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November 7, 2024

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FERC Rules in Three SPP Disputes

FERC last week issued rulings in three SPP dockets, including Tenaska’s complaint over a network upgrade cost assignment; a dispute between Nebraska Public Power District and Tri-State Generation and Transmission; and NorthWestern Energy’s challenge of a qualifying facility.

Split Decision for Tenaska in SPP Complaint

FERC last week ordered SPP to restudy a Missouri wind project by Tenaska, which complained that the RTO erroneously assigned it about $66 million in network upgrade costs (EL21-77).

The commission’s Dec. 16 order found that SPP appropriately applied its authority under its tariff to restudy the project after one or more higher-queued projects withdrew; corrected the omission of 4.5 GW of higher-queued generation; and used the network resource interconnection service (NRIS) standard to evaluate the project’s effects on its system.

At the same time, FERC said SPP’s use of 2019 transmission-planning models in the restudy was unduly discriminatory or preferential. It directed SPP to restudy the project within 60 days using the 2017 planning models and incorporate the 4.5 GW of missing generation. It directed SPP to make a compliance filing within 10 days of the restudy’s completion.

Tenaska alleged that SPP mistakenly assigned the upgrade costs during a restudy of the Clear Creek Wind Project, a 242-MW facility that is interconnected to the Associated Electric Cooperative, Inc. (AECI) transmission system. It said the costs were assigned as part of SPP’s affected system study (AFS) process and asked that they be rolled into regional transmission rates or that FERC set a hearing to determine their equitable allocation. (See Tenaska Challenges SPP Tx Upgrade Costs.)

Clear Creek became operational in May 2020.

The developer requested an NRIS study in 2017. AECI identified SPP and MISO as potential affected systems; MISO’s AFS found no network upgrades were necessary to its system.

In August 2018, Tenaska requested that SPP conduct an AFS of the Clear Creek project. The RTO told Tenaska the project would be queued between the 2016-002 and 2017-001 definitive interconnection system impact studies (DISIS) and that it would use the 2016 cluster’s transfer case, reflecting capacity additions and associated network upgrades, as the base case. That transfer case used SPP’s 2017 Integrated Transmission Planning (ITP) study models, as the basis for its regional transmission planning studies.

SPP’s first AFS study identified $31.2 million in network upgrades it said were necessary to connect the project to the AECI system. The grid operator twice revised the study, in November 2018 and March 2019; the latter found approximately $33.5 million in network upgrades. FERC noted SPP only identified network upgrades to resolve constraints when modeling for energy resource interconnection service (ERIS).

After Tenaska began construction in 2019, it said it was told by SPP that the RTO intended to restudy the project because a higher-queued project had withdrawn from the interconnection queue. The RTO then told Tenaska in May 2020 that, because the initial studies’ models were more than a year old, staff intended to conduct the affected system restudy using the 2019 ITP models.

The study identified $763 million in network upgrades to the AECI system and the need for NRIS network upgrades. SPP said it had inadvertently omitted 4.5 GW of higher-queued generation on the MISO transmission system in the project’s first AFS and the DISIS 2016-002 cluster. The RTO deemed the initial AFS invalid and decided to use the 2019 ITP models for the restudy that lowered Tenaska’s cost responsibility to $106.8 million. In February 2021, that amount was lowered again to $91 million.

Clear Creek Project (Tenaska) Content.jpgTenaska’s Clear Creek Wind Project in Missouri | Tenaska

In March 2021, SPP posted the most recent affected system restudy results, assigning about $99 million in network upgrades to Clear Creek, comprised of $34 million in ERIS network upgrade costs and $66 million in additional network upgrade costs necessary to provide NRIS identified in the affected system restudies.

Commissioner Alison Clements concurred with the order “only because it conforms to the standards and requirements currently applicable to SPP’s affected system study process” and filed a separate statement.

She said the order demonstrates that reasonable efforts and good utility practice standards are “currently so lenient that neither SPP’s delay of over a year in completing the restudy process … nor SPP’s serious omission of 4.5 GW from its initial studies rises to the level of a violation.”

“I am sympathetic to the formidable challenges that overwhelmed regional interconnection queues cause for transmission owners, operators and interconnection customers,” she wrote. “Our regulatory standards do not mean much, however, if they are lenient to the point of impotence. As the commission turns to addressing transmission and interconnection reforms in the coming months, the standards applicable to interconnection studies must be among the topics to receive the commission’s attention and careful scrutiny.”

NPPD Complaint Rejected

The commission also rejected a Nebraska Public Power District (NPDD) request that FERC find Tri-State Generation and Transmission’s inclusion of certain costs in its 2021 annual transmission revenue requirement (ATRR) unjust and unreasonable (EL21-100).

FERC said NPPD did not demonstrate that Tri-State’s inclusion of amounts related an agreement between the two SPP members seriously harmed the public interest.

NPPD in 2018 asked the commission to direct Tri-State to remove from its ATRR costs related to an earlier Western Nebraska Joint Transmission Agreement (NETS Agreement) between the two that governed the use of transmission facilities. Under the agreement, the party making greater use of the facilities was required to make an annual cost equalization payment to the other party.

The agreement originally had a 2020 termination date, which Tri-State agreed to extend to March 1, 2021, to allow for negotiations between the two and SPP. The cooperative made its final payment under the agreement to NPPD in February 2021.

In July, SPP posted Tri-State’s update of its 2021 ATRR for the rate year beginning Sept. 1 and included an annual cost-equalization payment of more than $1.84 million. NPPD said the payment’s inclusion led to unjust and unreasonable rates because the NETS agreement was terminated and Tri-State had made its last payment. It also alleged the cooperative was no longer incurring any costs under the agreement and that Tri-State refused to remove the payment from the annual update process.

FERC said it found the disputed cost component was included in 2017 settlement agreement between NPPD and Tri-State over SPP’s placement of the Tri-State in NPPD’s transmission zone. (See FERC Rejects NPPD Objection to Tri-State Zonal Placement.)

The commission said that under the agreement, NPDD had to demonstrate that the proposed modifications to the ATRR and underlying rates satisfy the “public interest” application of the just and reasonable standard. It said the utility had failed to do so.

FERC also found that NPPD agreed in the settlement to Tri-State’s use of a formula rate based on the prior calendar year’s financial data. It said that by arguing that the cooperative should not be permitted to include the annual cost equalization payment Tri-State made in 2020 in its 2021 ATRR, “NPPD is seeking to modify the nature of the formula rate and, thus, modify the settlement agreement.”

“We find that NPPD, as a settling party, must make a showing sufficient to demonstrate that, without the proposed changes, the settlement agreement ‘seriously harms the public interest,’” the commission wrote.

NorthWestern Protest Denied

FERC denied NorthWestern Energy’s (NASDAQ:NWE) protest of a solar developer’s self-certification as a small power production qualifying facility (QF) under the Public Utility Regulatory Policies Act (PURPA) of 1978 (QF21-1213).

Gallatin Power Partners in September filed a form self-certifying its Shields Valley Solar Facility, to be interconnected with the NorthWestern system in Montana, as a QF. It said the development would have a 160-MW nameplate capacity but would also incorporate a battery-storage system with an expected 80 MW capacity on the solar array’s DC side, resulting in a maximum net AC power production capacity of 80 MW.

NorthWestern protested, arguing that the solar array and the storage systems were separate power-production facilities and that their capacities should be analyzed separately and then aggregated, resulting in a production capacity substantially larger than 80 MW. It based its argument on FERC’s March rehearing order for Broadview Solar that restored longstanding commission precedent for determining QF eligibility and extending it to integrated battery energy storage. (See FERC Reverses Ruling on Montana QF.)

The commission determined that because the Shields Valley facility could only deliver a maximum of 80 MW of AC electricity to NorthWestern’s system at any time, its production capacity “cannot and will not” exceed 80 MW. It said NorthWestern’s protest relitigated the Broadview rehearing orders’ capacity analysis and “effectively” requested that FERC overturn its findings and amounted to a “collateral attack” on those orders.

Commissioner James Danly concurred in part and dissented in part, saying as he did in the Broadview orders that “there is no net-output exception” to PURPA’s production capacity threshold.

However, Danly also disagreed with NorthWestern’s protest, noting batteries and other storage systems cannot be included when determining a facility’s “power production capacity” because they “do not ‘produce’ power — they simply store it for later delivery.”

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Court Overturns FERC on CAISO CPM Rates

The D.C. Circuit Court of Appeals on Friday overturned a 2020 FERC ruling that approved CAISO’s decision to award a 20% adder to above-cap bids for resources needed for grid reliability, saying FERC’s decision “was not the product of reasoned decision-making.” (20-1388).

The case involved CAISO’s capacity procurement mechanism (CPM), which lets the ISO purchase electricity needed to maintain grid reliability in extraordinary circumstances. It was based on a challenge by the California Public Utilities Commission, which claimed that CAISO and FERC had erred by awarding the adder to CPM resources that exceeded CAISO’s soft-offer cap reference bid of $6.31/kW-month.

CAISO and FERC had previously approved a 20% adder for resources that bid under the ISO’s soft-offer cap, saying the adder would cover going-forward costs such as maintenance and upgrades. FERC relied on its prior decision to also approve the 20% adder for resources that sought compensation above the soft-offer cap by applying for a higher rate from FERC.

The D.C. Circuit said FERC had relied on its own precedent regarding the soft-offer cap without considering the differences in the two cases.

“The commission relied chiefly on its 2015 CPM Order approving the soft-offer cap, which includes a 20% adder,” the court said. “The commission inferred from its 2015 order that applying the same adder to above-cap CPM bids would be just and reasonable.”

That was a mistake, the court said.

FERC “may attach precedential, and even controlling weight to principles developed in one proceeding and then apply them under appropriate circumstances in a [precedential] manner,” the court said. “But application of precedent is warranted only if the factual composition of the case to which the principle is being applied bears something more than a modicum of similarity to the case from which the principle derives.”

“Here … the commission failed to grapple with the distinction between bids submitted below or above the soft-offer cap, resulting in the commission’s reliance on precedent without recognition of the substantial differences between the two cases,” it said.

With the below soft-offer cap bids, “CAISO reasoned that the 20% adder would allow resources with costs higher than the reference resource to recover their going-forward costs and additional fixed costs, as well as providing investment incentives,” the court said. “In the event that the soft-offer cap does not allow a resource to recover its going-forward costs, that resource can submit a cost-justified filing to the commission for a higher rate.”

Providing the adder to above-cap bidders, however, “effectively renders the compensation formula uncapped; the greater a facility’s going-forward costs, the more it stands to recover through its cost-justified bid. This uncapped recovery stands in stark contrast to the soft-offer cap, which is meant to cap maximum bids evenly in order to facilitate competition among resources.”

Without reference to its precedent regarding soft-offer cap bids, “the commission’s order has little else, if anything, to support it,” the court said.

The court vacated FERC’s order and remanded the case for further proceedings consistent with its order.

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Maryland Adds 1,600 MW in Offshore Wind

Maryland regulators on Friday selected US Wind and Ørsted’s Deepwater Wind to build 1,600 MW in offshore wind, completing the state’s second OSW solicitation and bringing the state close to 2,000 MW in total.

The Public Service Commission awarded US Wind 808.5 MW in offshore wind renewable energy credits (OREC) at a levelized price of $54.17/MWh and Deepwater’s Skipjack Offshore Energy 846 MW at $71.61/MWh. Both awards are for 20 years from when the projects become operational, which is expected by the end of 2026 (Order 90011).

The new projects are in addition to the 368 MW of offshore wind already being developed by the two companies following the PSC’s first solicitation in 2017. The 2017 ORECs were priced at almost $132/MWh. (See Md. PSC OKs 368 MW in Offshore Wind Projects.)

US Wind submitted three bids and Skipjack submitted two in the latest solicitation, which were evaluated on criteria including costs to ratepayers, economic development impacts and progress on lowering the state’s greenhouse gas emissions. The PSC said the new projects would result in almost $1 billion in spending and create more than 10,000 new direct jobs in Maryland.

The commission said it concluded the round 2 projects can be built without exceeding the bill caps set by the state legislature: 88 cents/month for residential customers and no more than 0.9%/year for commercial and industrial customers.

The Clean Energy Jobs Act of 2019 charged the commission with procuring at least 1,200 MW of OSW in its second solicitation. Because this round yielded 1,600 MW, the PSC is cancelling plans for additional procurements as part of round 2.

The PSC’s award requires that the developers create at least 10,324 direct jobs during the development, construction, and operation of the projects and include goals for involving small, local and minority businesses.

The developers also agreed to use port facilities at Tradepoint Atlantic in Sparrows Point outside Baltimore and in Ocean City for marshalling, operations and maintenance. US Wind has previously pledged to develop a monopile construction facility at Sparrows Point while Skipjack has committed to build subsea cable and turbine tower manufacturing facilities in the state and invest in upgrades to Crystal Steel Fabricators, an Eastern Shore company that assembles steel components for wind turbine foundations.

The two companies will also pay $6 million each to the Maryland Offshore Wind Business Development Fund, a grant program for offshore wind supply chain and workforce training initiatives administered by the Maryland Energy Administration.

“The effects of climate change are real, and with its more than 3,000 miles of tidal shoreline, Marylanders are especially vulnerable,” PSC Chair Jason M. Stanek said. “That’s why it is important for the commission to take this action that will put our state on a path of deeper decarbonization and help Maryland achieve its aggressive clean energy goals.”

US Wind won a federal lease in 2014, paying $8.7 million for a site off Maryland that it says has capacity for 1.5 GW. Its Momentum Wind project will be 15 miles from shore at its closest point.

Skipjack’s windfarm will be 20 miles offshore. The Interior Department’s Bureau of Ocean Energy Management (BOEM) leased the site in 2012 to Bluewater Wind Delaware, which sold it to Deepwater Wind in 2016 (#OCS-A 0519). Ørsted acquired Deepwater Wind from D.E. Shaw group in 2018.

Ocean City officials had asked the PSC to require no turbines within 30 miles of shore to ensure they were not visible from land. (See Maryland Offshore Wind Plans Draw Enthusiasm, Controversy.)

The commission declined, saying the projects are sited in federal waters and are subject to BOEM’s review.

The PSC said Ocean City’s request that it require all turbines be located at least 30 miles from shore “is not reasonable in that it would disqualify all existing bids and unreasonably delay the next steps towards a greener energy future for Maryland as envisioned by the legislature. … The applicants are constrained by their lease areas, over which the commission has no control.”

The PSC said, however, that it will require the projects to use “the best commercially reasonable efforts to minimize the viewshed impacts.”

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Oregon Adopts GHG Cap-and-invest Program

Oregon’s Environmental Quality Commission (EQC) voted 3-1 Thursday to approve rules setting declining caps on greenhouse gases from fuel suppliers, cutting their emissions 90% by 2050.

A key pillar of the state’s growing climate change efforts, the Climate Protection Program (CPP) comes after Oregon Department of Environmental Quality (DEQ) staff worked for a year-and-a-half engaging in listening sessions, technical workshops, town hall meetings, committee meetings and extensive rulemaking proceedings before proposing the final rules.

“I’m just shocked we got to this point,” EQC Vice Chair Sam Baraso said ahead of the vote. “At the time when you all laid out your schedule, I know I was like, ‘That is not going to happen, and there’s no way it’s going to happen,’ and so I’m incredibly, incredibly impressed.”

DEQ Director Richard Whitman said that while the CPP is “not by any means the only piece of the puzzle,” it represents the “glue that kind of knits together” all of Oregon’s climate efforts and “gives us a clear pathway to a cheaper, cleaner energy future.”

Covered by the Cap

The CPP consists of two components: a cap program covering fuel suppliers and a best available emissions reduction (BAER) program for stationary sources.

The cap program covers natural gas local distribution companies and suppliers of gasoline, diesel and propane. Starting next year, those companies will together be subject to a cumulative GHG emissions cap of 28.1 million metric tons (MMT), a figure based on the average 2017-2019 emissions from the sector.

That cap will steadily decline every year, falling to 15 MMT in 2035 and 3 MMT in 2050, compared with an earlier proposal to set the caps for those years at 16.5 MMT and 6 MMT, respectively.

Nicole Singh, DEQ senior climate change policy adviser, attributed the change to the recent release of “a lot more scienced-based” information on the need for quicker measures to stave off global temperature rise, including dire warnings from the U.N. Intergovernmental Panel on Climate Change report in August. (See Too Late to Stop Climate Change, UN Report Says.)

Whitman said the state is now better equipped to accelerate reductions in fuel emissions after the Oregon legislature last June passed a bill requiring that all electricity delivered to customers in the state be generated by non-emitting resources by 2040. (See West Coast Could be Net Zero by Midcentury.)

“By getting us to a point where we have completely clean electricity in Oregon by 2040, that actually makes the pathway to getting into this level of reduction in GHG emissions easier than it was 18 months ago because we now have this partnership with clean electricity, and that helps us get to more aggressive levels of reduction,” Whitman said.

The cap portion of the program will be broken into three-year compliance periods, starting with the 2022-2024 interval. In the first year, companies subject to the emissions cap will be issued “compliance instruments” equal to their baseline 2017-2019 emissions levels, with each instrument entitling a holder to emit 1 MT CO2e of GHGs.

As the emissions cap declines each year, DEQ will issue fewer instruments, requiring the fuel suppliers to either reduce their emissions or acquire surplus instruments from other companies that have achieved reductions. At the end of a compliance period, each covered company must retire compliance instruments equal to their estimated obligations or face a penalty of up to $25,000 for each violation.

“There is discretion for our enforcement division to determine whether they will use the maximum extent of the fine or not,” Colin McConnaha, manager of the DEQ’s Office of Greenhouse Gas Programs, said.

Entities subject to the cap can cover a portion of their compliance obligations through the purchase of Community Climate Investment (CCI) credits. Funds from those credits will be targeted at programs that reduce emissions, promote health and accelerate the transition from fossil fuels in the state’s environmental justice communities, which include low-income areas, communities of color and rural districts.

In the first compliance period, a fuel supplier can use CCI credits to cover 10% of its compliance obligation. That figure rises to 15% in the second compliance period (2025-2027) and to 20% for 2028 and beyond.

BAER Facts

DEQ says the BAER component of the CPP will cover “certain types of facilities and certain types of emissions that cannot readily be addressed through limits on fuel suppliers, such as facilities that receive natural gas directly from an interstate pipeline (which can only be regulated by … FERC), and industrial process emissions resulting from inputs other than natural gas that are inherently part of or necessary to the product output (i.e., semiconductor manufacturing).”

The BAER rules will apply to an estimated 13 stationary sources with an annual output of 25,000 MT CO2e of emissions. Those facilities must use best available technology to limit or reduce their GHG emissions and follow a process “to periodically update those requirements to reflect technological changes.”

The new rules stipulate that a stationary source notified by the DEQ conduct a site-specific BAER assessment intended to identify strategies to reduce emissions, estimate reductions from each strategy, determine the impacts of implementing the strategies and estimate an implementation timeline.

In response to the assessment, the DEQ will issue the facility a BAER order identifying the actions required for reducing emissions — based on cost-effectiveness and technical feasibility — and setting a timeline for completion.

Many public commenters in the CPP process early on expressed concern that emissions reductions are not guaranteed under the BAER approach, asking for mandatory targets, Singh said. Singh pointed out that the final rules make clear that DEQ is not bound by a facility’s own findings in the BAER assessment.

“DEQ is allowed to use other information that’s available to us as an agency when we’re trying to make the BAER order,” she said.

Lone Dissent

The lone “no” in Thursday’s EQC vote was cast by Commissioner Greg Addington, who resides in Southern Oregon’s rural Klamath County. Addington, who acknowledged that had “checked out” of the CPP process when it went into a Rulemaking Advisory Committee about a year ago, pointed to the “vast difference” between the estimated economic impacts found in separate analyses by the DEQ and state industries.

“If I just look at employment impacts over the next 25 to 30 years, the DEQ’s report includes a gain of 20,000 jobs, and the industry’s analysis is a loss of 121,000 jobs. And that’s a big difference. Why is that so big?” Addington said.

Addington also questioned why carbon sequestration projects, which largely benefit farmers and other rural landowners, would be ineligible to receive funding from CCI credits.

“I just think this element has very little downside and sends a very positive message to a lot of parts of the state,” he said.

EQC Chair Kathleen George said the rulemaking committee did consider funding of sequestration projects, but it determined that “the most urgent action needed are concrete steps to reduce the production of greenhouse gases and to incentivize decarbonizing our energy economy.

“I just want to say I believe sequestration is of value, and while it can capture carbon, it doesn’t reduce production or change the system,” George said.

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NJ Greenlights Incentives for Multi-dwelling EV Chargers

The New Jersey Board of Public Utilities (BPU) on Wednesday authorized new incentives to promote the installation of EV chargers in multifamily buildings in an effort to broaden the demographics of electric vehicle drivers.

The BPU voted unanimously to establish the new program, which will offer a $1,500 incentive for the installation of a Level 2 charger in an apartment, condominium or mixed-use residential building, and pay half of the project’s “make-ready” costs — for installing the wiring required for a charger — up to a total of $5,000. Incentives increase to $2,000 for a Level 2 charger, and 75% of make-ready costs up to a total of $7,500 for installations in low-income or minority communities or those overburdened with pollution or other negative environmental impacts.

The board allocated $1 million to the program out of $14 million previously set aside to encourage the deployment of charging stations around the state. To be eligible for the multifamily program, a building must have a minimum of five units and have dedicated off-street parking. Applicants can seek funding for up to six Level 2 chargers, which, at 240 volts, can top up an EV battery, for example, while the owner is sleeping.

The BPU’s vote in support of the program was one of several aimed at advancing New Jersey’s clean energy initiatives at the agency’s last regular meeting of the year. The board also extended the completion deadline for projects in the state’s community solar pilot program and endorsed an agreement to work with the National Offshore Wind Research and Development Consortium.

The approval of the EV charger incentives follows Gov. Phil Murphy’s signing in July of a law that makes it easier to install EV chargers in a variety of locations, including multifamily buildings. The law automatically made the installation of electric vehicle supply equipment or the creation of make-ready parking spaces a permitted use under municipal zoning laws.

The law removed the often time-consuming necessity to seek a municipal zoning variance to permit the installation of EV chargers and specifically removed that requirement for multifamily buildings with five or more units. To meet the eligibility rules outlined in the law, a developer must equip 15% of available off-street parking spaces with make-ready charging infrastructure and install EV chargers in at least one third of the available spaces.

Speaking before the vote, BPU President Joseph L. Fiordaliso, said the multifamily incentives are important because they expand “the participation of all communities within the state of New Jersey into renewable energy, into, in this case, electric vehicles.”

Residents in multifamily buildings may not have the opportunity to buy or drive an EV unless their building is equipped with a charger, Fiordaliso said. “This is a start,” he said. “Every segment of our population must have the opportunity to participate in the clean energy revolution that we’re going through in this country, and in this state.”

The new incentive program is part of Murphy’s plan to cut New Jersey’s carbon emissions by 80% of the 2006 levels by 2050. The state also sees the installation of chargers as key to reaching its goal of putting 330,000 light-duty EVs and plug-in hybrids on the road by 2025. Other 2025 goals including putting at least 1,000 Level 2 chargers and 400 DC fast chargers at locations available for public use.

Promoting Competition, Ratepayer Protection

The BPU also belatedly ratified comments drafted by New Jersey and seven other states and the District of Columbia responding to FERC’s Advance Notice of Proposed Rulemaking regarding transmission planning, transmission cost allocation, and generation interconnection (RM21-17). The seven states — Connecticut, Maryland, Massachusetts, Delaware, Rhode Island, Vermont and Minnesota — and the District of Columbia submitted the comments to FERC on Nov. 26.

The comments include two key points:

  • The commission’s plan must ensure any rules enacted do not impede open and transparent competition and result in discriminatory behavior. “The Commission must closely scrutinize any proposed transmission reforms, especially those that impact competition,” a section of the ratified comments states. Given that ratepayers will need to spend billions more to reach clean energy goals, we cannot afford inefficient, non-transparent and non-competitive planning and procurement processes,” the comments said.
  • The commission should establish regional independent transmission monitors to track the planning and cost of transmission facilities in the region. “An independent transmission monitor with expertise in evaluating transmission development costs, and the best means of controlling those costs, would give ratepayers an important additional protection and an unbiased entity to guard their interests,” the agencies stated. Without it, the “inherent economic self-interest of transmission owners” could lead them to oppose transmission expansion and limit new entrants seeking to develop transmission facilities, the agencies said.

BPU Extends Community Solar Completion Deadline

Solar developers who took part in the first phase of New Jersey’s Community Solar Energy Pilot Program, which the BPU launched in 2019, will get another four months to complete their projects, the BPU decided Wednesday. Without the extension, the completion deadline for projects approved in the pilot’s first phase would be Dec. 30.

Two of the first phase projects, developed in Perth Amboy by Solar Landscape of Asbury Park, began operating in January. But the 78 MW of projects approved in the first phase have faced several challenges, said the BPU order outlining the reasons for the deadline extension. (See Billing Key to NJ Community Solar Growth.)

Many had to cope with completing installations amid the COVID-19 pandemic, the order said. In addition, developers faced complications from a change in New Jersey’s solar incentive programs, switching the state’s original Solar Renewable Energy Certificates (SRECs) incentives to a transitional program issuing Transition Renewable Energy Certificates (TRECs).

As a result of such shifting conditions, program participants had different deadlines, and the extension to April will simplify the rules and bring all the program participants onto the same page, the board order said.

The BPU in October selected 105 projects totaling 165 MW for the second phase of the Community Solar Energy Pilot Program, but those projects are not affected by the deadline change. The board is planning a permanent community solar program that will begin in 2022. (See NJ Selects 165 MW in Community Solar Projects.)

Backing Clean Energy Collaboration

The BPU also backed two agreements related to the state’s growing offshore wind sector. In one, the board approved a memorandum of understanding with the National Offshore Wind Research and Development Consortium, a national nonprofit organization that works with industry to conduct research aimed at reducing the cost of offshore wind. The MOU will define the “procedures and protocols” for the BPU’s membership in the organization.

The second agreement, with the New Jersey Department of Environmental Protection, will determine how the state administers the revenues it will collect from fees of $10,000 per MW to be paid by developers of offshore wind projects approved in the second of the BPU’s two solicitation rounds. The fees are intended to “support research initiatives and the regional monitoring of wildlife and fisheries related to the introduction of offshore wind projects.” The agreement will determine the rules and guidelines governing how the funds are allocated.

The two agreements will be made public when they are signed, said BPU spokesperson Peter Peretzman.

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NYISO ICAP/MIWG Briefs: Dec. 14, 2021

NYISO Monitor: Q3 Energy Prices Up Sharply Y-o-Y

NYISO energy markets performed competitively in the third quarter of 2021, with all-in prices ranging from $38/MWh to $117/MWh, up 62% to 94% from 2020 in all regions except New York City, which saw a decrease of 16%, the Market Monitoring Unit said.

“So there was quite a large spread, with particularly high prices in Long Island,” said Pallas LeeVanSchaick of Potomac Economics as he presented the quarterly report on the ISO’s electricity markets to the Installed Capacity/Market Issues Working Group.

Energy prices rose 68% to 124% primarily because of higher gas prices, which rose 110% to 139% across the system. The exception was New York City, which saw a decrease driven by lower capacity prices resulting from a lower locational capacity requirement, he said.

Third quarter 2021 natural gas and fuel oil prices (Potomac Economics) Content.jpgThird quarter 2021 natural gas and fuel oil prices in the New York Control Area. | Potomac Economics

 

Nuclear output fell by an average of 820 MW/hour following the retirement of Indian Point 3.

Both 345-kV lines from upstate New York to Long Island were out of service for more than half of the days during the quarter, LeeVanSchaick said, which led to some “pretty extraordinary conditions on Long Island, very tight, with very volatile pricing.”

He said the loss of the lines resulted in several “inefficiencies” including:

  • Lack of reserve shortage pricing during Long Island capacity deficiencies;
  • Understated reserve requirements in the day-ahead and real-time markets;
  • Inflexible generator scheduling related to gas-balancing charges; and
  • Over-accreditation of capacity for some conventional Long Island generation.

NYISO was able to substantially reduce the use of out-of-market dispatch to manage congestion on Long Island because they started modeling two 69-kV facilities, which were constrained on more than 80% of the days in the quarter, LeeVanSchaick said.

Despite several heat waves, load exceeded 30 GW on just one day, and transmission owners activated utility demand response on 10 days, mostly for peak-shaving.

NYISO applied supplemental resource evaluation (SRE) — a determination of the least-cost selection of additional generators to be committed — for statewide capacity needs on three days. Some of those SREs probably would not be necessary if there was more consideration of the utility DR deployments that are going to be called before the ISO makes the decisions, LeeVanSchaick said.

The Monitor identified several categories of conventional generating capacity that may receive excessive accreditation under the current rules, which he said should be evaluated further.

“We do also still observe large quantities of out-of-merit commitment for operating reserve requirements that are not adequately reflecting the day-ahead and real-time markets … both at the larger level as well as in more localized areas,” he said.

Reserve Enhancements for Constrained Areas

Pallavi Jain, energy market design specialist, presented a study evaluating the feasibility of dynamically scheduling reserves in the security constrained unit commitment (SCUC), real-time commitment (RTC) and real-time dispatch (RTD) intervals

“We’re looking at dynamically scheduling reserves because the current static modeling of reserves and the associated requirements may not optimally reflect the varying needs of the grid to respond to operating conditions,” Jain said.

Based on all the mathematical formulations and the prototype, the ISO has determined that it is feasible to set dynamic reserve requirements based on the single largest contingency systemwide and using the available transmission headroom. However, this concept would need to be further developed and its applications to all reserve areas would need to be evaluated, Jain said.

National Grid pipeline sections (National Grid) Alt FI.jpgNational Grid pipeline sections stacked during construction. | National Grid

 

The ISO made several recommendations, such as considering revising the approach for the determination of the single largest contingency from the current static requirement to a more dynamic methodology; applying the dynamic reserves approach to all reserve areas; and keeping the methodology consistent between the day-ahead and real-time markets to the extent practical.

Senior Manager Tariq N. Niazi presented a consumer impact analysis of the reserve enhancements for constrained areas, which looked at four scenarios based on conditions on Aug. 5, 2021, a hot summer day.

In three of the scenarios LBMPs decreased between $0.60/MWh and $2.60/MWh in different load zones and reserve clearing prices increased by less than $0.10/MWh in the reserve areas. A fourth scenario found an insignificant change in prices.

The ISO will continue working on the prototype in hopes of completing a market design proposal by December 2022 and implementation in 2025.

Coordinating Tx and Distribution

NYISO also updated stakeholders on a project to ensure coordination between transmission system operators (TSOs) and distribution system operators (DSOs) in compliance with FERC Order 2222.

The project will ensure that NYISO and the New York transmission operators have the communication protocols and procedures in place to maintain reliability as DER penetration increases, said Michael Ferrari, market design specialist in new resource integration. (See NYISO Updates Grid in Transition Work and Plan for 2022.)

The ISO has been working with the applicable member systems individually to identify transmission nodes, with those identified in the New York Control Area now totaling 115.

Transmission nodes are electrically similar facilities to which individual DER may aggregate as a DER coordinating entity aggregation (DCEA), represented by a single point identifier (PTID).

A transmission node might comprise several load nodes, which provide the most detail for NYISO system modeling and are associated with distribution stepdown transformers at facilities below the transmission level NYISO currently secures.

NYISO will present the list of transmission nodes at an ICAP meeting early in the first quarter of 2022.

NYISO and the investor-owned utilities in the state have created a framework to prohibit resources participating through an aggregator from receiving compensation for the same services as part of another program. The ISO’s Order No. 2222 compliance filing proposes to require aggregators make attestations that its DERs are not providing the same service(s) in a retail market or program.

To prevent double counting, NYISO is collaborating with the utilities to develop a document identifying retail market services that conflict with wholesale market services.

This project and current coordination efforts will continue in 2022 with a focus on facility enrollment; metering and communications infrastructure and configurations; and NYISO administrative and operational manuals, an aggregation program manual, and supporting modifications to existing manuals, Ferrari said.

One stakeholder expressed concern that the ISO was working only with the utilities on DER participation and not with aggregators, saying the one-sided approach is a missed opportunity to encourage DER participation.

The ISO responded that any utility denying participation to DER must provide detailed data to back up its rationale and lay out steps the utility will take to improve market access in that specific case.

Prohibiting Critical Infrastructure Load from DR Programs

Responding to NERC and FERC guidance, NYISO is proposing to prohibit market participants from enrolling critical infrastructure load in its demand response programs. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)

Critical infrastructure is load needed to deliver natural gas, fuel oil, and other fuels used to supply generation, and load otherwise likely to impact the supply of fuels to generators serving the New York Control Area, said Francesco Biancardi, market design specialist. It includes natural gas compressors, LNG storage facilities, fuel oil suppliers, refineries and control centers.

NERC on Oct. 6 submitted a Standard Authorization Request to address extreme cold weather grid operations, preparedness and coordination. Recommendation No. 8 states that “balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.”

In January 2021, approximately 1,071 kW of curtailment capability was offered by special case resources (SCRs) that include critical infrastructure load, according to an ISO survey of DR providers. About 175 kW of such curtailment capability was offered in July 2021.

While the total kW of demand response load is small as compared to total system MW, it is possible that curtailment of a small amount of critical infrastructure load could have a material impact on generator availability, Biancardi said. For example, curtailment of a few kW of natural gas compressor station load could cause an outage of many MW of generation, Biancardi said.

The ISO is working toward implementation before Winter 2022/23.

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BOEM Issues Final Environmental Review of NY Bight

The U.S. Bureau of Ocean Energy Management (BOEM) gave a green light for further offshore wind development in the New York Bight Thursday, issuing a final environmental assessment (EA) with a finding of no significant impact.

The report clears the way for auctioning of up to 10 new wind energy leases, the first of which are expected early in 2022.

The EA considered potential environmental consequences of the OSW development, which includes site characterization activities (i.e., biological, archeological, geological and geophysical surveys and core samples) and site assessment activities such as the installation of meteorological buoys. The EA also considered project easements associated with each potential lease issued and grants for subsea cable corridors.

BOEM determined that the OSW work in the Bight would neither cause any significant impacts, nor constitute a major federal action significantly affecting the quality of the human environment within the meaning of the National Environmental Policy Act of 1969.

“Adverse effects to the environment … would range from negligible to minor,” the EA said.

New York has contracted nearly half of the 9 GW of OSW targeted for construction by 2035. (See NY Awards 2.5-GW Offshore Deal to Equinor.)

OSW developers also have begun constructing the port facilities needed to build and operate their projects, with Equinor using the Port of Albany for tower manufacturing, the nearby Port of Coeymans for turbine foundation manufacturing, and making the South Brooklyn Marine Terminal into an assembly and operations and maintenance hub. (See NY Builds OSW Ports in Brooklyn, Albany, Long Island.)

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NYPSC OKs Exelon Spinoff of 4 Upstate Reactors

New York regulators on Thursday approved Exelon’s (NASDAQ:EXC) plan to split its regulated transmission and distribution business and merchant nuclear power generation into two separate publicly traded companies (Case No. 21-E-0130).

The Public Service Commission accepted a joint proposal by Exelon staff of the Department of Public Service, the state Attorney General, the Alliance for a Green Economy and the Long Island Power Authority for four upstate nuclear power plants to be spun off by Exelon.

The spinoff, Exelon Generation, will become part of a new, independent, publicly traded entity that owns the two-unit 1,918-MW Nine Mile Point nuclear power plants in Scriba, Oswego County; the 579-MW R.E. Ginna nuclear power plant in Ontario, Wayne County; and the 842-MW James A. FitzPatrick nuclear power plant, also in Scriba.

“Getting all the parties from disparate sides to sit at the table together to agree on this shows how significant their goals were of supporting the interests of New York,” PSC Chair Rory M. Christian said. “The simple fact that we’re going to be able to decommission these plants in 20 years, rather than the recommended 60, is a huge accomplishment. The financial protections you accomplished and achieved through these negotiations are just as significant.”

FERC in August approved the corporate transfer proposal, determining the transaction to be “consistent with the public interest” (EC21-57). (See FERC Sanctions Exelon’s Plan to Split Utility, Generation Businesses.)

The current operating licenses expire in 2029 for Ginna and Nine Mile Point 1, 2034 for FitzPatrick and 2046 for Nine Mile Point 2. The Nuclear Regulatory Commission (NRC) and the PSC required funds be set aside for the decommissioning of the facilities and the restoration of the sites.

Operational Details

Diane X Burman (NYPSC) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

A lot of these issues were not as contentious as others for the parties, so working with the collaborative process seems to have worked here, Commissioner Diane X. Burman said.

Exelon has an “extraordinary obligation” to the state of New York, considering the more than $7 billion in ratepayer money that supports the four units and without which these plants would have ceased operation some time ago, Commissioner John B. Howard said.

“Second of all, the parent of this company, it should be pointed out, has had serious corruption allegations in the state of Illinois, and those are being pursued by various law enforcement and prosecutorial entities in that state and with the federal government. So that was the background by which we started this case,” Howard said.

Exelon also has proven itself devoted to focusing on safety and reliability, Howard said.

John B Howard (NYPSC) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

In addition, the nuclear plants represent “a huge chunk of the overall central New York economy” and the people working at the facilities are “maybe the highest-paid and best-benefited workers in the region,” he said.

Under the approved proposal, Exelon and Exelon Generation agreed to the following:

  • Continuation of emergency operation facilities in New York;
  • Depositing an additional $15 million in the remedial trust fund for Nine Mile Point Unit 2 and maintaining a minimum trust fund balance of $144 million per unit — or $576 million in total across the four units;
  • Provide a 20-year projected backstop timeline for decommissioning following the end of licensed term rather than the 60 years allowed by the Nuclear Regulatory Commission;
  • Acknowledgment of New York State’s 10 millirem clean up guidance standard for residual radiation, rather than the NRC 25 millirem standard;
  • Annual decommissioning trust fund reporting rather than the 2-year summary level reporting to NRC, and twice-a-year reports during decommissioning; and
  • Provide an 18-month advance notice of shut down rather than the 12-month NYISO requirement.

Proposal supporters included the affected counties, the New York State Building and Construction Trades Council and the International Brotherhood of Electrical Workers, Local 97, representing approximately 4,700 electrical workers across upstate New York.

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FERC Sits Out One Grand Gulf Tax Dispute

FERC told the Louisiana Public Service Commission Thursday that it would not appoint a discovery master or settlement judge in an ongoing dispute over Entergy’s decommissioning deduction for its Grand Gulf Nuclear Station.

The PSC is attempting to compel Entergy subsidiary System Energy Resources, Inc. (SERI) to hand over accounting information and discussion notes with the IRS and understand the sudden decision to forgo a deduction it has enjoyed and renewed for 17 years (ER21-142).

However, the tax clash will continue to play out in another FERC docket.

The federal commission said in its order that state regulators were raising their arguments under an informal challenge as an interested party and that they needed a more formal channel for those measures.

The PSC filed the information request through a 2020 amendment to SERI’s formula rate protocols that allows interested parties to request information and submit informal challenges to unit power sales agreements. The commission claimed it needed to better understand Grand Gulf’s 2020 formula rate inputs.

SERI owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy’s Arkansas, Mississippi, Louisiana and New Orleans subsidiaries. It’s taken a tax deduction since 2003 for future costs of shuttering the plant.

The Louisiana commission alleges SERI’s Grand Gulf power sales agreements contain “millions of dollars of unjust and unreasonable charges” because it didn’t reflect the decommissioning tax benefit in its rates. The PSC has accused Entergy of collecting money from ratepayers for taxes that were never paid.

The Louisiana commission and Entergy are involved in a separate docket before FERC over whether the utility violated filed rate doctrine by neglecting to include the decommissioning deduction as a rate base offset. The federal commission this year set that case for settlement hearings to determine customer refunds (ER21-748).

SERI relinquished its decommissioning deduction in 2020 following an IRS Notice of Proposed Adjustment that disallowed more than $1 billion of the deduction. The subsidiary quickly accepted the settlement, and Entergy said its net operating loss carryforwards would absorb the adjustment’s costs.

The Grand Gulf plant has been criticized in recent years for its persistent unplanned outages. Earlier this year, the PSC was joined by the Arkansas Public Service Commission and the New Orleans City Council in a FERC complaint over the plant’s malfunctions and performance issues. The trio argued that Entergy should refund customers the $800 million spent on upgrades to the plant in 2012. They also said Entergy should refund its customers the $361 million in power purchases it has had to make when the station was unavailable since the upgrade.

The Louisiana PSC has registered other grievances about Grand Gulf rates, arguing that SERI’s return on equity was overstated. (See FERC Rebuffs Challenges to Grand Gulf Ruling.)

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FERC Ups Hydro Dam Inspection and Safety Requirements

FERC on Thursday approved a rule to improve hydro dam safety by instituting a two-tier inspection program and requiring such inspections to be performed by teams with site-specific expertise, rather than a single independent consultant.

Additional provisions in the rule (RM20-9-000) will also codify a 2012 requirement that dam owners develop and file with FERC a Dam Safety Program, as well as report any public safety incidents, including rescues, related to project operations. The rule passed unanimously, with newly installed Commissioner Willie Phillips not voting. It will take effect 90 days after publication in the Federal Register.

The new requirements are based on recommendations from an analysis of the February 2017 incident in which California’s Oroville Dam, the tallest dam in the nation, saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area. Emergency response and repairs cost more than $1.1 billion, said a recent report from the Congressional Research Service.

Citing that report, FERC Chair Richard Glick said that the U.S. has 90,000 dams, 15% of which are classified as “high hazard potential,” meaning that any failure of the dam could result in loss of life. In addition, half the dams are more than 50 years old and could require upgrades costing an estimated $20 billion, Glick said.

FERC has jurisdiction over more than 2,500 hydro projects, said a Hydropower Primer the commission released in 2017. Following the Oroville incident, FERC convened its own review panel to suggest potential changes to its Dam Safety Program. A notice of proposed rulemaking (RM20-9) was issued in July 2020. (See FERC Proposes Tougher Hydro Safety Rules.)

David Capka, director of the Division of Dam Safety and Inspections in the Office of Energy Projects, said the final rule contains some “clarifying edits” made in response to comments received from stakeholders, including dam owners, other federal agencies and trade associations. But otherwise, it is essentially the same as the 2020 NOPR, he said.

Two-tier System

Prior to the vote, Tara DiJohn, attorney-advisor in FERC’s Office of General Counsel, provided more detail on the four “overarching objectives” of the rule.

All hydro projects under FERC’s jurisdiction will still be subject to the commission’s inspection rules, as spelled out in regulations known as Part 12D, which require inspections every five years. But, DiJohn said, under the two-tier system, “the required scope of the inspection will alternate between a periodic inspection and a comprehensive inspection.”

Ultimate damage at the service spillway (California Department of Water Resources) Alt FI.jpg
Ultimate damage at the Oroville service spillway | California Department of Water Resources

Periodic inspections will focus on “the performance of the project over the previous five years,” she said. “It includes a field inspection or review of project operations, an in-depth review of monitoring data trends and behavior, and an evaluation of whether any potential failure modes are occurring.”

Comprehensive assessments will build on the periodic reviews “with a deep dive into every aspect of a project, including a detailed review of the design basis, analysis of records and construction history, and evaluation of spillway adequacy [and] potential failure modes analysis and risk analysis,” she said.

Commissioner Allison Clements raised concerns about the cost of the new inspections. “If we’re going to strengthen safety, we have to balance the benefits of more stringent requirements with the cost burden to the regulated [projects], including the smaller entities that may have fewer resources,” she said.

The two-tier system is intended to help offset the cost of inspections, DiJohn said, with the periodic inspections being “less burdensome.” With smaller, less complex projects, licensees can also propose a single independent consultant to perform the inspection, she said.

First Line of Defense

The second major provision modifies who performs the Part 12D inspections. “Instead of focusing on the individual independent consultants, we will focus on the qualifications of the independent consultant teams,” DiJohn said.

“We have a lot of very large and very complex projects, and requiring one person to be responsible to review all the features of those projects is a lot to ask,” she said. “To have the right expertise, we want to ensure that licensees look at teams to do that.”

While first required in 2012, the Dam Safety Programs codified in the new rule will “formalize licensees’ policies and procedures related to organizational oversight and responsibilities, internal communication, resource allocation and continuous improvement,” DiJohn said. “A proactive, conscientious licensee is the first line of defense against potential dam safety issues.”

Finally, the rule expands requirements for reporting on public safety incidents at or near dams, DiJohn said, adding rescues to the list of incidents to be reported, along with serious injuries and deaths.

Calling dam safety “one of our most important jobs,” Glick said the new rule was “a step in the right direction … [but] not the end of our efforts to protect the public.” The commission is planning a staff-led technical conference, possibly in April, Glick said, examining financial assurance measures for hydropower projects to ensure than licensees have sufficient financial resources for dam maintenance and repair as needed for public safety.