New wind resource data for the Great Lakes is showing higher wind speeds than originally thought at potential spots for offshore wind development.
“This is a good result,” Walt Musial, manager of offshore wind at the U.S. Department of Energy’s National Renewable Energy Laboratory, said Tuesday.
Wind speeds in locations where wind projects might go on the New York side of Lake Erie and Lake Ontario average between 8.5 and 9 meters/second, Musial said during a public webinar on New York’s Great Lakes wind power feasibility study.
“We now have a 21-year record using ensemble-based analysis and an advanced weather research forecasting model that comes from the National Center for Atmospheric Research,” he said.
The new dataset replaces NREL’s Wind Integration National Dataset Toolkit for the Great Lakes, which used a seven-year record.
Higher wind speeds were found in new data for the Great Lakes, showing average speeds between 8.5-9 meters per second. | National Renewable Energy Labora
NREL’s analysis also found that the wind resource has “very little variability,” Musial said.
The New York State Energy Research and Development Authority (NYSERDA) is reviewing work that has already been completed for the feasibility study to produce a draft version before the end of the year, Sherryll Huber, project manager for offshore wind contracts, said during the webinar.
Last year, the New York Public Service Commission directed NYSERDA to identify the viability of Great Lakes wind energy as a resource. (See NY Kicks Off ‘Dynamic’ Great Lakes Wind Study.) NYSERDA expects to submit the final study to the commission early next year.
“Based on the findings of the study, the commission … will conclude if Great Lakes wind is a feasible addition to the state’s renewable energy portfolio, likely in 2022,” Huber said.
Ports
Lake conditions of Erie and Ontario will drive the turbine, vessel and port requirements for project development.
On Erie, Musial said, the water is shallower than in Ontario and will require fixed-bottom substructures that need heavy-lift vessels for wind turbine construction on the lake. Turbine size for Erie projects will be limited by the crane capacity of the vessels that can be on the lake.
Ontario, on the other hand, has deeper water and will “probably” require floating wind turbines, he said. Wind turbine assembly for floating turbines would take place in a port facility, and turbine size would be limited by the crane capacity at the port.
NREL reviewed four port possibilities for Ontario (Ogdensburg, Clayton, Oswego and Rochester) and three for Erie (Buffalo, Dunkirk and Erie).
With some upgrades, Oswego, Buffalo and Erie could accommodate OSW activities, Musial said.
Still to Come
NREL is still working on an economic analysis for the feasibility study.
Musial said the analysis will assume a project size of 600 MW, comprising 100 6-MW wind turbines, with locations yet to be determined. Costs for port upgrades and land-based connections will not be part of the project economics, and financing will be similar to projects already in development in the Atlantic.
NREL will customize its models for the specific conditions of each lake and run cost and sensitivity studies for a geospatial analysis and time-dependent parameters past 2030, according to Musial. The modeling, he said, will assume floating turbines for Ontario and fixed turbines for Erie.
In addition, NREL will conduct a jobs and economic development analysis. The results, Musial said, will calculate the actual jobs created by projects on the lake and the local revenues along with induced impacts of the workforce in local communities. An additional analysis will identify existing workforce availability and programs in the region that can train workers.
Extreme low temperatures remain a major threat to the Texas power grid in the upcoming winter months, according to NERC’s 2021-2022 Winter Reliability Assessment, while other regions face risks including natural gas supply disruptions and hydropower shortfalls.
February’s winter storms and the mass outages they caused across ERCOT, MISO and SPP are a natural focus in the report. John Moura, NERC’s director of reliability assessment and performance analysis, said the storms inspired an “innovative approach to our assessment [that] fundamentally changes the questions we’re answering as we perform our analysis.”
In a media call accompanying the release of the report on Thursday, Moura said that while all regions showed sufficient anticipated reserve margins — NERC’s traditional proxy for reliability — for the season, the events of February left the organization concerned that this metric was no longer adequate for a system increasingly comprising alternative types of generation like wind and solar power. Last year’s winter assessment showed adequate reserve margins but did not account for the failure of utilities in the south-central U.S. to prepare for unexpected extreme low temperatures. (See NERC Warns of Fuel Bottlenecks in Coming Cold Months.)
“Over the years, as the resource mix has changed, that measuring stick is not so useful anymore, because now we find that there’s not on-site fuel; that we can’t dispatch at will; that we have variable resources; that cold weather forces certain resources to come offline,” Moura said. He explained that for this assessment, NERC wanted to see how the grid might fare in the worst-case scenario, even if it is unlikely to happen.
“I think what we’ve done this year is say, ‘OK, instead of just looking at the things that happen most often, and [the] most likely thing to happen, let’s look at the tails, and let’s look at the worst things … that can happen and measure the resilience to them,’” he continued.
Severe Cold Dangers Persist in ERCOT
With February’s storms still fresh on everyone’s minds, NERC’s report identified severe cold weather as the most pressing concern in ERCOT, SPP and MISO.
For ERCOT, NERC warned that “resource derates for extreme conditions” similar to those seen in February could reach 28.1 GW, leading to a capacity deficit of up to 37.1%. This is despite the report finding that “operating plans for winter are in place,” based on responses to NERC’s Level 2 alert in August. (See NERC Issues Cold Weather Alert.) For MISO, conditions like those in February could cause a deficit of 1.2%, while SPP could see its reserve margin drop to 0.8%.
Seasonal risk scenarios for MISO, SPP, and Texas RE-ERCOT | NERC
NERC said that generator owners and grid operators’ “responses to questions about winterization plans and fuel coordination indicate that some plant vulnerabilities can be anticipated” this winter.
In an email to ERO Insider, Texas Public Utility Commission spokesperson Michael Hoke noted that the first phase of the PUC’s new weatherization rule, set to take effect Dec. 1, “requires generators to implement the recommendations that came out of the 2011 winter outages and to address the specific equipment failures” from February’s storm. (See Texas Senators Call for New RRC Weatherization Rules.)
He added that many of the recommendations in FERC and NERC’s joint report on this year’s storm “mirror the steps we have already taken to make sure the grid is more resilient this winter.” (See FERC, NERC Release Final Texas Storm Report.)
Additional steps taken by the PUC include designating natural gas facilities that supply power plants as critical infrastructure in order to avoid the gas supply shortfalls that caused many outages in February. Participants in Thursday’s media call acknowledged these efforts and said the goal of the report was to draw attention to areas where additional work can benefit more consumers.
“Our message is, the operator needs to be prepared to implement the plans, but relentless preparation is in order,” said Mark Olson, NERC’s manager of reliability assessments. “And if we follow that plan, the outages rates can be improved, and the situation [may] not be as catastrophic as was experienced earlier this year.”
Gas, Coal Shortfalls Possible
Hazards faced by other regions include limited natural gas infrastructure (WECC-California/Mexico and NPCC-New England) and limited water for hydropower because of the Western drought (WECC outside of Alberta and the Southwest Reserve Sharing Group). The potential gas shortfalls in NPCC-New England are because the fuel is used for both heating and electric generation, creating the possibility of bottlenecks in the region, while those in WECC-CAMX are because of limited storage capability.
Assessed unavailable capacity caused by insufficient weatherization plans | NERC
Global supply chain problems have also led to challenges in obtaining fuels; NERC noted that coal stocks in particular “have trended quickly downward in the last few months … after a buildup since last winter” and are at their lowest point in more than 10 years. While Olson said this level is “not an immediate concern for BPS reliability,” he said owners of fossil fuel-fired plants should monitor the situation closely because “late-state acquisitions this winter could be particularly challenging.”
NERC recommended several steps to reduce the risk of outages this winter:
Grid operators, generator owners and generator operators (GOPs) should review NERC’s cold weather Level 2 alert and take recommended steps before winter arrives.
Grid operators should prepare operating plans to manage potential supply shortfalls and take proactive steps for generator readiness, fuel availability and sustained operations in extreme conditions.
Balancing authorities and reliability coordinators should conduct drills on alert protocols, while BAs and GOPs should verify protocols and operator training for communication and dispatch.
Distribution providers and load-serving entities should review non-firm customer inventories and rolling blackout procedures to ensure that critical infrastructure loads such as gas and telecommunications are not affected.
Ever since a pair of run-of-the-mill conservation alerts in April and June spooked Texans still reeling from February’s winter storm, ERCOT and the Public Utility Commission have dialed back their communications efforts.
ERCOT has used social media twice since June, tweeting out the only two press releases the grid operator had issued in the interim. The most recent seasonal resource adequacy assessment (SARA), usually issued in a release and followed by a conference call with state and industry media, was quietly distributed in a market notice. (See ERCOT: Sufficient Capacity to Meet Fall Demand.)
A similar effort with the highly anticipated winter SARA, the first since the February storm, fell flat when the report was posted on the ERCOT website early Friday afternoon, only to disappear shortly thereafter. But it was taken down too late. Social media users had already taken notice, with one twitterer downloading the assessment and offering it to others.
The SARA was eventually posted before the close of business Friday.
ERCOT’s communications staff said that “to the best of [their] knowledge,” they didn’t post the initial report that was subsequently pulled down and were working to figure out what happened.
“There wasn’t any conspiracy or planned effort to post and pull down,” said Chris Schein, ERCOT’s interim communications director.
Matters were compounded later Friday when word began to spread on Twitter that Elaine Mendoza, one of ERCOT’s newest board members, had abruptly resigned. The PUC responded to media requests but did not issue a press release in what some saw as a pre-Thanksgiving news dump.
Texas Monthly’s Russell Gold broke the news of Mendoza’s resignation while he was stranded at Houston’s William P. Hobby Airport.
“It’s a bad look for ERCOT [and] Texas politicians who promised us reform [and] transparency [and] competency,” Gold said, expressing frustration with the radio silence.
Doug Lewin, a consultant with Stoic Energy and close observer of the ERCOT market, agreed.
“I’m deeply frustrated and concerned about the assessment of winter resource adequacy,” he told RTO Insider. “Everyone agreed communication and planning needed improvement, but [Friday] demonstrated little has changed; it might be worse.”
It’s not that communications has taken a back seat at ERCOT since the winter storm. A dozen of interim CEO Brad Jones’ 60-point “Roadmap to Improving Grid Reliability” items deal directly with communications and others tangentially touch on it. No. 33 deals with educating the public and news media about energy emergencies and operational notices and reviewing existing practices around conservation alerts to “minimize false alarms and public fatigue.”
Jones is also in the middle of a listening tour across the state, visiting city councils and holding town halls. The tour continues in December with seven more stops, including Dallas, San Antonio and the Rio Grande Valley, where ERCOT has placed an emphasis on adding transmission infrastructure.
Since Jones’ arrival, ERCOT has reduced the number of media interviews and cut back on the number of press releases and their social media activity. Officials have said they are focused on “making the necessary changes to protect Texans against the next winter storm.”
ERCOT Sees 62 GW of Peak Demand
ERCOT said assuming “typical winter grid conditions,” it anticipates having 85 GW of installed generating capacity to meet a forecasted winter peak demand of 62 GW. The latter is about 10 GW less than the grid operator’s peak demand before it began to lose generation resources during the winter storm.
The grid operator said it included additional low-probability, high-impact scenarios in the winter SARA as part of its “aggressive grid-management planning.” The assessment assumes nearly 9 GW of thermal outages based on historical data from the past three winters but excludes unplanned outages from last February because of the storm’s “exceptional impact.”
The extreme risk scenarios were expanded to include a new “extreme low” renewables output assumption and estimated renewable and thermal and outage improvements, ERCOT said, citing the PUC’s new weatherization standard and the natural gas industry’s “voluntary weatherization activities.” (See “Weatherization Rules in Effect,” Texas PUC Nears Market Redesign’s Finish Line.)
Twitter users were quick to poke holes in ERCOT’s assessment. Andrew Dressler, an atmospheric sciences professor at Texas A&M University and a climate scientist, has concluded that hourly peak demand was actually 82 GW at one point during the storm.
“[ERCOT staff] never show how they arrive at that number, and they have an incentive to low-ball the estimate,” tweeted Dressler, who was the first to notice the initial posting of the assessment.
“No rules, no enforcement, no fines from the [gas regulatory Texas Railroad Commission], just ‘voluntary efforts’ from an industry that made $11 [billion] in one week, but sure, they probably winterized [and] voluntarily gave up those profits this winter, right?” Lewin said in another Twitter thread.
While ERCOT did not publicize the SARA report, it did issue a market notice to its participants.
A&M a Market Participant?
Mendoza’s departure leaves ERCOT four directors short of a full board before its annual meeting of members on Dec. 10. She was only named to the board on Nov. 1. (See Three More Directors Added to ERCOT Board.)
PUC spokesman Michael Hoke confirmed Mendoza’s resignation from the board on Friday. He said a “re-examination” of her role as a regent of Texas A&M University found a potential conflict with her ability to serve on the ERCOT board.
Texas A&M has a 50-MW generation facility that primarily serves the campus but also has the ability to offer into the ERCOT market as a resource entity. That makes Texas A&M a market participant, Hoke said, and new legislation prohibits market participants from serving on the board.
“This was done out of an abundance of caution,” Hoke said in a statement to RTO Insider.
Schein said ERCOT is not involved in board selection or communications around the appointment. That responsibility lies with the Board Selection Committee, a three-person group selected by Texas’ political leadership and that coordinates appointment announcements through the PUC.
Mendoza is founder and CEO of Conceptual MindWorks, a medical informatics company in San Antonio, where she has been involved in expanding educational opportunities, health care and economic growth.
Senate Bill 2 replaced the five unaffiliated directors and eight market segment representatives with eight independent directors chosen by the selection committee. The ERCOT CEO, the PUC chair and the Texas Office of Public Utility Counsel’s CEO sit on the body as non-voting members.
The law requires each board member to be a Texas resident with executive-level experience in finance, business, engineering, trading, risk management, law or electric market design. When the winter storm nearly brought the ERCOT system to total collapse, Texans frustrated with the ensuing long-term outages directed their ire toward the six board members who lived outside the state. (See ERCOT Chair, 4 Directors to Resign.)
Concerns over FERC’s legal authority to mitigate greenhouse gas emissions came up throughout the commission’s technical conference on GHG mitigation Friday (PL21-3).
The first panel featured Commissioner James Danly disagreeing with FERC Chair Richard Glick on the commission’s statutory responsibilities under the Natural Gas Act and the National Environmental Policy Act.
FERC Chairman Richard Glick | FERC
“From my perspective, the law is very clear; the court decisions are very clear,” Glick said in summing up the day. “The D.C. Circuit [Court of Appeals] has told us that we can in fact mitigate greenhouse gas emissions; that we should in fact examine the impact of these emissions on climate change when we pursue our proceedings in terms of determining whether a pipeline is in the public interest.” (See DC Circuit Slaps FERC on Pipeline GHG Analysis.)
Danly said the NEPA analysis required is not as broad as Glick asserts it is, and any mechanism to enforce mitigation regimes would represent non-traditional employments of the commission’s powers.
“I really do believe that these legal questions are fundamental and should be determined in the first instance; they’re dispositive,” Danly said.
FERC Commissioner Allison Clements | FERC
Willie Philips, newly confirmed by the Senate as the third Democratic member on the five-member commission, would give Glick’s position the majority if the issue continues to divide along party lines.
FERC Commissioner Allison Clements said the issue will be litigated “no matter what happens,” and that an important component on which the commission now has a full record is procedural: how to determine need, the order of events that take place and providing a legally durable framework.
“I would just say that the biggest issue here is certainty: certainty for stakeholders and for project developers, and I think we’ve created a lot of uncertainty over the last several years,” Glick said. “My goal is a proceeding in which we’re hopefully going to have a revised policy statement in terms of how we pursue certification of natural gas plants [and pipelines], and I’m hoping that we can get to that much sooner than later.”
FERC Commissioner James Danly | FERC
The debate even drew a tweet from former Commissioner Bernard McNamee on the “interesting discussion on whether FERC has the legal authority to deny a pipeline certificate based on upstream or downstream emissions,” with a link to his 2019 concurrence as to why it does not.
The only state regulator to speak at the conference, New York Public Service Commissioner Diane Burman, said that the legal jurisdictional issues are a challenge, but that the threshold issue is something that needs to be addressed because legal uncertainty is going to be a problem.
“It’s best to collaborate and be reasonable, work with the industry, and you could sit with your other federal agencies or browse state partners,” Burman said.
Compliance and Cost Recovery
Currently, FERC’s post-certificate environmental monitoring begins at project construction and ends once commission staff deem additional restoration inspections are not necessary. One panel discussed the cost impacts to the industry from implementing GHG mitigation and how project sponsors should recover those costs.
Stephen Mayfield, City of Tallahassee | FERC
Cost impact to consumers is consideration No. 1 in evaluating any mitigation regime, said Stephen Mayfield, director of gas operations for the city of Tallahassee, Fla., speaking on behalf of the American Public Gas Association.
Given the higher energy burden borne by low-income households, “we in Tallahassee have shown our commitment to emissions reduction by joining EPA methane challenge programs and incorporating emissions-reduction best practices into our operations,” Mayfield said.
To the extent that mitigation measures are undertaken in a market-based context, whether those costs would be recoverable really depends on whether the investments are prudent, said Carl Pechman, director of the National Regulatory Research Institute at the National Association of Regulatory Utility Commissioners.
Carl Pechman, National Regulatory Research Institute | FERC
“So the answer really depends upon the regulatory structure under which investments and operation of the gas facilities are being undertaken,” Pechman said.
If project sponsors propose to recover the cost of mitigation measures, FERC should consider factors such as timing, technology, fugitive emissions, transparency of data and project sponsors as beneficiaries of perpetuated carbon industries, said Rachel Dawn Davis, public policy and justice organizer at environmental advocacy group Waterspirit.
After Davis expressed skepticism about the capacity of carbon capture and sequestration to help reduce GHG emissions, Paula VanLaningham, global head of carbon at S&P Global Platts, said it’s premature and counterproductive to claim that it is never going to be a solution to the emissions problem.
Paula VanLaningham, S&P Global Platts | FERC
“This is an area that is actively being improved and developed quite regularly now, and there are a number of different ways to do that both naturally, but then also in improved technology,” VanLaningham said.
People may be against renewable natural gas, hydrogen or carbon capture, but climate change requires an “all-hands-on-deck approach,” and the effort should be focusing as much on innovation and technology as anything, Burman said.
“It’s becoming more and more common to see operators employ gas-capturing techniques so that little or no gas needs to be purged to the atmosphere during maintenance activities,” Burman said. “The pumped-down technologies allow upwards of 90% of the gas to be captured and reinjected into the pipelines rather than admitted into the atmosphere during pipeline operations and maintenance activities.”
Mitigation Types
Finding ways to mitigate GHG emissions in proposed projects will take both technological advances and market-based approaches. Several panelists discussed current mitigation measures employed by project sponsors at facilities or by end users and future technologies.
Caitlin Tessin, director of market innovation for Enbridge (NYSE:ENB), said the company is constantly looking for ways to mitigate GHG emissions in their pipeline operations to reach their targets of a 35% reduction in their GHG footprint by 2035 and net-zero emissions from operations by 2050. Tessin said Enbridge is taking steps to reduce leaks and minimize the volume of natural gas vented during construction and maintenance by using tools like pneumatic value operators, dry seals and electric starters.
NYPSC Commissioner Diane X. Burman | FERC
Enbridge utilizes a blow-down collection system process, which is designed to pull down and recompress gas that would have been vented. Some of their electric compressors used in new compression capability are powered by solar resources, Tessin said, and Enbridge currently has the only two operating behind-the-meter solar projects powering electric compressors in North America.
“There’s no one-size-fits-all solution and physical mitigation techniques,” Tessin said. “In deciding what forms of mitigation may be appropriate at a particular site, we must carefully consider a range of factors, including operational limitations to ensure reliability, commercial considerations, customer preferences, regulatory requirements, landowner interest and more.”
Anna Scott, chief science officer of Project Canary, a Denver-based energy data company, said the company has been developing continuous emissions measurement and quantification. The company believes independent measurement is needed because of discrepancies reported between “estimations from emissions factors” and the measurements that are taken.
Project Canary’s market-based solution includes the installation of continuous and real-time monitoring units that can quantify emissions and alert operators to when emissions exceed normal levels, allowing them to identify and remediate emissions immediately. Data collection allows the operators to identify the largest sources of emissions, Scott said.
“We think this is the type of technology that is not only employable today, technologically feasible and affordable, but it can even be helpful for the American energy industry,” Scott said.
Bill Donahue, manager of natural gas resources for Puget Sound Energy, said the company’s pipeline replacement programs have been instrumental in mitigation efforts, identifying the most leak-prone aspects of the system and completely replacing out-of-date cast-iron and bare steel pipes. Donahue said the company is also studying value technology to reduce methane emissions and to consider in the viability of a hydrogen blend scenario in pipelines.
Donahue said the utility is also considering market-based mitigation efforts, including platforms to certify, record and account for credits in a “broad category of carbon reduction.” He gave an example of the Midwest Renewable Energy Tracking System (M-RETS), a system that records, documents and validates efforts made to reduce emissions.
“In the event that a market has exceeded their requirements, those products can be sold to another party that does not have access to renewable gas or other technologies,” Donahue said. “So there are products out there.”
New York regulators on Thursday approved a three-year rate plan for Central Hudson Gas and Electric, effective retroactively to July 1, 2021, praising the joint proposal made by the utility, consumer advocates and Department of Public Service staff as a model for other utilities to follow (Cases No. 20-E-0428; 20-G-0429; 20-M-0134).
The approved joint proposal balances varied interests while also ensuring the utility’s continued provision of safe and reliable service, furthering the goals of New York’s nation-leading Climate Leadership and Community Protection Act (CLCPA), and mitigating impacts to ratepayers, especially those suffering the financial effects of the COVID-19 pandemic, said Administrative Law Judge Michael Clarke.
Under the new rate plan, Central Hudson will identify ways to reduce its carbon emissions, targeting cumulative savings of 2019 gas and electric sales in the next four years by 2.5% and 6.9%, respectively, and will decommission by yearend 2025 its gas-powered 20 MW Coxsackie and 23 MW South Cairo power plants.
Central Hudson will expand access and increase bill discounts for low-income customers, including a $4.5 million customer bill moderation credit. It will pause residential service terminations as well as service metrics for uncollectible bills through 2022, and continue its Back to Business economic development program providing financial assistance to small businesses.
The New York Public Service Commission held its regular monthly session in hybrid fashion November 18, 2021, meeting both in person and via videoconference. | NYDPS
Clarke quoted one of the parties to the joint proposal, the Alliance for a Green Economy, as saying the plan “contains numerous provisions that represent meaningful compromise among normally adversarial parties and which specifically concede to the public interest positions taken by not-for-profit public interest organizations who represent constituencies within the company’s service territory.”
The Public Utility Law Project said the agreement’s mitigation of rate increases, low-income provisions, COVID-19 considerations and consumer protections, as well as efforts to promote the goals of the CLCPA are in the public interest.
“Of great interest to me is the adjustments towards declining block rates, which are viewed by some as a de facto incentive for greater gas use,” Public Service Commission Chair Rory Christian said. “By flattening those rates, you remove that incentive and better align customer use of natural gas with the overall goals of the CLCPA.”
The New York DPS defines a block rate as a commodity rate structure where blocks of consumption are sold at different rates to recognize differences in cost of service. Most commonly the block rates decline as consumption increases.
As part of the rate plan’s climate-related initiatives, Central Hudson will conduct a geothermal district loop feasibility study to identify potential project sites. The study will be funded by electric customers and capped at $250,000. If the study identifies a suitable project site, Central Hudson will discuss development with the commission to ensure it is consistent with state policies and ongoing community thermal system work at the New York State Energy Research and Development Authority.
Rate Design
The new rate plan allows a 9% return on equity and will decrease electric base delivery revenues by $3.1 million the first year but increase them in the following two years by $19.5 million and $20.7 million, respectively. Gas base delivery revenues would increase in each of the three rate years, going up by $4.7 million the first year, then by $6.3 million and $6.4 million, respectively, in the succeeding two years.
The PSC’s order said an earnings sharing mechanism “is triggered if the company’s actual ROE exceeds 9.5% in any rate year (after certain adjustments). Earnings above 9.5% to 10% would be shared equally between Central Hudson and ratepayers; ratepayers would receive 75% of any earnings greater than 10% up to 10.5%; and ratepayers would receive 90% of any earnings over 10.5%.”
Central Hudson customers may not understand how electric rates regulated to go down a bit by the order may actually rise substantially with the increase in commodity prices being experienced now, Commissioner John B. Howard said: “Let people know that the commodity portion that will be affecting their bill is not what we’re voting on here today. We’re voting on a delivery rate that is separate and apart.”
This settlement discussion should be a model that other companies follow, Commissioner Tracey A. Edwards said. She also thanked the utility “for recognizing that we are in a diverse state” and creating a Spanish-language website and offering translation of other languages.
Regulating ESCOs
The PSC also announced steps related to eight energy service companies, or ESCOs, operating in New York, denying permits to four companies, prohibiting another from further marketing or enrolling new customers, and allowing one company to serve low-income customers after demonstrating its ability to provide guaranteed savings (Cases No. 12-M-0476; 21-M-0491; 21-E-0490).
The commission in December 2019 placed ESCOs under new restrictions and requirements that they must honor in order to sell to the state’s residential customers and small business owners. (See NYPSC Reins in ESCOs, Expands Community DG.)
“Our ongoing efforts to improve the ESCO market remains a priority,” Christian said. “When an ESCO proves they are fair to customers, we allow them to continue their activities in New York to bring choice and energy services to customers.”
The commission denied SunSea Energy, Starion Energy NY, Smart One Energy and Josco Energy’s applications for eligibility to serve mass-market customers after staff found that each of the four firms knowingly made false and misleading statements in its application to do business.
The PSC ordered that Got Gas? and Graystone Technologies each show cause within 30 days why their eligibility to act as an ESCO in New York should not be revoked for allegedly violating the commission’s uniform business practices rules. Neither company has customers in New York.
The commission also approved NOCO Electric and NOCO Natural Gas’ request to serve low-income customers.
California’s three large investor-owned utilities are on track to meet the state’s goal of serving retail customers with 60% renewable energy by 2030, but some smaller utilities and community choice aggregators (CCAs) are lagging, a report issued Friday by the California Public Utilities Commission concluded.
The CPUC’s annual report on the state’s renewable portfolio standard assessed the progress made by electricity retailers — IOUs, CCAs, small and multijurisdictional utilities (SMJUs) and electric service providers (ESPs) — on procuring 33% of energy from renewable sources by 2020 and 60% by 2030, as well as interim periodic goals.
The CPUC and the California Energy Commission oversee the state’s RPS program, the most ambitious in the nation. CPUC-jurisdictional load-serving entities serve approximately 75% of in-state load.
Senate Bill SB 100, signed by former Gov. Jerry Brown in 2018, established the 60%-by-2030 mandate, as well as the requirement that all retail customers be supplied with 100% carbon-free energy by 2045.
“As of 2021, the investor-owned utilities have executed renewable electricity contracts necessary to meet 2021 RPS requirement and are forecasted to have excess renewable procurement through 2027,” the CPUC said in a statement. “The small and multijurisdictional utilities, electric service providers and community choice aggregators collectively need to procure additional renewable resources to meet the 2021-2024 compliance period requirements, as well as future requirements.”
Combined progress of utilities toward meeting the state’s 60%-by-2030 renewables goal. | CPUC
The IOUs — Pacific Gas and Electric (NYSE:PCG), Southern California Edison (NYSE:EIX) and San Diego Gas & Electric (NYSE:SRE) — are expected to “continue to surpass RPS requirements as they are forecasted to have excess procurement for the next seven years,” the report said. “The IOUs may choose to apply excess renewable electricity procured in prior and future years to meet their RPS requirements in future compliance periods. Alternatively, they may sell the energy and renewable energy credits” to other retail providers.
Millions of customers departing the IOUs to join CCAs and adopting rooftop solar have bolstered the big utilities’ RPS statistical performance, the CPUC said.
“A variety of market factors have contributed to the IOUs being procured beyond their minimum RPS requirements,” the commission said. “These market factors include the initial need to hedge against early program experience with project failure; the continued trend of load departing from IOUs; and the increase in behind-the-meter solar generation.”
That leaves the CCAs and others needing to ramp up their efforts.
“All of the SMJUs must procure additional resources to meet their 40% RPS requirement for the 2021-2024 compliance period … [and] 19 CCAs and six ESPs were notified by the CPUC that their RPS compliance reports show a risk of not meeting RPS requirements in the current or next compliance period based on a compliance risk analysis of their procurement quantities and/or progress toward the long-term contracting requirement,” the report said.
The three SMJUs are Bear Valley Electric Service, which provides electricity service to the Big Bear Valley in the San Bernardino Mountains of Southern California; Liberty Utilities, serving counties in the Lake Tahoe Basin; and PacifiCorp, a multistate utility that serves four rural counties in far Northern California.
CCAs are local government entities certified by the CPUC to buy and provide electricity for their communities instead of getting it from the IOUs. The growing number of CCAs “play an increasingly significant role in meeting the state’s renewable energy and CPUC-jurisdictional greenhouse gas reduction goals,” the commission noted.
Those falling behind “must procure more RPS resources and sign additional long-term contracts in the near term to meet the RPS requirements,” the CPUC said in its statement.
FERC on Thursday approved a consent agreement between its Office of Enforcement and Golden Spread Electric Cooperative over charges of market manipulation that will cost the utility almost $1 million (IN21-9).
Enforcement alleged Golden Spread offered its gas-fired Mustang Station generating unit in West Texas into SPP’s market so that it “improperly targeted” and increased the unit’s day-ahead make-whole payments.
Golden Spread neither admitted nor denied the alleged violations but agreed to pay $375,000 in disgorgement funds (profits from the alleged behavior and interest) and a $550,000 civil penalty. FERC also directed the cooperative to strengthen its compliance training program and will subject it to compliance monitoring.
The commission stressed that Golden Spread’s market transactions were based on “fraudulent intent” and not on market fundamentals, which are prohibited by its anti-manipulation rule.
“Make-whole payments are not intended to provide an incentive to resource owners to design offers that seek to target and inflate such payments,” FERC said.
The commission said Enforcement staff found evidence of an offering strategy at the 521-MW Mustang Station related to make-whole payments for six months in 2016. Golden Spread received $314,151 in make-whole payments from the SPP market during that time by “strategically” offering the facility in self-commit status during certain hours of the operating day, staff said.
SPP told FERC that make-whole payments are designed to keep resource owners indifferent to the RTO’s commitment decisions by incentivizing them to offer their units in market status so that staff can make and optimize unit commitment decisions for the entire market, as opposed to resource owners self-committing their units.
FERC said the SPP market and its participants bore the cost of Golden Spread’s violation and directed the RTO to use its “best efforts” to allocate the disgorgement funds on a pro rata basis to affected market participants.
Commissioner James Danly dissented from the decision, saying the proceeding represented “another instance of the commission penalizing a market participant for doing nothing more than attempting to maximize its revenues in conformity with the provisions of the tariff under which it operates.”
“Golden Spread … responded to the incentives established by [SPP’s] open access transmission tariff in the very manner in which SPP intended and, in so doing, provided the exact benefit to the market that SPP stated the tariff was designed to achieve,” Danly wrote in his eight-page dissent. “Because Golden Spread acted within both the spirit and the letter of the tariff, it could not have committed market manipulation.”
During the commission’s open meeting Thursday, Danly said the settlement was “totally unjustifiable, and it represented a departure from our precedent in which a jurisdictional entity can comply with both the spirit and the letter of the tariff and still find themselves in the position where they have to buy their way out of enforcement scrutiny with a settlement.”
FERC noted that Golden Spread cooperated with Enforcement during the investigation.
Golden Spread did not respond to a request for comment. The Amarillo, Texas-based cooperative’s members serves more than 300,000 customers in Texas, Oklahoma, Kansas and Colorado.
What was expected to be a short discussion at Wednesday’s PJM Members Committee meeting regarding the West Virginia Public Service Commission’s request to attend Liaison Committee meetings turned into a two-hour debate.
In a sector-weighted vote of 3.39 (67.8%), stakeholders indefinitely postponed a vote on allowing the PSC to observe LC meetings, surpassing the 3.33 threshold. An amendment by Public Service Enterprise Group to not produce a voting report was also added to the motion.
The LC is a closed-door forum, billed as an opportunity “for direct communication between the members and the PJM Board” of Managers. RTO staff, the Independent Market Monitor, government officials and members of the media are not allowed to observe.
The original motion, advanced by Procter & Gamble and seconded by the Organization of PJM States Inc. (OPSI) on behalf of the PSC, asked, “Do members object to the request of the Public Service Commission of West Virginia (as an ex officio non-voting member of the standing committees) to attend the Liaison Committee as an observer?”
Jackie Roberts — the PSC’s federal policy adviser and former West Virginia consumer advocate — said some members have “strong opinions” about who can attend the LC.
“This is not about how we feel about it or what we want or don’t want,” Roberts said. “This is about the language in our governing documents.”
2018 Vote
From 2011 to 2018, PJM had allowed certain non-members — such as state regulators and their staff, FERC staff, PJM management and staff, and the Monitor — to attend the LC, though this was technically unallowed. The MC voted in September 2018 to enforce the committee’s charter and keep the meetings private. (See “Liaison Committee Meeting to be Closed to Nonmembers,” PJM MRC/MC Briefs: Sept. 27, 2018.)
From 2011 to 2018, OPSI and all the state commissions were allowed to participate in the Liaison Committee, but the 2018 vote enforced the charter and limited attendance after some members requested enforcement.
In support of the PSC motion and attendance at the LC, Roberts cited Section 1.4.4 of Manual 34 that states:
OPSI and its member regulatory agencies are not members of PJM. Under a June 2005 memorandum of understanding between the OPSI and PJM boards, commissioners and their staff participate, deliberate, give input and engage at all levels of PJM stakeholder groups but do not vote on any issue.
But Roberts argued that under PJM’s governing documents, as one of the only ex officio members in the RTO — along with the Consumer Advocates of the PJM States (CAPS), which is allowed to attend as a voting member — the West Virginia PSC is “entitled” to act as a member on the LC.
“Clearly the Liaison Committee is a stakeholder group,” Roberts said. “If we don’t have a culture of compliance at PJM, then we don’t have a stakeholder process.”
Susan Bruce, counsel to the PJM Industrial Customer Coalition, sponsored the motion on behalf of Procter & Gamble; Greg Poulos, executive director of CAPS, seconded it on behalf of the Delaware Division of the Public Advocate.
Bruce said that because conversations impacting states have taken place at recent LC meetings, it’s “important” for the PSC to be in attendance. Bruce cited “incredibly informative” discussions on the capacity market, auction revenue rights and financial transmission rights.
“We think there’s value if states have the ability to be participating,” Bruce said. “We have no objection to their listening to the conversation to inform their advocacy.”
Jeff Whitehead of Eastern Generation asked why the motion was necessary if the governing document language was “clear cut” to allow the PSC to attend the LC, as Roberts argued. He said he was uncomfortable with voting on “interpretations” of the governing documents.
Roberts said the PSC informed PJM that it would be attending the LC, but the RTO responded that it was “concerned” over the 2018 vote and “how passionate the members can be” about attendance at the meetings.
PJM General Counsel Chris O’Hara said there is “clearly a difference” between the ex officio role of a non-voting member like the PSC and the ex officio role of a voting consumer advocate member.
O’Hara said it’s also “not clear” that the LC is a standing committee. He said the committee was created out of a “conversation” between members and the board and not intended to be a committee reporting to the MC.
The 2018 vote at the MC was the clearest indication of member opinions on who could attend the LC, O’Hara said.
Tabled
<img src=”//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783434.jpeg” data-first-key=”caption” data-second-key=”credit” data-caption=”Ed Tatum, American Municipal Power
Ed Tatum, vice president of transmission at American Municipal Power, appealed the decision of committee Chair Erik Heinle to put the motion up for a vote. Tatum said from a “parliamentarian standpoint,” the language of the motion was “a bit confusing” because it was written in the negative and is typically not considered at stakeholder meetings.
Tatum said he was “happy” to have a discussion if the PSC should be a part of the LC, but the vote on the motion seemed “inappropriate.”
“I’m a little bit confused as to what we’re doing here and why,” Tatum said.
Jason Barker of Exelon said the OA language doesn’t identify the LC as a standing committee, so the ex officio status regarding attendance of the LC is “meaningless.” Barker said the motion “intended to provide new rights” that are not included in the OA language.
In a sector-weighted vote of 3.28 (65.6%), the motion to reverse the decision of the chair was endorsed with 59 votes in favor, passing the 2.5 threshold.
Bruce offered to amend the language of the motion from “Do members object to” to “Do members support.”
Tatum said it was “still suffering from another defect” in that there are differing opinions whether the governing documents allow for ex officio attendance. He suggested the PSC come back with “explicit, specific changes” to either the OA or manual language.
“It’s important to me how this committee does business,” Tatum said. “The stakeholder process is important, and we all need to behave to a certain standard.”
Barker made a motion to indefinitely postpone the amended motion, with Calpine’s David “Scarp” Scarpignato, seconding it. Alex Stern, director of RTO strategy for PSEG Services, requested an amendment to suspend the rules to not produce a voting report generated on the issue, which was accepted.
Roberts said she “doesn’t have any idea” why members not impacted by the West Virginia PSC would have a stake in suspending the rules to not generate a voting report.
She said she was “really appalled” the rules would be suspended on the voting report, especially at a time when FERC is reaching out to states wanting help in solving resource adequacy and transmission issues.
MISO last week said it probably won’t meet a March deadline to gain approval of its long-range transmission plan’s first projects, saying the Board of Directors’ action will likely be pushed to May or June.
Aubrey Johnson, MISO’s executive director of system planning, said the filing needs to undergo more study and legal review before it’s ready for FERC.
The RTO has said it will create two separate but equal cost-allocation designs instituting a 100% postage stamp rate to load for its Midwest and South subregions. The grid operator has also committed to conducting three-year reviews examining whether new Midwestern transmission benefits MISO South.
“We’ve said at the beginning that this is a very iterative process,” Johnson told stakeholders during a special workshop Friday.
Stakeholders asked whether the new approval target would push the projects into the 2022 MISO Transmission Expansion Plan (MTEP 22).
Johnson said the projects will still be considered an addendum to MTEP 21. He said staff continues to build business cases for Midwestern projects and will bundle them early next year for stakeholder review. MISO likely won’t propose projects above a 345-kV rating under the first of four rounds of anticipated approvals.
In addition to the usual adjusted production cost savings, business cases for long-range projects will include resolved reliability issues, avoided future investments in transmission and generation, reduced risk of load shed, and contributions to MISO’s resource adequacy requirements. Staff is also exploring other benefits, such as decarbonization support and heightened grid resilience.
MISO has hypothesized that the first group of Midwest long-range projects won’t deliver meaningful benefits to MISO South and won’t share their costs between subregions. Some stakeholders remain skeptical that MISO South will benefit from transmission expansion in the north, given the RTO’s subregional transfer limit.
“I’m a little concerned right now because what I’m hearing is MISO assuming that there aren’t going to be regional benefits,” Sustainable FERC Project attorney Lauren Azar said. She said a presupposition of scarce systemwide benefits might find resistance at FERC, which has a duty to ensure that cost assignments are roughly commensurate with benefits.
Louisiana and Mississippi regulators have threatened to leave MISO if the first round of long-range project costs fall on their utilities’ ratepayers.
EDF Renewables’ Arash Ghodsian asked when the projects’ financial numbers will be available. Johnson said planners don’t expect to have cost-benefit values until next year.
Senior Manager of Transmission Planning Coordination Jarred Miland said stakeholders can expect the first cluster of long-term transmission projects to have near-term in-service dates because MISO is focusing on immediate transmission needs in its first long-range study cycle. The grid operator also said it’s giving extra weight to long-range projects that can be built along existing corridors, rather than securing new greenfield rights of way.
“Siting is probably the biggest challenge that we face, especially considering the challenges of the Cardinal-Hickory Creek line,” WEC Energy Group’s Chris Plante said, referencing MISO’s last — and most troubled — Multi-Value Project. (See Conservation Groups Win Injunction vs. Cardinal-Hickory Creek.)
But Plante said MISO should pay attention to whether two lines built near one another could be taken out simultaneously by severe weather.
Johnson also said staff will analyze any interregional projects coming from MISO and SPP’s joint targeted interconnection queue study to see if there’s any overlap with proposed long-range projects.
MISO’s next long-range transmission stakeholder workshop will take place Dec. 17.
Advocates for green energy last week clashed with activists seeking to preserve sensitive habitat at a hearing on a proposed solar farm in Central Washington.
The two green constituencies said they respected the views of the other side in the virtual hearing held by the Washington Energy Facility Site Evaluation Council (EFSEC) on Wednesday, but stuck by their own interests. EFSEC consists of representatives from several state agencies, who will eventually make a recommendation to Gov. Jay Inslee on whether he should approve the project.
One side supported Portland, Ore.-based Avangrid Renewables’ proposal to build the solar facility, which would produce 200 MW of electricity on almost seven square miles of highlands dubbed Badger Mountain, located about three miles east of the small Columbia River town of East Wenatchee.
Those speakers cited the need for a non-emitting renewable power source to combat global warming and for the green construction jobs that would help the local economy. Five landowners own the site and would lease the land to Avangrid.
A subsidiary of Spain-based energy giant Iberdrola, Avangrid Renewables operates roughly 70 wind and solar projects totaling about 7,000 MW across the U.S.
Opponents of the proposal cited risks to the sage grouse, which lives in the sagebrush-filled shrub-steppe habitat that borders the Avangrid solar site and is listed as endangered by Washington. Roughly 700 sage grouse live in the state, mostly in Douglas County, of which East Wenatchee is the county seat. The habitat areas surround the Avangrid site.
Climate change is also affecting these small birds, which weigh from two to nine pounds. A major part of Washington, including Douglas County, suffered a major drought this year, harming the sagebrush that the grouse need. Also, wildfires from the drying Cascade Range forests to the west have crept into Douglas County in the past two years, eliminating more sagebrush.
Sage grouse habitat once covered most of Central Washington. Now only 8% of that habitat remains in three scattered segments of which the area east of East Wenatchee is by far the biggest. Mike Livingston of EFSEC said that “Douglas County is pretty unique in its habitat for sage grouse.”
Avangrid official Scott Kringen said Wednesday that the actual site contains less than 3% shrub-steppe. “We’re trying to stay out of shrub-steppe habitat,” he said. Eighty-seven percent of the almost seven square miles is non-irrigated agricultural land.
However, opponents based their opposition on the threats to the sage grouse.
“The Sierra Club has a long history of supporting renewable energy in Washington state, but clean energy must be developed so it does not destroy the habitat of our endangered species,” Margie Van Cleve of the Washington Sierra Club said.
“There’s a chance that this project alone can remove this species from the state of Washington,” Keith Watson of Conservation Northwest said.
Mickey Fleming, lands program manager for the Chelan-Douglas Land Trust, said, “We hope you conclude this is not a proper place for solar development.”
Meanwhile, eight Central and Eastern Washington union representatives and construction workers spoke in favor of the Badger Mountain project, which they say could provide 400 jobs during its construction. They also cited needs for alternative power sources to combat global warming.
“We still need additional power generation to meet the needs of the state,” said Robert Abbott, a director at the Laborers’ International Union of North America.
Eric Thrift, a construction worker from East Wenatchee, said the project will help achieve the state’s goal of becoming almost carbon neutral by 2050. A 2020 Washington law sets carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050.
Higher wind speeds were found in new data for the Great Lakes, showing average speeds between 8.5-9 meters per second. | National Renewable Energy Labora
