Page 1110 – RTO Insider

May 10, 2019February 12, 2025

Overheard at IPPNY Spring Conference 2019

ALBANY, N.Y. — With Democrats now in control of both chambers of the state legislature, New York power producers might reasonably expect faster legislative support for Gov. Andrew Cuomo’s goals of 70% renewable energy by 2030 and a carbon-neutral grid by 2040.

But uncertainty still looms around those efforts, according to John Reese, senior vice president of Eastern Generation and chairman of the Independent Power Producers of New York (IPPNY).

IPPNY held its 33rd annual Spring Conference in Albany on May 7-8. | © RTO Insider

“With all the changes going on, it’s hard to assess whether we’re going down the right path or a blind alley,” Reese said Wednesday at IPPNY’s 33rd annual Spring Conference.

A New York City resident, Reese cited a recent move by the mayor and City Council to improve energy efficiency in buildings and to revive the Champlain Hudson Power Express project to bring 1,000 MW of Canadian hydropower to Manhattan.

John Reese | © RTO Insider

“IPPNY has been a long opponent to that project, particularly when it comes to the issue of carbon,” Reese said. “If you’re moving existing resources from one place to another, you’re not saving any carbon; you’re playing a shell game. … Certainly the preference would be to have new New York resources that contribute to the tax base, that contribute to jobs.”

The Climate Mobilization Act passed by the City Council on April 18 includes a definition of renewable energy credits that conflicts with the state’s Clean Energy Standard regarding the role of hydroelectric resources, said State Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee.

“The city’s language would allow certain large-scale hydro resources, which currently are not eligible [for RECs] under CES due to their evolving empowerments, that are not sources of methane emissions, to be eligible for the city’s program, hence the conflict,” Parker said.

Kevin Parker | © RTO Insider

“The conflicting RECs mean that the city’s end consumers and taxpayers would need to pay twice, once for the city’s REC and then again for the state’s REC [for other resources], and that Con Ed would be required to buy under the CES … which would require extra payment for Con Ed to secure eligible RECs,” Parker said.

The city’s program to import non-CES-eligible Canadian hydro also sends a negative signal to renewable energy investment in the state, especially for offshore wind, he said.

State Assemblymember Michael Cusick (D), chair of the Energy Committee, said he and Parker co-sponsored legislation that would require a feasibility study on achieving the state’s clean energy goals, “to support the incredible growth in offshore wind, energy storage and other resources.”

Michael Cusick | © RTO Insider

“The bill passed out of our committee, and I’ve spoken with people on getting that language in whatever package we have at the end of the session,” Cusick said, adding that he would also be pushing legislation on grid security, particularly cybersecurity.

Gavin Donohue | © RTO Insider

IPPNY CEO Gavin Donohue thanked both lawmakers for “leading the charge” in dealing with the New York Power Authority in the competitive marketplace and legislating public procurement procedures through “a combination of practicality and reasonableness.”

NYISO Interim CEO Robert Fernandez touched on the same subject when he said, “The focus today is on buyer-side mitigation.

“At the beginning [of NYISO markets 20 years ago], many people were concerned about suppliers setting artificially high energy prices and improper wealth transfers,” Fernandez said. “Instead, today we grapple with uneconomic entry, subsidies and price suppression in the capacity market.

“We have mandatory buyer-side mitigation rules, we apply them, and it’s the economics of a particular project that will determine whether that will be subject to an offer floor or not,” he said. “That’s all that’s going to determine that. There are no outside influences telling us how to move the meter on buyer-side mitigation testing.”

Carbon Pricing and Technology

Fernandez also referred to NYISO’s work on pricing carbon into its wholesale energy markets, which has relied heavily on assistance from consulting firm Analysis Group.

“I’m hopeful that with [Analysis Group senior adviser] Sue Tierney’s help we can get the state on board and get this concept down to More Details Divulged on New NYISO Carbon Pricing Study.)

Dale Bryk, the governor’s deputy secretary for energy and environment, highlighted energy efficiency as a “huge economic engine” employing thousands of electricians and contractors throughout the state.

Cuomo in January proposed increasing the state’s renewable portfolio standard from 50% to 70% by 2030, nearly quadrupling its offshore wind energy goal to 9 GW by 2035, doubling distributed solar generation to 6 GW by 2025 and deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)

Dale Bryk | © RTO Insider

Bryk dismissed the idea of the state using carbon offsets as an alternative to reducing pollution as “some kind of get-out-of-jail free card.”

“If you look at the experience in New York with Regional Greenhouse Gas Initiative offsets or components, they were never used,” Bryk said. “The way the program was designed, that really never made sense.

“If we’re talking about decarbonizing every sector, there really isn’t any place to get offsets, so the framing is different, but the concept of carbon neutrality and that flexibility is absolutely critical,” he said. “It’s not always linear, it’s not always numeric … we’re all-in for performance metrics, but we want to develop them in a professional way.”

Mark Younger | © RTO Insider

Mark Younger of Hudson Energy Economics said Bryk had neglected to address carbon pricing. “I don’t see how you can do an efficient change without internalizing the externalities … which all the literature shows lets you put the solar resources in an area where they knock out carbon rather than just happen to get subsidies from the state. So how do you do this without putting a price [on carbon], not just in the electric sector, but in all the sectors?”

“We have carbon pricing with RGGI, but I think of it as a cap on pollution that’s going down over time,” Bryk replied. “You sell pollution permits, that’s your price. The driver is the cap. We want people to have a price signal and see the long-term price signal and declining cap. What I care about is pollution going down … so you don’t only have a price, you don’t lead with price. We want to have both the price signal, the cap, and energy efficiency policies, because it’s not all about price.”

Jacob Worenklein | © RTO Insider

Jacob Worenklein, chairman of Ravenswood Power Holdings, which owns the largest power plant in New York City, said the great challenge is technology, “because we can in fact reduce carbon to zero right now, but nobody would do so … because the cost would be so huge.”

“When will we get the technology and when can we expect to begin to test technology that will enable us to do exactly what we’re talking about, say, by the 2035 or so time frame?” he asked.

Bryk likened the idea of encouraging new technologies to that of being “proactive with” workforce development — “and not just assume that that’s going to happen because the investment is there.”

“Just because you have policies … even with the price signal, that doesn’t bring you all of the technological innovation that we may need,” Bryk said. “What can the state be doing to help drive that R&D work and the commercialization demo projects?”

– Michael Kuser

May 10, 2019

Exelon to Close Three Mile Island

By Michael Brooks

Exelon on Wednesday announced it will permanently shut down the nearly 45-year-old Three Mile Island nuclear plant in Londonderry Township, Pa., by Sept. 30.

The company is making good on its May 2017 promise to close the plant absent the Pennsylvania General Assembly providing it subsidies before June 1 of this year, the deadline for purchasing its fuel. Each house of the legislature has been considering its own bill supporting nuclear generation, but the Senate has adjourned until June 3, and the House of Representatives will only meet three more times before the end of the month.

“Although we see strong support in Harrisburg and throughout Pennsylvania to reduce carbon emissions and maintain the environmental and economic benefits provided by nuclear energy, we don’t see a path forward for policy changes before the June 1 fuel purchasing deadline for TMI,” Kathleen Barron, Exelon senior vice president, government and regulatory affairs and public policy, said in a statement.

“While TMI will close in September as planned, the state has eight other zero-carbon nuclear units that provide around-the-clock clean energy, avoiding millions of tons of carbon emissions every year. We will continue to work with the legislature and all stakeholders to enact policies that will secure a clean energy future for all Pennsylvanians,” she said.

But at least one state legislator earlier this week predicted the plant would close regardless of what the General Assembly did. (See Pa. Lawmaker Contends TMI Rescue Unlikely.) The bills being considered would create a third tier in the state’s Alternative Energy Portfolio Standard program, from which suppliers must buy an additional 50% of their power by 2021.

“Today is a difficult day for our employees, who were hopeful that state policymakers would support valuing carbon-free nuclear energy the same way they value other forms of clean energy in time to save TMI from a premature closure,” said Bryan Hanson, Exelon senior vice president and chief nuclear officer. “I want to thank the hundreds of men and women who will continue to safely operate TMI through September.”

Nuclear Energy Institute CEO Maria Korsnick blamed the plant’s closure on “a flawed and distorted energy market that fails to value the attributes of nuclear power.”

“The shutdown will lead to the loss of hundreds of Pennsylvania jobs, more than $1 million in taxes annually to the community and more than 7 million MWh of carbon-free energy,” she said. “It’s in our nation’s best interest for lawmakers both in state capitals and Washington to push for market solutions and polices that value all clean energy sources, or face the economic and environmental consequences for generations to come.”

Three Mile Island is home to two reactors. Exelon has owned Unit 1 since 2000, when the company formed through the merger of Unicom and PECO Energy, the latter of which owned a 50% stake in the unit. The company purchased the other half in 2003 and began operating the plant directly in 2009. The same year, the unit was granted a license extension by the Nuclear Regulatory Commission to April 19, 2034.

Unit 1 was shut down for six years after the partial meltdown of Unit 2 in 1979, the worst commercial nuclear power plant accident in U.S. history. In 1985, over fierce opposition from nearby residents and anti-nuclear activists, NRC voted 4-1 to restart operations.

Exelon plans to begin transitioning staff within six months of the plant’s shutdown, winding down in three phases to 50 full-time employees by 2022. The company will begin to dismantle the plant in 2074.

May 10, 2019

Mild Weather Undercuts CenterPoint Q1 Earnings

CenterPoint Energy on Thursday reported that mild weather that reduced customers’ power usage drove first-quarter earnings down to $140 million ($0.28/share), from $165 million ($0.38/share) a year ago.

When adjusted for one-time gains and costs, the Houston-based company’s earnings came in at 46 cents/share, falling 4 cents short of Zacks Investment Research’s consensus.

Still, CEO Scott Prochaska said he was pleased with the results.

“While weather-related impacts affected first-quarter earnings, we remain confident in our anticipated 2019 full-year performance. Our utilities continue to benefit from strong customer growth and recovery mechanisms allowing for timely recovery of capital invested on behalf of our customers,” he said.

CenterPoint’s earnings excluded costs and other impacts of its $6 billion acquisition of Vectren. The Indiana utility, the acquisition of which was completed Feb. 1, reported a one-month operating loss of $9 million, which included $20 million in merger-related expenses.

The Indiana Utility Regulatory Commission recently recommended CenterPoint consider smaller-scale options instead of a proposed 700- to 850-MW combined cycle natural gas turbine, company officials said.

“The commission wants to see investment made in ways other than a bet on a single large plant,” Prochaska told investment analysts during a call Thursday.

CenterPoint’s share price closed Thursday at $29.25, down almost 4% from the previous close.

— Tom Kleckner

May 10, 2019

SPP Seams Steering Committee Briefs: May 8, 2019

SPP and MISO stakeholders are reviewing an initial draft of the RTOs’ 2019 Coordinated System Plan (CSP), which will jointly evaluate identified seams issues and determine the need for any interregional transmission projects.

SPP staff intend to “leverage” coordinated transmission needs identified in the RTOs’ transmission planning processes to study whether it makes the most financial sense to develop interregional projects that efficiently address seams needs. The RTOs’ have ditched the joint planning model previously used in the first two CSPs, neither of which resulted in an interregional project. (See MISO, SPP Seek Coordinated Plan in 2019.)

Interregional Coordinator Adam Bell told the Seams Steering Committee on Wednesday that the RTOs’ staff will incorporate the feedback into a final scope document, which will be distributed to the Interregional Planning Stakeholder Advisory Committee.

Stakeholders have until May 17 to send their comments to Bell at abell@spp.org or MISO’s Ben Stearney at bstearney@misoenergy.org.

The RTOs’ staff have committed to completing the study by Dec. 31.

MISO’s M2M Tab with SPP Reaches $60M

SPP earned another $2.3 million in market-to-market (M2M) payments from MISO in March, pushing the latter’s deficit to $60.8 million, staff told the committee.

M2M history summary through March 2019 | *SPP*

It was the 24th month in the last 30 in which M2M distributions have flowed in SPP’s direction. The RTOs began the M2M process in March 2015.

Permanent flowgates along the RTOs’ seam were binding for 141 hours and temporary flowgates were binding for 552 hours, resulting in $958,000 and $1.3 million in payments, respectively.

— Tom Kleckner

May 9, 2019

PGE Probed by Plaintiffs’ Lawyers, SEC

By Hudson Sangree

PG&E Corp. came under criticism this week from a federal judge, who ordered its new CEO and board members to view the scene of the devastating Camp Fire.

Lawyers representing victims of that disaster and others urged a bankruptcy judge Wednesday to order the utility to turn over internal records related to wildfire liability.

And PG&E said May 2 it was being investigated by the Securities and Exchange Commission for its accounting of wildfire losses.

In short, it was another bad week for beleaguered PG&E and its utility subsidiary, Pacific Gas and Electric, which are undergoing Chapter 11 bankruptcy re organization after devastating wildfires in the past two years. (See Calif. Must Limit Fire Liability, Gov ernor Says.)

A federal judge told PG&E leaders to go to Paradise, Calif., devastated by the Camp Fire in November 2018. | © *RTO Insider*

PG&E remains on probation for crimes associated with the San Bruno gas line explosion in 2010, which killed eight residents of a suburban San Francisco neighborhood.

In that case, U.S. District Court Judge William Alsup on Tuesday ordered PG&E’s board members to visit Paradise, Calif., where the Camp Fire killed at least 85 people and leveled most of the town of 27,000 residents in the Sierra Nevada foothills. Alsup said he wanted PG&E leaders to see the wreckage of the deadliest fire in state history.

Eleven of PG&E’s 13 directors are newly appointed, along with new CEO Bill Johnson, who started work May 2. (See Former FERC Commissioner Brownell Named PG&E Chair.)

In the bankruptcy case, lawyers for PG&E and those representing thousands of fire victims faced off for two hours Wednesday before U.S. Bankruptcy Judge Dennis Montali in San Francisco.

Attorneys for the creditor committee of tort claimants said they wanted information, which the utility refused to turn over, about the role of the utility and its contractors in starting the Camp Fire and the estimated cost, including any potential government fines that PG&E might have to pay.

The California Public Utilities Commissioned fined PG&E a record $1.6 billion after the San Bruno gas explosion, and plaintiffs’ lawyers said a similar fine could be imposed for the Camp Fire.

PG&E — A 55-plus community in Pardise was completely destroyed by the Camp Fire. | © *RTO Insider*

State fire officials haven’t concluded their investigation yet, but PG&E has said its equipment likely started the fire, which began beneath the 100-year-old Caribou-Palermo transmission line in rural Butte County on Nov. 8, 2018 — six months before Wednesday’s hearing.

Sounding exasperated, Montali told the lawyers to try to settle the dispute among themselves.

The judge is scheduled to rule soon on a petition by PG&E to enjoin FERC from interfering in the bankruptcy case. The commission recently reaffirmed its own ruling that it shares jurisdiction with the court over PG&E’s wholesale power purchase agreements. (See FERC Denies PG&E Rehearing Over Contracts Dispute.)

PG&E has indicated it may try to rescind or renegotiate hundreds of PPAs worth billions of dollars with generators of renewable energy, and it wants Montali to have sole authority over the contracts.

May 9, 2019

PJM Carbon Pricing Challenges Surmountable, Panel Says

By Christen Smith

CAMBRIDGE, Md. — As PJM considers how to best manage future carbon policies, energy industry experts say the unique challenges the RTO faces can be mitigated with strong coordination between policymakers, stakeholders and grid staff.

“You’re not the only ones looking at this,” Dirk Forrister, CEO of the International Emissions Trading Association, said during the General Session of PJM’s Annual Meeting, at the Hyatt Regency Chesapeake Bay Golf Resort, Spa & Marina, on Wednesday. “It is material, and it seems to be an issue, in terms of public sentiment, that’s coming up more and more.”

PJM’s General Session convenes on May 8. | © *RTO Insider*

Forrister, who once served as chairman of the White House Climate Change Task Force under President Bill Clinton, said the U.S. remains an “outlier” internationally as other countries embrace carbon pricing, with varied levels of success.

“Come on in, the water’s fine,” he said. “To get to the levels of climate protection that governments want, it implies a level of reduction that we haven’t seen before.”

PJM isn’t the first RTO to tackle carbon pricing, but its challenge of balancing the markets between participating and nonparticipating states proves unique compared with NYISO and CAISO.

In New York, NYISO is close to voting on a set of rules to price carbon that would include border charges for imported power and credits for exported power — just one way PJM could handle flows among its 13 states and D.C. (See More Details Divulged on NYISO Carbon Pricing Study.)

In CAISO, where power also flows to and from regions without carbon-reduction goals, operators prioritize curbing emissions over importing energy from the cheapest resources. It’s a focus that Ben Grumbles, Maryland’s secretary of the environment, encourages PJM to take as it examines how pricing could work across the grid.

“A carbon-constrained energy sector is absolutely the future,” he said. “Never lose sight of the fact that the goal should be to reduce emissions.”

Maryland and Delaware both participate in the Regional Greenhouse Gas Initiative, a coalition of Northeast and Mid-Atlantic states committed to capping carbon emissions from the power sector. Emissions have been cut in half since 2014, and more than $3 billion have been reinvested into cleaner energy and ratepayer reductions, Grumbles said.

“In RGGI, the key is to have the environment secretary for the governor and the energy regulators together so we can we find common ground,” he said. “It takes time.” He also emphasized the importance of preserving state sovereignty and protecting consumers from “windfall profits.”

Anthony Giacomoni, senior market strategist for PJM, said an ongoing internal study is quantifying the market impacts of a systemwide carbon price, versus a regional or sub-regional system.

“We want to enable state policies while preserving economic and competitive dispatch,” he said, noting that minimizing “carbon leakage” remains a top priority. “High prices will have very high leakage and, as a result, prevent states from reaching carbon-reduction goals.”

Mike Borgatti, of Gabel Associates, moderates a panel discussing carbon pricing possibilities in PJM. | © *RTO Insider*

Staff are also considering one-way and two-way border adjustments as other tactics to minimize the impact on nonparticipating states and maintain a level playing field for dispatching generation. While not an “exhaustive” study of all the ways PJM could accommodate carbon pricing, Giacomoni said the RTO hopes it will better inform policymakers and stakeholders of the market impacts.

He said staff will provide an update on study results at the May 15 Market Implementation Committee meeting, with a plan to release the full analysis later this summer.

May 9, 2019

ERCOT: More Capacity, but Emergency Ops Still Expected

By Tom Kleckner

ERCOT said Wednesday that its final resource adequacy assessment for this summer indicates “a potential need” to enter energy emergency alert (EEA) status in order to maintain system reliability.

The Texas grid operator is forecasting a peak demand of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. ERCOT will meet that demand with 78.9 GW of available capacity, a slight increase from its spring assessment of resource adequacy.

South Texas transmission lines | *CPS Energy*

The good news: ERCOT’s planning reserve margin for the summer has increased to 8.6% from an historic low of 7.4%. The grid operator’s target reserve planning margin is 13.75%.

“At this reserve margin level, it’s more likely we’ll have to use additional resources available under emergency operations procedures on several occasions this summer,” ERCOT’s Dan Woodfin, senior director of system operations, said during a media call Wednesday.

“We’re confident we’ll be able to maintain the reliability of the system as a whole. That’s our job,” Woodfin said in response to persistent questions about the possibility of blackouts this summer.

“It’s probably one of the lowest planning reserve margins on record — based on all the data we’ve seen historically — going into a summer peaking area,” John Moura, NERC director of reliability assessment, told the electric reliability organization’s Member Representatives Committee in St. Louis on Wednesday. “So [there are] certainly some challenges, but I believe the operators have the right tools in order to keep the system stable and operating the system reliably.”

Woodfin and ERCOT Manager of Resource Adequacy Pete Warnken said the grid operator has a number of tools at its disposal should operating reserves drop to 2.3 GW and force an EEA 1 declaration — the lowest emergency rating. At that point, ERCOT can take emergency imports from SPP over DC ties, use emergency response service and institute load-reduction measures, among other options.

“We have the tools and procedures in place,” Warnken assured his audience.

The ERCOT reserve margin for the summer months (June-September) was raised thanks to the return of a 365-MW NRG gas-fired unit, 111 MW of upgrades to 12 generating units and an increase in the amount of DC tie imports. (See NRG to Bring Back Gas Plant for Summer 2019) The grid operator’s Board of Directors in April approved a change to import forecasts, basing them on the amount of power that could be brought in during emergency conditions and not historical forecasts.

ERCOT on Wednesday also released a preliminary assessment for the fall months (October-November) and an updated capacity, demand and reserves (CDR) report.

ERCOT’s future demand and capacity | *ERCOT*

The fall assessment forecasts a peak demand of just over 61 GW, with more than 84 GW of capacity available.

The updated CDR includes an additional 733 MW of installed wind and solar capacity. It also includes 517 MW of battery storage as being newly eligible for inclusion.

The updated CDR forecasts above-normal growth in demand of 2.5 to 3% through 2022. Oil and gas development in West Texas and new industrial facilities on the Texas Gulf Coast account for much of that growth, ERCOT said.

The grid operator expects the reserve margin to reach 15.2% in 2021, when almost 6 GW of planned resources in the interconnection queue, primarily wind and solar projects, become eligible for the CDR. It projects the reserve margin will dip back below 8% in 2024, when peak demand is expected to exceed more than 84 GW.

Rich Heidorn Jr. contributed to this story from St. Louis.

May 9, 2019

PJM Members Committee Briefs: May 7, 2019

CAMBRIDGE, Md. — PJM stakeholders gathered for a special Members Committee meeting on Tuesday at the Hyatt Regency Chesapeake Bay Golf, Resort & Marina as part of the RTO’s Annual Meeting.

PJM’s Members Committee convened at the Hyatt Regency Chesapeake Bay Golf Resort, Spa & Marina in Cambridge, Md. | © *RTO Insider*

After ‘Challenging’ 2018, PJM Looks Ahead

After a “challenging” and “humbling” 2018, PJM CEO Andy Ott said the RTO will better lead stakeholders in 2019 as it works to adapt the grid to emerging state policies and renewable technology.

“It’s not enough anymore to just have reliability at the least cost and have open, competitive markets,” he said during his keynote address Tuesday. “We need to listen to that as an entity. But it’s not just PJM alone. It’s all of us. We’re all in it together.”

While he admitted the ongoing fallout from the GreenHat Energy default looms large, Ott said PJM is working hard to implement staffing and procedural changes that were recommended as part of an independent probe into the situation. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

He also said PJM will keep an “open mind” as it works to incorporate energy storage and possible carbon pricing into its markets in the coming years and requested clear direction from stakeholders and federal regulators on those issues.

Nothing ‘Magical’ About RPM

Stu Bresler, PJM’s senior vice president of markets and operations, said stakeholders might want to reconsider what market mechanism best accommodates growing generation subsidies as states continue enacting policies to reduce carbon emissions.

“Markets have worked, but we recognize there’s nothing magical about the Reliability Pricing Model,” he said. “It’s one option as far as resource adequacy is concerned. At some point, maybe we ought to talk about whether there are other alternatives we should look at that could better incorporate the policy goals out there that aren’t necessarily RPM as we know it today.”

The comments came during PJM’s “Year in Review Panel,” in which leaders from each department discussed the challenges and successes experienced throughout 2018.

“Well, there’s no shortage of challenges,” said Joe Bowring, PJM’s Independent Market Monitor, citing continued regulatory uncertainty that is beginning to affect investments in the grid. “The challenges are simple to say, very difficult to do. How do we maintain competitive markets?”

But it wasn’t all doom and gloom from the Monitor, who also praised the implementation of hourly offers and five-minute settlements for setting better price signals, especially with gas-fired generation.

Steve Herling, PJM vice president of planning, noted that increasing stakeholder transparency remains a top priority for staff. “It’s critical that stakeholders understand the assumptions, the analyses and the decision-making process,” he said. “We’ve done a lot over the past couple of years to enhance transparency, but we understand there is a lot more that needs to be done.”

Likewise, PJM’s Vice President of Operations Mike Bryson said that addressing fuel security issues should continue to be top-of-mind for stakeholders. “Each year we get surprised by a different aspect of the evolving fuel mix,” he said.

FTR Forfeiture Calculation Change Endorsed

Members endorsed calculation changes for financial transmission rights forfeiture to be incorporated in the Operating Agreement.

PJM and the Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on- and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation,” PJM MIC Briefs: March 6, 2019.)

FTR forfeitures are intended to discourage traders from cross-market manipulation. Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the endorsed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.

Incumbent Board Members Re-elected

Three incumbent members of the Board of Managers won re-election bids: Terry Blackwell, O.H. Dean Oskvig and Mark Takahashi will each serve another three-year term.

– Christen Smith

May 9, 2019February 18, 2025

Tucson Electric Power Signs up for Western EIM

By Robert Mullin

The Western Energy Imbalance Market chalked up another future member Wednesday after Tucson Electric Power signed an agreement with CAISO saying it will join the real-time market in April 2022.

The Arizona utility’s move comes just two weeks after Spokane, Wash.-based Avista announced it would be joining up with the EIM at the same time, potentially bringing the market’s participation level to 15 out of 37 balancing authorities in the West. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)

With Arizona Public Service already trading in the market, and Phoenix-based Salt River Project slated to join in April 2021, TEP’s membership will expand the EIM’s reach to include all of Arizona’s major population centers. TEP, a subsidiary of Canada-based Fortis, serves about 417,000 electric customers in the Tucson metropolitan area.

TEP estimates that participation in the EIM will save the utility about $13 million annually.

Tucson Electric Power expects to sharply increase its renewable energy portfolio with a new wind farm in southeastern New Mexico. | Tucson Electric Power

“The EIM will help TEP save money for customers by expanding our real-time access to renewable power and other low-cost energy resources across the Western grid,” Erik Bakken, vice president of system operations and environmental at TEP, said in a statement.

TEP owns or controls 2,531 MW of generating capacity, including 255 MW of utility-scale solar and 80.4 MW of wind; its service area also contains about 220 MW of commercial and residential rooftop solar. In March, the utility announced it would sharply expand its renewable energy portfolio with the construction of the 247-MW Oso Grande Wind Project in southeastern New Mexico.

The utility operates 2,175 miles of high-voltage transmission, with key links into wind-rich New Mexico and the neighboring balancing area of Public Service Company of New Mexico, whose own plans to join the EIM in April 2021 have been complicated by moves by state regulators. (See PNM’s Bid to Join Western EIM Gets Approved in Part.)

The EIM’s current members are APS, Idaho Power, NV Energy, PacifiCorp, Portland General Electric, Puget Sound Energy, Powerex and the Sacramento Municipal Utility District, which began transacting last month. The Los Angeles Department of Water and Power and Seattle City Light also are scheduled to go live in April 2020.

CAISO last month said the EIM has yielded $650.26 million in benefits for its members since being launched with PacifiCorp as its first member in November 2014.

May 7, 2019

FERC Rejects Oakland Appeal v. PGE

By Hudson Sangree

FERC last week denied a request for rehearing by the city of Oakland against Pacific Gas and Electric for charging retail instead of wholesale power and transmission rates at the Port of Oakland, which maintains an extensive distribution network (EL18-197).

The city, acting through the port, had claimed PG&E violated the Federal Power Act by charging the higher rates and failing to file a wholesale service agreement with FERC. It said that since 1997 it had resold virtually all the electricity it received from PG&E to metered electricity end-use customers and that PG&E should have been aware of the situation and charged wholesale rates. (See FERC Denies Oakland Complaint.)

The city asked for a refund of the difference between the retail rates PG&E charged and the wholesale rates the city argued it should have paid for electricity it received between 1997 and 2017, when it signed a wholesale agreement with the utility.

PGE — FERC rejected an appeal by the city of Oakland regarding rates PG&E charged the city’s port.

In its Dec. 20, 2018 order, FERC denied the complaint, finding that the port’s claims lacked legal and factual support and that its request for a declaratory order was unwarranted. In particular, FERC said Oakland had failed to provide evidence, such as invoices, of its resale of electricity to end users. Moreover, the city never specifically asked PG&E to change its rates from retail to wholesale, and the utility did not have an obligation to do so on its own, the commission said.

“We do not believe that Port has substantiated its general claim that PG&E violated Section 205c of the FPA by failing to file a wholesale transmission and power sale agreement …,” the commission said. “Port’s statements to the contrary are speculative, not supported by the record evidence, and insufficient to meet its FPA Sections 206 and 306 burdens.”

“[E]ven if we were to find that PG&E violated FPA Section 205c as alleged by Port, we would not direct refunds here,” FERC said. “As noted above, Port had ample opportunity over roughly two decades to clarify the nature of the service it took from PG&E and failed to do so. We therefore do not think requiring refunds from PG&E would be appropriate.”

In seeking a rehearing, the city argued FERC should have either issued a declaratory order or scheduled a hearing because the city had established a prima-facie case under commission regulations. The city contended FERC had failed to engage in reasoned decision-making and disregarded evidence.

FERC disagreed, saying the city had offered only a single photo of unmarked meters to show it was making wholesale sales and had failed to establish a prima-facie case.

“PG&E thus was not required to rebut Port’s purported evidence — i.e., the photograph showing its meters — on this point, and the commission was not obligated to set the issue for hearing,” FERC wrote.