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November 5, 2024

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AEP Completes 1.5-GW Wind Energy Development

American Electric Power said Monday its Traverse Wind Energy Center, the last of three Oklahoma wind projects with a total capacity of 1.5 GW, is generating energy for customers in Arkansas, Louisiana and Oklahoma.

The 998-MW Traverse Center is the largest of the $2 billion North Central Energy Facilities’ three wind farms. The Sundance Wind Energy Center (199 MW) and the Maverick Wind Energy Center (287 MW) began commercial operation in April and September of last year, respectively.

Collectively, the wind farms are among the world’s largest wind facilities. AEP said they will save customers an estimated $3 billion in electricity costs over the next 30 years.

“The completion of the North Central Energy Facilities is a significant milestone in our efforts to provide clean, reliable power to our customers while saving them money,” AEP CEO Nick Akins said in a statement.

AEP subsidiaries Southwestern Electric Power Co. and Public Service Company of Oklahoma have taken ownership of the three wind farms after Invenergy completed their development. Invenergy Services will provide operations and maintenance services as part of a 10-year agreement.

AEP is investing $8.2 billion in regulated renewables and nearly $25 billion through 2026 to modernize grid systems, improve reliability and resilience, and provide more emissions-free energy. It plans to add about 14.5 GW of wind and solar in its regulated states by 2030 as part of a goal to achieve net-zero carbon emissions by 2050.

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Burke to Succeed Morgan as Vistra’s CEO

Vistra (NYSE:VST) said Monday that its board of directors has named 16-year company veteran Jim Burke as its next CEO effective Aug. 1, replacing Curt Morgan after a transition period.

The move is part of the company’s formal succession planning process, Vistra said.

“I am incredibly honored and humbled to assume the responsibility of leading Vistra,” said Burke, currently the Texas-based company’s CFO. Vistra hopes to name his replacement before Aug. 1.

Morgan-Curt-2017-Oct-RTO-Insider-FI.jpgCEO Curt Morgan is leaving Vistra after 37 years in the industry. | © RTO Insider LLC

Burke joined Vistra when it was TXU Corp., under new CEO C. John Wilder’s leadership, in 2005 following the company’s international financial difficulties. In 2007, the company was bought by private equity investors in a $45 billion leveraged buyout and went private as Energy Future Holdings. It declared bankruptcy in 2014, eventually emerging as Vistra Energy in 2016.

Burke was CEO of TXU Energy, Vistra’s retail company, until 2016, when he was named COO. He became CFO in December 2020. He was president and COO of Gexa Energy before joining TXU.

Morgan has served as Vistra’s CEO since 2016 and has a 37-year career in the power industry. He said in a statement that with the company having “created significant value for our shareholders, transformed our company … and firmly established Vistra as a leader in the country’s energy transition, now is the right time for this leadership transition.”

Vistra board Chair Scott Helm thanked Morgan for his leadership in helping grow the company into “one of the largest power producers and retailers in the United States.”

“While achieving this tremendous growth, Vistra has also significantly reduced its carbon footprint by retiring coal-fueled power plants and is rapidly growing its zero-carbon portfolio [Vistra Zero], all while returning a substantial amount of capital to its financial stakeholders,” Helm said.

Morgan will remain until next April as a special adviser to Burke and the board, a spokesperson said.

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NYISO Business Issues Committee Briefs: March 16, 2022

Monthly Energy Prices up 123% Y-o-Y 

NYISO locational-based marginal prices averaged $94.06/MWh in February, down from $134.79/MWh the previous month and higher than the $63.70/MWh average in February 2021, Rana Mukerji, senior vice president for market structures, said in delivering the monthly operations report to the Business Issues Committee on Wednesday.

Day-ahead and real-time load-weighted LBMPs came in lower compared to January.

Year-to-date monthly energy prices averaged $118.36/MWh, a 123% increase from $52.99/MWh a year ago, which Mukerji attributed to higher natural gas prices.

February’s average sendout was 429 GWh/day, down from 451 GWh/day in January and 434 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $6.17/MMBtu for the month, down from $11.15/MMBtu in January and up 18.3% year-over-year.

Distillate prices were up 64.5% year-over-year. Jet Kerosene Gulf Coast averaged $19.79/MMBtu, up from $17.96/MMBtu in January. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $20.46/MMBtu, up from $18.53/MMBtu in January.

February uplift decreased to -$1.73/MWh from -$1.50/MWh in January, and total uplift costs, including the ISO’s cost of operations, came in higher than those in January.

The ISO’s local reliability share dropped to 4 cents/MWh/MWh in February from 9 cents/MWh the previous month, while the statewide share dropped to -$1.77/MWh from -$1.59/MWh.

The Thunderstorm Alert cost in New York City was $2.98 because of some unusual thunderstorm activity in the month.

Real-time BPCG Eligibility Changes

The BIC recommended that the Management Committee approve tariff revisions that would change the provisions for real-time bid production cost guarantee (BPCG) payments.

BPCGs are paid as an incentive for resources directed to run by the ISO. In order to close a loophole whereby units may receive inappropriate real-time BPCG payments under certain circumstances, the new tariff language would add an exception to the eligibility criteria for units placed out-of-merit (OOM) for reliability, said Mark Buffaline, senior settlements analyst at the ISO.

As an example, the ISO hypothesized a unit scheduled for energy in the day-ahead market (DAM) at 100 MW bidding self-committed fixed/flex in the real-time market with a self-schedule at 200 MW. That unit operating in real time at 200 MW aggravates any transmission constraint and would be placed OOM for reliability with a 140-MW upper operating limit (UOL).

“The unit receives RT BPCG for 40 MW, and by self-scheduling at 200 MW in real time, they have indicated that they want to be a price-taker for all output up to 200 MW,” Buffaline said.

Units that bid self-committed fixed/flex at megawatt levels above the DAM energy schedule are generally ineligible for real-time BPCG, but by placing them out-of-merit for reliability, this makes them eligible for real-time BPCG, which supersedes the self-commitment ineligibility rule, he said.

“That is the discrepancy between the rules that we’re plugging here,” said Chris Brown, lead settlements analyst at NYISO. “So those costs representing that self-committed bid are no longer going to be eligible for a make-whole payment under this scenario with units out-of-merit for reliability.”

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Winners and Losers Among Washington Climate Bills

A bill to help some smokestack industries compete with foreign competitors and another to impose a fee on banks investing in fossil fuels were among the biggest losers in the recent Washington state legislative session.

But in many ways, the session that ended March 11 was successful for climate change legislation.

Sen. Reuven Carlyle (D), chairman of the Senate Energy and Environment Committee, told NetZero Insider that the 2022 session built upon laws passed in 2021, and the two years must be viewed as one biennium of work on climate change. Last year’s session saw the passage of some major climate change bills, including the nation’s second cap-and-trade law. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)

Rep. Joe Fitzgibbon (D), chairman of the House Environment and Energy Committee, said the just-finished 60-day session was crammed with competing bills from other high-priority issues, such as police reform, homelessness and regulating Gov. Jay Inslee’s powers in the wake of his COVID mandates

Consequently, there was no time to tackle everything, and the number of bills identified for passage had to be whittled down, Fitzgibbon said.

Here is a rundown of what passed and failed in the 2022 session.

Failed: HB 1682

House Bill 1682 was intended to cushion trade-exposed Washington manufacturers from the economic impact of the state’s cap-and-trade program passed in 2021. (See Wash. Bill Buffers Some Industries Subject to Cap-and-trade.)

Fitzgibbon introduced the bill to provide some industries delayed enforcement of the cap-and-trade law.

Referred to as “energy-intensive, trade-exposed” (EITE), those industries are responsible for roughly 10% of the state’s carbon emissions.

EITE industries in Washington include manufacturers in the metals, paper, aerospace, wood products, chemicals, computer and electronics sectors, as well as food processors, cement producers and petroleum refiners.

With passage of the 2021 law, the state government is working this year to implement the nation’s second cap-and-trade system, which is due to begin operating next year.

The HB 1682 program would have tackled facilities that emit 25,000 metric tons or more of CO2 annually. There are at least 100 such facilities in the state.

Pushback came in February from several EITE industry lobbyists, who argued that much of the technology needed to curb emissions does not currently exist.

Fitzgibbon said the bill will be revived, noting that it included language that would not go into effect until the 2030s, providing a huge time cushion.

Failed: SB 5967

Senate Bill 5967 by Carlyle called for any financial institution in Washington that invests in fossil fuels to be charged an annual fee. Carlyle was inspired by discussions at the global climate change summit in Glasgow, Scotland, last November.

The bill would have required a financial institution with a presence in Washington and earning a net income of $1 billion to pay a surcharge on the institution’s business and occupation tax, the state’s tax on a firm’s gross income. (See Fossil Fuel Funders Face Fee Under New Wash. Bill.)

The bill proposed that any financial institution that spends more than 4% its investment on fossil-fuel-related businesses would pay a 0.5% surcharge to the state. The surcharge would fall to 0.375% for an institution that spends 2.5-4% of its investments on fossil fuels and to 0.25% for fossil fuel investment rates of less than 2.5%.

The legislation died in the Senate’s Ways and Means Committee.

Carlyle is retiring and won’t be around in 2023 to revive the bill. He said he believes in the concept, but it might take a couple years to gain traction, which is normal for major ideas.

He plans to talk with other Washington legislators about reviving the bill and to talk with Oregon and California legislators about pursuing the same concept.

However, Rep. Fitzgibbon does not think the concept will move ahead, telling NetZero Insider there are a number of technical details that need to be addressed. For example, Fitzgibbon said, the bill could interfere with interstate commerce protected by the U.S. Constitution, as well as international commerce.

Failed: HB 1099

House Bill 1099 would have added climate considerations to city and county land-use planning.

The bill by Rep. Davina Duerr (D) would have made this change to Washington’s Growth Management Act, which regulates long-range land-use planning for Washington’s city and county governments. It would have required local governments to review and, if needed, revise their comprehensive plans and development regulations every eight years.

Duerr’s bill would have required climate change to be considered in land-use and shoreline planning for the 10 largest of Washington’s 39 counties and in cities of 6,000 people or larger. The 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland.

Republicans in the Senate and House killed the bill on the final day of the session. (See Climate-related Land-use Bill Stalls Again as Wash. Session Ends.)

They mounted a parliamentary procedural challenge to the bill, which failed, but it also gobbled a few hours before the matter could be researched and resolved. Then House Republicans threatened to have all 41 of their members speak against the bill on the House floor late in the evening, which would take time away from other Democratic bills facing a midnight deadline for passage.

The Democrats decided to sacrifice House Bill 1099 to have time to pass two major budget bills.

Failed: HB 1766

House Bill 1766 by Rep. Alex Ramel (D) called for natural gas utilities to submit plans to the Washington Utilities and Transportation Commission by Jan.1, 2024, on how they plan to gradually decrease their greenhouse gas emissions through 2050.

These plans would have had to be updated every four years. The bill also called for some limits on the ability of gas companies to provide new gas service and to install new gas equipment to meet energy conservation targets. And it would allow gas companies to begin providing hydrogen to customers.

The bill died in the House Environment and Energy Committee following intense lobbying by the gas industry, Fitzgibbon said.

Failed: HB 1792

House Bill 1792 by Rep. Ramel would have expanded the types of hydrogen that municipal and rural utilities can provide to customers.

The bill would have provided tax credits for “green electrolytic hydrogen” produced, sold or distributed by municipalities and public utility districts.

Electrolytic hydrogen is hydrogen produced through electrolysis and does not include hydrogen manufactured by steam reforming or by any technologies using fossil fuels.

Despite strong bipartisan support, the bill did not reach a House floor vote prior to a late February cut-off deadline.

Failed: SB 5908

Senate Bill 5908 by Sen. Marko Liias (D) would have created a new interagency council to coordinate Washington’s phasing in of electric vehicles during the next few decades.

The proposed council’s duties would include developing a strategy to ensure that the state is ready for all new car sales in 2035 to be zero-emission vehicles. The body would have gathered and disseminated information about EV programs, policies and funding. It would coordinate grant funding on EVs throughout the state.

Despite Liias being chairman of the Senate Transportation Committee, where the bill was sent, no vote was taken to move it out of committee.

Passed: SB 5714

Senate Bill 5714 by Carlyle will provide tax breaks on the construction of solar panel canopies over parking lots. (See Builders Oppose Labor Provision in Wash. Solar Canopy Bill.)

The canopies will likely be built over large lots at shopping centers, Carlyle said.

The breaks will come in the form of repayments of sales and use taxes accumulated during construction, which must be completed in two years to receive all requested breaks.

Under the bill, a solar canopy installer will receive a 50% refund or deferral of its taxes if it is an organization owned by women, minorities, or veterans, or an entity with a history of complying with federal and state wage and hour laws and using apprenticeships — or hires workers living in the project construction area.

Refunds or deferrals of 75% would go to one of these organizations if workers on a project were compensated at prevailing wages determined by collective bargaining agreements.

A 100% refund would go to a contractor operating under a project labor agreement (PLA), a special collective bargaining agreement tailored to a specific project that supersedes existing agreements.  A typical PLA requires that workers are hired through union halls and that nonunion workers are paid union wages for the length of the project.

Passed: SB 5910

Sen. Carlyle’s Senate Bill 5910 will create a new state office to support development of electrolytic hydrogen and other alternative fuels. (See Green Hydrogen Bill Passes Wash. Legislature.)

The bill is supposed to boost Washington’s prospects to receive money from the federal Infrastructure Investment and Jobs Act to create one of four regional hydrogen hubs in the nation.

The federal law allocates $8 billion for the creation of at least four hydrogen hubs across the country, as well as $1 billion for the domestic manufacture of the electrolyzers needed to convert water to green hydrogen. The U.S. Department of Energy will solicit proposals for the hubs until May 15 and select the four sites a year later.

“It would be political malpractice not to get one of those grants from the federal government,” Carlyle said.

The proposed Office of Renewable Fuels in the Washington Department of Commerce would collaborate with other state agencies to accelerate market development of renewable fuel and hydrogen projects along their full life cycle, in part by supporting research and development around production, distribution and end uses. It would also identify ways to best deploy the fuels to support the state’s climate change mitigation and adaptation efforts.

Passed: SB 5722

Senate Bill 5722 by Sen. Joe Nguyen (D) will trim the carbon footprints of roughly 50,000 buildings in the state. (See Lawmakers Pass Wash. Building Emissions Bill.)

Nguyen’s bill calls for the state’s Department of Commerce to set draft standards to trim carbon by Dec. 1, 2023, for buildings ranging from 20,000 to 50,000 square feet. A 2019 law addresses the carbon footprints of buildings that are greater than 50,000 square feet, which number about 10,000 in the state. The state must inform the affected building owners by July 1, 2025.

The Commerce Department would fine-tune the standards and submit a report to the legislature in 2029. It would have to adopt the standards by Dec. 31, 2030, and the new rules would go into effect in 2031.

Twenty-seven percent of Washington’s carbon emissions come from buildings, the second largest emitter behind vehicles at 45%.

Passed: HB 1812

House Bill 1812 by Rep. Fitzgibbon will take Washington’s Energy Facilities Site Evaluation Council (EFSEC) outside the umbrella of its parent, the Washington Utilities and Transportation Commission, and make it an independent agency. (See Bill to Expand Wash. Siting Council Passes Senate.)

EFSEC, comprising representatives from several state agencies, makes recommendations to the governor for final decisions on the placement of solar farms, wind turbines and other energy resources.

If a wind or solar developer opts to seek state approval instead of obtaining county permits, it can bypass county governments by going through EFSEC. Or a developer can choose to have the appropriate county government handle the permitting, sidestepping EFSEC.

Besides being an option for wind farm and solar farm ventures, the expanded EFSEC will have jurisdiction over clean energy product manufacturing facilities, renewable natural gas facilities and hydrogen production plants. The bill also will require the Washington Department of Commerce to meet with rural stakeholders and to prepare reports on those meetings, including recommendations on how to more equitably disburse costs and benefits of energy projects to rural communities.

The bill directs a joint Senate-House committee to review inequities during the siting of large alternative energy projects with a report due by Dec. 1, 2023.

Passed: HB 1814

House Bill 1814 by Rep. Sharon Shewmake (D) will provide money through the Washington State University’s Extension Energy Program for public and tribal housing authorities to provide solar power to low-income residents.

A grant would be limited to 100% of project’s costs and must be between 12 and 199 kilowatts. An applicant must prove a direct benefit to its residents.

The bill allocates $300,000 for this program in fiscal 2023. Then it would allocate $25 million in each of the four subsequent budget biennia.

Transportation Budget Measures

The transportation budget included money to build two 144-car hybrid electric ferries and to convert a regular ferry to a hybrid electric model.

Washington State Ferries expects to start a multiyear contract to convert from solely diesel fuel engines to hybrid fuel-battery propulsion in October. The state ferry system — the largest in the U.S. — has 21 vessels that crisscross Puget Sound, serving 20 terminals on 10 routes.

The state’s ferries consume 19 million gallons of fuel annually. State officials believe that this move will dramatically trim that figure. When a ferry is docked to load and unload vehicles, the batteries will be hooked up to a shoreline charging station, which will replenish battery power in 18 minutes. However, the construction of the dockside charging stations is not expected to be complete until 2025.

The transportation budget also includes money to help restart the dormant Italco aluminum smelter in Whatcom County in northwestern Washington.

The proposed restart would come with equipment that would trim carbon emissions below August 2020 levels, when Alcoa shut down the plant, leading to the loss of 700 jobs. Two unidentified companies have expressed interest in buying and reviving the plant.

The transportation budget additionally includes money to help build a solar panel manufacturing plant in Grant County in Central Washington.

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CARB to Replenish Zero-emission Truck Fund with $430M

A California incentive program for zero-emission trucks that depleted $63 million of funding in nine minutes last year is set to reopen next week, and officials are hopeful the money will last longer this time.

The Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) will open at 10 a.m. on March 30, with $430 million in funding available.

The funding includes $196.6 million for standard requests, plus funds set aside for specific categories: $65.5 million for public transit buses; $46 million for class 8 drayage trucks; and $122 million for public school bus funding in small and medium air districts.

Last year, vehicle buyers quickly snapped up incentives offered through HVIP, a program that the California Air Resources Board (CARB) launched in 2009.

In the first wave of HVIP funding for 2021, which opened in June 2021, all $84 million in incentives were requested within three hours. A second wave of funding in August offered $12 million in incentives. In the third and final wave of funding for 2021 in October, HVIP offered $63 million in incentives and all the money was requested within nine minutes.

Pent-up Demand

During a CARB workshop on Thursday, agency staff said “pent-up demand” for the incentives caused by a period of limited funding contributed to last year’s rapid depletion. With more funding this year, along with policy changes such as reduced incentive amounts and a limit on the annual number of incentives per fleet, CARB is hopeful the money will last longer.

“We have the most robust budget we’ve ever seen for the HVIP program,” Andrea Morgan of CARB’s Mobile Source Control Division said. “And we think that a number of the policy changes that we put into effect in previous years will also help with demand. So we’re optimistic that the funds will last longer throughout the year, if not the entire year.”

And CARB is considering another restriction on HVIP eligibility: a fleet-size limit of 100 vehicles or fewer starting in 2023, falling to 50 vehicles or fewer in 2024.

At least one workshop participant opposed the fleet-size limit.

“We are very concerned about the categorical exclusion of the large fleets from the program … given what we see as the really important role they play in driving scale and gaining experience with [zero-emission vehicles],” said Andrew Schwartz, senior managing policy adviser for Tesla (NASDAQ:TSLA). “We really see them as very critical early movers.”

As an alternative, Schwartz suggested setting aside incentive money specifically for smaller fleets, while still allowing larger fleets to apply for the main pool of funding.

Range of Incentives

Since its inception in 2009, the HVIP program has issued 9,200 incentive vouchers totaling $604 million. More than 140 makes and models of zero-emission vehicles from 35 manufacturers are currently eligible for incentives, according to CARB.

Incentives vary based on the type and model of zero-emission vehicle. For example, incentives range from $45,000 to $85,000 for shuttle buses; from $85,000 to $198,000 for school buses; and from $85,000 to $120,000 for garbage trucks.

Last week’s workshop focused on CARB’s fiscal year 2022/23 funding plan for clean transportation incentive programs, including HVIP. Development of the funding plan is just getting started, and CARB has scheduled a series of meetings on different incentive programs.

A March 22 workgroup meeting will include a discussion of fleet-size limits in the HVIP program, CARB staff said. And during a yet-to-be scheduled workshop in May, results from this month’s HVIP funding wave will be discussed.

In addition to the funding wave opening on March 30, CARB is launching a new “innovative small e-fleets” pilot program within HVIP. The program is expected to open by early summer with $25 million in funds. The program is intended to help small trucking fleets and independent owner-operators with mechanisms such as flexible leases or peer-to-peer truck sharing.

CARB hosted a work group meeting on the program on March 3.

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PJM MRC/MC Preview: March 23, 2022

Below is a summary of the consent agendas scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:15-9:20)

B. Stakeholders will be asked to endorse proposed revisions to Manual 12: Balancing Operations resulting from a periodic review. The changes include attachment references and other minor revisions.

C. Stakeholders will be asked to endorse proposed revisions to Manual 13: Emergency Operations resulting from a periodic review. The changes include new columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.

D. Stakeholders will be asked to endorse proposed revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders, including those on the minimum offer price rule, the market seller offer cap and the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve. (See “Manual 18 Revisions,” PJM MRC/MC Briefs: Feb. 24, 2022.)

E. Stakeholders will be asked to endorse proposed revisions to Manual 37: Reliability Coordination resulting from a periodic review. The language would properly label Silver Run Electric as a transmission owner in Attachment A of the manual.

Endorsements (9:20-10:15)

1. Pseudo-modeled Combined Cycle Minimum Run Time Guidance (9:20-9:40)

Members will be asked to endorse a proposal that includes adding language to Manual 11: Energy and Ancillary Services Market Operations to address pseudo-modeled combined cycle minimum run time guidance. The proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of a pseudo-modeled unit to remove associated steam turbine start-up time included in the parameter limit when it’s dispatched. (See “Minimum Run Time Guidance,” PJM MRC/MC Briefs: Feb. 24, 2022.)

2. Capacity Capability Senior Task Force Sunset (9:40-9:50)

The committee will be asked to endorse the sunset of the Capacity Capability Senior Task Force. The task force was originally created in March 2020 to consider using effective load-carrying capability to set the capacity value of limited-duration resources such as battery storage. (See “CCSTF Sunset,” PJM MRC/MC Briefs: Feb. 24, 2022.)

3. Max Emergency Changes (9:50-10:15)

Stakeholders will be asked to endorse an issue charge and proposed revisions to Manual 13: Emergency Operations addressing the extension of a temporary change to maximum emergency status for gas combustion turbines and steam generators. PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation. (See “Max Emergency Changes,” PJM MRC/MC Briefs: Feb. 24, 2022.)

Members Committee

Endorsements (1:30-2:30)

1. FTR Credit Requirement (1:30-2:30)

Members will be asked to vote on several motions regarding revisions to PJM’s tariff on financial transmission rights credit requirements stemming from FERC’s recent rejection of the proposal to modify the calculation. The commission directed PJM to make an informal filing within 60 days of the date of the order to either show why its FTR credit requirement remains just and reasonable and not unduly discriminatory or preferential, or explain what tariff changes will remedy the commission’s concerns. (See FERC Rejects PJM’s FTR Credit Requirement Proposal.)

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MISO Finalizes Plan for DER Market Participation in 2030

MISO is collecting a final round of stakeholder feedback before making a compliance filing under FERC Order 2222’s directive requiring RTOs to open their wholesale markets to aggregations of distributed energy resources.

Stakeholders had until Monday to submit written comments. The compliance filing is due April 18.

MISO will lean on its electric storage participation plan for DER aggregations, limiting them to a single pricing node. The aggregations must self-commit in the RTO’s markets based on their own forecasts.

The grid operator last month set a 2030 completion date for DER aggregation’s participation in its wholesale markets. MISO envisions registration being available in late 2029, with participation in energy and ancillary service markets offered by the end of 2030’s first quarter. (See MISO: DER Aggregations Must Wait Until 2030 for Market Participation.)

Stakeholders have told MISO that eight years is too slow to comply with the order. Some of them have pointed out that substantial DER adoption could happen between now and 2030.

During a March 10 Market Subcommittee meeting, Deputy General Counsel Tim Caister said MISO must “get anchors in” before it’s ready for Order 2222 compliance. He said it’s not simply a matter of plugging DER participation into MISO’s new market platform, but that registration and settlement systems need to be overhauled as well.

Staff and stakeholders have extended the DER task force until July 2023 to discuss post-compliance filing issues and provide MISO guidance on other DER issues. The grid operator has long said that Order 2222 compliance will not be the only market offering for DERs.   

Task force lead Tricia DeBleeckere, a Minnesota Public Utilities Commission staffer, said upcoming meetings will probably become more stakeholder led. She said like the Order 2222 edict, MISO facilitates DER technologies, but members are the driving force behind their participation.

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CAISO Approves $3B Transmission Plan

The CAISO Board of Governors approved a 10-year transmission plan Thursday that far exceeds the estimated cost of any similar plan in recent years, its price driven by the proliferation of renewable resources, predicted load growth and the state’s reliability concerns.

“The need for new generation over the next 10 years has escalated rapidly, driving an accelerated pace for new transmission development in this and future planning cycles,” Neil Millar, CAISO vice president of infrastructure and operations planning, wrote in a memo to the board.

CAISO identified the need for 23 transmission projects with an estimated cost of $2.96 billion — nearly 14 times more than the $217 million average over the past five years, Millar noted.

The next highest year, 2018/19, saw a need for $644 million in transmission projects. Other years were far less. CAISO found the state needed $5 million in transmission projects last year, $142 million of projects in 2019/20, $271 million in 2017/18 and $24 million in 2016/17.

The ISO adopts a 10-year transmission plan every year, but the forecasted need often varies dramatically based on circumstances. The 2020/21 transmission plan, for example, envisioned adding 1,000 MW of new resources per year. This year’s plan estimates a need for 2,700 MW per year, while next year’s plan could boost that figure to 4,000 MW, CAISO said.

To explain the increase, CAISO cited an “accelerated pace of resource development” based on decarbonization efforts and the planned electrification of the transportation sector, which state planners expect to drive up demand. California has a goal of 100% clean energy by 2045 and a mandate that all new passenger vehicles sold in the state be electric or zero-emission vehicles by 2035.

Reliability was also an issue. CAISO said the state will need generation and transmission development because of the potential for reduced imports from other Western states and high peak loads on hot summer evenings. Both factors contributed to the rolling blackouts of August 2020 and CAISO’s re-examination of its reliability risks.

CAISO also cited the need to replace several aging gas plants and Pacific Gas and Electric’s Diablo Canyon, the state’s last nuclear power plant. All are slated to retire in the next few years.

“The transmission system will need to be expanded, upgraded and reinforced to access and integrate these resources, as well accommodate the expected resurgence in electricity consumption as transportation and other industries electrify to reduce their carbon impact,” the plan said.

Sixteen projects, with an estimated price tag of $1.4 billion, are needed to meet load growth and the state fleet’s transition to renewable resources, CAISO said. They include two HVDC projects to serve Silicon Valley and the city of San Jose. Six policy-driven transmission projects, totaling $1.5 billion, are necessary to meet the generation requirements established by the California Public Utilities Commission’s renewable portfolio standards, the ISO said.

The plan will guide implementation, including initiating a competitive solicitation process for four high-voltage projects, the ISO said in a news release.

“Approval of the plan also sets in motion contractual agreements and cost recovery for transmission upgrades through ISO transmission rates,” it said.

The 10-year plan follows CAISO’s release on Jan. 31 of a first-of-its-kind 20-year transmission outlook. The outlook predicted a need for $30.5 billion of new high-voltage lines to transport wind power long distances across the West and to carry solar, offshore wind and geothermal power from in-state California generators to urban load pockets. (See CAISO Sees $30B Need for Tx Development.)

“While the 10-year plan is required by the ISO’s federal tariff and identifies specific projects for construction, the longer outlook is designed to provide a framework and longer-term vision for the system’s future transmission needs without recommending specific projects for approval,” CAISO said. “Together, the two documents will help map the short-term, intermediate and long-term milestones of the clean-energy transition, enabling rigorous and efficient planning coordination and creating the most cost-effective and durable transmission infrastructure to serve generations to come.”

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ERO Endorses Market-based Reliability Enhancements

NERC and the regional entities last week expressed support for “exploring ways in which market mechanisms can help ensure reliable operation” of the bulk power system and encouraged FERC and other stakeholders to take reliability into consideration when designing market enhancements.

The REs and NERC were responding to comments on the technical conferences held by FERC last September and October on energy and ancillary services markets in the electricity sector (AD21-10).

In the October conference, participants called for market participation rules to be revised to ease the entry of new and emerging resource types into wholesale electricity markets, while still incentivizing utilities to install the kind of energy products that can maintain grid reliability as the resource mix changes. (See Stakeholders Ask FERC to Support E&AS Market Changes.)

In their response, the ERO organizations acknowledged that while they play a direct role in reliability through the establishment and enforcement of reliability standards, assessing seasonal and long-term reliability, and training and certifying industry personnel, they do not take an active part in market design.

But while the ERO Enterprise declined to endorse specific market measures or incentives, its remarks pointed out that NERC’s “assessments over the past several years generally support policy enhancements which prioritize reliability under the transforming energy grid.” In particular, the groups highlighted last year’s State of Reliability Report, which laid out how “a rapidly transforming BPS has been impacted by a pandemic, extreme weather, cyber security, and supply chain issues.” (See NERC: Extreme Weather, Resource Changes Cause Mounting Concern.)

Reliability standards are not the only way to respond to these challenges, the ERO groups said; they function only as “part of a larger environment [comprising] overlapping energy regulation, markets, and jurisdictions.”

The ERO Enterprise reminded the Commission that NERC’s rules of procedure prohibit one of the organization’s standards from precluding market solutions as an approach to achieving compliance with it. As a result, reliability standards typically define only the desired result, rather than how to achieve it.

This does not mean that the methods for ensuring compliance must be left entirely to the utilities: NERC and the REs highlighted several comments that suggest ways that “market enhancements … may help address reliability concerns associated with the changing BPS.” Such market changes need not only involve NERC’s reliability standards but also can include proactive measures to promote reliability.

The Edison Electric Institute, for example, asserted that “market operators must be able to procure sufficient reserves and other ancillary services through the market,” even as the resources providing such services change. EEI urged FERC to ensure that RTOs and ISOs are working to make sure energy prices “reflect the full cost of the resources needed to reliably operate the system,” so that energy providers can accurately weight the costs and benefits of the resources they use.

MISO also got a mention from the ERO groups for asserting its efforts to ensure reliability through structuring the energy market, one of the pillars of the ISO’s “Reliability Imperative.” ISO-NE also noted in comments quoted by the ERO that “enhancements to the energy and ancillary services markets will be essential to [maintaining] reliable operations as the system transitions to … renewable resources whose uncertain output will need to be balanced using energy storage and a pipeline-constrained gas-fired generation fleet.”

“Well-designed ancillary service markets can help to ensure the system has all of the essential flexibility properties identified above — sufficient resources with dependable performance, sustainable output, and with the necessary response times to cover the increasing operational uncertainties and to provide a reliable system,” ISO-NE said.

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Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers

As laid out in a report released Tuesday, Gov. Glenn Youngkin’s (R) main argument against Virginia’s participation in the Regional Greenhouse Gas Initiative (RGGI) appears to be that none of the $300 million the state has received to date from the 11-state cap-and-trade program is being used to provide rebates to customers.

Because the state’s main utility, Dominion Energy, is allowed to recover the cost of the carbon allowances it must buy to comply with the program from its “captive” customers, Virginia’s participation in RGGI has resulted in a “direct carbon tax” on residents and businesses, the report says.

Announcing the report, Youngkin reiterated his longstanding claim that RGGI is “a bad deal for Virginians,” invoking the added burdens that recent inflation is putting on residents “at the pump and at home.”

According to the report, Dominion’s recovery of its RGGI costs has added $2.39/month to residential utility bills and $1,554 to bills for industrial customers. According to figures supplied by Dominion to the State Corporation Commission, cited in the report, the utility expects that RGGI participation will cost customers a total of $3 billion through 2045.

These increases are framed as an “emergency situation” allowing the governor to issue an emergency regulation to take Virginia out of RGGI, according to a draft letter from Michael Rolband, director of the state’s Department of Environmental Quality (DEQ). The letter and a copy of the proposed regulation repeal accompanied the report.

Under Virginia law, an emergency regulation of this kind could stay in force for up to two years. A draft of a letter notifying RGGI of Virginia’s intent to withdraw is also included with the report.

Environmental and clean energy advocates were quick to criticize the report’s arguments and Youngkin’s plans for RGGI withdrawal.

“The report willfully ignores the massive benefits that come from our participation in RGGI,” said Chelsea Harnish, executive director of the Virginia Energy Efficiency Council, noting that half of the state’s RGGI funds go to energy efficiency projects for low-income residents. Another 45% goes to flood preparedness programs, with 5% allocated to cover administration costs.

Nate Benforado, a senior attorney with the Southern Environmental Law Center, slammed the report as “designed to support a partisan repeal effort rather than to provide an objective look at available information.”

The report actually finds that “RGGI is working very well,” Benforado said in an interview with NetZero Insider. While RGGI states have cut GHG emissions more than 30% over the past decade, the report shows that Virginia’s emissions have remained about the same, he said.

‘A Pretty Misleading Statistic’

Youngkin’s report counters that while Virginia’s emissions have not declined overall, the state’s “emission rate, which is the amount of CO2 emissions produced by a set amount of electricity, has steadily and significantly been reduced.”

But Benforado said such emission rates are “a pretty misleading statistic to look at” and can be attributed to the retirement of coal plants in the state and the increasing use of natural gas to generate electricity.

“When it comes to climate change, emissions rate doesn’t matter at all,” he said. “It’s all about the actual amount of CO2 you’re putting into the air. … Virginia has fallen behind the other RGGI states.”

Further, the report also acknowledges that without an emissions-reduction program like RGGI, Virginia will not be able to meet the clean energy goals of the state’s Clean Economy Act, which requires Dominion to decarbonize its system by 2045, Benforado said.

“It seems like the issue the governor really has is less about RGGI and more about the cost to customers,” Benforado said. “If the governor is sincere that that’s his concern, then we should address that; repealing RGGI doesn’t fix that problem.”

RGGI was founded in 2009 as a regional “cap-and-invest” program, according to its website. Participating states set annually decreasing caps on carbon emissions from power plants, which must then buy allowances issued by the states to offset their emissions. One allowance offsets 1 ton of carbon dioxide. States can invest their RGGI funds in clean energy, energy efficiency or GHG abatement programs or in rebates and bill credits to customers.

Virgina RGGI Auction (RGGI) Content.jpgWith allowance prices topping out at $13.50, the most recent RGGI auction netted Virginia $74.2 million. | RGGI

 

As noted in the report, four states in RGGI — Delaware, Maryland, Maine and New Hampshire — do use a portion of the money they receive from RGGI’s quarterly auctions to provide rebates to customers to offset any increase in rates that comes from the program. Virginia’s program was originally designed to include customer rebates, the report says, but was later changed to split the money between low-income energy efficiency and flood preparedness programs.

J.R. Tolbert, vice president of strategy and partnerships for Advanced Energy Economy (AEE), defended the legislature’s decision to split Virginia’s RGGI funds as it did. According to Youngkin’s report, to date, the flood preparedness program has received more than $150 million in funding, while low-income energy efficiency programs have received more than $135 million.

“The governor seems to have picked a boogeyman in RGGI versus actually providing solutions on big issues, whether it be a rebate [or] how he would replace the money that’s going to communities all over the commonwealth dealing with rising water levels and how he would help low-income Virginians address energy efficiency needs in their homes,” Tolbert said.

‘The Courts Will Rule’

Advocates and Virginia Democrats have also argued that Virginia joined RGGI as the result of a 2020 legislative mandate (SB 1027), and therefore Youngkin does not have the unilateral authority to take the state out of the initiative.

“The legislature codified Virginia’s participation in RGGI, and in order for the state to withdraw from RGGI, the legislature would have to make that decision,” Tolbert said.

While Tolbert said AEE is not planning to take the governor to court, he expects that others will. “I think the way this plays out is that the courts will rule that we continue to stay in RGGI until the legislature decides otherwise,” he said.

However, an analysis from industry analysts ClearView Energy Partners suggests that the law may not codify RGGI, creating a fine point for the courts to decide. The language in the 2020 law “authorizes” the DEQ to design and implement Virginia’s RGGI program, ClearView said. Such language could be read as giving the DEQ permission for a RGGI program but not necessarily a mandate.

Tolbert, who advocated for the bill at the time, disputes that interpretation. “The legislative intent was that this was a mandate,” he said. “The reason they passed the law in the first place was because they wanted to take that extra step.”

Air Pollution Control Board

After his victory over Democrat Terry McAuliffe in the November election, Youngkin came into office vowing to take Virginia out of RGGI and signed an executive order to begin the process just hours after his Jan. 15 inauguration. (See Youngkin Takes 1st Steps Toward Va. RGGI Withdrawal.)

The order directed the Department of Natural Resources and DEQ to conduct a new cost-benefit study of Virginia’s RGGI participation and draft the letters and emergency regulations that would allow Youngkin to circumvent the legislature in taking the state out of the initiative.

With a Democratic majority in the state Senate opposing any effort to repeal the RGGI mandate, Youngkin’s strategy depends on the State Air Pollution Control Board. At the time of his inauguration, the board had a solid majority of members who had been appointed by former Gov. Ralph Northam (D). It had approved the regulations setting up Virginia’s participation in RGGI by a 5-2 vote and appeared unlikely to reverse that decision.

In the interim, however, the Senate rejected Andrew Wheeler, the former EPA chief under President Donald Trump, as Youngkin’s secretary of natural and historic resources. Wheeler, along with Rolband, was responsible for leading the RGGI withdrawal efforts. Youngkin has since made Wheeler a senior adviser, a post that does not need confirmation. (See Va. Senate Committee Rejects Wheeler Nomination.)

At the same time, the General Assembly rejected two members of the Air Pollution Control Board — Joshua Behr and Richard Langford — who had been nominated by Northam but not yet confirmed, leaving two vacant seats, according to DEQ spokesperson Anissa Rafeh. Two other members, Vice Chair Kajal Kapur and Gail Moore, term out in June.