MISO on Wednesday secured another four months to implement mandatory five-minute market settlements, providing its staff more time to roll out new software designed to manage the process.
FERC granted MISO’s request to delay implementation from March 1 to July 1 after the RTO said it requires “more time to develop and test the software, after which market participants need a minimum of three months to make corresponding adjustments to their own software and reporting systems” (ER18-314).
MISO’s Carmel. Indiana Control Room in 2013 | MISO
The decision marks the second time the commission has extended the deadline for instituting five-minute settlements, required under FERC Order 825. MISO last May won an initial extension from Jan. 11 to March 1, but late last year multiple stakeholders noted that delays in replacing the RTO’s overall settlements system would result in members rushing to adapt their own systems to accommodate the new process. (See “MISO Asks for 5-Minute Settlement Delay,” 8 Projects Set for 2018 MISO Market Roadmap.)
FERC determined that MISO’s request for more time was made in good faith and was necessary for software testing.
“We find that good cause exists to grant this extension because of the importance of ensuring that software and testing requirements are met for both MISO and its market participants. … This extension will facilitate a smoother and more effective implementation of five-minute settlements in MISO,” the commission said.
In February, MISO staff said the RTO is still on track for fully functional testing with stakeholders beginning April 1, with the new settlements computer system fully implemented by April 16.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved proposed rule revisions that would allocate day-ahead market congestion rent shortfalls and surpluses stemming from changes in transmission availability to the responsible transmission owner.
The measure, which would revise Attachment N of the ISO’s Tariff, will go to the Board of Directors for approval before a filing with FERC. The Business Issues Committee (BIC) recommended the proposal to the MC. (See “Day-Ahead Market Congestion Settlements,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)
At the Feb. 28 MC meeting, Operations Analysis and Services Supervisor Tolu Dina explained that the ISO’s proposed cost allocation methodology employs a de minimis threshold to determine when TOs are not allocated costs. The threshold applies to day-ahead constraint residuals less than $5,000, provided the sum of all such residuals falling below the threshold is not more than $250,000 or 5% of the sum of all day-ahead constraint residuals for the month.
Alternative Methods for Determining LCRs
The MC approved Tariff revisions to establish an alternative method for calculating locational minimum installed capacity requirements.
The revisions incorporate incremental changes recommended by stakeholders at the Feb. 6 Installed Capacity Working Group/Market Issues Working Group meeting, said Zachary Stines, NYISO associate market design specialist. (See “Alternative Methods for Determining LCRs,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)
Stines presented the new method for determining locational capacity requirements (LCRs) for localities, designed to minimize the total cost of capacity at the level of excess condition while meeting reliability criterion, maintain the installed reserve margin approved by the New York State Reliability Council and not exceed transmission security limits.
| NYISO
The ISO plan evaluates net energy and ancillary services revenue at different levels of installed capacity using data from the most recent of either the capability year after a quadrennial “demand curve reset” or the annual installed capacity update.
The Long Island Power Authority, NRG Energy and other stakeholders recommended sending the measure back to a working group for additional analysis. But other market participants countered that while a case can always be made for more analysis in a big project, the proposal — while imperfect — represents an improved approach for estimating requirements.
MC Rejects On Ramp/Off Ramp Changes
The MC rejected a market design proposal and related Tariff revisions that would have eliminated localities and revised the existing on ramp/off ramp rules to create a new locality.
Zach T. Smith, NYISO manager of capacity market design, told the MC the proposed methodology is based on reliability planning principles developed to determine whether to create and eliminate localities.
The unique geographic nature of Zones J and K, encompassing New York City and Long Island, makes it difficult to site generation in those areas, which also confront distinct environmental issues, Smith said.
Mark Younger of Hudson Energy Economics reiterated the objections he made at the BIC meeting earlier in the month, calling the market design proposal — and NYISO’s review process — “flawed.”
BIC Chair Erin Hogan said NYISO received about 10 letters of support for the capacity market design from members of the public, the first time she recalled such a response. The letters will be posted on the ISO’s website.
MISO and SPP are ready to reform their interregional planning process to improve their shot at producing their first cross-border transmission project, but they plan to wait a year before launching a joint study to identify such a project, the RTOs said Tuesday.
At a Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting, the RTOs admitted that criteria spelled out in their joint operating agreement might be preventing beneficial interregional projects from gaining approval. They said they are ready to work with stakeholders through the summer to ease some restrictions.
SPP Interregional Coordinator Adam Bell said the RTOs’ latest coordinated system plan study, concluded in 2017, showed they are still inconsistent in how they calculate adjusted production costs, develop regional models and review regional project proposals. Before being approved, proposed interregional projects must clear separate regional reviews by each RTO in addition to passing a joint review.
“We’ve learned a lot in both coordinated plans we’ve done,” Bell said. “Both SPP and MISO are interested in doing meaningful planning between our systems, and we want stakeholders to have faith in the process and feel good entering these studies. … Both RTOs support … designing a new study process that has stakeholder confidence. We’ve done this twice. Let’s fix this thing.”
Davey Lopez, MISO adviser of planning coordination and strategy, said the RTOs plan to collect stakeholder suggestions and do more research before returning to the IPSAC in May with recommendations on how to improve their joint planning. The RTOs plan to work with stakeholders through September to prepare a FERC filing to alter their JOA by the end of the year.
Comprising planning staff from both RTOs, the Joint Planning Committee will vote later this year on whether to pursue another coordinated system plan.
Staff from both RTOs cautioned that they were unlikely to develop a 2018/19 study because planners are inclined to concentrate fully on process improvements, but stakeholders will be provided a non-binding IPSAC vote on where planners should concentrate their efforts.
$5 Million Obstacle
SPP and MISO said a major piece of the overhaul would be lowering the RTOs’ $5 million cost threshold for interregional projects.
“Hopefully, we can remove some of these hurdles on the coordinated system plan,” Lopez said.
In response to a question by Entergy’s Yarrow Etheredge, MISO and SPP staff declined to identify any specific project they would have liked to see pass but for the RTOs’ stringent criteria, although Lopez noted a few instances in which lowering the $5 million threshold would have improved a project’s chances in the last coordinated system plan.
“We really finished one study and started another, so we didn’t have time to implement these improvements we identified,” Bell said, referring to the short gap between the 2014/15 and 2016/17 studies. At the time, MISO recommended awaiting a second coordinated study while the RTOs worked out differences between their planning processes, but MISO eventually abandoned the idea in favor of starting another study.
Bell said it’s imperative for the RTOs to align their adjusted production costs and more accurately model each other’s systems. He suggested removing MISO and SPP’s joint modeling efforts altogether in favor of working on more identical regional models. Several stakeholders objected to that idea, claiming it could complicate cost allocation between the RTOs. Bell pointed out that MISO and SPP would still have a joint study under his plan, just not a joint model.
The RTOs are additionally contemplating allowing for adjustments in modeling cost allocation to determine if the benefits of a project are amplified.
SPP also continues to support cost allocation for sub-345-kV interregional projects with MISO, Bell said, a subject that MISO continues to discuss, according to Lopez. MISO has proposed cost allocation changes for its market efficiency projects, including a sub-345-kV cost allocation and elimination of a footprint-wide postage stamp rate. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)
Entergy Critical of MISO-SPP TMEP
Entergy engineer Kyle Watson said the MISO-SPP seam does not yet have a structured enough coordination process to develop smaller interregional projects, such as those eligible to qualify under the new MISO-PJM targeted market efficiency project (TMEP) category, which relies on historical congestion to identify small transmission projects. MISO and PJM approved a $20 million, five-project TMEP portfolio late last year, representing the first interregional transmission projects between the two RTOs, and some stakeholders have called for a similar process on the MISO-SPP seam. (See MISO Board Approves $2.6B Transmission Spending Package.)
Entergy’s Matt Brown said there isn’t sufficient operational data since the integration of the company into MISO and the Western Area Power Administration into SPP to build a case for congestion-relieving projects. But SPP Director of Seams and Market Design David Kelley disagreed, saying MISO and SPP have already collected enough historical congestion data to justify projects that are less costly than continuing to pay market-to-market congestion charges.
“The day-ahead and real-time congestion is persisting,” agreed Lopez.
During the IPSAC meeting, the RTOs pointed out that one congested flowgate on the Oklahoma-Kansas border has been responsible for nearly $20 million M2M payments since February 2017.
Wind on the Wires’ Natalie McIntire and WPPI Energy’s Steve Leovy said their organizations are displeased that the RTOs are not inclined to begin another coordinated system plan this year, given that the 2016/17 plan focused narrowly on needs along SPP’s Integrated System in North Dakota, South Dakota and Iowa, and the larger SPP-MISO seam has areas of congestion.
“There’s a lot of consumers bearing costs because we’re not fixing these issues,” Leovy said. “There’s need for a major interregional study.”
“We’re not happy, but we recognize there’s general consensus beyond us,” McIntire said.
Peak Reliability and PJM officials on Tuesday promoted the independent and self-governing nature of their proposed Western energy market in an attempt to differentiate the effort from a competing initiative by CAISO.
“Our blank state for market governance really resonates with people, because they see they don’t have to inherit a governance structure from one entity or be burdened by a structure that is tied to a particular state,” Pete Hoelscher, Peak’s chief strategy officer, said during a Feb. 27 conference call.
Peak officials provided more details on the proposed market, along with feedback they have received from industry participants.
One major concern among participants interested in the market: getting the full and appropriate value for generation and transmission assets “because that is not happening in all cases today,” Hoelscher added.
| PJM Connext, Peak Reliability
In a parallel development, CAISO earlier this year announced a plan to bring day-ahead functions into its Western Energy Imbalance Market (EIM). (See CAISO Plan Extends Day-Ahead Market to EIM.) The California State Assembly this week also kicked off yet another legislative effort to regionalize CAISO, possibly setting up competition for who would create and operate a full Western RTO. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
While Peak officials have previously said they aren’t setting out to create an RTO, the organization said Tuesday that its proposal is a pathway to developing one. Peak expects to publish a business plan on March 30 and hopes that by mid-April interested parties will enter into nonbinding agreements to assist in market governance and design. Binding agreements are targeted for June, and the goal is to have the market go live in June 2020.
| PJM Connext, Peak Reliability
Peak said that potential participants in the new market have expressed doubt that it can be operational by the scheduled target date of mid-2020 because of technical, operational and regulatory tasks, but Peak officials are stressing the operational experience of PJM, which operates a 13-state eastern energy market.
Other commenters to Peak noted that they have already invested in joining the EIM and are receiving financial benefits from the real-time balancing market. Some have told Peak that CAISO’s proposed day-ahead market across the EIM seems like the only foreseeable next step in developing a Western market. Others say the West needs more fuel diversity and participation, according to a Peak presentation.
| PJM Connext, Peak Reliability
Based on feedback, Peak’s services would not include a capacity market, consolidation of open access transmission tariffs, or regional/sub-regional system planning for reliability, operational performance, public policy, market efficiency or interconnection.
Peak and PJM Connext announced their joint effort to develop a market in January. Visualized for day one is reliability coordination services, real-time and day-ahead energy markets, financial transmission rights allocation, balancing authority services, market monitoring and a self-governance model. (See Peak, PJM Pitch ‘Marketplace for the West’.)
FERC on Tuesday rejected MISO’s proposed pro forma agreement for pseudo-tying generation into PJM, saying the rules around termination were too broad.
“Although we believe that a pro forma pseudo-tie agreement is a beneficial instrument to promote uniformity, transparency and certainty as to what the responsibilities and obligations are with respect to the increasing interest to use pseudo-tie arrangements, we find that parts of the MISO agreement have not been shown to be just and reasonable,” FERC said in its order (ER17-1061).
The commission encouraged MISO to file a revised version.
In rejecting the agreement, FERC said MISO’s proposed termination provisions did not align with already accepted revisions to the MISO-PJM joint operating agreement. (See FERC OKs Change to MISO, PJM Pseudo-Tie Rules.) The agreement was unclear about the meaning and consequences of a suspension, FERC said.
| MISO, PJM
“The MISO agreement does not detail what happens to resources under suspension, how a resource may seek to resume normal operations, which balancing authority retains operational control of the resource while it is under suspension, or how a resource under suspension may be terminated,” FERC said.
The commission called the termination provisions “vague and open-ended.” While MISO proposed to give itself authority to “make all final determinations whether to implement or terminate [a] pseudo-tie,” FERC interpreted that language as granting the RTO the ability to terminate a pseudo-tie for any reason, provided it satisfied the six-months’ notice requirement.
The proposed agreement would have allowed MISO to suspend and terminate pseudo-ties if resource owners failed to provide real-time measurement values in a timely manner; if the generation-to-load distribution factor between MISO and PJM was not within 2%; and if a partially pseudo-tied resource injected more energy into MISO than the modeled limit.
MISO also proposed that a pseudo-tie maintain firm transmission service from source to sink for the life of the pseudo-tie, and that it could terminate a pseudo-tie if reliability is threatened, with no notice beyond compliance with NERC standards. However, the RTO proposed that its pro forma requirements would not be retroactively applied to existing pseudo-ties, provided that those existing pseudo-ties aren’t modified. In the event of a modification, MISO would restudy the pseudo-tie.
The rejected proposal was the subject of a deficiency letter last year in which FERC questioned under what circumstances MISO could revoke a pseudo-tie. (See MISO, PJM Respond to FERC’s Pseudo-Tie Questions.)
FERC’s ruling also dismissed as moot a protest and rehearing request by the Illinois Municipal Electric Agency, which had complained that MISO’s proposal threatened the vested rights of market participants with long-term historic generation and transmission rights to serve load. The agency argued that MISO could terminate its long-term, fixed transmission rights at any time and that the proposed 2% distribution load provision “suffers from a lack of transparency because modeling upon which this provision is based is complex and, for the most part, confidential” between PJM and MISO.
IMEA also contended the agreement should be between MISO, PJM and the pseudo-tie owner, rather than just MISO and the owner.
MISO Reaction; IMM Reliability Suspicions
MISO briefly addressed FERC’s rejection during a Feb. 28 MISO-PJM Joint and Common Market meeting, saying it intends to file again.
“MISO feels that the circumstances surrounding that agreement still exist, and the agreement is still needed,” Director of Market Design Kevin Vannoy told meeting attendees. The RTO plans to return to the Reliability Subcommittee sometime in spring to revise the agreement with stakeholders.
MISO and PJM staff at the meeting also noted they have reliably administered a considerable increase in pseudo-ties since the start of the 2016/17 planning year. MISO says its total pseudo-tied volume increased from 1,966 MW in June 2015 to 5,668 MW in June 2016.
But MISO’s Independent Market Monitor challenged the RTOs’ assertion that pseudo-tied generation has operated reliably.
IMM staffer Michael Wander asked if either RTO could deny that they’ve experienced control room “emergencies” as a result of poorly managed pseudo-ties, but both Vannoy and PJM officials said they didn’t understand the question and would not answer it.
“Let me rephrase. Would you say there haven’t been any extraordinary actions taken?” Wander asked. “Because when you say you’ve implemented those reliably, that means business as usual, but that’s not what I’m hearing from reliability coordinators.”
MISO and PJM staff denied that pseudo-ties have affected reliability.
Wander ended the exchange by saying he would provide RTO leaders with confidential pseudo-tie data that have been troubling the Monitor. Staff agreed they could hold a later discussion on the matter.
ISO-NE is “in a race” to relieve natural gas pipelines constraints and interconnect new generation before New England loses older, uneconomic resources, CEO Gordon van Welie said Tuesday.
“If there’s a mismatch between the speed of those two or three activities, we’re going to have to do something to slow things down so that we keep the grid reliable,” van Welie told reporters in an online briefing on the state of the region’s power grid.
“The more we constrain oil, the more complicated, the more tenuous it makes our operations,” he said. “We have resources that are retiring, we have state environmental regulations that are aggressively lowering the amount of emissions that can be produced by fossil generators, and we have the states moving forward aggressively to invest in behind-the-meter resources, including energy efficiency and new renewable resources.”
In January, the RTO released an Operational Fuel-Security Analysis that examined 23 fuel-mix scenarios and concluded that inadequate fuel supplies would cause power shortages under 19 of the scenarios by winter 2024-25. Those shortages would require emergency actions such as voluntary energy conservation and involuntary load shedding, or rolling blackouts. (See Report: Fuel Security Key Risk for New England Grid.)
Smoker of a Cold Snap
During two weeks of bitter cold surrounding New Year’s Day, New England generators burned through nearly 2 million barrels of oil, more than twice the amount used by the region’s power plants during all of 2016, van Welie said.
| ISO-NE
Oil supplies at plants around New England declined rapidly during the 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.)
Contributions from other types of generators were crucial during the cold snap, according to the RTO’s analysis.
“For instance, electricity produced by the Millstone nuclear station during the cold spell is equivalent to what could be produced by about 880,000 barrels of oil, and the power from the Mystic 8 and 9 units in Boston, which are fueled by LNG from the nearby Distrigas import facility, was the equivalent of more than 360,000 barrels of oil,” van Welie said.
| ISO-NE
High oil consumption means higher emissions. At the end of the cold snap, just one week into 2018, several oil-fired generators were already nearing their annual emissions limits, he said.
“The region can pay the bill for its fuel-security risks periodically, in spiking wintertime prices and potential energy shortages, or the region can pay the costs proactively and avoid reliability risks by investing in infrastructure, firm fuel contracts and other incentives,” van Welie said.
That new infrastructure could include further efficiency measures, transmission lines, renewable energy resources, storage facilities for liquid fossil fuels and gas pipeline infrastructure.
“Clearly, as one makes some of these infrastructure investments, you begin to lower the costs of the reliability services that the ISO seeks to procure,” van Welie said.
As oil resources retire — including those solely fueled by oil — the grid becomes more dependent on imported LNG or dual fueling, he said.
“I think the dual fueling becomes more constrained given the emissions constraints in the region,” van Welie said. The solution is “really a combination of electricity imports from neighboring regions and LNG as the balancing fuels as we put more and more renewables on the system, and that’s assuming we make no more investment in the gas infrastructure.”
Since 2000, the share of oil- and coal-fired generation in the region’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%, he said.
Wind and CASPR
Solar has “exploded” in New England, largely because of state incentives, van Welie said, growing from 250 MW to 2,400 MW in just five years. Most resources are located in more than 130,000 small installations on homes or businesses.
| ISO-NE as of Jan. 29, 2018
And last year, wind power 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 onshore in Maine. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
As the amount of wind and solar power continues to grow, in part driven by state policies, the RTO in January proposed a new two-stage capacity auction, Competitive Auctions with Sponsored Policy Resources (CASPR), 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 ISO-NE Defends CASPR Against Protests.)
| ISO-NE
CASPR, which the RTO proposes to implement on June 1, would “fully integrate demand response resources … into the competitive energy and reserves markets, where they can compete with conventional generators,” van Welie said. “ISO New England will be the first in the country to fully integrate DR into energy dispatch, building on its longstanding commitment to DR.”
The most effective way to achieve the states’ environmental objectives is to put an appropriately high price on carbon, van Welie said, because it would spur investment in cleaner resources.
“That could be the most efficient way of doing it through a wholesale market mechanism,” van Welie said. “It would allow us to avoid making this CASPR proposal that we recently filed at FERC. But we do understand that’s not the preferred choice of the states, and we respect that, and hence we have come up with this method for accommodating what they’re doing through above-market contracts.”
Sempra Energy on Tuesday became the third California-based energy company to promise a “three-pronged” effort to recover costs related to wildfires and push back on liability for having potentially caused some of the state’s deadly — and costly — fires.
During an earnings call, Sempra Energy CEO Debra Reed said that many factors are contributing to the worsening scope and spread of wildfires and that “it is irrational to place all of the burden strictly on utilities.” She said a hearing held in the Assembly on Monday on the wildfire issue was a favorable development. (See Wildfires Ignite Worries at CPUC, Legislature.)
“There is a focus now on how to resolve this inverse condemnation issue now legislatively,” she said, adding that the California Public Utilities Commission (CPUC) and Legislature are working more closely on the issue. “I think there is going to be some movement in that area.”
SDG&E parent Sempra Energy released its fourth quarter and 2017 earnings on Tuesday | Sempra Energy
The “inverse condemnation” principle states that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.” California utilities have cited the principle in their attempts to recover the cost for repairing infrastructure damaged by wildfires.
CPUC in late November denied $379 million in cost recovery to Sempra subsidiary San Diego Gas and Electric (SDG&E) for wildfires that occurred in 2007, despite the company’s use of the principle. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) The state’s other two investor-owned electric utilities, Pacific Gas and Electric and Edison International, have joined in requests for a rehearing of the CPUC decision.
“We will proceed expeditiously in the court” if CPUC denies rehearing, Reed said Tuesday. “I think that it is important to remember FERC approved full recovery for the same fires and same facts over four years ago.” In 2011, a portion of SDG&E’s costs associated with the settlement of 2007 wildfire-related damage claims was identified as allocable to SDG&E’s FERC jurisdiction assets, initially totaling $19.7 million, according to company statements.
Sempra began discussing legal action last fall after the decision CPUC decision on the 2007 fires affected third-quarter financial results. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.)
Financial Results
In the fourth quarter of last year, Sempra recorded a loss of $501 million ($0.51/ share), compared with earnings of $379 million in the fourth quarter of 2016. Excluding the impact of an $870-million expense in the fourth quarter related to last year’s passage of the federal Tax Cuts and Jobs Act, a CPUC decision on 2007 wildfire cost recovery, and other factors, adjusted earnings were $389 million, compared with $383 million during the same period a year earlier, Sempra said.
“A portion of this income-tax expense relates to Sempra Energy’s plans to repatriate approximately $1.6 billion of undistributed foreign earnings over the next five years,” the company said.
The acquisition of Texas utility Oncor is another central issue for Sempra, and Reed noted the Public Utility Commission of Texas is due to vote on the deal as early as March 8. The U.S. Bankruptcy Court for the District of Delaware on Monday confirmed a reorganization plan for Oncor’s parent company, Energy Future Holdings, including the California company’s $9.45 billion acquisition of EFH and its 80% interest in Oncor (See Bankruptcy Court OKs Sempra-Oncor Deal.)
Sempra also reached a revised settlement regarding retirement of the San Onofre Nuclear Generating Station and resolved legal claims on the Aliso Canyon natural gas leak. Sempra subsidiary SoCal Gas has resumed injections at the gas storage facility, where limited withdrawals have contributed to gas supply concerns in Southern California.
WASHINGTON — American Public Power Association CEO Sue Kelly has been railing for years against RTO capacity markets and stakeholder rules she says are skewed in favor of large transmission and generation owners.
This week, as 600 APPA members gathered at the historic Mayflower Hotel for their annual Legislative Rally, the group could celebrate recent policy victories on both fronts.
On Friday, FERC ordered a technical conference to consider whether PJM should move from a year-round to a seasonal capacity construct, indicating that the newly constituted commission is having second thoughts about the restrictive Capacity Performance rules FERC approved in 2015. (See FERC Rethinking PJM Capacity Performance Rules.) APPA had opposed CP as an overreaction to the 2014 polar vortex, saying PJM and market participants had largely addressed reliability problems through other measures.
FERC also backed public power’s position in a Feb. 15 ruling that PJM transmission owners’ processes for developing supplemental projects violate Order 890’s transparency and coordination requirements. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
In California, meanwhile, proponents of legislation that could enable CAISO’s growth into a Western RTO said the grid operator would not back mandatory capacity markets. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
Kelly said, although APPA doesn’t lobby state government, it is pleased with the promise.
“Obviously, the California municipal utilities are an active and involved bunch,” Kelly said. “I will say that our members in the West have witnessed what went on in the East. It’s the old ‘Fool me once, shame on you. Fool me twice, shame on us.’”
A resolution approved by APPA’s Legislative & Resolutions Committee earlier Tuesday called for “consumer benefits and participatory multi-state governance” as essential elements of a Western RTO.
The committee also approved resolutions on supplemental transmission, electric vehicles, disaster response, infrastructure investments, and the Public Utility Regulatory Policies Act of 1978.
After the votes, many of the attendees — including public utility executives, mayors, and council members for cities with municipal utilities — went off to the Capitol to lobby Congress on their concerns.
Fighting Privatization
It hasn’t all gone APPA’s way of late, of course. The group is fighting a rear-guard action to block President Trump’s proposal to divest the transmission assets of the Tennessee Valley Authority, Southwestern Power Administration, Western Area Power Administration, and Bonneville Power Administration.
“We believe that the public power business model is a very strong one,” Kelly said.
APPA also is backing bipartisan legislation introduced in February to restore the ability of public power utilities to advance refund private activity bonds — a way of prepaying higher cost debt (H.R. 5003). “While we were largely successful in the tax bill that just passed at the end of 2017 in protecting and maintaining municipal bond financing — for which we are most grateful to Congress, don’t get us wrong — our ability to advance refund was taken away as part of that legislation,” Kelly said.
APPA leaders also were to meet with all five FERC commissioners this week to press their longstanding concerns about RTO wholesale markets.
“We are quite concerned about wholesale market rules that would make wholesale prices more volatile and impede our ability to self-supply,” Kelly said. “And we would like to see RTOs stop overriding state and local decision making.”
State and local control also was the focus of APPA’s resolution on distributed energy resources. “What works in Arizona may not work in New Hampshire. So, we believe Congress should not seek to federalize rate design or tip the scale [in favor] of any particular resource over others,” Kelly said. “Allow those decisions to be made at the state and local level.”
APPA filed comments Monday supporting EPA’s Advanced Notice of Proposed Rulemaking on replacing the Clean Power Plan. It agrees that the Obama administration’s final rule went beyond its authority under the Clean Air Act.
“We don’t want [there to be] no regulation but we want regulations that comport with what’s allowed in Section 111, and that would be things within the fence line — not this fuel switching from coal to natural gas, natural gas to renewables,” said Desmarie Waterhouse, vice president of government relations.
And what about critics who say inside-the-fence-line regulations will have little impact on carbon emissions? Utilities “have been reducing their CO2 emissions for quite a while and will continue to do so as they make resource decisions,” she responded. “The bottom line is a rule under the Clean Air Act needs to comport with the Clean Air Act, irrespective of how much it raises CO2 emissions.”
Cybersecurity Partnership
APPA also would like to see a stronger partnership with the federal government on cybersecurity. APPA has used Department of Energy funding to conduct cybersecurity reviews of some systems and to develop a cybersecurity “maturity model” tailored to public power. Going forward, Kelly said, the group wants to make “sure we have sufficient security clearances to be able to act when there are threats, [being able to] vet employees working in sensitive positions” to ensure they aren’t on terrorist watch lists.
Supplemental Transmission Projects
APPA’s resolution on supplemental projects, which urged FERC to enforce the transmission planning process requirements of orders 890 and 1000, grew out of concerns in PJM. But rising transmission spending is an issue nationwide, Kelly said.
“There is no question we have members in a number of different regions that are concerned about rapidly increasing transmission revenue requirements,” she said. “Don’t get us wrong, we’re not against new transmission, and we realize that reinforcements and extensions — and maybe eventually new facilities — may be needed. But we want to make sure that they’re properly vetted through the process and, frankly, that our members have the opportunity to own some of that. Rather than just: ‘It’s my tinker toys and I’ll impose all this on you.’”
Order 1000, said APPA General Counsel Delia Patterson, “hasn’t panned out to be what it was originally purported to be. There’s room for growth in Order 1000 in terms of actually having an impact on the industry.”
As for PURPA, Kelly said, the group seeks “modest revisions to ensure that the provisions are not abused and that we’re not required to buy power that we do not need at prices that are above market.”
SACRAMENTO, Calif. – California regulators and lawmakers are sounding the alarm over a possible decline in the financial and credit health of utilities stemming from wildfire risk and liability.
During an informational hearing Monday, State Assembly members expressed concern over the finances of the state’s investor-owned utilities due to their potential liability for a series of devastating wildfires in 2017.
Utilities and Energy Committee Vice-Chair Jim Patterson (R) repeatedly asked California Public Utilities Commission (CPUC) President Michael Picker if he would describe the event as a “crisis,” but Picker declined to use that term.
“I think we are headed toward bankruptcy for IOUs,” Patterson said. “I really think this is a crisis and needs a crisis approach to it. I think we need to engage on this seriously.”
“I see a continuum of constraints on utilities,” Picker said, adding that declining credit ratings and financial health will affect their ability to invest in renewables and electric vehicles and to obtain insurance. “Certainly, they are going to find it harder to borrow.”
In response to Patterson’s question about what steps the state is taking in response, Picker said: “I assume that is one of the reasons we are having this conversation here today.”
The third prong of that effort appeared to be underway Monday, with discussions at the hearing indicating that utilities have been in contact with lawmakers and are mobilizing a strong effort on the liability and cost recovery issue.
Picker asked the legislature for more guidance on the principle of “inverse condemnation,” the legal provision utilities use to recover wildfire costs. The principle states that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.”
Picker told RTO Insider that CPUC’s interpretation of inverse condemnation could lead to lengthy litigation, while the legislature can take quicker action.
And the money at stake in that proceeding does not include additional potential liability for billions of dollars of costs from devastating fires that raged across California in 2017, the causes of which are still under state investigation.
Fitch Ratings on Monday downgraded PG&E to BBB+ and placed it on negative credit watch, while also putting Edison International subsidiary Southern California Edison on credit watch based on wildfire risks. In addition, utilities are facing multiple civil lawsuits over the fires, and analysts are also scrutinizing the credit ratings of California cities and localities, according to press reports.
Utilities and Energy Committee Chairman Chris Holden (D) told Picker he plans another conversation on inverse condemnation, as well as discussions on “new legislation that gives you new direction on what the good, the bad and the ugly of what that represents.”
“This will not be the first and last discussion we will have on this topic,” Holden said, later adding that, “we are all trying to get our arms around the issue and how it has so many different components to it.”
Holden said that when the legislative session ended last year, “this was not necessarily the topic I thought was going to take up all the energy for us.” He is also leading a separate effort to spearhead the regionalization of CAISO. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
Speaking at the hearing, CPUC Director of Safety Elizaveta Malashenko said preparedness and rapid response are keys to preventing disasters. Utilities are using new data collection technologies and practices to prevent fires, for example by proactively de-energizing lines for risk reduction, a program CPUC approved for SDG&E.
“When you are talking about wildfires, you are talking about a race against time,” Malashenko said. The CPUC has increased its information sharing with the California Department of Forestry and Fire Protection, she said, and is investigating utility involvement in the 2017 fires. “It has been a very fruitful relationship,” with Cal Fire better preparing for and responding to fires, she said.
How should New York set carbon prices — and who should be tasked with doing it?
Those were questions the state’s Integrating Public Policy Task Force (IPPTF) began to tackle Monday in “Track 3” of the group’s effort to integrate carbon pricing into NYISO’s wholesale electricity market.
The group also touched on issues related to “Track 4,” which covers the specific interactions of carbon pricing with other state and regional programs, such as the renewable energy credit (REC) and zero emissions credit (ZEC) programs, as well as the Regional Greenhouse Gas Initiative (RGGI).
The effort to price carbon into the state’s wholesale electricity market is a joint effort by NYISO and the state’s Department of Public Service (DPS) (17-01821).
in real 2017 terms. | UK Dept. for Business, Energy & Industrial Strategy
On pricing, stakeholders at the IPPTF debated whether to use a nominal value of $1/ton or $40/ton in their calculations for a carbon charge — or whether the debate was a waste of time given that the state’s Public Service Commission (PSC) would ultimately decide the number.
Representing New York City, Couch White attorney Kevin Lang suggested participants examine different sources for a social cost of carbon, both international and national.
“If we’re trying to get something that is valid through time, not just through two or three years, but over a longer time period, hopefully we can look at what the different sources are and come up with something that is a little bit more rational and perhaps a little more stable or less volatile than politically influenced numbers,” Lang said.
Ben Carron, National Grid’s senior analyst for regulatory strategy and integrated analytics, said the price should be based on the cost of abating emissions, since abatement is the goal of the public policy.
“Doing a locational analysis would also be appropriate because in order to get an abatement cost, obviously it will cost different amounts to build renewable generation than to abate carbon in different areas, like upstate,” Carron said.
Carron said his company could envision “something like a renewable net [cost of new entry] with a renewable demand curve that sets the cost of carbon in a given area, which would not only provide a more efficient price, a locational cost of carbon abatement but also provide the price signal for transmission build that would be necessary to truly evaluate whether or not it was an efficient investment.”
Marc Montalvo, of the DPS Utility Intervention Unit, said it makes sense for stakeholders to “seed our thought process” with various sources related to social cost of carbon, but that the price would ultimately come down to “the minimum charge that achieves the [Clean Energy Standard] objectives. … and analytically we should be trying to determine what that number is.”
New York City Deputy Director for Infrastructure Susanne DesRoches said, “Those goals and objectives from the CES need to be clearly defined as to what the carbon charge is trying to solve for. You can look at other models and look at what their goals are, what they were trying to solve for, and how those structures supported that end goal, but without a clear understanding of what this effort is trying to solve for, I think it will be difficult to put a number on the cost of carbon.”
Warren Myers, DPS chief of regulatory economics, said the PSC would be setting the price of carbon in another forum.
“So, debating abatement versus damage costs, I don’t think is that relevant here [and is] only [relevant] to the extent that it influences the straw level of carbon pricing we use for our modeling efforts,” Myers said, adding that the PSC is at least likely to “listen to our arguments about abatement costs.”
REC, ZEC, and RGGI
Speaking about how pricing carbon might interact with other state and regional programs such as REC, ZEC, and RGGI, Power Supply Long Island Director of Wholesale Market Policy David Clarke, asked whether RGGI impacts would diminish the effect of carbon pricing in New York.
“We would need to reduce the RGGI targets to reflect the impact of the carbon pricing as well as CES … otherwise, RGGI itself would see a lower price, absent a ratcheting down of the RGGI requirements,” Clarke said. “Other folks outside of New York would be able to emit more, taking back some or all of the requirements. This is one where you need to think through this and make sure we don’t have the takebacks associated with not reflecting any carbon pricing in the RGGI requirements.”
Representing a coalition of large industrial, commercial, and institutional energy customers, Couch White attorney Michael Mager said, “From a consumer perspective it’s a clear windfall on double payments. Despite arguments by some parties, including us, the commission time and time again has gone ahead and forced customers to bear the brunt of 20-year fixed contracts, where we are paying for carbon-free emissions under contract.”
One of the main purposes of the PSC moving to competitive electricity markets is to shift the risk of generation ownership from consumers to developers and owners, who willingly choose those risks, he said.
“There will be risks, there always will be, but lately one by one a lot of these risks are being shifted back onto consumers, despite the original intent,” Mager said.
If the RGGI system shifts all New York’s carbon reductions to the other RGGI states “and there’s essentially zero or hardly any carbon reduction from this, then whatever the price tag is, it’s probably too high,” Mager said.
Myers said one stakeholder concern is that “we add through policies, regulations, and government an externality price to the wholesale market … if the development community doesn’t know if they can trust this policy to hang around for more than a year or two, you could be kidding yourself on not paying twice even with future contracts.”
IPPTF Co-Chair Nicole Bouchez, NYISO market design specialist, said the group would next meet to discuss Track 3 on April 16 and Track 4 on May 14, with the goal of delivering recommendations by October.
Bouchez also noted that there would be no IPPTF meeting March 5 but that the task force would next reconvene at NYISO headquarters on March 12.
