Search
`
November 8, 2024

Posted on

FERC Splits on Waivers from SPP IC Process

FERC last week settled a pair of disputes over waivers from SPP’s generator interconnection procedures (GIP), approving one and denying the other.

The commission reaffirmed Lookout Solar Park’s request for a limited waiver of the GIP’s financial security cure period and posting requirements in responding to SPP’s rehearing request (ER21-1841). However, the agency also denied Invenergy’s request for a prospective waiver from GIP security posting requirements (ER21-2807).

In the first Dec. 1 order, FERC found that the waiver request it granted Lookout Solar earlier this year satisfied the commission’s criteria for granting waivers in that the request did not harm third parties or have undesirable consequences. It clarified that the waiver order extended Lookout Solar’s timeline to either make the applicable financial security payments or withdraw from the generator interconnection queue.

Lookout Solar is developing a 110-MW solar facility in South Dakota and entered the SPP GI queue in 2017. It said in its waiver request that the grid operator posted the results of its definitive interconnection system impact study (DISIS) queue cluster on Oct. 30, 2020, but then reposted revised results on Nov. 20, 2020, triggering a requirement that Lookout Solar post about $16.9 million in financial security.

Proposed-Lookout-Solar-Park-(WAPA)-Content.jpgThe proposed Lookout Solar Park in South Dakota. | WAPA

The developer disputed the revised obligation and said it had reached an agreement via email with SPP that further modified the obligation to $8.1 million. The RTO posted additional study results in April allocating Lookout Solar $181.6 million in upgrades and requiring $28.1 million in financial security. SPP subsequently notified the cluster’s customers that it had identified errors in the DISIS and extended the cluster’s next decision point until May 13.

The solar developer contended that SPP acknowledged that the study “appeared” to over-allocate certain upgrade costs to the facility. It said the RTO did not revise the reposted study results and ultimately told Lookout Solar that no substantive corrections were required.

SPP withdrew Lookout Solar from the queue and asked that it post its financial security amounts to restore its position, leading the developer to file its waiver request. FERC granted the request over SPP’s objections.

Commissioner James Danly concurred separately with the order but expressed his “continuing concern” over the “innumerable” waiver requests FERC grants and reiterated that the commission “must be sparing in its liberality.”

Invenergy Issue not ‘Concrete’

The commission found that Invenergy did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver” in the second order.

The renewable developer said it had eight interconnection requests pending in the same DISIS queue cluster as Lookout Solar. It alleged that SPP said the DISIS study would need to be redone because higher-queued requests were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.

Invenergy said that faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.

FERC said Invenergy did not show that its potential loss of its posted financial security was a concrete problem warranting a waiver from SPP’s tariff. It said there was not sufficient detail to demonstrate that an IC customer having to make decisions and provide financial security based on information it views as unsatisfactory warrants granting the waiver.

The commission also said Invenergy’s waiver request is distinguishable from Lookout Solar’s request in that the agency relied on undisputed allegations in the record of SPP’s inconsistent communications and actions.

Commissioner Mark Christie dissented from both orders, saying that after reading the Lookout Solar rehearing order, he could “reach no conclusion other than that today’s [second] order unduly discriminates against Invenergy in an unlawful manner.”

He said there is no “rational basis” for distinguishing between Invenergy and Lookout Solar and said the decision to deny Invenergy’s waiver on “thin factual differences is mystifying.”

“Today the commission relies on semantics to get itself out of the mess it inevitably made by granting the initial waiver in Lookout Solar — the result of which is to put Invenergy (and presumably any subsequent waiver applicants in the cluster) at a patently discriminatory commercial disadvantage to another member of the queue without any rational basis to distinguish the two waiver requests,” Christie wrote.

Posted on

SEIA Policy Forum Asks ‘To RTO or not to RTO?’

WASHINGTON — Organized power markets have proven their worth over the past 20 years, but former FERC Commissioner Tony Clark says that doesn’t mean RTOs are the best choice for states in the West and Southeast seeking regional cooperation and reliability.

A senior adviser at Wilkinson Barker Knauer, Clark said RTO membership should be a state decision. “As we move forward, are there third ways that are going to develop? It seems like there kind of are in ways that make sense for those regions,” he said at the Solar Energy Industries Association 30×30 Policy Forum on Thursday. He cited current discussions about regional resource adequacy in the Pacific Northwest and the Southeast Energy Exchange Market recently approved by FERC.

“To RTO or not to RTO?” was the question posed to Clark, current FERC Chair Richard Glick and former Commissioner Suedeen Kelly at the SEIA conference. The solar trade association has set a goal of solar providing 30% of U.S. power generation by 2030, and organized markets will be critical in that effort, said moderator Gizelle Wray, SEIA’s director of regulatory affairs.

Suedeen-Kelly-2021-12-02-(RTO-Insider-LLC)-FI.jpgSuedeen Kelly, Jenner & Block | © RTO Insider LLC

“Organized wholesale markets are the key to unlocking the cheapest, most reliable and affordable solar in the country,” Wray said. “We have seen time and time again that wholesale markets provide our members — independent power producers — with opportunities that are not afforded in vertically integrated states. At the moment, only organized wholesale markets are capable of providing the long-term certainty that clean energy businesses need to deploy solar and storage at scale.”

Glick said he favors RTOs and the benefits they provide in terms of economies of scale and regional power integration and reliability, but mandating their formation raises some thorny issues of jurisdiction. While he believes FERC does have the authority to mandate RTO membership for Western states, any such effort would not apply to municipal and public power utilities — such as the Bonneville Power Authority or the Los Angeles Department of Water and Power — which are outside of the commission’s authority.

“I think we need to encourage RTO development,” Glick said. “I think the time is now to act. We see the threats due to weather [and] the lack of resource sufficiency in certain areas. If [the states] don’t start working together, I think we’re going to see some calamitous issues.”

Kelly, partner at Jenner & Block, also underlined the advantages of RTOs — creating large, integrated transmission networks that foster reliability and eliminate unnecessary costs — but, like Clark, she saw the need for more flexible market structures. The West’s Energy Imbalance Market, while valuable, does not include a transmission component, she said, which makes it inefficient and difficult for “people in Santa Fe or Albuquerque to get an electron from California because they have to go through all the transmission [issues].”

“The states in the West come at this at a time when they’ve seen a history of how RTOs work,” Kelly said. “Most of those states want to see more renewables and a cleaner electricity mix. They have the opportunity to create an RTO that is not a cookie cutter, and my sense is that this FERC would be open to a construct that is not cookie cutter; rather [one] that is designed to achieve the goals” of those states.

Flexibility and False Dichotomies

The hundreds of gigawatts of solar and storage projects in interconnection queues across the country are, Wray said, “stuck in a perpetual waiting room because the transmission pathways to the markets are not being built.”

“This is not acceptable if we want to deploy a record amount of solar across the country,” she said. “We want FERC to reform the transmission planning process to include interconnection. Right now, renewable energy generators are left guessing which projects are needed and where, and these reforms will help to clarify the process and send the right market signals.”

Glick said changes to transmission planning are major priorities at FERC, with the Advance Notice of Proposed Rulemaking potentially providing solutions to bottlenecked interconnection queues. He expects a proposed rulemaking “by early next year,” he said.

As more renewables come onto the grid, flexibility, along with reliability, will be a key issue, Glick said. “There are certainly lots of ways to handle reliability, but how do you attract, how do you encourage flexibility?” he said. “Whether it’s gas or storage, how do you encourage, how do you incent [it] so it’s adequately compensated for the value it provides to the grid?”

Tony-Clark-2021-12-02-(RTO-Insider-LLC)-FI.jpgTony Clark, Wilkinson Barker Knauer | © RTO Insider LLC

While agreeing that thorough-going changes are needed, Clark argued that RTOs are not the only answer, particularly for reliability. “There’s sometimes a false dichotomy that’s presented to public policymakers, which is on one hand here, we have markets and free enterprise and competition and that’s RTOs, and on the other hand we have big, bad old [state] regulation,” he said.

Drawing on his experience at FERC and as a state regulator in North Dakota, Clark said, “There’s as much politics and rent seeking and regulatory capture in the RTO stakeholder processes as we ever dealt with in the cost-of-service regime. So, what you’re really dealing with is a couple of different administrative constructs, both of which can utilize myths of competition, or elements of competition, to try to drive outcomes that are good for consumers.”

States with vertically integrated utilities may be better at ensuring capacity than those with restructured retail power markets, Clark said. “The reason is because if you need to retain that sort of dispatchability in your capacity, you just go to your state commission [and] you build it into rates,” he said. “It’s going to be a trickier situation in most regions that have transitioned away from that.

“In my mind, Texas is kind of the canary in the coal mine on that issue,” he said, referring to last winter’s power outages in the state.

Getting Rid of Barriers

Kelly noted that the U.S. has experimented with a range of market-making strategies. The Public Utility Regulatory Policies Act helped kick-start the commercial and utility-scale solar market, she said.

Creating markets through incentives could be the “advantageous” result of the Build Back Better Act, with its $555 billion in funding for tax credits and other clean energy programs, she said.

But FERC’s creation of the RTOs and wholesale power markets was “revolutionary” for the U.S., she said. Beyond economies of scale and cost savings, the deployment of new technologies was also a core driver for the initial formation of RTOs, she said. But at that time, combined cycle natural gas plants were the “new guy on the block” facing market barriers from vertically integrated utilities, she said.

The caveat, Kelly said, is that state participation in RTOs is “optional, but an option that I think everyone should have available to them. The more buyers and the more sellers that can come together in one place, the better.”

Glick said FERC’s role is to remove barriers to markets, such as the commission’s orders opening wholesale markets to demand response (Order 745) and energy storage (Order 841).

“But we have a lot more to do in terms of hybrid resources,” such as solar and storage projects, he said. “Are there market rules out there discriminating against hybrid resources? Offshore wind is another area we need to take a look at; are there barriers there we need to get rid of? That’s the prime objective the commission needs going forward: getting rid of barriers.”

Posted on

NJ Hearing Debates 300 MW Competitive Solar Solicitation

A plan that would put solar developers in a competitive bidding process for state incentives for their projects received a mixed reception at a Tuesday hearing before the New Jersey Board of Public Utilities. The state’s top consumer advocate expressed support for the plan, but solar advocates said the proposed process would inject too much uncertainty into project finance, which would in turn draw few bidders.

The main point of contention was the BPU’s proposed Competitive Solar Incentive (CSI) Program, under which developers of solar projects above 5 MW would have to participate in a competitive bid to set the level of payment they would receive for solar renewable energy credits (SRECs) for their projects. Both behind-the-meter and grid-tied projects above 5 MW could participate, and the BPU would rank the bids and award the incentives to the lowest bidder.

The goal of the CSI program is to add 300 MW of new solar to the state’s energy mix every year, reaching a total of 17 GW of capacity by 2035 and 32 GW of solar — about 34 % of the state’s electricity — by 2050. Developers say grid-scale projects will be essential to meet the state’s targets. According to figures from the Solar Energy Industries Association (SEIA), the state has about 3,739 MW of solar installed.

But Scott Elias, senior manager of state affairs, mid-Atlantic, for SEIA, questioned how many developers would be interested in participating in the CSI solicitations for large, net metered projects, given the preparation work needed, without knowing the size of the incentive in advance.

“It’s pretty impractical for developers to meaningfully engage in complex and lengthy power purchase agreement negotiations with an offtaker [solar power purchaser] without knowing the revenue streams that will be available,” Elias said.

However, Sarah Steindel, assistant deputy rate counsel at the New Jersey Division of Rate Counsel, welcomed the BPU’s effort to set the level of incentives by a market process, rather than staffers deciding the incentive levels, as was done in the past.

“Over the years, rate counsel has advocated for competitive processes as a tool to control the high costs of solar for New Jersey’s utility ratepayers,” she said. “We strongly support the current effort to let the competitive market tell us what levels of subsidies are truly required to meet the state’s renewable energy goals.”

Tuesday’s hearing was the first of several the BPU expects to schedule to gather public input on the competitive component of the board’s plan for reshaping New Jersey’s solar incentive system, which the board released in July. The BPU expects to complete the information gathering process by the end of the year and develop a program guideline proposal by the end of March 2022. Additional hearings on the proposal will then be held, with the goal of having a completed plan in late spring.

“We’re working with getting the maximum benefits to ratepayers at the lowest cost,” said Louisa Lund, project manager for Daymark Energy Advisors, the consultant hired by the BPU to help develop the CSI program. “We want to support the growth of the solar industry. We want to help New Jersey meet its renewable energy credit goals. And we want to have a transparent process.”

Shrinking Incentive Rates

Earlier this year, Gov. Phil Murphy signed the Solar Act of 2021, which created a new incentive program and competitive bidding process for projects above 5 MW, with the goal of encouraging larger-scale projects in the state. (See NJ Grid-scale Solar Bill Signed by Murphy.) A few weeks later, the BPU incorporated that program into a larger new program to revitalize solar sector incentives offered by the state.

The new program, known as the Successor Solar Incentive Program (SuSI), includes two parts: the CSI competitive bidding program and the Administratively Determined Incentive (ADI) program, providing incentives for net metered residential projects, net metered nonresidential projects of 5 MW or less, and community solar projects. The ADI program was not the focus of the hearing Tuesday.

The legislation created a new program of solar renewable energy certificates, SREC-II, to be reimbursed by the BPU for each megawatt-hour of energy produced, with a goal of deploying 3,750 MW of new power generation capacity by 2026. (See NJ Sees Solar Growth in Reduced Incentives.)

New Jersey awarded similar energy credits for more than a decade through the Solar Renewable Energy Certificate (SREC) Program, which paid about $250 per MWh of power generated. Concerns about that program’s expense led to the Clean Energy Act of 2018, which shut down the SREC program when solar generation hit 5.1% of the state’s electricity production. That cap was achieved in April 2020, after which the state created an interim program with transition renewable energy credits (TRECs) of about half the value of those in the original SREC program.

Under the new program, SREC-IIs will be awarded in both the CSI and the ADI programs, with the value of certificates set in the ADI program varying between $70 and $100 per MWh, depending on the type of project, with an additional $20/MWh for public projects.

About 60% of the new capacity is expected to be generated with incentives at rates set by the BPU, and competitive bids under the CSI program will account for the remainder, with an emphasis on non-greenfield projects.

“We know that there’s a preference in New Jersey for developing on the previously disturbed lands,” Carrie Gilbert, internal project sponsor for Daymark, told the hearing. “But we wanted to understand some of the particulars of developing on contaminated land and landfills: like, how is the development timeline different than maybe a greenfield project? Are there additional costs? What kind of information could you provide on the environmental benefits that might help us figure out a ceiling for additional costs?”

Other issues raised by the BPU staff for public input include whether SREC-II subsidies should be provided through administrative rules or contracts, and whether developers believe that either of the two systems has “any implications on project cost, risk premium or other aspects of project financing.”

Seeking Serious Projects

The BPU and Daymark highlighted several specific issues for public input at the forum, including

      • whether projects on contaminated land and landfills should get special consideration — and longer time frames for completion — due to their complexity;
      • how big a fee the agency should charge bidders to take part in the competitive solicitation;
      • what kind of barriers might prevent the participation of public agencies in the bid process — such as public procurement requirements, financing and rigid timelines — and how can the BPU shape the program to alleviate them.

Joe Henri, vice president of business development at Dimension Renewable Energy, a California-based developer of community solar projects, encouraged the board to set application fees and performance deposits at levels high enough to “discourage speculation” and ensure a pipeline of viable projects.

“Performance deposits tend to suck the speculation right out of the market,” Henri said. “Knowing that you have a nonrefundable deposit helps focus the developer. If it’s a substantial and meaningful deposit, it ensures that their financiers have been over the proposed project to make sure that it’s actually viable and has a chance to go forward and produce what it’s promising to produce.”

Elias, of SEIA, said that if the competitive bid program goes ahead, it should avoid awarding fixed SRECs, which might “not offer any energy revenue certainty to project investors.” Although the SREC value will not change, fluctuations in energy prices will mean the developer’s income from selling energy will vary as market prices go up and down, Elias said. To avoid that, he suggested that the BPU consider an “Index-REC,” like the one offered in New York and being implemented in Illinois.

In the proceeding for the New York rule, the American Wind Energy Association [now the American Clean Power Association] and the Alliance for Clean Energy New York filed a petition arguing for an indexed REC based on a reference market index that will change monthly over the life of a project contract. Indexed RECs would serve as a hedge against market volatility, lower the financing costs for renewable generators, and provide lower costs and less volatile prices for ratepayers, the organizations said. (See NYPSC Expands Energy Efficiency, Indexes RECs.)

Echoing that argument, Elias said, “Instead of staying fixed, the Index-REC price will go up or down depending on the direction of prices in the energy and capacity markets.” That ensures “a consistent amount of revenue for developers, and the projects can always get what they need. This basically de-risks the revenue for the developer and [independent power producer] and allows the REC bids to be much more competitive” because they don’t have to add in a safety margin to the bid to account for possible market fluctuations, he said.

Posted on

Vermont Energy Plan Targets 100% Zero-emission Car Sales by 2035

Vermont has released a draft comprehensive energy plan (CEP) for the state that aims to facilitate a clean energy transition in an equitable manner while keeping electric sector costs down.

Among the draft’s recommendations is to make all light-duty vehicles sold in the state zero-emission by 2035.

The plan would expand the state’s “aggressive” renewable energy target and adopt the state’s greenhouse gas reduction requirements, said TJ Poor, director of the Vermont Department of Public Service’s (DPS) Efficiency and Energy Resources Division.

“We also recognize that currently the burdens and the benefits of energy policy in the state have not been equitably distributed across the state or its people,” he said during a public stakeholder meeting for the CEP on Thursday.

The DPS must update the state’s energy plan every six years, and it will provisionally adopt the CEP in January after taking public comment on the draft by Dec. 20.

EV Sales

In the 2016 CEP, DPS set a goal of having 10% of vehicles in the state powered by electricity by 2025. By the end of 2015, there were slightly more than 1,000 electric vehicles registered in the state. The total in-state passenger vehicle registrations at the time was 550,000.

By 2017, passenger vehicle registrations had risen to 578,000, and by the end of 2020, just fewer than 4,000 were EVs, according to the Energy Action Network’s 2020/2021 Annual Progress Report for Vermont. And new passenger vehicle sales, the report said, averaged 38,500 annually between 2012 and 2020.

Of the vehicles sold in that period, a steadily increasing number were light passenger trucks or sport utility or crossover utility vehicles, reaching 85% in 2020. The state will face specific challenges in transitioning sales in those vehicle categories to zero-emission technologies in the near term.

All-electric SUVs and CUVs currently on the market range in price from $40,000 to $100,000, and light-duty trucks are yet to arrive. The draft CEP acknowledges that Vermont’s zero-emission vehicle goal is dependent on the national vehicle market, and the state should re-evaluate the EV sales goal regularly. It also suggests that Vermont can influence the national market by adopting California’s ZEV standards, which will help put pressure on vehicle manufacturers to produce more EVs.

In addition, Vermont’s state-level incentives for EVs are not available for models that cost more than $40,000.

“This presents a particular problem in rural areas of the state where [all-wheel drive] vehicles are a necessity,” the draft CEP said. “Higher incentive amounts will help accelerate the [plug-in EV] market, encouraging consumers to purchase EVs sooner than they might otherwise do so.”

Vermont also needs to incentivize development of a fast-charging network in advance of the passenger fleet’s ability to sustain it. The state is “a long way” from having the charging units needed to support electrification of the transportation sector, according to the draft CEP.

“To the extent funding is available, Vermont needs to substantially up its investment in [EV infrastructure],” the draft says. “This may need to include funding to operate fast-charging stations at unprofitable sites for a period of years until the market share of [plug-in EVs] increases enough to make these stations profitable.”

Other options in the draft plan for reducing transportation sector emissions include:

  • establishing an incentive program for electric medium- and heavy-duty vehicles;
  • determining the viability and cost-effectiveness of converting the state’s diesel transit bus fleet to electric;
  • encouraging utilities to include utility load management for home and workplace EV charging; and
  • encouraging utilities to offer rates that relieve fast-charging load from traditional demand charges.

Climate Plan Alignment

DPS staff worked closely with the Vermont Climate Council this year to ensure that the updated CEP would be in line with the council’s first Climate Action Plan (CAP). (See related story, Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)

The council adopted its initial CAP on Dec. 1, but Poor said the CEP and CAP “are distinct plans.”

Both plans target GHG reduction requirements set by Vermont’s 2020 Global Warming Solutions Act. And while they shared energy sector analyses and public engagement during development, the CAP addresses energy and non-energy sector emissions.

The CEP and CAP also share recommendations to:

  • adopt California’s Clean Cars II regulations;
  • expand existing state weatherization programs (The CAP target is 90,000 homes by 2030, while the CEP target is 120,000 homes by 2030.);
  • consider a clean heat standard;
  • expand the state’s 75% renewable portfolio standard to 100% carbon-free power (The CAP target is “no later than” 2030; the CEP target is by 2032.); and
  • continue to work with other jurisdictions on implementing the Transportation and Climate Initiative Program and consider participating in it.

Equity

For the first time, the CEP seeks to “root out and redress” inequities in the energy system that “continue to disproportionately impact many of Vermont’s communities,” Poor said.

A chapter on equity and injustice issues in the state leverages the work of the Vermont Climate Council’s Just Transitions Subcommittee in preparing the CAP.

The subcommittee’s work “really grounded the energy plan,” Poor said, noting that the draft CEP recommends that equity be centered in decision-making alongside cost and environmental issues.

Among the CEP’s recommendations for a just transition is a call for the DPS to develop a diversity, equity and inclusion strategy.

Posted on

OGE, CenterPoint Complete Enable’s Disposal

OGE Energy (NYSE:OGE) and CenterPoint Energy (NYSE:CNP) said last week that midstream energy company Energy Transfer Partners (NYSE:ET) has completed its acquisition of their Enable Midstream Partners gas-gathering partnership.

The $7.2 billion all-equity transaction was announced in February. (See Energy Transfer to Acquire Enable Midstream.)

OGE, which owned about 79% of Enable’s common units together with CenterPoint, will keep approximately 3% of Energy Transfer’s outstanding limited partner units with the transaction’s consummation. CenterPoint received about 201 million common units of Energy Transfer and $5 million in cash for its common units of Enable and general partner interest.

OGE CEO Sean Trauschke said in a statement that the acquisition “is an important step in OGE’s plan to become a pure-play electric utility.”

“We are now firmly on an accelerated path to reducing our exposure to the midstream industry,” CenterPoint CEO David Lesar said.

Enable was created in 2013 by merging OGE’s Enogex midstream subsidiary with CenterPoint’s pipeline and field services businesses. OGE held a 25.5% limited partner interest and a 50% general partner interest in Enable; CenterPoint owned 53.7% of the common units representing Enable’s limited partner interests.

In early 2020, OGE and CenterPoint took major earnings hits when Enable halved its quarterly distributions to investors and cut its capital expenditures for 2020 by $115 million. The cost reductions came during a global slump in petroleum demand and the COVID-19 pandemic. (See Enable Losses Slam CenterPoint, OGE Energy.)

Energy Transfer now owns and operates more than 114,000 miles of pipelines and related assets in all major producing regions in the U.S. and markets across 41 states.

Posted on

Michigan ROFR Bill Approved, Sent to Governor

LANSING, Mich. — Legislation granting incumbent transmission owners the right of first refusal to build and operate transmission lines in Michigan is on its way to Gov. Gretchen Whitmer (D) for signature after winning final legislative approval.

SB 103, which would benefit ITC Holdings and American Transmission Co., was sent to Whitmer by the Michigan Senate Thursday after the House approved the bill in a 71-29 vote late Wednesday.

Whitmer’s administration has said nothing about the legislation, which had bipartisan sponsors, including Democratic Sen. Curtis Hertel Jr., who succeeded Whitmer in the Senate. It was opposed by only a few Democrats.

Most of the 29 opponents in the House were the most conservative of the majority Republicans.  The most conservative Republicans opposed the bill in the Senate, which is also controlled by Republicans.

ITC-Michigan-Tx-Map-(ITC-Holdings)-Content.jpgITC Holdings’ ITC Transmission and Michigan Electric Transmission Co. serve most of Michigan’s Lower Peninsula through a network of about 8,700 circuit miles. The companies have made $5.5 billion in capital investments in the state since 2003. | ITC Holdings

The bill was unchanged by the House from the version passed in the Senate in October. (See Mich. Senate OKs Transmission ROFR for Incumbent TOs.)

The bill would apply to “regionally cost-shared” transmission projects, such as those resulting from MISO’s Transmission Expansion Plan. It takes advantage of the exception under FERC Order 1000 that allows states to create a ROFR. The order prohibited such rights in tariffs filed with the commission in a bid to create competition, although some incumbents have recently urged FERC to reverse the prohibition in the commission’s Advance Notice of Proposed Rulemaking proceeding. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

With the legislature pushing to finish the 2021 session this week, the House Energy Committee reported the bill on Tuesday, and it was rushed through its final readings on the House floor before passing.  There was no debate on the bill in the House.

John Dulmes, executive director of the Michigan Chemistry Council, blasted the legislation, calling Michigan’s electric costs a major barrier to attracting investments and jobs. “That’s why it is disappointing to see today’s vote to support the interests of a monopoly energy company instead of ratepayers. Our policymakers need to get serious about competitive energy policies and the high bills paid by our businesses and residents,” Dulmes said in a statement.

The state’s utility costs — some of the highest in the region — were cited as a reason Ford Motor Co. (NYSE:F) announced in September it was locating a major new electric vehicle factory in Tennessee.

The Chemistry Council was one of only a few vocal opponents to the bill.  The measure was backed by as many as a dozen groups, including labor groups and the Michigan Chamber of Commerce.

When the bill passed the Senate, the chief sponsor Sen. Wayne Schmidt (R ), said the state’s efforts to reduce carbon emissions through electrification will require more transmission in the state. The bill will help ensure a more orderly system to develop transmission, he said.

Whitmer will have 14 days to sign or veto the measure once she receives the proofed and printed version of the bill.

Posted on

Clements: FERC, States Need to Work Together

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783230.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

FERC Commissioner Allison Clements

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Clements-Allison-2018-01-23-RTO-Insider-FI.jpg” align=”left”>FERC Commissioner Allison Clements | © RTO Insider LLC

FERC Commissioner Allison Clements told the ISO-NE Consumer Liaison Group on Wednesday that the country’s energy sector is facing a “system challenge” from a rapidly changing resource mix that requires intelligent transmission planning and investment as part of the energy transition.

Any system problem needs a system solution, said Clements, who is focusing on ensuring that the commission and states work together “to embrace the full portfolio of solutions to unprecedented and formidable challenges.”

Clements said there is a “once-in-a-generation opportunity” to invest in new transmission that can contribute to cost-effective and reliable facilitation of a changing resource mix. When asked about the uncertainty surrounding the New England Clean Energy Connect (NECEC) transmission line, which would supply hydropower from Hydro-Québec to the New England grid through a 20-year supply agreement with Massachusetts utilities, Clements called it a “clear example” of the challenges related to siting new transmission.

On a subsequent panel, Michael Giaimo, Northeast regional director for American Petroleum Institute, said policymakers should not be so quick to retire existing fossil fuel infrastructure.

“My parents taught me that if you leave a job, make sure you have another job,” Giaimo said. “So, the analogy here is if you want to ensure a reliable power system at a minimum, you shouldn’t retire infrastructure until you are certain.”

Given New England’s policies intended to stimulate solar, wind and electrification, Giaimo said the region needs to have resources in times when renewables aren’t available and to account for the increase in nightly load for electric vehicle charging and residential heating. Additionally, he said, it’s essential to consider that existing gas infrastructure can help facilitate low-carbon fuels, like green hydrogen, in the future.

Dale Bryk, director of state and regional policies at the Harvard Environmental and Energy Law Program, said the region “can’t say ‘no’ to things when we don’t have a plan.”

“But we also can’t use the absence of a plan as a weapon to prevent ever changing anything,” Bryk said. “We have to stop digging the hole and stop investments in fossil fuel infrastructure that we know we have to abandon and build the solutions in a timely way so that we do have a just, equitable and orderly transition.”

“This transition is happening,” Clements said. “It’s not the commission’s job to plan it. It’s the commission’s job to facilitate it and protect customers and contribute to the assurance and reliability while it’s happening. That’s exciting. It’s like we’re the underlying nuts and bolts that are allowing the implementation to take place.”

Posted on

Entergy LA, NOLA Add Ida-related Debt

FERC last week authorized Entergy Louisiana and Entergy New Orleans to assume more than $15 billion in debt and securities to help recover losses incurred from Hurricane Ida’s destruction (ES22-7, ES22-8).

The orders allow Entergy Louisiana to issue up to $13 billion in long-term debt, $450 million in short-term debt and $300 million in preferred securities. Entergy New Orleans can issue up to $1.24 billion in long-term debt, $150 million in short-term debt and $40 million in preferred securities.

FERC said the long-term interest rate cannot exceed 6.775% and the short-term interest cannot exceed 4.5%.

Additionally, the Entergy subsidiaries can also issue $170 million and $25 million in letters of credit to post collateral and secure their participation in MISO’s markets.

Entergy said the late August hurricane inflicted anywhere from $2-$2.4 billion worth of damage to its Louisiana utility arm and $120-$130 million in damages to its New Orleans affiliate. The repair costs caused the utilities to surpass their debt ceilings ahead of their mid-July 2022 conclusion.

Entergy affiliates usually simultaneously file requests with FERC to issue debt, making the out-of-cycle requests unusual.

The new debt authorizations went into effect Dec. 1 and end Oct. 13, 2023.

Entergy reported damage to approximately 500 transmission structures, more than 225 substations, more than 210 transmission lines and nearly 6,000 transformers. Repairs to 30,500 distribution poles and nearly 36,500 spans of distribution wire were also necessary, the company said.

The staggering restoration costs led two commissioners to issue a warning of the increased financial damage related to climate change that ratepayers will bear.

FERC Chair Richard Glick and Commissioner Allison Clements wrote a separate concurrence urging their fellow commissioners to consider transmission investment as a means to hedge increasingly steep repair estimates.

Glick and Clements said while they agreed with Entergy’s need to issue debt and securities, they were writing “to underscore that this is another clear example of the deep costs of climate change and extreme weather, which will ultimately be borne by customers.”

The two pointed out that according to Entergy, the costs inflicted by Hurricane Ida were more than the combined costs of Hurricanes Katrina, Ike, Delta and Zeta.

“Hurricane Ida is just one of 18 climate-related disaster events with losses exceeding $1 billion that has affected the United States this year,” Glick and Clements wrote. “We expect that restoration costs following climate-induced extreme weather events will continue to grow, and for that reason, the commission should consider how prudent investments in transmission system planning can ultimately save customers money.”

Entergy Louisiana CEO Phillip May has rejected the idea that a more resilient transmission system could have withstood Ida’s ravages any better than the existing grid. (See Entergy Fends Off Calls for Tx, Solar, Microgrid Investment.)

Posted on

MISO to Test Long-range Tx Allocation Benefits

MISO has commissioned a study meant to demonstrate that long-range transmission projects built in the Midwest won’t deliver benefits to the South.

The grid operator has tapped The Brattle Group to test its hypothesis that benefits from long-range projects built in either MISO Midwest or MISO South won’t cross its subregional transmission constraint. Brattle is using hypothetical and past projects from MISO’s 2011 Multi-Value Project portfolio to study a systemwide benefit spread.

The RTO plans to include the results in its FERC filing for a separate-but-equal postage stamp cost allocation that splits the system into MISO Midwest and MISO South for cost-recovery purposes. MISO hopes that the allocation will be temporary, and it plans to explore other long-range design options in 2022.

Speaking during a Dec. 3 Regional Expansion Criteria and Benefits Working Group, MISO’s Jeremiah Doner said staff will share the study report with stakeholders when it’s completed.

Some stakeholders asked whether MISO was deliberately creating a seam within its own borders with the first allocation design.

East Texas Electric Cooperative representative Paul Kelly said that some stakeholders already have performed analysis that show high-voltage, long-range transmission can deliver benefits systemwide despite the subregional transfer limit between the Midwest and South.

Stakeholders asked whether MISO would allow retroactive cost recovery in MISO South if Midwestern project benefits are shown to help the South and whether staff will again test for benefit flows once they finally recommend specific projects.

Currently, MISO won’t estimate how much the first group of recommended projects could cost. It has said its first transmission planning scenario shows a need for upwards of $30 billion worth of projects, but those are expected over multiple years.

“I just can’t help but ask … is there a plan in place if that scenario actually does show significant benefits to the South?” said Sam Gomberg of the Union of Concerned Scientists.  

MISO’s Aubrey Johnson said if study results show noteworthy benefits flowing to the South, staff would reopen cost-allocation discussions for the first Midwestern projects to emerge from the long-range transmission plan.

Johnson was asked whether MISO would then be unmoored on a singular cost-allocation design and propose allocation that could vary project-to-project or cycle-to-cycle. He said staff will not alter cost-allocation decisions once made but will use what it learns on benefits flowing Midwest to South to inform future allocation designs.

With the Brattle analysis, MISO once again delayed a FERC filing date for cost allocation, pushing it back from mid-December to mid-January. (See MISO Schedules Cost-allocation FERC Filing.)

The RTO’s long-range transmission plan has evolved meeting-to-meeting, with postponements and temporary reductions in scale announced near-monthly.

The grid operator first told stakeholders it would advance an initial subset of projects based on its most conservative 20-year transmission planning scenario with December’s approval of the 2021 MISO Transmission Expansion Plan. It then said it needed until March. Planners now say they won’t have project proposals ready for a board vote until late spring. (See MISO Postpones 1st Cycle of Long-range Projects.)

MISO is not tackling Southern projects until sometime in 2023, leaving MISO South transmission needs out of the study’s first cycle. Louisiana and Mississippi regulators have threatened to leave the grid operator if the first round of long-range projects’ cost allocation extends to their utilities’ ratepayers.

Stakeholders Tee Up 2022 Allocation Design Debate

Looking ahead to next year’s debates on long-range cost allocation, MISO South members and regulators resubmitted for consideration their allocation proposal first presented in the summer.

The plan prescribes costs be directly assigned to project beneficiaries from either increased reliability, economic gains, or attained policy goals. It would have only states with decarbonization goals splitting project costs that further their clean energy aims. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

Clean Grid Alliance’s Natalie McIntire said state goals that split transmission project costs are similar to MISO’s current participant-funded project type, where market participants can construct a project so long as it doesn’t harm the system. She said elements of the South proposal already are available as options in the MISO tariff.

Some stakeholders said the South proposal wouldn’t pass at FERC because it proposes different allocation types for a single project class.

MISO’s Environmental Sector countered the South proposal with a design that asks the RTO to incorporate all benefit metrics it has deemed acceptable, including improved public health from less pollutants. The sector also asked for a two-step cost assignment, with some costs assigned to the parties receiving quantifiable, economic benefits and the remainder spread evenly across a subregion to recognize the broad reliability benefits that high-voltage lines deliver but are difficult to calculate.

Sustainable FERC Project attorney Lauren Azar said the Environmental Sector’s proposal clamps down on free ridership. She said her sector would also like to see benefits assumed over a 40-year horizon, noting most transmission remains energized for about 60 years, making projects undervalued when their benefits are initially measured.

MISO has said its system will not be able to function reliably in a future with a changing resource mix without new, large transmission projects (See MISO Analyses Show Reliability Woes Without Transmission Builds.) Currently, more than 95% of its members have carbon-emissions reduction goals.

Both MISO South regulators and Entergy representatives have questioned the amount of renewable penetration the RTO forecasts in future planning scenarios. They have suggested states with clean-energy goals pay a larger share of transmission construction costs.

The grid operator said it may need more than a dozen 345-kV additions, a handful of 500 kV and 765 kV lines, and even a massive footprint-wide network of DC lines as part of its the long-range planning package. (See MISO Reveals Contentious Long-range Tx Project Map.)

Based on MISO’s annual MTEPs, the footprint could see more than 5,000 miles in new transmission lines come online over the next decade. Only about 200 miles of the new lines will be rated at 345-kV and greater.

MISO has not approved any large economic transmission projects since it changed their cost allocation in 2020. (See MISO Cost Allocation Plan Wins OK on 3rd Round.) The RTO had framed the new allocation as key to getting more Market Efficiency Projects approved.

Posted on

NEPOOL Participants Committee Briefs: Dec. 2, 2021

Tx Planning Tariff Changes Approved

ISO-NE stakeholders Thursday approved tariff changes that incorporate a new transmission planning process focused beyond the RTO’s current 10-year planning horizon.

The revisions, which the NEPOOL Participants Committee passed unanimously with one abstention, are part of a multiphase effort. The initial phase establishes the rules to enable the New England States Committee on Electricity (NESCOE) to request that the RTO perform longer-term, scenario-based transmission planning studies on a routine basis.

The present processes do not support state-requested transmission analysis based on state-developed scenarios, inputs and assumptions. The new approach includes the development of high-level transmission concepts and cost estimates, if requested, to meet the state-identified requirements.

The second phase, to begin in early 2022, will address the rules to enable NESCOE to consider potential options for addressing the identified issues and cost allocation for associated transmission improvements.

2021-2022 Winter Outlook

ISO-NE COO Vamsi Chadalavada presented the region’s 2021-2022 winter outlook during his monthly report, with the 50/50 and 90/10 winter peak demand forecasts both lower than last winter’s.

The 50/50 forecast of 19,710 MW is 456 MW (2.3%) lower, while the 90/10 forecast of 20,349 MW is 2.2% lower (457 MW). Chadalavada said that if this winter is similar to the last, the RTO anticipates reliable power system operation without the need for emergency procedures. It is assuming no significant generation or transmission outages and limited fuel replenishment in this profile.

Energy Market Value Falls

Chadalavada added that ISO-NE’s energy market value for last month (through Nov. 22) was $375 million, down $185 million from October but up $130 million from last November.

Natural gas prices were 6.1% higher than in October, while gas prices and LMPs were up 154% and 112%, respectively, over the same period last year. Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 98.6% during November, down from 99% during October, with the minimum value for the month of 93.9% posted Nov. 22.

Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $2.5 million, down $1 million from October, though $600,000 higher from November 2020. NCPC payments were 0.7% of the energy market value.

Two projects totaling 213 MW were added to the interconnection queue since Chadalavada’s last update. They consist of one battery project and one solar project, and each has in-service dates of 2024. In total, 300 generation projects are currently being tracked by the RTO, totaling approximately 31,947 MW.

2022 Budget

The PC unanimously approved — with abstentions — a 2022 budget of $6,587,000 for NEPOOL, up more than $350,000 from 2021’s spending plan. However, NEPOOL expects to spend $5,974,600 by the end of this year, $246,000 less than the 2021 approved budget.

The decrease mostly comes from declining committee meeting expenses amid the COVID-19 pandemic, as all gatherings were virtual events until October. Budget increases for 2022 include an increase in committee meeting expenses to $725,000, up from an approved figure of $510,000 in 2021 and 10 times the current forecast of $75,000.

Cavanaugh Re-elected Chair

PC Chair David Cavanaugh, vice president of regulatory and market affairs for Energy New England, was re-elected for 2022. Vice chairs were also re-elected include Tina Belew of the Massachusetts Attorney General’s Office; Frank Ettori, Vermont Electric Power Co.; and Michelle Gardner, NextEra Energy. Sarah Bresolin of ENGIE North America and Aleks Mitreski of Brookfield Renewable Energy Group were also elected vice chairs.