CARMEL, Ind. — MISO is proposing to eliminate a footprint-wide postage stamp rate and change its rules for market efficiency projects to include regional cost allocation for transmission projects under 345 kV.
The RTO wants to lower its cost allocation threshold to cover 230-kV projects, a move that Director of Strategy Jesse Moser said will capture a reality in the footprint, where 230-kV lines are prevalent and transport a high volume of electricity.
Speaking at a Feb. 13 Organization of MISO States (OMS) board meeting, Moser pointed out that certain parts of the RTO operate at a maximum 230-kV rating, especially in MISO South. That voltage represents a “sweet spot for effective mitigation of congestion,” according to MISO.
“This puts essentially the whole footprint on an equal playing field in terms of getting a cost-shared project approved,” Moser said.
Postage Stamp Removal
MISO is also recommending that it scrap its footprint-wide postage stamp rate for market efficiency projects. The RTO currently allocates 80% of project costs to local resource zones based on expected benefits and recovers the other 20% via postage stamp allocation to all regional load. Instead, MISO wants to assign all costs to benefiting transmission pricing zones and work with stakeholders to create more specific benefit metrics. The move will make for “more granular, more targeted cost allocation,” Moser said.
MISO currently relies on the postage stamp rate as a means of recognizing both transmission benefits not currently quantified within its cost allocation and the changing nature of beneficiaries as the fleet evolves.
Currently, there is no regional cost allocation within MISO for transmission projects below 345 kV, and Minnesota Public Utilities Commission staff member Hwikwon Ham said if it were to abolish its postage stamp rate, it should detail a much more precise set of valued benefits.
In adding new benefit metrics for cost allocation, Moser said MISO may consider aspects such as deferred reliability projects and savings that could arise from opening up the contract flow path with SPP that bridges MISO South and Midwest.
“The benefit metrics discussion will continue,” Moser promised state regulators.
Wind on the Wires’ Natalie McIntire asked MISO to devise a benefit metric for projects that facilitate state renewable portfolio standards.
The RTO will also consider creating smaller transmission cost allocation zones for a more targeted cost allocation and will hold discussions with stakeholders, Moser said.
However, MISO will leave some market efficiency project requirements untouched, including the benefit-based allocation to all zones, a required benefit-to-cost ratio of at least 1.25:1 and the $5 million minimum project cost threshold.
The proposed changes would not apply to multi-value projects. Moser said stakeholders offered “a lukewarm response” to any possible changes to those projects.
MISO is seeking to draft a nearly final allocation proposal by June, with a FERC filing to follow in September or October. It hopes to get approval by the end of the year and introduce the new allocation in early 2019.
Entergy’s integration transition period, which limits cost sharing in MISO South, expires at the end of this year. The RTO has not revised its cost allocation rules since the integration of South in 2013.
‘Something You All Can Live With’
“We’re certainly zeroing in on some specific reforms,” Moser told stakeholders at a Feb. 15 Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting. “We really tried to find areas where we could get broad support. We hope the overall package is something you all can live with.”
Xcel Energy’s Carolyn Wetterlin, chair of the RECBWG, reminded stakeholders that no allocation proposal will satisfy every stakeholder’s wish list.
“We’re getting into that phase where we really have to think about what we’re solid on and where we could give a little as we move toward a filing,” Wetterlin said.
Some stakeholders at the meeting asked for MISO to consider lowering the threshold further to 100 kV, given that some 100-kV projects are needed for reliability and provide economic benefits. Others pointed out that two years ago, FERC ordered a 100-kV minimum threshold for interregional market efficiency projects with PJM. But MISO has yet to propose a regional cost allocation for interregional economic projects down to 100 kV on the PJM seam.
MISO itself originally considered a 100-kV cost allocation threshold for market efficiency projects in a draft proposal issued last year.
Moser said 100-kV lines with solid business cases will still be eligible for local cost allocation, but the RTO prefers that costs for such low-voltage projects are not shared footprint-wide.
“We looked at all the perspectives we heard over the last year, and we view the 230-kV threshold as a reasonable compromise,” Moser added.
Since Entergy’s integration into MISO, the RTO has approved two 230-kV projects in MISO South that qualified under the “economic other” category, which are only eligible for recovery in zonal rates.
Other stakeholders argued for MISO keeping the 345-kV status quo, with one stakeholder saying lower voltage “Band-Aid projects” with limited footprint-wide benefits should not be allocated like higher-voltage “backbone” projects.
Last September, MISO Vice President of System Planning Jennifer Curran told the Board of Directors that the RTO anticipated a range of opinions among stakeholders on cost allocation approaches.
“It’s not surprising that we’ve heard a very large number of opinions,” Curran said at the time. “The one thing that holds true is that when MISO recommends transmission, we have to have a good, strong business case. We can’t recommend things that we don’t think will get passed.”
MISO will continue the cost allocation discussion with stakeholders at the March 15 RECBWG meeting.
ISO-NE is asking distribution utilities in the region to adopt interim ride-through requirements for solar PV inverters that it developed with Massachusetts stakeholders, the RTO told its Planning Advisory Committee on Wednesday.
The RTO said it needs to ensure solar PV generation can remain stable during voltage and frequency excursions because of its rapid growth in the region. The RTO’s 2014 forecast predicted about 1,750 MW of solar by 2022. By 2016, however, the RTO had almost 2,000 MW, and the 2017 forecast predicts 4,000 MW by 2022. Massachusetts, home to 60% of the RTO’s solar resources, is expected to double its PV capacity in the next decade.
| ISO-NE
The new rules are laid out in a source requirement document (SRD) ISO-NE developed with the Massachusetts Technical Standards Review Group, which includes representatives from developers, manufacturers, state regulators and utilities Eversource Energy and National Grid.
The SRD requires that solar inverters have voltage and frequency trip settings and ride-through capabilities and be certified under UL 1741 SA, the safety standard for inverters and interconnection system equipment used in distributed energy resources.
ISO-NE’s David Forrest said the SRD represents an effort to balance transmission and distribution system needs. “Ideally, we’d like DER to ride through any of these faults on the transmission system, [but] … we also have to look at issues on the distribution system,” he said. “So what the ISO is proposing is kind of a compromise between meeting the transmission needs and meeting the distribution needs.”
In Massachusetts, inverter-based solar PV projects greater than 100 kW will be subject to the new rules for interconnection applications submitted on or after March 1. Projects of 100 kW or less will be subject to the rule on June 1.
The RTO hopes utilities in all states will adopt the SRD, saying having one set of requirements for the region will minimize developers’ costs and simplify the modeling of DER in planning studies.
National Grid will require it in Rhode Island, and United Illuminating and National Grid are “looking at implementing the requirements” in Connecticut, Forrest said.
The Energy Policy Act of 2005 requires electric utilities to provide interconnection services based on the Institute of Electrical and Electronics Engineers’ (IEEE) Standard 1547 (Interconnecting Distributed Resources with Electric Power Systems).
ISO-NE said the SRD is “consistent with” Standard 1547 and can be met by all inverters certified under UL 1741 SA. “The key here is that we know that inverters meeting UL 1747 SA are available,” said Forrest.
The RTO sought interim rules while IEEE completes its work on a revised Standard 1547, he said. The institute hopes to complete Standard 1547.1 by late this year or early 2019. Once the revised standard is approved, UL 1741 SA will need to be updated to agree with the revisions, and it will take a year or longer for all inverter manufacturers to have their inverters tested and certified by safety company UL.
As a result, the RTO said it will be 2020 or later before utilities will be able to require use of the revised standard.
The SRD does not cover inverters for fuel cells, traditional generators or energy storage, although they may be covered in the future, Forrest said. “Down the road we may have to look at electric vehicles,” he added. “This isn’t a topic that is going to go away.”
“There haven’t been any significant economic and policy changes. We can tweak and refresh these [2018] futures and adapt them for MTEP 19,” MISO Planning Manager Tony Hunziker told stakeholders at a Feb. 14 Planning Advisory Committee meeting.
Hunziker said MISO planners found the Trump administration’s plan to pull the U.S. out of the Paris Agreement on climate change will do little to disrupt the trajectory of the RTO’s renewable penetration trends.
MISO last year assembled MTEP 18 futures designed to be reused over multiple years, provided there aren’t extreme policy changes or economic shifts. The four futures include a limited fleet change future; a continued fleet change future; an accelerated fleet change future; and a future in which distributed and emerging technologies become more widely used in the footprint. (See MISO Ranks MTEP 18 Futures by Stakeholder Preference.)
As it promised, the RTO will apply an even 25% likelihood weighting to each of the four futures, effectively eliminating the weights. MISO had originally sought to apply equal weights in MTEP 18 but had to delay the plan for a year after stakeholders — especially from MISO South — insisted on having a say in deciding the futures’ likelihood. (See MISO Delays Removing MTEP Futures Weighting to 2019.)
LSE demand forecast | MISO
This year, MISO projects a slight dip in load-serving entities’ demand forecasts, with the latest overall RTO forecast trending lower than forecasts prepared to inform MTEP 18. MISO now expects demand to grow at a preliminary 0.3% rate, lower than MTEP 18’s 0.5% growth rate and keeping the forecasted non-coincident peak below 136 GW through 2026. Hunziker said MISO has not yet rerun a resource forecast with the updated data.
The RTO now anticipates lower natural gas costs, predicting prices will remain below $6/MMBtu through 2033, compared with last year’s prediction of $6.50/MMBtu.
MISO also found that, compared to its MTEP 18 estimates, the capital cost of building new generation will slightly decline for all fuel types, except for coal, which increases slightly, and utility-scale solar, which decreases more dramatically from about $2,000/kW to $1,200/kW.
Forecasted coal retirements are predicted to hold steady, with MISO estimating that about 35 GW will shut down by 2032.
MISO will hold a March 20 workshop to further refine MTEP 19 futures with stakeholders. Hunziker asked for stakeholders to submit their comments about the reuse of futures and the RTO’s predictions by March 2.
WASHINGTON — FERC on Thursday ordered RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets, a move the commission said will enhance grid resilience (RM16-23).
The rulemaking, Order 841, requires each RTO/ISO to establish a “participation model” for storage resources to ensure they are eligible to provide all energy, capacity or ancillary services of which they are capable, while also enabling them to set clearing prices as both a buyer and seller. Grid operators will also need to establish a minimum threshold for participation that doesn’t exceed 100 kW.
FERC also required that storage resources be able to resell electricity into the markets at the wholesale LMP.
The order “will enhance competition in these markets and help ensure that they produce just and reasonable rates,” staff told commissioners at FERC’s open meeting.
The commission issued its Notice of Proposed Rulemaking on energy storage market participation in November 2016. It could be about two years until the new rules take full effect. (See FERC Rule Would Boost Energy Storage, DER.) FERC’s directives will become official 90 days after their publication in the Federal Register. RTOs will then have nine months to file their tariff revisions, up from the six months proposed in the NOPR in response to requests for additional time, staff said. The grid operators would then have a year to implement the revisions.
The commissioners said the order demonstrated their commitment to ensuring they were not “picking winners and losers” in the markets. Commissioner Cheryl LaFleur noted that the markets “were largely designed around the resources that prevailed when they were launched” but have evolved to accommodate new technologies.
“I think the storage participation model required by today’s order will facilitate storage being able to provide all the services it is technically capable of providing, for the benefit of consumers,” she said.
The order is “the kind of positive regulatory action that removes barriers to competition, allowing emerging technologies to compete in the marketplace,” Commissioner Neil Chatterjee said. “Put simply, it’s good regulatory policy that people from all political backgrounds can support.”
“In my view, today’s final rule also strikes the appropriate balance between prescriptive requirements and high-level directives,” Commissioner Robert Powelson said. FERC ordered RTOs/ISOs to take into account the unique physical and operational characteristics of storage, he said. “In doing so, we have given the RTOs and ISOs significant latitude to develop market rules that work best with existing market constructs and are respectful of regional differences,” he said.
The Energy Storage Association applauded the order.
“With this morning’s unequivocal action, the FERC signaled both a recognition of the value provided by storage today and, more importantly, a clear vision of the role electric storage can play, given a clear pathway to wholesale market participation,” CEO Kelly Speakes-Backman said in a statement.
Powelson at ESA Policy Forum
In an appearance at ESA’s Energy Storage Policy Forum at the National Press Club the day before FERC issued the rules, Powelson told attendees the order would demonstrate the commission’s commitment to fair and open markets.
He also spoke about the larger trends in electricity, and how storage will have a bigger role to play under the new rules. Increased use of renewables has led to “market-based decarbonization,” he said.
“Whether you’re a fan of the Clean Power Plan or not, we are not building coal plants right now, and we are not building … 1,200-MW cathedral nuclear plants,” Powelson said.
He pointed to the 2014 “polar vortex” and last month’s cold snap. “No one [in D.C.] wants to talk about … the benefits of demand-side resources,” Powelson said. “They want to talk about baseload, baseload, baseload.”
Tech Conferences for DER
The commission had also proposed directing RTOs to give aggregated distributed energy resources the same treatment as storage, but on Thursday it said it needed more information before it could take action, ordering a technical conference to be held April 10-11 and opening new dockets for the issue (RM18-9, AD18-10).
Among the changes under FERC’s proposal, a DER aggregator could register as a generation asset “if that is the participation model that best reflects its physical characteristics.” The commission hopes to remove the commercial and transactional barriers to DER participation in wholesale markets.
Previewing the technical conference, LaFleur and Powelson said they were particularly interested in how DER operates and is compensated in both the wholesale and retail markets. “There needs to be a crisp understanding of who pays what to whom for what,” LaFleur said.
“Distributed energy resources are becoming increasingly more integral to our resource mix, and we at the commission should make every effort to advance this issue without delay,” Chatterjee said.
Speaking to reporters after the meeting, Chairman Kevin McIntyre acknowledged “the quasi-disappointment that I heard between the lines from some of my colleagues, which I share. It would have been great if we could have addressed both storage resources and distributed energy resources today. …
“But really, after looking at the state of the record on those two side-by-side issues, we determined that we needed to bolster our record on the distributed energy resource side of things. So I think our conference will be very useful.”
AUSTIN, Texas — Sempra Energy’s proposed $9.45 billion acquisition of Energy Future Holdings and its interest in Oncor took a major step toward reality Thursday before the Public Utility Commission of Texas.
The commission canceled a hearing on the merits of the deal scheduled for next week and directed staff to prepare a proposed order in the proceeding (Docket No. 47675). The PUC is expected to revisit the issue during its next open meeting on March 8.
EFH, which declared bankruptcy in 2014, holds an indirect 80% interest in Oncor, once its crown jewel but now the lone business remaining in its portfolio. Hunt Consolidated, NextEra Energy and Berkshire Hathaway Energy have all come up short in previous attempts to acquire Oncor, the largest electric utility in Texas.
“The fourth time’s the charm!” said an onlooker to a smiling Oncor CEO Bob Shapard, clapping him on the shoulder as he left the PUC’s hearing room.
Shapard and General Counsel Allen Nye, who will both retain positions on the post-acquisition board of directors as chairman and CEO, respectively, were singled out for praise by PUC Chair DeAnn Walker. She thanked them for their work in what she said was a “very painful process” for them.
Walker also apologized to a large contingent of Sempra representatives, which included CEO Debra Reed, for making the long trip from California for a discussion that took less than two minutes. “Come back and see us anytime,” she said.
Walker acknowledged the work of both parties involved in the transaction. San Diego-based Sempra and Oncor have agreed to a list of commitments in settling with all 10 parties that have intervened in the case, rendering a hearing moot. (See Sempra, Oncor Reach Agreement with Texas Intervenors.)
“The unanimous settlement agreement is incredibly positive and demonstrates support for the proposed Sempra transaction from all parties,” Oncor spokesman Geoff Bailey said in an email to RTO Insider. “We look forward to reviewing the proposed order from the commission and answering any further questions that they may have.”
Sempra said it was pleased with Thursday’s developments. The company announced its intentions to acquire EFH last August and received approval from the U.S. Bankruptcy Court for the District of Delaware in September. FERC gave its approval for the acquisition in December, but the transaction remains subject to the PUC’s approval and that of the bankruptcy court.
“If approved by the commission, we will have the opportunity to potentially bring this long ordeal to a close, and Texas will get a terrific partner in Sempra,” Bailey said.
A clean energy consultant told Midwest regulators Tuesday that a future footprint with more renewables would benefit from modern transmission technologies.
Rob Gramlich, president and founder of Grid Strategies, said transmission technologies — dynamic line ratings, flow control devices and network topology optimization — will help manage congestion.
“We’re looking at a future where there are a lot of low-cost but remote resources,” Gramlich told the Organization of MISO States’ Board of Directors at the National Association of Regulatory Utility Commissioners’ annual meeting.
Gramlich said the technologies have improved dramatically and are ready for use today, but they need to be better valued monetarily.
“They’re there and ready, but the incentives aren’t in place,” Gramlich said. “It’s just hard to get low-cost improvements because they can’t be rolled into transmission owners’ rate base. … There’s a gap that state regulators can address.”
Dynamic line ratings are adjusted based on weather conditions, opening up transmission lines for more capacity when temperatures are cooler. Network topology optimization uses software to improve scheduling of transmission outages. Gramlich also said power flow control devices, like phase angle regulators, played a key role in PJM managing loads during the early January bomb cyclone cold snap.
“Operate the existing grid more efficiently and get more out of it,” Gramlich urged.
He expressed surprise at how many line limit and flow thresholds on the bulk power system are not exactly known, only estimated. “It’s not so often measured,” Gramlich said.
It’s time for the industry to develop a technology-managed smart grid, he continued, noting that much of the country’s sewer flows are managed through technology.
Such technologies are more widely used abroad, where incentives are in place, Gramlich said, pointing to Belgium, which makes widespread use of dynamic line ratings.
OMS DER Survey Begins
The board kicked off an effort to collect data from load-serving entities on the volume of distributed energy resources participating in their service territories.
OMS will survey LSEs across MISO through March 30 on the current and projected state of DER in their territories. The group plans to analyze the data to get a better understanding of the “structure, scope and pace of DER development in MISO.”
The survey is part OMS’ ongoing initiative to help state and local regulators make informed decisions as increased DER adoption potentially dictates the need to develop policy around the interaction between distribution and transmission systems. Last year, OMS formed a temporary working group to formulate ideas on incorporating DER into the grid after holding a MISO-wide workshop. (See OMS Discusses Next Steps in DER Policy.)
“The OMS board has made DER a priority because of the inherent jurisdictional overlap raised by future integration of DER connected to the distribution system into transmission-level planning, operations, and energy markets,” OMS President, and chair of the Arkansas Public Service Commission, Ted Thomas said in a statement.
“In a multistate region, it’s critical that cooperation among states and their utilities occurs to provide the necessary visibility to DER deployment that enables the continued efficient and reliable operation of the bulk electric system,” said OMS Vice President Daniel Hall, chair of the Missouri Public Service Commission.
ISO-NE’s 2018 Regional Electricity Outlook released Wednesday reiterates concerns about fuel security that were detailed in a separate report published by the RTO last month.
In a joint preface to the outlook, ISO-NE CEO Gordon van Welie and Board of Directors Chair Philip Shapiro said “the biggest challenge to the reliability of the grid is the lack of fuel infrastructure to supply the fleet of natural-gas-fired generators.”
The RTO’s Operational Fuel-Security Analysis examined 23 fuel-mix scenarios and concluded that power shortages because of inadequate fuel would occur in 19 of them by winter 2024/25, which would require emergency actions such as voluntary energy conservation and involuntary load shedding. (See Report: Fuel Security Key Risk for New England Grid.)
Shapiro and van Welie also cited further emission restrictions on oil-fired generators “and the reality that older oil and nuclear generators are becoming less economically competitive and may retire before the region has added sufficient new energy sources to replace them.”
The outlook pointed to the recent cold snap that hit the region from Dec. 26 to Jan. 7, during which “constrained pipeline capacity resulted in substantially higher natural gas and wholesale electricity prices, leading to less expensive oil and coal power plants operating instead of the usually competitive natural gas-fired generation.”
Oil supplies at plants around New England declined rapidly over the two-week cold spell as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
Testifying before the U.S. Senate Energy and Natural Resources Committee on Jan. 23, van Welie said that since 2000, oil- and coal-fired generation’s share of ISO-NE’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%.
Projected Changes in Key New England Power Resources and Energy Efficiency | ISO-NE
The outlook noted that wind power last year for the first time surpassed natural gas for the volume of generation seeking interconnection in the RTO’s queue. About 4,000 MW of that proposed wind would be located offshore of Massachusetts, with most of the remaining 4,500 MW slated for Maine.
“Because of the large distances from some of the proposed onshore wind power projects to the existing grid, major transmission system upgrades will be needed to deliver more of this power from this weaker part of the system to far-away consumers,” the report says.
As the amount of wind and solar power continues to grow, in part driven by state policies, the RTO last month proposed a new two-stage capacity auction, Competitive Auctions with Sponsored Policy Resources, to enable its Forward Capacity Market to accommodate state policy-sponsored, clean-energy resources in the wholesale market while maintaining a viable economic model for existing power plants. (See CASPR Filing Draws Stakeholder Support, Protests.)
Major New Generation Projects Clearing in FCM | ISO-NE
The RTO also says it’s keeping an eye on the increased adoption of electric vehicles and electric heating in New England as states in the region pursue decarbonization goals.
“The ISO plans to start working with regional stakeholders to quantify the impact of the states’ decarbonization policies on long-term demand so that we can understand their potential effects on the power system and reflect these in future Regional System Plans,” the report says.
FOLSOM, Calif. — CAISO is moving ahead with major modifications to its congestion revenue rights (CRR) auction even as some stakeholders urge a deeper look into the possible detrimental effects of the plan before it goes to FERC.
CAISO defended its approach during a Tuesday forum on the CRR process. Some commenters are saying the ISO is taking an overly simplistic view of the issue: whether the CRR auction is a legitimate hedging mechanism or a process that forces ratepayers to become unwilling participants in losing transactions.
CAISO’s Department of Market Monitoring has become increasingly outspoken about what it calls auction “payment deficiencies” of more than $500 million — the difference between auction proceeds and payouts, which are based on day-ahead market congestion. But some market participants are protesting that the ISO is ignoring other benefits from the transactions. The debate over financial transmission rights is also occurring in other ISOs and RTOs. (See Market Monitors Bring FTR Complaints to Congress.)
CAISO discussed reforms throughout last year and unveiled its initial reform proposal at the beginning of this month. (See CAISO Overhauling CRR Auctions.)
The ISO intends to eventually restrict CRR transactions to only those needed for physical transfer of energy, and limit CRR source and sink pairs to nodes between generators and interties, as well as between trading hubs, loads and interties. It has also proposed to decrease the amount of system capacity released in the CRR auction process from 60% to 40% in the long-term allocation, and 75% to 45% for the annual allocation and auction process — a move intended to reduce overselling of transmission capacity. The ISO would also eliminate disclosure of certain modeling information and align existing outage reporting rules with the annual CRR process.
Track 1 of the effort consists of measures to be put in place for the 2018 auction process this summer, slated for March approval by the Board of Governors. Track 2 will include more significant changes, targeted for board approval sometime in the middle of the year, CAISO Market Design Manager Brad Cooper said in a presentation.
Kolby Kettler, of energy and commodities trader Vitol, has questioned the proposal since it was introduced. On Tuesday, he said the plan could introduce detrimental effects and new risks that CAISO has not considered.
“Other ISOs have also gone down this avenue, looking at removing locations, and have backtracked” because of revenue loss to the market, he said. He urged CAISO to focus on “fixing the model, and not focus on removing what could be a legitimate hedging activity or valuing congestion.”
“We are working to try and quantify the benefits of auction CRRs to the broader market,” Cooper replied, adding that “this isn’t the net effect … because CRRs have a benefit to the bilateral market.”
Speaking for the Western Power Trading Forum, Ellen Wolfe contended that CAISO was operating from a narrow viewpoint. She said the ISO has “narrowed in on the premise of the purpose of the CRRs being this physical hedge,” but that certain hedges might be beneficial for physical supply in ways the ISO is not considering.
“You build these proposals based on that particular premise — it presents a very narrow viewpoint of the world — and present anything outside of that viewpoint as not legitimate,” she said. “It is at least beneficial … to acknowledge that not everybody agrees with your premise.” Previously, there was never a sense that CRRs should be made available only to generators serving a load, she said.
“We are doing all we can to understand the uses,” Cooper said, but the auction revenues are far short of what CRRs are paying. “Sure, we would be eliminating combinations to allow for every type of conceivable hedging opportunity,” but “I think we are striking a reasonable balance,” he added.
CAISO is taking comment on its CRR proposal through Feb. 28.
As far as PJM transmission owners are concerned, the customer doesn’t always know best. They lack the institutional knowledge of the TOs, who have been operating their systems for decades and are responsible for their performance.
PJM transmission customers agree that they don’t have the information the TOs possess. But some are trying to change that imbalance, saying they are no longer willing to pay for replacing aging infrastructure system without assuring themselves that the spending is necessary.
How much more information the TOs will be required to share could be decided at today’s FERC meeting. The commission is scheduled to release a decision on its 2016 show cause order that questioned whether TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
The commission is also scheduled to address the TOs’ proposed Tariff Attachment M-3, which they developed to codify the “additional detail and transparency regarding the process for planning supplemental projects” that they’ve agreed to (ER17-179). (See PJM Demands Agreement on Tx Replacement Definitions.)
RTOs Provide Customer Forum
For most of their existence, TOs have had only to persuade state and federal regulators that their infrastructure plans were necessary, under a monopoly structure that entitled them to cost recovery and a margin of profit. The development of RTOs and ISOs has given their customers a forum to voice concerns and seek influence over transmission planning.
In PJM, American Municipal Power has made controlling its transmission costs a primary focus. Supported by several other RTO members — fellow transmission customers, state consumer advocates and merchant transmission developers — AMP has pushed the issue to confrontation on multiple fronts, including a stakeholder task force focused on end-of-life issues for transmission infrastructure. (See AMP Presses AEP, PSE&G on Transmission Projects.)
The Transmission Replacement Process Senior Task Force (TRPSTF) became a flashpoint almost as soon as it was proposed in January 2016. TOs argue that PJM and FERC rules give them sole discretion over how to maintain their assets — including when and how to replace them. The task force went into a 10-month hiatus after FERC issued its show cause order but reconvened after PJM stakeholders reinstated it last year.
More Transparency Sought
AMP and Old Dominion Electric Cooperative said they have been concerned about transparency in the planning process for quite some time.
“I don’t know if we had a big bang or if we had a slow burn,” AMP’s Ed Tatum said in an interview with RTO Insider. “We just kept asking more questions. … That gave us some traction to continue to ask questions.”
Both sides acknowledge that infrastructure, at some point, needs to be replaced. But the customers argue they aren’t provided enough information to independently evaluate whether proposed replacements are necessary or excessive. “I feel there should be adequate information for us to determine what is needed,” Tatum said.
AMP and ODEC argue that TOs are incentivized by their formula rates to build as much as possible and that regulators’ oversight is not adequate to corral the impulse.
“To me, it’s more of a check and a balance: Before they start replacing something, does it make sense?” ODEC’s Mark Ringhausen said. “Maybe that’s a concern that some of the TOs have: [that customers will] figure out that we’re replacing more facilities than they really need to.”
They point to a sudden rise in supplemental transmission projects, which are projects developed by TOs for their own transmission zones to address their own planning needs. They don’t have to address any PJM criteria, nor do they require the RTO’s sign-off to begin work.
Through 2012, according to a study done for AMP, PJM had planned or in service $21.3 billion in baseline and network upgrades — which are subject to detailed review by the RTO — versus $6.8 billion of transmission-owner identified (TOI) and supplemental projects. Since 2012, the $11.6 billion in baseline and network upgrades have been exceeded by $12.7 billion of TOI/supplemental projects.
“There are more projects outside of the PJM planning process than there are inside,” Tatum said.
“Of the 270 supplemental projects in 2017, when presented at their respective first reads [at Subregional RTEP Committee meetings], 181 of the projects were already in a stage of development ranging from engineering to 100% complete, with five projects already in service at their first reads,” the customers said in a 61-page recounting of their arguments filed on Tuesday. “At the second read, 205 out of 270 proposed supplemental projects were beyond the conceptual/scoping development phase, with nine already in service. Said another way, 76% of supplemental projects were presented to stakeholders in the SRRTEP meetings at a stage of development where meaningful input is unfeasible at best.”
Customers believe TOs have used these opportunities to bypass the stakeholder process and go straight to state and federal commissions, where they say they maintain longstanding political influence, as their best bets for revenue growth. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“I think it’s pretty simple economics. They’re not making a whole lot of money on generation right now, and they’re getting [returns on equity] on transmission in the 10 to 12% [range]. We don’t blame them,” AMP General Counsel Lisa McAlister said.
“Part of the reason why [customer input is] so important is because there’s not a lot of other regulatory oversight, and when it does happen, it’s too late in the process to be meaningful,” said McAlister, who signed AMP’s filing. “There aren’t a whole lot of other stopgaps to help.”
In its filing Tuesday, which asked the commission to reject Attachment M-3 and order further changes to achieve compliance with Order 890, the customers said FERC should require TOs and PJM to:
Record and post all questions and answers from proposal reviews;
Provide the power flow study details, including a description of the violations or issue identified;
Provide more detailed descriptions of the proposed facilities, including descriptions and costs of the assets being retired, installed or replaced; and
Provide adequate time for review and analysis.
PJM’s subregional transmission expansion plan process “has no provision to validate a TO’s need for supplemental projects nor the prudency of the project,” the coalition said.
TOs’ Response
The customers’ requests ignore PJM’s function on supplemental projects, says Exelon’s Gloria Godson.
“PJM’s process is a planning process, not a prudency review,” Godson said in an interview with RTO Insider. The correct venue for cost complaints is at FERC and state commissions, not PJM, she said.
To best understand the conflict, Godson said, think of TOs as car manufacturers and their networks as their own unique vehicle that they lease to customers. Customers get to use the car for their needs and must pay for improvements and maintenance, but ownership, knowledge about and ultimate responsibility for it remain with the manufacturer.
Customers want to understand the car’s engineering so well that they can independently confirm the need for the expenses the owners want them to incur. But the owners fear customers are more focused on cost because they’re not on the hook for the car’s reliability.
PJM, in Godson’s analogy, is the company that builds and maintains roads. But the RTO can’t tell TOs what tires to install on the car or when to replace the radio, she said, any more than it can tell TOs how much that work should cost.
In a combined statement to RTO Insider, PPL, Public Service Electric and Gas (PSE&G), Exelon and Duquesne Light said replacement costs have increased in response to new obligations, such as higher security demands and increased efficiency and reliability standards.
“Shared final decision-making with a diverse set of stakeholders each with differing priorities would negatively impact the safety, reliability, security and efficiency of the transmission network. It would also lead to lack of clarity as to who has the responsibility for the impact of adverse events,” the TOs said.
Order 890, the TOs said in their October 2016 response to the order to show cause, “affirmed that the ultimate responsibility for planning remains with transmission providers and that it was not requiring transmission providers to engage customers in the transmission planning process on a ‘co-equal basis.’”
Godson pointed to her experience at Potomac Electric Power Co. (Pepco) with the failed Mid-Atlantic Power Pathway project as an example of regulators’ exercise of cost discipline. Pepco attempted to recover $87.5 million in costs after the project was canceled by PJM, but intervenors protested and FERC eventually approved a $80.5 million settlement (ER13-607).
No Bright Line
It’s not possible, TOs say, to develop a standardized way for customers to replicate the analysis that they would be able to endorse because it would require modeling so detailed and exact — on variables ranging from terrain and weather to population density, local regulations and load types — as to be impractical, along with institutional knowledge that they say only exists at the TO.
“There is no bright-line criteria for determining when an asset should be replaced, as it is based upon a variety of factors that require engineering and operational judgement,” the statement said.
“A company may be willing to take a different type of risk in a rural area than they may be willing to take in Washington, D.C., for example,” Godson added. “That goes from one TO to another, so it’s … not possible to have a cookie-cutter approach to system design. … My question would be, for what basis? PSE&G knows their system better than anybody can. … This is what they do for breakfast, lunch and dinner.”
More can be Done, Customers Say
Customers acknowledge the issues but say there’s more that can be done.
“There’s judgment to this, but those are discussions that need to happen,” Ringhausen said. “They need to present us enough information that we can understand their criteria.”
“One of my large concerns with this is [the industry] creating the exact same situation we’re in now for the next generation down the road,” AMP’s Ryan Dolan said. The transmission infrastructure was largely built at the same time, and TOs are “in a mad rush” to replace everything at the same time. Dolan argues that with some foresight and consideration, the replacements, and their costs, could be rolled out over time.
“Should we have a long, sustained capital investment?” he asked.
“TOs don’t have anything that predicts the longevity of assets. … Age is simply a bucketing mechanism, but whether and when an asset is actually replaced depends on the condition of that asset,” Godson responded. “So, you may have a transformer that is relatively newer, but if it begins to [break down], you cannot defer maintenance [just] because it’s not old enough. Conversely, there are assets that are 70 years old and still going strong. So it depends on the condition and performance of the asset.”
While TOs’ primary strategy is monitoring and replacing based on condition and performance, there are some times when equipment targeted for replacement can be addressed while repairs are being made to infrastructure nearby.
Improvements
TOs argue they have worked to improve information sharing in the monthly meetings that focus on PJM’s Regional Transmission Expansion Plan, as documented in Attachment M-3. “The PJM process is far and away the most transparent of any process in the country,” Godson said.
Tatum contends the sides are “fairly close” and that a solution to the dispute “doesn’t need a quantum shift.”
The TOs disagree with the magnitude of the change they say AMP and its allies are requesting.
“AMP’s proposal that PJM and the PJM stakeholders take over the TOs’ responsibility for asset replacement and managing the supplemental project planning process violates the [Consolidated Transmission Owners Agreement] and would breach a fundamental contract that forms the basis upon which TOs joined PJM,” the TOs said. “PJM does not have the expertise, experience or resources to take over the TOs’ asset management function. PJM has stated repeatedly that they do not consider this an appropriate role for PJM.”
CARMEL, Ind. — MISO is weighing how it can improve its interregional process and joint operating agreement with SPP to make it easier to develop cross-seams projects that have so far remained elusive.
“The assumption is the coordinated system plan is not setting us up for success,” Eric Thoms, MISO manager of interregional planning and coordination, told stakeholders at a Feb. 14 Planning Advisory Committee meeting.
Planning staff for both RTOs have agreed to meet this spring to devise ways to improve their joint study process.
Thoms said MISO is considering lowering hurdles for interregional projects, including removing the $5 million cost threshold and eliminating the joint model study requirement, which he said is unnecessary when the RTOs’ separate regional evaluations can adequately examine prospective interregional projects.
He also said the RTOs might identify more joint benefit metrics that could better illustrate the value of potential transmission projects and clarify to stakeholders the process for approving interregional projects.
However, some stakeholders said the RTOs must first address their disparate transmission usage charges before working toward interregional project approval.
“I’m glad to see MISO is trying for constituency between seams, but MISO and SPP have incompatible [unreserved usage charges],” said Minnesota Public Utilities Commission staff member Hwikwon Ham. Until the RTOs have comparable transmission usage charges, interregional projects will be difficult to approve, Ham said.
Xcel Energy’s Drew Siebenaler agreed the RTOs must discuss transmission service charges and resolve the issue of MISO consistently bearing more costs for potential projects that stand to benefit both sides of the seam.
Adam McKinnie, chief economist with the Missouri Public Service Commission, asked that the charges not be the lone hang-up in approving a possible near-term interregional project. Thoms promised to return to the PAC in April to further discuss the topic.
The next Interregional Planning Stakeholder Advisory Committee meeting will be held Feb. 27. Officials from both RTOs plan to present a more detailed coordination plan during the meeting.
