process because the offers have dried up. I think in the last couple of months we’ve only had three unique bidders.”
MISO charges about 90 cents/MWh for reservations to the PJM seam, while PJM charges about 83 cents/MWh. MISO also charges cleared CTS exports an extra $1.70/MWh in a multi-value project transmission fee, and PJM allocates uplift charges to CTS.
Grethen called the fees a “pretty significant disincentive.”
“Any of these fees can affect traders’ revenue and profitability,” he said.
Grethen also said the fees CTS traders incur when their offers don’t clear lead to subsequent higher offers so traders can recoup lost revenue from unsuccessful offers. He also pointed out that both RTOs offer “essentially free” hourly spot-in transmission service.
MISO could also improve its LMP forecasting in the CTS engine for the MISO-PJM common interface, Grethen said. Since June, the CTS engine has forecast prices about 30% below the actual LMP and it remains unclear why.
Capacity Auction Recommendations
MISO is receptive to two recommendations related to its annual Planning Resource Auction, though it said one needs further work.
The Monitor has advised MISO to require the installed capacity of planning resources to be deliverable over the transmission network. While the Tariff already requires all resources to be deliverable to load to qualify as capacity resources, the Monitor says MISO’s deliverability requirements are too relaxed because resources with energy resource interconnection service (ERIS) must only secure firm transmission for its unforced capacity values, which tend to be about 5 to 10% below full installed capacity levels.
IMM staffer Michael Chiasson said it’s problematic that MISO’s loss-of-load expectation (LOLE) study assumes that all installed capacity megawatts are deliverable when they’re not.
“That’s really a disconnect between the LOLE and the deliverability,” Chiasson said during a Nov. 7 Resource Adequacy Subcommittee meeting.
Laura Rauch, MISO director of resource adequacy coordination, said the RTO will likely adopt the Monitor’s suggestion, but it must first address additional details that would allow it to apply the rule to intermittent resources.
“We’re going to have some discussions with stakeholders and see what we can do for the 2020/21 PRA,” Rauch said.
MISO does not yet have a timeline for the Monitor’s other recommendation to create unique capacity credits in the PRA for emergency-only resources, though Rauch said the RTO will likely address that as part of its bigger initiative on resource availability and need (RAN).
“We are looking for solutions in the RAN process,” Rauch told stakeholders. She said MISO will finalize a timeline later this year and suggest changes on capacity accreditation in 2019.
Market Improvements Wait on New Platform
The Monitor’s report also emphasized a three-year-old recommendation to allow day-ahead committed peaking resources to set prices in MISO’s extended locational marginal pricing (ELMP).
Bladen said that while MISO agrees with the 2015 recommendation to expand ELMP, it must research the impact of the change on its outgoing market platform.
“The Market Monitor believes this could be done by changing a few lines of code, but our platform is of a vintage where changing a few lines of code impacts the entirety of the system,” Bladen said.
Bladen said MISO has arrived at “the raw judgment” that it should move ahead with the new platform while some market improvements wait in the wings, including plans to create a 30-minute capacity reserve product. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
“At this stage, the potential of a new platform delay is too great,” Bladen said. “There are meaningful performance issues, and cyber risks are increasing every day.”
MISO expects the first components of the new platform to be operational in 2021, with complete swap-out by 2023.
“It’s not a forklift replacement. It’s a component-by-component replacement,” Bladen said.
PJM’s Independent Market Monitor remains unconvinced that performance metrics during localized load sheds should be used to calculate capacity market default offer caps.
Among the new recommendations in the Monitor’s quarterly State of the Market report released last week was that PJM’s capacity market default offer cap not include balancing ratios calculated for localized performance assessment intervals (PAIs) but only use PAIs triggered on at least a sub-zonal or zonal level.
The recommendation could signal the re-emergence of a fight to revise how PJM calculates balancing ratios, which went on throughout the year. At the October Members Committee meeting, stakeholders declined by the slimmest of margins endorsement of proposed Tariff revisions that would change how the RTO estimates the expected future balancing ratio used in the default market seller offer cap. That leaves PJM using its current method, which requires PAIs to perform the calculation, but the RTO hadn’t experienced any such events until this year. Though both events were very localized, PJM staff assured stakeholders they could be used for calculating the balancing ratio.
The Monitor wasn’t so sure and warned at the time that it would revisit the issue. (See “Market Seller Offer Cap Balancing Ratio,” PJM MRC/MC Briefs: Oct. 25, 2018.)
The other new recommendations included:
PJM should better define its rules for unit-specific parameter adjustments “to ensure market sellers know the requirements.”
Generators should have to request use of inflexible sell-offer segments, which should only be permitted for defined physical reasons.
The $7.50 margin in the definition of the cost of Tier 2 synchronized reserves should be removed because it’s “a markup and not a cost.”
In the calculation of the penalty for a Tier 2 resource failing to meet its scheduled obligation during a spinning event, the actual number of days since the last event greater than 10 minutes should be used instead of the average number of days between events.
Aggregation should not be permitted to offset unit-specific penalties for failing to respond to a synchronized reserve event.
Offers in the day-ahead scheduling reserve (DASR) market should be based on opportunity cost only to eliminate market power, and payments for reactive capability should be based on the 0.9 power factor that PJM has determined is necessary.
PJM should re-evaluate the rules governing cost-benefit analysis and cost-allocation for economic projects in its planning for generation and transmission.
The Monitor also reiterated its concern with PJM’s capacity market, giving all of the RTO’s other markets a passing grade — with caveats — for the nine months from January through September.
Resilient Grid, Resilient Market
The Monitor noted that the structure of the capacity market is not competitive because, for almost all auctions held since 2007, the results have failed the Monitor’s three-pivotal-supplier (TPS) test both within all load delivery areas and PJM-wide. The TPS test measures the degree to which the supply from three suppliers is required in order to meet the demand in a specified market.
“The outcome of the 2021/2022 [Reliability Pricing Model] Base Residual Auction was not competitive as a result of participant behavior which was not competitive, specifically offers which exceeded the competitive level,” the report said, noting that several aspects of the RPM “still threaten competitive outcomes.”
The Monitor listed replacement capacity, unit offer parameters, allowing imports to substitute for internal resources, the default offer cap and allowing demand response to substitute for capacity as ways to improve competitiveness across PJM markets.
The Monitor said energy market results were competitive, though the RTO-wide market structure was not competitive every day, and the local market structure wasn’t competitive because of “highly concentrated ownership of supply in local markets created by transmission constraints and local reliability issues.”
The synchronized reserve, DASR and regulation market results were competitive, though the Monitor criticized all three markets for also having high ownership concentrations. “A significant portion” of day-ahead scheduling offers also “reflected economic withholding,” the Monitor concluded. The regulation market design is flawed, the Monitor said, because it continues to use an incorrect definition of opportunity cost.
The financial transmission rights auction market results were competitive, though its design is also flawed, the Monitor said, because auction revenue rights are not defined clearly enough and therefore “holders cannot determine the price at which they are willing to sell rights to congestion revenue.”
“The wholesale power grid is clearly resilient. The focus should be on ensuring that ongoing challenges to resilience are analyzed and addressed within a market framework. The real resilience question is whether the market construct itself is resilient. Can markets, and the market-based regulatory construct, coexist with efforts to increase the role of renewable resources through nonmarket revenue?” the Monitor wrote. “The solution must recognize that states have authority over generation and can choose to reregulate at any time.”
However, state policies are also harming markets, the Monitor said.
“Subsidies to specific resources that are uneconomic as a result of competition are an effort to reverse market outcomes with no commitment to a regulatory model and no attempt to mitigate negative impacts on competition. The unit-specific subsidy model is inconsistent with the PJM market design and inconsistent with the market paradigm and constitutes a significant threat to both,” the Monitor wrote.
The Monitor said the Sustainable Market Rule (SMR) it has proposed will “harmonize” the “three salient structural elements: state nonmarket revenues for renewable energy; a significant level of generation resources subject to cost of service regulation; and the structure and performance of the existing market-based generation fleet.”
“Harmonizing means that the integrity of each paradigm is maintained and respected. Harmonizing permits nonmarket resources to have an unlimited impact on energy markets and energy prices. Harmonizing means designing a capacity market to account for these energy market impacts, clearly limiting the impact of nonmarket revenues on the capacity market and ensuring competitive outcomes in the capacity market and thus in the entire market,” the Monitor wrote. “The expected impact of the SMR design on the offers and clearing of renewable resources and nuclear plants would be from zero to insignificant. The competitive offers of renewables, based on the net ACR [avoidable cost rate] of current technologies, are likely to clear in the capacity market. The competitive offers of nuclear plants, based on net ACR, are likely to clear in the capacity market.”
