Search
`
November 16, 2024

Posted on

In Passing Bill to Kill Competition, Arizona Lawmakers Rekindle Idea

The Arizona legislature passed a bill this week that would close the door to electric retail competition, but lawmakers indicated the conversation on deregulation is not over.

The state Senate on Tuesday passed House Bill 2101 on a 17-11 vote, with two senators not voting. The bill was transmitted Wednesday to Gov. Doug Ducey, who has five days to take action.

The same day as the Senate vote, House Speaker Rusty Bowers and Senate President Karen Fann announced the formation of a joint Ad Hoc Study Committee on Energy. The nine-member committee will meet after the close of the current legislative session, with a report due by Dec. 31.

“The interim work of the committee will enable future discussion of the state’s energy policies and the benefits and risks of energy ‘deregulation’ by providing a robust base of knowledge for policymakers and regulators,” Bowers and Fann said in a joint statement.

The committee will discuss the reliability and affordability of diverse power generation, transmission and distribution resources. Arizona’s governance over electric generation and transmission will be another topic.

Customer Choice

HB 2021 would repeal a 1998 law that was intended to give customers a choice of electricity service providers in the service territories of both investor-owned utilities and consumer-owned “public power entities” (PPE).

But rules that the Arizona Corporation Commission (ACC) adopted to allow competition were shot down by a 2004 appellate court ruling. And proponents of HB 2101 say competition should be rejected to maintain reliable electric service.

The bill, sponsored by Rep. Gail Griffin (R), comes as an application from Green Mountain Energy is pending before the ACC. Green Mountain, a renewable energy company, applied in August to provide competitive electric generation services within the territories of the state’s largest investor-owned electric utilities, Arizona Public Service and Tucson Electric Power.

HB 2101 had its ups and downs in the legislature, as proponents scrambled to gather enough votes.

The House passed the bill in February on a 37-21 vote — after rejecting the bill earlier that month but passing a motion to allow reconsideration. (See Retail Anti-competition Bill Hits Snag in Ariz.)

Similarly, the Senate shot down HB 2101 in March, but passed a motion to allow reconsideration.

During Tuesday’s floor session, several senators commented on why they switched their vote or stuck with their previous decision.

Sen. J.D. Mesnard (R) said HB 2101 would remove a statute that was not working, and his vote in favor of the bill had not changed. Mesnard said he generally supports free-market policies and would have preferred to have a replacement for the deleted statute. He said he’s hopeful that the interim committee will make progress in that regard.

“I’m going to be … very interested in a replacement and be an advocate for creating more competition, more choices for our ratepayers and our consumers,” Mesnard said.

But Sen. Lisa Otondo (D) questioned the timing of the interim committee. She remained opposed to HB 2101.

“Since when do we do an ad hoc committee and stakeholder meetings after the bill has passed?” Otondo said. “What a slap in the face. I vote ‘no.’”

Sen. Tyler Pace (R), who voted against the bill last month but in favor of it on Tuesday, said he had spent dozens of hours studying the issue. Electric retail competition is different from competition in other retail markets, he said.

“This idea that somebody in the middle can just buy energy from whoever they want and then sell it to whoever they want without ever producing and without ever actually laying the wire is not, in my personal or business opinion, a reliable market,” Pace said. “Because when something does go bad, there are some issues with that business model.”

Transparency Concerns

Pace and Otondo both noted a lack of transparency around the bill.

“It was sold as a simple fix to remove defunct statutes from the books, so that the [Arizona] Corporation Commission couldn’t deregulate the energy market and cause a catastrophe, like what we saw in Texas last winter,” Otondo said.

Otondo said she later learned that the utility pushing the bill was involved in antitrust litigation. The utility had been sued by customers with rooftop solar, who were being charged up to 65% more than customers without it, she said.

Otondo didn’t name the utility in the case but seemed to be referring to Ellis v. Salt River Project. HB 2101 would repeal a section of statute that says the Uniform State Antitrust Act applies to a PPE’s competitive electric generation service and other services.

Outside of the legislature, the business group Advanced Energy Economy called “phony” claims that HB 2101 was needed to increase energy system reliability. The group opposes the bill.

The bill does “next to nothing to strengthen the power grid,” AEE Principal Shelby Stults said. “It’s just a way for utilities to reinforce their control over Arizonans’ energy choices.”

If Arizona wants to improve reliability, it should look into joining a Western RTO, Stults told RTO Insider. That would allow more renewable energy to be incorporated in a reliable manner, she added.

Mark Parsons, Green Mountain’s vice president and general manager, said Arizona residents have indicated they want a choice of energy providers. The state has avoided aggressive governmental mandates for clean energy, he said.

Parsons urged Gov. Ducey to reject the bill.

“We are disappointed that HB 2101 repeals the statutory basis for us to receive a license to operate in the state,” Parsons said in a statement following this week’s Senate vote. “That is a legal prerequisite for us to be able to do business.”

Posted on

FERC Asks RTOs for Plans on Changing Market Needs

FERC on Thursday ordered CAISO, ISO-NE, MISO, NYISO, PJM and SPP to report on how their system needs are changing with their shifting resource mixes and how they intend to meet them (AD21-10).

The commission said the reports would build on the record developed during four technical conferences last year and provide a foundation for potential market changes.

“At this time, we do not propose a generic solution to address changing system needs across the RTOs/ISOs because of the diversity of those needs and the lack of a compelling record to support any one-size-fits-all solution for meeting those needs,” the commission said. “Instead, we believe that it is appropriate to gather additional information from the RTOs/ISOs … to enhance our understanding of the changing system needs in each RTO/ISO and potential mechanisms for addressing those needs as they change over time. We will review the reports and comments to determine whether further action is appropriate.”

The grid operators must report on:

      • current system needs under changing resource mixes and load profiles;
      • how each expects its system needs to change over the next five and 10 years;
      • whether and how each plans to change its energy and ancillary services (E&AS) markets to meet expected system needs over the next five and 10 years; and
      • information about changes to resource adequacy programs or other market changes, including to capacity markets, that would help each meet changes in system needs.

The commission gave the grid operators 180 days to file reports in response to the order, with public comments due 60 days later.

Democrat Richard Glick called for the proceeding after taking over the commission chairmanship last year.

The commission said the record developed in the docket indicated that “RTOs/ISOs currently face changing system needs that vary significantly by RTO/ISO. The time horizon (minutes, hours, days, seasons) of system needs, particularly with respect to net load variability and uncertainty, also appears to vary significantly across RTOs/ISOs.”

While the issues have been most acute in regions with the highest penetration of variable resources, such as CAISO and SPP, “other RTOs/ISOs also expect their system needs to change in the future, and the commission and stakeholders would benefit from additional information from all RTOs/ISOs on the subject.”

Concurring Statements

Although the commission unanimously supported the order, the panel’s two Republicans offered some additional comments in concurring statements.

Commissioner James Danly called for “a sincere effort to take the lessons learned in our markets and reevaluate whether and how those markets work.

“A single, basic set of questions must be at the heart of our examination: Are price signals providing the proper incentives for the orderly entry and exit of the correct type and quantity of generation to ensure resource adequacy and reliability?” he said. “What we should not do is try to engineer a record by which we might later justify commission action in pursuit of narrow, preordained policy goals.”

Commissioner Mark Christie said that although the primary focus of the reports ordered by the commission related to the E&AS markets, MISO’s latest capacity auction results “are only the latest evidence that the future of all RTO/ISO market constructs should be considered” in the docket. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

“Specifically, I propose fundamental questions regarding pricing and compensation in the energy, ancillary services and capacity markets that merit discussion due to their potential impact on reliability and fairness to consumers. For example, I think it is time to put the all-important question of the continued use of locational marginal pricing in these market constructs on the table for serious scrutiny and discussion,” he said.

Technical Conferences

In March 2021, FERC held its first technical conference in the docket, which focused on capacity markets in PJM, ISO-NE and NYISO and featured broad criticism of the minimum offer price rule. (See PJM MOPR in the Crosshairs at FERC Tech Conference.)

That led to PJM’s proposal to apply MOPR only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. The new rule took effect Sept. 29 “by operation of law” after the commission deadlocked 2-2. The rule change is the subject of a challenge by merchant generators before the 3rd U.S. Circuit Court of Appeals. (See FERC Declines Rehearing of PJM MOPR; Ball now in 3rd Circuit Court.)

A second conference on May 25 focused on ISO-NE’s markets. ISO-NE CEO Gordon van Welie told the commission markets are “never going to work very well” with inadequate infrastructure supporting them and cited a “misalignment” between the RTO markets and state policies. (See Regulators, ISO-NE Discuss Market Changes at FERC Tech Conference.)

A Forward Clean Energy Market, which is under consideration, could relieve some of the tensions, van Welie said. But he said problems will persist “until the region figures out how it wants to socialize some of these costs for reliability that are outside of the market.”

After months of debate, ISO-NE earlier this month filed a proposal to eliminate its MOPR after a two-year delay. (See ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision and Mass. Democrats Take on ISO-NE over MOPR.)

On Sept. 14, the commission held the first of two conferences on E&AS markets, with a focus on the need for flexible ramping products to compensate for shortfalls in forecasted wind and solar output. (See Flexible Ramping Grows as Ancillary Service.) FERC staff had teed up some of the issues in a Sept. 7 white paper.

The discussions continued at a conference Oct. 12, where speakers agreed that market participation rules should be revised to ease the entry of new and emerging resource types. (See Stakeholders Ask FERC to Support E&AS Market Changes.)

“One of the recurring themes we’ve heard from a number of participants is that increasing reliance on intermittent generation resources and changes in load profiles associated with the growth of behind-the-meter generation requires additional system flexibility,” Glick said at Thursday’s open meeting. He said the commission seeks feedback from market participants as well as grid operators. “That will help enable the commission to assess whether modifications of the markets we oversee are necessary and to address the changing needs of the system.”

Posted on

Higher Prices, Longer Queues Highlight FERC Market Report

Rising natural gas prices and extreme weather pushed wholesale electricity prices higher in 2021, FERC said Thursday in its State of the Markets report.

Commission staff said changes in fossil fuel markets “drove price increases” across the board, including for natural gas, oil, propane and electricity, reversing trends of flat to declining prices for several years.

Henry Hub spot gas prices averaged $3.82/MMBtu in 2021, compared with $1.99/MMBtu in 2020. And gas prices have continued to increase in 2022, averaging $4.54/MMBtu through March 14.

Average day-ahead peak prices increased last year at pricing hubs in each RTO and ISO, FERC said, up more than 45% on average and more than 100% in ISO-NE and NYISO. Commission staff said “stressed market conditions” during the February 2021 winter storm in ERCOT, MISO and SPP led to high prices that raised the average for the year.

Despite rising prices, FERC said, instances of negative prices in real-time markets continued to increase across various regions. In 2021, negative average hourly real-time LMPs occurred in about 3.5% of all hours across all RTO/ISO pricing points, compared with 3.1% in 2020.

SPP’s negative prices averaged -$15/MWh over the year, and the RTO accounted for 41% of negative LMPs across all markets, the result of high wind output and low demand, as wind’s share of total output jumped to 34% from 27% a year earlier. ERCOT accounted for 29% of negative prices at an average of -$12/MWh, while CAISO’s share was 21% at an average of $-15/MWh.

Generation Sources

Commission staff said higher natural gas prices also “increased the relative competitiveness” of coal-fired generation, with coal output rising 20% despite continued unit retirements.

Across the RTOs/ISOs, the share of coal-fired output increased from 21% to 24%, while gas-fired generation decreased from 38% to 35%.

Generating capacity continued recent trends, as aggregate nameplate generating capacity grew from 768 GW in 2020 to 789 GW across all RTOs/ISOs. As of December, natural gas represented 46% of the capacity mix, followed by coal at 18%, wind at 14%, and nuclear at 8%.

FERC said some RTOs/ISOs experienced “relatively large changes” in capacity mixes, including an increase in battery   storage capacity in CAISO from 0.7% to 3.2% of its capacity mix, an increase in wind capacity in SPP from 26.8% to 29.5% and solar capacity in ERCOT rising from 4.1% to 7%.

The largest portion of capacity retirements came from coal, the commission said, although the 6.5 GW of retirements in 2021 was the lowest number since 2014. FERC said the decline was partly driven by increased electricity demand and the higher natural gas prices.

Electric Transmission

About $15 billion of transmission projects came online in 2021, FERC said, with more than 1,000 line-related transmission projects entering service in the Eastern and Western interconnections. The commission said about one-fifth of the projects included new lines, and about a quarter of those projects were at or above 230 kV.

FERC highlighted the Western Spirit project, a 155-mile 345 kV line in New Mexico, costing $360 million and connecting more than 1,000 MW of generation in the state to the electricity grid operated by Public Service Company of New Mexico. The line was the largest new high-voltage transmission project and the only merchant transmission line to enter service in 2021.

The commission said Order 1000 transmission planning in each region “worked towards or completed a regional   transmission plan” in 2021. CAISO’s 2020-21 transmission plan identified three reliability-driven transmission projects estimated at less than $5 million, and two other transmission projects that could be replaced with battery storage. SPP identified 28 new projects with a total of 397 miles of new lines and 48 miles of rebuilt lines, costing $1 billion.

MISO identified 335 new transmission projects totaling 1,188 miles of new lines and 3,137 miles of upgraded lines, costing $3 billion.

PJM added to its Regional Transmission Expansion Plan with 118 new baseline transmission projects at an estimated cost of $920 million and 34 new network transmission projects at an estimated $48 million. Of the new baseline transmission projects, 52% were driven by transmission violations, 23% by generator deactivations and 25% by other NERC and PJM reliability criteria.

Electric Interconnection Queues

The commission said a changing resource mix with increasing renewables has made delays in generation interconnection queues a “persistent, growing feature” of the markets.

“There has been an unprecedented volume of requests to interconnect new generating facilities, which, in turn, has led to backlogs and delays in interconnection queues nationwide,” FERC said in its report.

The RTOs/ISOs had 716,783 MW in interconnection queues at the end of 2021. Solar accounted for the largest portion (282,978 MW), followed by batteries (216,426 MW), wind (114,634 MW), hybrid resources (41,873 MW), DC transmission (19,620 MW), natural gas (9,972 MW), thermal (6,034 MW), combined cycle (4,804 MW), hydro (2,958 MW) and steam turbines (1,119 MW).

Of all the regions, CAISO had the largest amount of capacity by megawatts in its interconnection queue, with solar and batteries as the most common resource types. PJM had the second largest queue by capacity volume, with solar and batteries also comprising the largest shares.

Posted on

FERC Issues 1st Proposal out of Transmission Proceeding

FERC on Thursday proposed changing transmission planning and cost allocation processes in the first in what may be a series of initiatives to help build out the grid in response to electrification and the shift to renewable generation (RM21-17).

FERC Open Meeting (FERC) Alt FI.jpgFERC met in person for its monthly open meeting for the first time in more than two years, though the meeting was not open to the press or public, only commissioners and staff. | FERC

Meeting in person for the first time after more than two years of telework during the COVID-19 pandemic, the commission voted 4-1 to issue the Notice of Proposed Rulemaking, which would direct transmission providers to revise their planning processes to, among many other things, identify infrastructure needs on a long-term, forward-looking basis and propose a list of benefits on which they would base their selections of proposed projects to meet those needs.

The majority of the commission said the proposal would help planning entities, including RTOs and ISOs, prepare for the growth of renewables, new sources of demand such as electric vehicles and extreme weather events, expected to increase as climate change worsens. In a separate order Thursday, the commission ordered the five jurisdictional RTOs and ISOs to report on how those forces were changing their system needs and what new market rules were required to satisfy them. (See related story, FERC Asks RTOs for Plans on Changing Market Needs.)

“If today’s proposed rule is finalized, it will facilitate much needed transmission investment, improving the resilience of the grid, enhancing reliability and reducing power costs,” Chair Richard Glick said. “It’s also going to address our nation’s changing resource mix and the changing role of electricity in our society.”

The NOPR follows an Advance Notice of Proposed Rulemaking issued in July 2021, which covered a wider range of topics. The results of the ANOPR, which drew hundreds of stakeholder comments, has been highly anticipated by not just transmission developers, but the renewable energy industries as well. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

The NOPR would not change planning and cost allocation rules for reliability or market efficiency projects, Commissioner Mark Christie noted. “We don’t want to mess with them, and we’re not,” he said. But it would require planners become more proactive in planning for what Order 1000 called “public policy” projects.

The proposed rule would:

  • require transmission providers to conduct regional transmission planning on a long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand;
  • require transmission providers to identify transmission needs through multiple scenarios that incorporate factors such as federal, state and local laws and regulations that affect the future resource mix and demand; trends in technology and fuel costs; resource retirements; generator interconnection requests and withdrawals; and extreme weather events;
  • broaden the benefits that could be considered for project selection and cost allocation;
  • require transmission providers to seek the agreement of relevant state entities regarding cost allocation; and
  • require an ex-ante cost allocation method or a state agreement process in which states can voluntarily agree to fund a project, or a combination of the two.

“The clean energy industry is developing thousands of megawatts of clean energy resources — but many projects are stymied by a lack of transmission capacity,” the American Clean Power Association said in a statement. “FERC’s proposed rule has the potential to accelerate backbone transmission development planning, ensure fair and consistent cost allocation, and provide a substantial role for states in planning transmission for the future.”

Many other stakeholder groups issued statements applauding the proposal, though some were more lukewarm. Many called it a “first step,” while Sarah Ladin, senior attorney at the Institute for Policy Integrity, said the proposal was “a modest but important step toward more efficient planning that can facilitate decarbonization.”

Glick assured stakeholders during the meeting that the commission had not forgotten about the ANOPR’s other issues, such as the backlogged generation interconnection queues, interregional transmission planning and incentives. Speaking to reporters after the meeting, Glick advised against taking “the fact that we did a NOPR today on transmission planning and cost allocation to suggest that there wasn’t enough support for any of those other issues. Just the contrary. …

“After all the comments came in on the ANOPR, we realized that there’s a lot here; there’s a lot of meat on the bone, so to speak. And we thought if we tried to handle to every single issue … in one big rulemaking, it would take forever. So, we thought we would streamline it into several different rulemakings. …

“My great hope is that in the very near future, we’ll able to issue a NOPR on interconnection reform, which is very important. … [But] we didn’t think it was wise to do it all in one big rulemaking.”

While perhaps not a complete overhaul, the proposal would result in significant changes to transmission planning. RTOs, for example, would be required to create scenarios, with a minimum time horizon of 20 years, that forecast changes in resource mixes and the probability of extreme weather events. Planners would then evaluate project proposals based on FERC-approved criteria that recognize the benefits over the time period for the purposes of cost allocation

Right of First Refusal

Among the most significant changes would be an exception to Order 1000’s elimination of the federal right of first refusal (ROFR).

FERC said regional transmission facilities subject to competitive procurements represent only a small portion of transmission investment in recent years and that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission.

Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, the commission said.

It proposed allowing an incumbent to exercise a federal ROFR for a regional project on the condition that it partner with an unaffiliated company with a “meaningful level of participation and investment” in the project.

While that change would be a win for incumbent transmission owners, the commission also proposed new procedures to ensure they don’t replace aging transmission infrastructure without evaluating whether they could be “right sized” to provide more cost-effective solutions to regional transmission needs.

Construction Work in Progress

Developers would also not be permitted to take advantage of the commission’s construction-work-in-progress (CWIP) incentive for their selected projects. Planners would also be required to seek state approval of their proposed cost allocation methods.

Those requirements were key to Christie’s support for the proposal. He said that CWIP puts consumers at risk by allowing developers to be paid “before a single ounce of steel is put into the ground, much less the project is in service.” Instead, pre-construction costs would be “booked” as allowance for funds used during construction (AFUDC).

“With AFUDC, the developer gets to book the costs but cannot collect from the consumers until the project is in service,” he said.

The former Virginia State Corporation Commission chairman was also exuberant about the provisions to include state input and approval. In this he disagreed with Commissioner James Danly, who dissented because, he said, “I don’t like the purpose of this NOPR.

“It is designed to encourage buildout of transmission specifically for the purpose of encouraging the development of certain types of resources. That is something that I think is not appropriately a concern of the commission. And it does so by socializing costs through putting public policy choices — that is, state and, if you can believe it, even local public policy choices — front and center in the transmission planning process.”

Commissioner Allison Clements rejected Danly’s criticism.

“It is also not a policy action to advance renewable energy interests. To so frame the proposed long-term transmission planning reforms, or to portray transmission planning as a zero-sum game, misses the point,” she said. “Rather, the proposal contains a sensible suite of reforms to shore up cost protections and reliability of the U.S. electricity system based on clear market signals about generation development and demand, the risks of extreme weather and the increasing threat of cyber and physical attack.”

Christie said the addition of a state role in cost allocation was “probably the single biggest reason” he voted for the proposal.

“For the first time, it puts states formally at the heart of the planning for these types of projects,” he said. “States are going to be at the heart of the planning. States are going to get the opportunity to agree to the criteria, and they’re going to get the opportunity to agree to the cost allocation. This has never been a formal requirement in FERC’s transmission regulation.”

Comments on the NOPR will be due in 75 days from publication in the Federal Register.

Posted on

Maryland PSC Approves Updates to Utility EV Charging Programs

The Maryland Public Service Commission (PSC) on Wednesday unanimously approved changes to the state’s Electric Vehicle Charging Pilot Program, increasing incentives aimed at boosting the number of EV chargers installed at locations often underserved by commercial charging companies — multi-unit dwellings, small businesses and nonprofits (Case 9478).

For Baltimore Gas and Electric (BGE), the PSC approved a new rebate program that will cover 50% of the cost of fleet and workplace chargers for 25 Maryland small businesses, with rebates capped at $30,000 for the installation of two DC fast chargers (DCFCs). A $30,000 cap also was approved for DCFCs installed at multi-unit dwellings, an increase of the current cap of $25,000.

Pepco and Delmarva Power were also approved for the $30,000 cap for a new workplace and fleet rebate program for small businesses and nonprofits, again targeting 25 installations. But both utilities will scale back the number of rebates they offer for multifamily dwellings — from 200 to 100 for Pepco and from 50 to 25 for Delmarva — but cover 100% of installation costs, instead of the 50% previously offered.

All three utilities, which are owned by Exelon (NASDAQ:EXC), also were approved to offer $50 e-gift cards as an annual incentive for residential customers to stay enrolled in EV charging programs that allow the companies to track their charging data through “smart charging” software.

Pepco and Delmarva also won approval to expand their residential programs for newer EVs with advanced technology that allows them to communicate charging data to a utility without needing a “smart” charger or extra meter to track usage. EVs with this technology will be eligible for an off-bill credit, $0.03/kWh, for off-peak charging, paid quarterly in the form of a cash card.

With Commissioner Anthony O’Donnell absent, approval of the changes marked the end of several months of negotiations over mid-course adjustments to the pilot program that was launched in 2019 and is scheduled to run through the end of 2023. Key goals include the installation of 1,000 utility-owned chargers in public locations — that is owned or leased by state or local governments — and filling specific gaps in EV charging infrastructure, such as for multi-unit housing and small businesses.

In its decision establishing the pilot program (Order No. 88997), the PSC laid out the number of public chargers each utility is supposed to install by the 2023 deadline: 500 for BGE, 250 for Pepco and 100 for Delmarva. According to information shared with the commission on Wednesday, BGE has installed 206 public chargers to date, while the combined total for Delmarva and Pepco stands at 149.

Two other utilities, Potomac Edison and the Southern Maryland Electric Cooperative (SMECO), are also part of the pilot program, but were not at Wednesday’s hearing.

The Multi-Unit Challenge

The changes approved, and those denied, reflect the complicated economics and changing technology in the EV market.

While the incentives are seemingly generous, the three utilities have not had a good response to the charger rebates for multi-unit dwellings, especially in low-income areas. According to Jamie Caswell, a spokesperson for Pepco and Delmarva, to date Pepco has installed 12 EV chargers at multi-unit dwellings in Maryland, with five more such projects in the pipeline. Delmarva has three multi-unit projects in the pipeline, but has yet to install any, Caswell said in an email to NetZero Insider.

As an alternative, BGE had proposed that low- and moderate-income (LMI) customers should be eligible for a $1,000 rebate to install EV chargers. The PSC turned down the request, siding with consumer advocates who pointed out that such incentives would not address the more significant obstacle of the higher upfront costs of EVs and were therefore “premature.” BGE should work with local organizations to better understand the needs of LMI customers and communities, the commission said.

The commission also rejected BGE’s request to expand its residential charger program to add rebates of $300 each for the installation of 2,500 smart chargers, which would allow the utility to track customers’ charging patterns. The PSC had originally approved the utility for rebates for 1,000 residential smart chargers, but BGE reported, the program was oversubscribed.

The commission said that for many, more well-off EV buyers, the $300 charger rebate was not an essential decision point. In addition, the PSC said, the extra expense of smart chargers is no longer justified since most EVs now have the technology to directly communicate their charging data to a utility. The utility is no longer offering rebates for residential chargers, according to an email from the company.

An Exercise in Balance

Both Maryland and the PSC are bullish on EVs.  According to the state’s most recent greenhouse gas inventory, transportation accounts for more than a third of Maryland’s emissions, and the state is pushing to get 300,000 EVs on the road by 2025.

However, “the state may be hamstrung to some extent” in reaching that goal, due to U.S. dependence on foreign sources for lithium and other minerals critical to EV battery production, said Commission Chair Jason Stanek, in opening remarks at Wednesday’s meeting.

Based on different industry sources, the state has about 40,000 EVs on the road at present (three of which belong to Stanek, Commissioner Odogwu Obi Linton and Commissioner Michael Richard). The state Department of Transportation reports 1,100 public chargers, with close to 3,000 ports in total.

Across the country, utilities are seeing the growing EV market as a major accelerator for demand growth but are also concerned about the impact of EV charging on local distribution systems, hence the interest in having access to charging data and designing special rates that encourage off-peak charging.

The Maryland EV Charging Pilot was intended to help remove obstacles to EV adoption. But, for the PSC, it has been an exercise in balancing the interests of the state’s investor-owned utilities in investing millions of rate-based or otherwise recoverable dollars in charging stations, and the impact of such initiatives on customer utility bills and the state’s competitive EV charging market.

For example, BGE’s original program proposal included plans for installing more than 18,455 residential, commercial and public chargers at a cost of $48.1 million. Pepco and Delmarva’s plans were more modest: $11.3 million for Delmarva to install 774 chargers, and $30.6 million for Pepco to install 2,264 chargers.

In its 2019 decision, establishing the program, the PSC knocked down those figures, stating the utilities had not “met their burden to justify the recovery of [millions] in cumulative program costs exclusively from ratepayers.” The decision gave approval for a scaled-down initiative including the residential rebates and time-of-use rates to encourage off-peak charging, the public charging targets and the multi-unit dwelling incentives.

Wednesday’s approvals were the latest iteration of this program dynamic. BGE, Pepco and Delmarva submitted a joint request to launch first a Fleet Calculator software platform that would “help educate fleet customers on the types of EVs that are available for purchase, what charging equipment to buy, and available EV rates.” The PSC approved the $300,000 price tag for launching the platform but balked at the $2.5 million the utilities requested to hire contractors to provide customers with more in-depth advisory services on fleet electrification.

Few utilities are offering this kind of service, the PSC said, and any efficiencies gained by a holistic approach to fleet electrification would be overshadowed by the cost to ratepayers, especially if a business decided not to electrify its fleet following an assessment.

Posted on

MISO Officials Explain 2022/23 Capacity Auction Mechanics

MISO officials this week answered questions about the more confusing aspects of the Midwestern shortfall and expensive prices in last week’s capacity auction while stakeholders asked for more supply data from before the auction.

The RTO’s 2022/23 Planning Resource Auction (PRA) resulted in the Midwestern zones, 1 to 7, being deficient by 1.2 GW of their collective planning reserve margin requirements and clearing at the $236.66/MW-day cost of new entry (CONE). (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) However, on the zonal level, only zones 4 to 7 — which include parts of Illinois, Lower Michigan, Indiana, Missouri and western Kentucky — couldn’t meet their local clearing requirements, and they couldn’t find extra supply from the other Midwestern zones.

MISO’s transfer limits between its subregions also kept the Midwest from accessing additional supply from the South that could have counteracted the regional capacity shortage.

Eric Thoms, MISO senior manager of resource adequacy operations, said the RTO’s auction clearing engine uses subregional resource zones and includes the marginal cost of a binding subregional flow limit in prices. In the case of this year’s auction, the South-to-North transmission limit bound. MISO used a 1,900-MW South-to-North limit and a 3,000-MW North-to-South transfer limit in the auction. The RTO begins with the usual 3,000-MW southbound and 2,500-MW northbound limits and subtracts firm service contracts to arrive at the transfer limits used in the auction.

MISO also used Zone 3’s $236.66/MW-day CONE to price the entire Midwest because it is the cheapest of the CONE prices, and the auction is designed to apply the lowest CONE when an entire region is short. The CONE values differ by zone because the cost of building new generation varies regionally.

“The objective of the multi-zone optimization methodology is to minimize the overall costs of capacity,” Thoms explained to stakeholders in a Resource Adequacy Subcommittee teleconference Wednesday.

Stakeholders asked MISO to telegraph a better feel of supply in the weeks and months leading into the auction. They said there was a large delta between confirmed unforced capacity and what was ultimately converted into zonal resource credits. Ahead of the 2022/23 planning year, MISO anticipated a 121-GW coincident systemwide peak, with 157 GW in total installed capacity and just short of 128 GW in total unforced capacity to cover it.

Stakeholders asked if MISO could have disclosed a level of accelerated suspended or retired megawatts ahead of the auction so market participants could have reacted and made more supply available.

Apex Clean Energy’s Richard Seide said the auction results were “astonishing.”

“I know things were getting tight, but if you read the data going into this year’s auction, you didn’t think it was going to go this way by a few hundred megawatts. You thought we were going to slide by again,” Constellation Energy’s John Orr said.

MISO Director of Resource Adequacy Coordination Zakaria Joundi said that while the RTO can’t reveal unit-specific data, it is reviewing the usefulness of the preliminary PRA data it posts.

“I think the process should be more transparent, so that choices to bring more capacity to the market can be viable,” Power System Engineering’s Tom Butz said.

Taylor Martin of the Independent Market Monitor, Potomac Economics, said the IMM tries ahead of time to project what will be unavailable but is bound by multiple confidentiality rules. But he said the Monitor found no evidence of economic or physical withholding.

Thoms also said no market participants this year elected to pay a capacity deficiency charge to MISO. According to MISO rules, load-serving entities can opt to pay out all or a portion of their planning reserve margin requirement.

The auction results are emblematic of the tricky situation MISO faces in navigating its members’ portfolio transition.

The 2022/23 capacity results brought longstanding criticisms of MISO bubbling back to the fore, including its lack of sturdier transmission connections between its South and Midwest regions, a bevy of thermal generation retirements and MISO’s use of a vertical demand curve over a sloped demand curve in the auction.

MISO said members in recent years have been replacing retiring thermal generation with even more megawatts from new intermittent resources.

The auction results come as Consumers Energy — Michigan’s largest electric utility — and stakeholders this week announced that they reached an agreement to close all coal plants by 2025, which could make it one of the first large utilities in the nation to eliminate coal use. The proposal still needs the blessing of the Michigan Public Service Commission. (See Consumers to End Coal by 2025 in IRP Deal with Mich. AG.)

Michelle Bloodworth, CEO of coal lobbying group America’s Power, said EPA’s recent crackdown on coal ash could also idle a little more than 2 GW of coal-fired generation in MISO Midwest as early as the fall. She said MISO should also factor that development into its supply picture.

Stakeholders said it seemed that a lot of the new capacity that MISO and the Organization of MISO States were expecting per their annual resource adequacy did not manifest. Some wondered if the RTO needs to recalibrate its expectations of generation that will complete the interconnection process.

Monitor: Sloped Demand Curve, Please

Monitor David Patton said the auction shortage reinforces the need for a sloped demand curve in the auction, a call he’s been making for 12 years now.

During the Market Subcommittee’s meeting Thursday, Patton said MISO undervalues capacity, sending “bad signals” to market participants. He said MISO’s long history of “near-zero” clearing prices spur too-early unit retirements.

Zonal clearing prices (MISO) Alt FI.jpgZonal clearing prices in the 2022/23 MISO capacity auction | MISO

 

“Since 2019, MISO lost almost 5 GW of capacity in the Midwest that would have been economic if the PRA had set efficient clearing prices,” he said. “Most of these retirements were by unregulated merchant suppliers that rely on the market signals to make investment and retirement decisions.”

2nd Regional Resource Assessment in the Works

MISO will pull together another long-term resource assessment by the end of this year, this time with assistance from its members.

Last year’s first regional resource assessment showed a need for members to add almost 140 GW of new capacity within the next 20 years. (See MISO Resource Assessment: 140 GW Needed Within 20 Years.)

Last year, MISO relied only on public data it independently searched. The regional resource assessment this year will include data sourced directly from members to get a better picture of protracted resource trends. The RTO said it has collected generation information from 75% of its load for the 2022 assessment.

MISO said preliminary results show a lower level of nuclear retirements 20 years out; net neutral natural gas retirements and additions over two decades; and the same 35 GW of coal plant retirements by 2040 that it originally expected last year. It also foresees a 65% reduction in emissions from 2022 levels by 2040.

Posted on

ISO-NE Defends Order 2222 Filing

ISO-NE defended its Order 2222 compliance filing on Wednesday, providing FERC its response to protests from environmental groups, renewable energy industry organizations and Massachusetts’ attorney general.

ISO-NE’s response to the federal order requiring RTOs to allow distributed energy resources to participate in wholesale markets has frustrated advocates, who say it fails to meet the goals laid out by FERC and would limit the availability of behind-the-meter resources to engage the market. (See ‘Beautiful Symphony’ or Bust on Order 2222, Advocates Say)

That frustration led to a number of protests arguing, among other things, that the order doesn’t allow sub-metering, gives utilities too much time to review aggregated DER proposals and that its seven participation models for DERs proposed by ISO-NE aren’t in compliance with Order 2222. Among those protests was a combined filing from environmental groups and another from several industry organizations.  

FERC’s rules technically don’t allow ISO-NE to file an answer to protests, but the grid operator is asking for an exception.

In its filing, ISO-NE argues that it has fully met the requirements of the FERC order.

Metering

Order 2222 gave RTOs flexibility in how they can establish market rules for metering DERs, ISO-NE said in its response.

And the alternatives that advocates proposed in their protests could lead to double counting of services, shift costs to customers without DERs and require new metering infrastructure, the RTO argues.

The filing also cites a previous FERC order in saying that metering at the retail delivery point (as proposed in the compliance filing) is appropriate for demand response resources, rather than the device-level sub-metering proposed in the protests.

And finally, it says FERC should reject the intervenors proposal to allow third-party metering because of double counting and data validation issues.

Utility Review

The protestors also challenged ISO-NE’s rule giving utilities 60 days to review DERs seeking to participate as part of an aggregation.

FERC’s order specifically allowed a 60-day review period, ISO-NE wrote, so the environmental groups’ request to shorten it should not be granted.

It gave a similar response to the industry groups’ proposal that the period for utilities to review the modification of DERAs be shortened.

Participation Models 

Perhaps most significantly, ISO-NE defended its seven participation models for DERAs wishing to take part in the models.

“The standards and requirements associated with each participation model in the Compliance Proposal are tailored to the products and services offered in the New England Markets,” ISO-NE argued, and they meet the requirements of Order 2222.

Specifically, the response provides defenses of ISO-NE’s continuous storage facility model, its settlement-only DERA model and changes to the existing Alternative Technology Regulation Resource.

Posted on

Rhode Island Advocates Hold out Hope for Stalled Clean Energy Policies

Members of the public asked Rhode Island’s climate leaders Tuesday to elevate the policies of three stalled energy-related bills as priority actions for reducing the state’s greenhouse gas emissions.

They said that the policies, which support energy storage and renewable energy deployment, should be a part of the state’s next plan for emission reductions in the electric sector.

Top among the policy priorities was a 100% renewable energy standard (RES) bill (H.7277) that was introduced in February and held for study in March by the House Environment and Natural Resources (ENR) Committee.

Passing a 100% RES by 2030 would be “really helpful,” Greg Gerritt, former executive director of the Environment Council of Rhode Island, said during the Executive Climate Change Coordinating Council (EC4) listening session. Amy Moses, general counsel for Utilidata, echoed Gerritt’s comment, saying that the standard is “critical” for the state.

EC4 hosted the electric sector-focused event as part of a series of listening sessions this year that will inform a legislatively mandated update to the state’s 2016 GHG Emissions Reduction Plan. A 2020 executive order from former Rhode Island Gov. Gina Raimondo put the state on a path to achieving 100% renewable energy, but it has yet to be codified.

Under the existing state RES, 19% of retail electricity supply must come from renewable sources this year, and the state had reached 12% of supply in 2020, according to U.S. Energy Information Administration data.

The Rhode Island Office of Energy Resources (OER) completed a 100% renewable energy study last year that recommended advancing an RES-like mechanism along with enabling actions, such as integrated grid planning, strategic energy storage deployment and regional collaboration on wholesale markets.

Gov. Dan McKee supported the RES bill in March 10 testimony for an ENR bill hearing, saying that the state needs a “largely carbon-free electric generation portfolio” to reach net-zero emissions by 2050. While the bill also received broad support from environmental groups and residents during the hearing, the Northern Rhode Island Chamber of Commerce urged the committee to gather insights from ISO-NE before adopting a mandate to accelerate renewables on the electric grid.

ENR still has the option of considering the RES bill again before the end of the session in June.

Rooftop Solar Cap

Eliminating current size requirements for solar rooftop systems should be an RES-enabling policy in the EC4’s emission-reduction plan update, according to Hank Webster, senior policy advocate and Rhode Island director at Acadia Center.

“We would like to see incentives for prioritizing rooftop solar throughout the state and removal of the cap on rooftop solar,” he said.

The House Corporations Committee took testimony March 1 on a bill (H.7333) that would remove size limitations on net-metered systems, but the committee voted to hold it for study.

In hearing testimony, the Division of Public Utilities and Carriers said the current limit ensures that a rooftop system meets on-site energy needs and protects ratepayers from the costs of “overly large systems.” National Grid also opposed the bill in its testimony, saying that net metering should not make rooftop solar a “revenue stream” for building owners.

Homeowners, however, should have the option to build larger systems that complement neighborhood-level demand or support peak grid demand, Webster said.

Energy Storage

An energy storage bill that the Corporations Committee held for study April 12 represents another priority policy that Webster says should be in the GHG plan update.

The bill (H.8026) would set an energy storage capacity goal for the state of 500 MW by 2032 and direct OER to develop programs and associated funding mechanisms to advance system deployments.

Sunrun supported the bill in hearing testimony, saying energy storage has a “critical role” to play in building a 100% zero-carbon electric grid in the state. The Public Utilities Commission, however, said a legislatively mandated storage compensation program, as proposed in the bill, could be more expensive than current market-based solutions and warrants further study.

Webster said that the 2022 GHG plan, which is due in December, should support a pathway to understanding where energy storage resources are needed across the region and where they can feed the distribution system.

Posted on

FERC Tells PacifiCorp to Refund Premiums

FERC told PacifiCorp this week that it must repay premiums it earned on wholesale electricity sales during the August 2020 Western heat wave that forced CAISO to order rolling blackouts and pushed prices sky-high in other parts of the West (ER21-60).

PacifiCorp received premiums on top of the spot market’s average index prices at Arizona’s Palo Verde trading hub on Aug. 18-19, 2020, when CAISO was struggling to prevent more blackouts like those it ordered Aug. 14-15, and the Western grid was strained by record triple-digit temperatures. (CAISO Blames Blackouts on Inadequate Resources, CPUC.)

Palo Verde wholesale prices on the Intercontinental Exchange (ICE) reached a record $1,515/MWh on Aug. 18 and $1,750 on Aug. 19, according to data posted by the U.S. Energy Information Administration. (The average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas & Electric said in FERC filings.)

Prices outside CAISO in the West fall under the Western Electricity Coordinating Council’s (WECC) soft price cap of $1,000/MWh, which requires sellers to justify prices above the cap to FERC or to issue refunds. The process, instituted in response to the California energy crisis of 2000-01, is meant to avoid the exercise of market power.

Prices above the cap can be justified based on three frameworks — a production cost-based framework, an opportunity cost-based framework or an index-based framework — FERC said in guidance it issued in June 2021. (See FERC Offers Guidance on Exceeding Western Price Caps.)

FERC found that PacifiCorp had justified its prices on Aug. 18-19 using the index-based framework, in which a seller cites an index at a specific trading hub to justify prices that exceed WECC’s soft cap. But FERC said the utility had failed to justify premiums it received above the index prices.

PacifiCorp defended the premiums by arguing it had seven bilateral spot market sales in August 2020 that exceeded the $1,000/MWh price cap. Four were brokered day-ahead transactions, with the price set by the buyer based on the Palo Verde day-ahead ICE index, and three were “direct transactions with counterparties that contacted PacifiCorp,” the commission said.

“PacifiCorp [contended] that, to the extent the prices reflect a premium over the prevailing index price, the premium was set by the customer, and PacifiCorp had no visibility into the prevailing index price for these transactions until after the ICE day-ahead market closed,” FERC wrote. “PacifiCorp notes that it served as a price-taker, which it argues the commission has recognized addresses any concern about the legitimacy of price formation.”

The premiums, which raise the cost of wholesale electricity marginally above the index price, usually are added by customers to “secure energy during times of scarcity,” the utility said.

FERC rejected the argument that the adders were justified.

“The Palo Verde price index already reflects scarcity conditions,” it said. “PacifiCorp’s attempt to justify prices above the soft cap by arguing it was a price-taker is insufficient.”

“In these circumstances, the index-based framework only justifies prices up to the index price and … any premiums above the index must be justified in other ways, which PacifiCorp failed to do,” FERC said. “Accordingly, we find that PacifiCorp has not provided adequate justification for the premiums above the index price.”

The commission directed the utility to refund the premiums to buyers within 30 days and report back to the commission in another 30 days. The decision did not cite specific amounts of the premiums or the total amount that could be at stake.

Four of the five FERC commissioners signed the order.

Commissioner James Danly issued a dissent in which he said FERC was meddling with contracts to sell electricity at market-based rates.

“I would … not require PacifiCorp to pay refunds for the ‘premium’ amount above the price index that PacifiCorp and the willing buyers freely negotiated because no showing has been made that the public interest is seriously harmed by the contract rate,” Danly wrote.

With its decision, FERC was putting sellers in an unworkable position, he said. The commission requires wholesalers to sell electricity, or it will investigate them for withholding and market manipulation, but then it negates market-based prices, he said.

“The de facto result is that we require PacifiCorp to sell, and then we require them to sell at our preferred price,” Danly said. “No wonder there seems to be no end in sight to the supply shortage in California and, increasingly, the Western United States.”

Posted on

CISA Issues Fresh Russia Cyber Warnings

The U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) joined the FBI and National Security Agency — along with security agencies in the U.K., Australia, New Zealand and Canada — on Wednesday to release a report detailing the cyber threats against critical infrastructure that have been detected in connection with Russia’s invasion of Ukraine.

The report, “Russian State-Sponsored and Criminal Cyber Threats to Critical Infrastructure,” presented hostile cyber activities by a host of Russian government agencies, including the Federal Security Service (FSB), Foreign Intelligence Service (SVR), Main Intelligence Directorate (GRU) and Central Scientific Research Institute of Chemistry and Mechanics (TsNIIKhM). Attacks could come “as a response to the unprecedented economic costs imposed on Russia, as well as materiel support provided [to Ukraine] by the United States and U.S. allies and partners,” the report said.

Veteran Cyber Units Hard at Work

Each Russian agency has been linked to previous cyber incidents: Just last month the Justice Department announced it had indicted agents of TsNIIKhM and the FSB for a series of cyberattacks against the global energy industry. (See DOJ Reveals Indictments Against Russian Energy Hackers.) GRU’s Unit 74455 — which analysts have variously dubbed Sandworm, Electrum and Voodoo Bear — is believed to have carried out attacks around the world, including against the Winter Olympics in 2018 and the Ukrainian power grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)

Industroyer, another breed of malware linked to Unit 74455 that knocked out 20% of Ukrainian capital Kyiv’s power grid in 2016, was back in the news recently after Ukraine’s Computer Emergency Response Team reported discovering a very similar attack underway last week. Like the earlier threat, the new “Industroyer2” hack appeared designed to attack the industrial control systems used by electric utilities; however, in this case the attack was stopped before any damage could be done. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Along with these officially government-linked groups, the report identified two malicious actors as “aligned” with Russia but not definitely known to be employed by its government. The first, dubbed Gamaredon or Primitive Bear, has “targeted Ukrainian organizations since at least 2013,” including multiple operations before Russia’s invasion. The other, known as Venomous Bear or Turla, “is known for its unique use of hijacked satellite internet connections” to attack NATO-aligned governments, defense contractors and “other organizations of intelligence value.”

Nominally independent cybercrime groups are another growing threat, the report said, with some gangs pledging support for Russia’s government and threatening to “retaliate against perceived attacks against Russia or materiel support for Ukraine.” Among the groups identified by code name is Wizard Spider, responsible for the Conti ransomware that has targeted more than 1,000 organizations worldwide. Other groups historically have focused more narrowly on the Ukrainian government.

Cybercrime gangs tend not to have the direct support of Russia’s government, even when based in the country; rather, law enforcement often turns a blind eye to their activities as long as they are directed against Russia’s perceived adversaries. The agencies noted that even for the groups that have promised to support Russia’s war in Ukraine, their primary motivation and mode of attack are likely to remain financial rather than participating in government hacking operations.

Warnings Becoming More Urgent

CISA has been in a “Shields Up” posture since Russia’s invasion began in February, calling for critical infrastructure operators to be vigilant for potential cyber interference. Though the agency initially said it had seen “no specific or credible cyber threats to the U.S. homeland,” it and other federal entities — including the White House — have issued more pointed warnings as the conflict wears on and Russia’s military seemed increasingly unlikely to score a clear victory on the battlefield, making a cyber escalation more probable.

“We know that malicious cyber activity is part of the Russian playbook. We also know that the Russian government is exploring options for potential cyberattacks,” CISA Director Jen Easterly said in a release. “We urge all organizations to review the guidance in this advisory as well as visit [CISA’s website] for continually updated information on how to protect yourself and your business.”