FERC Approves $249K Penalties in SERC, RF, Texas RE

FERC on Friday approved nearly $250,000 in penalties leveled by SERC Reliability and the Texas Reliability Entity in separate settlements against Duke Energy and Bryan Texas Utilities (BTU) for violations of NERC reliability standards (NP22-27).

NERC filed the settlements with the commission June 30 in its monthly spreadsheet Notice of Penalty, along with a separate NOP concerning an unnamed entity’s violation of the Critical Infrastructure Protection (CIP) standards; details of this NOP were not disclosed in accordance with NERC and FERC’s policy treating CIP violations as critical energy/electric infrastructure information. (See FERC, NERC to End CIP Violation Disclosures.) In its Friday filing, the commission said it would not further review the settlements, leaving the penalties intact.

Ratings Issues Across Duke Companies

SERC’s settlement with Duke involves FAC-009-1 (Establish and communicate facility ratings) and its successor FAC-008-3 (Facility ratings), which replaced the earlier standard in 2012. According to the NOP, Duke and its Energy Carolinas (DEC) and Florida (DEF) subsidiaries — had multiple instances of “facility ratings that were [not] consistent with their respective facility ratings methodology [FRM],” as called for in FAC-009-1. The violations began in 2007, when the original standard first took effect, and had not been fully resolved at the time of the filing.

The regional entity first learned of the violation in August 2018, when DEC submitted a self-report that DEF had discovered three cases of inconsistent facility ratings at a single 500-kV substation. (DEC submitted the report as part of an existing agreement with SERC.) DEF found that three 500-kV line segments had been recorded in the facility ratings database as bundled line conductors rather than single; as a result, the segments were not documented as the most limiting element in the substation.

During preparations for a subsequent audit by SERC, DEC and Duke discovered and reported additional instances of noncompliance; in a walk-down during the audit, SERC found more ratings that were inconsistent with the FRM. SERC then requested all Duke companies conduct extent-of-condition inspections, which returned as of November 2021:

DEC: 65 instances of noncompliance at 326 facilities;
DEF: 26 instances at 96 facilities; and
Duke: 69 instances at 725 facilities.

SERC identified the root cause of the violations as “the presence of vertical organizational silos,” primarily originating from Duke’s merger with Cinergy in 2006. Following the merger all of Duke’s companies had separate FRMs; while Duke and DEC later merged their FRMs, DEF and Duke Energy Progress still maintained their own facility ratings programs. This contributed to “a lack of uniformity and coordination over the years [and] a lack of awareness of the facility ratings program challenges” across Duke’s companies.

Duke’s mitigation activities include committing to form teams for each region to define walk-down processes and timelines and complete field walk-downs for all bulk electric system transmission substations at all Duke companies, reporting walk-down results and correcting any identified ratings discrepancies. The companies have also promised to conduct training for all relevant personnel and “assign additional staff to support FRM-related processes.”

Because part of the violations occurred in ReliabilityFirst’s footprint, SERC will share the $210,000 penalty with its fellow RE; based on the relative net energy for load of each region, RF will receive $85,260.

BTU also Settles over Ratings

Texas RE’s $39,000 settlement with BTU also stems from violations of FAC-009-1 and FAC-008-3, along with FAC-008-5. The noncompliance was first detected by Texas RE during a compliance audit, with a subsequent review by BTU discovering nine facilities in all where facility ratings were not consistent with the FRM.

The RE attributed the violation to “overreliance on stale field verifications,” noting also that BTU had not done a good enough job communicating with neighboring entities on the equipment ratings for their jointly owned facilities. Instead of using old field data, Texas RE said BTU could have proactively checked and verified facility ratings “when the opportunity was available,” for example during construction and maintenance.

Texas RE assessed the violations as a moderate risk to the reliability of the bulk power system, noting that no harm is known to have occurred as a result. However, it also said the violations were aggravated by their length, having begun in 2007 and continued until 2021 when BTU recalculated the inaccurate ratings and reported the results to ERCOT.

July 31, 2022

What’s in the Inflation Reduction Act, Part 2

The passage of the Inflation Reduction Act of 2022 (IRA) (H.R. 5376) — formerly known as the Build Back Better Act — is once again hanging on the vote of a conservative Democrat, in this case Sen. Krysten Sinema (Ariz.) and not Sen. Joe Manchin (W.Va.).

Sinema was not part of the negotiations between Manchin and Senate Majority Leader Chuck Schumer (D-N.Y.) that resulted in a deal on the bill, announced Wednesday. (See Schumer, Manchin Reach Climate Deal.) She has in the past opposed one of the bill’s key tax provision — the closing of so-called carried-interest loophole — which could cut into the lucrative income that asset managers earn from the large investments they manage.

Meanwhile, Manchin blitzed all the major Sunday talk shows to promote the bill. “This is a red, white and blue bill,” not green, he told Jake Tapper on CNN’s “State of the Union.”

While Sinema was not directly involved in the drafting of the IRA, Manchin said many of its provisions were influenced by her. Manchin also justified the secret negotiations between himself and Schumer because “I didn’t think it would come to fruition. I didn’t want to have disappoint people again,” he said.

“I think that basically when [Sinema] looks at the bill and sees the whole spectrum of what we’re doing and all of the energy we’re bringing and all the reduction of prices and fighting inflation … hopefully, she will be positive about it,” he said.

As they await Sinema’s decision and a review of the law by the Senate parliamentarian, clean energy companies and advocates are lining up with other Senate Democrats to push for passage of the bill, even if the Senate does not vote on it before its planned monthlong recess begins Aug. 8. (See related story, What’s in the Inflation Reduction Act, Part 1.)

Here are some of the key stakeholders and the provisions they support.

Carbon Capture and 45Q

The carbon capture industry has long lobbied for expanding the 45Q tax credit to apply to more projects by raising incentive amounts and lowering capture threshold amounts, the minimum CO₂ facilities would have to capture to qualify for the credit.

The IRA would deliver on both counts. Under the bill, the incentive for carbon captured and sequestered in geologic formations, such as saline aquifers, would jump from $50/MT to $85/MT. The incentive for carbon utilization ― for example, for either alternative fuels or enhanced oil recovery ― would increase from $35/MT to $60/MT.

The incentives for direct air capture would go as high as $180/MT for permanently sequestered CO₂ and $130/MT for carbon utilization or enhanced oil recovery.

Reductions in capture thresholds are even more dramatic. To qualify for the credit currently, CCS equipment at an electric generating facility has to capture 500,000 MT/year; under the IRA, the amount would be slashed to 18,750 MT/year. The threshold for other industrial facilities falls from 100,000 MT/year to 12,500 MT/year, and the threshold for direct air capture projects is cut from 25,000 MT/year to 1,000 MT/year.

If passed, these “monumental enhancements” could “provide the most transformative and far-reaching policy support in the world for the economy-wide deployment of carbon-management technologies,” said Madelyn Morrison, external affairs manager for the Carbon Capture Coalition. “Economy-wide commercial deployment of carbon-management technologies and infrastructure [are vital] if midcentury global temperature targets are to remain within reach.”

Green Hydrogen

Hydrogen production got a major boost in the Infrastructure Investment and Jobs Act with its $8 billion for regional clean hydrogen hubs and $1 billion aimed at reducing the cost of the electrolysis process used to produce zero-emission hydrogen.

The IRA follows up on this with a substantial production credit of 60 cents/kg for clean hydrogen, which could rise to $3/kg for facilities that pay prevailing wages and have certified apprenticeship programs.

Hydrogen production worldwide is estimated at 120 million MT, only about 1.9% of which is green, according to the International Energy Agency.

The bill would also provide reduced tax credits — 12 to 20 cents/kg — for blue hydrogen, produced from natural gas with carbon capture, depending on the level of emissions associated with any specific facility. However, a plant already receiving 45Q tax credits for carbon capture would not be able to receive the hydrogen credits.

These tax credits could make green hydrogen cheaper to produce than gray hydrogen, produced from natural gas without carbon capture, said Mona Dajani, global co-head of the Energy and Infrastructure Projects Team at New York law firm Pillsbury Winthrop Shaw Pittman.

Facilities qualifying for the $3/kg credit “will make it cheaper to produce [clean] hydrogen here in the U.S. than anywhere else in the world, because of natural gas prices,” she said.

Advanced Nuclear and HALEU

The IRA provides $700 million for building out a U.S. supply chain for high assay, low-enriched uranium (HALEU), which is the higher-density nuclear fuel needed for the advanced nuclear reactors being developed.

Unlike the uranium used for existing reactors in the U.S., HALEU has a higher level of the U-235 isotope, which allows it to produce more power per unit of volume, which in turn allows for smaller reactors.

According to Judi Greenwald, executive director of the Nuclear Innovation Alliance, $500 million of the IRA funds would go to supply chain development, with $100 million each for research and development, and for the transportation system needed to support the U.S. industry.

“It’s a significant investment for a really important component for advanced reactors,” Greenwald said. “A key condition for the success for advanced reactors is the availability of HALEU.”

At present, the Department of Energy is the only producer of HALEU in the U.S., and it can only enrich a small amount for use in research. Lawmakers on both sides of the aisle are eager to develop a domestic supply chain because Russia is the only other major producer of HALEU.

The IRA would provide another boost for advanced nuclear in the technology-neutral energy tax credits that will replace renewable energy production tax credits beginning in 2025, specifically for facilities producing zero-carbon energy. For plants complying with prevailing wage and apprenticeship requirements, the credit would be 1.5 cents/kWh.

Once a facility is online, credits would be available for 10 years, which “will make a huge difference in helping to get these early reactors built,” Greenwald said. “As you build them, you learn by doing, and then they get cheaper. This is the way we’re going to really help to commercialize advanced nuclear.”

Two advanced reactors, one in Wyoming and one in Washington state, being built with DOE funds are scheduled to be online by 2028.

Methane Emissions

The IRA would tackle methane emissions with a mix of incentives for mitigating emissions at wells, pipelines and other facilities, and penalties for emissions exceeding certain levels.

On the incentives side, the bill would give EPA $850 million through Sept. 30 2028, for “grants, rebates, contracts, loans and other activities” aimed at reducing methane emissions. The funds could be used for monitoring and reporting emissions, installing innovative emission-cutting equipment and plugging wells on nonfederal land.

An addition $700 million is allocated for similar activities targeted at “marginal conventional wells,” those that are more expensive to run because of environmental issues or low levels of production.

The bill would also authorize EPA to “impose and collect” penalties at a range of oil and gas facilities — including on- and offshore production plants, pipelines and storage — that emit more than 25,000 MT of CO₂ per year. The thresholds for different kinds of oil and gas facilities vary, but the penalties are uniform, starting at $900/MT in 2024, $1,200/MT in 2025 and $1,500/MT in 2026 and beyond.

These provisions got a chilly reception from fossil fuel groups.

“While there are some improved provisions in the spending package … we oppose policies that increase taxes and discourage investment in America’s oil and natural gas,” said Amanda Eversole, chief advocacy officer of the American Petroleum Institute.

The American Gas Association tweeted out praise for the bill’s support for hydrogen and renewable natural gas but was mum on the methane provisions.

OSW, Permitting, Clean Ports

The IRA would reverse the Trump administration’s 10-year moratorium on development off the shores of Florida and the Carolinas. It also would begin a process for exploring the feasibility of offshore wind development in Puerto Rico, Guam, American Samoa, the U.S. Virgin Islands and the Northern Mariana Islands.

To accelerate the permitting process, the bill allocates $125 million for DOE, $100 million for FERC and $150 million for the Department of the Interior “to provide for the hiring and training of personnel, the development of programmatic environmental documents, the procurement of technical or scientific services for environmental reviews, the development of environmental data or information systems, stakeholder and community engagement, and the purchase of new equipment for environmental analysis to facilitate timely and efficient environmental reviews.”

The bill would also provide $400 million through 2031 to provide incentives for businesses serving communities with high levels of air pollution to replace heavy-duty diesel vehicles with zero-emission vehicles. Another $2.25 billion would be available for zero-emission equipment at U.S. ports.

July 31, 2022December 10, 2023

PJM MRC/MC Briefs: July 27, 2022

Markets and Reliability Committee

2022 Quadrennial Review

The PJM Markets and Reliability Committee last week received a briefing on four alternative sets of capacity auction parameters as part of its 2022 Quadrennial Review.

Members will be asked to select one of the packages from PJM, the Independent Market Monitor, Calpine and Cogentrix at the MRC’s Aug. 24 meeting, which will be followed by a vote at a special Members Committee meeting. The votes are advisory, however; the Board of Managers will make the decision on what parameters to propose to FERC.

The parameters — which include the shape of the variable resource requirement curve, the cost of new entry for each locational deliverability area, and the methodology for determining the net energy and ancillary services (E&AS) revenue offset — would be effective with the July 2023 capacity auction for delivery year 2026/27.

Cogentrix’s proposal was the overwhelming favorite in a vote of the Market Implementation Committee on July 19-22, winning 73% support, with 62% saying they preferred it over the status quo. The PJM and Calpine packages tied at 28% each, while the Monitor’s proposal garnered only 15% support. (Members were permitted to vote for more than one option.)

The Cogentrix proposal, which was presented by GT Power Group’s Jeff Whitehead, adopts the status quo:

- - reference technology (combustion turbine);
  - variable operations and maintenance (VOM) parameter (major maintenance and operating cost included);
  - simulation method for calculating net energy revenues (peak hour dispatch); and
  - net E&AS (historical-looking inputs).

Cogentrix’s proposal also adopts PJM’s fuel assumption (firm transportation) and for the three points on the VRR curve but with the use of a CT rather than the RTO’s combined cycle reference technology.

The Cogentrix curve would result in a price of about $600/MW-day for an unforced capacity (UCAP) reserve margin of about 7.5%, up from about $500/MW-day with the current curve, according to PJM. The curve is almost identical to the RTO’s proposed curve above a 10% UCAP reserve margin.

Whitehead said Cogentrix chose a CT as the reference technology because it is less dependent on E&AS revenue than combined cycle plants. “We’ve seen how much E&AS revenues can change … in a relatively short period of time,” he said, a danger when parameters are being set four years in advance of delivery. LMPs, which hovered around $20/MWh “around the clock” during the coronavirus pandemic, averaged about $67/MWh in June, he noted.

He said CTs are also the most likely generation to be built in a “capacity crunch.”

David Scarp Scarpignato (PJM) Content.jpg

David “Scarp” Scarpignato, Calpine | PJM

He acknowledged energy storage may be a more appropriate reference technology in the future, noting they are “extremely dependent” on capacity revenue, with regulation their only other revenue source.

David “Scarp” Scarpignato of Calpine said his company’s proposal was based on PJM’s and the recommendations of the RTO’s consultant, The Brattle Group. However, Calpine favored a historic E&AS offset rather than the forward-looking approach proposed by PJM and the Monitor.

“It’s a bad time with all the volatility in the gas markets to be switching to the forward” approach, Scarp said.

Calpine chose PJM’s proposal for the first two points on the VRR curve and the status quo for the third point.

“The bottom part of the curve makes a lot of sense,” Scarp said. “MISO has a vertical curve. And we saw how that worked out in the last auction.” (See MISO Capacity Auction Values South Capacity at a Penny.)

Monitor Joe Bowring made a case for his proposal to use only operating costs in the VOM calculation. “Ideally the VOM would all be in avoidable costs, but we recognize it’s not currently” he said. As a result, the IMM proposed including major maintenance in energy offers. “If they are in the energy offers, they should not be in avoidable costs,” Bowring said.

Manual Revisions OK’d

The MRC endorsed:

- - changes to Manual 01: Control Center and Data Exchange Requirements, Manual 18: PJM Capacity Market and Manual 28: Operating Agreement Accounting to conform with new testing requirements for demand response and price-responsive demand. The changes, which were approved by FERC in June 2020, will become effective with delivery year 2023/24 (ER20-1590).
  - updates to Manual 14D: Generator Operational Requirements to support the process timing changes for generation deactivations. (See “‘Quick Fix’ Changes OK’d for Manual 14D,” PJM Operating Committee Briefs: July 14, 2022.)
  - revisions to Manual 28: Operating Agreement Accounting to support the start-up cost offer development proposal the MRC approved in May, which allows costs associated with a resource’s initial ramping megawatts and soak costs to be included in its start cost. The MC later endorsed related changes to Manual 15: Cost Development Guidelines, tariff definitions, Attachment K, Operating Agreement definitions, and Schedules 1 and 2. (See “Start-up Cost Offer Development Proposal Endorsed,” PJM MRC Briefs: May 25, 2022.)

Members Committee

Application of Designated Entity Agreement

PJM’s notice that it planned to make a Federal Power Act Section 206 filing asserting that the OA’s provisions on designated entity agreements (DEAs) are unjust and unreasonable prompted the cancellation of scheduled MRC and MC votes on competing issue charges on the matter.

One issue charge was proposed by consumer advocates for Delaware and New Jersey, and a second was by East Kentucky Power Cooperative on behalf of transmission owners. The latter would make out of scope any consideration of changes to the rights and responsibilities of PJM and the TOs under the Consolidated Transmission Owners’ Agreement.

Greg Poulos, CAPS | PJM

The sponsors withdrew their proposals after PJM gave notice of its planned FERC filing on the MRC and MC agendas. PJM also gave the MC “notice of consultation” of a potential filing under FPA Section 205 to revise the pro forma DEA in Attachment KK of its tariff.

“It didn’t make sense to have both a FERC proceeding and a stakeholder proceeding going on at the same time,” explained Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).

On July 26, a group of load-side stakeholders beat PJM to FERC, filing a complaint asking the commission to force the RTO to require incumbent TOs to sign DEAs on “immediate need” projects. The complainants contended the RTO has violated the OA by refusing to do so. (See related story, PJM Challenged on Oversight of ‘Immediate Need’ Tx Projects.)

PJM attorney Pauline Foley said the RTO received the stakeholders’ complaint late last Tuesday afternoon. “PJM is reviewing the complaint and assessing its path forward,” Foley told the MRC on Wednesday.

‘Seeding’ the Matrix

Members endorsed a proposal to allow PJM and stakeholders to add options to a Consensus Based Issue Resolution (CBIR) matrix before posting the matrix for discussion.

The change will allow PJM and stakeholders to offer options after completing the identification of design components (Step 1) and before posting to facilitate creation of the options matrix (Step 2) prior to solution package development (Step 3).

PJM’s Dave Anders said the proposal by John Horstmann of Dayton Power & Light and Adrien Ford of Old Dominion Electric Cooperative to modify Manual 34: PJM Stakeholder Process would address the “writer’s block” that sometimes occurs at the beginning of the matrix development.

Bowring said his prior concern that the proposal would give PJM an advantage were addressed by assurances that any options proposed by the RTO could be ignored. (See “Members Debate Change to CBIR Matrix Procedure,” PJM Stakeholders Pump the Brakes on ‘Clean Energy Expertise’ for Board.)

Steve Lieberman of American Municipal Power said he thought the change was unnecessary because the individuals sponsoring a problem statement and issue charge should be prepared to initiate discussion of options. But he said he was “not willing to fall on my sword” by opposing it.

The measure passed by acclimation with one objection and two abstentions.

PJM Annual Meeting

PJM will hold its first off-site Annual Meeting since the pandemic on Oct. 24-26 at the Hyatt Regency Chesapeake Bay in Cambridge, Md. Registration will be conducted online between Aug. 1 and Oct. 19. No walk-up registrations will be permitted. The fee for guests will be $400.

‘Clean Energy Expertise’ Requirement

The Illinois Citizens Utility Board presented three proposed revisions to the OA to add a requirement that one member of the PJM board have “clean energy resource expertise.”

Albert Pollard, who heads CUB’s CLEAR-RTO project, said one of the proposed revisions — requiring “expertise and experience in the development, integration, operation or management of clean energy resources” — was nearly identical to language the RTO is using in its current search for a replacement for Manager Sarah Rogers, who attended her final MC meeting Wednesday.

Pollard said the change is needed because the transition to carbon-free generation is a “top priority” for the RTO.

ODEC’s Ford questioned whether the OA should be revised. Cybersecurity expertise is also important to the board but is not mentioned in the agreement, she said.

“If the [requirements] matrix gets too big, it might result in focusing on some areas of expertise and neglecting of others,” she said.

MC Chair Erik Heinle said the issue will likely be on the agenda for the committee’s Sept. 21 meeting.

July 31, 2022June 14, 2023

NYISO Management Committee Briefs: July 27, 2022

Grid Performs Well in July Heat Wave

The New York grid performed well in the summer’s first heat wave July 20 to 24, Aaron Markham, NYISO vice president of operations, told the Management Committee on Wednesday.

NYISO and transmission owners recalled facilities to service and rescheduled transmission and generation outages to prepare for the hot weather. That week’s peak load occurred on July 20, a Wednesday, at 30,505 MW, or just over 97% of the baseline forecast for the summer, Markham said.

NYISO July Peak Loads (NYISO) Content.jpg

July 20 zonal peak loads in the New York Control Area | NYISO

“In general, generation performed well,” Markham said. “From a transmission perspective, the Neptune cable with PJM did return to full capability on Tuesday, [July 19,] so it was able to supply additional megawatts into Zone K [Long Island] from PJM.”

The Western New York public policy transmission project was also effective at reducing supply bottlenecking through the period, Markham said.

The ISO did activate emergency demand response and special-case resource (SCR) programs in Zone F [the Capital District] on both Tuesday and Wednesday in response to a forced outage at the 115-KV Greenbush substation in that area, which caused some supply bottling and added to transmission congestion into the region, he said.

“In summary, things went well, and we are watching the weather for next week,” Markham said. “It looks like it is warming up again, probably not to the level we experienced last week, but we will continue to monitor that and take actions as needed to be ready for it.”

June LBMPs Rise Slightly; Gas Prices Ease

NYISO locational-based marginal prices averaged $76.72/MWh in June, up from $70.60/MWh the previous month, COO Rick Gonzales said in delivering the monthly operations report.

Day-ahead and real-time load-weighted LBMPs came in higher compared to May. Year-to-date monthly energy prices averaged $87.37/MWh, a 115% increase from $40.59/MWh in June last year.

June’s average sendout was 422 GWh/day, higher than the 372 GWh/day in May but lower than the 458 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $6.91/MMBtu for the month, down from $7.39/MMBtu in May and up 164.5% year-over-year.

Distillate prices were up 115.4% year-over-year but mixed compared to the previous month. Jet Kerosene Gulf Coast averaged $30.68/MMBtu, up from $29.17/MMBtu in May. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $31.30/MMBtu, down from $32.97/MMBtu in May.

June uplift decreased to ‑61 cents/MWh from ‑5 cents/MWh the previous month, and total uplift costs, including NYISO’s cost of operations, came in lower than those in May. The ISO’s local reliability share dropped to 46 cents/MWh in June from 60 cents/MWh the previous month, while the statewide share decreased to ‑$1.07/MWh from ‑65 cents/MWh in May.

No RS1 Cost-of-service Study

The MC voted not to conduct a new Rate Schedule 1 cost-of-service study in 2022-2023. (See “RS1 Cost-of-service Study,” NYISO Management Committee Briefs: June 14, 2022.)

The last study, which considers the impact of the significant market design changes to be implemented, was done in 2011, and the tariff requires the committee to vote on whether to conduct one each year.

CEO Rich Dewey said NYISO will review the steps required to make a tariff change to remove the topic from requiring an annual vote. The ISO has plenty of work to do with the projects now underway, but next year it will come to the issue prepared with information on how much human resources would be needed to perform the cost-of-service study, he said.

“Then we’ll have better data in terms of how that intersects with other efforts within the project schedule, and market participants can be more informed about what that impact might be,” Dewey said.

Bad Debt Loss Methodology

The committee approved a recommendation from the Business Issues Committee to adopt a proposal from DC Energy to change the “look back” period in the tariff for determining each participant’s contribution to recover a bad debt loss, expanding the period from one month to three.

Bruce Bleiweis, director of market affairs for DC Energy, presented the change and said the company believes the goal of the payment default and bad debt loss allocation methodology is to spread the loss fairly based on NYISO stakeholders’ overall billing determinants. (See “Bad Debt Loss Methodology,” NYISO Business Issues Committee Briefs: June 22, 2022.)

One stakeholder asked whether the proposal had any risk of increasing market participants exposure to bad debts.

“This proposal does nothing to change the amount of credit or collateral that we have here,” said Sheri Prevratil, NYISO manager of corporate credit. “If a market participant defaults, we would always use that credit support first to cover any default before we declared a bad debt loss. … The ISO has no objection.”

July 29, 2022

Stakeholders Troubled over MISO Response to FERC Planning NOPR

MISO’s response to FERC’s proposed transmission planning rule will emphasize its worry that it could be too arbitrary and bog down the RTO with compliance check marks.

The grid operator plans to send comments to the commission in August warning against an overly prescriptive rulemaking. It will say it is concerned over the notice of proposed rulemaking’s level of detail and specifics and that “ongoing compliance will impede ongoing expansion.”

However, some stakeholders said this week they are worried that MISO’s fixation on specifics could leave the nation with another toothless transmission rulemaking.

MISO staff said its transmission planning already covers the NOPR’s suggestion for scenario-based regional transmission planning (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

During a Planning Advisory Committee (PAC) meeting Wednesday, MISO’s Jackson Evans said that while the RTO supports the aim of long-term, scenario-based planning, grid operators need flexibility “to meet the unique needs of the regions and their stakeholders.”

“There’s really no one way to do this correctly,” Evans said. He said MISO doesn’t want to be forced to “take resources away from its existing planning and devote them to compliance.”

Evans said an overly prescriptive rule might imperil the grid operator’s ongoing planning under its long-range transmission plan (LRTP) and its joint targeted interconnection queue (JTIQ) study with SPP.

“MISO was a leader in this area before this week,” Evans said, referencing the Board of Directors’ approval of the $10.3-billion LRTP Monday. (See MISO Board Approves $10B in Long-range Tx Projects.)

MISO said FERC should “order direct changes to regions it deems to be insufficient in meeting objectives” and said the commission should exercise its Section 206 authority and “tailor its focus” to regions that are not performing robust planning.

Stakeholders Push Back

Multiple stakeholders said FERC Order 1000’s failure to spur transmission projects is evidence that the commission should be more prescriptive, not less, when it comes to planning.

“I’m not saying we need a nanny state, but we need a prescriptive set of requirements,” the Union of Concerned Scientists’ (UCS) Sam Gomberg said during a cost-allocation meeting Tuesday.

Others said MISO should assume there’s always room for improvement and that FERC’s final rule could help the RTO achieve better quality planning.

“I think it would be arrogant to assume we’re doing it 100% right and we’re perfect,” Customized Energy Solutions’ Ginger Hodge said during the PAC meeting.

Andy Kowalczyk of activist group 350 New Orleans suggested MISO highlight the ingredients of its planning success with FERC to help shape minimum requirements. “I strongly urge MISO to lean not too hard into flexibility,” he said.

“MISO is a leader in transmission planning, but that doesn’t mean we can and shouldn’t do better,” Sustainable FERC Project attorney Lauren Azar said.

Azar said MISO’s planning aims can be swayed or stymied by stakeholders, who are in some instances able to “thwart” transmission planning. She pointed to the 2017 regional transmission overlay, which failed to yield a project, as an example. (See Early Release for MISO Long-Term Tx Overlay Study.)

“We’re more than five years behind in building out a grid,” she said.

Azar said some nationwide standards could help MISO and the nation overcome resistance to grid expansion.

Mississippi Public Service Commission attorney David Carr disputed the idea that the 2017 regional overlay study was ever meant to result in projects. He characterized the study as MISO’s response to the Clean Power Plan, which was ultimately struck down.

Basking in LRTP’s Afterglow

MISO took a victory lap after approving its first LRTP portfolio.

During an executive update Tuesday, Aubrey Johnson, vice president of system planning, said he was “pleased and excited” that the board voted in favor of the LRTP’s 18 lines. He said staff will now study a second set of transmission needs for MISO Midwest that considers a more rapid fleet change and decarbonization.

“Growing pressures on the fossil fuel industry are accelerating retirements,” Johnson said. He added that new renewable energy additions aren’t currently keeping pace as a reliable, accredited replacement.

“It is clear that the future is going to look very different than the past,” he said.

With the LRTP’s approval, MISO and SPP’s JTIQ study investment will shrink from $1.65 billion to $1.06 billion. The portfolios contain the same two 345-kV projects in North Dakota and Minnesota. MISO decided several months ago that it would independently pursue the projects under its regional planning; it has said SPP’s share of benefits from the projects are negligible and not worth pursuing in cost splits. (See MISO Stakeholders Uneasy Over Long-range Tx, JTIQ Overlap.)

The NOPR and long-term planning discussion come as MISO’s cost-allocation stakeholder group mulls new benefit metrics for transmission projects that strengthen the grid’s reliability and resilience. On Tuesday, the group discussed how to quantify the benefits of a line’s ability to withstand extreme weather events and valuing a minimum transfer capability.

Climate scientist Rachel Licker, with UCS, said it’s clear that climate change is driving more common and longer-lasting heat waves, which will intensify air conditioning demand. She said MISO may be underestimating future demand for cooling in its modeling. Licker added that nighttime lows are no longer dipping to historic averages, making air conditioning use at night more common.

Gomberg said MISO should value transmission that helps achieve decarbonization to avoid more devastating heat waves and storms, which can decimate power lines and equipment.

July 29, 2022November 30, 2023

FERC Proposes Allowing RTOs to Share Credit-related Info

WASHINGTON — FERC on Thursday proposed allowing RTOs and ISOs to share credit-related information about market participants, fulfilling one of the main requests the grid operators made at a technical conference last year (RM22-13).

The Notice of Proposed Rulemaking, approved unanimously at the commission’s monthly open meeting, would require the grid operators to revise their tariffs to eliminate confidentiality provisions that prevent them from sharing such information. They would also be allowed to use received information for the same purposes for which they use information from their own market participants.

Allowing this information sharing “could improve the accuracy of credit exposure and risk assessments across multiple electric power markets,” the commission said in a statement. “It also could enable market operators to respond to credit events more quickly and effectively, thereby minimizing the overall risks of unexpected defaults by market participants.”

At a technical conference in February 2021, RTO credit risk officials told FERC that although they meet monthly with their counterparts to share best practices, confidentiality rules prevent them from sharing market participant-specific information, even if the participant may pose a credit risk in multiple markets. (See RTOs: Let Us Share Trading Info.)

The commission agreed this is a problem.

“Negative credit events affecting a market participant’s credit standing in one market may impact its credit standing in other markets,” FERC said in its proposal. “An RTO/ISO that cannot obtain market participants’ credit-related information arising from their activities in other organized wholesale electric markets may not be able to fully protect its organized wholesale electric market from mutualized default risk.”

The commission also specified that information sharing must not be predicated on a market participant’s prior notice or consent. “A market participant facing financial difficulty would have little incentive to consent to credit-related information sharing,” it said.

Comments on the NOPR are due 60 days after publication in the Federal Register.

Collateral Requirements

The technical conference stemmed from PJM’s debacle with GreenHat Energy, which FERC accused of defrauding the RTO by acquiring a massive 890 million-MWh portfolio of financial transmission rights with only about $550,000 in collateral. When it defaulted on the portfolio in 2018, its three principals made off with $13 million and left PJM members holding a $179 million bag, FERC said in a January lawsuit after the company failed to pay $242 million in fines. (See FERC Levies $242M in Fines on GreenHat, Owners.)

FERC cited GreenHat in a second unanimous order Thursday requiring CAISO, ISO-NE, NYISO and SPP to show cause as to why they shouldn’t revise their tariffs to include provisions ensuring FTR market participants maintain sufficient collateral (EL22-62, et al.).

The commission said that after considering remarks at the technical conference and comments in that docket, it believes “that two specific practices may be particularly critical to effectively managing credit risk for FTRs”: a mark-to-auction mechanism and a volumetric minimum collateral requirement. Three of the grid operators cited in FERC’s order already implement one practice, but not the other; CAISO implements neither.

The first practice requires that participants maintain sufficient collateral to support the change in value of the FTR positions they hold based on the most recent auction prices for those FTRs. The commission noted that GreenHat’s losing positions went unnoticed by PJM because the RTO used historical FTR values. Since the company’s default, PJM — along with ISO-NE, MISO and NYISO — revised their tariffs to implement mark-to-auction mechanisms.

“While CAISO has limited opportunities to update the collateral requirements of [congestion revenue rights], it does not have a robust mark-to-auction FTR collateral requirement similar to what has been adopted recently in other organized wholesale electric markets,” FERC said. “SPP’s current TCR [transmission congestion rights] collateral requirements also do not include updating of collateral requirements based on the current value of a market participant’s TCR portfolio for all TCR positions.”

In addition, a minimum collateral requirement based on volume ensures that a market participant is required to cover potential defaults even when it has offsetting positions, FERC said.

“In some RTOs/ISOs, market participants are allowed to net FTRs with negative collateral requirements against FTRs with positive collateral requirements within the market participant’s portfolio, which can lead to large, risky FTR portfolios that require little or no collateral,” FERC said. “This can be a problem if future congestion is significantly different than historical congestion because the collateral held by the RTO/ISO may be insufficient for a portfolio’s risk.”

MISO, PJM and SPP all instituted volumetric minimum requirements after GreenHat’s default. “While [CAISO, ISO-NE and NYISO] establish minimum capitalization and participation requirements, they appear to lack any volumetric minimum collateral requirement that scales with a participant’s FTR portfolio to ensure participants cannot minimize their required collateral without correspondingly reducing their risk,” FERC said.

CAISO, ISO-NE, NYISO and SPP must file their responses within 90 days.

July 29, 2022

Xcel Sees Benefits in $3.2B Transmission Opportunities

Xcel Energy executives Thursday praised both the MISO long-range transmission plan (LRTP) and late-breaking agreement in D.C. over the $670 billion Inflation Reduction Act, telling financial analysts both will help the company add 10 GW of renewable energy in its resource plans.

CEO Bob Frenzel said the company is “excited about our transmission expansion opportunity” and expects a $1.2 billion investment for six projects in the LRTP’s $10 billion first tranche of projects. Several projects in Xcel’s Wisconsin footprint have been identified as upgrades, which will keep them in the company’s hands. (See FERC Allows MISO to Exclude Tx Projects from Competition.)

Combined with Xcel’s Colorado Power Pathway — a $1.7-$2 billion, 560- to 650-mile project with regulatory approval — and the transmission needs in its Minnesota resource plan, the company now has about $3.5 billion in large-scale transmission projects.

Frenzel said that will help Xcel add to the renewables it needs for its Minnesota and Colorado resource plans and reach its target of 80% carbon reductions by 2030.

The Minneapolis-based company also reacted positively to the deal reached Wednesday between Senate Majority Leader Chuck Schumer (D-N.Y.) and Sen. Joe Manchin (D-W.Va.) on a climate package that could be up for a reconciliation vote. (See Schumer, Manchin Reach Climate Deal.)

“It appears to include nearly all the broader clean energy tax credits, including new and extended tax credits for wind, solar, hydrogen storage and nuclear,” Frenzel said. “The energy provisions included in the act would provide substantial customer benefits and help enable our clean energy transition while keeping our customer bills affordable. There’s still a lot of twists and turns that can happen in Washington, but we’re optimistic that the bill could become law.”

Xcel reported second-quarter earnings of $328 million ($0.60/share), slightly above last year’s second-quarter earnings of $311 million ($0.58/share). Operating earnings came in at $0.60/share, in line with the Zacks Consensus Estimate.

The company’s share price closed at $72.21 Thursday, up 2.8% from the previous close.

July 29, 2022June 14, 2023

SPP Regional State Committee Briefs: July 25, 2022

SPP’s Regional State Committee on Monday approved its Cost Allocation Work Group’s recommendation to approve a congestion-hedging solution for three DC ties that will connect the RTO’s Eastern and Western interconnection footprints.

The DC ties are owned by members of SPP’s Western Energy Imbalance Service market, providing up to 510 MW of capacity for RTO operations. Other DC ties could be added as the grid operator continues its Western expansion.

The DC Tie Solution Group developed the recommendations earlier this year in a white paper. It said the ties provide a necessary link to “facilitate single market operations” between the two interconnections and to ensure the best use of the facilities and maximum market benefit.

Dana Murphy, OCC | SPP

The RSC has agreed that a DC tie cost-allocation methodology should be developed because of their unique operational characteristics and their market functionality. According to the white paper, the AC portion of the transmission-service paths that cross a specific DC tie will be awarded auction revenue rights (ARRs) and transmission congestion rights (TCRs) as a single path source to sink and then settled in multiple parts. The rights will be settled in two stages, with the AC portions settling in their respective interconnections. Day-ahead market congestion rent across the DC tie in both stages will be an option style, with the AC portions remaining as obligations.

The solution group recommends a four-year transition period. In the first four years, DC tie congestion settlement is removed from the TCR market. After that, the DC tie settlements process moves to SPP’s existing TCR market approach. TCR holders will be compensated for a specific tie’s congestion based on the awarded TCR megawatt amount.

Legacy facilities’ annual transmission revenue requirement will remain in their respective local transmission zone and will also remain part of the zone’s network and point-to-point rates. However, increased use of the DC ties will result in increased maintenance costs, the solution group said, with increased costs being borne fully by the tie owner’s zone unless cost recovery mechanisms are put in place.

The white paper creates two new revenue recovery mechanisms, an access charge and an incremental market efficiency use (MEU) charge, to recognize beneficiary-pays principles and recover increased operational costs due to market operations.

CAWG to Continue Safe Harbor Study

The committee directed the CAWG to spend at least another quarter exploring further changes to SPP’s three safe harbor criteria and its $180,000/MW limit and bring back the results to its October meeting.

The RSC’s review of safe harbor criteria is its first since 2018. A 2020 study was canceled in 2019 following the regulators’ decision to conduct in-depth safe harbor reviews every five years. (See “Regulators Cancel 2020 Safe Harbor Review,” SPP Regional State Committee Briefs: July 29 & Aug. 5, 2019.)

The reviews are intended to determine whether modifications should be made to the thresholds used to determine what project costs should be borne by the load-serving entities (LSEs) making long-term transmission service requests (TSRs).

SPP’s aggregate transmission service study process combines into a single study all long-term point-to-point and designated network resource requests received during a specified time period. The RTO splits the costs of transmission projects between the entire SPP footprint and the LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.

The safe harbor exempts LSEs from upgrade costs when a TSR meets the aggregate studies’ waiver criteria, which include:

wind generation not exceeding 20% of designated resources;
a minimum five-year term for designated network resources TSRs; and
designated resources not exceeding 125% of forecasted load.

The CAWG will bring back any modifications to the criteria or the amount. Several states have expressed an interest in further evaluating the 125% load and 20% wind criteria, regulatory staff said.

Travel Costs Increase Budget

The RSC approved a proposed budget for 2023 that reflects rising travel costs, despite a reduction of in-person meetings from four to two.

The total budget of $424,500 includes $270,00 for travel and meetings, an almost 57% increase from last year.

The committee is more than $123,000 under this year’s budget. Members have spent more than $37,000 of a budgeted $86,000 on travel and meetings.

Members, who will only meet twice in person this year, discussed the possibility of a third face-to-face meeting next year. Minnesota’s John Tuma, sitting outside in what he described as 76-degree temperatures and mild humidity, suggested the RSC gather in the Minneapolis-St. Paul area for its next July meeting.

Fiegen to Chair Nomination Committee

Members selected South Dakota’s Kristie Fiegen to chair the RSC’s Nomination Committee, where she will be joined by Arkansas’ Ted Thomas and Missouri’s Scott Rupp.

They will be responsible for bringing the 2023 proposed leadership slate to the RSC’s October meeting. They will also have to select at least one new member for the committee, as Oklahoma’s Dana Murphy is term-limited after this year.

July 29, 2022November 30, 2023

FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables

FERC issued two rulemakings Thursday that would impose a “duty of candor” in communications and set new accounting regulations for renewables.

The Notice of Proposed Rulemaking that would amend the Uniform System of Accounts (USofA) to create new accounts for non-hydro renewables was approved unanimously, while the NOPR to address the current “patchwork” of requirements regarding truthful communications (RM22-20) moved forward on a 4-1 vote, with Commissioner James Danly dissenting.

The latter would require truthful communications with the commission, RTOs/ISOs, their market monitors, NERC and its regional entities, and other companies under FERC jurisdiction in the electric, natural gas and oil industries and markets, including transmission or transportation providers.

Gabe Sterling, FERC Office of Enforcement | FERC

“In the past, different duties of candor have been adopted by the commission governing specific types of communications from certain organizations and persons and related to discrete areas of the commission’s jurisdiction,” Gabe Sterling, of the Office of Enforcement, said during a presentation at FERC’s open meeting. “This existing patchwork of requirements is insufficient to encompass all of the situations in which the commission must be assured that it is receiving accurate communications that are necessary for it to adequately conduct its regulatory oversight.”

The proposal, intended to capture communications that have not been explicitly included in existing requirements, is based on 18 C.F.R. section 35.41(b), approved nearly 20 years ago to govern communications by electricity sellers with market-based rate authority.

It would require covered entities to submit “accurate and factual information and not submit false or misleading information or omit material information.”

“We cannot do our job if we’re getting bad information … which arguably, we’ve gotten at times,” said Chair Richard Glick.

“It doesn’t really seem like a lot to say you have to tell the truth when you’re coming to the commission,” he added. “What blows my mind is that we actually don’t require that in many instances.”

As with section 35.41(b), entities would not be accused of violations if they can demonstrate due diligence to prevent false statements.

That wasn’t enough protection for Danly, however, who said the rulemaking was too expansive and vague.

He said the rule lacks the “ordinary safe harbor provisions” to protect First Amendment rights and that the commission failed to define “due diligence” or potential penalties for violations.

“The number of people that are covered by this is huge,” he said. “I am worried that people are going to be reticent to comment [negatively on the NOPR] because [it] would be construed as some kind of a declaration that they don’t believe that truth is necessary.”

Commissioner Mark Christie — a Republican, like Danly — said his colleague’s concerns were misplaced.

“I’m not worried at all about anybody’s reluctance to comment,” he quipped. “If people are queasy about commenting about the truth, all they’ve got to do is just hire their lawyer to do it.”

Commissioner Allison Clements also dismissed Danly’s criticism, saying “we are not going down the extreme path that” he suggested.

“I take seriously what Commissioner Danly said,” Commissioner Willie Phillips said. “We have to right-size it. I think the team has thought about that in the questions that they have proposed, and I too look forward to the comments.”

Those comments will be due 60 days after publication in the Federal Register.

In his dissent, Danly said the proposed rule could result in legal action against a landowner angry about construction noise who “says something like ‘I’ve never heard such a racket,’ but in fact she had heard such a racket at a Poison concert in 1988? Absurd? Yes. Duty of candor violation? Also, yes.”

In his press conference after the meeting, Glick said he became concerned about the issue when it came up in a 2019 order regarding connected entities (Order 860, RM16-17). “I was just appalled that we didn’t move forward with [the duty of candor] part of the order; that we couldn’t even require people to tell the truth,” he said. (See FERC Reduces MBRA Data Requirements.)

He conceded that “there’s a lot of detail that has to be worked out.”

“We’re asking for comments; we’re looking forward to reading those comments and making changes based on those comments. But at least let’s try to move forward with something,” he said.

Anyone found violating the rule could be subject to Enforcement action. But the NOPR said “it is not the commission’s intention to investigate or penalize all potential violations of the proposed regulation. As a general matter, we do not intend to penalize inadvertent errors, especially those of limited scope and impact.”

Renewable Accounting Rule

The second rulemaking (RM21-11) would be the latest in a number of revisions that the USofA has received in response to changing technology, laws and market conditions since its creation by FERC’s predecessor, the Federal Power Commission.

The NOPR, which resulted from a January 2021 Notice of Inquiry, proposes four changes:

the creation of dedicated production accounts for wind, solar, and other non-hydro renewable assets. Because the current USofA does not have unique accounts for non-hydro renewables, utilities characterize them as “other production.” The new categories will result in more uniform and transparent reporting, FERC said.
the creation of a single class for energy storage accounts to end the need for utilities to reallocate costs between production, transmission and distribution accounts based on usage of the assets. The commission said the current practices are impractical and a significant burden on the filing entities.
the codification of the accounting treatment of renewable energy credits (RECs) and similar financial instruments. It would result in the creation of dedicated inventory accounts for RECs, consistent with previous commission guidance on emissions allowances.
the creation of dedicated accounts for computer hardware, software and communications equipment. The NOPR seeks comment on whether FERC should also create such accounts for natural gas pipelines, oil pipelines and service companies.

Kimberly Horner, FERC Office of Enforcement | FERC

Kimberly Horner, of the Office of Enforcement, said the new accounts for renewables “would provide utilities with the ability to report in a more transparent manner to better inform the ratemaking process and also inform the public of their investments in these technologies.”

She said the current handling of energy storage assets is burdensome because the cost of the same asset must be reallocated among the different accounts based on their usage, which frequently changes. “The new proposed accounting would instead propose one account, and it would reduce the burden by allowing for the cost of the same asset to be recorded in one account, rather than continuously reallocated,” she said.

In addition to the proposed changes, the NOPR seeks comment on whether FERC’s chief accountant should issue guidance on accounting for hydrogen applicable to public utilities and licensees and natural gas companies.

Comments are due 45 days after publication in the Federal Register.

Michael Brooks contributed to this article.

July 29, 2022

What’s in the Inflation Reduction Act, Part 1

The text of the Inflation Reduction Act (IRA) of 2022 released by Senate Democrats on Thursday carries the same number (H.R. 5376) as the ill-fated Build Back Better Act passed by the House of Representatives last November, but its $670 billion falls far short of the original $2.2 trillion.

“Look, this bill is far from perfect. It’s a compromise,” President Biden said Thursday. “But it’s often how progress is made: by compromises.” He hailed the bill, rescued by Senate Majority Leader Chuck Schumer (D-N.Y.) through negotiations with Sen. Joe Manchin (D-W.Va.), as the strongest that could be passed right now to lower inflation and advance clean energy.

Energy industry leaders and advocates had already welcomed the IRA’s $369.75 billion for clean energy on Wednesday, after which they started digging into the bill’s 725 pages to parse out how that money is allocated and will be spent. (See Schumer, Manchin Reach Climate Deal.)

Reflecting Manchin’s thinking on the U.S. energy transition, the bill leans toward a broad definition of clean energy technologies, encompassing solar and wind, as well as nuclear, green hydrogen and carbon capture.

For example, in its provisions on rebates for zero-emission vehicles, mentions of “qualified plug-in electric motors” have been changed to “clean vehicles,” allowing fuel-cell vehicles to qualify for the incentives.

Similarly, investment and production tax credits for solar and wind are extended through the end of 2024, after which they become technology-neutral clean energy credits, according to an analysis from the American Council on Renewable Energy (ACORE).

Experts and advocates continued to comb through the bill on Thursday, nailing down details, but here are some key takeaways.

Energy Efficiency

Energy efficiency is a big winner. The top line numbers in the bill summary provided by Senate Democrats include $9 billion in rebates to help low-income consumers perform energy-efficient home retrofits and electrify home appliances.

The summary also mentions tax credits for energy-efficient home improvements, which the bill spells out in more detail. For example, tax credits for installing energy-efficient windows or skylights top out at $600 per year, while credits for heat pumps and biomass stoves and boilers go up to $2,000.

Such “historic investments … will reduce energy waste, cut costs for homes and businesses and slash greenhouse gas emissions,” said Steven Nadel, executive director of the American Council for an Energy Efficient Economy. “It would enable major efficiency and electrification upgrades in millions of homes and buildings to save energy and improve comfort and health, especially for low- and moderate-income households.”

EVs

Manchin has often criticized EV incentives as rewarding the wealthy, who don’t need rebates to afford new EVs. While the IRA does provide rebates for both new and used EVs, it also limits which cars and consumers will be eligible.

Rebates for new EVs, topping out at $7,500, will only be available for passenger vehicles that cost $55,000 or less, while the cap for electric SUVs, pickup trucks and vans will be $80,000. Income caps for prospective buyers range from $300,000 for couples filing joint tax returns to $150,000 for individuals.

The law also contains a $4,000 rebate for “previously owned” EVs, which it defines as vehicles “the model year of which is at least two years earlier than the calendar year in which the taxpayer acquires such vehicle” — so, no rebates for buying a year-old EV. The cap on sales price in this case is $25,000, and the rebate is only available on the first resale of the EV; that is, from its original owner.

The income caps for the used car rebates are $150,000 for couples and $75,000 for individuals.

Supply Chain and Transmission

The law also supports the buildout of a clean energy supply chain with new tax credits for advanced manufacturing of a range of solar, wind, storage and inverter components. The bill summary lists $10 billion for investment tax credits for “clean technology manufacturing facilities, like facilities that make electric vehicles, wind turbines and solar panels.”

Christian Roselund, senior policy analyst at Clean Energy Associates, said the tax credits for manufacturing could have a big impact on the solar supply chain in the U.S. “One of the fundamental challenges to onshoring U.S. solar manufacturing has been cost and specifically [operating expense] costs,” Roselund said. “It’s been the cost of not just building factories … but the cost of running factories.”

The bill provides a detailed list of tax credits for specific technologies. Solar cells, whether thin film or crystalline photovoltaic, will be able to claim credits of 4 cents/W, while panels will be eligible for credits of 7 cents. At present, the capacity for individual rooftop panels is about 350 to 375 W.

Industry advocates who lobbied for a transmission investment tax credit will be disappointed, according to ACORE, but it does provide:

$2 billion in direct loans for construction and modification of transmission deemed in the national interest;
$760 million in grants for permitting and siting and for economic development in communities with transmission builds; and
$100 million for modeling and analysis.