Page 1196 – RTO Insider

March 20, 2018

PJM Stakeholders Explore Cost Containment Complexities

By Rory D. Sweeney

There’s more to transmission planning cost containment than simply comparing estimates among proposals, stakeholders learned last week at a special session of the PJM Planning Committee on the issue.

While all sides presented differing opinions, they also seemed to strike a conciliatory tone.

pjm ferc cost containment — Stakeholders at PJM’s Special Planning Committee meeting on cost containment last week debated whether requiring staff to consider cost-containment offers into transmission planning would be overall beneficial or deleterious to customers and the grid. Acker | © *RTO Insider*

Staff highlighted procedural and process challenges of adding cost containment as a factor in decisions, including the potential impact the extra analysis would have on the timing of developing planning models. They also explained that project costs often must be considered as a range, rather than a specific number, which complicates comparisons.

LS Power’s Sharon Segner walked through the final two of four templates her company has proposed to help PJM standardize its comparison of transmission proposals based on several factors, including transparency, the strength of the cost-containment proposal and developers’ rate requirements. Her cost-cap analysis, for example, would create a checklist of attributes, and proposals would be categorized based on how many of those attributes PJM believed each one had.

“If it’s a weak cost cap, it’s essentially treated as a cost estimate,” Segner explained, noting that estimates would calculated based on the in-service year rather than at the time of the proposal.

“We want a better understanding about how PJM values cost containment. … From my company’s standpoint, we think there needs to be improvement [in the PJM comparative cost analysis] from the status quo,” she said. “There’s been a lot of good points raised by the transmission owners in saying … these projects have to meet the technical need and they have to solve the technical problem. … That is my company’s position as well.”

A series of events at January’s Markets and Reliability Committee meeting culminated in the issue going back to the Planning Committee for additional consideration and LS retaining control of the main proposal that the MRC will consider. To ensure its proposal has enough support to be implemented, LS narrowed the focus of revenue requirement caps to include just total all-in return on equity and capital structure cap proposals and removed the ability to offer caps on operations and maintenance costs. A representative for NextEra Energy supported removing the operations and maintenance cost-cap option. The proposal goes back before the MRC at its May meeting. (See “Transmission Flashpoint,” PJM Markets and Reliability Committee Briefs: Jan. 25, 2018.)

Transource Energy’s Brian Weber made a presentation that endorsed some of the LS goals but also opposed the overall proposal. He said it would put the focus on cost containment and “severely limit” what developers offer, moving PJM away from the “creative solutions” of the sponsorship model for transmission planning and toward the procurement model used in other RTOs/ISOs.

PJM’s sponsorship model is similar to that used for architecture proposals, where bidders are encouraged to develop their own creative solution to necessary criteria and staff are prepared to consider a wide range of potential factors. The procurement model is more like the bidding process for construction contractors, where the design has already been chosen and applicants are mostly competing on cost. A hybrid approach that tries to focus on both creativity and cost could limit the ability to achieve either of them.

RTO staff underscored the implication in their analysis of the changes necessary to consider cost-containment factors.

“Almost everyone else in the industry has one bucket of risks,” PJM’s Mark Sims said. “It adds a dimension to the level of analysis that PJM has to do.”

“I think the pragmatic reality of this is that developers will limit their submissions” due to their project designs being subsequently awarded to undercutting competitors, Weber said, adding that the plan “provides pretty significant disincentive to provide value” through creativity.

Erik Heinle with the D.C. Office of the People’s Counsel praised the technical creativity and asked why it couldn’t be replicated on the financial side.

“Great technical flexibility should be matched with flexibility and creativity in the cost arena as well,” he said.

“There is a difference between creativity and blind risk taking,” Weber responded. “Which risks should developers be expected to take? They should be expected to take the risks that they can control.”

Earlier in the meeting, PSEG Services’ Vilna Gaston had said she hoped that incorporating those cost-focused measures wouldn’t lead to a situation like the fatal bridge collapse in Florida on March 15. Ruth Ann Price with Delaware’s Division of the Public Advocate agreed and noted that media coverage showed the bridge contractor had several past successes along with several safety complaints.

Weber touched on this concern in his response to Heinle, noting that he has seen developers take risks in their cost-capped agreements filed at FERC and that he is confident they could not have had the time to perform the due diligence necessary to ensure they’re doing it correctly.

Building Consensus

Alex Stern with Public Service Electric and Gas presented transmission owners’ analysis of how easily the current proposals could implement design components that were previously identified. The analysis found that PJM’s original proposal could implement the principles with relative ease; however, it was vetoed at the MRC meeting in January.

Stern said he “fully respect[s]” concerns about gold-plating the system but acknowledged that “PSE&G would probably be at a competitive disadvantage because we’re not going to lower our standards for the customers of our state and anything we’re involved in … to the minimums that were set in [the Designated Entity Design Standards Task Force]. We’ll try to abide by what we believe are the right standards.”

He said a reasonable alternative would be limiting cost caps to construction costs.

“We’re not supportive of cost caps. Having said that, as part of the negotiation and consensus building, we were willing to try to consider taking that step. … I don’t like it, but I would concede … that it’s probably the one that provides bang for the buck to the ratepayer with an ability to track and achieve objectives. It’s probably the most enforceable,” Stern said, suggesting that implementing cost containment is such a big change that it should be eased into slowly.

“The sponsorship model might not be the best model for complex cost caps and there are challenges. I’m not suggesting it’s not doable; I’m suggesting there’s more challenges with it,” he said. “And that begs the question, do we change up the paradigm to facilitate broad-based cost caps recognizing there’ll be impacts to [the Reliability Pricing Model], they’ll be impacts to the [Regional Transmission Expansion Plan], there’ll be impacts to the interconnection queue … or do we start smaller and see how things work first?”

Heinle and Price urged implementing some way to standardize comparisons so their offices have a better chance to engage in the process. Price said staff in her office who don’t fully understand the process will immediately decline expensive projects, “so I need information to convince them.”

“If we compare apples to apples to apples, it becomes a lot easier,” she said. “I think most offices want to be actively involved in projects in their regions, but they need to the tools to be reasonably [informed].”

PJM’s Steve Herling said the process is already completely optimized and there is no lag time available for additional analysis on understanding and comparing values.

“There comes a time where there’s nothing left you can do. … You’ve got a fixed start time and a fixed end time and everything you add has to fit in between” to finish the annual RPM case build, he said. “We don’t believe you can fit it in the time frame you have. There is more work required than can be fit into this schedule.”

He pointed out that it might not be possible to standardize the process to show whether costs are comparative costs.

“There are going to be times when something is a little more than you need and there’s going to be times when it’s a lot more than you need. People make proposals. Our job is to figure out whether it’s a little more than we need or a lot more than we need and then figure out is the additional cost worth it,” he said.

March 20, 2018

NYPSC Approves Higher Rates for Bitcoin Miners

The New York Public Service Commission on Thursday ruled that upstate municipal power authorities can charge higher electricity rates to cryptocurrency companies in order to prevent disproportionate increases in local retail rates.

The intense computer processing by cryptocurrency companies, such as Bitcoin miners, requires large amounts of electricity, prompting them to move their server farms upstate for the relatively cheap hydropower.

The order (18-E-0126) cited the situation in Plattsburgh, where monthly bills for average residential customers increased nearly $10 in January because of two cryptocurrency companies operating there.

The New York Municipal Power Agency, an association of 36 municipal power authorities in the state, petitioned the commission regarding concerns that these high-density load customers were having a negative impact on local power supplies.

Cryptocurrency companies look for commercial or industrial facilities where they can access the large amounts of power required for their banks of computers to create — or “mine” — digital currency.

The commission “must ensure business customers pay an appropriate price for the electricity they use,” said PSC Chair John B. Rhodes. “This is especially true in small communities with finite amounts of low-cost power available.”

In some cases, such currency miners account for 33% of a municipal utility’s total load, an “extraordinary amount” of power for a single customer to use, the commission said. By comparison, a large paper manufacturer employing hundreds of workers might use one-quarter the amount of electricity per square foot of such customers.

PSC Slashes National Grid Electric Rate Increase

The PSC approved three-year electric and gas rate plans for National Grid that came up far short of the company’s requests.

The ruling (17-G-0239) limits electricity revenue increases in the first year to only $43 million (1.7%), rather than the $326 million (13%) sought by the utility. Natural gas revenue increases in the first year were capped at $13 million (2.4%), compared to the requested $81 million (14%).

A typical residential customer using 600 kWh of electricity per month under the new rate plan would see a total monthly bill increase of $2.22 (2.9%) in the first year starting in April 2018, $3.03 (3.8%) in the second year and $3.25 (3.9%) in the third year. Eligible low-income electric customers will see a bill reduction of up to 55%.

The plan “includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Rhodes said. “It moves forward the state’s climate agenda by expanding energy efficiency while funding non-wire alternatives and other REV-like initiatives for smarter investments.”

PSC Continues Crackdown on ESCOs

The commission ruled to restrict three energy service companies (ESCOs) from serving low-income customers while granting a fourth company its petition to serve them after demonstrating that it could guarantee a 1% savings against the utility price.

The March 15 actions (17-G-0239) included suspending the ability of Flanders Energy to market to and enroll new residential and nonresidential customers and directing the company to refund any overcharges to customers that it enrolled without proper authorization. Flanders does business in Consolidated Edison’s service territory.

The commission also denied separate petitions from Drift Marketplace and M&R Energy Resources for rehearing on original orders denying the companies’ requests to serve low-income customers. Neither company was able to demonstrate how it was going to guarantee savings, the rulings said. Drift does business in Con Ed’s territory, while M&R operates in the Central Hudson Gas & Electric and Orange & Rockland Utilities areas.

“Our ongoing efforts to reform the ESCO market remains a priority,” Rhodes said. “In instances where an ESCO proves they are fair to customers, we allow them to continue their activities in New York to bring choice and energy services to customers.” (See NYPSC Limits ESCO Service, Sets New DER Compensation.)

The commission approved New Wave Energy’s petition, which stated the company will immediately assign all its customers that participate in the utility assistance program to its guaranteed savings product. New Wave operates in the National Grid, New York State Electric and Gas, National Fuel Gas and Rochester Gas & Electric service territories.

The state’s Department of Public Service has provided evidence that many ESCOs have been significantly overcharging many mass market customers. It has also found many ESCOs have abused customers via high-pressure and deceptive sales tactics, teaser contracts and exploiting vulnerable elderly, immigrant and low-income populations.

PSC Approves Tier 2 Changes to CES

The PSC expanded Tier 2 of the state’s Clean Energy Standard, changing Maintenance Tier eligibility to include certain renewable facilities in operation prior to Jan. 1, 2015, and establishing delivery requirements into New York consistent with those for Tier 1.

The order (15-E-0302) applies only to eligible, pre-existing renewable facilities and expands the number of projects eligible for funding under the program in cases of need. The commission also increased the size threshold for eligible existing hydropower facilities from 5 MW to 10 MW, and provided for a streamlined review process, as well as a standard contract term of three years with the potential for contract renewals.

The commission said the changes will reduce the administrative burden on facilities seeking maintenance support and will better reward the environmental contributions of existing baseline renewable resources.

PSC Hems on Public Policy Tx Planning

The commission on Friday declined to identify and refer any public policy transmission planning requirements to NYISO.

The March 16 order (16-E-0558) directed DPS staff to work with the ISO and the New York Transmission Owners to identify potential transmission constraints on the bulk and non-bulk systems that may warrant the future identification of a public policy requirement, considering current and projected resources.

bitcoin mining cryptocurrency ny psi — | *NYSEG*

The commission said that while it “recognizes that there are certain regions, such as the northern and southwestern parts of the state, where additional transmission facilities may support the deployment of renewable resources, the extent and magnitude of such needs requires further consideration.”

NYISO’s Tariff, approved by FERC, says that the PSC may identify which public policies, if any, constitute requirements; if the commission identifies such a need, the ISO will then solicit and evaluate proposed solutions to it.

— Michael Kuser

March 20, 2018

ISO-NE Planning Advisory Committee Briefs: March 15, 2018

ISO-NE’s draft 10-year Capacity, Energy, Loads and Transmission (CELT) forecast is reducing projected summer loads in 2026 by nearly 6% in part because of a sharp increase in projected energy efficiency, RTO officials told the Planning Advisory Committee on Thursday.

The draft 2018 CELT reduces the net annual energy forecast by 4.5% lower in 2025 with the net summer 2026 50/50 forecast reduced by 6.0% and the summer 90/10 forecast cut by 5.8%.

The behind-the-meter solar photovoltaic forecast for 2026 is about 0.6% higher, with energy efficiency boosted by 16.2%. The new report foresees about the same regional economic growth through 2026 as last year’s forecast.

The gross 50/50 load forecast — calculated before reductions from passive demand resources (PDR) and behind-the-meter PV — was cut by 2.7%, and the gross 90/10 forecast was 2.8% lower. The gross annual energy consumption forecast increased by 0.3%.

ISO-NE IPSAC Byron nuclear plant CELT Report — ISO-NE’s draft 2018 CELT report increases the gross annual energy consumption forecast by 0.3% over the 2017 study. | *ISO-NE*

The solar PV forecast included the expected impact of the tariffs imposed on solar panels by the Trump administration. It also includes a 0.5%/year PV degradation rate to account for solar panels’ declining conversion efficiency over time, based on research by the National Renewable Energy Laboratory.

The RTO develops the CELT 10-year forecast as part of its annual forecast process.

The finalized forecasts will be shared at the April 26 PAC and published by May 1.

Update on Transmission Projects

ISO-NE has put 22 upgrades in service since October, the RTO said in its transmission projects and asset condition update, including the new Scobie–Tewksbury 345-kV line and five other projects in the Boston area.

The RTO reported an $11.9 million increase in the estimate cost for Project 945–Adams in Central Western Massachusetts (installing two new 115-kV breakers and replace two existing 115-kV breakers and associated line relocations). The cost increased because of “an enhanced understanding of the multiple site condition impacts on the construction plan,” the RTO said.

That increase was more than offset by a $12.3 million reduction in the estimated cost of Pittsfield/Greenfield Projects 1662, 1664, 1665 and 1663 because of “project cost alignments.”

No new reliability or market efficiency-based transmission system upgrades have been added to the Regional System Plan project list since October. However, 36 new projects totaling $549.5 million have been added to the Asset Condition list, largely for the replacement of aging infrastructure.

Eastern Connecticut 2027 Needs Assessment

The PAC heard an update on the 2027 Eastern Connecticut (ECT) Needs Assessment, which is evaluating reliability needs for the 10-year period extending until 2027.

The draft needs analysis found violations of low-voltage and high-voltage reliability criteria for first and second contingencies as well as some severe thermal violations in some areas following second contingencies. All the violations were also found to be present in 2020.

ISO-NE announced the needs analysis last June. The previous ECT 2022 Needs Assessment report was finalized in June 2015 but work on solutions to address the region’s time-sensitive needs were suspended in February 2017 pending a review of RTO criteria, assumptions and methodologies impacting needs assessments and solutions studies.

The RTO said the review had “sufficiently progressed” to allow initiation of the new study.

The final scope of work was posted earlier this month, along with responses to stakeholder comments.

The study area is a rectangle bounded by the Long Island Sound on the south and the Massachusetts border on the north, with the eastern boundary the Rhode Island border and the western boundary just west of New London.

“This area hasn’t been studied in a long, long time,” said Brian Forshaw, a consultant for Connecticut Municipal Electric Energy Cooperative (CMEEC). “So, we’re glad to see things are progressing from a needs assessment to solutions studies.”

He said, however, that the needs assessment was “more limited than it should have been” and criticized the “top-down” load forecast.

The finalized needs assessment will be posted by May 31. The RTO will work with Eversource Energy and CMEEC to address the needs on their transmission systems.

Eversource Equipment Replacements

Eversource made a presentation on the replacement of its Montville 16X 115/69-kV transformer, which is at its end of life after 67 years. Total project cost is estimated at $6.3 million (-25%/+50%).

The company also provided an update on replacement of the Card Street 11F-5X autotransformer, which was originally presented in September.

The September PAC presentation recommended its replacement with a three-phase spare unit located at the Montville 4J Substation. Eversource said it conducted a re-evaluation that determined the summer long-term emergency rating of the replacement could be increased from 458 MVA to 512 MVA. The existing autotransformer is rated at 491 MVA. The estimated cost remains $8.6 million (+50%/-25%).

Transmission Planning Technical Guide

ISO-NE is continuing its revisions to the Transmission Planning Technical Guide, which was reorganized last year to a new format with four main sections: Introduction, Modeling Assumptions, Reliability Criteria and Guidelines, and Analysis Methodology.

Revision 2 was posted on the ISO website on Nov. 14, 2017.

Staff is now updating the appendices for consistency with the RTO’s style guide and publication template:

App. A – Terms and Definitions (Expected Q2 2018): Adding/removing terms and definitions; adding references to NERC and Northeast Power Coordinating Council glossary of terms.
App. B – Fast Start Generation List: Retired after change to probabilistic methods for base case dispatches of transmission needs assessments and solution studies.
App. C – DR Modeling Guide (Expected Q2 2018): New terminology associated with price responsive demand (PRD).
App. D – Damping Criteria: Retired after criteria moved to Section 3.3.3 of Technical Guide.
App. E – Voltage Sag Guideline (Expected Q2 2018): Update to clarify methodology.
App. F – 2000 STF Memo (Draft Posted March 2018): Updated diagrams for clarity.
App. G – Phase Shifter Guide (Draft Posted March 2018): Changed name from Modeling Guide to Phase Shifter Guide to focus on content of appendix; remove Sackett Phase Shifter and 3rd Waltham Phase Shifter; update all descriptions to match current operating practices.
App. H – No-Fault Contingencies (Draft Posted March 2018): Updated to current version of Planning Procedure No. 3.
App. I – Transfer Methodology (Draft Posted March 2018): Reorganized structure to align with Technical Guide format; new terminology associated with PRD.
App. J – Load Modeling Guide (Draft Posted March 2018): Added descriptions for solar PV modeling; added equations to explain methodologies; new terminology associated with PRD; adding Area-Owner-Zone-Bus assignments.

Stakeholders can provide comments for 15 days after the posting of each document on the PAC website to PACMatters@iso-ne.com. Comments on Appendices F, G and H are due April 3.

The PAC’s next meeting is April 26 at the Doubletree Hotel in Milford, Mass.

— Rich Heidorn Jr.

March 20, 2018

Powelson Tells New England to Learn from Pennsylvania

By Michael Kuser

BOSTON — FERC Commissioner Robert Powelson said last week that New England needs to overcome its aversion to new energy infrastructure to avoid natural gas shortages in the winter.

“You all burned 2 million barrels of oil during this recent bomb cyclone,” Powelson said at Raab Associates’ 157th New England Electricity Restructuring Roundtable on Friday. “We didn’t do that in Pennsylvania; we burned a lot of natural gas, we ran economic nuclear plants and we integrated renewables with close to 1,400 MW of wind capacity.” (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)

ISO-NE FERC Natural Gas Robert Powelson — van Welie | © *RTO Insider*

Paired in a session with ISO-NE CEO Gordon van Welie, Powelson was the only FERC commissioner who voted against accepting the RTO’s Competitive Auctions with Sponsored Resources (CASPR), the grid operator’s two-stage capacity auction to accommodate state renewable energy procurements.

Powelson wrote a dissent calling the construct “a complicated, patchwork solution that will neither accommodate the desires of the states, nor send proper price signals to market participants.” (See Split FERC Approves ISO-NE CASPR Plan.)

“Here you are today, with 15 million customers in the New England market during these weather events paying some of the highest gas [and electricity] costs in the country,” Powelson said. “My good friend here [van Welie] will say, ‘Well that was the least-cost resource.’ Well so much for your [greenhouse gas] requirements that you’ve set forth as state regulators.”

Powelson did say he was “extremely impressed” with the RTO’s capacity auction results last month, where the clearing prices were the second-lowest in the history of the market. (See ISO-NE Capacity Prices Hit 5-Year Low.)

Despite his praise of some aspects of the New England wholesale electricity market, Powelson joked, “Gordon, I might have you come down to PJM, do a little 12-step program.”

Tectonic Baseload Shift

Extreme weather events put regulators on a “tipping point” of addressing reliability, Powelson said.

“We’re seeing this tectonic shift in our baseload resources of accelerated retirements of coal and nuclear plants,” he said. “Last time I checked, we’re not building coal plants in New England — is that correct? By the way, I live in Pennsylvania, and we’re not building a lot of coal plants in Pennsylvania; in fact, I don’t think we’re building any.

“I looked at the last two capacity auctions; the clearing resource is a combined cycle gas plant with a 6,600 heat rate, sourced under the greatest blessing we have — and I don’t want any boos in this room, but Marcellus shale has had a profound impact on my state’s economy,” he said.

Powelson continued a theme he had taken up earlier in the week at the American Council on Renewable Energy’s (ACORE) Renewable Energy Policy Forum in D.C., where he said that ISO-NE’s Operational Fuel Security Analysis report issued in January was “like a horror story.” The study found the region will face energy shortfalls because of inadequate natural gas supplies in almost every fuel-mix scenario by winter 2024/2025. (See Report: Fuel Security Key Risk for New England Grid.)

“Siting is hard, but you gotta get there,” he told the ACORE conference Wednesday, citing the region’s inability to win approvals for new gas pipelines or transmission to import Canadian hydro.

“Fifteen million customers in [New England] paid the highest gas-basis costs in the country and they were less than 200 miles from the Leidy gas hub in Pennsylvania in a $2.34/MMBtu trading market,” he continued. “I recognize it’s probably going to be hard to get 30-inch pipe into New England, but in lieu of that, we’ve got to solve this problem. … This is all going to be a failed experiment if we have reliability issues in the New England states.”

Massachusetts Sierra Club Director and Newton City Councilor Emily Norton challenged Powelson at the Boston conference, saying she was “surprised and disturbed” at his “lack of attention to the full costs” inherent in choosing fracked gas, such as the water pollution in Pennsylvania.

“To that customer or to your constituent, I think they should have peace of mind that they’re going to have safe, affordable and sustainable energy to their homes,” Powelson said. “A lot of people in Pennsylvania are switching fuel from oil to natural gas. Not everybody can afford a rooftop solar installation on their house, or a battery storage behind that, or for that matter, a propane or natural gas-fueled Generac or Cummings generator.”

ISO-NE’s 2025 lookout has some alarming points for a regulator, he said. He added that he had read about the risk of rolling blackouts and other emergency measures becoming necessary in New England if the region didn’t act to secure the supply of natural gas for its generators.

“Look, what happens with Millstone?” Powelson said. “I don’t know, I’ll leave that to Connecticut, [PURA Vice Chairman Jack] Betkoski and others, and Gov. [Dannel] Malloy. What happens more recently in this post-bomb cyclone with lack of adequate gas supply where you’re dealing with storage issues here in the New England market? There’s a case where storage is meeting your demand right now, but we don’t have adequate pipelines into the market.

“The reality for this region is that state governors, both Democrat and Republican, are committed to incent investment and develop policies that support that investment, which is a good thing,” Powelson said. “In lieu of a national energy policy, the states have to drive that. … The states are getting ahead of the federal government. So be it. … But we’re also building a lot of things in the PJM footprint.”

Resilience of the Grid

Closing on the topic of resilience, Powelson said that he and his fellow FERC commissioners “are in a very good spot.”

“The feedback from the RTOs has been what we expected,” he said. “If a resource needs to close and exit the market, there should be orderly entry and exit, and I use my example of PJM, where roughly 13,000 MW have come offline. That’s the reality of the market.”

Price suppression created by resources like cheap natural gas is displacing uneconomical resources, “so why should we go out there and pick winners and losers in a market?” Powelson said. “To do what? Hurt the other, more efficient units in the market or send bad market signals?”

Van Welie said the question is how much further the RTO can go with retirements before they must slow them down.

The National Oceanic and Atmospheric Administration last fall “forecast a return to ‘normal’ winter after two unseasonably warm ones, whatever ‘normal’ is in New England anymore,” van Welie said. “But no one was predicting a 100-year cold snap over the Christmas-New Year break.”

The RTO’s winter preparedness program created an incentive for the oil-burning generators to fill up going into the winter, but when it came to resupplying during the winter, they were buying on the spot market, van Welie said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)

“And they were competing with home heating on the spot market,” van Welie said. “So then we hit all kinds of logistics problems, where truck drivers don’t have enough hours to move the fuel around, and the oil suppliers are going to supply homes before they’re going to supply generators.”

The RTO’s job is “to procure the reliability services we need through the wholesale market construct,” he said. “In our resiliency filing with FERC, we are asking for a year to work things out, asking to wait until the second quarter of 2019.”

Moderator Jonathan Raab asked van Welie: “If CASPR is a transition mechanism, what might be a long-term solution to help states ‘achieve’ their climate reduction commitments without undermining the integrity of wholesale markets?”

“The obvious answer is carbon pricing, but we’re not going to do that as none of the states want to,” van Welie said. “It’s really going to have to be the states that take the lead on that.”

— Rich Heidorn Jr. reported from the ACORE conference in D.C.

March 20, 2018

DC Circuit Rejects NorthWestern Reg Service Appeal

By Tom Kleckner

The D.C. Circuit Court of Appeals on Friday upheld FERC’s determination that NorthWestern Energy’s proposal to recover the costs of a generating station providing regulation service was not just and reasonable.

The court rejected NorthWestern’s claim that FERC’s decision was “arbitrary and capricious” and violated the Administrative Procedure Act’s requirement that an agency’s decision be “reasonable and reasonably explained” (No. 16-117).

The Midwest utility had filed with FERC to revise its rates to recover the costs for its Dave Gates Generating Station, a gas-fired facility built in Montana to provide its own regulation service, after purchasing 60 MW annually of the service from other utilities became too expensive. The 150-MW plant went into service in 2011.

Dave Gates Generating Station | *Corval Group*

NorthWestern proposed to use Gates to supply 105 MW of regulation service to all its customers. Retail customers would pay for 45 MW at a state-approved rate, separate from Schedule 3 under NorthWestern’s Tariff with FERC. Retail and wholesale customers would pay for the remaining 60 MW under Schedule 3, which was calculated by multiplying the plant’s revenue requirement by 0.57 (the ratio of 60/105).

The utility also proposed to charge customers for fuel costs but credit them for any revenue the Gates plant might bring in from off-system sales and other nonregulation service sales; charge customers for the regulation service that it purchased during a 2012 outage; and charge customers for any regulation service that NorthWestern might need to purchase during future outages.

FERC affirmed an administrative law judge’s order reducing NorthWestern’s proposed rate by: (1) multiplying the revenue requirement by a different cost-calculation ratio of 0.13 (19/150); (2) excluding fuel costs from the Schedule 3 rate and rejecting the utility’s crediting arrangement; (3) requiring the utility to make a separate filing to recover costs associated with the 2012 outage; and (4) requiring it to make separate filings before charging customers for any regulation service that it might need to purchase during future outages.

The commission directed NorthWestern to refund its customers the difference between the proposed rate and the modified rate. It also denied a request for rehearing.

Northwestern Energy Generating Facilities | *Northwestern Energy*

NorthWestern raised four challenges in arguing the case before the D.C. Circuit in December. It said FERC “unreasonably” reduced the numerator of its proposed cost-calculation ratio from 60 MW to 19 MW, but the court said the commission “reasonably modified” the calculation after determining that only 19 MW were needed to serve Schedule 3 customers.

The utility also contended that the commission arbitrarily increased the denominator of its proposed calculation from 105 MW to 150 MW. The court disagreed, noting that under FERC precedent, the denominator should reflect the nameplate capacity (150 MW), not just the megawatts that NorthWestern planned to devote to regulation service.

Third, NorthWestern argued that FERC inadequately explained its decision not to allow fuel costs and failed to account for the fact that the utility may be able to retroactively recover fuel costs. The court ruled otherwise.

Finally, the utility said the commission acted arbitrarily by requiring it to make separate Section 205 filings to recover costs associated with the 2012 outage and for any regulation service that it might need to purchase during future outages. FERC adopted the ALJ’s reasoning, which justified the separate proceedings on reasonable grounds, and “acted reasonably here as well,” the court ruled.

Writing for the court, Judge Brett Kavanaugh said he was not persuaded by NorthWestern’s challenge of FERC’s order for refunds. He noted that the commission “concluded that NorthWestern over-collected from its Schedule 3 customers, making this the kind of case in which FERC ordinarily orders refunds.”

“That determination was reasonable,” he said.

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.”