Page 1467 – RTO Insider

October 23, 2017

$23 Million Owed to Ratepayers in Presque Isle SSR Case

By Amanda Durish Cook

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.).

FERC SSR Presque Isle Michigan Lower Peninsula — Presque Isle power plant | *WEPCo*

Judge Michael Haubner issued an initial decision in July, saying WEPCo had overcharged ratepayers over the SSR agreements. (See Upper Peninsula Ratepayers to Seek FERC Probe of Billing Fraud.)

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.

October 23, 2017

ERCOT OKs Plant Retirement; TAC Meeting Canceled

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.

ERCOT TAC technical advisory committee — 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.

—Tom Kleckner

October 23, 2017

FERC Again Rejects SPP Rules on ARRs, LTCRs

By Rich Heidorn Jr.

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).

SPP FERC ARRs auction revenue rights — 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).

October 23, 2017

SPP to Consider Tx Planning Policy for Energy-Only Resources

By Tom Kleckner

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.

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.”

October 23, 2017

CAISO Expands Attendee Roster for Stakeholder Symposium

By Jason Fordney

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.

caiso stakeholder symposium energy storage — CAISO for the first time held a panel with other industries. | © *RTO Insider*

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.

October 23, 2017May 20, 2025

CAISO Symposium Panelists Talk Grid of the Future, Western RTO

By Jason Fordney

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.

CAISO’s Symposium 2017 attracted about 1000 attendees. | © RTO Insider

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.

Left to right: moderator John Danner, UC Berkeley-Haas & Princeton University; CAISO Board Members Richard Maullin, Chair; Angelina Galiteva; Mark Ferron; David Olsen | © RTO Insider

“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.

Left to right: David Danner, Chair, Washington UTC; Libby Jacobs, President, The Jacobs Group and former Iowa Utilities Board Chair; Michael Picker, President, California PUC; Dr. Laura Nelson, Energy Advisor, State of Utah; Travis Kavulla, Vice-Chair, Montana Public Service Commission | © RTO Insider

“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.

Left to right: Martha Guzman Aceves, Member, California PUC; Judith Schwartz, President, To the Point; Geof Syphers, CEO, Sonoma Clean Power; Dr. Felicia Federico, Executive Director, California Center for Sustainable Communities, UCLA | © RTO Insider

“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.

October 23, 2017

FERC Upholds Cost Allocation on Va. Tx Undergrounding

By Rory D. Sweeney

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.

FERC cost allocation undergrounding — FERC Headquarters | © *RTO Insider*

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.”

October 23, 2017

EBA Panelists Discuss Carbon Policy, Renewables Integration

By Rory D. Sweeney

WASHINGTON — Two panels at the Energy Bar Association’s Mid-Year Energy Forum on Tuesday offered starkly contrasting views of the future.

EBA renewables carbon emissions — EBA’s Mid-Year Energy Forum underway | © *RTO Insider*

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.

EBA REV renewables carbon emissions — Fotouhi | © *RTO Insider*

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.

Disagreement over Coal ‘Bailout’

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.”

October 20, 2017

FERC Sets 40-Year Term for Hydro Licenses

By Rich Heidorn Jr.

WASHINGTON — FERC on Thursday set a 40-year default term for hydropower licenses, a move it said will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments.

“This is quite a big deal, because we’re changing a policy we’ve had in place for several decades,” said Commissioner Cheryl LaFleur.

The commission’s policy statement (PL17-3), which will apply to original licenses and license renewals, also set conditions under which it will consider terms longer or shorter than 40 years:

If necessary to coordinate license terms for projects located within the same river basin;
When a different term is included in a “generally supported” and “comprehensive” settlement agreement that does not conflict with terms for projects in the same river basin; and
When an applicant requests a longer term based on “significant measures” voluntarily implemented during the prior license term or expected to be required for renewal. The commission has previously found that the construction of pumped storage facilities, fish passage facilities, fish hatcheries, recreation facilities, dams and powerhouses warranted longer license terms.

FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years. There is no minimum license term for original licenses.

FERC Hydropower Transmission Upgrades — | *FERC*

The commission’s policy on renewals had been to set a 30-year term when there is little or no new construction or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.

The change resulted from the commission’s November 2016 Notice of Inquiry, which followed licensees’ complaints that the commission should consider longer license terms to recognize settlement agreements, prior investments, relicensing costs and losses in generation value resulting from environmental measures. (See FERC Considers Change to Hydro License Rules.)

The NOI generated more than 40 responses, most of which supported policy changes. Some complained that license applicants lack guidance on what measures will yield longer license terms. Others said that because the commission’s policy is forward-looking, licensees delay seeking approval for capacity upgrades and environmental and recreational enhancements until they apply for a new license.

Some industry commenters complained that the license term cannot be used as a “bargaining chip” in settlement talks because the commission might reject that term; they also said the current policy penalizes well-maintained and low-impact projects that don’t require substantial new investments and thus only receive a 30-year license.

Compromise

The 40-year default represents a compromise between industry stakeholders — who generally supported a 50-year default — and environmental groups and most federal and state resource agencies, who said making the default equal to the FPA’s maximum would eliminate incentives for applicants to agree to mitigation measures.

“The resource agencies also contend that such policy would result in applicants focusing their license application study efforts on disproving project effects rather than on identifying potential mitigation measures,” the commission said.

FERC staff expects more than 300 relicensing requests through 2025, which would have required case-by-case analyses under the current rules.

The commission said the change will provide licensees and other stakeholders with more certainty while reducing administrative burdens. Case-specific assessments will only be required for licensees seeking a term longer than 40 years that is not subject to a settlement agreement.

The new rules will apply to all licenses issued following publication of the policy statement in the Federal Register. Those with pending license applications can file petitions demonstrating why the commission should grant a term longer than 40 years or settlement agreements that include longer terms. “The commission, however, will not entertain applications to amend existing licenses to extend their license terms simply on the basis of this new license term policy,” FERC said.

October 20, 2017

FERC Accepts Nondisclosure for ISO-NE Capacity Bids

By Michael Kuser

FERC on Thursday approved ISO-NE’s request not to disclose — even to non-market participants — any proprietary information from certain de-list bids for the RTO’s upcoming 12th Forward Capacity Auction.

The commission’s Oct. 19 order (ER17-2110) accepted the filing of de-list bids and granted the RTO’s request to waive a requirement that parties seeking privileged treatment for certain filings provide intervenors who execute a nondisclosure agreement access to that material.

ISO-NE in July submitted both privileged and public versions of a filing describing the permanent de-list bids and retirement de-list bids submitted for the upcoming FCA 12, to be held in February 2018 for the 2021-22 Capacity Commitment Period.

FCA ISO-NE Forward Capacity Auction — Pittsfield, Mass generator being scrapped

The RTO reported that it received one permanent delist bid and 23 retirement delist bids from six power suppliers for the upcoming FCA, covering resources located throughout all eight New England zones.

FERC staff in August issued a deficiency letter in response to ISO-NE’s filing of de-list bids, asking that the RTO also submit a form of NDA. The RTO responded two days later with an NDA as well as its waiver request.

The RTO’s auction qualification process requires owners of existing capacity resources that wish to exit their capacity supply obligation to submit delist bids specifying a price below which they do not wish to provide capacity. Such bids submitted ahead of an FCA may be “static” for a one-year exit from the capacity market; “permanent” for a permanent exit from the capacity market; or a “retirement” de-list bid for permanent exit from all ISO-NE markets, including that for energy.

Public Citizen Protest

Public Citizen filed the only protest to the request, contending that lack of access to the privileged components of the filing made it “impossible to determine” whether the permanent de-list bids and retirement de-list bids were just and reasonable.

ISO-NE countered that the privileged information includes “the [de-list] bidders’ expected cash flows, expectations regarding capacity market payments and information regarding opportunity costs … [and] critical aspects of suppliers’ likely bidding strategies … [which], in conjunction with the other confidential information, reveals the prices at which supply would be withdrawn in the auction.”

The grid operator asserted that the privileged portions of its filing contain “highly confidential, market sensitive information” that could “provide market participants who obtain it with an unfair competitive advantage” in future capacity auctions, thus negatively affecting the competitiveness of those auctions. The RTO referred to an earlier FERC order on FCA 8 in which the commission agreed that revealing resource-specific bid data would result in such significant harm to the Forward Capacity Market that it could not be provided to parties even if they signed an NDA.

Public Citizen argued that the FCA 8 order did not apply to its own request because the organization is not a market participant.

“We disagree,” the commission said in its ruling. Although the FCA 8 order referred to market participants, the commission reiterated its finding that harm could not result solely from disclosure to market participants. Rather, “the potential for harm to the FCM and to New England customers from any disclosure of this protected information could be significant.”

In the FCA 8 order, the commission noted that parties had access to a significant amount of publicly available information regarding the auction and therefore did not require ISO-NE to disclose the privileged information.

“We find that the same rationale applies here,” FERC ruled Thursday.