PJM can attain extensive decarbonization with lower costs to consumers by 2030 through the pursuit of market-based policies like carbon pricing instead of relying on various state clean energy policies and subsidies, according to a new study released Wednesday.
The study, “Least Cost Carbon Reduction Policies in PJM,” was prepared by California-based consulting firm Energy and Environmental Economics (E3) on behalf of the Electric Power Supply Association (EPSA). It found that greenhouse gas emissions could be cut by 80 million metric tons, or roughly 28%, across the PJM region by 2030 with a carbon price of $10/ton. Such a price would keep annual costs at $2.8 billion less than the “business-as-usual” approach that includes a “hodgepodge of state and local clean energy policies,” it said.
Status quo policies are more expensive and less effective than a regional approach on carbon pricing, the study found, with existing state carbon policies and subsidies projected to increase electricity costs by more than $3 billion in 2030 and achieving less than half (40 million metric tons) of emissions reductions that could be achieved through a competitive, market-based approach.
Arne Olson, E3 senior partner | EPSA
Arne Olson, E3 senior partner and the lead author of the report, said it found that the most effective carbon policies for PJM will be ones maximizing choices for market participants and that will “leverage resource and geographic diversity” across the RTO.
“Carbon pricing is shown to be the most efficient way to achieve deep levels of carbon reductions,” Olson said.
Olson said the study examined carbon-reduction policy cost impacts through 2050 and was designed to provide baseline information for PJM’s stakeholders and policymakers as they decide the best ways to balance costs, reliability and the environment related to electricity generation.
Installed capacity and annual generation in a PJM system under 80% GHG reduction by 2050 goals | E3
Instead of constraining resource choices, Olson said, emissions can be efficiently and effectively reduced without hampering reliability by: a regional carbon price; encouraging competition and innovation; and allowing all resources and technologies to compete on a level playing field, including natural gas generation. Olson said the constraint of resource choices through state mandates and incentives increased costs in every scenario analyzed.
EPSA CEO Todd Snitchler | EPSA
E3 also found that 50 to 90 MW of “firm, flexible natural gas generation” will be needed in PJM through 2045 to provide reliability. To meet 100% net-zero carbon emission targets, the report said, the development and innovation of “yet-to-be-developed technologies” will be necessary, with carbon pricing providing the best path to provide incentives for innovation instead of state subsidies.
EPSA CEO Todd Snitchler said the report’s findings make clear that competition is key to a “more affordable, reliable and cleaner energy future.”
“We have the tools we need to succeed right in front of us, with PJM’s markets already saving customers money and driving down carbon emissions,” Snitchler said. “This data should inform smart policy decisions in PJM and other markets — and EPSA and our members look forward to aiding that effort as competitive power suppliers continue to provide what customers, markets and the grid demand.”
A “macro grid” that allowed transmission of cheap renewable energy throughout the Eastern Interconnection would produce $7.8 trillion in private investment, create 6 million jobs, cut carbon emissions and save consumers more than $100 billion, according to a study released Wednesday by clean energy advocates.
“Most of America’s world-class renewable resources are currently stranded in remote areas where the power grid is weak to nonexistent,” said the report by Americans for a Clean Energy Grid (ACEG), a coalition that includes the American Wind Energy Association, WIRES, transmission operator ITC Holdings and renewable generator Enel North America. “Policy barriers in how we plan, pay for and permit transmission are blocking private investment in modernizing our power grid.”
The report says its proposed transmission investments could “cost-effectively” cut electric sector CO2 emissions by more than 95% by 2050, with the region getting more than 80% of its electricity from wind and solar.
Change in jobs (2018-2050) in the high solar case (left) and high wind case | Americans for a Clean Energy Grid
It also claims average electric rates would drop by more than one-third, from more than 9 cents/kWh today to about 6 cents/kWh.
“Just as the Eisenhower interstate highway system unleashed U.S. manufacturing in the 20th century, a strong macro grid will deliver massive economic and public health benefits for all Americans in the 21st century,” ACEG Executive Director Rob Gramlich said.
The report does not identify the “policy barriers” nor recommend ways to overcome them. The authors said their focus was to illustrate the complementary roles that wind, solar, storage and transmission play in providing reliable and affordable power.
4 Scenarios
The report includes four scenarios, including a “strong carbon reduction” case in which transmission costs would average 3.6% of total electricity costs. “Transmission yielded savings many times greater than that by providing access to low-cost renewable resources and increasing the overall efficiency of the power system,” it said.
It projects a fivefold increase in electric sector employment, with more than 6 million net new jobs.
“This job creation is driven by as much as $7.8 trillion in generation and transmission investment across the eastern U.S. through the year 2050,” it said. “Several states receive more than $400 billion in additional investment in generation and transmission, driving up tax revenue, indirect job creation outside of the electric sector and broader economic development. The vast majority of this investment will flow to economically depressed rural areas.”
The report includes two “weak carbon policy” scenarios — one with high solar deployment and one with high wind deployment — created by extrapolating the “business as usual” rate of CO2 emissions reductions from 2005 to 2017.
“Strong carbon policy” cases were based on meeting the Paris Agreement requirements.
Transmission expansion (2030) under a strong carbon/high solar deployment (left) and strong carbon/high wind deployment | Americans for a Clean Energy Grid
The weak-carbon, high-solar scenario was estimated to require the addition of less than 80,000 GW-miles of interstate transmission by 2050 while the two strong carbon cases would add about 140,000 GW-miles. (A 500-mile transmission line that carried 2 GW would equal 1,000 GW-miles.)
“Many of the same transmission upgrades were built across all four scenarios, indicating these investments will be needed regardless of future trends in renewable costs or carbon reductions. The model also used battery storage to increase the utilization of transmission lines, demonstrating that storage is a transmission complement, not a substitute,” it said. “Storage, particularly storage that is strategically sited near wind and solar resource areas, can complement transmission investment by increasing the utilization factor of transmission lines.”
The high-solar scenario deploys much of the storage in the East, particularly the Southeast, to shift excess daytime production to the night.
The high-wind scenario would put much of the storage in western states such as Kansas and South Dakota. “Notably, much of that storage shifted out of Indiana and Pennsylvania, where expanded west-east transmission delivering wind generation to the Northeast steps in to replace the need for storage,” the report says.
Speakers at FERC’s technical conference on offshore wind transmission Tuesday repeatedly invoked CAISO’s Tehachapi Wind Resource Area and Texas’ Competitive Renewable Energy Zones (CREZ) as models for developing the infrastructure needed to deliver remote wind to load centers. But they also acknowledged that both of those projects were limited to single-state grid operators, which simplified political and cost allocation issues.
While no one was willing to predict PJM’s 13-state footprint or ISO-NE’s six states would be able to replicate Texas’ and California’s successes, they said there are lessons to be gleaned, nonetheless.
Abe Silverman, general counsel for the New Jersey Board of Public Utilities, cited CREZ and Tehachapi as examples of the “bold vision” he said is needed for New Jersey and other East Coast states to meet their targets of almost 19 GW of OSW by 2035.
Johannes Pfeifenberger, The Brattle Group | FERC
The Brattle Group’s Johannes Pfeifenberger cited CREZ and Tehachapi as a counter example to ISO-NE’s inability to capitalize on Maine’s strong onshore wind.
“Northern Maine has thousands of megawatts of low-cost onshore wind, and none of it is getting developed under the generator interconnection process because the transmission solutions necessary to interconnect that wind is too large for individual generators to pay for,” he said. “The solution to that is regional planning.”
Former FERC Chairman Jon Wellinghoff, now a consultant, said CREZ and Tehachapi are evidence that Brattle’s proposed planned mesh network (PMN) is superior to the generator lead line model. “Both projects had multiple wind developers who agreed and understood that the PMN transmission infrastructure would be built and was the most cost-effective way to get their wind energy to market,” he said. (See related story, FERC Pushed to Change Tx Rules for OSW.)
Tehachapi
Tehachapi Wind Resource Area | Southern California Edison
In a white paper released Monday, the Business Network for Offshore Wind cited Tehachapi as a model for solving the “chicken-and-egg problem associated with the risk of building transmission to serve OSW generation.” (See OSW Group Seeks Changes on Tx Planning, Cost Allocation.)
Located near Los Angeles, Tehachapi is the largest of the six wind resource areas in California, responsible for 3,282 MW of the state’s 5,644 MW of operational wind capacity in 2016, according to the state Energy Commission. Although the project was a trunkline designed mostly to carry wind power, it also serves solar and storage and has multiple interconnections to the CAISO grid, allowing it to address local transmission congestion and reliability concerns.
In 2007, FERC approved CAISO’s proposal to broadly allocate the initial cost of the trunkline to ratepayers, with generators later paying back some of the cost and ratepayers absorbing the risk of under-subscription. FERC required that the project serve remote generation, be designated by the state as serving an important “energy resource area,” meet a minimum threshold of interest from interconnecting generators and be approved by the ISO’s planning process. “An offshore transmission project should be able to meet those criteria,” the Business Network said.
The project, 250 circuit miles, cost about $2.1 billion. Segments 1 to 3A were completed in 2009. Segments 4 to 11 were completed in late 2016, increasing the project’s capacity to 4,500 MW.
Former ERCOT Independent Market Monitor Beth Garza, now a senior fellow on electricity policy for R Street Institute, gave a detailed description of the development of CREZ. She noted that ERCOT has charged all load for all transmission since the wholesale generation market was opened to competition in the mid-1990s.
“One of the foundations that I believe led to the process being a success was a well established and well understood transmission cost allocation mechanism,” she said. “The arguments over the allocation of costs were simply not an issue during the development of the CREZ plan.”
Garza said the Texas Legislature authorized the project when it expanded its renewable portfolio standard because of frequent curtailments for the state’s first wave of wind generation.
The legislation required the delivery of renewable energy from CREZ in a manner “most beneficial and cost effective to customers.” In considering certificates of convenience and necessity for transmission lines, the bill did not require the Public Utility Commission to consider adequacy of the existing grid or the need for additional service. “This was the key aspect allowing a future-looking, enabling transmission plan to be developed,” Garza said.
Texas’ five Competitive Renewable Energy Zones and the transmission delivering wind power to load centers | ERCOT
She also noted that the legislation did not define where the zones were or how much energy should be enabled, leaving that for the commission and stakeholders to decide. The commission ended up with five zones in West Texas and selected a target of 18.5 GW from among four potential scenarios ranging from 12 to 24.4 GW.
In 2009, the commission used a competitive process to select more than a dozen entities, including incumbent utilities and newly created transmission providers, to build the transmission under cost-of-service rates of return.
Generators had to make deposits of $10,000 to $15,000/MW to demonstrate their financial commitment. “During the five-, six-, seven-year process of actually defining the plan … wind generation developers could see, ‘This is happening.’ And more and more wind developers came into the queue,” Garza said. “One of the phrases that we use frequently as a prelude to CREZ [was], ‘If you build it, they will come,’” in reference to the film “Field of Dreams.”
By early 2014, 3,600 circuit miles of transmission had been constructed. “The resulting plan enabled an almost tripling of wind capacity and energy at a time when wind was providing about 3% of [the state’s] total generation requirement,” Garza said. Although the project cost $6.9 billion, it also reduced electricity costs by $1.7 billion annually, according to Brattle.
Garza noted that two of the five CREZ zones are in the Texas Panhandle, which is part of SPP, not ERCOT. “I see that it’s very similar to what my friends and colleagues on the East Coast are trying to do and unlocking this vast resource off the coast,” she said.
Texas now has more than 30 GW of wind, more than all countries except four, according to the American Wind Energy Association. “Certainly, a fair bit of that is because CREZ was put in,” said Theodore Paradise, senior vice president for transmission strategy for Anbaric Development Partners.
Multi-Value Projects
MISO’s Multi-Value Projects | MISO
While Tehachapi and CREZ were built by single-state grid operators, several speakers also noted MISO’s success in winning approval of its Multi-Value Projects.
MVPs allowed MISO to finance $5.2 billion in transmission upgrades in 10 states through its centralized transmission planning process after its interconnection queue was swamped by requests from wind projects. It began with a plan to minimize total transmission and generation costs by accessing lower-cost wind resources.
“One of MISO’s most important innovations was simultaneously accounting for … the value of transmission for meeting economics, reliability and public policy (renewable interconnection to meet state RPS requirements) needs,” the Business Network said. “MISO made sure to spread planned transmission projects across the entire MISO footprint to ensure that all zones received projects and had a strong benefit-to-cost ratio, ensuring their support for the overall portfolio. All Multi-Value Projects planned through this process received broad cost allocation to all MISO ratepayers.”
Differences
FERC Commissioner Richard Glick asked the third panel of the technical conference whether there were aspects of OSW that were clearly not applicable to the CREZ and Tehachapi examples.
Eric Wilkinson, Orsted | FERC
Eric Wilkinson, energy policy analyst for North America at Ørsted, said the risk allocation should be different from onshore because upgrades and outages at sea tend to take much longer than onshore. “Having those things more clearly locked up and defined before a shared system like that gets up and running is going to be critical,” Wilkinson said.
Silverman agreed, saying, “I don’t necessarily think it’s a FERC role, but there is a huge difference in the risk. When you have a misalignment of onshore generation and transmission … when you translate that to the offshore side, we’re talking about such a huge amount of money being invested, and the losses can add up very quickly, so you really need to hammer home on this allocation of commercial risk.”
Theodore Paradise, Anbaric | FERC
Paradise said one of the big lessons learned from CREZ, Tehachapi and Europe’s OSW development is that “the barriers we encounter are much more a case of what sentences are in tariffs, what words are on pages … than physics problems. The second thing is we see that transmission is the great enabler. In Europe, we now see subsidy-free solicitations for offshore wind because the transmission is there and has made it competitive on the actual cost of energy.”
Al McBride, ISO-NE director of transmission services and resource qualification, said New England has two key takeaways from Tehachapi. “One was the technical piece, which is identifying the solution,” he said. “But the more difficult part is cost allocation. … I think what we’re hearing … from the states is certainly interest in what would our Tehachapi be, and which should we build?”
Al McBride, ISO-NE | FERC
In a separate panel, Anne Marie McShea of Ocean Winds North America, cited CREZ to identify the keys to a successful “transmission first” model. But she said the East Coast would need to compress CREZ’s “very long planning horizon.”
“The overall time frame from legislation through to commissioning took nine years,” she said. “A nine-year planning and construction horizon would push an operational offshore wind transmission backbone to 2030. This planning horizon would likely need to be compressed and then carefully managed in order to align with the next round of states’ offshore wind solicitations.”
The BPU’s Silverman also cited CREZ as evidence of the need for cost controls, saying its cost ran to $6.9 billion, well above the original $4.7 billion budget. Part of the increase resulted from the redrawing of power lines to minimize disruptions, which added more than 600 miles of lines to the more direct routes originally envisioned.
“There is clearly a role for competition to reduce costs and prevent transfer of risk onto captive consumers,” Silverman said.
A webinar panel on Monday discussed how different energy storage technologies are coming to market in Connecticut, the various state targets and incentives, and the challenges for developers in working with both state-sponsored projects and the wholesale electricity markets.
“Connecticut is really trying to get into the game when it comes to energy storage,” said Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett, who moderated the discussion for more than 50 members of the Connecticut Power and Energy Society.
“Last session … we saw the chair of our Energy and Technology Committee, Rep. David Arconti, introduce House Bill No. 5351, which would have established an energy storage target for the state by Dec. 31, 2020, of 1,000 MW,” Gillett said. “While that bill did not receive an up or down vote due to the coronavirus suspending all activities in the legislative session, PURA has been moving forward on its energy storage dockets as part of our Equitable Modern Grid proceeding.” (See Conn. Lawmakers Seek to Balance Energy Goals, Costs.)
State Targets
While it’s important to have federal policies, “the name of the game” is states setting targets, promoting incentives and including storage in their planning, Energy Storage Association CEO Kelly Speakes-Backman said.
“Incentives are sending the signals to companies like ENGIE and Key Capture to know that it’s OK to come and open up business in the state,” she said.
Clockwise from top left: Rachel Goldwasser, Key Capture Energy; Sarah Bresolin Silver, ENGIE North America; Kelly Speakes-Backman, Energy Storage Association; and Connecticut PURA Chair Marissa Gillett. | CPES
“What I’d like to see ultimately come out of Order 2222 is a system of aggregated [DERs] that can ride through … short-term outages like we saw in California last month,” Speakes-Backman said. “I want to see this two-way system … [where] buildings can act as a generation source and vehicles can participate in grid systems. Order 2222 starts to get us towards that mix between what’s at the distribution level and what’s at the wholesale level.”
Order 2222 is considered to be a companion order to Order 841, “and we hope it will do for DER aggregations the same thing that 841 did for storage,” said Sarah Bresolin Silver, director of government and regulatory affairs and wholesale markets policy at ENGIE North America.
The order is important because it requires ISOs and RTOs to establish participation models DER aggregations and accommodate all the physical and operational characteristics of those aggregations, she said.
“The goal is to have these assets participate in the wholesale markets without too much burden and perhaps someday without the need for state incentives, [so,] we have to be involved in ISO-NE stakeholder processes to make sure that any changes made welcome these resources into the markets.”
Bridging the Regulatory Gap
Rachel Goldwasser, a lead legal adviser at Key Capture Energy, an Albany-based developer with several projects operating or under construction in New York and Texas, said that ERCOT is much different from ISO-NE.
“There’s no capacity market, and the model the market is built on expects price volatility and expects investment to follow that price volatility,” Goldwasser said. “When you couple that with significant expansion of wind energy, and some level of congestion permitted on the transmission system, you end up building a marketplace that supports the development of storage and certain applications in certain environments and locations.”
In ERCOT, the company doesn’t have to worry about a minimum offer price rule (MOPR) or about clearing the capacity market, she said. It can go wherever the grid needs storage to be deployed.
“ERCOT is fun because it’s just a market, and you can find economic ways of doing storage,” Goldwasser said.
New York is a different story, she continued. From a regulatory perspective, NYISO is a close sibling of ISO-NE.
As of January 2020, battery storage comprised about 11% of the 20,100 MW proposed in the ISO-NE generator interconnection queue. | ISO-NE
She said the grid operators’ capacity markets are “an ongoing concern that we hope will be less of one over time. But we also have established programs in New York to support storage; there’s the market bridge incentive program, and utility procurements … and a program causing retirement of fossil fuel generators there, peaking plants in particular.”
It takes time to bring all stakeholders together, including ratepayers, Speakes-Backman said.
“There is a very methodical step from the regulatory perspective in including storage, and that’s why legislation is so important: It creates a bridge of incentives and targets so that businesses know that there is a path forward to make it worth investing in,” Speakes-Backman said.
“One of the biggest challenges we’ve had, and I think this is true of a lot of renewable energy and storage companies with respect to the MOPR and market monitoring … is around managing the state-facilitated projects and the wholesale markets together,” Goldwasser said.
A second issue is the unique nature of storage.
“How do the withholding rules work? What is economic discharge? How do you think about the deployment of a battery over 24 hours in the energy market with respect to what would traditionally be seen as market monitoring concerns?” Goldwasser said.
The ongoing COVID-19 pandemic is forcing NERC and the regional entities to continue adapting their policies in hopes of helping utilities cope with the outbreak.
NERC announced on Thursday that the ERO Enterprise will once again delay the expiration of the coronavirus-inspired expansion to its self-logging program originally implemented in May. (See NERC Expands Self-logging During Pandemic.) Under NERC’s revised guidance, the policy — which was previously extended through December along with deferrals of on-site activities such as audits and certifications — will now continue through the end of March 2021. (See NERC Extends Self-logging, Deferments Through Dec.)
“In coordination with registered entities, the ERO Enterprise has had success throughout 2020 in coordinating remote virtual audits and other activities that were originally scheduled to be on-site in 2020,” NERC said in a statement. “The ERO Enterprise will return to on-site activities as it becomes safe to do so and in a manner that prioritizes risk.”
REs’ Remote Work Policies Extended
The extension to the self-logging program follows extensions to COVID-19 response measures from several REs. The Midwest Reliability Organization announced this week that it will continue its remote work policy through the end of the first quarter of 2021, and SPPsaid at the beginning of the month that it will delay opening its offices from Oct. 5 to Jan. 4, 2021.
U.S. COVID-19 cases per 100,000 residents reported in the last seven days by state/territory | CDC
No changes have been revealed for NERC’s office policy since the organization announced in August it would keep its offices in Atlanta and D.C. closed and have staff work from home through the end of the year. (See NERC Offices to Stay Closed Through December.) However, Elsa Prince, a principal adviser to NERC, told the Project Management and Oversight Subcommittee (PMOS) at its meeting on Wednesday that an update is expected at the Board of Trustees’ meeting in November.
Prince also confirmed that “there will be no in-person meetings with external stakeholders for the remainder of the year”; NERC had said such events would be considered on a case-by-case basis. Several high-profile events scheduled for this fall have already been called off, such as the Electricity Information Sharing and Analysis Center’s annual security-focused conference GridSecCon, which was scheduled for Oct. 20-23 but canceled in April. (See FERC Extends NERC Compliance Filing Deadline Again.)
The inaugural Electric Power Human Performance Improvement Symposium, a joint effort between the ERO Enterprise and the North American Transmission Forum, has also been delayed again, after a previous deferral from September to March 2021. NERC on Monday announced that organizers would seek “a more accommodating time in the future” for the conference, while “exploring potential methods to deliver content in the interim.”
Budget and Travel Uncertainty Persists
NERC’s reopening plan, with the current remote work posture to remain in place at least through the end of the year | NERC
Some of the discussion at Wednesday’s PMOS meeting turned on the frustration felt by many participants at the way the pandemic’s uncertain time frame has made planning for next year difficult. In response to a question by Chair Charles Yeung about whether members would be able to attend public meetings if and when they resume next year, Masuncha Bussey of Duke Energy pointed out that for many entities, it is still too early to judge when travel policies and budgets can return to normal.
“As with every other company here in Charlotte, [N.C.,] people are [being laid] off,” Bussey said. “My company is having budget issues just like everyone else, so there’s no guarantee they’ll have the money for me to travel.”
Yeung acknowledged the difficulty, but he reminded participants that “there is a commitment … to attend” in-person meetings if NERC decides to return to normal operations. He urged members to “make it known to your finance folks” so the organization can begin to make plans.
Efficient development of offshore wind transmission will require changes to current planning, interconnection and cost allocation procedures, speakers told FERC Tuesday in a daylong technical conference (AD20-18).
RTO officials agreed with wind developers and others that while the first few OSW projects are progressing through interconnection queues, the current process does not allow the coordinated planning needed to maximize the limited number of good interconnection points on shore.
Speakers also said cost allocation rules don’t properly assign costs to parties that will benefit from the additional offshore and onshore transmission that will be required for states to meet their clean energy goals and OSW targets.
Transmission Queue Process
“The current RTO/ISO planning and cost allocation methods generally hinder the integration of offshore wind on a large scale,” said Anne Marie McShea of Ocean Winds North America, a joint venture of EDP Renewables and ENGIE, which has a 50% stake in the Mayflower Wind project off Massachusetts.
McShea, head of offshore wind business development for New York and the MidAtlantic region, said that PJM, NYISO and ISO-NE are overly reliant on the interconnection queue to determine transmission needs, and that they evaluate transmission needed for reliability, market efficiency, resilience and public policy “in an unintegrated manner.”
PJM’s Regional Transmission Expansion Plan (RTEP), she noted, uses a 15-year planning horizon and considers changes to the generation mix based on the interconnection queue. “This analysis does not reflect the true mix of resources that will be relied upon by, say, 2030,” she said, adding that FERC should require RTOs to reflect state OSW procurement targets and solicitation schedules in their transmission plans.
“The interconnection process is a very incremental process that cannot efficiently identify low-cost interconnection points nor identify low-cost transmission solutions that work for this scale,” said The Brattle Group’s Johannes Pfeifenberger. “One project at a time simply won’t get that kind of transmission built.”
Pfeifenberger estimated PJM, ISO-NE and NYISO will have to spend about $10 billion in onshore transmission upgrades to accommodate the 15-20 GWs of renewables that their states already require.
“If you look at the PJM interconnection queue, after the first couple thousand megawatts, you hit $1-2-3 billion in already identified onshore upgrades. … We might find that we have to upgrade all the medium voltage transmission lines along the coast to 500 kV. … I’m afraid that the onshore bottlenecks will create the biggest uncertainty and the biggest risk for cost-effective offshore wind,” he said.
“We cannot afford to develop the offshore transmission grid in piecemeal,” agreed Judy Chang, Massachusetts’ undersecretary of energy, saying the load growth expected from decarbonizing the economy and electrifying buildings and transportation calls for “a paradigm shift” in transmission planning.
“The old principles are not valid anymore. The changes that our electric grid [needs] blur the lines between what is reliability needs versus … congestion relief and public policy needs,” she said.
James Cotter of Shell New Energies, which has investments in the Mayflower and Atlantic Shores offshore projects, said he fears that the current approach to transmission may limit offshore wind installations to 4-5 GW on the East Coast and prevent development on the West Coast.
PJM and ISO-NE officials agreed on the need to make changes to accommodate OSW.
Ken Seiler, PJM | FERC
“To date, PJM’s existing interconnection queue process has provided a useful tool for helping begin to achieve the states’ renewable targets through onshore renewables and provide a path for some offshore projects,” said Ken Seiler, PJM’s vice president of planning. “However, PJM anticipates that as the scale of offshore wind projects increases — and the scope of the transmission upgrades necessary to integrate offshore wind generation grows in complexity and cost — the traditional interconnection queue construct may not be sufficient, and PJM may need to develop alternative mechanisms to accomplish the required transmission buildout.”
He cited limited points of entry from the ocean and limited transfer capability to reach load centers.
Abe Silverman, NJBPU | FERC
Abe Silverman, general counsel for the New Jersey Board of Public Utilities, noted that PJM’s transmission planning has generally assumed West-to-East flows of power. As a result, he said, transmission near New Jersey’s shore is less robust than it is in more inland areas, and the state’s 500-kV generally runs North-South, about 40 miles inland. “The fact is that large portions of the existing grid along the coast are not designed to accommodate injections associated with a large amount of offshore wind, and so we need to find a way to efficiently get the power from shore to the backbone of the PJM system,” he said.
Silverman called for a “bold vision” to rethink OSW planning, citing as examples the Competitive Renewable Energy Zone project in Texas and the Tehachapi transmission line in California. New Jersey hopes to have 7,500 MW of OSW by 2035, with solicitations every 18 months to two years between now and 2028.
Robert Ethier, vice president of system planning for ISO-NE, said the RTO’s planning process is functioning “pretty well” with system impact studies complete for more than 3,900 MW of offshore wind. He said interconnection agreements are ready to be signed with TOs and construction can start on projects.
“As we reach the limits of the current system and have to start building out the onshore infrastructure to accommodate the new offshore infrastructure, almost certainly it’s going to make sense to do big projects that would facilitate lots of interconnection at one time,” Ethier said.
He also noted that the region will need to align its short-term transmission needs with its longer-term goals. “I think it’s important that these two processes become one process or at the very least talk to one another.”
Zachary Smith, vice president of system and resource planning for NYISO, cited the “flexibility” in the ISO’s planning process. “Once solutions come forward, we have many ways to look at them, not just in a single silo of reliability, economic and public policy,” he said. “That approach has served us quite well in New York.”
Don’t Move the Goal Posts
Gabe Tabak, counsel for the American Wind Energy Association (AWEA), called for flexible planning and interconnection policies so they can react to the rapidly evolving “policy drivers, economic imperatives and technological innovations.”
Policy should balance the needs of projects in various stages of development, he said. “The commission should ensure that changes in transmission planning or interconnection rules allow projects that are currently well underway to proceed without shifting the goal posts. This principle also means that any longer-term planned offshore transmission system — which most members agree would be needed to attain the 29 GW of Eastern state goals — should have adequate lead time, to ensure that later projects are not subject to excessive upgrade costs.”
Tabak called on FERC to conduct “a holistic examination of renewable energy integration strategies,” citing the interplay between offshore and onshore integration policies.
“Many of the topics discussed today — including the role of state policies, the potential role of a ‘transmission first’ model, the benefits of transmission, modeling of inverter-based generation and transmission approaches from other jurisdictions — are not confined to the offshore context. The rapid growth and potential of offshore wind provides an opportunity for fresh evaluation of transmission planning, cost allocation and interconnection rules in other contexts.”
‘Transmission First’ Model, Merchant Transmission
McShea also called for continuity, saying projects already underway using radial interconnection should not be delayed by the adoption of other models. But she said the “transmission first” model — in which large-scale transmission facilities are built for anticipated generation to achieve economies of scale — will be needed for future projects.
The commission said its current regulations do not include a transmission first approach “except perhaps the merchant transmission framework.”
A transmission first model also would require changes to cost allocation rules, McShea said, noting that PJM’s “state agreement” approach assigns all transmission costs to the sponsoring state even when the transmission may also benefit its neighbors. She called for cost allocation based on a broader set of criteria including contributions of the project to system reliability, operational performance, economics and resiliency in addition to “public policy” goals.
Jon Wellinghoff, Grid Policy | FERC
Former FERC Chair Jon Wellinghoff, now a consultant, said merchant transmission development is not well suited for OSW because developers will have difficulty raising financing without guarantees that generators will support their project. He cited the failure of the Atlantic Wind Connection, a proposed HVDC offshore transmission backbone from the Carolinas to New York and New England.
“Calculations provided to me as chairman of FERC at the time by the project developers indicated that the project was ‘profitable’ simply with energy interchanges between the Southeast and New York and New England,” Wellinghoff said. “Although initial development costs were backed by Google and Japanese investors, the project was unable to secure funding to proceed with building actual transmission infrastructure.”
Seiler also discussed challenges to the merchant model, noting that a radial merchant line that extends the PJM grid without connecting to another RTO or an identified generation project is not eligible to receive interconnection rights under PJM’s Tariff. (See FERC Rules Against Anbaric in OSW Tx Order.)
He said the RTO and its stakeholders have discussed alternative approaches but have not reached consensus. He said the issue was the generation not being connected at the time of the request for the merchant transmission line. “The concerns at that time were really the locking up of the transmission capability for the offshore wind, when there may be competing needs with onshore generation at the time, and stakeholders could not come to any agreement in that space.”
Silverman also expressed doubts about current rules, saying New Jersey’s phased procurements make it impossible to “‘broadly solicit interest in the project from potential customers or conduct a meaningful open season” as required by FERC’s 2013 policy statement on merchant and participant-funded transmission. He said FERC should consider a “hybrid merchant” investment model that includes merchant features such as absorbing cost overruns and building facilities on a fixed-fee basis.
Lead Line vs. Network
Generator lead line vs. planned mesh network for New England | The Brattle Group
Wellinghoff endorsed The Brattle Group’s proposed planned mesh network (PMN), saying it is “clearly superior in every single respect to the” radial generator lead line (RGL) model.
The PMN would be an HVDC backbone network that gathers power for multiple wind projects. Brattle proposed one each for ISO-NE and the NYISO. Although Brattle did not do a study for PJM, “a unified single network could be created along the entire Eastern Seaboard from ISO-NE through PJM,” Wellinghoff said.
Generator lead line vs. planned mesh network for New York | The Brattle Group
He also called on FERC to issue a policy statement declaring PMN as the “preferred” OSW transmission infrastructure and convening a joint process involving ISO-NE, NYISO and PJM to develop a transmission infrastructure needs assessment and procurement process resulting in solicitations approved by the grid operators’ boards.
Wellinghoff told RTO Insider he disagrees with a recommendation by the Business Network for Offshore Wind that the Department of Energy provide technical research and support for stakeholder engagement. (See OSW Group Seeks Changes on Tx Planning, Cost Allocation.) “FERC is the agency to do this job,” he said.
Larry Gasteiger, former FERC chief of staff and now executive director of the WIRES trade group, agreed with the need for “a holistic planning process” to ensure cost-effective transmission development and said some of his members are eager to pursue OSW transmission projects. “But we also have members who … are in the middle of the country and have real concerns about being allocated costs for projects from which they’re not seeing benefits,” he said.
Pacific Gas and Electric told the federal judge overseeing its felony probation that a distribution line under investigation for starting the deadly Zogg Fire on Sept. 27 remained active even as other circuits in the same region were de-energized during a large-scale public-safety power shutoff.
In a court filing Monday, PG&E responded to an inquiry by U.S. District Court Judge William Alsup about the utility’s possible role in starting the Zogg Fire in Shasta and Tehama counties. The fire killed four people, including a mother and her 8-year-old daughter, destroyed 204 structures and burned more than 56,000 acres before being brought under control.
The California Department of Forestry and Fire Protection (Cal Fire) seized a portion of PG&E’s Girvan 1101 12-kV circuit, near the rural community of Igo, where the fire began, PG&E told the California Public Utilities Commission (CPUC) in an Oct. 9 incident report. (See PG&E Under Scrutiny in Deadly Zogg Fire.)
A PG&E power line is under scrutiny for starting the Zogg fire on Sept. 27. | Jeff Head via Flickr
Alsup asked PG&E to explain why the Girvan Circuit hadn’t been de-energized, and who made that decision, during the Sept. 27-29 public-safety power shutoffs (PSPS) that blacked out more than 64,000 customers in 15 counties in Northern California.
“The Girvan Circuit was energized because PG&E’s PSPS models, developed well before the Zogg Fire, did not identify that circuit for potential de-energization based on the facts and weather predictions available for the September 27, 2020, PSPS event,” the utility told Alsup.
“Circuits not identified for inclusion in the scope of a potential PSPS event remain energized and are not subject to any decision during the event to leave the circuit energized,” PG&E said. “Accordingly, there was no ‘decision to leave [the line] energized.’”
The utility said it experienced a series of drops in voltage on the Girvan Circuit on the afternoon the Zogg Fire started. But the problems weren’t enough to cause a line “recloser to open or ‘trip,’ resulting in de-energization of the line it protects,” prior to the fire’s start.
The line de-energized only after a wildfire camera and satellites photographed smoke, apparently from the fire, the utility said.
PG&E told Alsup it did not yet know if its equipment started the fire.
“PG&E recognizes the devastation caused by the Zogg Fire, which resulted in the loss of four lives and destroyed many homes,” it said. “Like the court, PG&E is actively seeking to understand the cause of the fire and the role, if any, of PG&E’s facilities.”
Alsup has been an outspoken PG&E critic during his years overseeing the utility’s probation on felony convictions related to the San Bruno gas pipeline explosion in September 2010.
PG&E noted in its filing that during the five days Alsup gave it to respond to his Oct. 21 order, it had been engaged in a massive PSPS event due to the driest and windiest conditions of the year and that “relevant PG&E personnel who may have otherwise provided input” were unavailable.
PG&E shut off power to 361,000 customers, or more than 1 million residents, in portions of 36 counties on Sunday and Monday as powerful Diablo winds swept through the Sierra Nevada foothills and the coastal mountains north of San Francisco, where PG&E equipment started major fires in 2017, 2018 and 2019.
During this week’s wind events, numerous small fires started in Northern California but were largely under control as of Tuesday, Cal Fire reported. Santa Ana winds rapidly spread two major fires in Southern California, the Silverado and Blue Ridge, the causes of which remain under investigation.
Rhode Island Gov. Gina Raimondo (D) announced Tuesday a new competitive solicitation to procure up to 600 MW of offshore wind energy.
Raimondo in January signed an executive order committing Rhode Island to meet 100% of its electricity demand with renewables by 2030. The order directed the state Office of Energy Resources to conduct economic and energy market analysis and develop policies and programs such as the OSW RFP.
Raimondo also recently joined with the governors of Connecticut, Maine, Massachusetts and Vermont to issue a joint statement calling for reforms to New England Governors Call for RTO Reform.)
“In the face of global climate change, Rhode Island must drive toward a cleaner, more affordable and reliable clean energy future,” Raimondo said in a statement. “It is critical that we accelerate our adoption of carbon-free resources to power our homes and businesses while creating clean energy jobs. In January I set a nation-leading goal for Rhode Island to meet 100% of its electricity demand with renewables by 2030. Offshore wind will help us achieve that bold but achievable goal while creating jobs and cementing our status as a major hub in the nation’s burgeoning offshore wind industry.”
Rhode Island is home to North America’s first operational OSW farm off Block Island, and the 400-MW Revolution Wind offshore project received state approval in 2019.
The RFP will be developed by National Grid with oversight by the state Office of Energy Resources and is ultimately subject to approval by the Public Utilities Commission.
“Our state, communities and local economies are facing unprecedented challenges as we confront the COVID-19 pandemic, but now more than ever, it’s imperative that we lean into our shared commitments to enable and progress the clean energy transition,” said Terry Sobolewski, president of National Grid Rhode Island. “Expanding large-scale renewables across Rhode Island is crucial to delivering clean, reliable, affordable energy for our customers and future generations.”
A draft RFP will be filed with state regulators this fall. If approved, a final RFP will be issued early next year. Any contracts for OSW projects resulting from the competitive process additionally require separate regulatory approvals.
Goal ‘Within Reach’
“Offshore wind is a vitally-important renewable resource that will help power our decarbonized future — both here in Rhode Island and throughout New England,” said state Energy Commissioner Nicholas Ucci. “Importantly, offshore wind can also help our electric system meet winter peak demand with stability-priced clean electricity, helping temper power price spikes faced by local homes and businesses.”
State OSW targets | States of Massachusetts and Rhode Island
Ucci said the RFP, “coupled with other locally developed, carbon-free resources and a continued commitment to robust, cost-effective energy efficiency,” puts the state’s 100% renewable goal “within reach.”
“I am committed to ensuring that Rhode Island leverages the benefits of market competition to secure cost-competitive renewables and reduce long-term energy costs while fostering clean energy jobs and mitigating greenhouse gas emissions across our economy,” Ucci said.
Rhode Island had 933 MW of renewable energy in its portfolio as of the second quarter of 2020, representing a ninefold increase since 2016. The state target from OSW energy is 1,030 MW, with 430 MW currently selected and the potential addition of 600 MW, which would meet the target.
Added Rhode Island Secretary of Commerce Stefan Pryor: “Among U.S. jurisdictions, Rhode Island is the pioneering state in the offshore wind field. Given its first-in-the-water status, Rhode Island has positioned itself as a premier destination for offshore wind companies, suppliers and related enterprises. Under Governor Raimondo, we are pleased to be pursuing a second significant expansion of our turbine constellation, and we look forward to partnering with the industry and key stakeholders to ensure the success of this expansion.”
Northeast Clean Energy Council President Peter Rothstein said the next 10 years “must be a decade of action” to reduce greenhouse gas emissions by procuring more renewable resources.
“With this announcement, Governor Raimondo recognizes that investments in offshore wind not only move us closer to 100 percent renewable electricity, but also put Rhode Island in a pole position to reap the economic benefits that this industry will deliver,” he said.
MISO board members on Monday gave an initial nod to MISO’s $4 billion 2020 Transmission Expansion Plan (MTEP 20).
In a special Oct. 26 conference call, the four-member System Planning Committee of MISO’s Board of Directors voted unanimously to send MTEP 20 to a full board vote in early December.
Director Mark Johnson said the committee’s voting took place about a month earlier than usual this year to allow more time for the full board of directors to deliberate about the plan.
MTEP 20’s 515 projects include 75 baseline reliability projects, accounting for 18% of the plan’s cost, but they still come in $70 million below MTEP 19’s crop of baseline projects. It also includes 100 generator interconnection projects, representing 15% of costs.
MISO said it’s normal to have boom-and-bust investment years in terms of baseline reliability projects. This year most baseline projects are located within the Central planning region, which account for $372 million.
Executive Director of System Planning Aubrey Johnson said while MTEP 20’s spending tracks closely with the 2019 package, spending on generator interconnection projects increased from $269 million last year to $606 million this year.
MTEP 20 stats | MISO
“We’ve seen an almost three times increase of interconnection projects from this year to last, and we attribute that to clearing out some of the [interconnection queue] backlog,” he said.
MISO’s Planning Advisory Committee approved MTEP 20 in September; however, some members asked that MISO be more specific about the breakdown of projects in its “other” category. (See “Members Endorse MTEP 20,” MISO Planning Advisory Comm. Briefs: Sept. 23, 2020.)
The “other” category includes load growth-based projects, age and condition-based upgrades, and economic, environmental and reliability-driven projects. It usually represents the lion’s share of MTEP spending and this year accounts for $2.8 billion. MISO said 40% of “other” projects are needed for reliability, 36% for age and condition, 21% for load growth and 2% for other local transmission owner needs. RTO executives said some load pockets are experiencing load growth, even if it’s not occurring footprint-wide.
“The old proverbial ‘other’ bucket, I really encourage MISO to refine that. … It’s just a little too nondescript, and I know I’m not the first director to raise this issue with MISO management,” Mark Johnson said.
“More definition would be helpful,” agreed Director Todd Raba.
MISO executives also briefed the board of directors on the removal of Entergy Louisiana’s nearly $74 million, 27-mile, 230-kV, Waterford-to-Churchill transmission line approved as part of MTEP 16. MISO said the line no longer demonstrates the benefits it once did. Over four years the benefit-cost ratio dropped from 2.3 to about 0.2, according to Entergy. (See “Entergy Cancels MTEP 16 Project,” MISO in Final Stretch of $4B MTEP 20.)
MISO’s agreement to rescind the project ruffled some feathers within the stakeholder community this fall.
MISO Director Nancy Lange asked whether stakeholders disagreed with the decision to withdraw the project or the opaque manner in which the decision was made.
Aubrey Johnson said some stakeholders weren’t comfortable with MISO conducting a withdrawal analysis in the background without notifying them of the study’s process or progress. He said some argued that MISO didn’t provide them time to perform their own no-harm analyses to find out if the project’s removal would negatively impact other subsequently approved MTEP projects.
“For this project, I do not believe the benefits are there. Whether we need other transmission in the area is an ongoing question,” Vice President of System Planning Jennifer Curran said.
“I think the question is, if you’re going to have projects withdraw like this, how do you present that to the stakeholders earlier in the process, if you will,” Aubrey Johnson said. He added that MISO will re-examine its process of monitoring and recommending withdrawal of MTEP approved projects.
New Jersey is moving closer to adopting wide-ranging programs promoting the deployment of electric vehicles and energy storage throughout the state.
The New Jersey Board of Public Utilities held two days of hearings last week to hear comments on Public Service Electric and Gas’ petition to implement the EV and energy storage portion of its Clean Energy Future program. Commenters at the hearing were generally in support of the petition.
The BPU approved the company’s plan last month to commit $1 billion toward energy efficiency investments over the next three years.
Joseph Accardo, vice president of regulatory affairs for PSE&G parent Public Service Enterprise Group, provided an overview of the EV and storage portion, saying the initiatives will bring the benefits of cleaner air, more renewable resources and a more reliable electrical grid through electrification of transportation and “targeted, cutting-edge energy solutions.”
“PSE&G’s electric vehicle filing supports the development of electric vehicle infrastructure and energy storage solutions in New Jersey to benefit customers, meet state goals and spur the state’s green economy,” Accardo said.
PSE&G originally filed its petition with the BPU in October 2018. The objective of the program is to accelerate EV adoption and deployment of storage technology in New Jersey, supporting the goals set forth in the state’s energy master plan, Accardo said. (See NJ Unveils Plan for 100% Clean Energy by 2050.)
The plan calls for the installation of nearly 40,000 EV charging stations across the state. As charging stations have grown in other states at a pace of purchase of vehicles, Accardo said, New Jersey ranks 45th in the country for stations per registered EV. He said PSE&G’s plan emphasizes that the state needs to provide consumers with easy access to charging infrastructure.
For the EV portion of the program, PSE&G is seeking BPU approval to commit up to $261 million in direct investments over a period of six years. It includes a $93 million residential subprogram that will pay for the cost of a home EV charger and installation for EV users, with a cap of $2,000 per installation.
The proposal includes a $39 million mixed-use charging subprogram and a $62 million DC fast-charging subprogram. It also features a $45 million vehicle innovation subprogram to promote EV use, including a $33 million electric school bus project and $12 million to fund other vehicle electrification projects.
Approving the program would initially increase electric rates to customers by about $9.7 million over an 18-month period, PSE&G said, with rate recovery continuing until 2064. A peak revenue requirement would occur in the 2024-2025 time frame.
Storage Component
New Jersey’s Clean Energy Act calls for 600 MW of energy storage by 2021 and 2,000 MW by 2030.
For the storage portion of its program, PSE&G is seeking approval to commit up to $109.4 million in direct investment over a period of six years. It includes subprograms to smooth intermittent solar generation ($13.1 million), resolve forecasted distribution grid overload conditions ($38.6 million), deploy mobile battery storage devices ($20 million), develop microgrids for critical facilities ($25.7 million) and facilitate peak reduction for public sector facilities ($11.9 million).
Approval of the program would increase rates by about $700,000 over an 18-month period. Rate recovery for the program would continue until 2045, with a peak revenue requirement in the 2025-2026 time frame.
Stakeholder Responses
A typical PSE&G residential electric customer would see a $1.24 (0.09%) increase in their annual bill, the company said.
Testimony at the BPU hearing featured several hours of stakeholder comments from across the state, with all parties expressing support for PSE&G’s proposal.
James Sherman, vice president of Climate Change Mitigation Technologies (CCMT), a New Jersey-based developer of medium- and heavy-duty battery electric truck projects, provided testimony on the EV program. Sherman said the possibility exists to make New Jersey “the East Coast center” of the zero-emission, medium-duty truck and bus industry.
Sherman said his company is closely following developments in California’s EV program, especially within the California Energy Commission. (See California Looks to EVs for Grid Resilience.) He said the PSE&G subprogram is consistent with what is happening in California and will accelerate charging infrastructure to deploy more EVs.
The school bus fund and the vehicle innovation portion are also key, Sherman said, providing money for towns and cities to convert to EV fleets. CCMT is working on building an EV bus and truck manufacturing plant in Patterson, he said, with operations to begin in 2021 if sufficient orders and state-level funding are in place. The plant would add 45 new jobs at full production, with 500 trucks and buses being manufactured per year.
Sherman said all the EV programs fit like a puzzle, creating a new clean energy economy in the state.
“When put together, we get advanced, zero-emission vehicle technologies, job creation and, hopefully, increased grid reliability,” Sherman said. “We get school buses made in New Jersey and driven in New Jersey. We get immediate clean air benefits at the community level.”
Shihab Kuran, CEO of Power Edison, a New Jersey-based clean energy solutions company focused on energy storage, said he is in “full support” of PSE&G’s filing, though he called the storage subprogram a “very, very small step” toward increased reliability. He said he would like to see it approved quickly to move on to other programs with “meaningful megawatts” in helping New Jersey meet its goals.
“We are far behind other states in the U.S. when it comes to energy storage,” Kuran said. “We have set up our own targets. … But frankly, I don’t see a path for how we can get to 600 MW by 2021. We should have started the work two to three years ago.”
Trenton Mayor Reed Gusciora also spoke in support of the programs. He said his city is made up of dense areas experiencing the pressures of urban environments, including pollution.
Gusciora said the concept of environmental justice is important to the residents of Trenton, leading to “fairness, opportunity and a better quality of life.” Steps have been taken by companies and communities to be more environmentally friendly, he said, but only a small portion can be done on a local level to solve current environmental issues.
The mayor said proposals like PSE&G’s are a step in the right direction, spurring statewide interest in EVs that will lead to better air quality.
“PSE&G’s proposal to deploy nearly 40,000 EV charging stations across the state is the kind of initiative that can deliver public health and environmental and economic benefits to all residents across New Jersey,” Gusciora said.
