FERC last week opened a Section 206 investigation into inconsistencies in MISO’s Tariff after re-examining the 2016 termination of a North Dakota wind farm’s generator interconnection agreement (GIA).
| EDF Renewables
The commission on Thursday said MISO’s rules may not be just and reasonable because of discrepancies between the generator interconnection procedures outlined in the RTO’s Tariff and its pro forma GIA. It required MISO and interested parties to file briefs for a paper hearing (EL17-18). FERC expects to render a final decision in June and issued an Oct. 19 refund date.
The commission’s concern centers on a pre-2012 provision in the generator interconnection procedures that allowed an interconnection customer to extend its commercial operation date by up to three years without losing its position in the interconnection queue if MISO found that the extension would not adversely impact lower-queued customers. The provision was narrowed in 2012 so that once entering the definitive planning phase, MISO only allowed the three-year extension if it was caused by a change in milestones by another party to the GIA or a change in a higher-queued interconnection request.
MISO added a third provision for study delays in 2016. At the time, FERC said, “MISO’s proposal to limit the types of changes permissible in the definitive planning phase is consistent with the need to ensure that a project that enters the definitive planning phase is ‘definitive.’”
However, MISO’s GIA was never edited to add the three conditions for a three-year extension and “effectively provides interconnection customers an ability to extend their [commercial operation date] by three years before MISO can seek to terminate a GIA,” according to the commission.
FERC pointed out that MISO has cited the three-year limit in its generator interconnection procedures when terminating GIAs and said the RTO’s latitude to terminate GIAs is “permissive in nature.” The commission also said MISO’s outright termination of GIAs based on the three-year condition ignores its material modification analysis process, which is triggered when an interconnection project experiences changes that affect cost or in-service timing.
FERC said MISO’s interconnection procedures should be revised to reference its GIA and “allow that once a GIA is executed or filed unexecuted, a three-year period from the [commercial operation date] should lapse before MISO seeks to terminate the GIA.”
The issue was initially raised by EDF Renewables subsidiary and wind developer Merricourt Power Partners, which contested FERC’s acceptance of a MISO notice of termination of a GIA entered into by enXco Development and subsequently assigned to Merricourt. (See FERC Upholds MISO Cancellation of GIA.) At that point, the 75-turbine, 150-MW Merricourt wind project in North Dakota had missed its Dec. 1, 2012, commercial operation date by more than three years.
In seeking rehearing of the decision, Merricourt had argued that the commission erred by relying on MISO’s generator interconnection procedures alone and not considering language in the GIA.
FERC ultimately denied Merricourt’s request for rehearing of the termination, saying that MISO’s generator interconnection procedures don’t allow the three-year-plus commercial operation date extension the company sought, even considering “factors beyond the plain language” (ER16-471-001). The commission also said that it could not consider MISO’s study delay provision for Merricourt because it wasn’t yet active at the time the company missed its operating date.
FERC Commissioner Cheryl LaFleur issued a concurring statement, saying the investigation would provide “needed clarity to MISO and interconnection customers regarding their respective obligations going forward.” LaFleur was the sole dissent in FERC’s first decision to cancel the GIA, saying it could create barriers for other wind projects.
“I concur in the decision to deny Merricourt’s requested relief at this time. While I would have granted that relief in March 2016, it is now over a year and a half later, past even the Sept. 30, 2017, [commercial operation date] extension date sought by Merricourt. I do not see a basis to grant rehearing at this point,” LaFleur said.
EDF is still working to secure permitting from the North Dakota Public Service Commission for the project.
FERC ruled Thursday that Wisconsin Electric Power Co. overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million under MISO-ordered system support resource agreements.
The commission largely agreed with an administrative law judge’s initial decision on refunds under two SSR agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability (ER14-1242-006, et al.).
WEPCo had argued that the commission should accept its simple three-year average of historical costs from 2011 to 2013 as basis for compensation in the SSR agreements, but FERC took the judge’s view, agreeing that SSR compensation should be limited to actual costs. FERC said the plant’s compensation “must be limited to Wisconsin Electric’s going-forward costs, and the record shows that the negotiated amount was not shown to be a reasonable estimate of Wisconsin Electric’s going-forward costs. In fact, the negotiated amount greatly exceeded Wisconsin Electric’s actual going-forward costs.” The commission also rejected the company’s portrayal of the order as “retroactively implementing a new standard for SSR compensation without providing fair notice.”
Under MISO’s first SSR agreement (Feb. 1 through Oct. 14, 2014), WEPCo collected almost $37 million in fixed-cost compensation, but FERC said the utility should have only gotten about $23 million, resulting in a refund of about $14 million.
FERC said ratepayers were due an $8.6 million refund from MISO’s second SSR agreement (Oct. 15, 2014, through Jan. 31, 2015) because the agreement contained an excessive cost of capital and ineligible capital expenditures. FERC agreed with Haubner’s view that MISO didn’t adequately support its proposed 11.5% long-term cost of capital during the second SSR, saying 9.68% was more appropriate.
The refunds include a $2.4 million charge collected under the first SSR agreement to overhaul a generator turbine. FERC ruled the charge must be refunded to avoid WEPCo taking advantage of upgrade costs and then planning a return to service.
FERC gave MISO 45 days to make a refund report, brushing aside the RTO’s complaints that Haubner’s initial order did not provide clear guidance on how to calculate refunds.
The commission also agreed with the judge that WEPCo must refund a $1.4 million consulting services invoice relating to upgrades to bring the 61-year-old coal plant into compliance with EPA’s Mercury and Air Toxics Standards. But it stopped short of determining whether changed dates on the invoices constituted fraud.
Last year, Cloverland Electric Cooperative accused WEPCo of backdating the consulting contract after the plant operator learned that the second version of its SSR agreement would cover costs incurred from MATS upgrades under a revised fixed-cost component. MATS upgrades were ineligible for recovery under the previous SSR agreement.
“We make no findings at this time regarding whether Wisconsin Electric committed fraud or engaged in manipulation when a date was changed on an invoice for MATS compliance related costs, but we have referred the matter to the commission’s Office of Enforcement for further examination and inquiry as may be appropriate,” FERC said.
ERCOT’s Technical Advisory Committee has canceled its Oct. 26 meeting because of a limited number of items for consideration. The TAC will instead hold a one-hour web information session Monday to prepare for an email vote on the load distribution factor (LDF) library.
Staff will discuss the methodology behind generating and maintaining LDFs used in the congestion revenue rights (CRRs) and day-ahead market clearing activities. LDFs are developed using historical state estimator or supervisory control and data acquisition (SCADA).
ERCOT protocols require the ISO to maintain the appropriate LDF libraries for use in the day-ahead and CRR auctions. Staff updates the libraries by maintaining the existing LDF sets and generating new LDF sets when required, based on significant changes in systemwide load patterns.
TAC Vice Chair Bob Helton has yet to set a date for the email vote.
ERCOT Approves Barney Davis Gas Unit’s Retirement
ERCOT on Thursday approved the retirement of a 330-MW gas unit at the Barney Davis plant near Corpus Christi, saying it is not needed to support system reliability and can now be decommissioned.
Barney Davis Power Plant | Terry Ross/Flikr
Talen Energy announced on Sept. 27 its intention to retire the unit, triggering ERCOT’s reliability review. The unit went into service in 1974.
FERC on Thursday again ordered SPP to rewrite its rules on auction revenue rights (ARRs) and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable” (ER17-1575).
Inside SPP’s control room | SPP
In a related order, the commission also rejected SPP’s proposal to provide ARRs and LTCRs to network service customers subject to redispatch on the same basis it provides them to customers not subject to redispatch (EL16-110). The commission ordered SPP to revise its Tariff to apply to network service customers subject to redispatch the same limitation on ARR and LTCR eligibility that the RTO currently applies to point-to-point service customers subject to redispatch.
SPP had drafted the Tariff language after the commission ordered a Section 206 inquiry in September 2016 in response to complaints by Southern Co., the American Wind Energy Association and the Wind Coalition. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)
In Thursday’s orders, FERC approved SPP’s proposal to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. But the commission said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.
SPP said it wanted to ensure that customers that contracted for network service subject to redispatch — service that is “confirmed” but has not commenced — remain eligible for ARRs for the full term of their service agreement.
The commission said that proposed revisions to section 34.6 of SPP’s Tariff were unjust and unreasonable because they would allow the RTO to provide ARRs and LTCRs to network service customers subject to redispatch while necessary transmission upgrades are constructed on the same basis it provides ARRs and LTCRs to firm transmission customers not subject to redispatch.
FERC said SPP must not allocate ARRs to customers with network service subject to redispatch on the same basis as firm transmission customers not subject to redispatch, “except for those times and amounts not subject to redispatch.” LTCRs also are barred for network customers subject to redispatch.
But the commission approved grandfathering ARRs and LTCRs already granted for network service subject to redispatch under the current language of section 34.6. “Allowing customers with network service subject to redispatch to retain their already-granted ARRs for the periods of time and the amounts of service subject to redispatch obligation and to retain their already-granted LTCRs, while preventing the future allocation of ARRs and LTCRs to such service on the same basis as firm transmission customers not subject to redispatch, appropriately balances the interests of network customers with service subject to redispatch who were granted ARRs and LTCRs based on SPP’s interpretation of its Tariff with the need to prevent ARRs and LTCRs from continuing to be awarded in an unjust and unreasonable and unduly discriminatory or preferential manner,” the commission said.
In related orders, FERC also:
Clarified that its Sept. 23, 2016, order did not prevent customers from seeking relief or address any retroactive relief (ER16-1286-002, EL16-110-001);
Rejected Southern Co. unit Alabama Power’s allegation that SPP violated its Tariff by treating customers with network service subject to redispatch as eligible to receive ARRs and LTCRs (EL17-11); and
Rejected a complaint by Buffalo Dunes Wind Project asking the commission to order SPP not to allocate new ARRs or LTCRs to network service customers subject to redispatch for the 2017-2018 allocation year (EL17-69).
LITTLE ROCK, Ark. — SPP staff agreed last week to bring stakeholders a strawman proposal addressing concerns over the RTO’s transmission planning policy for energy-only resources.
Under current rules, capacity resources must go through transmission-service study (TSS) processes, while wind farms and other energy resources can bypass the TSS process and participate in the market, often creating transmission congestion. Stakeholders said the discrepancy creates uncertainty regarding future resource development as well as concerns over the fairness of cost allocation.
“It will take some time … to bring you something that will be a good strawman for you to start poking holes at,” COO Carl Monroe told the Strategic Planning Committee on Thursday, offering to deliver an update at its January meeting.
Staff will attempt to define the treatment of capacity and energy-only resources in the long-term planning process, taking into consideration reliability, public policy and economic concerns. It may also work to create incentives to generation-interconnection customers to proactively pursue upgrades needed to improve the deliverability of energy-only resources, and possibly develop a mechanism to treat all resources as firm capacity.
| SPP
Antoine Lucas, SPP’s director of transmission planning, said things changed when tax incentives led to a rush of wind energy on the RTO’s system.
“Once the markets developed, we started running into blurred lines between what’s firm and what’s non-firm capacity,” he said. “It used to be black and white. If it’s a capacity resources, it was a firm service. You issued physical curtailments, with priority going to those firm resources. That’s not the most economical way to handle resources.”
Dogwood Energy’s Rob Janssen agreed with the need for a strategic vision, saying cost-allocation problems that have cropped up in recent years are “issues of [SPP’s] success.”
“We had a goal to build a robust transmission system, and we built it out to accommodate 12 to 15 GW of wind,” he said. “We made it work, but we haven’t stopped to re-evaluate our goals and needs now, and we’re seeing the cracks in the system. We need to step back and clearly identify our goals. How much more renewables do we need? Do we want to pay for those?”
SPC Chair Mike Wise, of Golden Spread Electric Cooperative, thanked the committee for the robust discussion, saying it was “pulling the scabs off several issues.”
“Little things can be dealt with here and there, but we need to keep the overall strategic picture in mind,” he said. “Let’s not just resolve this issue, but let it take us into the next world.”
SACRAMENTO, Calif. — The rapidly changing energy landscape in the Western U.S. was the recurring theme at CAISO’s 2017 Stakeholder Symposium last week. About 1,000 attendees from the industry, its disruptors and other counterparts gathered at the Sacramento Convention Center.
This year, the ISO expanded the scope of the conference by inviting representatives from agriculture, Western oil and gas companies, and the commercial development industry to present fresh perspectives. The discussions revealed that policymakers, those responsible for grid reliability and large energy-using industries have accepted California’s legislative, regulatory and public commitment to renewables.
But there are many questions about what lies on the road ahead. California’s evolving mix of technologies and complex policymaking structure has placed much attention on a state that would boast the sixth largest economy in the world if it were an independent country.
A wide range of stakeholders, particularly those from neighboring states, are grappling with the questions of creating an RTO and a changing model for electricity delivery and consumption that is moving toward storage and distributed energy resources. Rising consumer costs and other impacts on the public were themes interwoven into the talks, and memories of the 2000-2001 Western Energy Crisis linger like ghosts among California policymakers.
Renewable Interests Discuss Storage
Participants on an Oct. 18 panel discussion of energy storage focused on the reliability and cost considerations of renewables and how energy storage can be used to better balance variable wind and solar output.
Storage is seen as the next wave in California energy development because of the large amount of photovoltaic and thermal solar coming online, panelists said. Concerns center on replacing the ramping ability of traditional generation, a role that would be suitable for responsive energy storage devices.
High-volume, bulk storage allows solar thermal plants to act like a traditional generating station, SolarReserve CEO Kevin Smith said. The California market is headed toward 50% renewables and beyond, but there are problems related to the “duck curve” and negative energy prices due to overgeneration. To reach the goal of reaching even 50% zero-carbon sources, “you are going to have to have thousands of megawatts of energy storage,” Smith said.
“Largely, renewable generation is going to have to go towards energy storage,” he said. Solar PV plus batteries can provide short-term ramping capability of up to an hour, but longer ramping capability will be needed to meet system needs.
First Solar CEO Mark Widmar said “Solar 1.0” was about attaining as much solar energy as possible, while “Solar 2.0” will be “incorporating flexibility and controllability.”
“Solar 3.0” will be about integration of storage. Other countries and states are looking to California to see how it is handling such a large influx of renewables, he said.
“Everyone is looking at California, particularly in the States,” Widmar said. “Everyone wants to know how California is going to create a sustainable market.”
The conversation around renewables often revolves around subsidies, but “maybe the market just needs to get the values right without overriding policies that skew that,” Ormat Technologies Executive Director Paul Thomsen said.
California utilities have procured a great volume of low-cost renewable compliance solar, “and now they are struggling with the best fit, and that is where we are today,” said Thomsen, a former member of the Nevada Public Utilities Commission. The market will provide the needed products, he said. “But we are not going to do it unless you give us a price signal.”
Other Sectors Weigh in
To bring new voices into the conversation, CAISO invited representatives from the New Buildings Institute (NBI), California Farm Bureau Federation (CFBF) and Western States Petroleum Association (WSPA) to discuss how they are managing the changing electric grid.
WSPA President Catherine Reheis-Boyd said that big changes are also happening rapidly in the petroleum industry: “It is not just the electricity industry; it is ours as well.”
Despite California’s moves to electrify the transportation sector, there are still 26 million internal combustion engines in the state, compared with about 200,000 to 250,000 electric vehicles. California is the third largest consumer of transportation fuels in the world, she said, and the industry produces 3 million gallons of gasoline and diesel every hour.
“We are going to be with you in this conversation for a while, at least for the foreseeable future,” Reheis-Boyd said, and “very much a part of this mix.” The magnitude and timing of electrification is extremely important, she added.
NBI CEO Ralph DiNola said the group is committed to energy efficiency research in design and construction. “It is clear that California policy is driving toward electrification, and I think the building sector is front and center.” Buildings serve as the nexus to the grid, he said, and can be designed and built as grid assets that can be managed and implemented.
A large percentage of energy is used by agricultural producers to pump water to irrigate crops and other after-harvest applications, CFBF attorney Karen Norene Mills said. Many have made investments to adjust to the existing time-of-use rate structure and the incentives matched their practices.
“Our members are struggling with what is happening with the changing landscape,” she said, particularly changing rate structures. “We are finding as we talk to them that there are some real challenges with that.” In the past they have been able to manage their systems and set up operations so they could pump off-peak, and if that is changing, their investments will not be as effective as they have been.
SACRAMENTO, Calif. — CAISO’s Board of Governors last week provided insight into a new 2030 energy “vision” for California and the region, one of many discussions at the ISO’s 2017 Stakeholder Symposium.
Governor David Olsen said the “Electricity 2030” paper examines the “the sustained, orderly retirement of gas turbines.” It also discusses the importance of states working together and collaboration among agencies and the public.
CAISO is taking comments on the document, which says a decarbonized, decentralized and more regional electric grid is driving the transition in California. The paper calls for a grid powered by two-thirds non-fossil fuel — and no nuclear — generation by 2030, and lists economic benefits from clean energy jobs and better public health.
But operational dispatch to meet locational capacity needs will be different on a decentralized grid, and “there are engineering challenges along the way” to incorporate the combined capabilities of new resources such as solar and distributed generation, Olsen said.
“It is very important for all of us to take these challenges seriously,” he said, “because nothing will stop movement toward a modernized grid faster than a blackout.”
Challenge and Opportunity
NRG Energy last week took steps to withdraw its application for a new natural gas plant in Ventura County to replace 2,000 MW of generation retiring because of the state’s once-through cooling rules. (See NRG Signals Pull-out on Proposed Puente Plant.) The Ventura/Moorpark load pocket is one example of how locational needs require massive capital investment, as costs for the three distributed energy options to replace the capacity range from $309 million to $1.1 billion.
Governor Angelina Galiteva said the shift to a new type of grid is inevitable and discussed what she called the “financial justice” of the transition. Managing renewable integration “is a challenge, but it is also an opportunity,” she said.
“We tend to agree that moving towards a much more decarbonized grid is where everybody is moving,” Galiteva said. A diversity of resources is important to optimize the system, meaning that interstate cooperation to optimize resources “becomes increasingly important.”
She added that climate change is a global issue, and developing countries will benefit from successful efforts in the U.S. “They can leapfrog technologies; they can build microgrids,” she said.
Governor Mark Ferron called for an “optimistic” attitude toward the emerging technology and new communications and called for a “forward-looking approach.”
“I kind of turn it around and say, ‘What’s the alternative?’” he said. “It is not a long-term winning strategy to try to restrict consumer choice or roll back new technology.” He also mentioned the “sea change” of integrating electric vehicles, which must become a grid asset and not a liability.
Regulators Discuss Regionalization
Montana Public Service Commission Vice Chair Travis Kavulla moderated a panel of state regulators who discussed regional differences and the effort to regionalize the Western electricity grid, which is expected to be resumed by the California State Legislature next January.
“There are a variety of cultural issues these days,” California Public Utilities Commission President Michael Picker said, adding that, aside from political differences in California, “we have a long-standing fear of FERC.” He predicted there will be some flexibility in terms of governance of an RTO.
“We have this enormous advantage of having this great diversity of resources in the West,” Picker said, which makes electricity planning easier than planning in other sectors, such as water rights.
Giving the inland West perspective, Laura Nelson, energy adviser to the Utah Public Service Commission, said: “Regionalization is inevitable, but it is a very, very slow-moving ship.” There are political differences to contend with, she noted.
“In parts of the Rocky Mountain West, we really do have a different view of our resources,” she said, but “Utah has been engaged in those conversations.” Utah has traditionally used a lot of coal for generation but also has natural gas and is on track to increase its renewable penetration to 8%.
Most panelists agreed that the trend toward regionalization will increase with time, with the large and dynamic gathering in Sacramento perhaps representing a step toward that end, if all parties can be brought into sufficient alignment while keeping electricity affordable and reliable.
FERC last week decided a seven-year-old dispute over the cost allocation for three Virginia Electric Power Co. transmission undergrounding projects, ruling the costs should be shared by all VEPCO network integration transmission service customers with loads in the state.
The commission reversed some findings from an administrative law judge’s 2016 initial decision while upholding the remainder (EL10-49-005). The commission also denied requests for rehearing of its March 2014 order that said VEPCO loads outside Virginia could not be allocated the incremental costs of the undergrounding, which was ordered by the state (EL10-49-004).
At issue was whether Old Dominion Electric Cooperative and North Carolina Electric Membership Corp. should be required to pay the additional costs of undergrounding VEPCO’s Pleasant View, DuPont Fabros and Garrisonville projects.
“The cost impact of the state’s actions is stark: Approximately 64% of the collective total costs of the projects — almost $150 million — was incurred to place the lines underground,” the commission said. “Considering the three projects together, placing the lines underground nearly tripled construction costs.”
The commission reversed Administrative Law Judge Michael Haubner’s determination on calculating the costs to be allocated to the two utilities for the projects, ruling that it should only include depreciation, return on capital investment, income taxes, accumulated deferred income taxes and property taxes.
It also reversed the judge’s determination that the methodology used to allocate the underground component of project costs should be used for future capital expenditures that don’t increase the projects’ capacity. FERC affirmed, however, its 2014 ruling on cost allocation, the ALJ’s determination that future capital expenditures that increase the projects’ capacity are beyond the scope of the proceeding and its determination of refunds, which are dated to March 17, 2010.
VEPCO must submit tariff revisions and rebill customers within 30 days, and file a refund report within 60 days.
The commission rejected challenges to its March 2014 order, which concluded that the undergrounding costs could not be collected from out-of-state loads because the additional cost was necessitated by state requirements, not reliability needs. The projects created “systemwide benefits,” so the costs should be allocated among wholesale customers rather than just retail, the commission said.
“The commission is not limited to adopting only a remedy put forward in the complaint or in briefing, as the rehearing applicants allege,” FERC said. “The commission has considerable discretion in fashioning remedies and can base that remedy on the record developed.”
The opening morning panel focused on the future of carbon policy, with several panelists offering a potential future for coal. A later panel focused on the impact of increasing intermittent generation on the grid.
EPA Deputy General Counsel David Fotouhi said Administrator Scott Pruitt has targeted three coal-related environmental rules for reconsideration: the Clean Power Plan; 2015 steam-electric effluent limitations in the Clean Water Act; and the coal-combustion residuals rule in the Resource Conservation and Recovery Act.
“Those three efforts in common share the touchstones of rule of law, cooperative federalism and process, and making sure the process is regular,” Fotouhi said.
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity, said he received no forewarning of the Department of Energy’s Sept. 29 Notice of Proposed Rulemaking calling for price supports for coal and nuclear facilities.
“We didn’t know this was going to happen until we saw it,” he said. “We’re also trying to understand this proposal like many others right now.”
He said his organization, which represents coal-fired generators, doesn’t view it as a bailout.
Marc Chupka of The Brattle Group said domestic coal production would be aided by the CPP repeal and improving mining techniques to reduce costs. However, he warned that inexpensive natural gas “will end up crushing coal.”
“There is very little that [coal-fired] generators can do in the face of $3 gas,” he said.
Benjamin Longstreth, an attorney with the Natural Resources Defense Council, disagreed with Bailey’s description of the DOE NOPR and said there was “an absolute lack of analysis to support the proposal.” He quoted Pruitt’s complaint that EPA was “picking winners and losers” in the CPP.
“I don’t agree with Pruitt’s description of the Clean Power Plan, but I think it aptly describes DOE’s proposal,” Longstreth said. “We view it as a bailout.”
The NOPR argues that retaining coal and nuclear facilities that have 90-day fuel supplies maintains grid reliability, but Longstreth said that only 0.007% of outages are due to fuel shortages.
Andrew McKeon, the executive director of the nine-state Regional Greenhouse Gas Initiative, said the past 200 years of economic prosperity has been “very closely tied” to fossil fuel use, but the two trends must “decouple” to address climate change.
“The fact is it’s a global problem and needs a global answer,” he said.
RGGI is providing one path, he said. The states involved — Delaware, Maryland, New York, Connecticut, Massachusetts, Rhode Island, Vermont, New Hampshire and Maine — have seen a 45% reduction in carbon dioxide emissions from electric generation since 2005.
“We’re doing the job twice as fast as the rest of the country,” he said.
Filling the Breach
All panelists acknowledged federalism and the importance of states making decisions on their own.
“We absolutely believe that states should step into the breach” left by Trump administration policies, Longstreth said.
New York is trying to be one of those states. In a later panel, NYISO’s Robert Pike explained New York’s analysis for implementing carbon pricing. The state is already providing renewable energy credits (RECs) and zero-emissions credits (ZECs) for nuclear facilities. The state commissioned a study by Brattle to determine if NYISO’s market could achieve the same function as its existing administrative solutions.
“It’s about a wash in costs,” Pike said. “The bills stay about the same for consumers because the carbon price would then offset the need for RECs and ZECs.”
Pike said there also are questions about how the DOE proposal would be applied. He noted a coal facility in New York that runs very infrequently.
“What does a 90-day coal pile look like at a unit that runs 1% of the time?” he asked.
Ralph Romero, of infrastructure developer Black & Veatch, said the cost of energy storage “has dropped dramatically” in recent years to between 40 and 50 cents/W depending on location. He said some analysts have predicted that $100/kWh for batteries by 2020 is “not beyond the realm of possibility.”
ICF International’s Kevin Petak joined with others in the natural gas pipeline industry who have said that securing firm pipeline capacity is complicated and not always feasible. He noted that while electricity can move at nearly the speed of light, gas moves about 30 mph, so suppliers require time and planning to ensure gas is physically available.
Pipeline companies have argued that gas-fired generators need to pay for uninterruptible pipeline deliveries if they want to ensure supplies, but Petak said generators aren’t able to recover that cost from customers.
Marketers can bundle capacity with the gas when they make contracts, he said, but “since there is no mechanism to buy the capacity and pass that cost on to the consumer, there has been reservation on the part of generators to reserve capacity.”
CROMWELL, Conn. — In Connecticut, “50 by 50” does not refer to the state’s renewable energy goals by the half-century mark, but to the projected rise in sea level: 50 centimeters by 2050.
Speaking Tuesday at the Connecticut Power & Energy Society’s Future of Energy Conference, Robert Klee, commissioner of the state’s Department of Energy and Environmental Protection (DEEP), pointed out that the Connecticut Institute for Resilience and Climate Adaptation had just briefed his staff the previous day on estimates for localized sea level rise.
“That’s a fundamental change in the way we need to plan for infrastructure along the coast,” Klee said.
But Klee touted the state’s grid-scale clean energy procurements and low- and zero-emission renewable energy credit programs — as well as the work of the Connecticut Green Bank — in helping develop a sustainable energy framework.
“You can’t drive around Connecticut anymore without seeing rooftop solar somewhere, on homes, on businesses — and that’s a real achievement,” Klee said. “And microgrids were kind of a sleeper hit. I go to microgrid conferences, and folks in other states are always amazed that we have six that are operational. Most other states are still [at the stage of] drawing boards or concept.”
Utilities Focus on Customers
Penni McLean-Conner, chief customer officer at Eversource Energy, serves on the Boston Green Ribbon Commission, which gathers business, institutional and civic leaders to seek ways to fight climate change.
She explained that her company built its newest substation in Boston’s Seaport neighborhood 23 feet above sea level, designed to handle 150 mph winds and with 80 pilings that sink into the bedrock below.
“Why? Because we’re right on the water,” she said. “We know the flooding is going to occur as we look at the climate models going out to 2050, so if we’re going to put in an asset that’s going to last another 50 years, we need to be thinking about resiliency.”
But whether adapting to climate change or using new technologies to provide a reliable energy platform, the utility of the future will be dramatically different from today in that it will be grounded in the voice of customers, McLean-Conner said.
UIL Holdings CEO Anthony Marone III agreed, saying utilities need to match offerings to customer wants.
“You can have all the technology in the world, but not every customer wants to pay for it,” Marone said. “We can’t just keep putting more gadgets on the system if there’s not a value proposition that makes sense.”
Mike Calviou, senior vice president for regulation and pricing at National Grid USA, said the utility of the future has to be more agile to meet varied needs, driven by three primary forces: decarbonization, decentralization and digitization.
“On regulatory innovation, we’re absolutely convinced that the traditional, backwards-looking, rate-based regulated utility just really doesn’t make sense in the environment we’re moving into,” Calviou said. He cited electrification of transportation as the most exciting opportunity for utilities.
Need for Market Evolution
On Energy Secretary Rick Perry’s call earlier this month for price supports for coal and nuclear plants, Dean Ellis, Dynegy senior vice president for regulatory affairs, said “I would argue there’s a big difference between a sales tax break upstream or a property tax agreement, and paying someone to produce electricity when it’s not economic to do so.” (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
Subsidies lead to more subsidies, and while production incentives incent a build-out of a particular resource type, they also affect other resources competing in the market, Ellis said.
“We definitely agreed with the [Department of Energy’s] issue that there needs to be some evolution here with the markets, but the way they went about it was absolutely wrong. It’s a solution looking for a problem,” he said. “If the DOE is going to pay us to keep 90 days of coal on-site, we’ll put coal in the cafeteria if we have to, but that’s not the best way to go about incenting the outcomes. If one of the outcomes is to increase grid reliability, then let’s have a really honest conversation about what a reliable grid looks like in the future.”
Carbon pricing looks better than subsidies to Stephen Molodetz, vice president for business development at Hydro-Québec US.
“We’re one of the few suppliers who thinks the real solution is to price carbon into the market,” Molodetz said. Getting participants in a multistate RTO like ISO-NE to agree on a pricing mechanism “seems to be the Holy Grail,” he added.
“We’re currently working hard [on carbon pricing] in New York, again a one-state ISO … and to be honest there, I still think it’s a longshot,” Molodetz said.
Katie Dykes, chair of Connecticut Public Utilities Regulatory Authority (PURA), asked industry executives what “X factors” they’ve considered in the their company planning.
“If you look at some of the recent history of the emergence of the New England markets, there’s a lot of unexpected surprise factors that have created the landscape, the shale gas revolution being one,” Dykes said. “Who would have guessed that we were going to have people fretting about how to deal with very low wholesale prices?”
Molodetz said that, in Hydro-Québec’s six partnered bids for Massachusetts’ recent clean energy procurement, he was surprised by the high level of public engagement in the siting processes. And that’s not a negative point, he added. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
“Increased environmental stakeholder involvement will lengthen the siting process, but we’ll have better projects for it,” he said. “The demand for clean energy is large and it’s growing. Québec peaks in winter, while New England peaks in summer, so matching those peaks in connected transmission is great for consumers and for grid operators.”
Molodetz said Hydro-Québec foresaw growing demand for renewables and began expanding its hydro capabilities a decade ago to enable the company to increase its cross-border transmission. The company’s largest customer is still the province of Québec, with New England a distant second and New York behind that.
Elisabeth Treseder, senior regulatory adviser at DONG Energy North America, pointed to the technological leap in capability for renewable resources. She said renewable energy providers often look to the states for leadership on procurement, but that everyone benefits from evolving technology.
“We recently decommissioned our first offshore wind project, built in 1991, which produced as much in 25 years as one of our new projects can generate in 16 days,” Treseder said.
Millstone Issue
During the conference, Commissioner Klee also addressed a question about state support for Dominion Energy’s Millstone nuclear plant.
In June, Connecticut’s General Assembly failed to pass a bill that would have allowed the 2,111-MW facility to bid into the state’s procurement process (S.B. 106). The following month Gov. Dannel Malloy issued an executive order requiring state officials to assess the plant’s economic viability and determine whether the state should provide support it financially. The governor also directed DEEP and PURA to assess the viability of all forms of renewable energy and to report their findings by Feb. 1. (See Commenters Seek Broader Response on Millstone.)
“Millstone is the largest single power plant in New England and is essential in terms of being a carbon-free resource and to the grid’s reliability,” Klee said. “The flip side is, because it is so large, our normal set of tools that we traditionally use don’t always seem to fit or may start to cause intersections with the regional grid and its market rules and components that are new and different, uncharted territory.”
The plant is also essential for the region’s winter peak problems, which are exacerbated by gas pipeline constraints, he said. The state is currently getting those gas-free and carbon-free reliability attributes for “free” in paying wholesale with no adder, Klee said.
“That valuation process is complicated and that starts getting into things that are more in the crucible of a legislative session,” Klee said. “The answer is still unknown and it gets more complicated by the week as DOE is inserting itself into this space with their [Notice of Proposed Rulemaking] on reliable or 90-day sources of baseload energy.”
Mary Sotos, deputy commissioner for energy at DEEP, encouraged participants to comment on the docket her agency has opened on Millstone. “We’re accepting comments throughout the proceeding and are required to deliver the results of that study to the legislature in the beginning of February,” she said.
Dynegy’s Ellis said the DOE proposal talked about preserving baseload energy because it is more resilient.
“Again I would argue that all resource types offer different reliability attributes,” Ellis said. “Natural gas-fired plants complement the intermittency of renewable energy better than baseload energy does. … If we’re going to pick and choose which reliability attributes we want to value, we need to take a look at all of them.”
