FERC on Thursday gave final approval to a rule updating its processes for the handling of Critical Energy Infrastructure Information (CEII), a measure to protect the grid from terrorist attacks (RM16-15, RM15-25-001).
The rule (Order 833) is intended to comply with the Fixing America’s Surface Transportation (FAST) Act. Although the bill mainly dealt with highway funding, Congress added the CEII provisions (Section 215A of the Federal Power Act) following controversy over the agency’s security procedures.
The order establishes rules for designating information as CEII; prohibits unauthorized disclosure of CEII; and sets penalties for FERC employees who knowingly and willfully make unauthorized disclosures. FERC said the final rule “largely adopts” the proposals in its June Notice of Proposed Rulemaking. (See FERC Proposes Protections on CEII.)
In response to concerns raised by the Nuclear Regulatory Commission, FERC clarified that its rule “does not limit the discretion of other federal agencies to protect sensitive information in their custody” but provides a way for agencies to consult with the commission’s CEII coordinator.
“We believe this change strikes a reasonable balance by recognizing other federal agencies’ discretion to protect their information, while adhering to the statutory framework that limits CEII designation authority to the commission and” the Department of Energy, FERC said.
The commission also said it would make a change to clarify it has delegated to the General Counsel authority to decide appeals of CEII designations.
Penalties
The rules include sanctions for unauthorized disclosures of CEII by commission staff and a requirement to refer improper disclosures by commissioners to the Energy Department’s Inspector General. FERC commissioners and staff could face dismissal and criminal prosecution for improper disclosures.
The commission said it has already instituted requirements that former employees and commissioners certify that they are not unlawfully removing records from the agency and acknowledge potential criminal penalties for doing so.
The FAST Act’s CEII provisions were both a vindication and a rebuke of former FERC Chairman Jon Wellinghoff’s controversial campaign to raise awareness of the grid’s vulnerability to sabotage.
Wellinghoff | FERC
The sanctions for unauthorized release of CEII stemmed from Wellinghoff publicly discussing a confidential FERC analysis on the grid’s vulnerability to physical attacks. But the bill also included measures to protect the grid from terrorist attacks and natural disasters, giving the secretary of energy emergency powers and creating a Strategic Transformer Reserve. (See Transportation Bill Includes Grid Security Measures.)
Sharing, NERC Information
The rule requires recipients of CEII outside of FERC to sign nondisclosure agreements. FERC said it will continue to “balance the requestor’s need for the information against the sensitivity of the information.”
“The commission has utilized this balancing approach effectively in response to Critical Energy Infrastructure Information requests for almost 15 years.”
Order 833 also implements the commission’s June order giving FERC access to NERC’s transmission availability data system, generating availability data system and protection system misoperations databases. (See FERC to Look over NERC’s Shoulders on Reliability.)
The commission said it will treat information downloaded from NERC databases as nonpublic. It will evaluate whether it should be designated as CEII in response to a request for the information or if the commission determines such information should be disclosed.
FOIA Improvement Act
In a separate order, FERC also approved a final rule implementing the requirements of the FOIA Improvement Act of 2016 (RM17-5).
The law requires federal agencies to:
Allow a minimum 90-day period for Freedom of Information Act requesters to file an administrative appeal — up from 45 days.
Include in any FOIA denial letter a notice that the requester may seek dispute resolution services from the Office of Government Information Services in the National Archives and Records Administration.
Provide requested information unless “the agency reasonably foresees that disclosure would harm an interest protected by an exemption” or “disclosure is prohibited by law.”
Make reasonable efforts to segregate and release nonexempt material by redacting protected information in documents.
Release records 25 years or older that would otherwise be subject to the deliberative process exemption.
Make information that has been requested and disclosed three times publicly accessible in an electronic format.
LA QUINTA, Calif. — The future of U.S. nuclear energy policy was the subject of a spirited Oxford-style debate at the National Association of Regulatory Utility Commissioners conference last week.
The resolution under debate: Retaining all U.S. nuclear capacity is essential to maintaining reliable, cost-effective, environmentally responsible service.
The event kicked off with an audience poll showing 48 respondents in favor of the resolution, six opposed and three neutral.
“Perfectly mirroring the population at large,” joked Ralph Cavanagh, co-director of the energy program at the Natural Resources Defense Council, which opposes construction of new nuclear plants.
Cavanagh then addressed the audience, largely consisting of state utility commissioners.
“I’m going to point out to you that you’ve been rejecting that resolution with your feet for the last 40 years,” he said. “You’ve been right to do it, and you should continue to do it.”
Retaining all nuclear capacity is just one of many options available for ensuring a low-emission, cost-effective, reliable supply of power, Cavanagh contended.
“The nuclear option should compete with other low-carbon options and not be declared the winner in advance,” he said.
Cavanagh’s opponent was Michael Shellenberger, president of the pro-nuclear, climate change advocacy group Environmental Progress, who said the loss of nuclear power impedes decarbonization by increasing the role of coal and gas-fired generation.
Checkered History
Cavanagh reviewed the history of nuclear power development in the Pacific Northwest — specifically the Washington Public Power Supply System debacle in the early 1980s. WPPSS defaulted on $2.25 billion in bonds after more than $20 billion was spent to construct plants eventually deemed unnecessary for the region.
Since U.S. nuclear output peaked in 1990, the inflation-adjusted price of electricity has only fallen — as have emissions and consumption, Cavanagh said. There are 99 reactors online today, versus 112 then.
And the reactors still in service are getting old — averaging 36 years.
“Life extension past 40 is certainly possible, but it often requires significant investment and refurbishment,” Cavanagh said. “Energy efficiency projects are meanwhile continuing, and wind and solar are putting pressure on giant baseload units as they gain market share.”
While Cavanagh didn’t advocate for full-scale nuclear retirements, he said the financial viability of U.S. nuclear plants should be examined on a case-by-case basis.
One example of a plant requiring retirement, he said, is California’s Diablo Canyon, whose relicensing would have required Pacific Gas and Electric to invest 10 cents/kWh in refurbishments.
“That almost certainly puts the plant out of the money in the zero-carbon inventory we’re trying to build,” Cavanagh said. “A plant of that cost, that size, that inflexibility … becomes a liability, not an asset, in the continuing energy transition.”
‘Pre-Emptive’ Retirements
Shellenberger countered that the “pre-emptive” retirement of nuclear plants has resulted in a decline in clean energy’s share of total global output, despite the increase in renewable resources.
In California, power plant emissions have declined less than the national average since 2000, with that effect being especially pronounced since the passage of state climate legislation in 2006, Shellenberger said.
“People don’t like nuclear very much — they’re afraid of it,” Shellenberger said. “It’s a little bit more popular than coal, but I don’t think people fear coal in the same way as nuclear. They don’t think that they’re going to have to evacuate or that they’re going to get cancer” from a coal plant.
This belief persists despite the fact that a study published by the British medical journal The Lancet showed that nuclear is the safest way to generate power, Shellenberger said. “There’s really no debate about nuclear safety among people who study public health,” he said.
Shellenberger said that nuclear’s unpopularity translates into solar getting 140 times more in subsidies than nuclear generation, according to a 2013 U.S. Energy Information Administration report. Wind gets 17 times as much.
“I used to think that maybe environmentalists were naive in thinking that you can power the world on solar or wind,” Shellenberger said. “They’re not. When you actually read the documents, every time, they are pushing fossil fuel plants instead of nuclear because [Cavanagh] and the NRDC and Sierra Club know full well that you can’t power hospitals and cities and societies on intermittent sources of power that generate electricity just 20 or 30% of the time.”
Energy Efficiency not a Resource?
Shellenberger also derided claims that energy efficiency programs can be considered a resource and that they are responsible for flat electricity consumption in California in recent decades.
“Why didn’t it go up like the rest of the country?” Shellenberger asked. “Because we lost all of our manufacturing jobs due to high electricity prices and because we don’t need as much heating and cooling.”
Shellenberger “is painting a pretty dour picture of the global power sector, and in some ways he’s right,” Cavanagh responded. “And I’m here to cheer him up.”
Cavanagh said two things can change dramatically for the sector.
“One is just how fast these small-scale, fast-acquisition resources [such as solar and wind] can grow, and how quickly they can change a picture — national and international — that looks relatively dour right now,” Cavanagh said. “And the other is the contribution of energy efficiency, which [Shellenberger] says is not a resource.”
On the subject of subsidies, Cavanagh said, “When a nuclear power proponent complains about renewable energy subsidies, I have to say I feel like I’m being lectured on temperance from a barstool.”
Shellenberger countered that nuclear power received about 10 years of subsidies. On the question of speed of scalability, he pointed to a recent report appearing in the journal Science that showed that the fastest increases in the growth of carbon-free electricity have occurred during the scale-up of national nuclear programs.
“When you take [a nuclear power plant] offline, you’re giving a lease on life, not just to natural gas, but to coal,” Shellenberger said.
The debate concluded with a second audience poll on the original resolution. The result this time: 66 in favor and 22 against — a 75% majority for the pro-nuclear side, down from 84% at the beginning of the session.
Based on Oxford rules, Cavanagh could claim a debate win. But the argument over nuclear energy’s role will undoubtedly persist.
LA QUINTA, Calif. — Hundreds of state regulators, utility officials and other stakeholders traveled to the California desert last week for the 128th Annual Meeting of the National Association of Regulatory Utility Commissioners.
Among the topics were new generation technologies, the impact of the 2016 elections and the priorities for incoming NARUC President Robert Powelson. NARUC also approved its first manual on ratemaking for distributed energy resources and resolutions defending its authority against federal intrusion.
Here’s some of what we heard.
Rooftop vs. Utility-Scale Solar Battles not a Concern for Industry
At a breakfast presentation sponsored by the Solar Energy Industries Association, Georgia Public Service Commissioner Tim Echols asked about what he called “infighting” between the utility-scale and rooftop solar proponents. “They’re splintering organizations and it’s almost like if your state can’t do distributed generation, you’re not doing true solar,” Echols said. “Is this splintering within the solar community … helpful to the cause?”
“I think it’s a sign of a maturing industry. Everybody’s in competition with everyone else,” responded California Public Utilities Commissioner Mike Florio, who said he had seen the price of grid-scale solar drop from 15 cents/kWh to as low 4 cents since he joined the commission in 2011.
Former Maryland Public Service Commissioner Anne Hoskins, now chief policy officer for rooftop installer Sunrun, saw the two as meeting different needs rather than being in direct competition.
Rooftop solar is “taking advantage of the built infrastructure,” she said. “You’re not having to take up other land. You’re not having to deal with wetlands or any of those other kinds of challenges.”
Rooftop solar also is attractive to those wanting to power electric vehicles or to have a backup power source other than a gas generator.
Community solar, on the other hand, provides an option for renters and others for whom rooftop solar isn’t an option.
“I don’t see it as a competitor to [rooftop] solar at all. I see it as a way to expand access to solar,” she said. “There’s really room for all of it. We have a tremendous climate challenge.”
Former Hawaii Public Utilities Commissioner Mike Champley said it is “a huge debate” in his island state, where he said DERs collectively represent the biggest source of generation.
“The way it’s pitched is utility-scale is solar of the 19th century and rooftop is the solar of the 21st century. There’s some people who believe the future is a distributed-centric world,” he said. “My opinion [based on] my 40 years in this business is that portfolios [of various resource types] will be the appropriate thing.”
M&A: Is Bigger Better?
A session on utility mergers touched on recent trends and looked into the future.
Dan Ford, managing director of Barclays, said the impact of the 2016 presidential election was unclear. Changes in tax policy, he said, “could change the economics of combinations pretty dramatically.”
“We don’t know how much of the campaign rhetoric turns into actual policy,” he said, adding that the biggest change for utilities thus far has been the rising cost of capital. “The yield curve has noticeably steepened since the election,” signaling expectations of higher inflation.
“I think that in all likelihood the election will have the effect of migrating us back from what we’ve seen the last several years — which is acquisitions for cash, for growth by large companies and small companies — to more of a merger of equals regime.”
Those mergers are designed to reduce costs to “create headroom” for more money to invest.
“I think there is a great deal of efficiency that can still be wrung out of this industry, as capital intensive as they are.”
Connecticut Consumer Counsel Elin Katz said she didn’t expect mergers slowing down absent a “dramatic change in tax policy or major shift in the market.”
Richard McMahon Jr., vice president of energy supply and finance for the Edison Electric Institute, agreed. “There’s still 44 investor-owned utilities … and hundreds and hundreds of munis and co-ops. The concentration isn’t an issue like it might be in some other industries.”
As for whether mergers are good for consumers, Katz said it depends.
“It really depends where you start and it depends where you end up. The devil you know is your own local utility. … If you start with a company that’s financially weak or in a disadvantageous position and perhaps remote management has not gotten along so great with the regulators or with the legislators or you’ve had some a checkered history with respect to storm response and people are fed up with that then, yeah, I think there’s potential for benefits. But on the flip side we always worry about the loss of local control.”
Ford said the typical utility merger in the last two decades has outperformed expectations “both in terms of actual achieved efficiencies on behalf of customers — and because of regulation that gets recaptured in the future.”
“So you shouldn’t think a merger as the last time you get a bite at the apple from a regulatory standpoint. You always get a bite at the apple.”
“You may get another bite at the apple, but it’s still the same apple,” responded Katz. “You can’t unwind a merger. Obviously you’re going to have to live with it for a long time.”
D.C. Public Service Commissioner Willie Phillips asked questions as moderator. But he was reticent when asked about the on-again, off-again Exelon-Pepco merger, which consumed D.C. regulators for months. Phillips said he couldn’t say much because there are still challenges pending to the deal. (See Exelon Closes Pepco Merger Following OK from DC PSC.)
“There was lots of zigs and zags,” he said. “And I’m not going to go farther than that.”
Powelson, a Pennsylvania Public Utility Commissioner, was elected to replace Montana’s Travis Kavulla as NARUC president.
Connecticut Public Utility Regulatory Authority Commissioner John Betkoski III moved up to first vice president and Commissioner Ellen Nowak, chair of the Wisconsin Public Service Commission, was elected second vice president. Confirmed to the board of directors were Margaret E. Curran of Rhode Island, Mark Vannoy of Maine and Nick Wagner of Iowa.
In his remarks to the conference, Powelson said his one-year term would focus on “infrastructure, innovation and investment.”
He lamented that the U.S. spends less than 2% of GDP on the electric grid and other “modern day infrastructure investment,” far below the spending of India and China.
“We’re not going to cut it spending less than 2%,” he said. “And I think that we as an association have a key role to play in driving that agenda.”
On the subject of innovation, he noted that one of the resolutions approved at the meeting was one encouraging state regulators to consider whether utilities should be able to earn a rate of return on cloud computing services and pay for them out of their capital budgets.
The resolution says that although commercial cloud computing services can provide increased reliability, flexibility and security, utilities may be unwilling to use them because they don’t earn a rate of return on software-as-a-service expenses. In contrast, they can capitalize spending on hardware and “on-premise” software.
Members also approved resolutions asserting state authority over DERs and calling for an extension of the nuclear production tax credit and changes in the Public Utility Regulatory Policies Act’s mandatory purchase rules.
Nuclear Production Tax Credit
NARUC called for an extension of the federal income tax credit of 1.8 cents/kWh for power produced by advanced nuclear reactors. The credit, included in the Energy Policy Act of 2005, is limited to the first 6,000 MW of capacity placed in service on or before Dec. 31, 2020. Only four advanced nuclear reactors totaling 4,400 MW currently under construction — Georgia Power’s Vogtle Units 3 and 4 and South Carolina Electric & Gas’ V.C. Summer Plant Units 2 and 3 — are expected to be completed in time to qualify.
The resolution urges Congress to pass legislation extending the in-service date for the credits and to expand the eligibility to public power entities and consumer-owned electric cooperatives that own shares of advanced nuclear units but do not pay federal income taxes.
NARUC approved a resolution asserting that state commissions should have control over decisions on mandatory purchases and avoided cost determinations under PURPA and that the law’s goal of promoting qualifying facility development “must be balanced with the states’ interest in just and reasonable rates.”
Because of the growth in renewable generation, NARUC said the mandatory purchase obligation has created unintended consequences, including generation not needed to serve loads, high-cost long-term fixed-price contracts and planning challenges because of the “unexpected and unpredictable addition” of PURPA projects.
“A number of state regulatory commissions have recently been devoting an inordinate amount of time attempting to discern the intent and assess the impact of PURPA, the meaning of FERC regulations and the parameters of state discretion,” the resolution says.
NARUC also defended its jurisdiction over DERs, saying it was concerned over the U.S. Federal Trade Commission’s June 21 workshop concerning electric utilities and anti-consumer and anti-competitive activities.
NARUC said it “opposes any attempt by the FTC, or any other federal agencies, to infringe on areas that are exclusively under state regulatory authority, because this could produce unintended consequences and would disrupt a carefully balanced set of technologies, markets and interests.”
Although FTC “acknowledged explicitly” state jurisdiction, NARUC said the commission also was critical of state rate designs, saying rate reform “may be a disguised effort by utilities to make solar [distributed generation] less desirable relative to the status quo, thereby minimizing solar DG as a competitive threat.”
NARUC called for a “partnership and dialogue” with the commission, saying the agency “can contribute meaningfully in enforcement against the business practices of non-regulated power providers, DER marketers and utilities that do not protect the interests of customers.”
DER Manual
Completing a yearlong project that attracted some controversy, NARUC released a manual intended to help state commissions in designing rates and compensation policies for DERs: “Distributed Energy Resources Rate Design and Compensation.”
NARUC’s effort led to a dust-up with SEIA, which sent the organization a letter in August raising questions about the transparency of NARUC’s effort. In response, NARUC assured the solar group that it would publish all of the comments it received. It reviewed more than 70 comments from stakeholder groups.
Sean Gallagher, vice president of state affairs for SEIA, pronounced the group happy with the final result, saying the manual “was significantly improved due to their willingness to be open to input from stakeholders.”
“I would have loved to have had this manual” when the Nevada Public Utilities Commission was updating its rules, said Anne-Marie Cuneo, the PUC’s director of regulatory operations, who participated in a briefing on it.
“Everyone can find something in it to dislike,” Kavulla joked. “Which means we must have done our job.”
ERCOT established a record for all grid operators last week when it registered a new peak for wind generation with 14,122 MW.
Thursday’s mark broke its previous high of 14,023 MW, set in February, and gave ERCOT another mark in its good-natured battle with SPP to see which grid operator produces the most wind generation.
For the time being, SPP still holds the wind-penetration mark of 49.17%, but ERCOT in October surpassed 17,000 MW of installed wind-generation capacity. Texas has another 11,273 MW of wind energy in its interconnection queue.
“Texas has done an incredible job integrating renewables,” native Texan and NYISO CEO Brad Jones said during the Texas Renewable Energy Industries Alliance’s recent GridNEXT conference. “No matter SPP’s brag, Texas still owns the record for the most renewables in the country.”
Texas Wind Farm | Target
ERCOT also set a new peak load record for October when total demand hit 59,848 MW on October 5. Wind accounted for 17% of the ISO’s energy needs in October.
Natural gas accounted for 36.7% of ERCOT’s energy production during the month, coal 35.7% and nuclear 10.3%, according to the ISO’s latest demand and energy report.
For its part, SPP exceeded 11,000 MW of wind generation for the first time Thursday, setting a new record of 11,305 MW and tying its wind-penetration mark of 49.17%. The new record came at 6:13 p.m.
| SPP
The mark broke the previous wind peak of 10,989 MW, set in April, and was the fifth such record set in 2016.
The RTO’s generation interconnection queue includes about 22,000 MW of additional wind.
MISO has FERC’s permission to end a system support resource agreement in Michigan’s Upper Peninsula effective Nov. 26 (ER16-2528).
The order allows a transmission reconfiguration plan from American Transmission Co. to take the place of the White Pine Electric Power SSR agreement, which has cost local ratepayers about $6 million per year.
FERC’s decision cuts off revenue to the utility’s 20-MW coal-fired unit, which had been operating under the SSR designation since mid-2014. Under ATC’s plan, the transmission network in the western Upper Peninsula will be split into two separate load pockets. (See MISO Will Use ATC Plan to End Upper Peninsula SSR.) The dual, radial-fed configuration would only be used during planned maintenance on the area’s two 138-kV transmission lines.
Map shows ATC’s transmission system in the western Upper Peninsula. Orange circles indicate how the load pocket will be split into two radially-fed areas. White Pine Unit 1’s location circled in blue. | MISO
Some MISO stakeholders argue that the plan introduces an increased risk of consequential load loss following a subsequent contingency, but the RTO maintains the risk is within NERC standards.
The Michigan Public Service Commission noted that while White Pine Unit 1 was called on only a “handful” times during its SSR agreement, it was entitled to receive about $4.7 million in 2014-2015, $7.3 million in 2015-2016 and $6.6 million in 2016-2017. The PSC also asked FERC to take the high poverty rates of Upper Peninsula ratepayers into consideration.
In a protest, White Pine accused MISO of a “hurried” reliability analysis that did not adequately study the possible “adverse reliability impacts” of severing the SSR agreement. The utility argued that Unit 1’s retirement would lead to more load curtailment, overloads in summer peak conditions and risk of voltage collapse. White Pine also said the SSR termination was not properly discussed in stakeholder meetings.
FERC rejected White Pine’s protest. It said it found “MISO appropriately studied and determined that the ATC transmission reconfiguration plan is a feasible alternative to the second revised White Pine SSR agreement and adequately involved stakeholders in that determination.”
BOSTON — Quebec hydropower already supplies about 12% of New England’s electricity and its exports are expected to grow considerably over the next decade. So there was plenty to talk about at the 24th U.S./Canada Energy Trade & Technology Conference last week.
The Massachusetts Energy Diversity Law, passed over the summer, commits the state to acquire 9,450 GWh of new large-scale hydropower contracts annually by 2027 — a 73% increase from the nearly 13,000 GWh that ISO-NE imported from Quebec in 2015.
“For the first time, the Commonwealth of Massachusetts is designating large-scale hydropower, like the kind we generate in Quebec, as a source of clean energy that can help meet the objectives of the Global Warming Solutions Act,” Hydro-Quebec CEO Eric Martel said during a keynote speech. That law commits Massachusetts to a 25% reduction in greenhouse gases by 2020.
Matt Beaton, Massachusetts’ Secretary of Energy and Environmental Affairs, said expanded imports will both reduce emissions and help maintain system reliability.
“We have always looked kindly on the import of hydroelectricity and recognize that it is one of the few resources that help us reach all three of the targets we are trying to accomplish: It’s a reliable resource, it’s affordable and it’s one that helps us meet our climate goals,” he said.
Entergy’s decision to close the 680-MW Pilgrim nuclear plant in 2019 is a major setback for the state’s climate goals, said David O’Connor, senior vice president for energy and clean technologies at ML Strategies.
“The Pilgrim nuclear plant by itself produces 85% of the [carbon-free] energy consumed in Massachusetts,” O’Connor said. “When it goes away, there’s going to be a dramatic alteration of the carbon profile in the state.”
Ed Krapels, CEO of transmission developer Anbaric, is looking at what he called the Greater Northeast — including New England, New York, Quebec and Ontario — where a massive buildout of renewable generation is needed to achieve climate reduction targets.
“For us, we look at this as a 5,000- to 10,000-MW transition, so there’s room in that for many different things. Distributed energy will be a large part of that, as well as batteries, solar microgrids, all of that will have a big impact. But we still have bulk power needs,” he said.
Anbaric is proposing stand-alone transmission development, as well as collaborations with wind generators to pair with hydropower in cross-border projects throughout New York and New England.
Marcy Reed, president of National Grid Massachusetts, joked that although she heads an electric utility, she spends most of her time talking about natural gas.
“You talk about a balanced approach. We need pretty much everything. We need renewables, we need efficiency, energy storage, natural gas; we need a full platter of solutions to get us where we ultimately need to be,” she said.
Natural gas analyst Richard Levitan said the failure of pipeline projects to overcome litigation and community opposition leaves the system vulnerable in the winter, when gas generation must compete with gas heating for fuel supplies.
ISO-NE has incentivized generators to provide dual-fuel power sources, but that fails to solve the underlying problems, he said.
“The Winter Reliability Program is chipping away at a fundamental problem of the region’s great reliance and growing reliance on natural gas,” he said. “Is it enough? Well, this winter it probably is enough, if ISO-NE’s 50-50 load forecast materializes. And that the pipeline and storage infrastructure linking us to the Marcellus region is fully available and nothing bends or breaks.”
Over the longer term, the addition of solar and wind resources presents serious challenges that are only now starting to be addressed, said Peter Rothstein, president of the Northeast Clean Energy Council.
Rothstein said the modernized grid that’s needed to enable renewable integration and two-way power flows must join the conversation along with cleaner generation.
“We can deploy a great amount of solar resources over the next five or 10 or 15 years, but we’re going to hit a wall and it’s going to become inefficient and not at all cost-effective, so we have to modernize the grid,” Rothstein added.
Election Talk
The election of Donald Trump as president creates much uncertainty, many speakers said. But they agreed that clean energy will likely lose federal support and climate issues will be confronting a hostile federal administration.
“If you look at the election, it’s easy to get discouraged because we need a lot of policy support, and it’s not going to be there,” said Joshua Paradise of Current, GE’s LED, solar, energy storage and electric vehicle business. “But as a skeptic [of conventional wisdom] as I think of what’s happened, this train [of strong support from the states and the public] has left the station. … We’re already at the tipping point.”
Jon Norman, vice president of business development for Quebec-based Brookfield Renewable, was a bit more circumspect. He said he feared climate change deniers becoming more entrenched in government under Trump.
“It’s unquestionable that the need for state action is far more urgent than it was [before the election]. And that need for action has to happen and I don’t think we can delay it until we have all the right answers [on technology]. But I’m optimistic, especially in New England because you have states with very aggressive targets and they’re taking actions to implement them.”
What appears likely is that the federal governments of the U.S. and Canada will take divergent paths on global climate initiatives. Former Prime Minister Stephen Harper was aligned with fossil fuel interests and was hostile to international climate accords, said Monica Gattinger, director of the Institute for Science, Society and Policy at the University of Ottawa.
Prime Minister Justin Trudeau “has taken a very balanced approach to energy. On fossil fuels, [Trudeau’s Liberal Party] is quietly supportive. They’re visibly supportive of clean renewable energy,” she said. “When it comes to the environment, from a bragging perspective, they wanted everyone to know Canada was back in Paris last year [for the 21st Conference of Parties’ climate agreement], and with a commitment to moving on a carbon tax.”
FERC on Thursday approved a rate settlement for a transmission project that may never happen.
The agreement settled a dispute over how much profit LS Power’s Northeast Transmission Development should receive for building transmission infrastructure across the Delaware River to address stability issues at New Jersey’s Artificial Island (ER16-453).
It was brokered between Northeast Transmission and several objectors in the case: Delaware Public Service Commission, American Municipal Power, Old Dominion Electric Cooperative and Delaware Municipal Electric Corporation.
However, the decision may be moot. Following complaints over cost allocation and a near doubling of the estimated cost, PJM suspended the project — PJM’s first Order 1000 competitive solicitation — pending a “comprehensive” staff analysis to be completed by February. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
The settlement includes a base return on equity, an equity cap and a three-year moratorium on any involved party petitioning for modifications to the deal:
Northeast Transmission’s base ROE will be 9.85%, retroactive to February 1.
A hypothetical capital structure of 50% equity/50% debt approved in an order issued by FERC in April will remain effective until PJM assumes control of the project.
The equity component used by Northeast Transmission to calculate its weighted average cost of capital will be the lesser of 54.75% and the actual ratio of equity as a percentage of total capital.
The moratorium is in effect until three years after PJM takes control of the project. It includes prohibitions on making Federal Power Act Section 205 or 206 filings or supporting others’ filings. Northeast Transmission also is barred from petitioning to include construction work in progress in its rate base.
Artificial Island is the site of three nuclear power plants owned by Public Service Enterprise Group. The proposed project would address stability issues that prevent PSEG’s Hope Creek and Salem 1 and 2 units from maximum generation. It would include a 230-kV line from the existing Salem substation in Lower Alloways Creek on the New Jersey side to a newly constructed Silver Run 230-kV substation in Delaware. The Delaware substation would connect the project with the existing Red Lion – Cartanza and Red Lion – Cedar Creek 230-kV transmission lines.
VALLEY FORGE, Pa. — PJM’s efforts to hammer through manual revisions ahead of FERC action on fuel-cost policies were stymied at last week’s Markets and Reliability Committee meeting.
Despite PJM’s desire to implement the changes as soon as FERC approves PJM’s hourly offers compliance filing, stakeholders shrugged off the urgency and insisted on perfecting the language.
The revisions to Manual 15 were approved by the Market Implementation Committee on Nov. 2 following months of debate. At the MRC meeting, stakeholders said there are still unresolved issues with how the changes are worded. Of particular concern at last week’s meeting was the requirement that generators “immediately” replace a revoked policy. (See “Fuel-Cost Policy Revisions Approved,” PJM Market Implementation Committee Briefs.)
“It makes it sound like we need to be at the ready every day” with a new policy, said Steve Lieberman of Old Dominion Electric Cooperative. “I think everyone here would agree it’s a bit of a challenge to get one approved initially.”
PJM’s Jeff Schmidt responded that the intent is that generators should already have a policy approved, but stakeholders were not swayed.
“We do need to make some change to address that ‘immediately’ business,” American Municipal Power’s Ed Tatum said. “When things get going, people refer to the governing language.”
Catherine Tyler Mooney of Monitoring Analytics, PJM’s Independent Market Monitor, reiterated concerns that “confusing language” is creating “a problematic process.”
“The proposed M15 language creates a PJM fuel-cost policy review that overlaps the timing and scope of the Market Monitor’s independent review. There’s a potential where we have a PJM-approved version of a fuel policy that can’t be accepted by the Market Monitor,” she said.
Schmidt said PJM continues to bring the revisions forward because it will have 45 days after FERC’s approval to implement the rules, which might not be enough time to secure all the committee endorsements. Several stakeholders acknowledged this concern, including Bob O’Connell of PPGI Fund A/B Development, who said continuing to put off the vote might put stakeholders in the position of having to make changes within an unattainable deadline.
PJM’s Suzanne Daugherty, who chairs the MRC, said the committee can convene over the phone for a single-issue conference call if it becomes necessary to send an advisory vote to the board prior to the January MRC. The revisions will be returned to December’s Market Implementation Committee meeting to address the wording issues.
Citigroup Wins Change on Capacity Resales
Citigroup Energy’s Barry Trayers sparred with PJM’s Stu Bresler over Trayers’ proposed revisions to Manual 18, but Trayers’ changes were endorsed without PJM’s additions.
Trayers’ manual change eliminates PJM rules for how “early replacement” of capacity obligations can be made. He noted that the rules’ deadline of Nov. 30 for performing replacement transactions isn’t supported by language in the Tariff.
Bresler, PJM’s senior vice president of operations and markets, had proposed language changes that Trayers had originally accepted as a “friendly amendment.” However, he rescinded that approval at the MRC, saying he had received advice that the amendment strayed from his intent. That meant Bresler’s amendment would only be considered if Trayers’ original proposal failed.
At issue is how quickly capacity sold during the Base Residual Auction can be replaced through Incremental Auctions. Trayers said the change allows him to reconcile his books much sooner. Bresler said it widens a loophole that allows participants to arbitrage price differences between the Base and Incremental Auctions by reselling the replaced capacity.
Both Bresler and the Independent Market Monitor said they preferred the status quo over Trayers’ motion. Because Trayers’ proposal was approved, PJM’s amendment was never considered.
DASR Approved Despite Slight Change
The proposed day-ahead scheduling reserve for 2017 was approved despite being “slightly different” than what PJM outlined to the Operating Committee earlier this month, said PJM’s Tom Hauske. The change came because not all performance information had been collected at the time. The approved figure was 0.04 percentage points less than originally proposed, from 5.52% to 5.48%.
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Manual 35 Retired; PJM Promises Further Consolidation of Definitions
Members endorsed retiring Manual 35: Definitions and Acronyms but only after confirming that a document consolidating all definitions will be developed.
PJM said Manual 35 hasn’t been properly maintained in years, raising the risk of legal disputes over members using incorrect and outdated definitions. Going forward, the legal definitions will be maintained in a single section within the Tariff, Operating Agreement and Reliability Assurance Agreement.
Only informal definitions — “layman’s terms,” as PJM’s Janell Fabiano called them — will be included in the glossary on PJM’s website. Staff deleted more than 400 outdated terms from the glossary and added an expanded disclaimer noting that it is for reference, and that the formal definitions in the governing documents are legally binding.
Fabiano said RTO officials will discuss creating a consolidated legal definitions document at a Dec. 2 meeting of the Governing Document Enhancement & Clarification Subcommittee.
Venue for DER Discussions to Change
PJM’s Dave Anders said the special MRC meetings on distributed energy resources have gone into stasis while two key issues get hashed out elsewhere.
The Planning Committee is continuing work begun in August on an alternate queue process and the allocation of upgrade costs less than $5 million while discussions on potential market rule changes will be conducted in special sessions of the MIC.
The venue of future discussions will be determined by how resources plan to connect. “You have to make a choice: You have to be in front of the meter or behind it,” Anders said.
Resources that plan to be in front of the meter will follow the process being developed by the PC to secure capacity injection rights. Behind-the-meter resources, which can both reduce load and inject power, will be governed by the process developed through the MIC. The special MRC sessions will reconvene as necessary once those routes are finalized.
MRC Endorses Manual Changes
Members also unanimously approved the following manual changes:
Manual 3: Transmission Operations. Revisions, the result of a periodic review, include updating voltage control at nuclear stations, certain special protection scheme references and the BC/PEPCO operating procedure.
Manual 18B: Energy Efficiency Measurement & Verification. Revisions, the result of a periodic review, include updates to incorporate the implementation of Capacity Performance.
Manual 28: Operating Agreement Accounting. Revisions made to align with recent Manual 1 revisions. It clarifies metering language and defines a “fully metered EDC.”
Members Committee
Guerry Applauded at Final MC
In her final act as the chair of the Members Committee, EnerNOC’s Katie Guerry gave an emotional farewell, saying the two-year position “has been a wonderful thing that happened in my life.”
PJM CEO Andy Ott sat between her and Susan Bruce of the PJM Industrial Customer Coalition, who will transition from vice chair to chair in January. “I’m flanked by two very accomplished women,” Ott said, before reviewing the major issues Guerry presided over during her time in office. “Through all of that, I think you’ve done a fantastic job,” he said.
Ott presented her with a ceremonial gavel, and they shared a laugh about the inscription. He explained that it hadn’t been updated yet and still read “chairman’s gavel” as it did when she first took the position.
Guerry wasn’t fazed. “I only wanted the girls’ version if it was encrusted with diamonds,” she explained.
Elections
The Members Committee elected the designated slate of candidates to fill expired and vacated positions. O’Connell quickly cut off any potential for additional nominations by making a motion, which was seconded by Dan Griffiths of the Consumer Advocates of PJM States. The candidates were approved by acclamation.
Elected were:
American Municipal Power’s Chris Norton, Dynegy’s Jason Cox and Calpine’s David “Scarp” Scarpignato to the Finance Committee.
Lieberman, Bruce, Guerry, Gabel Associates’ Michael Borgatti and Public Service Enterprise Group’s Jodi Moskowitz as sector whips.
Borgatti as the Members Committee’s new vice chair.
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Preview of Security Committee Receives Tepid Response
PJM Chief Information Officer Tom O’Brien introduced plans for a new, non-decisional Security and Resiliency Committee. O’Brien said members of the public and the media will be barred from the sessions so that members can openly discuss sensitive security issues and potential solutions. External government and private sector attendees will be allowed by invitation only.
“It’s cutting across more than control systems,” O’Brien said. “It’s cutting into the Internet of Things.”
Jason Barker of Exelon said it’s an initiative his company sees as “a duplicative effort” it “struggles to support” because it “taxes limited resources that could be addressing concerns instead of attending another meeting.”
“The objectives are very broad. We struggle with how they’d be roped into something that is administratively efficient for us to staff and attend,” he said. “We don’t see where the topics you’ve just described are PJM-specific. … We see this as another place where we have to drag the same people who are having the same discussions elsewhere.”
To be truly non-decisional, he said, the charter’s key work activities would need to be modified to eliminate creating subcommittees or delegating assignments.
O’Brien said the point is “very well taken” about staffing. “That’s kind of how we got to where we are. The key is to have discipline around who staffs what,” he said.
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee on Thursday rejected two proposals members said threatened the Capacity Performance construct, but it approved two others that would investigate potential changes in the rules.
A proposal to change rules on penalties for underperformance failed in a sector-weighted vote with 47.6% support, well below the two-thirds threshold. Nearly three-quarters of the Generation Owners sector supported the proposal, but other sectors were split or strongly opposed.
The proposal would have changed the nonperformance assessment charge rate and ownership requirements for making retroactive replacement transactions. It also would have introduced a way to offset underperformance with overperformance and a new monthly stop-loss provision while changing the annual stop-loss rule.
Reduced Incentives
Opponents said the changes reduced incentives for generators to meet their commitments.
Because prices in PJM’s Base Residual Auction are much higher than those for incremental auctions in which the RTO sells excess capacity, load has recognized little savings for the reliability benefits it has forgone. | PJM
“Every one of these proposals is designed to undermine those incentives,” said Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor.
PJM’s Stu Bresler also voiced concerns with the proposal and said the RTO couldn’t support it.
A proposal to extend Base Capacity another year through the 2020/21 Base Residual Auction in May fared better but also fell short in a sector-weighted vote, receiving 58.6% in favor.
Direct Energy’s Jeff Whitehead presented the proposal as a stop-gap to allow seasonal resources to continue participating in the market pending a FERC ruling on PJM’s plan to make it easier for them to qualify as CP.
The proposal had near-unanimous support from the Electric Distributor and End Use Customer sectors but was opposed by most Generation Owners and Transmission Owners.
PJM Filing
PJM filed its plan with FERC on Wednesday, requesting a Jan. 19 implementation date to ensure the new rules are in effect for the BRA on May 10 (ER17-367). It would make it easier for summer- and winter-only resources to aggregate for the year-round deliverability required under CP. (See No End in Sight for PJM Capacity Market Changes.)
Stakeholders said extending Base Capacity would impede the full implementation of CP. Both PJM and the Monitor rejected Whitehead’s proposal, but they said they were open to further discussion on how to incorporate seasonal resources.
Brock Ondayko of American Electric Power said those who supported the Base Capacity proposal but not the proposal to relax underperformance penalties were being “disingenuous” and called the extension “poor irony” because it creates competition to CP offers.
“There’s no such thing as Base Capacity in the year 2021, so this is essentially a new product that will take away from the existing products,” he said.
Exelon’s Jason Barker opposed the proposal, saying his company is “eager” to see if CP reforms are effective.
Talking Past Each Other
Dan Griffiths of the Consumer Advocates of the PJM States immediately responded, saying stakeholders “continue to talk past each other” based on differing perspectives on CP. He portrayed his ongoing back-and-forth with Barker on the topic as one holding a sign that read “A” and the other holding one that says “Not A.”
“I don’t see how this reduces the incentives for performance,” he said.
Following his proposal’s failure, Whitehead retained the floor to propose a problem statement and issue charge on how PJM should offer back excess capacity purchases in the incremental auctions that balance out supply and demand in the run up to a delivery year.
“If you didn’t like that last one, maybe you’ll like this one,” he said.
He was right: Stakeholders eventually approved them by acclamation with objection only from Calpine’s David “Scarp” Scarpignato.
Scarp initially appeared supportive, but he backed off when stakeholders demanded additional language in the issue charge that limited its scope to the auction’s structure and PJM’s actions only when it is a capacity seller.
Later in the meeting, stakeholders also approved by acclamation a problem statement and issue charge on investigating adequacy and capacity requirements for winter-season resources. The proposal passed despite 10 objections and four abstentions. It was presented by economist James Wilson on behalf of the Maryland Office of People’s Counsel, the New Jersey Division of Rate Counsel and the Delaware Division of the Public Advocate.
In a rulemaking reflecting both reliability concerns and the technological advances of renewable generators, FERC on Thursday proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA) to require all newly interconnecting facilities to install and enable primary frequency response capability (RM16-6).
The commission said the existing pro forma LGIA may be unduly discriminatory because its primary frequency response requirements apply only to synchronous generating facilities “and do not account for recent technological advancements that have enabled new non-synchronous generating facilities to now have primary frequency response capabilities.”
The proposed changes will “ensure fair and consistent treatment for all types of generating facilities, help balancing authorities meet their frequency response obligations pursuant to NERC reliability standard BAL-003-1.1 and help improve reliability during system restoration and islanding situations,” the commission said.
FERC said the rules would not apply to nuclear generators and would not impose “headroom” requirements for new generators. The commission said it would not require that generators be paid for complying with the frequency response requirement.
Declining Frequency Response
Acknowledging concerns over declining frequency response performance, the commission asked for comment on whether the Notice of Proposed Rulemaking is sufficient “to ensure adequate levels of primary frequency response, or whether additional reforms are needed.”
“While the three [contiguous] U.S. interconnections currently exhibit adequate frequency response performance above their interconnection frequency response obligations, there has been a significant decline in the frequency response performance of the Western and Eastern Interconnections,” FERC said.
The commission noted declining frequency response was identified as early as a 1991 study by NERC and the Electric Power Research Institute.
It also cited a 2010 NERC survey of generator owners and operators that found that only 30% of generators in the Eastern Interconnection provided primary frequency response and that only 10% provided sustained primary frequency response. “This suggests that many generators within the interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response,” the commission said.
“The commission’s pro forma generator interconnection agreements and procedures were developed at a time when traditional synchronous generating facilities with standard governor controls and large rotational inertia were the predominant sources of electricity generation. However, the nation’s resource mix has undergone significant change since” the pro forma rules were issued in 2003 and 2005.
“This transformation has been characterized by the retirement of baseload, synchronous generating facilities and the integration of more distributed generation, demand response and natural gas generating facilities, and the rapid expansion of non-synchronous variable energy resources (VERs) such as wind and solar,” the commission said.
It cited U.S. Energy Information Administration data that the U.S. added 13 GW of wind, 6.2 GW of utility-scale solar photovoltaic and 3.6 GW of distributed solar PV generation in 2014 and 2015. “Conversely, NERC has reported that almost 42 GW of synchronous generating facilities (e.g., coal, nuclear and natural gas) have retired between 2011 and 2014, and the EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas generating facilities retired in 2015.”
The commission said that although wind and solar generators now have the technology to provide primary frequency response, “this functionality has not historically been a standard feature that was included and enabled on non-synchronous generating facilities. Moreover, wind and solar generating facilities typically operate at their maximum operating output, leaving no capacity (or ‘headroom’) to provide primary frequency response during under-frequency conditions.”
RTO Rule Changes
The commission acknowledged it was playing catch up with RTOs that have already begun changing the rules for asynchronous generators:
ISO-NE and NYISO have adopted provisions to their LGIAs that establish more specific requirements for governor operation.
PJM has implemented governor requirements for non-nuclear generators and required new non-synchronous generators to have “enhanced inverters” allowing the provision of primary frequency response. (See Enhanced Inverters Clear MRC.)
MISO requires governor operation as a condition for providing regulating reserves but does not require specific settings.
The commission recently accepted CAISO Tariff rules on governor settings and provisions for sustained primary frequency response.
