Vineyard Wind announced Wednesday that it reached a transmission agreement with ISO-NE to deliver power to the RTO’s grid from Vineyard Wind 1, the first large-scale offshore wind project in the U.S.
A joint venture of Avangrid Renewables and Denmark’s Copenhagen Infrastructure Partners, Vineyard is building the 800-MW wind farm 15 miles off the coast of Martha’s Vineyard, Mass.
Vineyard said the agreement would provide “clean, renewable and cost-effective energy” for more than 400,000 homes and businesses across Massachusetts and reduce carbon emissions by more than 1.6 million tons per year.
“We’re very pleased to reach this agreement, another important milestone in a project that will bring an entirely new industry to the U.S.,” Vineyard Wind Deputy CEO Sy Oytan said in a statement. “There is tremendous potential for job creation, not just during construction but also for operations and maintenance. These are good-paying jobs that will be around for decades to come.”
In September, FERC approved the company’s execution of the interconnection agreement with the RTO, effective July 10. The agreement allows Vineyard Wind 1 to interconnect at the 115-kV Barnstable switch station on Cape Cod. Vineyard was selected to enter into power purchase agreements with electric distribution companies as part of the Massachusetts Green Communities Act offshore wind solicitation.
At FERC’s technical conference on OSW transmission Tuesday, Al McBride, director of transmission services and resource qualification, said there is room for the region’s power system to accommodate the initial wave of projects, but connecting further projects would be more expensive as this “low-hanging fruit” is used on the transmission system.
| Vineyard Wind
ISO-NE spokesperson Matt Kakley said Wednesday that McBride’s observation reflected the 2019 Economic Studies for the New England States Committee on Electricity and Anbaric Development Partners. It estimated that injecting 7,000 MW of OSW capacity at optimal locations could avoid significant reinforcements to the 345-kV transmission system. Injections above 7,000 MW would require additional power plant retirements or support to the onshore transmission system, the report concluded.
“We’re looking forward to discussing with the New England states and market participants how to best shape the development of the regional grid to accommodate regional policy goals, under the authority provided by the ISO’s tariff and under any needed enhancements to the ISO’s planning scope.” Kakley said.
Speakers at the technical conference said the efficient development of offshore transmission will require changes to current planning, interconnection and cost allocation procedures. (See related story, FERC Pushed to Change Tx Rules for OSW.)
A white paper released Monday by the Business Network for Offshore Wind stated that RTO processes fail to capture all the benefits from offshore transmission, particularly an interregional network that could improve ISO-NE resilience. (See OSW Group Seeks Changes on Tx Planning, Cost Allocation.)
Southern California Edison told the state Public Utilities Commission on Tuesday that one of its power lines might have started the Silverado Fire, an explosive blaze that critically injured two firefighters and caused tens of thousands of residents to flee their homes this week.
“It appears that a lashing wire that was attached to an underbuilt telecommunication line may have contact[ed] SCE’s overhead primary conductor, which may have resulted in the ignition of the fire,” SCE told the CPUC in an incident report. On a transmission tower or pole, an “underbuilt” line is one strung under electric power lines in a space reserved for telecommunication infrastructure.
“Preliminary information reflects SCE overhead electrical facilities are located in the origin area of the Silverado Fire,” the utility said. “We have no indication of any circuit activity prior to the report time of the fire, nor downed overhead primary conductors in the origin area.”
The 13,350-acre fire, which ignited and spread quickly during powerful Santa Ana winds on Monday, was 25% contained as of Wednesday afternoon, according to the California Department of Forestry and Fire Protection. It threatened thousands of structures northeast of the densely populated city of Irvine in Orange County.
A jet drops fire retardant on the Silverado Fire near Irvine, Calif. | Orange County Fire Authority
Another blaze, the 14,334-acre Blue Ridge Fire, also started in the hills of Orange County on Monday. Firefighters brought it under control Wednesday as winds subsided and many residents in both fire areas were allowed to return to their homes.
2nd Incident
SCE’s report to the CPUC marks the second time this fire season that the state’s second largest utility has fallen under suspicion for starting a major wildfire.
In September, SCE filed a report with the CPUC saying the Bobcat Fire, burning in the mountains near Los Angeles, started in the same area and around the same time as the utility experienced a line fault. However, SCE said a fire camera had recorded smoke from the blaze shortly before its relay tripped, suggesting the fire preceded the line problem.
“The Bobcat Fire was reported in the vicinity of Cogswell Reservoir/Dam in the Angeles National Forest on Sunday, Sept. 6, 2020, at 12:21 p.m.,” SCE told the CPUC. “The Jarvis 12-kV circuit out of Dalton Substation experienced a relay operation at 12:16 p.m. on Sept. 6, 2020. The Mount Wilson East camera captured the initial stages of the fire, with the first observed smoke as early as approximately 12:10 p.m., prior to the relay operation.”
Both fires remain under investigation. The investigation of the Bobcat Fire is being conducted by the U.S. Forest Service, which on Sept. 15 “requested that SCE remove a specific section of SCE overhead conductor in the vicinity of Cogswell Dam,” the utility reported. (See Calif. IOUs Escape Blame for Fires So Far.)
SCE and Pacific Gas and Electric have been trying to avoid starting wildfires this season after three years of cataclysmic blazes in 2017-2019 that hammered the companies’ finances.
PG&E, which entered bankruptcy in January 2019 because of an estimated $30 billion in wildfire liabilities, has turned off power to hundreds of thousands of residents on multiple occasions this summer and fall in public safety power shutoffs (PSPS) meant to prevent utility equipment from sparking fires.
Nevertheless, a PG&E distribution line fell under scrutiny in the Zogg Fire, which killed four residents in a rural area near Redding, Calif. (See related story, PG&E Line Was Active when Zogg Fire Started.)
After emerging from bankruptcy in June, PG&E’s stock price, which exceeded $70/share before its equipment started the wine country fires of October 2017, has generally hovered around $9 to $10/share. It stood at $9.70/share at close of trading Wednesday.
SCE has been more conservative in its power shutoffs, partly because it lacks the PG&E’s vast territory in fire-prone areas and has had longer experience using PSPS.
As news spread of SCE’s possible involvement in the Silverado Fire spread, the already lagging stock price of its parent company Edison International fell further on Wednesday, from a high of $58.64/share at 10 a.m. ET to $56.56/share at the close of trading.
MISO should have adequate capacity to navigate winter but could still face abnormal weather-related generation outages or a load-shedding event, RTO officials said Wednesday.
The RTO expects to have 146 GW of available capacity to manage an expected 104-GW winter peak, 5 GW less than its all-time winter peak on Jan. 6, 2014.
Executive Director of Real-Time Operations Rob Benbow said anticipated electricity usage paired with the “outages we have planned” show adequate reserves.
But as usual, a combination of high demand and unexpectedly high generation outages could put MISO operations in jeopardy.
“I think we all know that unforeseen events and outages can change our position, and we will work with members to mitigate issues and ensure the reliable and efficient operation of the grid,” Benbow said during a winter readiness teleconference.
“I believe it’s important to spend time on winter readiness just as much as we talk about summer readiness,” he added.
Using a high-load, low-generation forecast, MISO said it could exhaust all 10.5 GW of its load-modifying resources (LMRs) on a January peak day and be forced to order load-shedding from members. Using the more likely forecast provided by its market participants, a high-demand, peak day in January containing a more typical number of outages could still force MISO to declare an emergency to access some of its LMR stack. If winter conditions are harsh enough, the grid operator said it could tie its 109-GW all-time winter peak.
NOAA and MISO winter predictions | NOAA and MISO
Resource Adequacy Coordination Engineer Eric Rodriguez said December and January bring the highest risk of a maximum generation event.
“MISO is planning minimal risk in February, which appears to be a preferential time to schedule generation outages,” Rodriguez said.
Last winter, MISO’s generation outages trended lower than its five-year average, averaging about 22 GW.
The National Oceanic and Atmospheric Administration is forecasting above-average temperatures this winter in MISO South and lower-than-normal temperatures for Minnesota, Wisconsin and the Dakotas (Zone 1). The agency also predicts more precipitation than usual in MISO Midwest and a drier winter for South.
“The past 10 winters have been within 10% of NOAA’s predictions,” Rodriguez said.
Director of Balancing and Interchange Operations Tag Short said MISO has undertaken dramatically more winter preparation since the polar vortexes and subsequent maximum generation events of 2014 and 2019 and the two-day MISO South emergency in January 2018. Since the Midwestern arctic blast in 2019, the RTO has been including the cold-weather cutoff thresholds of wind generators.
“We do have a pretty good ledger now of extreme temperatures,” Operational Forecast Planner Adam Simkowski said, adding that MISO now factors public building and college closures into its load forecasting. He said polar vortexes tend to produce more subdued, weekend and holiday-style forecasts.
MISO’s Geoff Brigham also said generators this winter can turn to the RTO’s multiday operating margin forecast, launched last November, to help make commitment decisions. The forecast shows a week-ahead expected supply picture.
The RTO is also exploring publishing multiday outage and derate information, Brigham said.
Generation and Balancing Authority Operator Michael Carrion said MISO’s approximately 200 natural gas generators representing 70 GW have ample access to basins, pipelines and storage by virtue of the RTO’s broad territory.
| MISO
Carrion reported that the Midwest’s natural gas storage levels are above the five-year historical range and “nearing the five-year maximum storage threshold due to strong production, reduced load and relatively mild temperatures.”
MISO also doesn’t expect any unusual transmission limitations this winter.
Principal Adviser of Standards and Assurance Bobbi Welch said NERC has landed on a scope for the cold weather preparation rules, which will rely on existing plant winterization standards and communications on generation capability.
The standard might be nothing more than business-as-usual, especially for generator owners and operators in the northern portions of MISO’s footprint, Welch said.
“They’re hoping that this will make it more palatable,” she said. “It’s going to take a look as a system on how we get ready for winter weather.”
In a 2019 report on the MISO South emergency, FERC and NERC concluded that generation owners failed to properly winterize their equipment, contributing to the supply crunch.
Welch said the standards should be ready for use in late 2021, “about a one-year horizon.”
A Rising Winter Risk
The cold weather standards are being developed as MISO devotes more time to assessing an emerging wintertime loss-of-load risk.
The RTO has recently said it could define unique seasonal system reliability requirements, hold seasonal capacity auctions and use risk assessments beyond its summer-emphasized loss-of-load study. (See MISO Lays Out Seasonal Capacity Options.) The options would have MISO moving away from summer peak modeling and forecasting in favor of determining multiple loss-of-load risk hours throughout the year, called resource adequacy hours.
MISO’s current loss-of-load modeling tends to underestimate wintertime risk, a trend that will be exaggerated as the footprint adds more solar generation, MISO analysis shows.
During a special teleconference Monday, MISO Director of Research and Development Jessica Harrison said stakeholders are interested a monthly or seasonal division of capacity auctions.
“We want to land on a model that mitigates risk under a variety of resource portfolios,” Harrison said, adding that any resource adequacy design must also be practical for MISO to implement.
Senior Manager of Resource Adequacy Coordination Lynn Hecker said it would be easy enough for MISO to incorporate new sub-annual modeling inputs.
Using an expected unserved energy calculation — where MISO calculates the expected amount of energy when load is set to exceed generation — the RTO found risk in January, February, May and December, in addition to the prevailing risk in June, July, August and September identified under summer peak loss-of-load modeling.
Using a five-year-out generation portfolio based on queue projections, MISO found risk in every month except April, November and December, with the most pronounced risk occurring in February and September.
Hecker said results using the revised inputs generally track with emergency events MISO has experienced under its current portfolio. Most of its roughly dozen emergency declarations since 2016 have occurred outside of summer months.
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.
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.
