Page 589 – RTO Insider

October 11, 2021June 14, 2023

Stakeholder Soapbox: Transmission Planning Needs to be Improved — And We Already Know How to Do It

Johannes P. Pfeifenberger | The Brattle Group

Both reliability and clean energy related public policies are increasing the need for and benefits of large-scale regional and interregional transmission to avoid increased total electricity costs. Most studies of decarbonization find that a cost-effective end result requires at least a doubling of the delivery capacity of the U.S. transmission network.

Proven industry practices show that the industry already knows how to put together transmission plans based on co-optimizing generation and transmission to reliably and cost-effectively link anticipated future generation with anticipated future load. Any reasonable estimate of future generation reveals that each region will have a generation mix that is very different from today’s. But as FERC said in its recent Advanced Notice of Proposed Rulemaking, “transmission planning processes generally do not plan for the needs of anticipated future generation.”

In a new report, analysts from the Brattle Group and Grid Strategies offer some solutions that need to become standard practice, based on some proven examples of forward-looking, multi-benefit planning by some RTOs/ISOs and other grid planners in the U.S. and abroad. (See related story, New Tx Study Calls for Holistic Planning Across Regions.)

Rob Gramlich | Grid Strategies

The U.S. has been investing between $20 billion and $25 billion annually in improving the nation’s transmission grid. Over 90% of these investments are justified based on: (1) the local reliability criteria of transmission owners, including the replacement of the many aging transmission facilities built before the 1970s; (2) the local and regional reliability upgrades triggered by generation interconnection requests, which are now dominated by renewable generation and storage resources in many regions; and (3) the reliability criteria associated with regional planning processes conducted by grid operators. To date, only a small portion of transmission spending is justified on economic criteria and full analysis of broader regional and interregional benefits and costs.

The prevalent approach to transmission planning can be described as inefficiently reactive and incremental. It fails to take account of the large economies of scale and scope that exist in more holistic forward-looking plans. It fails to capture the co-benefits that exist in “reliability,” “economic,” and “public policy” based transmission facilities. Improved practices will significantly reduce electricity costs relative to status quo planning.

Costs associated with the prevalent planning approaches can be shown to be excessive when comparing studies under the current approach versus a holistic plan. For example, our report compares the results of a recent “regional” offshore wind analysis with the results of PJM’s generation interconnection studies. PJM’s study shows that the current generation interconnection study process (evaluating one interconnection cluster at a time) approximately doubles the transmission-related costs of integrating offshore wind generation compared to a more proactive, regional study process.

Improve Planning Processes

The planning processes can be improved by taking advantage of the last decade’s proven industry experience. MISO’s Multi-Value Project planning effort was a great example. It was proactive by incorporating anticipated future generation and load. It was multi-value, considering reliability, public policy, production costs and other benefits. It was scenario-based, finding a “least regrets” set of lines that were valuable under multiple potential future states. And it was portfolio-based, finding efficiencies and a less contentious cost allocation approach compared to considering projects individually.

MISO’s MVP plan is only one example. SPP’s Integrated Transmission Planning, numerous CAISO economic planning efforts, New York’s public policy transmission planning, and ERCOT’s CREZ and long-term system assessment approaches are all great examples of what can and should be done routinely.

These examples of successful, effective and proactive transmission planning demonstrate that we have proven and workable planning methodologies that can be employed. RTOs, their stakeholders and members, states, and FERC should see to it that these methods become the rule, not the exception. Thus far we do not have any good examples of joint interregional planning efforts that could lead to efficient interregional transmission infrastructure, but we’ll need to have that as well to achieve an efficient, reliable and resilient network.

The Planning Imperative

It will be critical to improve the existing processes for transmission planning and generation interconnection with proactive approaches that employ the above methodologies. Without such improved planning, we will not be able to build the more cost-effective, more flexible electricity grid necessary to meet reliability, economic and public policy needs at lower overall costs. In fact, without improved planning processes we may not even be able to bring online the clean-energy resources necessary to achieve the public policy mandates in place today.

Johannes P. Pfeifenberger, The Brattle Group’s practice leader for electricity wholesale markets and planning, is an economist with a background in electrical engineering and over 25 years of experience in electricity markets, regulation and finance.

Rob Gramlich is founder and president of Grid Strategies LLC, which provides economic policy analysis for clients on electric transmission and power markets in pursuit of low-cost decarbonization. He serves as executive director of Americans for a Clean Energy Grid and the WATT Coalition.

October 11, 2021November 6, 2023

Regulators Debate Competition in Entergy’s Texas Footprint

Texas regulators last week discussed the lack of competition in Entergy Texas’ (NYSE:ETR) footprint in the state’s southeastern portion, questioning whether the costs that previous commissions have allowed the utility to recover have benefited ratepayers.

At issue is a transmission-to-competition rider the Public Utility Commission approved in 2006, allowing Entergy to recover $14.5 million annually over a 15-year period for expenses incurred in 1999 through 2005, plus carrying costs, a figure that amounted to $207 million. The order was a result of 2005 legislation (House Bill 1567), which allowed an investor-owned utility to recoup spending more for capacity under power purchase agreements than were included in its last rate case (31544).

“It troubles me that ratepayers in the southeast spent [$200 million] on the transition to competition, and they have nothing to show for it,” Commissioner Jimmy Glotfelty said during the PUC’s open meeting Thursday.

The order stipulated three true-up periods every five years, with the last occurring this year. Entergy’s final true-up, approved by the PUC on Thursday, reflected a cumulative overcollection of $3.1 million (51806).

The Entergy Texas footprint creeps close to Houston. | EntergyThe utility, then known as Entergy Gulf States, opted out of ERCOT’s competitive market, eventually joining MISO in 2013.

“It seems to me competition has been good for the rest of the state,” Glotfelty said. “If this moves us toward a competitive market in that area, I think that would be prudent. Stakeholders need to tell us is it’s time to move forward with competitive choices in the southeast region.”

Commissioner Will McAdams echoed Glotfelty’s comments, saying expanding competition into the southeast has been “heavily debated” within the state legislature, where he once worked. He also noted opinions over whether Entergy Texas should join ERCOT’s competitive market have gone back and forth.

The February winter storm “has made people evaluate that maybe [competition] is not such a good thing,” McAdams said. “If consumers and ratepayers want to see any type of competitive benefit in the future, we should provide them a venue at the PUC during the interludes between legislative sessions, where they can speak in front of their elected representatives.”

Commissioner Lori Cobos reminded her peers that one of the reasons Entergy joined MISO was that it wanted to “garner some of the benefits of being in an actual RTO or ISO.”

“As a commission, we should continue to review whether that is producing the benefits that were proffered to us as joining MISO. This merits a lot deeper consideration,” Cobos said.

After listening to the debate, PUC Chair Peter Lake offered his opinion on what Entergy’s customers can do.

“If they want to have that conversation, they should let us know,” he said.

ERCOT to Continue Conservative Ops

ERCOT staff told the commission that they will continue with their conservative operations approach through the winter and into next summer because of maintenance outages during the shoulder months.

After assuring the commission they would recall or deny thermal maintenance outages should unseasonably warm or cold weather create tight conditions, staff did just that on Friday, issuing an advanced action notice for Monday. The grid operator said it expects to withdraw or delay approved or accepted outages from 3 to 9 p.m. to scrounge up 94 MW of capacity to meet expected demand.

According to the notice, ERCOT expects wind and solar contributions to amount to about 6 GW from 6 to 7 p.m.

Dan Woodfin, senior director of system operations, told the PUC the amount of thermal capacity taken offline for maintenance outages has increased this fall to 18 GW, up from 10 GW a year ago.

Woodfin and Kenan Ögelman, vice president of commercial operations, also briefed the PUC on the recently completed summer season that they summarized as cooler than normal, wetter than normal, less windy than normal and conservative.

With the exception of August 2019, ERCOT’s ancillary services expenditures this summer exceeded the previous two. | ERCOT

Average daily temperatures were 1 to 2 degrees cooler than normal, without the widespread temperatures across the state that generally mark Texas summers. ERCOT did set new monthly peaks for June (70.2 GW) and September (72.2), but the summer peak of 73.5 GW on Aug. 31 was far short of the projected 77.2 GW.

Additional solar resources led to higher solar generation June through August, peaking at a record 7.04 GW on Aug. 31. Wind energy also set a new demand peak, hitting 23.6 GW on June 25.

Ögelman said prices were relatively low during the summer, with few spikes. ERCOT committed more resources through reliability unit commitments than it has in previous summers — for more than 2,000 effective hours, compared to about 200 in 2020 — and spent more than $50 million each month during the summer procuring non-spin reserves and other ancillary services.

ERCOT has drafted a nodal protocol revision request (NPRR) that will allow non-controllable load resources to participate in non-spin reserves, Ögelman said. The measure has cleared the Technical Advisory Committee and goes before the Board of Directors next. (See ERCOT Technical Advisory Committee Briefs: Sept. 29, 2021.)

“There’s no good reason not to allow load to participate,” Ögelman said when asked the reason for the change. “You want all the resources that can provide value to that space providing value to that space. Secondarily, this adds more liquidity to that market.”

When Ögelman told the commissioners the NPRR may not be implemented until the middle of next summer, Lake said softly, “We can work on that.”

PUC Clarifies Securitization Order

Staff have filed draft orders codifying the commission’s response to ERCOT’s requests for debt-obligation orders that would allow the grid operator to securitize $2.9 billion in market debt as a result of high charges incurred during February’s storm (52321, 52322). (See Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)

The commissioners agreed that companies that opt-out of ERCOT’s proposal to finance $2.1 billion in debt would have to form a new entity if they want to start serving unaffiliated customers. Upon re-entering the market, the entities would be assessed uplift charges.

An NPRR wending its way through the ERCOT stakeholder process would strengthen the grid operator’s market-entry qualification and continued participation requirements. The commissioners decided to wait on the NPRR, rather than direct ERCOT to develop and implement it.

In another storm-related docket, the commission agave staff the go-ahead to publish a rulemaking for public comment that cuts the high systemwide offer cap (HCAP) from $9,000/MWh to $4,500/MWh. It will become effective Jan. 1 (52631).

The HCAP is currently set by rule at $2,000 after it was stuck at $9,000 for too many consecutive hours during the storm but was to revert back to $9,000 on Jan. 1. The cap was designed to incent generation to come online during tight conditions. (See “Offer Cap Could be Halved,” Texas PUC Directs Tx Construction in Valley.)

“By no means will this be the only action we take on the ERCOT market design structure,” Lake promised.

Status Reports for Valley Project

Following the PUC’s directive last month to three utilities that they add a second 345-kV circuit to an existing transmission line in the Rio Grande Valley, Cobos requested quarterly updates on the project (52682).

Cobos asked that effective Nov. 1, AEP Texas, Sharyland Utilities and South Texas Electric Cooperative file progress reports detailing tasks, time estimates, coordination with ERCOT, delays, and reliability and safety measures necessary to complete construction.

In other actions, the PUC:

rejected Entergy Texas’ application to acquire a proposed 100-MW solar facility in southeast Texas, agreeing with an administrative law judge that the utility did not prove the acquisition was a cost-effective way to provide consumer benefits when compared to alternatives (51215);
signed off on a unanimous settlement agreement between AEP Texas, staff and other parties under which the utility will refund $23.4 million to ratepayers for transition bonds issued by its AEP-Central Division (51484);
granted requests by Southwestern Public Service (52072) and Texas-New Mexico Power (52153) to adjust their energy-efficiency cost recovery factors for the 2022 program year by $6.3 million and $7.2 million, respectively; and
assessed a $56,000 administrative fee against AEP Texas for exceeding SAIDI and SAIFI standards by more than 5% during its 2019 reporting year (52034).

October 11, 2021

MISO Market Subcommittee Briefs: Oct. 7, 2021

An emerging underfunding trend has led to some early concerns for MISO’s congestion-hedging market.

MISO says there’s a burgeoning mismatch between awarded auction revenue rights (ARRs) and actual congestion patterns in the footprint. As a result, load-serving entities hold a historically smaller share of financial transmission rights (FTRs) and the congestion value associated with ARRs is falling, the RTO said.

Staff’s John Harmon said during a Thursday Market Subcommittee teleconference that the trend began in December 2019.

The grid operator said while it won’t propose FTR market changes for the 2022-23 planning year, it said “substantial foundational rule changes” could be on the horizon to better line up ARR awards and congestion patterns. The RTO has hired an outside consultant to investigate its FTR-ARR auction structure.

ARRs and FTRs in MISO are issued based on transmission capacity and used by LSEs and other market participants as financial hedges against congestion charges in the day-ahead market. The grid operator funds FTRs through day-ahead congestion costs. An ARR is the LSE’s entitlement to a share of revenue from FTR auctions because of their historical use and investment in the transmission system.

MISO Independent Market Monitor David Patton observed that FTR obligations in 2020 exceeded congestion revenues by $74.6 million, a 4.1% shortfall.

MISO said increasing wind generation has reduced the volume of ARRs. Wind generation ARRs tend be about one-third of those associated with retiring baseload generation.

“Even though wind can produce up to 20 to 25% of energy, it has a smaller share of auction revenue rights,” Harmon said.

MISO said its FTR-ARR market was developed to “protect long-term rights with provisions for very limited, incremental portfolio change.”

Harmon said the recent move to lower generation shift factor cutoffs from 1.5% to 0.5% in the day-ahead market should better line up congestion with FTR rights. MISO will monitor the change’s effects before proposing any changes to its FTR market structure, he said. A lower generation shift factor allows staff to redispatch generators to improve transmission constraints.

Bill Booth, consultant to the Mississippi Public Service Commission, suggested MISO restrict participation in the FTR auctions to LSEs and those with long-term power contracts. WEC Energy Group’s Chris Plante has said it doesn’t seem fair that “a significant amount of day-ahead congestion revenue is allocated to entities that are not allocated any of the transmission system cost.”

Stakeholders have also recommended MISO revive its dormant FTR working group to examine potential changes to FTR and ARR mechanisms.

Harmon said MISO isn’t supportive of eliminating FTRs altogether, as some have suggested. “That would be a substantial overhaul of how we allocate congestion in our day-ahead market,” he said.

MISO Encourages Accurate Renewable Forecasts

MISO is proposing that its tariff contain direction on member-derived forecasts for dispatchable intermittent resources.

The RTO has said for months that its output forecasts for intermittent resources are consistently more accurate than those created by its members.

“As we get high wind and solar penetration, accuracy of forecasts is going to important for reliable operations and market efficiency,” Congcong Wang said of MISO’s day-ahead market and reliability commitment division.

The grid operator is proposing tariff language that members’ maximum forecast limits “reflect the most likely forecast outcome, and be directly derived from an accurate, and statistically unbiased forecast, using the most current forecast data available for the specific dispatch interval.”

The RTO also said that the forecast should be “directly derived” from a resource’s capabilities, actual generation data and weather predictions “relevant as of the time of submission.” It plans to file with FERC by December.

Staff will also periodically check its market participants’ forecasts to see if they continue to be less accurate than MISO’s. Wang said staff will reach out to market participants with chronically inaccurate forecasts before forcing them to use MISO’s forecasts. After that, a market participant can submit evidence to regain control of its forecasting.

More than 95% of MISO’s nearly 270 intermittent resources already use the grid operator’s renewable output forecasts. The RTO estimates that its footprint will contain more than 30 GW of wind and about 11 GW of solar in the next few years.

Some stakeholders have asked whether MISO couldn’t simply dictate that holdouts use MISO’s forecasts instead of making their own.

Wang said the language represents a “first big step” from the tariff being silent on forecast accuracy to prescribing careful forecasting. She said MISO doesn’t want to be too prescriptive in members’ forecasting.

Tx Customers Ask for Additional Load-forecasting Data

MISO transmission customers are asking for more insight into staff’s weekly load forecasts.

McNees Wallace and Nurick attorney Ken Stark, appearing on behalf of the Coalition of MISO Transmission Customers, said MISO is an outlier among RTOs because it doesn’t make its load forecasting data over the next week available to customers.

“MISO provides a day-ahead forecast by local balancing authority; however, that forecast is much less valuable than a current day plus six-day forward-looking forecast,” he said.

Stark said if large transmission customers had access to more specific load data, they might have been able to prepare and assist during Tuesday’s maximum generation alert and conservative operations declaration for the Midwest region. The event was unexpected because of mild weather and systemwide load of 72 GW.

He asked that customers have access to seven-day load forecasting data on the local balancing authority or local resource zone level. Stark also said MISO could make the data available to customers via a secure portal if the RTO is worried about revealing nonpublic data.

IMM: June 10 Emergency Unnecessary

MISO’s Independent Market Monitor has concluded that the RTO did not need to escalate a maximum generation alert to a maximum emergency on June 10.

The brief emergency resulted in a surfeit of load-modifying resource (LMR) response and non-firm imports. (See “MISO Defends June Emergency Declaration,” MISO Market Subcommittee Briefs: July 8, 2021.) Ultimately, the event generated $2 million in day-ahead margin assistance payments to resources “that had to be held down to make room for the additional supply,” the IMM’s David Patton said.

“The combination of commitments, LMRs and higher imports led to a surplus in the Midwest exceeding 10 GW for most of the event,” he said.

Patton called for a more “surgical” method for deploying LMRs so that MISO is more precise in ordering curtailments. The grid operator has about 11.5 GW in LMRs participating as capacity, split 60-40 between demand response and behind-the-meter generation.

“We’re a unique RTO that … has 16, 17 GW import capability,” he said.

Patton suggested MISO attempt modeling that contemplates non-firm imports when it is struggling and its neighbors aren’t.

He said suggested the grid operator delay making real-time commitments until control room operators are certain they’re necessary.

In this year’s State of the Market report, Patton asked the RTO to create an “uncertainty product” from fast-start resources to replace the expensive, out-of-market commitments that control room operators make. He said the system’s rising numbers of intermittent generators necessitates another class of energy reserves.

VoLL Pricing at Dead Buses Questioned

The subcommittee meeting contained another disagreement over MISO’s policy of pricing dead buses at their $3,500/MWh value of lost load (VoLL).

Some stakeholders question how MISO can price dead buses at the VoLL when generators are unable to deliver power to customers.

Kevin Vannoy, MISO’s director of market design, said it’s an incorrect assumption that all dead buses can be traced to a catastrophic event. He said that sometimes, it’s as simple as a generator being offline.

“The value of energy is the value of energy whether it’s theoretical or possible,” Vannoy said.

“It’s a theory that cost $90 million,” Booth said, referencing VoLL pricing during Hurricane Laura.

The RTO originally said force majeure events that lead to dead buses should not be priced using VoLL. (See MISO to Outline New Pricing Plan for Hurricanes.) It said VoLL is appropriate to price capacity emergencies, even when they’re caused by force majeure, but that local and systemwide transmission emergencies should be shielded from the pricing.

“The procedures don’t speak to the cause of the emergency; they give us the tools to manage the emergency,” Vannoy told stakeholders during July’s subcommittee meeting.

Patton said February’s arctic event was a “garden variety” combination of transmission and capacity emergencies. He said it becomes difficult after emergencies to separate those caused by unavailable transmission or inadequate capacity.

“The distinction is really, I think, harmful,” Patton said in July.

October 10, 2021

MISO Draws on Storage Model for DER Aggregations

MISO said last week it will pivot to its existing electric storage resource participation model in allowing distributed resource aggregations into its markets under FERC Order 2222.

The announcement scraps MISO’s original plan to use a modified version of dispatchable intermittent resource participation model for DER aggregations. (See MISO Assembling Order 2222 Compliance Plan.)

“We’re creating an entirely new model that largely leverages our [electric storage resource] model,” Market Design Adviser Michaela Flagg said during a Tuesday Distributed Energy Resources Task Force teleconference.

Under the new plan, all aggregations will be responsible for self-committing in the markets, instead of just those 1 MW in size or smaller. MISO will recommend that aggregators perform DER forecasting and reflect it in offers. The RTO also said it won’t dictate state-of-charge parameters, leaving those to aggregators.

The new DER aggregation model will use all eight of the operating modes in MISO’s electric storage model, with commitment statuses including:

injecting,
emergency injecting,
withdrawing,
emergency withdrawing,
continuous, or the ability to move between injecting and withdrawing,
available,
not participating or
outage.

MISO expects the injecting, withdrawing and continuous modes will be most popular with aggregations.

The grid operator will likely require aggregators enrolling DERs to choose between demand response, distributed storage or distributed generation. Some stakeholders said having DERs declare just one registration type ignores DER’s other uses. One stakeholder likened it to a “choose-your-own adventure” book that disadvantages participating aggregators.

MISO’s response is that aggregators will be responsible for understanding DERs’ capabilities in their aggregations and should tailor the offers accordingly.

Kristin Swanson, the RTO’s DER program director, said it’s up to aggregation management to choose whether a DER will generate, inject or conserve energy. She said the market cannot currently choose between two separate bids from the same resource and the RTO’s real-time modeling cannot accommodate two resource types from a single resource.

“That’s not something we’re capable of doing right now,” Swenson said.

MISO won’t finalize a registration process until February.

Staff still plans to limit DER aggregations to a single pricing node they say will keep pricing simple and ensure that aggregations don’t aggravate transmission constraints.

Swenson has said Order 2222’s instruction that MISO cross the “distribution barrier is going to be a new experience.” She also called the 100-kW minimum size threshold “pretty tiny.”

“MISO’s not the only party that has to be ready in order for this to work,” she said during a Sept. 30 Reliability Subcommittee meeting.

Some stakeholders have asked MISO to keep cybersecurity at top of mind when designing communication modes with distribution operators.

Swenson has said she expects MISO’s first tariff filing, should FERC accept it, will require adjustments over time.

“We know we’re not going to have a perfect, comprehensive tariff filing in April, and we’ll never have to touch it again. We’re very aware that this is an emerging class of grid services,” she said.

Swenson also said MISO will maintain a “parking lot” list of DER ideas beyond Order 2222 compliance that it can’t currently accommodate because of current system limitations.

October 10, 2021

MISO, SPP: Economics Secondary in Joint IC Planning

MISO and SPP said on Friday that a weak economic showing isn’t necessarily a dealbreaker in building transmission projects to accommodate generation from the RTOs’ overflowing interconnection queues.

Staffs told stakeholders Friday that their joint targeted interconnection queue (JTIQ) project has identified 11 projects in the upper Midwest that relieve most MISO-SPP constraints, but with a 0.33:1 combined benefit-to-cost ratio. The projects, tested with five other combinations of effective projects, are valued at $2.445 billion.

The grid operators also continue to consider a $424 million package that incorporates a long-distance, 345-kV line from Big Stone, S.D., to Alexandria, Minn.; a 345-kV line on the northeast side of Kansas City; and a transmission facility on the west side of Minneapolis. The multi-pronged project shows a combined 2.08:1 B/C ratio, but SPP experiences a negative 0.06:1 economic benefit ratio because of downstream impacts on other transmission lines.

If a project shows a negative B/C ratio to one RTO, it won’t automatically quash its chances of being approved, staff said.

MISO and SPP’s second round of evaluations tested 28 RTO-originated and stakeholder-submitted transmission solutions using their respective reliability and economic models. Eight solutions failed to relieve any transmission constraints, staff said.

The RTOs identified several projects crisscrossing South Dakota, Minnesota and Missouri during a first round of research under their joint targeted interconnection queue study. (See MISO, SPP Name Projects to Help Queue Troubles.)

Kelsey Allen, SPP’s lead engineer of transmission planning, said the JTIQ work began primarily as a reliability study, and the RTOs don’t intend to switch up projects now to chase higher adjusted production cost (APC) benefits.

The RTOs said they will have a final study report ready in December. Multiple stakeholders asked for an additional call to discuss project evaluation and selection before staff issues the final report.

MISO and SPP might use each footprint’s APC metric to determine cost allocation, increased transfer capability and real-time congestion reductions. The two could also assign some project costs to individual interconnecting generators based on avoided network upgrades.

SPP senior engineer Neil Robertson said the RTOs continue to collaborate on a final cost-allocation approach. He said it’s not easy to boil projects down to benefit dollars, so staffs may develop a rubric to divide costs that uses a scoring system for benefits like APC savings and new megawatts from the interconnection queues.

“I think anyone would want to see a simple benefit sheet in dollars,” he said. “You’re taking very different perspectives and traditional planning calculations and trying to compare them to one another. It’s apples to oranges.”

October 10, 2021

Texas Senators Call for New RRC Weatherization Rules

Saying the Texas Railroad Commission’s (RRC) proposed weatherization rules for natural gas facilities don’t align with the state legislature’s intent, a Senate committee has sent a letter to the agency urging it to revise its rulemaking.

“It has become abundantly clear that failure to properly identify and weatherize critical natural gas infrastructure contributed to widespread power outages across the state,” the letter says. “The commission’s proposed rules contemplate designating all natural gas infrastructure assets as critical without regard to whether these assets directly support critical generation.”

During a Sept. 28 hearing before the Senate Business and Commerce Committee involving the RRC, which regulates the state’s oil and natural gas industries, the senators learned that under the commission’s proposed weatherization requirement, facilities can avoid the rule by not declaring themselves as critical infrastructure and paying a $150 opt-out fee. A Federal Reserve Bank of Dallas report said it can cost between $20,000 and $50,000 to weatherize new and existing wellheads. (See “State Senate Grills Gas Regulator,” Texas PUC Finances Market Debt over Lt. Gov.’s Objections.)

The letter, signed by all nine members of the committee, said rather than designate all facilities as critical, the RRC should start with gas-fired units and work backward through the supply chain to prioritize those elements “most directly essential to electric generation.”

“We sent this letter to the RRC to provide guidance as they proceed in their rulemaking process,” committee Chair Charles Schwertner (R) tweeted. “I will continue to hold these agencies accountable.”

Separately, Rep. Jon Rosenthal (D) filed a bill last week to close the loophole. “It is vital that we fix this oversight, so that Texans may finally have a reliable power grid,” Rosenthal tweeted.

The RRC on Thursday requested the state’s natural gas operators to “take all necessary action” to prepare for winter weather, according to the Houston Chronicle.

October 10, 2021June 14, 2023

New Tx Study Calls for Holistic Planning Across Regions

A new study on regional and interregional transmission planning pinpoints inefficiencies that hinder the integration of new renewable resources and recommends solutions to save the industry time and money and keep customer rates down.

The Brattle Group and Grid Strategies released their report Thursday ahead of this Tuesday’s deadline for submitting comments on FERC’s Advance Notice of Proposed Rulemaking (ANOPR) (RM21-17). The commission is looking at potential changes to improve electric regional transmission planning, cost allocation and generator interconnection processes.

The report finds systemic under-planning and under-investment in transmission. It recommends “incorporating realistic projections of the anticipated generation mix, public policy mandates, load levels and load profiles over the lifespan of the transmission investment,” rather than planning piecemeal on a case-by-case basis.

Transmission costs may grow as a percentage of total electricity costs but are still small relative to generation and present a more cost-effective solution that reduces systemwide costs and mitigates electricity rate increases, the report said.

“I think it’s hard to even say that we’re doing transmission planning, except for limited instances … like in the New York public policy work … and MISO MVPs [Multi-Value Projects],” Grid Strategies CEO Rob Gramlich told RTO Insider. “But just to comply with NERC regulations each year and make some upgrades here and there … is hard to call planning.”

Questions for the Future

The commission in its ANOPR gave several examples of questions it wants to address, starting with whether the existing regional planning processes appropriately consider the transmission needs of anticipated future generation, and whether reliability, economic considerations and public policy requirements are inappropriately siloed from one another.

“The geographic scope of regional and interregional RTO planning processes tends to be narrowly focused in its consideration of the transmission-related benefits’ geographic scope, typically quantifying only a subset of transmission-related economic and public policy benefits,” the planning report said.

FERC also posed the question of how to appropriately identify and allocate the costs of new transmission infrastructure in a manner that satisfies the commission’s cost-causation principle: that costs are allocated to beneficiaries in a manner that is at least roughly commensurate with estimated benefits.

Planners now consider only benefits that accrue to their own region without considering the broader set of interregional benefits, the report said.

“Projects near the regional boundaries, such as an upgrade to a shared flowgate, can address the needs of neighboring regions and need to be considered if the goal is to determine the infrastructure that most lowers cost,” the report said.

Without considering interregional needs, quantified benefits will be understated, and even “regional” projects near RTO seams could fail to meet applicable benefit-cost thresholds for regional market-efficiency and public policy needs simply because the planning process ignores the benefits that accrue on the other side of the seam, the report said.

A key driver of MISO’s MVP cost allocation process was state representatives requesting the RTO to evaluate cost-effective transmission solutions that could meet the region’s combined state-level renewable portfolio standards.

MISO’s $6.6 billion worth of MVP projects approved in 2011 are now estimated to provide economic net benefits of $7.3 billion to $39 billion over the next 20 to 40 years. | The Brattle Group

“A high-level outlook of how states wish to pursue meeting their goals, or a more detailed set of scenarios, would greatly improve the ability of RTOs to plan their future system without having to develop a specific portfolio of resources to do so,” the report said. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

“The findings reinforce that there are many ways FERC can improve the current planning processes, particularly by ensuring that well known and previously tested transmission benefits are fully quantified,” said Barbara Tyran, director of the American Council on Renewable Energy’s Macro Grid Initiative, which supported the planning study.

New public policies and regulatory guidance is needed to implement improved planning processes that can achieve more efficient results, the report said.

FERC also asked whether and how to better coordinate between regional and local transmission planning processes to identify more efficient or cost-effective solutions; and whether it is necessary, and how, to more clearly identify the lines of regulatory authority and oversight between states and federal authorities.

Grid operators and planners need to be part of the policymaking process to ensure efficient and reliable integration of renewables, the Eastern Interconnection Planning Collaborative said in a white paper Wednesday. (See related story, Grid Operators Seek Policy Role, Reliability ‘Safety Valve’.)

October 10, 2021October 30, 2023

Oregon Group Contemplates RTO for a ‘Decarbonized World’

A Western RTO would likely take shape for reasons much different from those that motivated the creation of organized markets in other parts of the U.S.

That view was widely shared among members of Oregon’s RTO Advisory Committee last Wednesday, when it met for a second time to hammer out the contents of a study on the benefits and risks of RTO membership, due to the legislature by the end of the year.

During the committee’s first meeting in September, Adam Schultz, the Oregon Department of Energy’s Electricity and Markets Policy Group lead, promised that the second gathering would address a key question: What problem is the state attempting to solve by joining an RTO?

The answers for other organized markets usually centered on the anticipated cost savings to utilities — and their ratepayers — from the centralized dispatch of generation and regional transmission planning.

But the views expressed Wednesday pointed to a different factor driving the need for a Western RTO: namely, its potential role in decarbonization.

‘Feeling of Desperation’

What’s changed?

“I’d say it’s the conversation around our state’s mandates on procuring more clean energy, but also around the impacts and effects of climate change is having on our system,” said Nicole Hughes, executive director of advocacy group Renewable Northwest.

“Ten years ago, we weren’t seeing the radical climate [and] weather impacts; we weren’t dealing with the wildfire situation that we are today,” Hughes said. “So I think for some people involved in this conversation, there’s a feeling of desperation that if we aren’t doing everything that we could possibly do, to continue to live the lifestyles that we are hoping to live, then we’re not doing enough.”

For Renewable Northwest members, an RTO would be “one of the solutions” to decarbonizing the electricity sector, Hughes said.

Speaking from the virtual audience, Michael Jung, vice president of government affairs at generation and transmission cooperative PNGC Power, said his group’s members are committed to achieving carbon neutrality by 2033. Jung said PNGC’s membership of publicly owned utilities has in the past relied on the vast and “cheap” hydroelectric system managed by the Bonneville Power Administration to serve their customers “and never really had to think very hard about what to do to shape the future.”

But BPA’s “preference” customers confront a future in which the Federal Columbia River Power System will no longer be able to fully meet their needs. “The easy way out is no longer going to be an option,” Jung said.

“In the context of our carbon commitment, we really do believe that a Northwest RTO is going to be an essential ingredient towards giving us options that go beyond just the BPA preference power portfolio, and giving us a market that we can turn to to meet our needs, particularly in clean power, as well as facilitating the delivery across the transmission network, which may or may not be BPA[-operated],” he said.

Sarah Edmonds, director of transmission services at Portland General Electric, said an RTO is “unique” in offering the “integrated solution” needed to facilitate “deep decarbonization and clean energy integration” through better utilization of “resource solutions that don’t look like our traditional set of generation resources” on the grid.

“And when I say ‘integrated,’ I’m emphasizing the fact that the RTO brings all of the inputs and outputs from the market optimization part of the RTO, the transmission planning and the resource adequacy piece — potentially. And because those pieces are under one roof, they’re able to leverage each other, and the data that’s produced from these different functions and mechanisms can be integrated to provide that solution where all the pieces are coming together,” Edmonds said.

Mary Wiencke, vice president of market, regulation and transmission policy at PacifiCorp, cautioned that an RTO by itself will not reduce carbon emissions.

“I think the idea is to operate the system more effectively and enable that decarbonization to happen more efficiently, more cost effectively,” she said.

But Wiencke said any RTO dispatch model would need to consider state policies, such as California’s carbon pricing, a policy soon to be adopted by Washington state as well. “Those state policies will need to be reflected in the market rules in some fashion,” she said.

“I think one thing for you all to consider is that all seven RTOs/ISOs that have been formed were formed in a carbon environment. This is an opportunity for the region to consider what an RTO would look like in a decarbonized world,” said Ravi Aggarwal, a BPA manager and ex officio member of the RTO Advisory Committee.

‘Art of the Possible’

During the committee’s first meeting in September, it was Aggarwal who posed the idea that the Pacific Northwest consider an “incremental” approach to developing an RTO. (See Oregon RTO Committee Ponders Paths to Regionalization.) On Wednesday, he clarified that he wasn’t advocating for foregoing the pursuit of an RTO with the looser arrangements that exist in the region today.

But Aggarwal pointed out that the Northwest is unique in that it contains BPA, a non-FERC jurisdictional entity that controls about 70% of the region’s transmission and faces possible statutory limitations related to how it can participate in an RTO.

“If you look at the history, it took us about four years just to form a regional planning organization — Northern Grid — and that’s just one functionality of many that an RTO serves,” Aggarwal said, recounting other incremental developments such as the expansion of the Western Energy Imbalance Market (WEIM) (which BPA will joint next year) and the creation of the Western Resource Adequacy Program by the Northwest Power Pool. (See RA Program Will Require Restructuring of NWPP.)

“All those are incremental steps that move us probably closer to an RTO construct. It doesn’t take us directly to an RTO, but it builds a pathway to maybe eventually get to an RTO,” whether within an area like the NWPP footprint or West-wide, he said.

Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said his organization has supported the incremental steps the region has taken so far but thinks those efforts might be reaching the limits of their effectiveness.

“I think we’re going to get up to the edge of not being able to do much more, to evolve our grid to deal with emerging issues like the commitment of Washington and Oregon to 100% clean grids. We’re not to that edge yet; I think perhaps the [WEIM] day-ahead market possibly will be the edge of that functionality that can be bolted on to our existing grid without a more fundamental shift, which an RTO represents,” Gray said.

Wiencke said the need to decarbonize might outpace the timeline for creating an RTO.

“The conversation, I think, is really about urgency, and really about accelerating the decarbonization process, and I think there’s a lot of things that are needed to achieve that, including potentially an RTO,” Wiencke said. “However, I think there’s real tension there, because an RTO is going to take a long time to put together and to put in place, and I don’t know how to advise on sort of accelerating the development of an RTO.”

Oregon Public Utility Commissioner Letha Tawney pointed to other “constraints” beyond BPA’s jurisdictional status that have consigned the Northwest’s electricity sector to a policy of incrementalism — both rooted in California.

The first is CAISO’s state-run governance model, which Tawney believes California lawmakers would be willing to amend.

More intransigent though is the state’s resource adequacy model — overseen by the California Energy Commission rather than CAISO — which Tawney thinks the legislature is less likely to change.

“To incorporate [California] in the [RTO] dispatch, to take advantage of all the solar that they want to send out on a daily basis, and all of the investment they’re making in batteries, we will face a real challenge if we try to bring both the RA construct and a market construct together,” Tawney said. A governance change for RA program “isn’t even on the table right now.”

“There isn’t that sort of perfect RTO that we’re comparing to; we’re comparing to the art of the possible, given the existing landscape we’re operating in,” she said.

October 8, 2021November 17, 2023

DOE, NREL Launch Energy Cybersecurity Accelerator

Seeking to “encourage the rapid development of cybersecurity technologies,” the Department of Energy and the National Renewable Energy Lab (NREL) on Wednesday announced a program to accelerate the creation of cybersecurity solutions for the North American power grid.

The Clean Energy Cybersecurity Accelerator is sponsored by DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) and Office of Energy Efficiency and Renewable Energy (EERE), which will both contribute experts to serve as a federal advisory board within the program. A steering committee will include representatives from industry to provide “strategic direction and cost-sharing.” Xcel Energy (NASDAQ:XEL) and Berkshire Hathaway Energy are among the first members of the committee.

According to a statement from NREL, the effort is aimed at addressing vulnerabilities in the existing bulk power system, as well as new weaknesses expected to develop as the grid moves away from traditional generation resources toward renewables, distributed energy and storage solutions.

“A disruptive approach to rapidly infuse cybersecurity innovation into renewable energy systems, without delaying time-to-market, is needed to outpace the speed of emerging threats to our evolving energy infrastructure,” NREL said.

The accelerator will work on a yearly cycle, with the advisory board and steering committee setting a priority topic for each term. A new cohort of security-focused startups working on early-stage technologies will be recruited each year to go through a three- to 12-month incubation period.

Technologies developed during each cycle will be evaluated with NREL’s Advanced Research on Integrated Energy Systems (ARIES) platform. ARIES is a simulated grid environment with a three-layer model — representing electrical, control and telecommunications systems — in which utilities can test various threat scenarios. Along with cybersecurity, the platform has also been used to test the impact of energy storage and hybrid energy systems, new system architectures and advanced energy infrastructures.

“The transition to a clean energy economy will require groundbreaking cyber solutions to strengthen America’s grid security, protect our energy infrastructure and address the increasing threat of extreme weather events across the country,” Deputy Energy Secretary David Turk said in a separate press release. “We are grasping the opportunity to build a grid that can dispatch historic amounts of renewable energy across the country while addressing grid vulnerabilities and positioning America for a clean energy future.”

The launch of the new accelerator comes amid a time of growing awareness and concern in the utility sector around the safety of the grid’s electronic components. High-profile cyberattacks like the Colonial Pipeline ransomware attack in May have already led to new cybersecurity requirements on the nation’s pipeline network. (See TSA Issues New Pipeline Cybersecurity Requirements.)

Following the Colonial attack, President Biden in July announced an initiative to strengthen cyber defenses in industrial control systems at “priority critical infrastructure” systems. (See Biden Launches ICS Cybersecurity Initiative.) The president has warned in the past that “a real shooting war with a major power” is a significant possibility in the event of a major cyberattack against the U.S.

October 8, 2021November 13, 2023

‘Last-mile’ Deliveries Drive Demand for NJ Truck Incentives

The New Jersey Economic Development Agency (EDA) is adding $9.25 million to a pilot program that provides incentives of up to $100,000 toward the purchase of medium- and heavy-duty (MHD) electric vehicles after eager applicants exhausted the program’s initial $15 million fund in a matter of months.

The EDA is also expanding the program, known as New Jersey Zero Emission Incentive Program (NJ ZIP), which started with a focus on encouraging electric truck adoption in Camden in South Jersey and Newark in North Jersey. The program will now be open to New Brunswick and 33 surrounding communities in Central Jersey.

The expansion offers a glimpse into the market dynamics unfolding as New Jersey, like other states, seeks to persuade drivers — in this case, truck drivers — to get behind the wheel of an electric vehicle. The EDA said it had received 38 applications for a total of 148 vehicles in the first phase of the program, which began accepting applications on April. 6.

So far, the agency has approved 17 projects totaling 66 vehicles, purchased with vouchers worth $6.76 million; the remaining applications are pending, the agency said. The first vehicles purchased under the program are expected to hit New Jersey streets in December, the EDA said.

Most of the trucks receiving the incentives are for deliveries, according to the EDA, with a slight majority of applicants going for larger trucks, around the Class 5 or 6 size, which are considered medium-duty, commercial vehicles. The reason: not as many smaller, pickup trucks — Class 2b — are available, and purchasers of larger trucks can get a bigger incentive, the agency said.

Two manufacturers that are supplying vehicles to the buyers said the main market driver behind the applicants’ shift to electric trucks is their intended use for deliveries from a transportation or distribution hub to the final destination, often the customer’s residence, if it is an e-commerce delivery.

“What we’ve seen in Jersey is a huge demand for mid-mile, last-mile delivery solutions,” said Ryne Shetterly, vice president of sales and marketing for GreenPower Motor Company. The California-based electric truck maker is supplying nine vehicles for four NJ ZIP customers, who together will receive incentives totaling $890,000.

“Most of the business that we’ve written out there has been for the cargo vehicles, box trucks, things of that nature,” Shetterly said.

Persuading Truck Buyers to Try EVs

The NJ ZIP vouchers start at $25,000 for a Class 2b truck and then go up to $100,000 for a Class 6 truck. In the first phase of the program, those incentives were used to fund the purchase of zero-emission trucks within 10 miles of Newark and Camden. Incentive bonuses are also available. For example, a small business that scraps a gas-powered vehicle and replaces it with an electric truck can get $2,000 more per vehicle. For women-, minority- and veteran-owned business, bonus incentives are an additional $4,000 per vehicle.

The program is funded with money from New Jersey’s participation in the Regional Greenhouse Gas Initiative (RGGI). To be eligible for the incentives, an electric truck must be registered in New Jersey for three years, and 75% of the miles covered annually must be within the state, according to program rules.

In the first phase, the vehicles had to either have a home base in or around Newark or Camden or travel 50% of their vehicle miles in the area around the two cities. Both areas are considered environmental justice communities due to severe emissions from truck traffic around both cities. In the second phase, eligibility will be extended to New Brunswick and the Central Jersey region.

The incentives are designed to persuade potential truck buyers to go electric by covering the added cost of an electric vehicle over a traditional gas or diesel vehicle, said Victoria Carey, senior project officer, clean energy for EDA.

Similar EV voucher programs had proven successful at putting drivers in electric trucks in California and New York; it was no surprise that applicants exhausted the funds in New Jersey’s program in five month, she said.

“I think that there’s a lot of hunger for this type of” program, she said. “We worked really hard to make sure that we would have a positive uptake.”

The Newark area, the state’s largest city, which is also located next to the Port of New York and New Jersey, accounted for almost twice as many applications as Camden, Carey said. No decision has been made on whether to make the program permanent; the pilot’s goal is to provide the agency with enough information to make that determination, she said.

Among the recipients of the first wave of incentive awards are Marcelli Formaggi, a Clifton importer of Italian foods, which bought one truck; and Juan Kelmy Productions, a Union City photography and video production company that bought two trucks. Bergen County also received incentives totaling $850,000 to buy 10 senior citizen shuttles.

Peerless Beverage Co., a Union, N.J., beer distributor bought two Class 5 trucks, a 2021 Hino M5 model, made by Sea Electric, another California-based electric vehicle manufacturer, said Benjamin Nussbaum, the company’s regional sales manager for New Jersey.

The NJ ZIP incentive of $170,000 for both trucks paid just over half the $165,000 cost of each vehicle, he said. The company will fit the trucks with sliding doors used for beer distribution and expects each one to do around 120 miles a day, well below the 175-mile range of the vehicle, Nussbaum said.

“They are going to be doing short-haul deliveries in the Jersey City and greater Newark area, delivering beer to bars,” he said.

Shetterly called the New Jersey program “the most comprehensive, lucrative program for users who are looking to be early adopters” of electric trucks.

“We have more inbound calls coming in from New Jersey right now than everywhere else in the country,” he said.

Stop, Start – Short Range Trips

The program is one of several that offer incentives to help the state reach its goal of reducing greenhouse gas emissions 80% below 2006 levels by 2050. Tackling transportation emissions will be critical since they constitute 42% of GHG emissions statewide. The state’s master plan, released in 2019, assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.

Truckers in New Jersey, like those around the nation, cite the lack of MHD charging sites as a key obstacle to greater use of electric trucks. Other barriers include the short range of existing electric trucks — larger trucks can do only up to around 250 miles — and the high cost of the vehicles.

Tony Fairweather, CEO and founder of Sea Electric, said the range issue is less important for the trucks the company is selling in New Jersey. Six companies will be receiving a total of 32 trucks from Sea Electric, resulting in incentives totaling just under $3.4 million.

“It’s all last-mile delivery, so the typical application is [a driver] doing somewhere between 70 and 130 miles on a daily basis — start, stop, around town; 12-hour operation. Return to a depot at night and plug into a Level 2 charger to charge back to 100% overnight, and then to do it over again.”

Shetterly said that GreenPower is focusing its marketing efforts in urban areas, such as New York City and Jersey City, where the range issue is largely irrelevant. In those areas, a truck can work eight to 10 hours a day and still only go 50 miles, he said.

“In our vehicles, that would use about a third of the battery pack,” he said. Some customers top up a vehicle through “opportunity charges,” stopping for 10 to 15 minutes to use a DC fast charger, he said.

In the long term, electric truck users could expect to see a 60% to 70% reduction in operating costs, mainly due to cheaper fuel, Shetterly said.

“Whether it’s regenerative braking, transmission services, or lack thereof, no oil changes, almost zero motor maintenance — that’s where you’re going to get that 60 to 70%,” he said. “For a small business owner, this is going to be a godsend.”