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.
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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.
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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.)
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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.
Utility executives have criticized CPUC’s decision to deny San Diego Gas and Electric $379 million in cost recovery stemming from 2007 fires, rejecting the utility’s inverse condemnation argument. (See Wildfires Color California PUC Utility Decisions.)
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.
Sempra Energy announced Monday that the U.S. Bankruptcy Court for the District of Delaware has confirmed a reorganization plan for Energy Future Holdings, including the California company’s $9.45 billion acquisition of EFH and its 80% interest in Texas utility Oncor.
“Today’s action by the Bankruptcy Court paves the way for EFH to end its long-running bankruptcy case and advances our proposal to acquire a majority stake in Oncor to the final stage,” said Sempra CEO Debra Reed in a statement.
Sempra still needs to win the approval of the Texas Public Utility Commission, which is expected to consider an order approving Sempra and Oncor’s joint change-in-control application as early as March 8. The PUC on Feb. 20 canceled a hearing on Sempra’s proposed merger and asked staff to prepare a final order in the proceeding (Docket No. 47675). (See Sempra Moves Closer to Securing Oncor Acquisition.)
Sempra said it plans to close the transaction “soon” after PUC approval. The company became the fourth serious suitor to pursue Oncor, Texas’ largest electric utility, when it was able to shove aside Berkshire Hathaway Energy in August. (See Sempra Outmuscles Berkshire for Oncor.)
Previous acquisition attempts by Hunt Consolidated and NextEra Energy fell apart before the PUC.
EFH’s Texas roots are deep. It was known as Texas Utilities and then TXU before it was acquired in a 2007 leveraged buyout by EFH and its consortium of private-equity investors. The deal went sour when energy prices collapsed, and EFH filed for bankruptcy in April 2014.
In 2016, EFH disposed of its generation (Luminant) and retail (TXU Energy) businesses in a tax-free spinoff. The companies are now under the Vistra Energy umbrella. (See Luminant, TXU Energy Emerge from Bankruptcy.)
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week failed to reach agreement on how to classify Southern Cross Transmission (SCT) after debating the company’s bid to become the ISO’s first merchant DC tie operator.
TAC representatives and members will again take up the discussion during its March meeting, as part of an ERCOT legal staff effort to update the ISO’s bylaws and 18-year-old articles of incorporation. The proposed bylaw amendments include an attempt to place SCT in the appropriate membership segment.
The Public Utility Commission of Texas last year directed ERCOT to determine the best “market participation category” for SCT (Project No. 46304), which is behind an HVDC transmission project that would be capable of shipping more than 2 GW of electricity between the Texas grid and Southeastern markets.
During a September workshop, SCT proposed it be included within the Investor-Owned Utilities segment as an “independent DC tie operator.” It defined the classification as being appropriate for any entity that is not a transmission or distribution entity or an affiliate of a T&D entity, or for entities that own or are preparing to own or operate “a DC tie to be interconnected to the ERCOT transmission grid.” (See “Southern Cross Offers Suggestions for its Market Participation,” ERCOT Briefs.)
ERCOT’s legal staff pointed out that SCT does not fit within the “currently defined” segments and said one of the existing definitions within the bylaws would have to be amended to accommodate an entity “whose ERCOT-based activities are limited to owning or operating a [DC] tie” interconnected to the ERCOT grid.
In a 12-page memo, staff recommended that the TAC consider the IOU and Independent Power Marketers segments as appropriate for SCT. “The activities of typical members in these two segments more closely align with those of SCT than the activities of typical members” in other segments, they wrote.
ERCOT does not currently include DC tie operators as market participants. Three of its IOU members — American Electric Power, Oncor and Sharyland Utilities — operate ERCOT DC ties as “electric utilities” or “transmission service providers.”
Staff said they believe they have a directive to move the issue forward, and plan to bring a recommendation to the Board of Directors’ Human Resources and Governance Committee in April.
“At some level, the choice that gets made here is just a name,” said Cratylus Advisors’ Mark Bruce, who represents SCT. “What it boils down to is, are you a member? Do you have a role in corporate governance? Are you able to cast an individual vote as a member? Those are particular areas where having a corporate membership in the organization affords you a right — and it’s an important right.”
Like ERCOT staff, Oncor has suggested that a DC tie operator, “if such a member does not fit in any other classification,” should participate in the market as an IPM. That segment includes entities that are not transmission/distribution service providers (TDSPs) or affiliates of a TDSP, and are registered at the PUC as power marketers in ERCOT.
Liz Jones, legal counsel for Oncor, compared the discussion to a “big ol’ game of keep-away.”
“[One segment] says not us, other segments say not us,” she said. “ERCOT segments are founded on the notion [that] IOUs should not be running the market. The fact we own transmission, in and of itself, is not distinguishable, because the end-use transmission customers also own transmission elements.
“We, coupled with the NOIEs [non-opt-in entities], are the foundation of the open-access market,” Jones continued, referring to cooperatives and municipally owned utilities that offer customer choice in ERCOT. “I do not think it is consistent with the community interest to include Southern Cross in the IOU segment. We have previously found a home for misfit children. I’m sure neither Southern Cross and the power marketers will be particularly thrilled, but that’s not enough of a reason to throw them into the IOU segment.”
“Southern Cross does not really have religion,” Bruce reiterated. “It’s just a name and a way to get a vote. As long as we get a vote, it doesn’t matter. On the other hand, optics matter. Being called a power marketer when you don’t market power is awkward.”
SCT foresees qualified scheduling entities (QSEs) buying capacity from it just as they do from the ISO’s existing five DC ties. The company would not participate in the settlement process, but the QSEs would. SCT would not have a Texas tariff or collect transmission rates, leaving the QSEs responsible for paying transmission service charges for use of the ERCOT system.
“If the Southern Cross DC tie was located 1 inch further west than planned, it would be a Texas utility and a TSP [transmission service provider],” Bruce said.
He noted that because the tie is not in the state of Texas, SCT is an electric utility under federal law, with a FERC code of conduct and an open access tariff. Bruce said that the fundamental feature of power marketers is that “they take title to the electricity they buy and sell. Southern Cross will not buy or sell energy and will not take title to power.”
“Southern Cross will do the exact same thing at a DC tie that AEP does, that Sharyland does,” he said. “Southern Cross will follow ERCOT instructions to net out approved e-Tags and provide open access to the ERCOT system.”
SCT obtained FERC approval in 2014 for interconnection to and transmission service in ERCOT that maintains the ISO’s jurisdictional status quo.
The project would link ERCOT to the Eastern Interconnection through a 38-mile, 345-kV line owned by Garland Power & Light that connects with a converter station just across the Louisiana border. SCT would build a 400-mile, 500-kV DC line to connect with Southern Co.’s existing 500-kV system in Alabama.
The PUC last May approved Garland’s application for the 345-kV line, which has an established route (Docket No. 45624).
Members Reject Appeal from Small Municipalities
Members unanimously rebuffed an appeal of a rejected change to the ISO’s Nodal Operating Guide regarding the definition of transmission owners, with some saying the decision should be left to the PUC.
“I think we’re the wrong body to handle this,” said Citigroup’s Eric Goff. “I’d like it to go the commission as soon as possible.”
Tom Anson, legal counsel for the Small Public Power Group of Texas (SPPG), said the group has an agreement with the PUC’s enforcement staff to pursue the rule change, and would instead take its appeal to the ERCOT board, which next meets in April.
The revision request (NOGRR149) would exempt municipal distribution service providers without transmission or generation facilities from having to procure designated TO services from a third-party provider if their annual peak load is less than 25 MW. The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW.
The cities of Goldsmith and Bartlett, with a combined peak of less than 4 MW, have since joined the SPPG appeal.
The group has been filing regular monthly progress updates with the TAC. Anson refreshed the committee on the group’s most recent status report, which indicated none of the municipalities has been able to reach an agreement with its TSP.
“As a group, some of them have been able to make more progress than others … but none of them have a permanent [market] solution in place today,” Anson said, acknowledging the committee’s concerns over the lack of progress. “TAC asked us to look at potential market solutions, and we have done that. Whether it’s a potential market solution with third parties or some other solution, it can’t happen overnight. We’re dealing with other parties who sometimes are dealing with other parties.”
Anson proposed several alternatives to finding market solutions for the SPPG members, including a “TO light” category representing small systems that would get a partial exemption to a lower level of standing within ERCOT. However, none found favor with the TAC.
“You have asked SPPG members to pursue market solutions, and they have done so,” Anson said. “If you decide nevertheless to have a vote today, to me, that is essentially determining there are no sufficiently available market solutions.”
“It frustrates me that this revision request isn’t what we want, which is to exempt [municipalities] from load-shed obligations,” Goff said. “I understand why it’s complicated. Why would you want to pay for something that’s expensive for the size of the customer? Not that there aren’t any options, but it would be worth pursuing those in another venue.”
“We can’t be on the record for supporting an appeal that exempts someone from the market,” said Austin Energy’s Barksdale English. “We all have our obligations, and we have to meet them.”
The appeal was tabled for six months when brought to the TAC in March 2016, shortly after it failed to pass the Reliability and Operations Subcommittee. (See “Small Municipalities’ Appeal Tabled Again,” ERCOT Technical Advisory Committee Briefs: Aug. 24, 2017.)
Eight members, representing cooperatives, municipalities and independent generators, abstained from the vote, which led to a five-minute recess to review TAC’s bylaws. Eventually, ERCOT staff and TAC Chair Bob Helton determined there had been enough votes from the 22 remaining members to reject the appeal.
Committee Endorses Task Force Restructuring Recommendations
TAC members unanimously endorsed a task force’s recommendation to designate the Commercial Operations Subcommittee (COPS) and several of its working groups as inactive, and to move its remaining groups to other subcommittees.
The TAC Subcommittee Restructuring Task Force (TSRTF) noted that COPS was created to focus on “substantial and urgent” market communication and settlement issues, but it has now reached a “steady state concerning those issues.” Designating the subcommittee as inactive will protect access to historical information and allow for its reactivation, if necessary, the task force said.
The TSRTF and COPS agreed to also designate the Communications and Settlements and Market Data working groups as inactive, with some of their responsibilities inherited by other subcommittees. Settlement discussion items will move under the Wholesale Market Subcommittee.
As part of its work, the task force looked at the Retail Market Subcommittee (RMS), which, after meeting with the task force, agreed to move the Advanced Metering Working Group to inactive status and distribute several COPS duties to its other working groups. The RMS would also inherit and deactivate COPS’ Profiling Working Group.
The task force hopes to complete its work reviewing and modifying the TAC and its subcommittee procedures and voting structures, so it can make a formal recommendation to the board in April.
Although COPS may be living on borrowed time, the TAC confirmed its 2018 leadership and goals. Heddie Lookadoo (Reliant Energy Retail Services) and John Moschos (Tenaska) serve as its chair and vice chair, respectively.
TAC Unanimously Approves Slim Set of Revision Requests
The committee unanimously approved two NPRRs and two changes to the Resource Registration Glossary (RRGRRs):
NPRR854: Allows NOIE TDSPs to submit meter data for NOIE points of delivery, rather than incurring the expense of installing, testing and maintaining an ERCOT-polled settlement meter, resulting in decreased expenses for both the NOIE and ERCOT.
NPRR860: Clarifies certain day-ahead market practices and cleans up protocol language to better match the current implementation, including clarifying 1) the language for offering in three-part supply offers and ancillary service offers for offline non-spinning reserve in the same hour for day-ahead consideration; 2) the self-commitment treatment of resources with only an ancillary service offer submitted for the day-ahead; and 3) the ancillary service offer resubmission rules. Also removes the reference to congestion revenue rights being co-optimized in the day-ahead.
RRGRR015: Clarifies glossary definitions and detailed descriptions of data fields to help market participants successfully submit their resource asset registration forms (RARFs). The change does not add or delete any data requirements, does not require a revision of the existing RARF form and does not require resubmission of previously submitted data already accepted by ERCOT.
RRGRR016: Provides amplifying direction to RARF users for completion of certain solar data and narrows the data in order to provide solar forecasters with more precise data.
In a potential win for PJM ratepayers and demand response providers, FERC on Friday ordered a technical conference to consider whether the RTO should move from a year-round to a seasonal capacity construct (EL17-32, EL17-36).
The commission ordered the conference in response to two complaints: one from the Advanced Energy Management Alliance, and a combined filing from Old Dominion Electric Cooperative, Direct Energy and American Municipal Power.
The order calls for the conference to address whether:
the exclusive use of a year-round capacity product raises customer costs unnecessarily compared to retention of a seasonal capacity product;
standalone participation by seasonal resources in non-summer months would jeopardize reliability;
alternative models, such as establishing distinct summer and winter capacity markets, could assure reliability at lower costs;
if it is true that nearly all loss-of-load-expectation (LOLE) risk currently exists in 10 summer weeks, there is an alternative distribution of LOLE risk that could meet the one-day-in-10-years reliability target at a lower total cost; and
PJM’s load forecast methodology incorporates load-serving entities’ peak-shaving actions in an adequate and timely manner to yield just and reasonable rates for consumers.
The order indicates that FERC is having second thoughts about PJM’s year-round Capacity Performance construct — even before the rules have been fully implemented.
PJM proposed CP, which eliminated summer-only DR, to address generator outages that peaked at 22% during the January 2014 polar vortex. The rules call on all resources to be able to respond to dispatch calls throughout the year and requires the RTO to contract for enough year-round capacity to meet its annual demand peaks in the summer. The rules also subject resources to stiff financial penalties if they fail to perform during critical periods known as “performance assessment” intervals. But much of the capacity goes unused in the periods of lower demand: Summer peaks can top 150 GW, while the winter typically peaks at less than 100 GW.
| PJM
Under PJM’s transition, “base capacity” resources that operate only in certain seasons, such as renewables and DR were phased out. Only CP resources were permitted in last year’s Base Residual Auction, which procured capacity for the 2020/21 delivery year.
The two complaints offered different justifications, but both asked FERC to delay full implementation of CP and continue to allow base capacity resources until rules are developed to allow meaningful participation from seasonal resources. The Pennsylvania Public Utility Commission filed comments in support of their arguments.
AEMA pointed out recent analysis from PJM that showed that the RTO could increase its summer requirements by roughly 500 MW to allow more than 17,000 MW of annual capacity to be replaced by less expensive summer-only resources, and that an additional unit of summer-only capacity has 97% of the reliability value of an additional unit of year-round capacity.
“Once base capacity resources are eliminated, customers will need to pay for tens of thousands of megawatts of unnecessary capacity in non-summer weeks to compensate for the loss of base capacity resources during the peak summer period,” the commission wrote, summarizing AEMA’s argument.
PJM and several generators opposed the complaints, arguing they don’t bring up anything new and aren’t justified. They said the RTO had provided an ample opportunity for participation by seasonal resources. In a separate order last week, FERC approved Tariff revisions that allow offsetting seasonal resources to aggregate into a single, annual product that conforms with CP’s requirements. (See related story, FERC Endorses Previously OK’d PJM Aggregation Rules.)
FERC sided with the complainants.
“Capacity Performance has now been in effect for two years, and the complainants have raised important issues as to whether certain aspects of the construct are performing as well as expected,” the order said. “Complainants present analyses prepared by PJM which call into question the assumption that permitting any standalone participation by seasonal resources would negatively impact reliability in non-summer months.”
FERC Chairman Kevin McIntyre and Commissioner Robert Powelson, former chairman of the Pennsylvania PUC, did not participate in the order. Of the three other commissioners, only Cheryl LaFleur was on the panel when it approved CP in 2015.
PJM said Monday that its generation fleet performed much better in this New Year’s cold snap than during the 2014 polar vortex, but that high uplift costs during the event signal the need for its proposed pricing rule changes.
The RTO’s report on the Dec. 28, 2017, to Jan. 7, 2018, cold snap noted that temperatures were higher and customer demand lower than in 2014, although it did record its sixth highest winter peak on Jan. 5, when demand hit 137,522 MW in the 6-7 p.m. hour.
PJM reported a maximum of only 23,751 MW of forced outages during the 2017-18 cold snap, a little more than half the 40,200 MW lost at the peak of the 2014 polar vortex. | PJM
It reported a maximum of only 23,751 MW of forced outages (12.1% of total capacity) on Jan. 5, a little more than half the 40,200 MW lost on Jan. 7, 2014 (22% of capacity). The report echoed the message CEO Andy Ott delivered to a Congressional hearing in January. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“PJM did not call a performance assessment interval, a 72-hour maintenance recall or any transient shortage intervals. … Even during peak demand, PJM had excess reserves and capacity,” the report said. “Many factors drove this improved performance. In addition to the milder weather, these include enhancements PJM and its member companies have put in place in the years since the polar vortex, such as increased investment in existing resources, improved performance incentives, enhanced winterization measures and increased gas-electric coordination.”
However, PJM’s operators dispatched many generators that did not set LMPs, resulting in average uplift charges of $4.3 million per day during the peak of the recent cold, 11 times the normal average of $389,000 per day.
PJM incurred $47 million in uplift during this year’s cold snap. Uplift averaged $4.3 million per day during the worst of the cold, with one day totaling almost $9 million. | PJM
“On these days when the system is under additional stress, the actions the operators take to ensure that reliability is maintained are often not reflected in the transparent clearing prices. This problem, clearly evidenced by the cold weather experience, highlights the need for PJM and its stakeholders to evaluate reforms to address this issue in a timely manner,” PJM said. “These reforms include enhancing the manner in which reserves are procured and priced so that all operator actions are included in price signals and enhancements to the calculation of locational marginal pricing.”
PJM said it received cost-based energy offers exceeding $1,000/MWh between Jan. 3 and Jan. 7, but that “due to system conditions,” the resources did not receive day-ahead awards or run times during each of the operating days.
In December, PJM won stakeholder endorsement for creation of the Energy Price Formation Senior Task Force, which is considering rule changes to ensure prices accurately reflect the cost of serving load and minimize the need for uplift. The task force is scheduled to hold its fourth meeting March 5.
The report said PJM needs to continue improving its gas-electric coordination “to include improved contingency modeling and improved information sharing with local distribution companies.”
“Another area of fuel security that needs additional analysis, and potentially additional tools for operators and owners, is tracking and transportation of fuel oil supplies. While oil is typically a backup resource, PJM resources used more oil during the cold snap, which stressed some resources and supplies,” the RTO said.
A key California lawmaker is seeking comment this week on a revived effort to regionalize CAISO and create a multistate Western RTO, an effort that has sputtered over the last two years.
State Assemblymember Chris Holden (D), chair of the Utilities and Energy Committee, is taking public comment through Wednesday on proposed amendments to AB 813, which would authorize CAISO’s Board of Governors to develop a governance proposal for an RTO that would eventually allow California to relinquish its direct oversight of the grid operator.
The bill stipulates that the plan would then be submitted to the California Energy Commission, which — along with the California Air Resources Board — would review the proposal and also take public comment. If the CEC determines the proposal complies with the law, and if one or more transmission owners signs an agreement to join the new RTO, CAISO would be authorized to implement the new governance structure.
“Composition of the new board would not trigger until CEC approval and an agreement with at least one new balancing authority to join,” committee staffer Kellie Smith told RTO Insider in an email.
The proposal would provide for the establishment of a Western States Committee with three representatives from each state with TOs in the new RTO to provide input. According to the bill’s language, states would preserve their authority over member balancing authority areas, including procurement policy, resource planning and generation, and transmission siting within their states.
Holden led a similar effort last year, but it stalled along with separate legislation that would establish a 100% zero-carbon energy requirement for utilities in the state. (See CAISO Regionalization, 100% Clean Energy Bills Stall.)
While some industry interests favor regionalization to create a wider market for power generation, California labor unions have expressed concerns that the effort could export jobs to other states, and some state officials also worry about losing control over the state’s aggressive renewable and climate change policies.
Regionalization has been a longstanding goal of Gov. Jerry Brown, who is serving out his last year as governor ahead of this November’s elections. Two years ago, he put the effort on hold because of unresolved questions from critics both inside and outside California. (See California Lawmakers Take Up CAISO Expansion.)
The new amendments also stipulate that a Western RTO “not endorse, organize or operate a centralized capacity market in California for the forward procurement of electrical generating capacity that requires capacity to clear at a market clearing price in order to count for resource adequacy purposes.” It also calls for equitable transmission cost allocation rules, creation of an independent market monitor and voluntary participation by TOs.
“The ISO has thoroughly studied the benefits a regional grid has to offer and looks forward to providing any information to the Legislature, including Assemblyman Holden, as the measure moves forward,” CAISO told RTO Insider. “A regional approach is critical to supporting renewables, as energy leaders and environmentalists have noted about European experience, where many nations there leverage low-carbon resources through a single, coordinated grid.”
Changes Across the West
The restart of the regionalization effort comes amid several developments that could reshape the wholesale electricity industry in the West. Since late last year, CAISO has kicked off efforts to expand its day-ahead market across the Western Energy Imbalance Market (EIM) and depart Peak Reliability to become its own reliability coordinator (RC) — as well as offer reliability services across the region. (See CAISO to Depart Peak Reliability, Become RC.)
On Monday, the Bonneville Power Administration and Western Area Power Administration separately announced they have signed nonbinding notices signaling their intent to depart Peak Reliability by the end of 2019. BPA said it is exploring receiving RC services from CAISO, while WAPA is considering SPP’s RC services for its Upper Great Plains West and Western Area Colorado Missouri balancing areas, and SPP and CAISO for its Western Area Lower Colorado area.
“Our balancing authorities cover an expansive area in the West. Each has unique circumstances and requirements that we will respect when seeking the best possible RC for our operations and our customers,” WAPA Administrator Mark A. Gabriel said in a statement. “As we explore the best path forward for each of our BAs, the reliability of the grid will remain our top priority.”
Peak Reliability and PJM have also announced an effort to create a new western energy market, an effort the companies say will not be an RTO. (See Peak, PJM Pitch ‘Marketplace for the West’.) Peak has been the provider of RC services in much of the West since 2014.
