Search
`
November 5, 2024

Posted on

Grain Belt Express Asks FERC to Overrule MISO on In-service Date

Invenergy asked FERC on Nov. 7 to order MISO to allow it to energize part of its Grain Belt Express project in 2028 despite delays in upgrades needed in Ameren’s territory (EL24-35).

The approximately 800-mile, 600-kV high-voltage direct current transmission line will have the capacity to deliver up to 5,000 MW of renewable generation from Western Kansas to the Midwest and PJM.

Grain Belt Express (GBX) asked the commission to add a limited operation provision to Attachment GGG of MISO’s Open Access Transmission, Energy and Operating Reserve Markets Tariff.

Invenergy said it will be able to put Phase I of its project into operation in 2028 because it has obtained siting permits in all four states on its route and has nearly completed right-of-way acquisition.

However, on Sept. 15, MISO informed GBX that it was delaying the in-service date from Dec. 1, 2027, to Dec. 1, 2030, because two network upgrades Ameren will build require regulatory permits, extending the time for their completion.

GBX said it asked MISO to incorporate into its transmission construction agreement (TCA) an option for limited operations “comparable to the limited service options included in the commission’s pro forma large generator interconnection agreement (LGIA) for generator interconnections, and which some RTOs have explicitly expanded to merchant transmission.”

GBX said MISO rejected its proposal because it is not a provision in its current tariff. The RTO told GBX it would add the proposal to a list of issues to be discussed with stakeholders but that “it would not be something pursued in the near term as it is working through other pending initiatives, including completion of its Order No. 2023 compliance requirements … activities that can be expected to extend throughout 2024 and likely 2025 as well.”

GBX said that meant “by the time it finishes its pending initiatives, starts stakeholder proceedings, develops a tariff proposal, and then files it with and obtains commission acceptance, it will likely be close to or past GBX’s planned 2028 operations date.”

“As such, MISO’s promise to look into this at a later date may not result simply in a delay, but in practical terms, a denial of limited operation. It is important that GBX have certainty as it is lining up customer commitments and moving forward on obtaining financing, and that the potential for limited operation prior to 2030 be managed now.”

GBX said it will also ask FERC to modify the TCA, which MISO is expected to file unexecuted this month.

MISO did not immediately respond to a request for comment.

Limited Operation

Phase I of GBX will interconnect its Kansas converter station with a converter station in Monroe County, Mo. A 40-mile AC tie-line will connect that station to the MISO system along an Ameren Missouri 345-kV AC transmission line connecting the McCredie substation and the Montgomery substation and interconnecting with the Associated Electric Cooperative Inc. system at the McCredie 345-kV substation.

GBX said MISO should modify the TCA to allow limited operation of the project without the Ameren upgrades for whatever lower amount of capacity could be connected and injected prior to the upgrades’ completion.

It cited FERC’s pro forma LGIA, which says that, if upgrades are not expected to be completed prior to the commercial operating date of a generating facility, the transmission owner will perform studies to determine the extent to which a customer may operate prior to the completion of those upgrades.

GBX said it has commissioned studies “which, on a preliminary basis, are indicating that there should be some potential for operating at less than full capacity prior to the completion of the two Ameren lines.”

Invenergy said FERC’s “policy of providing a limited operation option to generator interconnection customers applies equally to MHVDC connection customers.”

It said PJM has merged its procedures for all types of new service requests, including merchant transmission interconnection, and explicitly permits limited operation of merchant transmission facilities if there is a gap period between the completion of the transmission and network upgrades.

“MISO’s rejection of GBX’s request for limited operation while it awaits completion of network upgrades for three years after the GBX facilities are completed is unreasonable given the urgent need for transmission in the U.S. and the harm to GBX,” it said.

It said the delay would require it to carry the financing cost of its projects for an additional three years before beginning service to paying customers.

It asked FERC for an expedited order by March 15, 2024.

Posted on

RSTC Sends DER Proposal Back to Working Group

At their quarterly meeting Dec. 6, members of NERC’s Reliability and Security Technical Committee rejected a proposal to endorse a standard authorization request (SAR) to update reliability standard EOP-005-3 (System restoration from black start resources) to better account for distributed energy resources.

NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group developed the SAR based on a recommendation in the ERO’s October 2022 Reliability Standards Review white paper, which the working group also developed. The group’s intended changes to EOP-005-3 would require transmission operators to consider the automatic responses of DERs when designing their system restoration processes.

But during the discussion of the SAR, several RSTC members said they were reluctant to endorse what they considered a lower-priority project, despite understanding the need to ensure DERs are accurately modeled in system planning. Southern Co.’s Todd Lucas reminded attendees that NERC’s Standards Committee “has got their hands full with … existing projects” and suggested that instead of “just [piling] more things in the hopper,” the RSTC could wait to send the SAR through.

“I’m questioning, does this one rise to the level of adding it into that hopper, or should we just take an opportunity to reprioritize and see where it falls out?” Lucas said. “Is it something we want to push forward now, or is it something that would be more effective if we pursued it later?”

After the motion to endorse the SAR failed — with 48% of the committee voting against, 41% voting for and 10% abstaining — RSTC Chair Rich Hydzik suggested that SPIDER rework the SAR and present it at the committee’s next meeting in March. Robert Reinmuller of Hydro One said it is important for the SAR to return to the committee as soon as possible.

“We don’t look good when we say, ‘Well, two years ago we thought this was important, and now we’re just going to ignore it for a little while,’” Reinmuller said. “Everybody knows today that as we add more DERs … and have more uncoordinated responses, and you don’t understand what a DER does or doesn’t do … the risk will continue to increase. So I think [this] document is very useful to create that clear visibility for every [generator operator] or every owner of assets that is connecting and operating DERs.”

PRC-006 SAR Approved for Comment Period

The EOP-005 SAR was the only one up for endorsement at the meeting; however, the committee did agree to post another SAR developed by SPIDER for a public comment period.

The SAR, also developed following the Reliability Standards Review paper, proposes to revise PRC-006-5 (Automatic underfrequency load shedding) to correct a potential danger to the grid from DERs tripping because of underfrequency load shedding (UFLS). This behavior could “impact the ability of the UFLS program to properly arrest a frequency decline,” SPIDER said.

SPIDER’s proposal noted that a minority of the group’s members felt it “should not be seeking posting or comment” on the SAR because other projects constituted a higher priority for the RSTC, but the committee approved its posting for a 45-day comment period.

The RSTC also approved several reference documents and security guidelines at the meeting:

    • 6-GHz communication interference white paper — discussing the potential for communication in the 6-GHz radio spectrum to interfere with the energy industry;
    • Product security sourcing guide and reference guide — helping asset owners identify and address potential cybersecurity vulnerabilities when purchasing grid control products;
    • Electric vehicle technical reference document — presenting a model for understanding the impact to the grid of charging EVs; and
    • Reliability guideline: fuel assurance and fuel-related reliability risk analysis for the bulk power system — providing information to help utilities ensure their fuel supplies are sufficient to ensure reliability.

The committee’s next meeting will be held in person at the Westin Gaslamp Quarter hotel in San Diego on March 13-14.

Posted on

FERC Orders Settlement Procedures on NY Utilities’ Tx ROE Filing

FERC has ordered two New York utilities into hearing and settlement judge procedures over their proposed return on equity (ROE) on transmission investments to support the state’s renewable energy goals (ER23-1816, ER23-1817).

The commission’s Dec. 4 order accepts for filing Rate Schedule 19 formula rate protocols and templates for Avangrid’s New York State Electric & Gas (NYSEG) and Rochester Gas and Electric (RG&E) effective July 3, 2023, subject to refund.

In response to a protest by the New York Association of Public Power (NYAPP), FERC called for hearing and settlement proceedings on the utilities’ proposed 10.87% “ceiling base” ROE — a fixed value in the formula rate that would be subject to a lower ROE authorized by the New York Public Service Commission.

NYAPP said FERC should adopt the ROE and capital structure approved by the New York commission in the most recent retail case for NYSEG — 9.2% for 2024, with a capital structure of 52% equity and 48% debt and customer deposits.

FERC agreed that the 10.87% ROE had not been shown to be just and reasonable. “We find that applicants’ proposed ceiling base ROEs raise issues of material fact that cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures ordered below,” it said.

Schedule 19 and the Cost Sharing and Recovery Agreement (CSRA) — a voluntary participant funding agreement among the six New York state-regulated public utility transmission owners — are intended to provide a cost recovery and allocation framework for local transmission upgrades needed to meet the state’s Climate Leadership and Community Protection Act and the Accelerated Renewable Energy Growth and Community Benefit Act.

Historically, local transmission upgrades have been funded via bundled, local transmission and distribution rates. Under the CSRA, the costs are instead shared statewide and recovered on a volumetric load-ratio share basis from load-serving entities.

FERC’s order requires the settlement judge to file a report on the status of the settlement discussions in 60 days after the judge’s appointment.

While FERC sided with NYAPP on the ROE issue, it rejected the group’s contention that the formula rate misallocates administrative and general expenses.

Posted on

‘Missing Pathway’ Advancing Through Approval Steps in West

The proposed Cross-Tie transmission project — a 214-mile line across Utah and Nevada that’s seen as a missing link in the Western transmission system — is moving through the federal approval process with a targeted in-service date in 2027. 

TransCanyon LLC has proposed the 500-kV HVAC line connecting PacifiCorp’s Clover substation in Utah with NV Energy’s Robinson Summit substation in Nevada.  

The U.S. Bureau of Land Management, the lead federal agency for the project, released a draft environmental impact statement for the proposal last month. BLM expects to decide in 2024 whether to grant the developer’s right-of-way request. 

TransCanyon is a joint venture between Berkshire Hathaway Energy’s BHE U.S. Transmission and Pinnacle West Capital, the parent company of Arizona Public Service (APS). 

The 1,500-MW Cross-Tie transmission project will cost an estimated $750 million and is expected to begin service in 2027, according to TransCanyon’s website. TransCanyon plans to develop, own and operate the transmission facilities. 

Delivering Renewables

TransCanyon called Cross-Tie a “missing pathway” in the Western transmission system that would enhance resilience and reliability and boost the delivery of renewable energy. 

At its eastern end, Cross-Tie would connect to the southern tip of PacifiCorp’s 416-mile Gateway South transmission line, which runs across Wyoming, Colorado and Utah. 

At Cross-Tie’s western end is the Robinson Summit substation, the northeastern vertex of NV Energy’s planned transmission triangle around Nevada. The triangle consists of the proposed Greenlink North and Greenlink West lines and the existing One Nevada Line. 

TransCanyon said that Cross-Tie, in concert with PacifiCorp’s Energy Gateway projects, the Greenlink projects and the Harry Allen-to-Eldorado project in southern Nevada, would provide needed transmission capacity between the Intermountain West and the Desert Southwest. 

“This additional transmission capacity would facilitate access between the significant existing and planned renewable resources, primarily wind in Wyoming and wind or solar resources in central Utah and eastern Nevada, to the diverse utility load profiles in the Desert Southwest/California,” TransCanyon said in a development plan submitted to the BLM. 

In addition, Cross-Tie might reduce solar curtailments and battery storage needs in California and the Desert Southwest, the plan said. 

During a virtual public meeting hosted by BLM on Dec. 5, one attendee asked whether any contracts are in place that would guarantee Cross-Tie will deliver renewable energy. 

TransCanyon representative Roger Yensen said the developer plans to complete the environmental review process with BLM before entering into contracts. 

But given its strategic location, Yensen said, “we anticipate there will be a significant portion of energy that will be carried on the Cross-Tie [project] that will be from renewable resources.” 

In October, the U.S. Department of Energy announced it would become an anchor off-taker for three interstate transmission projects, including Cross-Tie. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) Yensen said negotiations with DOE are underway. 

TransCanyon isn’t currently planning to connect Cross-Tie to the Intermountain Power Plant in Utah, even though the transmission project’s path runs near the facility. But that could be considered in the future, according to the development plan. 

Alternative Routes

In its environmental review of Cross-Tie, BLM is examining the developer’s proposed transmission path as well as several alternatives that would add four miles to about 150 miles to the route. BLM staff said the transmission project will cost roughly $3.5 million per mile. 

One alternative route addresses concerns from the town of Leamington, Utah, about the project’s impacts on scenic views. 

“Why would any project be proposed that destroys the view the residents of Leamington have enjoyed and cherished for over 150 years when a viable alternative is readily available?” Leamington’s mayor said in a written comment submitted for the virtual meeting. 

Other alternatives were designed to reduce impacts to cultural resources, environmentally sensitive areas or the U.S. Department of Defense’s Utah Test and Training Range. BLM has not yet selected a preferred alternative. 

In addition to the virtual public meeting, BLM held four in-person meetings on Cross-Tie in late November. 

The deadline to comment on the draft environmental impact statement is Jan. 2. 

Posted on

MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries

ORLANDO, Fla. — Several MISO stakeholders took exception to the RTO’s proposal before FERC to cap the volume of interconnection requests it accepts annually. 

MISO made two filings with FERC last month to establish an annual megawatt cap on projects, enforce stricter proof of land use, enact automatic and escalating monetary penalties for withdrawals, and increase milestone fees for its generator interconnection queue (ER24-340 and ER24-341). (See MISO’s More Stringent Interconnection Queue Rules Go Before FERC.)  

DTE Energy said a queue cycle cap would be “unprecedented” and argued it won’t address “the root cause of MISO’s inability to timely process interconnection requests.”  

DTE said it’s not the number of projects overall, but the percentage of speculative projects in the queue that’s the problem. Developers have resorted to “over-saturating the interconnection queue with projects as an insurance strategy to secure a position” because of long wait times in the queue, DTE argued. DTE supported the other aspects of MISO’s queue rule changes.  

MISO has said there are only so many potential generation projects it can simultaneously consider in interconnection studies while still achieving accurate results. (See MISO Relaxes Proposal on Stricter Queue Ruleset.) 

But the Coalition of Midwest Power Producers argued MISO wants to impose a megawatt cap “without articulating how a lower volume will ensure accelerated queue processing.” The coalition said MISO didn’t detail “unique processes or additional computing power to resolve the volume and study pace issues that have been the albatross of the MISO queue process.”  

NextEra Energy agreed MISO didn’t provide evidence to show a cap will “remedy or mitigate the factors leading to its unwieldy, inefficient and untimely interconnection queue.” It said the cap will stymie competition and create barriers to entry for smaller generation developers.  

Ameren said it thought the cap “is a blunt tool that is not fully thought out and may result in unjust outcomes.”  

Xcel Energy, on the other hand, said MISO has sufficiently explained a megawatt cap is key to alleviating the overstuffed queue. Entergy agreed the sheer size of the interconnection queue is interfering with “realistic” study results and not giving developers a clear picture of whether they should proceed with generation projects.  

The Organization of MISO States also threw its support behind the cap, saying a “backstop mechanism is needed — at least temporarily — to ensure MISO can produce realistic network upgrade studies based on a smaller, more manageable queue size.”  

“MISO’s queue is oversaturated with projects that are vying to identify the cheapest locations to interconnect, causing MISO to choose to effectively shut down its interconnection queue,” OMS told FERC.  

MISO’s current generator interconnection queue contains more than 1,300 projects at nearly 230 GW — nearly double MISO’s summertime peak demand.  

“It is not reasonable to expect MISO to continue to try and work through this level of requests in its queue process,” Xcel said.  

In a joint protest, the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance argued that limiting projects annually is diametrically opposed to the rapid transition of clean energy resources. They said it’s only natural MISO’s queue has expanded rapidly in recent years.  

“If accepted, the cap proposal would create perverse incentives that will create havoc, increase uncertainty and discriminate against the very clean-energy resources that the region needs,” the clean energy groups contended.  

Alliant Energy argued MISO’s proposal to cap queue cycles is an odd choice when the grid operator has been telling stakeholders new capacity additions are crucial. Alliant referenced OMS’ most recent resource adequacy survey showing the footprint runs the risk of a 9-GW capacity shortfall by 2028.

MISO Leadership Hopeful for ‘More Confident, Less Speculative’ Projects

At MISO Board Week in Orlando, Executive Director of Resource Planning Scott Wright said even though there are some complaints, stakeholders’ comments reveal “a broad consensus that the staggering queue line was unsustainable.”  

Scott Wright, MISO | © RTO Insider LLC

Wright said an annual megawatt cap on projects, an automatic penalty scheduled for withdrawal and increased milestone fees will encourage a “more confident, less speculative” class of projects to enter the queue.  

“Many of the projects in the queue are highly speculative despite our past rule changes to use a ‘first-ready, first-served’ approach,” he said. Wright also said MISO’s existing withdrawal process are too “low-consequence.”   

Wright added that the “staggering” number of queue projects is developers’ “rational” response to more favorable economic conditions for renewable energy development. He said it’s natural MISO found itself having to tighten requirements, so its historically “high-quality” queue isn’t compromised. 

Wright said since the last Board Week in September, members have announced more retirement plans, with Michigan adopting a clean energy pledge by 2040. 

MISO predicts it will add about 250 GW in installed capacity over the next 20 years, but it will only amount to a 38-GW increase to MISOS’s current 172 GW in accredited capacity.  

50 GW in Greenlit and Unfinished Projects Haven’t Budged

Wright added that the prospective projects in the queue still face inflation and supply chain headwinds. MISO’s large number of approved but unbuilt generation projects hasn’t budged since the summer. (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.)  

Today, 50 GW across 316 projects are awaiting construction, with 50% of those developers saying wait times will average 650 days until commercial operation. Most of the on-hold projects are solar generation, accounting for 32 GW.  

By year’s end, Wright said that amount could grow to nearly 60 in approved but unbuilt generation projects.  

Vice President of System Planning Aubrey Johnson said nationally, 260 GW in generation projects have signed interconnection agreements in the organized markets and yet remain unconstructed. Johnson said that side of the issue deserves more awareness in conversations about the country’s interconnection woes, when usually, inadequate transmission planning is emphasized.  

“This is something that needs national attention. It’s something that we call attention to at every turn,” Johnson said.  

Posted on

FERC Rejects Wabash Valley Contracts, Sets Tariff for Proceedings

FERC on Nov. 6 rejected new contracts the Wabash Valley Power Alliance had filed for its members and a distributed generation policy proposed by the generation and transmission cooperative (ER24-36). 

The commission said the rejections were without prejudice and opened a show cause proceeding (EL24-16) to determine whether Wabash’s tariff is just and reasonable and not unduly preferential. 

Indiana-based Wabash serves wholesale customers in both MISO and PJM, meaning it has to buy transmission and ancillary services from both RTOs. However, two of its members — Tipmont Rural Electric Membership Cooperative and Citizens Electric Corporation — alleged that Wabash failed to separate out those purchases in contracts with those customers, running afoul of FERC’s unbundling rules. 

The new contracts, filed in 2023, should be subject to FERC Order 888 because its unbundling rules have been in effect for all contracts since July 1996, the complainants argued. 

Wabash argued that, while Tipmont and Citizens are members of the alliance, the two co-ops declined to sign 2023 contracts and should not be allowed to participate in the FERC proceeding. The pair’s arguments are based on existing contracts and should not have an impact on FERC’s review of the 2023 deals, Wabash said. 

FERC found that the contracts do not run afoul of the commission’s unbundling rules because they do not establish a bundled rate, but merely incorporate the rate established by the Wabash tariff, which is on file with the commission. 

But the commission said it could not accept the contracts as written in part because they require member co-ops to provide 31 years of notice to avoid an automatic five-year extension.  

“While we do not here decide whether it might ever be just and reasonable to include a provision requiring 31 years of notice to avoid an automatic five-year extension in a requirements agreement, it is incumbent on the applicant in an FPA section 205 proceeding, i.e., Wabash, to affirmatively demonstrate that such a provision is just and reasonable with regard to the agreement presented to the commission for its approval,” FERC said. “Wabash does not support this proposal other than to observe that the executing members desired the long-term stability of their contractual relationship with Wabash and that they signed the 2023 contracts.” 

Wabash did not adequately show its proposal to be just and reasonable, instead focusing more on Tipmont’s arguments against it and claiming that the co-op failed to prove the 31-year notice requirement was unjust and unreasonable, the commission said. 

Tipmont and Citizens also argued that several policies that should be included in the tariff are not. In any future filing, Wabash will have to include them or show that they do not affect rates and service significantly.  

The two members also filed protests against “Buyout Policy D-2” in the contract, which determines the amount of money a member would owe Wabash when departing from the cooperative. Tipmont is pursuing exit from Wabash in a separate, ongoing proceeding, and Citizens complained that Wabash just applied the methodology from that case to all members even though it was only designed for Tipmont. 

FERC also rejected Buyout Policy D-2, saying Wabash failed to make clear how it will use any methodology developed in Tipmont’s exit case and instead relied on unclear language saying it would take the case “into account” when dealing with future exits. 

FERC additionally rejected Wabash’s Distributed Generation Policy, which determines how much of that type of resource its members can use. The commission found fault with Wabash’s proposal that it could waive that policy for any given member based on 75% approval of its board.  

The rule “would give the board unfettered discretion when considering a member request to waive the terms of a policy that the commission had otherwise found just and reasonable,” FERC said. 

While none of the contracts ran afoul of FERC’s unbundling rules, the commission said it could not say the same for the tariff, which will be the subject of the show cause proceeding. Unbundling is needed to implement non-discriminatory open access transmission, and it is unclear whether the tariff provides it, FERC said. 

Wabash will have to come back to FERC within 60 days to either alter the rules in question or explain why they do not run afoul of unbundling requirements. Interested parties will be able to file comments 21 days later. 

Wabash can revise its tariff to deal with the unbundling issues under Section 205 of the Federal Power Act, which would place the Section 206 show cause proceeding in abeyance, FERC said. 

Posted on

Affordability Must not Lose out in Energy Transition, NE Regulators Say

BOSTON — New England policymakers and stakeholders must not overlook the need for electric affordability in the energy transition, officials from Massachusetts, Rhode Island and Connecticut told attendees of the New England Power Generators Association’s fifth annual New England Energy Summit on Dec. 6.

Rhode Island Public Utilities Commission Chair Ron Gerwatowski compared juggling the priorities of decarbonization, reliability and affordability to “adopting a coyote, a wolf and a bunny rabbit, putting them in the same corral, and asking how you can get them to get along without harming each other.”

“The coyote and wolf might find a way to coexist, but that bunny rabbit, I don’t know about it,” Gerwatowski told attendees.

The bunny rabbit, in Gerwatowski’s analogy, is affordability. With decarbonization and reliability considered nonnegotiable in the region, affordability is being overlooked, he said.

“When we add up the combination of rising costs from distribution, transmission, regional markets and renewable procurements, electricity rates are driven upward, and affordability gets severely strained,” he explained.

To prevent rates from skyrocketing, Gerwatowski said that policymakers should consider impacts on ratepayers when weighing different decarbonization strategies, and potentially avoid funding transportation and heating decarbonization initiatives through electric rates.

Additionally, states should consider providing stronger price signals and demand response incentives for consumers to reduce their electricity consumption during times of peak loads to limit the overall demand on the system and bring down prices, he said.

“I’m not suggesting that we slow down our pursuit of a carbon-free future,” Gerwatowski said. “What I’m saying is that it’s not too late to adjust the way we plan for our future.”

Rebecca Tepper, secretary of Massachusetts’ Executive Office of Energy and Environmental Affairs, agreed with Gerwatowski’s concerns about affordability and noted that the Massachusetts Department of Public Utilities is planning to open a docket focused on rate affordability.

“Addressing things on the demand side is extremely important,” Tepper said, pointing to the results of ISO-NE’s 2050 Transmission Study, which found that reducing the 2050 winter peak load from the projected 57 GW to 51 GW would save the region roughly $8 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) Tepper floated the idea of a “6-GW Earthshot challenge.”

Tepper added that the region should “think as creatively as we do about generation with demand response. We’ve all started thinking about energy efficiency as our first fuel; reducing demand needs to be our second fuel.”

Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said collaboration between Northeastern states around clean energy generation and infrastructure will be “the key to addressing affordability challenges.”

Dykes added that collaboration can both enable states to unlock lower prices through larger contracts and help states share the costs of projects that provide regionwide reliability benefits.

“We’re benefiting in Connecticut from the investments that Massachusetts is making in transmission to import hydropower,” Dykes said. “The entire region is freeriding on the support that Connecticut ratepayers are providing to prevent the Millstone nuclear facility from shutting down.”

Building Local Support

The officials and other industry speakers also stressed the importance of building local support for clean energy projects by communicating the climate benefits and providing tangible local incentives for communities to host infrastructure.

“We need to get communities excited about the energy infrastructure that’s in their towns,” Tepper said.

The “fundamental question,” said Mike Cuzzi of Cornerstone Government Affairs, is whether “the social and political will is there to build these things.”

Cuzzi added that building community partnerships early in the development process and speaking to the self interest of local communities are essential aspects of building support for projects.

“Listening to the people, early, upfront and understanding where you’re going to have problems … all those pieces are very important,” Cuzzi said. “Even that may not lead to success, but you’re at least going to win some degree of the public relations war.”

Gerwatowski called upon environmental activists and organizations that advocate for clean energy legislation to support clean energy infrastructure in regulatory proceedings and help communicate the climate benefits of electric infrastructure to local communities.

“They’re noticeably absent in these proceedings,” Gerwatowski said. “Why aren’t you coming out in droves like when it’s time to pass a bill?”

Posted on

Massachusetts Moves to Limit New Gas Infrastructure

Massachusetts has moved to discourage new investment in natural gas infrastructure by blocking utilities from recovering costs unless they can show they first considered non-gas alternatives. 

The order issued Dec. 6 by the Department of Public Utilities in Docket No. 20-80 follows more than three years of work by the DPU to engineer a reduction in the state’s greenhouse gas emissions.  

But it is only a first step, an attempt to discourage and dissuade rather than to ban. Ratepayer discretion is preserved, and the order’s effectiveness will depend in large part on the decisions they make. 

There are many more steps to come as the DPU works to balance all the moving pieces, competing interests and still-unknown factors to create a climate-protection solution that is workable, affordable and equitable. 

The Acadia Center, which had been pushing for a strong statement by the DPU, applauded Wednesday’s order, calling it a potentially transformative measure that addresses many of the clean energy advocacy group’s priorities. 

Eversource Energy and National Grid, which combined have more than 1.5 million gas customers in the Bay State, said in separate statements they support the state’s net-zero goals and are reviewing details of the 140-page order. 

Consider the Options

With the order, the DPU no longer will allow a utility to recover what it spends on natural gas infrastructure unless the utility can prove it considered alternatives such as electrification or district geothermal heating. It also will not allow cost recovery for efforts to promote expansion of natural gas. 

It sets the framework for much more, including management of stranded costs for utilities, cost control for customers, environmental justice and workforce transition. 

In announcing the order, DPU Chair James Van Nostrand called it a “forward-thinking framework that charts a path for moving toward clean energy and enhancing the state’s ability to achieve its climate goals while ensuring a fair, equitable and orderly process.”   

The gas utilities will need to file climate compliance plans every five years and undertake pilot projects with the preferred alternatives to gas — electrification and networked geothermal. 

The order excludes renewable natural gas and hydrogen as potential decarbonization solutions. Concerns surround the cost, availability and carbon footprint of RNG and hydrogen. Both may well have a role in Massachusetts’ journey to net-zero status, the DPU said, but at this stage of the process, utilities cannot use them as an alternative to fossil natural gas to comply with Wednesday’s order.  

Some other components of the wide-ranging order: 

The gas utilities each have their own mechanism to calculate the cost of line extension; the DPU will move to standardize them. 

Close coordination will be required between gas and electric utilities because reduced gas use likely means increased electric use, and grid capacity may vary by region, or even from one neighborhood to the next. 

The cost of the clean energy transition may be considerable, but the need for the transition is too pressing to slow the timetable. Instead, the DPU in a separate proceeding will investigate solutions to the cost burden the transition will place on low- and middle-income ratepayers. A change in its statutory authority likely will be needed for it to carry out some of those solutions. 

Utilities will continue to recover the billions of dollars they have invested in natural gas infrastructure — the order affects future efforts, not past spending. But the DPU will scrutinize future infrastructure spending to limit future stranded costs. 

It is important, the order states, for gas utilities to move beyond “business as usual” and actively participate in developing innovative solutions in what is expected to be “an exceedingly complex undertaking.” 

The Massachusetts Clean Energy and Climate Plan calls for net zero greenhouse gas emissions by 2050, with an emissions reduction of at least 85% from 1990 levels. 

Reactions

Wednesday’s order prompted responses from some of those affected. 

National Grid said: “We support the commonwealth’s goals and are committed to achieving net zero emissions. Our proposed strategy will reduce energy use, right-size and decarbonize our network, and maintain affordability and reliability for customers, while recognizing the critical role the gas networks play in keeping people warm and our economy going. We are reviewing the order and will have more to say later how we think it achieves these outcomes.” 

Eversource said: “We are working every day to help the commonwealth achieve its nation-leading decarbonization goals and we remain fully engaged with other utilities and stakeholders to define a practical path forward to reach them. We are currently reviewing the order and are thankful to the Department of Public Utilities for bringing together all stakeholders in an open and transparent process. Our customers’ energy needs are diverse, and it’s important that the clean energy transition provides access to safe, reliable and affordable energy for everyone.” 

The Beyond Gas Coalition said: “Today’s ruling is a historic and transformative climate decision. Not only is the DPU’s decision a major victory for the millions of Massachusetts gas customers who would otherwise be stuck paying for risky, unproven gas utility ventures, but sets a precedent for utility regulators across the country to rein in gas utility spending. From the outset, it has been clear that plans to blend ‘renewable’ natural gas with hydrogen for home heating would not only fail to measurably reduce emissions, but would be dangerous, expensive and not feasible. Highly efficient electric equipment, paired with weatherization and better insulation, is the only viable way to affordably build healthier communities and meet Massachusetts’ ambitious climate goals. The DPU is absolutely right to throw cold water over these risky utility plans and instead protect consumers.” 

Gas Transition Allies said: “The Department makes clear that the commonwealth is committed to ensuring that there is a just transition that includes equity for both customers and gas workers. Gas companies must not only address the potential for stranded assets that risk leaving customers holding the bag for gas companies’ imprudent investments, they must also work with electric companies to develop integrated plans to decarbonize buildings through increased electrification.”   

The Acadia Center said: “The 20-80 order today from the DPU has the potential to be one of the most transformative decisions in Massachusetts climate history. … That being said, implementation and follow-through will be incredibly important, as always. Thoughtful planning by the Department and the commonwealth will be needed to ensure positive outcomes on key areas such as customer affordability, a just transition for gas workers, and infrastructure planning and management. This order therefore serves as an important midpoint in a multiyear process, as this decision will now lead to other key dominos like evaluation of gas utility stranded asset risk, decoupling mechanism revisions, systematic consideration of non-gas pipeline alternatives, and reassessment of gas utility policies on new and existing customer connections.” 

Posted on

FERC OKs $150K Penalty on Black Hills for Delayed Filings

FERC on Dec. 5 approved a $150,000 civil penalty on Black Hills Corp. (BHC) and its three electric public utility subsidiaries for their failure to timely file 103 jurisdictional agreements (IN23-10).

The stipulation and consent agreement between FERC’s Office of Enforcement (OE) and BHC and its subsidiaries — Black Hills Power; Cheyenne Light, Fuel and Power; and Black Hills Colorado Electric — stems from a prolonged FERC investigation triggered by the utilities’ self-reporting of their omissions.

Jurisdictional agreements detail rates, terms and conditions of services regulated by FERC and are essential for ensuring transparency, regulatory compliance and fair pricing.

On July 14, 2017, Black Hills Power reported to FERC that it had failed to submit six jurisdictional agreements as mandated by the Federal Power Act and FERC regulations (ER17-2095). This lapse led to Black Hills Power refunding $8,621 to customers.

This incident prompted BHC to conduct a more extensive investigation into its subsidies to determine if there were any other unfiled contracts.

By November 2021, BHC expanded its self-report to include an additional 97 unfiled contracts, leading to an estimated $1.2 million in refunds.

As of October 2021, BHC had filed all 103 previously unfiled agreements with FERC, some of which have been accepted, while others are still under review.

“As a result of these violations,” the stipulation said, “Black Hills provided jurisdictional services without an accepted just and reasonable rate on file at the commission.”

The agreements consisted mainly of short-term firm and nonfirm transmission service contracts, but also included transmission wires-to-wires interconnection agreements, delivery service to wholesale customers over distribution assets agreements, and joint ownership agreements and operation and maintenance services agreements on transmission assets.

FERC acknowledged BHC’s cooperation with the OE throughout the investigation.

In addition to the financial penalty payable to the Treasury, BHC was required to admit its non-compliance and implement measures to prevent future violations.

These measures include submitting semi-annual status reports that detail the status of each of the 103 previously unfiled agreements every six months for two years or until FERC has accepted or disposed of all the unfiled agreements. It must also undergo compliance monitoring for two years following the acceptance or final disposition of all filed agreements by the commission.

BHC must pay the civil penalty within 20 days of the agreement’s effective date and submit its first semiannual status report six months thereafter.

FERC Commissioner James Danly did not participate in the order.

Posted on

MISO and IMM: M2M Flowgate Issue with SPP not Sustainable, May Require Litigation

ORLANDO, Fla. — MISO and its Independent Market Monitor agree that legal action is likely on the horizon concerning the RTO’s payments to SPP for a market-to-market flowgate.  

Monitor David Patton said congestion costs remain high at nearly $600 million over the fall in MISO. At a Dec. 5 Markets Committee of the MISO Board of Directors, he singled out the 230-kV Charlie Creek-Watford line, a market-to-market flowgate with SPP, as a major source of congestion. 

The line recently began delivering power to 220 MW in new load from a cryptocurrency mining operation in northwest North Dakota. Patton said Charlie Creek-Watford’s status as an M2M constraint should be revoked because MISO can offer SPP little relief.  

Patton also suggested MISO’s millions of dollars in firm flow entitlement payments to SPP involving the constraint might be improperly calculated by SPP. He added SPP has had challenges in modeling use of the line.  

“This is a mess,” Patton said. “This is really a bad scenario for MISO customers … I think there’s a good chance we head to litigation at FERC because we can’t keep these payments up.”  

Patton said the line accounts for most of the current funding shortfalls in MISO’s financial transmission rights market.  

“This one is going to be a legal issue in how we interpret the joint operating area, and we just need to sit down with SPP to work it out,” MISO CEO John Bear said.   

MISO Executive Director of Market Operations J.T. Smith said new load was allowed to be activated in an already constrained SPP load pocket. Smith said while transmission upgrades are planned for the area, they’re not yet in place  to help the situation. The load pocket is served by several other lines in addition to the line in question.  

SPP maintains it and MISO have “robust coordination procedures in place to ensure the market-to-market congestion management processes are working as intended” and in accordance with the RTOs’ joint operating agreement. 

“Over the last few months, the RTOs have extensively discussed the congestion issues associated with the Charlie Creek-Watford market-to-market flowgate that is being impacted by the operation of both markets,” SPP spokesperson Derek Wingfield said in an emailed statement to RTO Insider. 

Wingfield said if SPP and MISO are unable to reach a solution through informal discussion, SPP is still optimistic that it and MISO will be able to leverage the formal dispute resolution procedures contained in their JOA. SPP is hopeful for a “mutually agreeable outcome prior to this becoming a legal matter at FERC,” Wingfield said.