California regulators are set to vote next month on a proposal that community choice aggregators (CCAs) be subject to the resource adequacy requirements of electric utilities.
The California Public Utilities Commission’s approval would require CCAs to comply with resource adequacy rules “in order to ensure that sufficient energy supply for customers is being procured by the appropriate utility.”
Yellow dots = Operational CCAs; green dots = CCAs launched in 2017; blue dots = CCAs in process or being explored | California PUC
The proposal modifies the timelines for the creation of CCAs so that they are coordinated with the annual CPUC and CAISO resource adequacy and reliability programs. It would require CCAs to submit to a process that includes a timeline for submission of implementation plans; a ‘meet and confer’ requirement between the CCA and the incumbent utility that can be triggered by either; a registration packet including a CCA’s service agreement and bond; and a commission-authorized date to begin service.
It also calls for “universal access” to CCAs, equitable treatment of all customers and compliance with state laws regarding aggregated service. All prospective and expanding CCAs would be subject to the requirements for implementation plans received after Dec. 8, 2017.
CCAs are growing rapidly, creating some controversy over the stranded costs for regular utility customers. California legislators expressed surprise last summer when they were told that utility customers will be on the hook for hundreds of millions of dollars in long-term energy contracts procured by investor-owned utilities for customers who have departed for CCAs. (See California CCAs Spur Worry of Regulatory Crisis.)
The idea has been embraced by cities surrounding the San Francisco Bay Area that promote CCAs as “green” electricity programs. It was municipalities in the San Francisco and Los Angeles areas that lobbied for CCAs in response to a failed deregulation effort that in part caused the Western Energy Crisis of 2000/01. AB 117, enacted in 2002, allows local governments to form CCAs by aggregating retail customers and securing electricity supply contracts to serve them. CCAs also exist in Ohio, New York, Massachusetts, New Jersey, Rhode Island and Illinois.
Pacific Gas and Electric, which has opposed CCAs, argued to state lawmakers in August that about $180 million has been shifted from CCA customers to IOU customers — an amount it said will grow to $500 million by 2020.
California CCAs include Apple Valley Choice Energy, CleanPower San Francisco, Lancaster Choice Energy, Marin Clean Energy, Peninsula Clean Energy in San Mateo County, Redwood Coast Energy Authority, Silicon Valley Clean Energy and Sonoma Clean Power.
WASHINGTON — A panel on investing in grid innovation and clean energy infrastructure last week gave Congress low marks and said emerging economies are proving quicker to adopt some technologies. But speakers at the GridWise Alliance’s GridCONNEXT conference said they are bullish on the future.
David Yeh, a White House adviser during the Obama administration who is now managing director of Capitol Hill, an advisory firm for high net worth individuals, global asset managers and start-ups, said he is not overly concerned with the Base Erosion Anti-Abuse Tax (BEAT) provision in the tax bill passed by the Senate earlier this month. Some renewable advocates fear the language, which is intended to prevent multinational corporations from moving profits and jobs out of the U.S., will reduce the value of wind and solar tax credits.
“Right now clean energy, especially at the utility scale, is competitive, if not cheaper than, fossil fuel energy. So, you can talk about regulation; you can talk about policy. But economics will trump all of that.
“This year, clean energy funds raised about $5 billion, while fossil fuels have raised about $2 billion. That’s showing what the demands are from the … capital providers [and allocators] of this world. … These are sovereign wealth funds; these are pensions; these are large, super high net worth families. … This is how the capital markets — and these are capital markets that start with a ‘T’ — trillions — view clean energy infrastructure. When they move their allocation from 1% to 5%, that’s a game changer. And they’re moving towards that.”
Nancy Pfund, founder and managing partner of DBL Partners, predicted that there will be few gas-fired peaking plants built in California in the future.
“They’re expensive. People don’t like them. They’re [crude] compared to solar and storage or wind or demand response or any combination. That’s an example that you have to let go of what the 20th century was all about. This is really different and if you stand in the way … of consumers who want their solar or want batteries, they are going to run you over.”
An ‘F’ for Policymakers
Policymakers in D.C. haven’t heard that message, however, she said, as reflected in “the $4 billion worth of annual subsidies that the fossil industry gets.”
“If the people on Capitol Hill were in a public policy class or business school course, they would get an ‘F’ because [they are subsidizing] an industry that’s 100 years old. I think anyone in our [clean energy] industry would say we would love a level playing field. Get rid of all incentives. But it’s kind of a ‘David and Goliath’ story at this point.”
Puon Penn, executive vice president and head of technology capital for Wells Fargo, said investors would be wise to look past the U.S. to China and other growing economies that have committed to abandoning the internal combustion engine in favor of electric vehicles.
“Do you think the [original equipment manufacturers] … the Fords and the GMs are looking at the United States as their primary market today? They sell more vehicles in China. And if you’ve got to make electric vehicles for the Chinese market, you’re damn well not going to make a bunch of internal combustion vehicles for the United States. You’re just going to build one platform that you’re going to distribute across the planet. It’s inevitable. But people are still behaving like we’re still [the] Jolly Green Giant walking the earth and determining the order of things. We’re not anymore.”
Penn said new technologies are allowing greater capacity utilization in the electric industry than in the past. “There’s no other industries where you have high [capital expenditures] and such low capacity utilization,” he said. “Today we do have the wherewithal to increase capacity utilization and therefore benefit the entire economy.”
WASHINGTON — Speakers at the GridWise Alliance’s GridCONNEXT conference last week left no doubt: Electric storage is long past the “tipping point.”
Moderator Ram Sastry, vice president of infrastructure and business continuity for American Electric Power, had posed the question: “Are we going to see large-scale deployment of energy storage systems? And if not, what’s stopping that?”
“I think we’re at or past that tipping point,” responded Andy Marshall, practice director for distributed energy resource management at Landis & Gyr. “I think you see the flexibility of storage and its ability to get deployed relatively quickly. You have not only the stuff that’s going on down in Australia, but you also have the things that are happening most recently in California.”
On Dec. 1 — the first day of summer for Australia — Tesla turned on a 129-MWh lithium ion battery, the world’s largest, to help the nation’s fragile electric grid. California deployed 100 MW of storage in just six months in response to natural gas constraints following the Aliso Canyon leak.
Praveen Kathpal, vice president of AES Energy Storage, said “the technology is mature,” noting that his company entered the business a decade ago. AES claims 500 MW of storage already deployed or in development.
“There haven’t been any components that needed to be invented for any of the deployments that we’ve done, because they’re all based on lithium ion battery technology, which was commercialized 25 years ago and has benefited from its use in the consumer electronics and transportation sector,” Kathpal said.
“The tipping point we see in storage is really meshing with some of the other megatrends facing our industry right now. We have the accelerated growth in renewables, and we also have the electrification of more sectors including transportation.”
Kathpal predicted new storage technologies will break below the current pricing floor for lithium ion. “So, 10 years from now, do I think we’ll have a commercially available storage technology that’s below $100/kWh? Sure. And that’s exactly why at AES the technology platform we’ve developed is forward compatible with technology change.”
“I think you could argue that the tipping point was several years ago when big PJM systems started to come online,” said Luke Witmer, lead research engineer for Wärtsilä’s Greensmith Energy. “More and more markets continue to value the fast-ramping and bidirectional capability that energy storage provides. And I think as … systems continue to decline in cost, we will compete in more and more markets. A lot of the market prices basically clear according to the natural gas price. … So it’s really just a matter of getting renewables plus storage to below that threshold in more and more places.”
Richard Brody, director of sales and marketing for Lockheed Martin Energy’s energy storage unit, said storage is still relatively expensive when compared with energy efficiency and demand response.
“Whether we’re talking about a C&I customer or a distribution utility, when we come look at an energy problem, we look not just at storage, but we start with efficiency, permanent load reduction, load control, demand response, demand management, grid analytics — all the tools you can bring to solve an energy problem. … We tend to look at other things first because storage — despite the declining costs — remains the most expensive way to address these problems.”
But he is nevertheless bullish on storage. “In terms of the tipping point — oh yeah, we’re passed it. This is a rapidly growing market.
“We’re seeing very strong growth in interest in doing large solar and wind coupled with storage. Most of the large developers we’re working with aren’t contemplating any large development of solar — and increasingly wind — without some way to firm it up with a fairly significant storage system.”
Brody said the demands are exceeding the four-hour maximum life for lithium ion batteries. “We’re looking at much more ambitious efforts that would require the attributes of a flow battery, which is a minimum of six to 12 hours of energy.”
A Sierra Club report released last week that said captive customers of SPP utilities are paying for uneconomical coal plants has drawn considerable pushback from the RTO and some of its members.
But the head of SPP’s Market Monitoring Unit (MMU) says the environmental group has a point in its criticism of utilities that self-commit coal generators when the RTO’s market prices don’t cover their operating costs.
When a utility self-commits a unit, it operates the plant regardless of whether SPP’s market clearing prices are sufficient to cover the plant’s marginal costs. Although self-committed units are ineligible to receive make-whole payments from SPP, the Sierra Club says, some units are apparently recovering losses from captive customers through state ratemaking proceedings.
The Sierra Club report, “Backdoor Subsidies for Coal in the Southwest Power Pool,” alleges that utilities in the footprint operate coal plants outside the wholesale markets, generating $300 million in excess costs that consumers were forced to pick up in 2015 and 2016.
SPP and its members responded by saying the Sierra Club’s analysis relied heavily on wholesale rates, which aren’t the same as retail rates that are subject to public policy and regulations. Nor do wholesale rates consider the cost of long-term supply contracts or ensuring grid reliability, they said.
Keith Collins, executive director of the MMU, says that while the report took some of the MMU’s observations out of context, self-commitment is a problem in the RTO’s markets. MMU staff raised the issue in their 2016 State of the Market report, which Collins reviewed with SPP’s Board of Directors and Members Committee in July.
The Sierra Club said it conducted a “high-resolution analysis” of 14 coal plants in SPP’s footprint. It used hourly market data to develop each plant’s cash flow analysis.
“All 14 units operated for extended periods of time when, objectively, it would have been less expensive for the electric bills of utility customers for the plants to sit idle,” the group’s report said. “The utilities that own each of the 14 coal units we examined would have saved its customers money if the coal units had operated less often.”
The report said all but one of the 14 units studied were owned by state-regulated utilities, municipal utilities or an electric cooperative with captive customers.
Utilities should be purchasing electricity for its captive customers in the SPP Integrated Marketplace (IM), the report said. But it said some utilities “appear to be going back to state commissions and using rate cases and other dockets to obtain ratepayer-funded subsidies for costs incurred in operating otherwise uneconomic coal plants.”
“In the SPP market, where nearly half of the resources are self-committing, how much of an energy market can SPP really be claiming to operate?” the report asked. “The consequence of these facts is that the SPP Integrated Market is possibly a market in name only. The impact of utility self-commit and underbidding energy offers within the SPP IM might be the most anticompetitive and anti-consumer behavior in any integrated electricity market anywhere in North America.”
The report also says self-committed coal units are denying revenues to independent merchant generators. “RTOs are supposed to create nondiscriminatory rates, but allowing coal units to self-commit discriminates against those operators that don’t have captive customers to fund a ratepayer subsidy. Moreover, it is discriminatory and unreasonable for the market to ask one subset of customers to pay above-market costs while all other customers pay market costs.”
Collins told the board and members that self-commitment of resources has declined but is “still very big.”
“When resources are self-committing, it can put downward pressure on prices also,” he said at the time, referring to the effects of incorporating uneconomic resources in wholesale prices.
“The point of the [Sierra Club’s] report is consistent with what we noted in the 2016 annual report,” Collins told RTO Insider. “Self-commitment can distort the market. It’s a message we’ve been presenting as well.”
The MMU report noted generation offers in the day-ahead market averaged 48% as “market” commitments and 35% for “self-commit” in 2016. Those numbers were 46% and 39%, respectively, in 2015. Outages accounted for the remainder.
The Sierra Club report quoted the MMU report, which said plants self-commit because of contract terms, low gas prices “that reduce the opportunity for coal units to be economically cleared in the day-ahead market,” long start-up times, and “a risk-averse business practice approach.”
Collins took exception to the Sierra Club’s claim that “reliability isn’t one” of the reasons why a unit might self-commit.
Although the MMU’s report didn’t cite reliability, Collins said, “reliability could play a factor where some of these resources self-commit. Our report identified a set of reasons for self-committing, rather than a complete list.
“We have been discussing this essentially since I’ve been here,” said Collins, a former FERC staffer who joined SPP in June from CAISO. “What are the factors [behind self-commitment]? What can we do to promote more market commitment? Some of it is education and creating awareness. At least there’s a dialogue there that’s begun.”
SPP Disagrees
SPP General Counsel Paul Suskie said in a statement that the RTO disagreed with the report’s fundamental assertion that “utilities’ option to either self-commit resources or purchase from the market equates to a subsidy and undermines the effectiveness and cost-efficiency of SPP’s Integrated Marketplace.”
Suskie said that “assessing the market’s fairness and effectiveness based on wholesale cost of electricity to consumers does not take into consideration a number of factors that may lead utilities to self-commit.” He listed contractual obligations, capital investments, public policy and fossil fuels’ contribution to renewable resources’ deliverability as among those factors.
“Our day-ahead market has functioned successfully for four years and, in that time, has reduced the cost of energy in our region by more than $1.25 billion while continuing to ensure the reliability of the grid,” Suskie said.
Peter Main, a spokesman for SPP member Southwestern Electric Power Co., said the company bids its generation into the RTO’s markets under its market protocols and will continue “to seek opportunities” to produce net energy revenues benefiting its customers.
“The Sierra Club report does not provide an accurate portrayal of the incremental (variable) costs and revenues associated with offering generation into the SPP Integrated Marketplace,” Main said in a statement.
Plant Operators Dispute Findings
According to the report, SWEPCO’s Dolet Hills and Pirkey plants in the East Texas-Louisiana region burdened customers with $210 million in costs in 2015 and 2016. However, SPP said the plants serve load in “locations in northeast Texas without significant wind.”
Oklahoma Gas and Electric, which owns two of the plants identified in the study, has said the units stopped self-committing into the market more than two years ago. Two other generators — Entergy-owned or co-owned plants in Arkansas — serve load in MISO.
Al Armendariz, with the Sierra Club’s Lone Star chapter, said he was confident the group has a “good handle on the cost to run these coal plants in SPP.”
Armendariz, who worked in EPA under President Barack Obama, said the Sierra Club compared the SPP LMPs paid to power plants in the immediate vicinity of the coal plants studied. The organization obtained operating data from S&P Global Market Intelligence, the U.S. Energy Information Administration and SPP in running its analysis.
“Our report is really a comparison of the revenue for electricity, compared to what it costs to actually run the power plant,” Armendariz said.
Rule Changes Sought
The Sierra Club would like to see several things happen, Armendariz said. “We think SPP should clarify its rules to require power plants to bid in their real cost of fuel and other variable [operations and maintenance] … in the day-ahead market.”
Armendariz also said the Sierra Club would like to see state commissions in SPP’s footprint “investigate this problem of self-commitment and disallow the recovery of costs borne by consumers when uncompetitive coal plants are operating.”
“Vertically integrated utilities should not be forcing their customers to pay the variable costs,” he said. “State commissions should not allow the recovery of those costs through the rate base.”
Asked whether the group planned to file a complaint with FERC, Armendariz told RTO Insider that the Sierra Club “is evaluating all avenues of legal recourse that may be available to rectify the problems.”
Both Armendariz and Collins agreed the problem of self-commitment is not unique to SPP. Collins said he saw self-dispatch at CAISO and “knows” it occurs in other markets. Armendariz said although uncompetitive coal plants are running in “virtually every market … the problem seems most acute in SPP.”
The MMU believes that will change as market participants continue to familiarize themselves with SPP’s day-ahead and real-time markets, which have been in operation for less than four years.
“It appears that resource owners are becoming more confident in the market and allowing the market to commit the resource instead of self-committing their resource,” the State of the Market report said.
The Monitor also said the market systems’ optimization algorithm is restricted to a 48-hour window. “Hence, large baseload resources with long-lead time and substantial start-up costs may not appear economic to the day-ahead market commitment algorithm,” the report said.
Collins said SPP’s Market Working Group has discussed a potential multiday optimization approach. A Tariff change has yet to materialize, he said, “but that could help address some of the concerns.”
WASHINGTON — Almost 190 investors, utility officials, technology company executives and others gathered for the GridWise Alliance’s two-day GridCONNEXT conference last week. Here’s some of what we heard.
FERC Enforcement, Tx Investment, Cybersecurity
Former FERC Commissioner Philip Moeller, a Republican, and Spencer Gray, a Democratic aide on the Senate Energy and Natural Resources Committee, talked about the newly reconstituted commission, transmission investment and the limited prospects for bipartisan action in Congress.
“We are at a low ebb in bipartisan relations,” Gray said.
But he said there was one exception. “I think there’s broad bipartisan consensus in the Senate to … focus more funds on cyber[security],” Gray said. “We’ve gotten [feedback] from a lot of groups in recent years that the federal government should have a more robust R&D program to develop new cyber tools and understanding of emerging cyber threats. That just seems like the lowest hanging fruit to me. It’s not a partisan issue at all.”
Moeller, who oversees the Edison Electric Institute’s business operations group and regulatory affairs, said the industry is “actually doing a very good job” on cybersecurity through the Electricity Subsector Coordinating Council. “But I’m not sure as an industry we necessarily tell our story well, partly because of the sensitivity” of the subject matter.
Moeller lamented the court rulings that rejected FERC’s “backstop” transmission siting authority in the 2005 Energy Policy Act. But he acknowledged the commission’s efforts to encourage transmission investment haven’t always been helpful.
“Our feeling is that the capital is out there but perhaps some of the [investment] signals need to be clarified. Whether it’s the [return on equity] mess at FERC, which I helped create unintentionally. But in trying to solve a problem, we’ve probably made it a little bit worse. I think there’s some uncertainty on the future of Order 1000. And it took a while I think for people to, like it or not, have the Clean Power Plan more in the rear-view mirror before they could focus on the expansion of the transmission grid.”
On Wednesday, EEI released a report suggesting changes to FERC’s ROE calculations that ClearView Energy Partners said could increase the model’s results by approximately 50 basis points.
Gray said Sen. Maria Cantwell (D-Wash.), ranking member of the ENR Committee, will be watching “what happens under the new leadership of FERC to the Enforcement office.” In response to the abuses that contributed to the 2000-2001 Western Energy Crisis, Cantwell helped draft language in the 2005 Energy Policy Act that gave the commission increased authority over market manipulation.
Scott Prochazka, CEO of CenterPoint Energy and chairman of the GridWise Alliance, said Hurricane Harvey — “our third 500-year storm in two and a half years” — proved the “incredible” value of mobile substations. The company also is likely to add airboats and trucks able to drive through high water, he said. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)
Robert Schimmenti, senior vice president of electric operations for Consolidated Edison, recalled how the utility was “humbled” by the 14-foot storm surge that drenched parts of Brooklyn and Lower Manhattan during Superstorm Sandy in 2012.
“All the weather predictions were around 12 feet. We did all the math and all the projections, and we thought we were good for about a 12-and-a-half-foot storm surge. It was only until a bunch of bright engineers linked the buoy data in the East River to a map of storm projections that they created — and this is well before high tide — and as they created these projections, we were like ‘Hey, wait a second. This doesn’t look good.’”
More than 1 million Con Ed customers in New York City and Westchester County lost power during the storm. The company has spent $847 million to make its system more resilient, including the addition of “smart switches” to isolate and clear trouble on lines, flood gates, pumps and 3 miles of flood walls around critical equipment.
Hurricane Maria took down “only” 220 230-kV towers in Puerto Rico, said Bruce Walker, assistant secretary for the Department of Energy’s Office of Electricity Delivery and Energy Reliability. But replacing each tower is a five- to seven-day project requiring ferrying of workers and equipment by helicopter, Walker said.
“One of the things that was striking to me regarding their system is their transmission lines; while very well built, [they’re] built right through the mountains. There are no rights of way; there are no roads. There is no tree clearing in those areas.”
Praveen Kathpal, vice president of AES Energy Storage, said his company recently outlined for the Puerto Rico Energy Commission “a vision of how 10 GW of solar plus 2.5 GW of storage, arranged in essentially sectionalized grids across the island, could provide both resilience and lower costs, because those [investments] break even with how much Puerto Rico would spend on burning oil for power generation over the next 10 years.”
Kathpal said AES’ 10-MW battery installations in the Dominican Republic “rode through all the grid disturbances of Hurricanes Irma and Maria” despite damage to transmission lines and generation outages. “A battery installation is physically resilient. It’s not as subject to the factors that during an intense storm would cause other resources to disconnect. So even as 40 to 60% of the generation in the Dominican Republic tripped off, the batteries continued to operate. And as you can imagine with those kinds of generation trips, the frequency was flopping all over the place. So they actually did more work to restabilize the system.”
BOSTON — FERC Commissioner Neil Chatterjee promised Thursday that the commission will not become part of what he called the “hyper-politicized” policymaking process in D.C.
Chatterjee made his remarks at a meeting of ISO-NE’s Consumer Liaison Group on Dec. 7, which also included a panel on energy storage and a discussion of energy and capacity prices.
Chatterjee is among the four commissioners who have joined FERC since August. He spoke to ISO-NE hours after the swearing in of Kevin McIntyre, who replaced him as chairman. (See related story, McIntyre Takes FERC Chair; Wins Delay on NOPR.)
A former energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), Chatterjee said it’s increasingly difficult to get any policy change through the legislative process, particularly regarding energy.
“Increasingly, energy policy is being made by provisions in the tax code, measures in big, year-end spending bills, or more so, more and more policy decisions are being made at agencies throughout the federal government,” Chatterjee said. “As someone who now works in the executive branch and may be the short-term beneficiary of that increased authority in the executive branch, I don’t think it’s good for democracy or good for America.”
Energy policy needs to be made in Congress to have lasting impact and avoid regulatory uncertainty, he said.
“For instance, in the EPA, the mission of the EPA today under Administrator [Scott] Pruitt is the polar opposite of what Administrators [Gina] McCarthy and [Lisa] Jackson had under the prior administration,” Chatterjee said. “There’s been a wholesale shift in direction, and that really leads to regulatory instability for consumers, for folks in the business of power generation and distribution. It creates just so much lack of clarity and uncertainty.
“One of the things I’m proud of is FERC provides stability. Not only is the nature of the work at FERC inherently technical, not political, but also because you have the bipartisan board structure — where the president’s party never has more than three members — you’re never going to lurch dramatically in a new direction. So even though there’s new leadership at the commission today, and we may not go in the exact same direction as the prior leadership was going, we’re not going to go in a dramatically different direction than the prior leadership.”
Republicans now hold a 3-2 edge on the panel. Because of the commission’s turnover and “what is perceived to be a political exercise” with the Department of Energy’s call for price supports for coal and nuclear plants, Chatterjee said, he’s heard concern that the commission will become more political. (See FERC’s Independence to be Tested by DOE NOPR.)
“I have to tell you, that’s not going to happen,” he insisted. “If you look at the composition of the five of us who sit at the commission, you have Commissioner [Cheryl] LaFleur, who has seven years’ experience on the commission but also decades in the energy space. She’s a leader we all respect and look up to and she will provide that stability.
“Kevin McIntyre, who was sworn in as chairman today, is one of the top energy lawyers on the planet, let alone in the country. He’s a serious, thoughtful leader who’s got a great temperament who will provide that steady leadership.
“Both Commissioner [Richard] Glick and I come from the Senate, and the thing about the Senate … is you work for the whole country … and see things holistically. Commissioner [Robert] Powelson had been chair of a state commission and brings that very valuable state experience … and state commissioners are very attuned to the interests of consumers.”
Chatterjee said one reason he wanted a seat on the commission was to encourage new technologies such as energy storage, which he said could help improve grid resilience.
“We are currently working through a storage rule at the commission that will … remove barriers to competition and access for storage, and enable storage to be properly compensated for the value it provides,” Chatterjee said.
Working on Energy Storage
The Consumer Liaison Group meeting included a panel on energy storage moderated by Robert Espindola, energy systems program manager for Acushnet. On Thursday, his company won a $700,000 grant from Massachusetts for a storage project at the company’s Titleist golf ball factory in New Bedford. (See Massachusetts Awards $20M in Energy Storage Grants.)
CLG Energy Storage Panel (L-R) Robert Espindola, Acushnet; Christopher Parent, ISO-NE; DOER Commissioner Judith Judson; Lewis Milford, Clean Energy Group
Also on the panel were Christopher Parent, the RTO’s director of market development; Massachusetts Department of Energy Resources Commissioner Judith Judson; Lewis Milford, president of Clean Energy Group, a nonprofit in Montpelier, Vt.; and Ted Ko, director of policy at Stem, which pairs artificial intelligence with storage to automate cost savings.
Judson had appeared earlier that day at a ceremony marking the storage grants.
In July, DOER adopted a 2020 target of 200 MWh energy storage for the three electric distribution companies in the state. Judson said that the short-term target is line with the 2025 goal of 600 MW laid out in the state’s State of Charge report last year.
As of Dec. 1, the RTO had 400 MW of energy storage in the interconnection queue, or about 3% of all generation applying to interconnect, Parent said. (See ISO-NE Preparing for Energy Storage Growth.)
ISO-NE Vice President for External Affairs and Corporate Communications Anne George, who presented an update on the RTO’s activities, said it projects an energy market value of $3.9 billion for 2017. The value has been declining for a decade and is down more than two-thirds from the $12.1 billion posted in 2008, she said.
“But we also see the capacity market is ticking upwards,” George said. “That’s really because back in 2013 we saw … a large chunk of the resources retired in the region, and when they did that, in the eighth Forward Capacity Auction we saw prices rise. That’s how markets behave.” Prices continued to rise in the succeeding FCA, then dropped in FCA 10 and FCA 11, she said.
“So, you’ll see some increase in the capacity market portion of wholesale market costs over the next couple of years, but then you’ll start to see it level off and come back down,” George said. “Right now, we are in a surplus situation.”
FCA 12 is scheduled to take place for February 2018, covering the June 1, 2021, to May 31, 2022, capacity commitment period. In November, the RTO submitted a pre-FCA informational filing with FERC for review, which included all FCA-related calculations and determinations.
CARMEL, Ind. — MISO will require its managers to undergo training on handling harassment complaints amid heightened awareness over sexual misconduct in the workplace.
MISO Vice President of Human Resources Greg Powell announced the new training during a Dec. 5 Human Resources Committee of the Board of Directors meeting.
In response to a question from Director Mark Johnson, Powell also said HR and management will have additional discussions on sexual misconduct awareness in the first quarter of 2018. “What are we doing from an overall standpoint to make sure all employees feel safe?” Johnson asked.
The HR Committee also decided to reserve time during first-quarter meetings to take up the topic.
“News headlines in recent weeks remind all organizations of the importance of ensuring a respectful and professional workplace,” Powell said, referring to the spate of sexual harassment and assault accusations that have roiled the media, politics and other industries. “Even some in our energy industry have fallen to this very bad situation in the headlines.”
NERC CEO Gerry Cauley resigned last month after his arrest for assaulting his estranged wife after she allegedly discovered his relationship with a female subordinate. (See Cauley Resigns; NERC Launches Search for Replacement.)
Powell said MISO will initiate a longer, more intense training for managers that will cover “all workplace harassment issues” in addition to the existing annual springtime sexual harassment training required of all employees.
Director Barbara Krumsiek has also been tapped to advise leadership and the MISO board on preventing sexual harassment and addressing accusations. Krumsiek has served as senior industry fellow of Georgetown University’s Women’s Leadership Institute and has given a TED Talk on women making their way to C-suites in “toxic” cultures.
MISO urges employees to contact managers, HR and its legal department with complaints. The RTO also maintains an anonymous hotline.
Powell said MISO will continue to concentrate on training and increasing awareness among its HR ranks and management.
“In addition to a strong, comprehensive sexual harassment policy and regular training required annually for all employees, we are working to extend beyond the expected actions to involve employees at every level to support a strong, open and inclusive way of life,” Powell said. “This includes the recent launch of our Diversity and Inclusion Council and Women’s Resource Group, which were created to ensure we continue our steadfast focus on diverse viewpoints in the organization and our communities.”
The RTO currently has a 3.1 approval rating out of 5 on Glassdoor with a 36% CEO approval rating. Among more than 100 reviews by present and former employees are multiple references to MISO as an “old boys’ club” with “top-heavy” management.
“Creating a Women’s Resource Group and then promoting men who mistreat women (you know who I’m talking about) won’t fix MISO,” one anonymous reviewer identifying as a current MISO engineer said in a review posted in May.
MISO declined to say whether it has disciplined any employees for harassment or sexual misconduct, saying it considers all personnel-related information confidential.
SALT LAKE CITY — The Western Electricity Coordinating Council’s board of directors last week endorsed a new three-year operating plan for the organization, part of a larger reinvention intended to more precisely define the organization’s role in protecting electric grid reliability.
The Regional Entity is undergoing a transformation that began with its 2014 restructuring and bifurcation into WECC and Vancouver, Wash.-based Peak Reliability. WECC is the largest and most diverse of NERC’s REs responsible for monitoring and enforcing compliance with reliability standards.
WECC Board of Directors (Left-Right): Joe McArthur, Richard Woodward, Shelley Longmuir, CEO Jim Robb, Chair Kris Hafner, Vice-Chair Ian McKay, Gary Leidich, Mike Core, Richard Campbell (not pictured) | Kirha Quick for WECC
Peak Reliability, which counts utilities, transmission owners and CAISO among its six classes of members, now serves as reliability coordinator for the Western Interconnection, except the Canadian province of Alberta. The organization last week said it is exploring developing a new market structure with a division of PJM. (See PJM Unit to Help Develop Western Markets.)
WECC CEO Jim Robb | Kirha Quick for WECC
“Really, [WECC] got kind of refocused on its core reliability assurance mission,” WECC CEO Jim Robb told RTO Insider. The 2018-2020 operating plan endorsed by the board “is really just building a process that wasn’t in place before, recognizing that we have a new kind of board, new management and a new relationship with the members.”
WECC develops and implements reliability standards and regional criteria across 14 Western U.S. states, Alberta, the Canadian province British Columbia and a small, northern portion of Baja California, Mexico. It is a 501(c)(4) “Social Welfare organization” with a current annual budget of $27 million.
Last week Robb detailed the company’s many ongoing initiatives to the board at WECC headquarters, in a modernized former hardware store in downtown Salt Lake City. The discussion illustrated the many complexities in monitoring reliability on an electric grid that is rapidly changing in resource mix and market structure.
A year ago, the WECC board approved five areas of strategic focus for the next three to five years, including focusing on the reliability impacts of new and changing market structures, such as the Western Energy Imbalance Market (EIM) and Mountain West Transmission Group’s effort to join SPP.
Other areas of focus include the reliability impact of changing load and energy resources, identifying and mitigating key vulnerabilities, and analysis of future events that could affect grid reliability that encompassed “high impact, low frequency” events.
What’s in a Name?
WECC has recently revived a proposal to change its name to “Reliability West,” which officials contend would complete the bifurcation efforts begun in 2014 and position the organization as “mission-driven” and “create separation from its history as a Registered Entity,” according to a WECC white paper published last month to tackle issues around the name change, which has been under discussion for three years. The change has many implications regarding implementation costs, perceptions of what the organization does and possible confusion with other entities that share the WECC acronym, the document shows.
The WECC Board and Committees met on December 4 – 5 in Salt Lake City, Utah | Kirha Quick for WECC
“Some folks think this is just a branding effort,” Robb said at the meeting, adding that the proposed name is more reflective of the company’s mission and easier for employees to engage with.
WECC is also drawing up a three-way memorandum of understanding with NERC and the British Columbia Utilities Commission to better define the roles and responsibilities of each organization, and developing a reliability agreement with the Mexico’s Energy Regulatory Commission (CRE). It is also taking comment through Feb. 5 on proposed changes to the operating rules for its Western Renewable Energy Generation Information System (WREGIS).
WECC is funded through allocations to end users in its footprint based on net energy for load, as described in its delegation agreement with NERC. It is not a resource planner, but assesses the reliability implications of resource decisions and identifies concerns to address.
The organization also produces reliability reports on the Western grid. Its June 2017 State of the Interconnection Report showed that, between 2015 and 2016, loss of generation or transmission in the U.S portion of the Western Interconnection increased by 50% to 24 events. (See WECC Generation, Transmission Loss Events Spike.)
In the area of assuring reliability, WECC said its second-quarter index score of reliability outcomes in the Western Interconnection was at or above the average of the past eight quarters, as was the score of indicators of entities building better compliance programs.
CARMEL, Ind. — MISO’s Board of Directors on Thursday unanimously approved the RTO’s annual Transmission Expansion Plan, including 353 new transmission projects valued at $2.6 billion.
But a Texas project subject to shifting cost allocation was benched for at least two months before approval.
MTEP 17 contains $1.4 billion of projects driven by transmission owners’ local needs, including reliability, replacement of aging equipment and upgrades for environmental requirements. Almost $1 billion will be spent on baseline reliability projects, while nearly $240 million will go to generator interconnection projects. The proposed projects have expected in-service dates through 2024.
“The bulk of the dollars are being driven by local needs,” MISO Vice President of System Planning Jennifer Curran said.
MISO South represents 41% of spending under the new plan, in keeping with a trend that increasingly allocates more spending to the southern portion of the RTO’s footprint, which is experiencing load growth — unlike the Midwest region.
Texas Project Delay
The board postponed approval of the $130 million Hartburg-Sabine 500-kV line market efficiency project (MEP) in eastern Texas for two months because of a late change to cost allocation for the projects. Last month, regulators from both Texas and Louisiana asked MISO to create separate zones for the two states to allow for a more specific cost allocation.
Hartburg to Sabine Junction project | MISO
MISO has since filed with FERC to rename Local Resource Zones as “Cost Allocation Zones” for the purposes of allocating MEP costs only, with Louisiana becoming Zone 9 and Texas becoming Zone 11 (ER18-364). The proposal does not eliminate LRZs, which are used to determine resource adequacy needs, nor does it change their boundaries.
“Out of an abundance of caution, MISO does believe that a short delay would be prudent,” Curran said. A board vote on the project has been put off until Feb. 5, allowing FERC time to respond to MISO’s filing.
“The change to the zonal requirement makes sense,” Curran said. “Most of our other cost allocation zones are based on state lines.”
MISO policy requires that 80% of the costs for MEPs be allocated to local resource zones based on their relative share of adjusted benefits.
Curran said the delay would not affect MISO’s timeline for issuing a request for proposals for the project.
The Hartburg-Sabine project will be MISO’s second-ever competitively bid transmission project and the first such project to include a substation, and the RTO plans to add two new staff members to oversee the competitive process behind the project. The line is intended to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area straddling Texas and Louisiana.
“There’s a significant amount of aging infrastructure in this area,” MISO interregional adviser Adam Solomon said.
The Texas project has already frustrated some stakeholders, who last month considered requesting a longer delay over concerns about the project’s cost estimates. (See MTEP 17 Advances with Disputed Texas Project.)
TMEP project locations | MISO
MTEP 17 also includes five targeted market efficiency projects, smaller interregional projects meant to relieve historical congestion on seams shared with PJM, whose Board of Managers also approved the TMEP portfolio on Monday. (See related story, New Wave of PJM Transmission Upgrades Rankles AMP.)
All five TMEP projects this year are upgrades to existing systems. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined.
TMEP project costs will on average be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million within four years of going into service.
TMEPs are designed to address cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. To qualify, projects must cost less than $20 million, be in service within three years of approval and provide historical congestion relief that is equal to or greater than construction costs within the first four years of operation.
CARMEL, Ind. — The MISO Board of Directors last week learned about the recent discovery that PJM had been committing two market-to-market errors that have likely cost MISO millions of dollars over a period of years.
They also heard that MISO may have little recourse to recover those losses.
At issue was PJM’s longtime practice of overstating its own transmission loading relief (TLR) because of a calculation error and its failure to order mandated tests required to define M2M constraints between the two RTOs. (See MISO Monitor Blames PJM for Market-to-Market Errors.)
During a Dec. 5 meeting of the board’s Markets Committee, Independent Market Monitor David Patton said MISO has anted up millions in unnecessary congestion costs stemming from PJM’s mistakes.
The untested M2M constraints led to $84 million worth of congestion in 2016 and $187 million in 2017, Patton said, adding a disclaimer that his firm probably couldn’t perfectly duplicate the constraint test that the RTOs perform, and that they may show different congestion values. Delays in defining constraints resulted in $44 million worth of congestion last year and $25 million this year.
“If they don’t define the constraint, they basically get to a free pass to use the transmission system,” Patton told the board.
Patton said one flowgate that wasn’t tested or defined as M2M led to $43 million in congestion in September alone.
“A unit was running, overloading the constraint, and we did not tell PJM to back it down,” Patton said. “We need to be vigilant. … We don’t always ask our neighbors to test the constraints.”
Willful Neglect?
Patton said PJM’s failure to order these tests was deliberate: “In our mind, this is a pretty gross violation of the Tariff, particularly since they knew they weren’t doing the test.”
Director Baljit Dail asked how Patton could be sure PJM knowingly neglected the test.
Patton said at the beginning of the RTOs’ M2M process nearly a decade ago, PJM was aware it needed to devise a new constraint model that included an actual representation of MISO system outages with shift factors, but it failed to create such a model. “They never did it, and they knew they didn’t do it.” Patton said.
“I’ll hold the rest of my questions for closed session,” Dail replied, referring to a closed session on the matter following the board’s open meeting.
“What is it that we can do as a board?” Director Thomas Rainwater asked.
Patton said there weren’t many options available to the board. It could urge enforcement by FERC, “which to be honest, hasn’t been very active in enforcement on violations of RTOs.”
“I don’t think there’s a lot you can do other than telling PJM how serious you think this is,” Patton said. He also said MISO stakeholders could pursue resettlement of prices related to the TLR miscalculations, although no precedent exists for such resettlements. PJM has been overstating its TLR response since 2009, “inappropriately” raising the relief obligation of MISO and other balancing authorities, Patton said.
Patton said it’s up to stakeholders to decide whether to pursue TLR resettlement at FERC.
“We’ve certainly resettled for less,” Patton said.
“These are serious issues with big dollar amounts,” Director Barbara Krumsiek said.
MISO Executive Vice President of Operations Richard Doying said strategies for resettlement would “certainly be a closed discussion item.”
PJM Responds
PJM Chief Communications Officer Susan Buehler told RTO Insider that PJM acknowledges it had “an internal process issue regarding the flowgate tests as well as a calculation error with respect to relief obligations,” but it disagreed that the issues amounted to a Tariff violation. She also said the MISO Monitor is possibly overstating the monetary impacts.
“PJM has corrected both issues and is evaluating the potential impacts, but at this time we do not believe the impacts are what the MISO IMM has indicated,” Buehler said.
She also said the congestion impacts and monetary values the Monitor has disclosed are projections and not solely a consequence of PJM’s “internal process issues” and “potential M2M inefficiencies” with constraints. PJM cannot confirm Patton’s numbers, she said.
JOA with TVA
Patton also urged the board to consider entering a joint operating agreement with the Tennessee Valley Authority over the TLR issue. MISO discovered PJM’s incorrect TLR values while investigating a northeastern Tennessee constraint, and Patton said TVA often calls TLRs on its 500-kV Volunteer-Phipps Bend line, which leads to price increases in the Midwest and corresponding reductions in the South. The TLR constraint contributed to higher prices during a late September emergency event, Patton said.
He said MISO has incurred 100 dispatch violations of its own constraints in responding to the competing dispatch effects of the Volunteer-Phipps Bend constraint.
“We’ll violate our own constraints in order to provide TLR to TVA,” Patton said. He also said TVA’s generation is almost always more effective and economic for managing a TVA constraint than MISO’s.
Patton originally complained about the excessive amount of relief MISO is asked to provide the Volunteer-Phipps Bend more than two years ago. (See External Constraint Vexing MISO, Market Monitor Says.) Now he thinks the RTO could lower its transmission constraint demand curve for TLR requests to avoid incurring costs to provide “very small amounts of relief.” He said MISO should instead pay TVA for economic relief on constraints pursuant to a JOA.
Doying said MISO is not in 100% agreement with the Monitor’s suggestions. “We value the reliability of our neighbor’s systems as much as we value the reliability of our own,” Doying said.
However, Doying said MISO is currently drafting a narrow JOA with TVA that would govern certain flowgates. He said MISO has had similar agreement with TVA in the past.
Patton also noted that TVA at times orders TLRs on Volunteer-Phipps Bend as a proxy to obtain relief on a nearby 161-kV constraint, and he questioned the efficiency of TVA’s process.
Director Paul Bonavia asked MISO executives if it was appropriate under NERC rules to use the 500-kV line as a proxy for a 161-kV line. Doying said the practice doesn’t violate NERC policies.
MISO General Counsel Andre Porter then reminded the board that further discussion was best left for a closed session.
“We’re not going to solve all of this today, but we’ll grapple with it, get it on the table,” Bonavia said. “How do we approach the resettlement issue. … How do we help our neighbors without being overzealous?”
“I do think we have a lot of issues to untangle with PJM and TVA,” Doying said.
