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November 7, 2024

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Oregon Study to Examine Prospects for Floating Offshore Wind

An upcoming study on the “benefits and challenges” of developing floating offshore wind (FOSW) off the coast of Oregon will explore a range of topics to help inform state lawmakers looking to produce bills to cultivate the sector.

Among the topics under examination: What impact, if any, would the state’s participation in an RTO have on facilitating development of FOSW?

During a virtual meeting to kick off the study, Jason Sierman, senior policy analyst with the Oregon Department of Energy (ODOE), said that areas of the East Coast currently seeing heavy development of OSW all have RTOs or ISOs.

“The department is interested in exploring how the nuances [of RTOs] could pose benefits and challenges to floating offshore wind coming to Oregon,” Sierman said. “Have RTOs helped spur the development of offshore wind on the East Coast? Was it primarily driven by costs or the state mandates? Or were RTOs helpful for that? Could that type of transmission structure potentially be a key for helping to spur floating offshore wind development off Oregon’s coast?”

The Oregon FOSW study is the product of House Bill 3375, passed last year to require ODOE to examine the impacts of integrating 3 GW of offshore wind into the region’s electricity system by 2030. ODOE staff are initiating the project close on the heels of completing another study weighing the benefits and risks of Oregon joining an RTO, which was submitted to the legislature late last month. (See Study Provides Ore. Lawmakers with Wide Shot on RTO Membership.)

In a similar vein to the RTO study, the FOSW report is not intended to offer policy recommendations. Instead, HB 3375 calls for ODOE to conduct a literature review and gather input from industry and regional stakeholders, various Oregon state agencies and federal entities such as the Bonneville Power Administration, the Bureau of Ocean Energy Management, the Department of Defense and energy research laboratories.

Ruchi Sadhir, ODOE associate director of strategic engagement, said the study will examine the FOSW issue from a range of perspectives, including renewable energy goals, job creation, infrastructure, transmission and ports, resilience and reliability, as well as “potential effects like impacts to ocean users and land users, impacts to the environment, public beaches, scenic byways — that sort of thing.”

“We would like the end product to be a final report to the legislature that provides neutral reporting on the literature and the range of perspectives that we’ve heard throughout this study process,” Sadhir said.

West vs. East

Oregon and the West Coast differ from the East Coast in that a sharp drop-off in the continental shelf relatively close to the coastline makes the installation of fixed-bottom OSW turbines impossible, leaving as the only option the less common floating turbine designs, which are just a “blip on the map” compared with fixed designs, Sierman said.

“There’s just a handful of [FOSW] projects out there right now, and the largest project is 50 MW, so relatively small in the grand scheme of energy projects. And the bottom line here is it’s a nascent industry,” translating into higher costs to build, Sierman said.

The West and East coasts also differ in that population centers in the former are largely situated far from the coast, leaving little existing transmission infrastructure available to interconnect large-scale OSW projects.

Sierman pointed out that most of the Pacific Northwest’s high-voltage transmission network was designed to carry energy from large hydroelectric dams in the Columbia Valley to the region’s load centers, while no large lines run out to the coast, where the largest are 230 kV.

“The big takeaway here is that as economies of scale might drive up floating offshore wind projects, there’s kind of an upper bound or a limitation currently without upgrades to existing transmission infrastructure here,” Sierman said.

For that reason, questions regarding transmission infrastructure will be one of the key topics addressed by the study. Other topics include FOSW technology, port infrastructure, siting and permitting, and “foundational” questions related to clean energy targets, equity and economic development. Another topic covers energy markets and RTOs.

Responding to a question from RTO Insider, Sadhir said the study would not attempt to capture the varying economics of placing wind turbines in different wind speed zones.

“We don’t expect to have our own technical analysis occurring,” she said. “It’s more about reviewing the literature, sharing it and giving an opportunity to get those qualitative perspectives from stakeholders on those questions as well.”

But Sadhir said the study will consider how OSW can contribute to the region’s resource adequacy, a subject she called “very topical in the energy sector.”

ODOE must submit the completed study to the legislature by Sept. 15, Sadhir noted. The department is seeking stakeholder comments by Feb. 18 and will hold another public meeting on the subject March 10.

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COVID Leads GCPA to Reschedule MISO-SPP Conference

HOUSTON — The Gulf Coast Power Association said Thursday during its annual meeting that it has rescheduled its annual MISO South-SPP regional conference to March 30-31 in New Orleans.

GCPA had canceled the conference, originally scheduled to take place Feb. 9-10, because of an increase of COVID-19 cases in Louisiana and its “concern for the safety of our attendees.” The organization’s executive director, Kim Casey, said several speakers had also expressed concerns about attending.

Mark Dreyfus Katie Coleman 2022-01-20 (RTO Insider LLC) FI.jpgKatie Coleman (right) congratulates her successor as GCPA president, Mark Dreyfus. | ©RTO Insider LLC

The city of New Orleans requires a mask in all indoor spaces and proof of vaccination or a negative COVID test within 72 hours for indoor dining, bars and event spaces. Effective Feb. 1, the city’s protocols will require proof of two vaccine doses or one dose of the Johnson & Johnson vaccine, or proof of a negative COVID test within 72 hours.

The organization will reopen registration for the conference on Tuesday. Barring further developments, the two-day conference will be held at the Pan American Life Center. MISO CEO John Bear and SPP CEO Barbara Sugg had both agreed to deliver keynote addresses.

The annual conference was last held in 2020. It was canceled last year because of the pandemic.

This year’s meeting will mark the beginning of energy consultant Mark Dreyfus’ two-year term as GCPA’s president. Dreyfus succeeds Katie Coleman, a partner in O’Melveny & Myers’ Austin office.

Dreyfus, who has 25 years of industry experience, praised Coleman, whose term began just before the world shut down for the pandemic and also included the state’s response to the February 2021 winter storm.

“Katie led GCPA through these last two challenging years,” Dreyfus said. “My focus in this next year is to continue the recovery of the organization from the impacts of COVID, focusing on GCPA’s core functions of information exchange through our quality, low-cost conferences, and creating networking opportunities for our members.”

GCPA members also voted MISO’s Daryl Brown, executive director of external affairs for the RTO’s South region, to its board of directors.

GCPA is a regional electric power trade organization that serves Texas and the Gulf Coast and promotes an improved understanding of power market issues and opportunities.

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DC Circuit Upholds FERC on Duke-Muni Battery Dispute

The D.C. Circuit Court of Appeals said Friday it would not “second guess” FERC’s interpretation of a power purchase agreement between Duke Energy Progress (NYSE:DUK) and the North Carolina Eastern Municipal Power Agency (NCEMPA), upholding a ruling that allowed the latter to use storage to reduce its capacity charges (20-1495).

NCEMPA, which serves 32 cities and towns with municipal electric distribution systems, asked FERC in 2019 to issue an order declaring that its 2015 “full requirements” PPA with Duke permitted it to use battery storage to reduce the munis’ load during the peak hour each month that is used to determine capacity charges.

The capacity charge — based on NCEMPA’s pro rata share of the demand on Duke’s system during the one-hour peak — is intended to cover Duke’s fixed costs and provide a return on its infrastructure investments. NCEMPA also pays an energy charge to reimburse Duke for its fuel costs and variable operations and maintenance costs.

The munis cited sections 9.4 of the PPA, which permits demand-side management (DSM) (e.g., end users allowing the agency to turn off appliances during high-demand periods), and section 9.5, which permits demand response (end users acting themselves to curtail consumption in response to real-time price signals).

Duke spokesperson Randy Wheeless said the company was disappointed by the D.C. Circuit’s ruling. The company asked FERC in December to approve revisions to the PPA on the assumption that the commission’s ruling would be upheld on appeal (ER22-682).

“Although Duke Energy is supportive of battery storage technology, we must be mindful how the current rate design could potentially shift costs and unfairly burden other customer groups,” Wheeless said Saturday. “As more energy storage devices are deployed, this issue will continue to arise between utilities and wholesale customers.”

FERC Order

FERC granted NCEMPA’s request in an order in September 2020 (EL20-15). (See NC Muni Wins Right to Add Storage over Duke Objections.)

In its appeal, Duke contended that batteries don’t qualify as DSM or DR. And it said allowing NCEMPA to use batteries would make the PPA “confiscatory” by permitting the agency to reduce its demand to zero during the system peak, eliminating its payments toward Duke’s fixed costs.

The D.C. Circuit said the case hinged on two competing interpretations of section 9.5, which it called “a model of ambiguity.

“It does not define demand response; it never mentions batteries; and interpreting the provision required the commission to infer the meaning of two of its terms, ‘demands’ and ‘load,’ by reference to another provision of the agreement,” Circuit Judges Karen LeCraft Henderson, David S. Tatel and Cornelia Pillard ruled in an opinion written by Tatel.

Duke contended that section 9.5 only permitted reducing demand through communication of pricing information to the agency members and their customers. FERC concluded that the language allowed NCEMPA to reduce members’ demand through the use of pricing information — specifically the “combined system load signal” — data that allow the agency to predict when the maximum demand on Duke’s system will occur.

FERC noted that “Duke will continue to supply (and [NCEMPA] will continue to pay for) the energy needed to charge any batteries.”

“Given that we must ‘defer to the commission’s construction of the provision at issue so long as that construction is reasonable,’ it is not enough for Duke to offer its own reasonable interpretation of the provision,” the court said. “Instead, Duke must demonstrate that the commission’s interpretation is unreasonable. It has failed to do so.”

The court said section 16 of the PPA outlines a process for Duke to propose changes to the agreement if the utility has “concerns regarding whether the contract remains appropriately compensatory.”

“Accordingly, should [NCEMPA] deploy its batteries in a way that renders the agreement ‘confiscatory,’ Duke can return to the commission for relief,” the court said.

Contract Revision Sought

Duke did just that in seeking to reopen the PPA on Dec. 17.

“The enclosed rate design change is required because, even since the commission’s interpretation of the contract, certain power agency members have publicly and clearly announced their intention to procure enough battery storage technology to drastically reduce, and even eliminate entirely, their responsibility for capacity charges by superficially reducing or eliminating their demand only during the single coincident peak hour of the month, even though their reliance on the [Duke] system during the majority of other hours in the month continues unabated,” it said.

NCEMPA protested, saying Duke’s
“proposal would penalize the development of distributed energy resources, not only by NCEMPA and its members, but also by the members’ retail customers, thus increasing the cost of the resource transition, undermining reliability, and potentially increasing the use of carbon-emitting resources.” On Monday, NCEMPA filed a motion to lodge the D.C. Circuit’s ruling in the FERC docket.

Drew Elliot, manager of government affairs for NCEMPA parent ElectriCities of NC, said two of the agency’s larger member utilities — each 1,000 kW AC — have installed pilot battery projects since May 2019. “They are operated by the individual utilities, not the power agency, and are used for peak shaving,” Elliot said.

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MISO Promises Long-range Tx Project Reveal Soon

MISO is close to proposing its first cycle of projects under its long-range transmission effort and has signaled that a massive transmission line touching four states shows promise.

During a special stakeholder workshop Friday, the RTO promised more specifics on project proposals next month.

“This work is complicated, but we’re starting to see some clarity around our first tranche of projects,” MISO’s Jarred Miland said.

Miland said staff has completed much of the reliability analysis on prospective projects, with economic analysis to continue into February. Transmission planners will have the projects’ business justifications solidified sometime in March, he said.

By April, discussions on the long-range projects will be handed over to the Planning Advisory Committee, Miland said. The RTO plans to have its board of directors vote on approval of the first cycle of projects in mid-June. (See MISO Postpones 1st Cycle of Long-range Projects.)

The first group of projects are limited to the Midwest and based upon MISO’s most conservative 20-year transmission planning future, which contemplates the three futures’ least amount of renewable penetration, fossil fuel retirements and electrification.

MISO is optimistic that a vast, curved 345-kV project would cross through Iowa, Illinois, Indiana and Michigan. The RTO said the line resolves “multiple, severe” steady state issues from the first planning future.

Staff said while the project appears to be a standalone corridor on a map, it ties into MISO’s existing 345-kV system at several points.

“It’s not one long line. It’s more of a reinforcement of the existing system; it’s not just a point A to point B,” MISO expansion planning adviser Matt Tackett said.

Tackett also said a 345-kV rating is the best call for the massive project. “While we intend to look into higher voltage, 765-kV lines in the future … we need a strong underlying 345-kV system to build on,” he said.  

Study continues on a handful of smaller, 345-kV projects that are spread across central Iowa, northern Missouri, the Dakotas and western Minnesota, and Minnesota into Wisconsin. MISO is interested in constructing a path between South Dakota’s existing 345-kV infrastructure and a 345-kV line in southwest Minnesota built under its CapX2020 initiative.  

While MISO is not prepared to issue cost estimates, some stakeholders said the first cycle of projects could reach $10 billion.

MISO Senior Engineer James Slegers said though the new lines may be near existing transmission and might be able to share right of way, staff is not going to propose the removal or replacement of existing lines under the long-range plan.

Staff also said they’re monitoring and sharing results with the MISO-SPP team working on the RTOs’ Joint Targeted Interconnection Queue (JTIQ) searching for interregional transmission projects to boost generation interconnections.

Julie Fedorchak, chair of North Dakota Public Service Commission, has pointed out that some projects under consideration in the plan are included among the joint study’s possible transmission solutions.

“That bothers me because they obviously have benefits to SPP if they’re on the JTIQ map,” Fedorchak said during a Jan. 13 Organization of MISO States meeting.

Aubrey Johnson, the RTO’s executive director of system planning, said that if similar solutions are showing up in both the long-range and JTIQ studies, it shows how desperately needed the projects are.

“We are internally discussing how to handle that overlap,” Johnson said. “Ultimately, these are all projects that are wholly located within MISO, so we think it’s appropriate to include them in the long-range plan.”

Customized Energy Solutions’ Ginger Hodge said she was concerned about a “lost opportunity” to share costs if the projects are shown to benefit SPP.

“I just really encourage MISO to think about that,” she said.

Stakeholders also asked that MISO’s models contemplate that the Cardinal-Hickory Creek line never gets energized. A federal judge recently ruled that the line couldn’t cut through protected wildlife habitat in Wisconsin. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.)

The Cardinal-Hickory Creek line is the last of MISO’s $6.7 billion, 17-project Multi-Value Project portfolio approved in 2011; MISO has long assumed the project will become part of its system.

Some stakeholders asked whether the grid operator would increase its renewables projections before it proposes long-range projects based on the second and third future scenarios. MISO developed its current set of planning futures in 2020, and some stakeholders said that the speed of renewable installations can mean transmission projections quickly become outdated.

Johnson said he didn’t see a need for that as MISO’s three planning futures account for anywhere from 130 to 330 GW of resource additions, mostly from renewable sources.

“I think we’ve got it covered,” he said.

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FERC Grants MISO Temporary Storage Waiver

FERC last week gave MISO a hall pass on ensuring offline energy storage resources (ESRs) can furnish certain types of energy reserves.

Thursday, the commission granted the RTO both a temporary waiver and removal of tariff language that states offline storage resources can provide supplemental reserves or short-term reserves. The waiver is effective Nov. 23, 2021, and the tariff edits took effect Dec. 7 (ER22-461 and ER22-462).

MISO said that in implementing its new short-term reserve product late last year, it discovered that its markets cannot clear those reserve offers from energy storage resources, which currently only participate as either Stored Energy Resource Type II (SER Type II) or Demand Response Resource Type II (DRR Type II).

The grid operator said since its systems currently cannot track energy storage’s state of charge, it can’t detect whether those storage assets are offline.

SER Type II is a temporary resource designation created in 2017 for use until no later than 2023, when MISO should have a full participation model in place for storage under FERC’s Order 841. SER Type II was modeled after MISO’s existing DRR Type II. (See FERC OKs MISO Plan to Expand Storage.)

The RTO has committed to phasing out SER Type II “soon after” storage resources have access to full market participation under MISO’s Order 841 compliance design. The grid operator will begin registrations for storage assets in early June and open full market participation to them sometime in September.

MISO said it would be “extremely complicated, costly and time-consuming to explore, develop, test and install a software solution” that would allow offline storage to provide short-term and supplemental reserves until its full storage participation model is up and running.

FERC called the waiver an “appropriate interim solution.”

The Solar Energy Industries Association (SEIA) protested MISO’s plan, arguing that it “must compensate offline storage resources for the services those resources provide.”

But the commissioners agreed that MISO shouldn’t have to incur steep costs and man-hours creating a temporary fix. It also said the RTO seemed to have acted in good faith.

“We disagree with SEIA’s arguments that MISO’s proposed tariff revisions are an attempt to limit storage resources’ ability to participate in the markets. We note that, in fact, MISO’s proposed tariff revisions are a temporary measure until such time when [energy storage resources are] fully integrated in MISO’s markets,” FERC said.

MISO’s short-term reserve product went live Dec. 7. It’s meant to source energy within 30 minutes where needed from both online and offline resources, while accounting for real-time transmission constraints. (See MISO Begins Software Build on Short-term Reserves.)

The grid operator has said the reserves will reduce make-whole payments, cut down on out-of-market commitments, make market pricing more transparent, and provide pricing signals that encourage a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply.

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Tri-State Reaches Settlement over Resource Plan

Tri-State Generation and Transmission Association has reached a settlement with more than two dozen of its members and other parties over the first phase of its 20-year, $21.3 billion plan to reduce its carbon dioxide emissions.

The Colorado-based cooperative said Wednesday that the “landmark” agreement, filed for approval with the Colorado Public Utilities Commission, sets near-term targets for greenhouse gas emission reductions before 2030 as part of its Responsible Energy Plan (20A-0528E).

Duane Highley (SPP) Content.jpgTri-State CEO Duane Highley | SPP

Tri-State CEO Duane Highley thanked the cooperative’s members, state officials, environmental advocates and labor representatives who worked on the settlement, which he called “a meaningful advancement in our efforts to transform our cooperative as we responsibly serve reliable and affordable power to rural communities, for our members and Colorado.”

The agreement includes “numerous and complex provisions” resolving Phase I of Tri-State’s electric resource plan (ERP) that it filed with the PUC in December 2020 as part of an ongoing proceeding.

Under the settlement’s terms, Tri-State agreed to reduce GHG emissions related to its wholesale sales in Colorado by 26% in 2025, 36% in 2026, 46% in 2027 and 80% in 2030. The amounts will be calculated based on the cooperative’s 2005 emissions baseline.

Tri-State also said it will report its progress on GHG emission reductions to the commission in its ERP annual progress reports going forward and conduct a competitive solicitation for new resources with in-service dates through 2026.

The parties, which included PUC staff, agreed to recommend the PUC approve Tri-State’s resource plan, subject to certain modifications in the settlement. They also agreed to an extensive set of modeling assumptions and inputs for the ERP’s second phase.

Tri-State expects the commission to review and consider the settlement’s approval during the first quarter this year.

Jon Goldin-Dubois, president of Western Resource Advocates, said Tri-State “has come a long way” in “committing to near-term, enforceable reductions in climate-changing greenhouse gas pollution.”

“This agreement will make significant progress in accelerating emission reductions in the West, all while reducing costs for customers and supporting communities most impacted by the transition,” he said. “We have much work to do, but Tri-State is to be commended for taking these steps to maximize near-term emission reductions, the most important action society can take to avoid the worst impacts of climate change.”

Goldin-Dubois was one of several environmental advocates and members quoted in Tri-State’s press release announcing the settlement. Those groups are among those that have previously criticized the cooperative for its reliance on coal-fired energy.

Colorado lawmakers passed legislation in 2019 requiring utilities to cut CO2 emissions by 80% from 2005 levels by 2030 and 100% by 2050.

In January 2020, Tri-State responded with its Responsible Energy Plan to shut down more than 1.1 GW of coal-fired resources, transition to a cleaner energy portfolio and ensure compliance with Colorado’s environmental regulations. (See Tri-State to Retire 2 Coal Plants, Mine.)

Tri-State said it added 304 MW of wind energy last year, and it plans to add six additional solar projects by 2024. It said renewable energy will account for 50% of its 42 members’ consumption that year and 70% by 2030.

The settlement agreement’s additional modeling will include continued analysis of the retirement date for Craig Station Unit 3, which previous modeling validated would retire by 2030.

United Power to Exit Tri-State?

While Tri-State works to clean up its fuel mix, it may also lose one of its largest members.

United Power, which accounts for about 20% of Tri-State’s business, filed with FERC in December its intention to withdraw from Tri-State, effective January 2024 (ER21-2818).

United made its termination contingent on FERC’s determination that the exit fee to leave the association is just and reasonable. Last November, the commission accepted Tri-State’s methodology for calculating membership exit fees, subject to a refund hearing set for May, and also opened an inquiry under Section 206 of the Federal Power Act. (See FERC Accepts Tri-State’s Exit Fee Calculation.)

“Tri-State will work with United Power, as it would with any other member, through the contract termination process to support an orderly withdrawal,” Highley said in a statement. “The contract termination tariff approved by the FERC ensures that any utility member’s withdrawal does not harm the remaining members of our cooperative or Tri-State.”

Kit-Carson-Windpower-(Tri-State)-Content.jpg

Tri-State’s Kit Carson Windpower facility | Tri-State

United has said its exit fee should be between $200 million and $300 million. Tri-State has set the amount at $1.5 billion.

Two of Tri-State’s members have already paid the exit fee and left the association. As many as eight other members have asked the co-op what it would cost them to exit their contracts.

Kit Carson Electric Cooperative departed in 2016, paying $37 million, and Delta-Montrose Electric Association left in 2020, paying $136.5 million. (See Tri-State, Delta Officially Part Ways.)

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DOE-DOT Joint Office to Begin Rollout of EV Infrastructure Funds

The Joint Office of Energy and Transportation will take the first steps in rolling out the Infrastructure Investment and Jobs Act’s (IIJA) $7.5 billion in funding for a national electric vehicle charging network next month when it releases a guidance document to help states submit plans for the federal dollars.

Announced Thursday at the National EV Charging Summit, the guidance document “will really be the beginning of a very deep collaboration where states are developing EV development plans, but we at the federal government level, the joint office, will be working very closely to support the states, provide them with the data — the information, the know-how — in that process,” said Michael Berube, the Department of Energy’s deputy assistant secretary for sustainable transportation.

The goal will be to get the state plans submitted and approved, and then to get the first federally funded chargers installed this year, Berube said. “But our point really is, let’s get it right. Let’s make sure we have a good national plan.”

While not providing specifics, Polly Trottenberg, deputy secretary at the Department of Transportation, said the guidelines would reflect the joint office’s goals of equity, accessibility, reliability and affordability and include standards and requirements for industry partners to follow.

“The initial focus is really building out those national [charging] corridors coast to coast,” Berube said. “We’re going to make sure we’re hitting all the communities — rural spaces, urban spaces, everywhere there are interstates and major travel corridors — so that will provide a certain backbone of access and equity.”

Transportation Secretary Pete Buttigieg and Energy Secretary Jennifer Granholm launched the joint office in December to oversee the rollout of the EV charging funds from the IIJA. Trottenberg said $5 billion will go to “formula” grants to help the states implement their EV charging plans and $2.5 billion to a discretionary grant program.

The discretionary funds are intended, in part, for communities “where otherwise private investment wouldn’t go,” Berube told reporters after the announcement. The priorities include environmental justice issues and “those people that don’t have EV charging at home because those are problems and that’s really where government can come in to help solve some of those issues,” he said.

“We’re going be looking for ideas from the public sector, the states on innovative services to provide charging for people in that situation,” Berube said. “Is it DC fast-charging in their community? Is it Level 2 overnight charging? Is it street charging or at least at the multiunit dwelling facility? So, there is not a one-size-fits-all.”

Collaboration across federal, state and local agencies and the private and nonprofit sectors was itself a central theme of the half-day summit, which was organized by the National EV Charging Initiative, a coalition of regional and national groups, private companies and labor.

Working with utilities to ensure grid reliability, especially as the number of EVs and chargers increase, is also part of the joint office’s vision, Berube said.

“We have some test cases looking at smart charging management to have both EVs and the grid working together … to basically make sure that as we add EVs, which will be the largest new load on the grid, we do it in a way that can be managed as a managed load,” he said. “That is a lot of the Level 2-type charging, workplace charging, home and community-based charging. Deploying that smart charger technology at the grid side and the charger side will be one key aspect of the sector.”

The other big focus for the joint office will be highway charging facilities with fast chargers that can be upgraded continually, Berube said. With fast-charging technology hitting 150 kW and even 350 kW, the highway network “will really start to get the future EVs that are in the 300-mile range chargeable in that 15-minute window,” he said. “That’s the vision.”

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NYPSC Mandates Meshed Offshore Tx Grids

The New York Public Service Commission on Thursday unanimously approved requiring offshore wind project developers to provide “mesh-ready” transmission plans in their bids for state solicitations, as recommended by the commission’s power grid study a year ago (Case Nos. 15-E-0302; 18-E-0071; 20-E-0197).

The commission’s order seeks detailed plans from Con Edison for a wind energy interconnection hub, particularly on the availability of points of interconnection in lower Manhattan for up to 6 GW of offshore injections.

“The order will complete the requirements established by the Accelerated Renewable Energy Growth and Community Benefit Act of 2020 and ultimately improve the utility of the state’s entire renewable energy portfolio,” said PSC Chair Rory Christian.

OSW proposals that integrate energy storage will receive extra scoring weight under the order, and a new technology working group will test and deploy advanced transmission technologies. The PSC scheduled a virtual technical conference on Jan. 27 for utilities to present an overview of the proposed coordinated grid planning process.

The Initial NY Power Grid Study Report released last January by the state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA) recommended that transmission planners focus on beefing up the infrastructure needed to import 6 GW of offshore wind energy into New York City. (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

Details and Costs

“The power grid study suggests that constructing an offshore grid network may have significant advantages in terms of operational flexibility, reliability and ratepayer benefits,” Robert Rosenthal, general counsel to the commission, said in testimony.

Under prior orders related to offshore wind, the commission required NYSERDA solicitations to include direct or radial lines to the point of interconnection. A single radial configuration could result in the energy from the project not being deliverable with advanced system in an outage situation, he said.

By contrast, projects with a meshed grid would be connected to each other in the ocean, from which a number of transmission lines will be interconnected to the onshore grid. Rosenthal said. If one line is down, he said, the energy can be diverted to another line.

“As the power grid study recommended, the order directs that NYSERDA modify its offshore wind procurement requirements to include mesh-ready design, primarily because the cost of modifying projects on the design team is small in comparison to the cost of a future retrofit,” Rosenthal said.

In addition, the power grid study highlights the significant constraints that impact the possible undersea transmission cable routes into New York Harbor, including the anchorage areas and navigation channels that occupy an area known as the Narrows.

Coordinated state planning for the use of this corridor into New York City is critical, says the order, which directs staff to collaborate with other state agencies to develop plans for cable routing and report on their progress no later than Sept. 1.

Mesh-ready costs (NYDPS) Content.jpgMesh-ready costs for 230 kV, including transformation | NYDPS

 

The order acknowledged a recommendation in the power grid study for interconnections to use 320 kV direct current or DC cables to maximize the capacity that can be carried through the available corridors, and it requires the use of DC transmission as part of future offshore wind solicitations.

“I will caution that we aren’t over the hump by any stretch, and in fact we’re really at the starting gate,” said Commissioner Diane X. Burman. “We still have to set up a hub, to look at siting, and we have to address the supply chain challenges.”

With all the talk of offshore wind and community solar, very little attention has been paid to the transmission needed to make new generation assets work for the grid and which will allow decarbonization to be a reality, said Commissioner John B. Howard.

On the issue of cost there are two parts: how much it actually costs to do these projects and who should pay, Howard said.

The mesh grid for offshore will be not so much a technological challenge as a bureaucratic and regulatory challenge. Making the mesh grid work along the Northeast coast will require cooperation from neighboring states as well as neighboring RTOs on cost allocations, and a large share of planning and funding will fall to the federal government, he said.

Any cost analysis should include the full amount of what it may cost to taxpayers or ratepayers, and particularly for the issues surrounding the Con Ed hub, which may incur billions of dollars in costs and trigger “well over $100 million of windfall potentially to the city of New York,” Howard said.

“We have tried to slay this dragon as best we can, but it would have been far better for all New Yorkers had these issues of transmission and system integration fees been articulated at the front end of our desire to decarbonize our system,” Howard said.

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California PUC Postpones Net Metering Plan

The California Public Utilities Commission is delaying its consideration of a highly controversial plan to slash rooftop solar credits amid an outpouring of criticism, including from Gov. Gavin Newsom and former governor Arnold Schwarzenegger.

The proposed decision, released in December, would reduce electric bill credits for homeowners with rooftop solar arrays by up to 80% and add a monthly grid charge to their bills. (See California PUC Proposes New Net Metering Plan.)

Opponents, led by the solar industry, contend it will decimate rooftop solar adoption. Proponents, including the state’s large investor-owned utilities, argue utility-scale solar is more cost-effective and can serve far more consumers.

The CPUC said in its proposed decision that the current net-metering scheme unfairly shifts costs from homeowners who can afford rooftop solar to those who cannot.

It “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” Administrative Law Judge Kelly Hymes wrote.

The proposal was widely expected to be taken up at the commission’s voting meeting on Jan. 27, the earliest date on which it could be heard under commission rules, but the CPUC’s agenda for the meeting does not include the item.

In a recent press conference, Newsom said he thinks the plan needs more work. (See CPUC Takes Heat on Rooftop Solar Plan.)

And in a New York Times opinion essay published Jan. 17, Schwarzenegger criticized the plan as a threat to solar adoption.

“California has more rooftops with solar panels than any other state and continues to be a leader in new installations,” he said. “But a proposal from the state’s public utility commission threatens that progress. It should be stopped in its tracks.”

The state’s generous net energy metering (NEM) rates are credited with helping to install roughly 1.3 million residential arrays. NEM offsets customer bills at full retail electricity rates, which are much higher than current solar costs.

In an email Thursday, CPUC spokesperson Terrie Prosper said the commission felt it was too soon to vote on the proposed decision.

“We have two new commissioners, one of whom has not started yet,” Prosper wrote. “Comments from parties on the proposed decision have just been received for this extremely important policy matter. We will provide more information once a schedule has been determined.”

Newsom appointed his former energy adviser, Alice Reynolds, as the new president of the CPUC in November. (See Calif. Governor Names Next CPUC President.)

In December he appointed John Reynolds (unrelated to Alice), a lawyer and former CPUC staff member, to fill the seat vacated by Commissioner Martha Guzman Aceves. Reynolds previously worked as managing counsel to self-driving car company Cruise in San Francisco. He has not yet begun work at the commission.

Guzman Aceves, the lead commissioner on the proposed net-metering plan, left the CPUC to become head of the EPA’s Region 9 in December, at about the same time that former CPUC President Marybel Batjer retired. (See Biden Appoints CPUC Commissioner to Head EPA Region 9.)

The CPUC’s two new members, Newsom’s critique and the largescale public outreach campaign by the solar industry now leaves the plan in limbo.

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FERC Proposes New Cybersecurity Standard

FERC on Thursday issued a Notice of Proposed Rulemaking that would have NERC to expand its Critical Infrastructure Protection (CIP) reliability standards to cover internal communications (RM22-3).

The proposed standards would require registered entities to implement internal network security monitoring (INSM) for high- and medium-impact bulk electric system cyber systems (BCS), correcting what FERC staff called a “gap in the security standards” during Thursday’s open meeting.

Currently the CIP standards require a utility to monitor communications from the inside of its electronic security perimeter (ESP), the electronic border around the internal network to which BCS are connected, to the outside. The NOPR seeks to expand this monitoring to communications within the ESP, allowing “the earliest possible alerting and detection of intrusions and malicious activity” into the “trust zone” — the utility’s internal computing environment that is protected by the ESP.

As defined in FERC’s order, INSM is not a single process or piece of software but rather a set of practices for gaining visibility into an entity’s own system. It includes tools such as antimalware, intrusion detection and prevention systems, and firewalls; this software can have both passive, information-gathering applications, or active functions that block malicious network traffic.

FERC’s order was motivated by recent cyberattacks, most prominently the SolarWinds hack of 2020. The hack of SolarWinds’ Orion management software, used by thousands of public- and private-sector organizations around the world (including FERC itself), left many of those entities with malicious code inside their systems. (See FERC, E-ISAC Report Details Reach of SolarWinds Compromise.) Last April the U.S. accused Russia’s Foreign Intelligence Service of perpetrating the original attack and later leveraging their access to gain network privileges to SolarWinds’ Microsoft 365 and Azure Cloud environments.

Because the compromised software came via Orion’s official update channel, the SolarWinds attack “demonstrated how an attacker can bypass all network perimeter-based security controls traditionally used to identify the early phases of an attack,” FERC staff said. Adding INSM to the CIP standards would give all entities the means to detect and respond to suspicious activity by software within the network by, for example, recording normal network traffic and using it as a baseline to flag anomalous activity for further investigation.

“If [the hackers] do get in … you’d have enough awareness about that early to be able to take quick action to alleviate any concerns that might exist,” FERC Chairman Richard Glick said in a press conference following Thursday’s meeting. “Sometimes people get into your system using these perfectly legitimate pieces of software … and so, companies need to be vigilant not only about hackers getting in [but also] if people figure that out, let’s make sure that we have our defenses on internally to be able to address that as quickly as possible.”

For now, FERC is only proposing to add INSM to high- and medium-impact BCS because those systems are defined in the CIP standards, while low-impact systems are not; this distinction makes it difficult to apply CIP requirements to low-impact BCS because there is much more variety among these systems.

However, staff said in Thursday’s meeting that they “are seeking comments on the usefulness and practicality” of requiring INSM in low-impact systems, along with potential challenges of implementing INSM in general, what hardware and software capabilities would be needed to achieve the NOPR’s security goals, and what is a reasonable time frame for developing and implementing the new reliability standards.

Comments on the NOPR are due 60 days after its publication in the Federal Register.