Page 1194 – RTO Insider

March 20, 2018

Counterflow: German La La Land

By Steve Huntoon

It’s what you know that ain’t so …

That will get you in trouble.

The February Fortnightly features an article about the German Energiewende (“Energy Transition”) that makes three basic claims: (1) Germany is successfully decarbonizing with renewables, (2) Energiewende is “good news for consumers” and (3) there will be no adverse impact on electric reliability.^[1]

The first two claims are simply wrong. The third cannot be correct.

Wrong: German Electricity is Decarbonizing

German electricity isn’t decarbonizing. Because of its tragic decision to close nuclear plants, Germany is substituting coal and renewables for nuclear.

Despite the increase in renewable generation that Fortnightly extols, there has been no material decrease in carbon dioxide emissions from German electric generation. Germany is doing much worse than the European Union generally, much worse than the U.S. and much worse than France, as shown by changes in electric sector carbon dioxide emissions (2008 baseline):^[2]

In a nutshell, Germany is substituting coal and renewables for nuclear,^[3] while the U.S. and France are substituting natural gas and renewables for coal.^[4] Germany isn’t making a serious dent in its carbon dioxide emissions from electricity, while other nations are.

Does Germany “point the way”? No way.

Wrong: Energiewende is Good News for Consumers

Truth is that Energiewende has driven Germany’s sky-high electricity prices even higher. Here are Germany’s residential prices relative to the European Union, France and the U.S. (U.S. cents/kWh):^[5]

Energiewende, Germany, Energy Transition — | *Eurostat, EIA*

It may be hard for Americans to get their heads around it, but German residential electric prices are now three times U.S. prices.

For U.S. regulators out there, how many years of a 10% price increase each year would it take for the average U.S. residential price to reach the average German residential price?

The answer is 12 years. But the torches and pitchforks appear long before then. Like Year 2.

By the way, Energiewende hasn’t yet hit stride. Germany is planning much more costly renewable and transmission projects that are estimated to ultimately cost 25,000 euros per family household.^[6] That’s $30,750 American.

Does Germany “point the way”? No way.

Cannot be Right: No Impact on Reliability

The Fortnightly article claims that decarbonization has/will have no adverse impact on reliability. This claim is premature and cannot be correct.

The vision seems to be that Germany gets rid of all nuclear plants and all coal plants, and will rely on a combination of renewable resources, flexible fossil (presumably natural gas) generation, demand response and storage (batteries).

Fortnightly seems to think this is feasible because “Germany already produces hours of nearly 100% renewable electricity on the system.” According a German spokeswoman, “‘Baseload is no longer needed,’ otherwise it could ‘block the grid.’”

Say what? The problem isn’t hours when solar and wind generate enough to meet demand. The problem is all those other hours when they don’t, like these sorts of hours and days and weeks:^[7]

Renewables generated very little for a two week period. The vast bulk of demand had to be met with existing conventional power plants.

Supposed Reliability Fixes

Now let’s look at the supposed fixes when existing nuclear and coal power plants are eliminated: flexible fossil fuel (natural gas) generation? Creating a new fleet of gas generators with the necessary pipeline infrastructure would be astronomically expensive and make Germany even more dependent on Vladimir Putin’s natural gas.

By the way, the new German coalition agreement’s sole reference to natural gas is: “Make Germany a location for liquefied natural gas (LNG) infrastructure.”^[8] No such LNG infrastructure exists, and the one proposed LNG terminal looks like more of a pipe dream.^[9] And a very expensive one at that.

OK, how about demand response? An optimistic estimate of theoretically possible DR is about 10% of Germany’s total demand,^[10] requiring a new infrastructure and, of course, customers’ agreement.

Not only is the potential small, but the demand reduction is for one or two hours max. The chart above shows solar and wind can take a powder for days on end.

Batteries fall prey to this same problem. The cost of batteries is typically quoted in terms of four hours of stored energy for each hour of maximum output. What if you need battery output to last eight hours? Then the nominal cost of batteries doubles. If you need 24 hours, then the nominal cost of batteries goes up six times.

So when we think about the need to cover days of renewable non-generation, we should understand that the cost of batteries is many times the current publicized cost. And we can understand why no sophisticated industry player is flocking to batteries (unless subsidized by Other People’s Money — in which case they’re a great idea of course).

The claim that Germany can maintain reliability without nuclear and with only “very small amounts of fossil fuels,” as the article says, sounds like it came from the breatharians, who believe they only need air, and not food, to survive. We don’t hear from them too often — at least not the same ones. For the obvious reason.

The Fortnightly article goes on to cite customer outage and loss-of-load expectation (LOLE) data and projections supposedly demonstrating continued reliability under Energiewende. But the vast bulk of customer outages are attributable to distribution and transmission problems, not resource problems (as the article itself notes at the outset citing a Rhodium Group report). So outage data, especially with renewables still a minority of total resources, says nothing about future resource adequacy.

As for LOLE projections, the article relies on studies that assume that more than 30 GW of coal plants remain in Germany^[11] — which is the opposite of the article’s premise that they are eliminated. You can’t eat your cake and have it too.

In summary, Germany’s future without nuclear and without coal has no plausible means of meeting customer demand.

Does Germany “point the way”? No way.

Bottom Line

Energiewelde isn’t decarbonizing German electricity, only increasing sky-high electric prices, which it will continue to do indefinitely. And reliability can’t be sustained on the equivalent of thin air.

Energiewende does point a way. The wrong way.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.

https://www.fortnightly.com/fortnightly/2018/02/how-german-energiewendes-renewables-integration-points-way. ↑
2008 emissions set at baseline of 100% for all data which is tons of carbon dioxide emissions. First year is 2008 because that is the first year of Eurostat data here, http://appsso.eurostat.ec.europa.eu/nui/show.do?dataset=env_ac_ainah_r2&lang (“Electricity, gas, steam and air conditioning supply.”) I thank Aldyen Donnelly of Vancouver for pointing me to the Eurostat database. U.S. emissions from EPA data here, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks (Table 2-4, EPA inventory archives used for years 2008-2011). ↑
For discussions of this phenomenon, http://www.eiu.com/industry/article/1205236504/is-germanys-energiewende-cutting-ghg-emissions/2017-03-20, https://www.economist.com/news/europe/21731171-thanks-panicked-decision-shut-its-nuclear-plants-germany-carbon-laggard-germany. ↑
https://www.edf.fr/en/the-edf-group/our-commitments/corporate-social-responsibility/doing-even-more-to-reduce-co2-emissions. ↑
European prices from Eurostat data here, http://appsso.eurostat.ec.europa.eu/nui/show.do?dataset=nrg_pc_205&lang=en (select time frame back to 2008 and prices including all taxes and levies; prices converted to U.S. cents/kWh at 1.23 euro/dollar exchange rate). U.S. prices from Energy Information Administration data here, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_5_03. ↑
http://energypost.eu/energiewende-running-limits/. ↑
http://energypost.eu/end-energiewende/. ↑
https://www.cleanenergywire.org/factsheets/climate-and-energy-germanys-government-coalition-draft-treaty. ↑
http://interfaxenergy.com/gasdaily/article/29453/german-lng-terminal-plans-draw-mixed-response. ↑
https://www.diw.de/de/diw_01.c.532689.de/presse/diw_roundup/demand_response_in_germany_technical_potential_benefits_and_regulatory_challenges.html. ↑
https://www.entsoe.eu/Documents/TYNDP2018_MAF2017_Market%20Data_provisional.xlsx (Tab BE 2025, Germany columns for “Hard coal” and “Lignite” assume 31.3 GW of coal capacity and, by the way, 27.6 GW of natural gas capacity); https://www.entsoe.eu/Documents/SDC%20documents/MAF/MAF2016_market_modelling_data.xlsx (prior year version with similar coal and gas natural capacities); https://www.bmwi.de/Redaktion/DE/Downloads/V/versorgungssicherheit-in-deutschland-und-seinen-nachbarlaendern-en.pdf?__blob=publicationFile&v=3 (pdf page 32). ↑

March 20, 2018January 15, 2024

FERC Rejects TO Complaint on SPP Zonal Placements

FERC last week denied a complaint by SPP transmission owners that the RTO’s transmission zonal placement is unjust and unreasonable, saying the members did not meet their burden of proof to back up their claims (EL18-20).

The companies filed their complaint in October, arguing that a “loophole” in SPP’s Tariff forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants said, runs counter to the “no legacy cost shift” protections SPP has established to prevent cost shifting between zones. (See SPP Tx Owners Take Zonal Placement Concerns to FERC.)

The TOs contended SPP’s zonal integration decisions create unjustified rate increases in the form of cost shifts between customers. They argued the Tariff is unduly discriminatory because the cost shift burden is not evenly distributed and the disparate rate treatment is not based on any differences in service or the customers.

The legacy TOs said SPP’s recent creation or expansion of multi-owner zones highlighted various notice and equity issues that did not exist in historical single-owner zones.

Kansas City Power & Light made the filing and was joined by American Electric Power (on behalf of subsidiaries Public Service Company of Oklahoma and Southwestern Electric Power Co.); City Utilities of Springfield, Mo.; KCP&L Greater Missouri Operations; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service; Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.

The companies filed after failing to revise the Tariff to include a mechanism holding customers in an existing zone harmless from network integration transmission service rate increases of more than 2% or $1 million (whichever is lower). The proposal was rejected by both the Markets and Operations Policy Committee and the Board of Directors in July. (See SPP Board Rejects Changes to Tx Zonal-Placement Rules.)

The commission said that although it was denying their complaint, “this does not alter the rights that existing SPP transmission owners … have to represent their interests and take action to address cost shifts that may result from zonal integration.”

Pointing to SPP’s newly revised TO zonal placement process that sets notice and information-exchange requirements for potential new TOs, the commission said existing owners retain their ability to negotiate with the RTO and new owners about zonal integration issues and to design measures to mitigate potential cost shifts. (See “SPC Approves Zonal Placement Process Document,” SPP Strategic Planning Committee Briefs: July 13, 2017.)

In addition, parties can participate in SPP’s stakeholder process to develop and consider proposals to address this issue with more comprehensive participation by all stakeholders, FERC said.

SPP argued that not every cost shift resulting from placing a new TO in an existing zone is unjust and unreasonable. It said FERC has never taken a “rigid view” that rate impacts and cost shifts are universally and patently unjust and unreasonable, but instead “recognizes that matters of rate design involve judgment on a myriad of facts.”

The RTO asserted that its Tariff is not unjust and unreasonable because it does not require SPP to involve itself in evaluating and mitigating cost shifts. Those determinations are best addressed by the commission on a case-by-case basis, SPP said.

Proposed Tariff Revisions Set for Settlement

The commission set for settlement hearing SPP’s proposed Tariff revisions to add an annual transmission revenue requirement (ATRR) and implement a formula rate template for transmission service using South Central MCN’s facilities, when the utility acquires them and transfers their functional control to the RTO.

In an order related to the hearing, FERC also approved South Central’s purchase of transmission lines and related assets from the city of Nixa, Mo.

FERC said its preliminary analysis indicates that SPP’s proposed Tariff revisions “may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” but it accepted and suspended them to become effective the first day of the month after South Central acquires the Nixa assets, subject to refund and the outcome of other ongoing proceedings before the commission.

The commission granted SPP’s waiver request of its regulations regarding cost-of-service statements, consistent with its prior approval of formula rates. However, it allowed the administrative law judge to provide for “appropriate discovery of such information.”

SPP filed its request in October, proposing to incorporate South Central’s previously accepted formula rate to populate the utility’s ATRR with certain Nixa transmission facilities. SPP said the assets, about 10 miles of 69-kV lines and associated infrastructure, interconnect with its system in the Southwestern Power Administration (SPA) and City Utilities of Springfield pricing zones, but are not included in SPP rates.

The RTO proposed placing the Nixa assets and their associated ATRR in the SPA zone, using the revised zonal placement process. The Nixa assets would be the first facilities subject to the revised process.

FERC noted that South Central’s formula rates and implementation protocols are the subject of several ongoing proceedings before the commission, and that the utility has also filed a request for rehearing or clarification.

“Accordingly, certain provisions of South Central’s previously approved formula rate template and implementation protocols could change based on the outcome of those proceedings,” FERC said.

AEP, KCP&L, Sunflower, Mid-Kansas, Westar and Xcel Energy took issue with SPP’s rate-impact analysis under the new process.

The TOs argued that SPP’s calculation of a 46% rate increase “appears to be a simple comparison of total zonal ATRR before and after South Central’s integration.” They said that because network service rates are based on ATRR and load ratio share, it would be necessary to evaluate the ATRR and any associated changes in load to accurately determine the rate impact.

The TOs also contended that the rate impact on existing customers in the SPA zone “is further obfuscated” by the fact that Nixa’s load transitioned to SPP network service in June 2017, but the transfer of facilities and recovery of their ATRR through zonal rates would not occur until a later date.

SPP argued that it did not fail to calculate the impact of adding load because South Central is not a load-serving entity and the Nixa load had already begun service in the zone. That meant there was no change in load associated with the assets’ integration, the RTO said.

Responding to a complaint that it “did not provide sufficient evidence” of the assets’ actual rate impact in the SPA zone, SPP said it provided the information “directly to each SPP transmission customer” in the zone during the zonal-placement process.

South Central, a transmission-only SPP member, said it intends to transfer functional control of the facilities to the RTO once the transaction closes. The facilities will be incorporated into the utility’s ATRR in its zone.

FERC found the transaction to be in the public interest because:

- - It does not involve the transfer of generation facilities or the combination of transmission facilities with affiliated generation in the same market, and thus would not have an adverse effect on competition;
  - It would not have an adverse effect on rates, as potential rate increases in the SPA zone would be attributable to incorporating the Nixa facilities, not the change in ownership; and
  - It would not have an adverse effect on regulation. The commission said it found no evidence that either state or federal regulation will be impaired by the transaction, and noted that no party alleges that regulation would be impaired by the transaction and no state commission has requested that FERC address the effect on state regulation.

South Central said the ATRR for transmission service using the Nixa facilities will be recovered pursuant to its formula rate from SPP ratepayers in the zone. Nixa currently recovers its costs to own and operate the assets directly from retail customers through a bundled rate that includes its costs for generation, transmission and distribution service.

The utility acknowledged that “there will be a ‘rate impact’ in the broadest sense” because of the new arrangement but said that the zone’s customers will see only “very small” increases in their rates, pointing to an estimated annual difference of $87,000 between its ATRR and Nixa’s ownership. It said those increases will be offset by the transaction’s benefits.

South Central is a subsidiary of GridLiance, a competitive transmission company that collaborates with public power utilities. The Nixa municipality serves more than 9,000 retail customers.

March 19, 2018

Conn. Officials Talk State Policy, Wider Trends

By Michael Kuser

CROMWELL, Conn. — State officials last week shared their musings on a range of subjects, including the state’s energy agenda, regulatory woes and China’s approach to siting nuclear plants.

Connecticut nuclear plants PURA ISO-NE — The Connecticut Power and Energy Society had a dinner meeting on March 14 | © *RTO Insider*

At a March 14 meeting of the Connecticut Power & Energy Society, Eric Johnson — the group’s president and director of external affairs for ISO-NE — introduced the speakers a day after New England had been hit by its third nor’easter in two weeks.

“I see some weary utility people in the room who have been pulling storm duty and lines-down duty perhaps,” Johnson said. “I know in our house, folks are ready for spring.”

Jack Betkoski, vice chairman of the Public Utilities Regulatory Authority, noted his agency will hold its first technical conference on grid modernization April 3 and also has a docket open on the nationwide issue of tax reform.

The PURA continues “to look into best practices of electric suppliers,” he said. “We continue to work hard and cooperatively with the companies that come up with procedures that will make life easier for the companies and also make life easier for us as the regulatory agency.”

Regulatory Independence

Betkoski also pointed to a state-level trend around the country to “blow up” regulatory agencies, citing situations in South Carolina, where the House of Representatives has voted to fire the seven-member Public Service Commission after the abandonment of constructing two units at the V.C. Summer nuclear plant, and Tennessee, where the government changed the structure of the Regulatory Authority — now the Public Utility Commission — with regulators now working part-time.

People need to be educated that “we’re kind of like judges, and we need to be independent,” Betkoski said. “The legislature … serves a great purpose and comes up with great tools for us to work with, but you still have to maintain the independence of the regulatory body and the legislative body. I think that’s imperative, and when that starts to be compromised I don’t think anybody wins.”

Soon after becoming NARUC president last August, Betkoski went to China and Japan to see their coal-fired and nuclear plants.

“China has an interesting way of siting their nuclear plants: They just take over a whole town and say this is the way it’s happening,” Betkoski said. “I said, ‘What was here before?’ A town. They’ve got five nuclear plants now and that’s just the way they do it over there.”

Comprehensive Energy Strategy

Tracy Babbidge, head of energy and technology policy for the state’s Department of Energy and Environmental Protection, provided an update on the Comprehensive Energy Strategy (CES) released last month.

Babbidge said the strategy is intended to be comprehensive without getting too far into the details. “We’re trying get to the point and also trying to cover every topic,” she said.

Among other things, the plan calls for increasing the state’s renewable portfolio standard to 40% of total electric usage by 2030, from 24% in 2018. Environmentalists protested the plan’s emphasis on natural gas as a clean resource, and University of Connecticut students rallied outside the capitol in Hartford last month to push the state to support more renewables.

The CES recommends that Babbidge’s division of DEEP increase its engagement with other states and regional organizations to help shape policy at FERC and ISO-NE.

In addition, the plan recommends the state streamline permitting and siting and work to make the average cost of solar PV installations fall below residential rates, and that DEEP monitor waste-to-energy facilities as long-term power purchase agreements expire and operating costs increase.

“One of the big themes is ensuring sustainable and equitable funding for energy efficiency,” Babbidge said. “This really speaks to the legislative diversions, and they need to make sure that [for] our clean energy programs, both on the efficiency side and the Green Bank, that the funding is secure.”

March 19, 2018April 9, 2024

Overheard at ACORE Renewable Energy Policy Forum

WASHINGTON — The American Council on Renewable Energy’s (ACORE) 15th Renewable Energy Policy Forum brought regulators, federal officials, investors and others to a downtown D.C hotel for discussions on environmental policy, the growth of markets in the West and the Department of Energy’s budget. Here’s some of the highlightsWestern Markets

Several speakers discussed the growth of the Western Energy Imbalance Market (EIM) and SPP’s planned expansion with Mountain West.

FERC Commissioner Robert Powelson said the developments of markets in the West is remarkable given the distrust that remains from the 2000-2001 Western energy crisis.

“Who could have thunk it … that today around the CAISO market that you could see markets like the Energy Imbalance Market or the potential expansion of the Southwest Power Pool bringing together an eclectic group of state regulators, renewable investors, vertically integrated utilities and all doing it under the guise of market development,” Powelson said.

“Yes, there were a lot of lessons learned post-California energy crisis. But today these markets — especially EIM — have enormous potential for this industry. And I think we need to stay the course in supporting the market design and more importantly staying away from collapsing these markets with regressive policy actions.”

“I think that you’re going to see probably a Rocky Mountain state [market] formed around Southwest Power Pool … then you’re probably going to see one that’s more coastal in nature that’ll be more North-South,” said California Public Utilities Commission President Michael Picker. “I think eventually they’ll grow together. There may be some transfers across the seams. There’s always going to be too much Wyoming wind for any of the other Rocky Mountain states to swallow. But they’ll want to go talk to the [public utilities] in the Pacific Northwest — they’re seeing California as their more natural market than going east.”

“By 2020, two-thirds of the Western Interconnection will be participating [in EIM]. That’s great,” said Patrick Reiten, senior vice president of government relations for Berkshire Hathaway Energy. “That’s only within-hour energy. You want to get to hour-ahead energy. You want to get to day-ahead.”

Converting CAISO to a multiple-state RTO would require a change in California law, he noted. (See related story, CAISO Presses Lawmakers on RTO Conversion.)

“I was pleased to hear President Picker express some optimism in terms of state legislation to enable that,” he continued. “But there may be an interim step with the EIM entities actually engaging in a day-ahead market — day-ahead unit commitment — without full ISO membership. That would require some flexibility on FERC’s behalf.”

Reiten said the markets’ promise would be enhanced by making it easier to build transmission. He recounted his experience winning federal permits for PacifiCorp’s Energy Gateway projects, which could add as much as 2,000 miles of transmission.

“It took us 10 years to federally permit those. And you can imagine what happens in 10 years between envisioning the project and actually delivering [power]. Loads change, markets change, regulations change. And so when you have that kind of lag, the risk profile [for] making the investment obviously goes up. We need to change that.”

Reiten said any federal infrastructure legislation should include changes to siting and permitting policies and the National Environmental Policy Act. “We need three things: … We need a single point of accountability — a lead federal agency that has power to make decisions. We need concrete timelines — and that gets a little sensitive because we’re talking about NEPA reform. And then we need to make sure that federal decisions aren’t revisited in the pendency of the permitting process so we can get out of the ‘Groundhog Day’ syndrome. If you can get those three things, that should shorten the permitting timeline [and] reduce the risk. We’ll see more transmission developed.”

Decarbonizing Transportation

Picker also had some advice for ACORE’s members in addressing his state’s “glut” of renewable energy.

“Rather than taking a bigger share of the existing market, think of how you could partner with the existing electric utilities or other parties to foster the electrification of transportation. In California, 20% of our carbon emissions come from the electric industry, 30% come from buildings, 40% come from transportation. So the utilities are taking a great interest in this. They see that as probably being a more natural thing for them to do, which is to build things rather than just to sell electricity. If California is going to meet its carbon goals, decarbonizing transportation becomes more important than decarbonizing the slimmer and slimmer margins in the electric industry.”

Solar Industry: ‘It Could Have Been Worse’

Christopher Mansour, vice president of federal affairs for the Solar Energy Industries Association, said his industry is unhappy about the Trump administration’s tariffs on imported solar energy cells and panels but relieved that the investment and production tax credits survived the tax cut bill signed by the president in December.

“We don’t like the 30% tariff. It’s not good. It’s not going to be helpful to our industry in general,” said Mansour, whose organization has estimated the tariffs will cost 23,000 industry jobs. “On the other hand, given the policy environment we’re in, it could have been worse.”

SEIA is now backing a bill by Sens. Dean Heller (R-Nev.) and Martin Heinrich (D-N.M.) to create an investment tax credit for storage. “We’re hopeful. We came close this last go-round with the continuing resolution, which put in a bunch of tax extenders. We came close with that.”

Storage Role Outside of RTO Markets

Todd Glass, a partner in Wilson Sonsini Goodrich & Rosati, who moderated a panel on grid resilience, noted that FERC Order 841 — which directs RTOs and ISOs to remove barriers preventing storage from participating in energy, capacity and ancillary service markets — does not apply to utilities outside the organized markets. (See FERC Rules to Boost Storage Role in Markets.)

How will storage make inroads with them, he asked?

“In terms of the rest of the country, in the vertically integrated markets, that’s on groups like us and ACORE and others to get out there and educate our state regulators and work with our utilities to have storage recognized as part of the [integrated resource plan] process,” responded Marissa Gillett, vice president of external relations for the Energy Storage Association.

Ott Promises to Protect Markets

ACORE CEO Gregory Wetstone said his group is relieved that FERC rejected the Department of Energy’s call for coal price supports but concerned about policies that may result from the commission’s resilience docket.

“We’re worried that we see traces of the [DOE proposal] in various market design and pricing proposals,” he told PJM CEO Andy Ott, after Ott put in a plug for the RTO’s proposal to allow inflexible generators to set clearing prices.

Ott assured Wetstone that competition is the “hallmark” of PJM. Ott also said a repricing proposal the RTO will file later this month will be designed to allow state clean energy procurements to coexist with its markets.

“We really can’t put one of these above the other. We need to make sure both are equally accommodated so that … when a state does make that decision it shouldn’t be penalized. But we need to figure out a way that the market signal remains healthy.”

DOE Budget

Wetstone also had some tough questions for Under Secretary of Energy Mark W. Menezes, after Menezes spoke glowingly of the work of DOE’s national laboratories. Menezes cited the department’s battery storage goals for 2030: reducing the price to $100/kWh, increasing the range to 300 miles per charge and reducing the charging time to less than 15 minutes. “In pursuit of that goal last year, we made an award for up to $15 million for research projects on batteries and vehicle electrification technologies to enable extreme fast charging,” he said.

“You’ve made a phenomenal case for innovation, R&D investment and — I guess I would argue — opposition to the proposed DOE budget, which eliminates ARPA-E … proposes a 66% reduction in [the Office of Energy Efficiency and Renewable Energy, and] eliminates the loan guarantee program,” Wetstone told him.

Menezes responded that all department research projects come with defined goals, such as reducing costs or reaching production thresholds.

“The point is that … our job is to do early-stage research and move it along the technological readiness levels eventually getting it to where it’s commercially deployable,” Menezes said. “So, sure you can continue spending money there, but then potentially where would be the opportunities for new energy breakthroughs?”

“I think the case is there that there’s lots of good things that need to be done that the national labs would be immensely helpful with,” Wetstone persisted.

100% Renewables a ‘Red Herring’

Varun Sivaram, Philip D. Reed fellow for science and technology at the Council on Foreign Relations, and author of the newly released “Taming the Sun,” is under age 30, but even he doesn’t think he’ll live to see 100% renewable energy.

“Forget about 100% renewables. I don’t even want to talk about that. [It’s a] red herring — hugely expensive,” he said. “We should focus on getting as far toward that goal as possible, but laying out 100[%] as this magical milestone, I don’t think is a good or useful idea.”

March 19, 2018May 31, 2024

NRG Set to Retire California Gas Plants

By Jason Fordney

Environmental groups last week cheered NRG Energy’s announcement that it will retire three gas-fired plants in Southern California.

But while the company’s GenOn subsidiary has filed paperwork to shut down the units, recent market dynamics could keep them online if they’re required for reliability.

NRG on Feb. 28 alerted the California Public Utilities Commission that it plans to retire Etiwanda Units 3 and 4 on June 1. The company also notified regulators that it will shut down Ormond Beach Units 1 and 2 on Oct. 1 and the Ellwood Generating Station on Jan. 1, 2019.

The Sierra Club and other groups on March 9 said the closure of the plants is part of a trend in the state toward renewable power and energy storage.

But the proposed retirement of gas plants in California is complicated by broader issues playing out in the state’s wholesale electricity.

While other gas-fired plants in the state have filed notices to retire, they have also been identified as necessary to support system reliability and receive reliability-must-run payments from CAISO to remain online. The RMRs are expensive and controversial, facing strong opposition from the CPUC, which recently replaced a series of Calpine RMRs with solicitations to procure energy storage. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.)

CAISO NRG gas-fired plants CPUC Puente Plant

NRG’s Puente Power Project viewed from beach | California Energy Commission

When asked whether the NRG plants are slated for RMR contracts, company spokesman David Knox told RTO Insider: “We have filed the paperwork to close them. I do not want to speak for the CAISO or CPUC, but [I] am confident that in response to the filings, they will conduct the reviews to determine if they are needed for reliability beyond those dates.”

With no coal plants remaining in California, natural gas has become an increasing target for environmental and other groups opposed to fossil fuel generation. NRG in October 2017 asked the California Energy Commission to suspend its review of the proposed 262-MW Puente plant in Oxnard after two commissioners issued an “unusual” notice recommending denial of the plant. (See NRG Signals Pull-out on Proposed Puente Plant.)

Puente Site Plan | NRG

The developments occur within a larger restructuring of NRG, which has undertaken plans to boost its share price. NRG last month announced that it was selling its NRG Yield, South Central Generating, and Boston Energy Trading and Marketing subsidiaries for nearly $2.9 billion and initiating a $1 billion stock buyback program. (See NRG Announces $1 Billion Stock Buyback, $70 Million Sale.) The company last year said it would seek to raise $2.5 billion to $4 billion in cash through asset sales.

Also, on March 15, Calpine requested the California Energy Commission suspend its application for the proposed 275-MW Mission Rock Energy Center, a gas-fired/storage facility in Ventura County. The company said that California policies have been in transition since the plant was proposed on Dec. 31, 2015, and that Southern California Edison’s latest request for offers for reliability support in the Moorpark subarea “does not appear to present an opportunity for Mission Rock Energy Center.”

March 19, 2018

Whitehouse: Business Can Move GOP on Carbon

By Rich Heidorn Jr.

WASHINGTON — A dozen Senate Republicans are willing to consider a price on carbon emissions but need political cover from business lobbying groups to proceed, Sen. Sheldon Whitehouse (D-R.I.) told the American Council on Renewable Energy (ACORE) Renewable Energy Policy Forum on Wednesday.

Sheldon Whitehouse social cost of carbon GOP ACORE — Whitehouse | © *RTO Insider*

Whitehouse spoke to the group the day after giving his 200th floor speech on climate change, or as he put it, “banging my head against the wall of Castle Denial.”

“The day that corporate America steps in on this issue in Congress and does not abandon the field to the fossil fuel industry, you’ll have much more balance. And when that balance happens, it gives running room to Republicans,” said Whitehouse, who has served since 2007. “I will assure you there are at least a dozen Republicans in the Senate who want to work on a carbon bill. … They just don’t want it to be their last political act.”

Seeking ‘Good-Guy Corporations’

Whitehouse said Republicans in Congress won’t move on climate change until “the good-guy corporations” who are expanding their renewable energy purchases and have progressive climate policies put their lobbying muscle behind the effort.

“Even the corporations you think would show up on climate … when they come to Congress, it’s ‘Abandon all hope, ye who enter here,’” Whitehouse said, citing Coca-Cola and Pepsi. “The American Beverage Association, which is their trade association, doesn’t lift a finger on anything related to renewables or climate. Indeed, it funnels money through the [U.S.] Chamber of Commerce, which is probably my most powerful and inveterate adversary on all things renewable and all things climate.”

He also noted that TechNet, the lobbying organization whose members include Apple and Google, has not included climate policy among its legislative priorities. “You look at the policies of Apple, Google, Facebook [and] Microsoft, it’s weird that they would not put climate or even renewable energy into their [lobbying] priority list. It gets even weirder when you look at the rest of the members of TechNet, which includes Sunrun, Bloom Energy [and] SolarCity. They are actually in the green energy business and they have not been able to get green energy into their own trade association’s list of priorities.”

Although some oil company CEOs have said “‘we take climate change seriously; we know that our product is causing it and we support a carbon price’ … their entire legislative apparatus is still fully dedicated to making sure that none of that stuff [passes] Congress,” Whitehouse continued.

He said he is cautiously encouraged by news that the four oil majors are considering supporting a $40/ton price on emitted carbon.

“That’s only 10 bucks away from where my bill is. That’s within negotiating range. Now I’m ready to talk, if we can start to get something done. But they have to be serious about it,” he said. “I’ve got to see [the American Petroleum Institute] move. I’ve got to see the U.S. Chamber move. I’ve got to see their political apparatus get into alignment with their CEOs’ statements.”

Litigation over climate change is putting increasing pressure on corporations, he said. “As the lawsuits pile up and as discovery begins to become more of a threat, as security regulators begin to say, ‘Hey, wait a minute. These reserves you’re reporting: let’s measure them against 2 degrees centigrade or 1.5 degrees and see how real they really are.’”

He told his audience to take “full advantage” of court rulings supporting a social cost of carbon. “Under the Trump administration, they’re not going to want to look at that. But there are three circuit courts of appeal and probably a dozen district courts — as well as a number of administrative agencies, both state and federal — that have said: ‘Look, when you’re dealing with these energy questions, if you haven’t baked the social cost of carbon pollution into your analysis, you are not meeting the standard of basing your decision on substantial evidence and avoiding decisions that are arbitrary and capricious.’” (See related story, Dem Dissents Show FERC Divide on Carbon.)

To be acceptable to Republicans, Whitehouse said, carbon legislation must be based on a market-based price, be revenue-neutral and “border adjustable, so the cement plant in Texas doesn’t have to compete unfairly with a cement plant in Mexico.”

“There’s nothing about this that is inherently partisan,” he said. “The partisanship is a feature of the manner in which the fossil fuel industry deploys its political forces.”

He acknowledged that carbon legislation will be a tougher sell among House GOP members, who face re-election every two years and, he said, are more dependent on party leadership for campaign funds.

Heather Reams, managing director of Citizens for Responsible Energy Solutions, which is seeking to build Republican support for what it calls “common-sense, conservative solutions” on energy, agreed.

“We’ve got to meet [House] members where they are,” she said, speaking on a panel earlier in the day. “We’ve got to recognize we can’t go in with a one-size-fits-all message and say, ‘Here you go.’ … That’s not going to work in the House.”

She called for what she called “storytelling.”

“This is not [just] a renewable business or clean energy [story]. It is business. It is a massive part of our economy. It’s growing rapidly. Why do you want to abandon that?”

March 19, 2018

PJM MRC/MC Preview: March 22, 2018

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. NOTE: After the meetings, Independent Market Monitor Joe Bowring will provide a briefing on the 2017 State of the Market Report.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

(There appears to be an error in PJM’s post-ed agenda for the MRC. The times for Items 3 and 4 overlap.)

Markets and Reliability Committee

2. PJM Manuals (9:10-9:40)

Members will be asked to endorse the following proposed manual changes:

A. Manual 1: Control Center and Data Exchange Requirements. The revisions were developed as part of a periodic review and encompass real-time system monitoring and communication requirements, including external resources.

B. Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). The revisions were developed to implement new NERC standards for transmission owners to monitor and report the quality of their real-time assessments in intervals of at most 30 minutes.

C. Manual 14A: New Services Request Process and Manual 14E: Additional Information for Upgrade and Transmission Interconnection Projects. Revisions developed to implement previously approved revisions to PJM’s transmission service and upgrade requests. (See “Transmission Issues,” PJM PC/TEAC Briefs: Feb. 8, 2018.)

D. Manual 33: Administrative Services for PJM Interconnection Agreement. Revisions developed as part of a comprehensive periodic review to clarify and streamline language.

E. Manual 37: Reliability Coordination. Revisions developed to clarify language and simplify references to NERC standards.

3. Energy Price Formation Senior Task Force (EPFSTF) (9:40-10:15)

Members will be asked to endorse a proposed charter for the EPFSTF and proposed revisions to the energy price-formation issue charge related to development of a real-time, 30-minute reserve product. (See “30-Minute Reserves,” PJM Operating Committee Briefs: March 6, 2018.)

4. Tariff Revisions to Address Overlapping Congestion (9:30-9:45)

Members will be asked to endorse Tariff and Operating Agreement revisions to address overlapping congestion. A vote on the proposal was held over from February’s MRC meeting to address concerns about cancellation of certain market-to-market payments. (See “Overlapping Congestion,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)

Members Committee

1. Tariff and Operating Agreement Revisions to Address Overlapping Congestion (1:10-1:30)

Members will be asked to endorse proposed Tariff and Operating Agreement revisions to address overlapping congestion. (See MRC Item 4 above.)

— Rory D. Sweeney

March 19, 2018

NYISO Business Issues Committee Briefs: March 15, 2018

RENSSELAER, N.Y. — NYISO energy prices averaged $33.83/MWh in February, down sharply from their cold snap average of $99.55 in January but up 9.3% from the same month a year ago, Rob Pike, director of market design, told the ISO’s Business Issues Committee on Thursday.

The ISO’s year-to-date monthly energy prices averaged $72.85/MWh in February, up 92% from a year earlier. Average sendout was 426 GWh/day, compared with 463 GWh/day in January and 418 GWh/day a year ago.

New York natural gas prices for the month averaged $3.14/MMBtu at the Transco Z6 hub, down from $17.94 in January. Prices were up 11.1% from a year ago.

Distillate prices gained 19.3% year over year, with Jet Kerosene Gulf Coast averaging $13.72/MMBtu. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.86/MMBtu, compared with $14.83 in January.

The ISO’s local reliability share was 14 cents/MWh, lower than 59 cents the previous month, while the statewide share of -64 cents/MWh was higher than -$1.52 in January. Total uplift costs also rose from January.

Broader Regional Markets

Reviewing the Broader Regional Markets report, Pike highlighted NYISO’s ongoing work to clarify the minimum requirements for delivering external capacity into the Installed Capacity (ICAP) market. The BIC in January approved ICAP Manual revisions covering deliverability requirements for capacity imports from NYISO Business Issues Committee Briefs: Jan. 17, 2018.)

Pike also noted that NYISO last month urged FERC to deny a complaint by the New Jersey Board of Public Utilities against the ISO, PJM, Consolidated Edison, Linden VFT, Hudson Transmission Partners and the New York Power Authority. The complaint challenges the implementation of the mutual benefits provisions in the NYISO-PJM Joint Operating Agreement and requests amendments to it.

“First, the complaint was an impermissible collateral attack on prior FERC orders, attempting to reopen matters that have been addressed or are being addressed in other proceedings,” the ISO said in its FERC filing. “Additionally, the complaint is inconsistent with an Order No. 1000 cost allocation principle requiring voluntary agreement for the NYISO to be allocated costs.”

The ISO further argued that the complaint is inconsistent with the provisions of the JOA and tariffs that address cross-border cost allocation. The BPU also misinterpreted provisions of the JOA spelling out that NYISO and PJM not charge each other for mutual benefits, the ISO said.

External Deliverability Rights

The BIC recommended that the Management Committee approve Tariff revisions that would create external-to-Rest of State (ROS) deliverability rights, which would improve the ability for transfer capability into ROS to participate in the capacity market.

Ethan D. Avallone, senior market design specialist, said Hydro-Quebec US (HQUS) proposed that the ISO develop a method for awarding capacity resource interconnection service (CRIS) to entities that create increased transfer capability through transmission upgrades over external interfaces.

FERC in January 2017 granted HQUS a waiver (ER17-505) making it eligible to receive CRIS corresponding to the incremental transfer capability created by its Cedars Rapids Transmission intertie project. The commission noted that the issue was not addressed earlier because of other priorities and not because of objections from the ISO or other stakeholders.

2017 Congestion Assessment and Resource Integration Study

The BIC also voted to recommend that the Management Committee ask the Board of Directors to approve the ISO’s 2017 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 report.

The 2017 CARIS includes six studies on three areas, Edic-Marcy, Central East, and New Scotland-Pleasant Valley. | *NYISO*

Tim Duffy, economic planning manager, presented the draft report, which he said provides analysis of the potential costs and benefits of relieving congestion on the New York grid by using generic transmission, generation, demand response and energy-efficiency solutions.

One stakeholder expressed skepticism about the rationality of the projected resource mix used to theoretically meet the state’s goals to get 50% of its energy from renewables by 2030.

NYISO business issues committee cold snap energy prices — Real-time fuel mix, March 12, 2018. NYISO is updating its manual for combined cycle generating units equipped to switch from gas to oil. | *NYISO*

“We certainly recognize that any of these numbers could be argued with, but the objective was to get to the 2030 goals,” Duffy said.

The study presents a series of metrics for a wide range of potential futures and scenarios. One set of results can be viewed as a “business as usual” case, incorporating incremental resource changes based on the ISO’s study inclusion rules, Duffy said.

Some results identify limited opportunities for transmission build-out based solely on production cost reductions. A second set of results is more forward-looking and captures impacts of changes on the grid through large-scale growth in renewable resources and implementation of energy-efficiency programs.

The ISO identified the three transmission elements — or groups of elements — where congestion was most prevalent in the New York Control Area based on an analysis of historic and projected congestion, and potential production cost savings.

Manual Update on Fuel Swap Testing

The BIC approved sending the Operations Committee a proposed update to the Ancillary Services Manual covering automatic fuel swap capability testing.

Harris Miller, associate operations engineer, said automatic fuel swap tests are required each capability period by combined cycle generating units that participate in Con Ed’s minimum oil burn program and are equipped to automatically switch from gas to oil.

Each applicable generating unit must demonstrate a swap from natural gas to oil after an actual loss of gas pressure, a simulated loss of pressure, or an operator-initiated swap.

The swap must occur within a time frame consistent with the design parameters of the unit, must not exceed 60 seconds and should occur during stable operation while the unit remains synchronized to the transmission system. Each unit must coordinate real-time automatic swap tests with both the ISO and Con Ed.

In the event of a failed test, the operator must identify the cause of failure, undertake remedial action, and keep Con Ed and the ISO informed about its progress fixing the problem.

— Michael Kuser

March 19, 2018

Stakeholders Debate MISO Cost Allocation Plan

By Amanda Durish Cook

CARMEL, Ind. — Stakeholders are questioning a MISO proposal that would draw a sharp distinction between the cost allocation eligibility for interregional and internal projects.

The preliminary proposal would make cost sharing available to 100-kV projects along the PJM and SPP seams but limit it to internal market efficiency projects of 230 kV and above.

MISO staff have expressed confidence about the proposal — unveiled last month — and say the change will capture a reality in the footprint, where 230-kV lines are prevalent. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.) The plan also respects FERC’s 2016 order requiring MISO to lower its voltage threshold to 100 kV on interregional projects with PJM.

“Views can change in the next few months, but right now, we’re on a good path,” MISO Director of Strategy Jesse Moser said of the allocation proposal during a March 15 Regional Expansion Criteria and Benefits Working Group meeting.

Several stakeholders at the meeting asked MISO to consider lowering the internal market efficiency project voltage threshold to 100 kV, while others favored the 230-kV limit — and a few preferred keeping the 345-kV limit.

Ottertail Power’s Stacie Hebert said her company favors maintaining the 345-kV market efficiency project threshold, but it thought 230 kV was a “reasonable compromise.”

Moser said the divergent stakeholder views he’s heard on the proposal suggest the RTO may have struck a compromise.

But WEC Energy Group’s Chris Plante said he couldn’t understand the reason for the differing thresholds.

“We have difficulties reconciling a 100-kV interregional voltage threshold with a 230-kV voltage threshold for MISO market efficiency projects,” Plante said.

While Plante said his company could become comfortable with MISO’s proposed removal of the postage stamp rate, he asked the RTO to also examine the possibility of implementing separate postage stamp rates for the Midwest and South regions. Since Entergy joined the RTO in 2013, MISO South has been subject to an integration transition period, which limits cost sharing in the region.

Madison Gas and Electric’s Megan Wisersky also said her company supported “consistency between internal and interregional projects” and a regional postage stamp rate.

Changing Nature

MISO has recommended that it scrap its current footprint-wide postage stamp rate for market efficiency projects. The RTO currently allocates 80% of project costs to local resource zones based on expected benefits and recovers the other 20% via postage stamp allocation to all regional load.

The RTO wants to assign all costs to benefiting transmission pricing zones and work with stakeholders to create more specific benefit metrics and cost allocation zones. It currently relies on the postage stamp rate as a means of recognizing both benefits not currently quantified within its cost allocation and the changing nature of beneficiaries as the resource fleet evolves.

MISO FERC cost allocation MISO Annual Stakeholders' Meeting — Lopez | © *RTO Insider*

MISO planning coordinator Davey Lopez said the RTO’s current interregional cost-sharing rules are inconsistent and complicate interregional planning. To remedy this, Lopez said MISO must lower its SPP interregional cost-sharing threshold to 100 kV, matching its threshold with PJM.

“Most of the existing tie lines between MISO and SPP are less than 230 kV,” Lopez added.

MISO’s Tariff does not currently define regional cost allocation for sub-345-kV economic projects with PJM (although a plan is due in October in response to a FERC directive) and still requires economic projects with SPP to be at least 345 kV to be eligible for regional cost-sharing. The Tariff also doesn’t address sub-345-kV interregional projects located wholly outside of the RTO.

More Cost Allocation Zones

Other stakeholders at the meeting called on MISO to provide more detailed benefit metrics regarding a plan to further refine and shrink its existing cost allocation zones, which are currently based on the historic grouping of transmission pricing zones by state jurisdiction. They are nearly identical to the 10 local resource zones used in the annual capacity auction, although MISO this year won FERC approval to carve out an 11th zone in Texas for more specific cost allocation for the impending 500-kV Hartburg-Sabine project, the RTO’s only competitively bid transmission project this year. (See MISO Board Approves Texas Competitive Tx Project.)

MISO FERC cost allocation postage stamp rate — Cost Allocation Zones in MISO today | *MISO*

MISO staff stressed they haven’t established a position on rearranging existing transmission pricing zones or valuing new benefit criteria. Discussions on the new cost allocation plan will continue through fall.

March 19, 2018

Utilities Urge Extension of EV Credit

A coalition of the country’s largest utilities last week urged Congress to maintain an electric vehicle tax credit and remove the cap that limits the benefit to the first 200,000 manufactured vehicles.

In a March 13 letter to congressional leaders, the 36 energy companies asked Congress to maintain the EV tax credit in its fiscal year 2018 omnibus spending legislation and eliminate the existing cap in order to accelerate the adoption of EVs and “boost our economic and national security.”

“First-mover companies — all American manufacturers — are all likely to hit the existing 200,000 vehicle-per-manufacturer cap this year, just as a new generation of affordable, state-of-the art EVs hits the market,” the letter says. “These automakers created thousands of American EV jobs by making early investments in EV research and development, manufacturing capacity and charging infrastructure.”

EV electric vehicle tax credit — Utilities want a 200,000-vehicle cap removed from an EV tax credit | *emotorwerks*

Signatories to the letter include American Electric Power, Consolidated Edison, Duke Energy, Edison International, Florida Power & Light, Long Island Power Authority, National Grid, NV Energy, Pacific Gas and Electric, Public Service Enterprise Group, Seattle City Light and National Grid.

The utilities said they “look forward” to a time when EVs can support grid resources, help integrate intermittent renewable generation and provide demand response. Eliminating the cap would provide certainty to automakers and consumers, and support jobs, the utilities said.

Section 30D of the Internal Revenue Service code provides a credit of up to $7,500 for EVs. It was originally included in the Energy Improvement and Extension Act of 2008 and was amended in the American Recovery and Reinvestment Act of 2009. The credit begins to phase out when at least 200,000 EVs have been sold for use in the U.S.

— Jason Fordney