Page 1185 – RTO Insider

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

March 19, 2018

SPP Hits 60% Penetration Level, as Promised

By Tom Kleckner

Two years ago, SPP said a staff wind-integration study had found the RTO could “reliably handle” wind penetration levels of up to 60% of load with a few operational modifications. (See Study: 60% Wind Penetration Possible in SPP.)

On Friday morning, it happened. At 3:45 a.m. March 16, wind accounted for 13,928.94 MW of the system’s total load of 22,998.71 MW, a penetration level of 60.56%.

SPP said the record was among nearly a dozen it has set in the previous 90 days. Last year, it became the first North American RTO to exceed wind penetration levels of greater than 50%. Wind penetration reached as high as 56.25% in December, when SPP set its record for wind demand at 15.7 GW.

SPP ERCOT Wind Power load forecasting — | *SPP*

The RTO has added almost 12.5 GW of wind capacity since 2010, giving it 17.75 GW of installed wind. With the addition of another 5.3 GW that have interconnection agreements but are not yet in service, SPP’s wind capacity will exceed its minimum load of 20.42 GW. Another 35 GW of wind capacity is under various stages of review in the generator interconnection queue.

“We are continuously evaluating the development of generation resources in our footprint to ensure a safe and reliable operation,” said Bruce Rew, SPP’s vice president of operations. “As additional generation is constructed, we will compare those impacts to our forward-looking studies to ensure a reliable grid.”

At the time of the 2015 wind integration study, SPP’s wind penetration levels were approaching 39% and its record wind peak was 9,948 MW. The report recommended installing voltage reactive support capabilities for existing wind farms; enhanced operations tools to monitor real-time voltage stability limits; allowing the reliability coordinator additional flexibility in redispatching; and new planning criteria for and evaluation of phasor measurement units to provide real-time situational awareness.

Rew said the RTO has improved its wind forecasting capabilities and made “numerous” changes since 2015 through its market and reliability coordination processes.

March 18, 2018

FERC Affirms Ruling Favoring Entergy Bandwidth Calculation

By Amanda Durish Cook

FERC last week affirmed an initial decision approving how Entergy has equalized production costs among its operating companies, batting away several grievances raised by Louisiana regulators.

The commission affirmed three findings from an administrative law judge’s 2016 ruling on the company’s bandwidth payments (EL10-65-005), determining that Entergy:

Properly accounted for the 9.3% interest sale and leaseback of the Waterford 3 nuclear plant near New Orleans in its accumulated deferred income taxes when it characterized the sale as financing and excluded it from bandwidth formula payments;
Can keep interruptible load in its system monthly coincident peaks used to develop the 2010 and 2011 bandwidth calculations, although all other years of Entergy’s bandwidth payments exclude interruptible load; and
Appropriately accounted for the costs of the allowance for funds used during construction (AFUDC) for the River Bend nuclear plant north of Baton Rouge in bandwidth payment calculations.

The allocation of 2007-2015 production costs among Entergy’s half dozen operating companies under its multistate system agreement has been a source of disagreement for a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.

FERC Bandwidth Payments AFUDC Entergy — River Bend plant | *Entergy*

In a 2010 filing with FERC, the Louisiana Public Service Commission contended that Entergy’s bandwidth payment calculation suffered from several inconsistencies. Among its complaints: 1) The formula needed to include the company’s Waterford 3 sale and leaseback account as production costs, and 2) the demand responsibility factor for allocating fixed costs and the reserve equalization cost credit for interruptible load used to calculate 2010-2011 bandwidth payments was incorrect and warranted refunds. The PSC also said the bandwidth formula should include certain River Bend plant-related costs excluded from Entergy’s total production costs, arguing that the company should not have treated the plant’s AFUDC as a regulatory asset and liability, even though it was apparently ordered to do so in a 1991 order (U-17282).

However, FERC said accumulated deferred income taxes associated with Waterford 3 are not “properly includable for commission cost-of-service purposes.” The commission also determined that Entergy in 1991 did not have the requisite data to make accounting changes for the River Bend AFUDC, and that the company had correctly accounted for AFUDC in regulatory asset and liability accounts by recording it in plant-in-service accounts.

“We are in no position to speculate on the Louisiana commission’s intentions,” FERC said of whether the Louisiana PSC actually meant for Entergy to create the regulatory asset and liability nearly 30 years ago.

FERC also said it already resolved the interruptible load issue in a 2012 order that required Entergy to remove all of it from its cost allocation in response to the Louisiana commission’s 2007 complaint (EL07-52-001). “No further relief is available in this separate proceeding,” FERC said.

The commission also agreed with the judge’s position that it had “already ruled on the interruptible load issue and provided relief to the maximum extent possible when it prescribed refunds for the refund effective period from April 3, 2007, through July 3, 2008, and prospectively from May 7, 2012.” The administrative law judge in 2016 said the appropriate time for the Louisiana PSC to “have asked for extraordinary relief beyond the 15-month refund period” would have been in 2012.

March 16, 2018

Overheard at Capture the Energy 2018

By Michael Kuser

ALBANY, N.Y. — With the cost of energy storage declining worldwide, New York plans to ride the wave of the technology to a cleaner energy future, targeting deployment of 1,500 MW by 2025.

Participants heard that and more at the Capture the Energy 2018 conference on Wednesday, hosted by the New York Battery and Energy Storage Technology (NY-BEST) Consortium.

William Acker, executive director of NY-BEST, said three key factors are driving the use of energy storage.

“We talk about increasing the efficiency of the grid, about reducing peak load and serving as a peaking facility for the grid,” Acker said. “We talk about increasing renewables.”

And the “linchpin,” according to Acker: resilience.

“We were over at National Grid yesterday and we were talking about resilience, that resilience means something different from reliability,” Acker said. “Reliability is how well you do on typical operating days; resilience is how well you do in the face of adversity. Winston Churchill had resilience. It’s how well you do when you’re facing the storms.”

‘God Wants Storage’

NYISO Capture the Energy — Rhodes | © *RTO Insider*

New York Public Service Commission Chair John Rhodes, whom the governor tapped to lead his energy storage initiative, said the state’s Reforming the Energy Vision “can be an awesomely complex interweaving of multiple proceedings, but it’s kind of a complicated machine that’s trying to do something simple.”

“It’s good to keep in mind what that simple thing is: arrive at an energy system that is cleaner, that’s more affordable, that’s more resilient, that’s always reliable,” Rhodes said. “Basically, the energy system that’s right and necessary for New Yorkers.”

He said the grid contains latent value that is not currently being captured or monetized. A natural approach to remedying that shortcoming would be to reveal and reward that value, whether it relates to carbon reduction, location, firming and time-based capabilities, or the provision of system-level services.

Rhodes also emphasized the benefits of markets at scale.

“We know that when markets get big, costs come down, innovative companies find different ways to persuade different kinds of customers with a different kind of proposition appealing to their different motivations,” Rhodes said. “We want that. We don’t want one-offs. If we’re doing things, we’d rather see first-of-a-kind innovations than one-of-a-kind innovations.

“As a regulator, and as a contributor to this agenda, we’re obviously trying to encourage more innovation and more investment — other people’s money,” he said. “And we’re obviously going to try to do that as smartly as possible. We are going to as much as possible stay in the mode of being solution-agnostic. We want to specify the problem and have the world come up with solutions, harvest the benefits of competition, pick the best and set the others aside.”

Rhodes said the preliminary results of a storage study New York is developing already indicate that the lifetime benefits of the state’s 1,500 MW by 2025 storage goal “completely and clearly” exceed costs.

“And they also reveal that God wants storage to be in Zones J and K [New York City and Long Island]. Amazingly, it’s confirming what everybody expected,” Rhodes said.

Costs and Goals

Yayoi Sekine, a Bloomberg energy analyst, spoke about the decreasing cost of lithium-ion batteries and the increasing penetration of electric vehicles in the automobile market. She predicted the cost of the batteries will drop from the current $209/kWh to $70/kWh by 2030, and that EVs will make up one-third of all motor vehicles by 2040.

The world has moved from a scenario in which the people talking about EVs “seemed kind of crazy” to one in which more than 1 million EVs were sold last year, with major automakers moving into the market, Sekine said.

Joe Martens, director of the New York Offshore Wind Alliance, detailed some of the “stunning” developments in offshore wind mentioned by Rhodes.

Wind farms are growing in scale along with the size of wind turbines, Martens said, noting that General Electric this month announced the development of the largest-ever offshore wind turbine, a 12-MW giant standing 853 feet tall.

“New York is off to a very good start,” Martens said, noting that the state has set a goal of 2.5 GW of offshore wind by 2030 and issued a master plan for the industry, while the Long Island Power Authority last year signed a contract with Deepwater Wind for 90 MW of wind power from what will be the largest offshore wind farm in the U.S. when it becomes operational in 2022.

Capture the Energy Energy Storage — | *Bloomberg New Energy Finance*

The state plans to conduct offshore wind solicitations over the next two years, each a minimum of 400 MW. (See NY Offshore Wind Plan Faces Tx Challenge.)

Also last year, the New York State Energy Research and Development Authority recommended that the U.S. Bureau of Ocean Energy Management establish at least four new wind energy areas off the state’s coast, each capable of siting a minimum of 800 MW of generation, Martens said.

“There is cause for optimism” regarding the prospects of combining storage with offshore wind projects in New York, Martens said. The Massachusetts offshore wind solicitation in December provided one hopeful sign, with two out of three bidders pairing storage with their generation plans. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

Martens also mentioned Statoil’s recent bid to combine offshore wind with storage off the coast of Scotland. “The purpose of that was to teach the battery when to hold back and store electricity and when to send power to the grid, which is obviously the Holy Grail of trying to figure out how to maximize profits,” he said.