ISO-NE touted its role in New England’s clean energy transition on Tuesday as it announced the finalized results of Forward Capacity Auction 17, for the 2026-2027 procurement period.
Non-emitting generators secured nearly a quarter of the auction’s total obligations, the RTO said.
“The 7,620 MW of obligations secured by these resources represents an 11% increase over the 6,844 MW of obligations secured by non-carbon-emitting resources in the 12th Forward Capacity Auction, held in 2018,” the grid operator said in a press release.
Solar and wind generation accounted for 3.5% of all obligations in FCA 17, and battery storage accounted for another 3.5%.
In that vein, the auction may also signal that an end to the use of coal for generation in New England is near: The region’s last remaining coal-fired plant, Merrimack Station in Bow, N.H., submitted a dynamic delist bid and did not win a capacity supply obligation.
In its detailed explanation of the auction, the grid operator said that its reviews of delist bids, including three permanent ones totaling 12.5 MW and two retirements worth 7.8 MW, did “not show the need to retain for reliability any resources”; all of the bids were therefore accepted.
Among the significant delist bids were two oil units at the Middletown plant in Connecticut and the Millennium gas plant in Massachusetts.
ISO-NE also confirmed that the clearing prices it listed in its initial announcement were accurate: $2.59/kW-month in all zones and import interfaces except for the New Brunswick interface, which cleared at $2.551.
WASHINGTON — The energy transition still presents some key hurdles that need to be overcome for it to occur successfully, speakers said at Electric Power Supply Association’s (EPSA) Competitive Power Summit on Tuesday.
“We need to think broadly about how we can collaborate to ensure reliability,” EPSA President Todd Snitchler said. “We’re looking at working through a period of energy expansion, not merely passively watching an energy transition.”
Getting to 100% renewable power plus electrifying key new areas of demand such as home heating and transportation means the industry will have to build more supply than it has now as it cleans up its generation stack, he added.
“Reliability has been a top priority for as long as competitive markets have been in place, but competing interests from policymakers and regulators have drawn attention away from that first responsibility,” Snitchler said.
NERC CEO Jim Robb noted that the industry has been through a number of high-profile events in recent years that have kept his organization busy, from winter freezes to physical attacks on grid infrastructure.
“Many of the issues and challenges that we’re starting to see are really coming at us through the generation side of the business, which is a little bit different than what we dealt with when the ERO was originally stood out in the mid-2000s,” Robb said. “And those issues are particularly around fuel supply and energy production.”
The key challenge facing the grid is reliably transitioning to a more intermittent resource mix while preserving the key reliability services that traditional, synchronous power plants provide. The grid’s dependence on natural gas and the lack of coordination were “exposed in Technicolor” during the outages in Texas and its neighboring states in February 2021, Robb said.
“Managing the pace of this transition is going to be key to being able to navigate it successfully,” Robb said. “And we’ve seen, through our reliability assessments, a steady decline in the risk profile of the sector of the last five years. And that’s in spite of a very strong aggregate performance, but the risks are clearly growing.”
Extreme weather is becoming more commonplace, and that has huge impacts on demand, especially in markets that use electricity for heat.
“Once the temperature drops to a point where heat pumps can perform, and you switch to electric resistance heating, the demand goes pretty much vertical,” Robb said. “That I think is going to be one of the main headlines coming out of our inquiry into Winter Storm Elliott,” referring to the storm that led to outages in the Southeast over the holidays late last year.
The changing grid also means that weather has a greater impact on generation, as too little or too much wind can knock out power from that renewable resource, or snow and clouds can block sunlight from reaching solar panels.
NERC has recently implemented winterization standards that it started after a cold snap in 2018 and were updated after the winter storm of February 2021.
Robb said that NERC needs to step up the pace of developing new standards so it can adequately respond to the changing grid, but efforts at streamlining the standards development process hit a snag earlier this month when a set of proposed changes to the organization’s Standards Processes Manual (SPM) failed on its first ballot. He said that industry stakeholders had not been particularly constructive in that effort.
“Our goals here are to speed the process, eliminate low value-added time sinks; actually maintain stakeholder engagement, stakeholder ownership of the outcomes; and we do want to give the board the authority to set meaningful deadlines to move things along,” Robb said.
The proposed SPM changes included creating a tiered system of comment periods, under which the initial 45-day comment and balloting periods would be followed by shorter comment periods. Another significant change would have removed the requirement for a final ballot to confirm the results of the most recent successful ballot, if the standard drafting team (SDT) felt that no further “substantive changes” were needed. (See NERC Standards Process Changes Headed for Public Comment.)
The changes were approved by NERC’s Standards Committee in January, following an order issued by the Board of Trustees at its November meeting. Trustee Sue Kelly said in December that the board was trying to address concerns that NERC’s “deliberative” standards development process was not keeping up with the increasingly rapid pace of industry change. (See NERC Board Member Argues for Increased Authority.)
Industry rejected the proposed SPM changes by a significant margin, with 118 votes against and 76 in favor. Some commenters, such as the Northern California Power Agency (NCPA), said the revisions did not adequately address issues of “due process, openness and balance of interests, [which] are already problematic under current SPM rules.” NCPA also complained that “SAR [standard authorization request] drafting teams do not always appear to make an effort to resolve SAR objections” as the SPM currently requires.
Commenters also objected specifically to the proposed shortening of later ballot periods, with Andrea Jessup of the Bonneville Power Administration pointing out that “industry subject matter experts are all very busy and … need the full 45 days to allow time for” full review. Jessup said that reducing the time for comments “would likely cause less industry participation” in the process.
Referring to the idea of eliminating the final ballot, the Midwest Reliability Organization’s NERC Standards Review Forum said that “only language approved by industry should be considered by the Board of Trustees for approval,” a view echoed by multiple commenters. NCPA said it could only agree with the proposal if the SDT makes no changes to the standard that passed the final ballot, explaining that “one person’s … idea of ‘not making a substantive change’ may not always be consistent with entities that voted for the proposal prior to … change.”
LS Power Sees Much Work Ahead
LS Power Generation President Nathan Hanson argued that the industry was just getting started on the transition to cleaner energy.
“If you really step back and think how much progress we’ve really made facilitating the transition, either on the regulatory basis or even legislatively, I don’t think we’ve really made any ground, and we’re basically a year closer to having to manage the issues that are showing up at the grid in California and Texas, or PJM and New England, over the Christmas period,” Hanson said.
That changeover needs to happen in a reliable and affordable way to avoid any customer revolts, he added.
“We have legislation and regulations that are going to allow as many renewables into the space as we can. The question is … can you manage the grid when you do that?” Hanson said. “And I would argue we’re on the tip of being able to manage it effectively even right now.”
Keeping existing plants running is the cheapest way the industry can keep on balancing the grid, but that value is not coming through in many markets, leading to retirements of resources that could help maintain reliability even if they are only run rarely.
Robb also called out the RTOs, saying that they need to revisit their market rules in light of recent issues the industry has faced.
“RTOs really need to revisit their market rules and create some way through market incentives and compensation to synthetically recreate the obligation to serve that guided this industry for such a long period of time,” Robb said. “We allow too many decisions to be made based on probabilities, economic returns, the likely scenarios going forward; and those are great. And those work for 99% of the time. It’s that 1% though; if we get outside of that, we get into real trouble.”
Shell’s Comer Endorses the US Approach to Energy Transition
Shell Energy Americas President Carolyn Comer said her firm was well poised to move on the energy agenda and offered praise to the U.S.’ “carrot-heavy” policy approach to guiding the energy transition.
The main issue is getting clean sources of energy to scale up because as that work continues, demand is going to grow, with 2 billion more people expected by 2050 and demand for power expected to double globally in that same period, she said. Sometimes the arguments get too simplistic, such as pitting the transition to clean energy against affordability.
“I would argue, actually, if we don’t clean up our act and we don’t deal with climate change, or we don’t tackle the environmental stresses that we’re causing, the cost will be greater than the cost of investing in clean technologies in the first place,” Comer said.
While there is usually no line item on a power bill, customers are paying for catastrophic climate events from wildfires in the West to the deep freeze that led to days of outages in Texas in 2021, she added.
The Inflation Reduction Act will help the industry move on the transition with a number of “carrots” in the form of tax breaks and other forms of investment in clean technologies.
“I think it’s the right way to go because it protects the industrial base at the same time as we actually embark on an accelerated energy transition,” Comer said. “And so, I think it’s actually kind of leading the world from that perspective.”
Calpine has the largest geothermal fleet in the world, a collection of more than 350 wells with a nameplate capacity of about 1,590 MW, which CEO Thad Hill says the company is hoping to expand. But, in a “fireside chat” with EPSA CEO Snitchler, Hill said he does not see geothermal as a game-changer for the energy transition, as building new capacity, specifically closed-loop systems, will be expensive.
At the same time, Hill does see carbon capture as one of the new technologies that will be critical in reaching national and some state-level decarbonization goals, and Calpine hopes to lead the sector as it develops.
Turning to the summit’s key theme of reliability, Hill said, the lessons of the February 2021 winter storm in Texas — including the need for better forecasting and gas-electric coordination — have been addressed, but challenges still lie ahead.
“We’re in a very different era now. We’ve got a lot more intermittence. Our traditional definition of what was reliable [is changing],” he said. “Now we have a huge amount of other qualities of risk. We need to talk about reliability from a brand-new standpoint. We’re beginning to see that in every single organized market in the country right now.”
Compensation for reliability is already being rethought, but further changes may be needed as new intermittent renewable energy comes online, Hill said. “A system … based on how capacity got measured [is not] going to work when you’re putting in tens of thousands of megawatts of super-subsidized resources that make sense — almost regardless of the market conditions — to build economically,” he said. “So, we’ve got to think through how we’re going to compensate that.”
He pointed to PJM’s proposals for capacity accreditation as a potential solution, as well as more performance-based compensations schemes now being discussed across the industry.
“I happen to think you should get hammered if you don’t perform,” he said. “But then you should be able to bid some chance risk into the capacity price you’re going to receive in the market.”
Hill also sees the increase in corporate clean energy goals and procurement as a positive sign for independent power producers in competitive markets. Innovation on the generation side and the customer side could provide the best way to keep costs down, and he sees rate design, in particular, keeping non-bypassable charges on the low side, as a critical factor.
“I actually think you know, on this construct, we’re actually aligned more with our customers, our large customers,” he said. “The more non-bypassable charges we have, the less room there is for innovation … whether it’s behind the meter, generation [or] storage.”
The Biden administration last week launched a $2.5 billion program to fund EV charging stations across the nation, but the state of Nevada doesn’t plan to apply.
Instead, the Nevada Department of Transportation will support applications from local governments and other entities that apply for the funding.
The new funding, through the U.S. Department of Transportation’s Charging and Fueling Infrastructure (CFI) discretionary grant program, is a complement to the federal National Electric Vehicle Infrastructure (NEVI) program. (See DOT Opens New Round of IIJA Funding for EV Chargers.)
All 50 states plus Puerto Rico and D.C. submitted NEVI plans last year, which the Federal Highway Administration approved in September. The goal is to create a national network of public EV charging stations. Nevada is receiving $38 million in NEVI funds.
“At this point, Nevada is looking to spend the NEVI funds. We are not looking to apply for discretionary grants,” said Kandee Bahr Worley, NDOT’s division chief for sustainability and emerging transportation. “We’re hoping that our MPOs, [metropolitan planning organizations] our cities, our counties and other entities would be reaching out for those funds for projects that they’re putting together.”
Bahr Worley said NDOT is willing to write letters of support for funding applicants, offer grant-writing assistance “and hopefully win those grants and bring that money into Nevada.”
Bahr Worley’s comments came during a Southwest Energy Efficiency Project (SWEEP) webinar last week on funding opportunities for EV infrastructure in Nevada.
Travis Madsen, SWEEP’s transportation program director, said that Nevada is one of the top 10 states when it comes to EV market share. Last year, nearly 10% of light-duty vehicle sales in Nevada were EVs. Close to 50,000 light-duty EVs will be on Nevada’s roads by the end of the year, he projected.
“Nevada is well on its way in the journey toward transportation electrification,” Madsen said.
Interstates, U.S. Highways
With the growing number of EVs comes the need for more public charging. Efforts to build a statewide charging network in Nevada got underway with the Nevada Electric Highway program, which funded about 30 EV charging stations.
The NEVI program will build on that work, and Bahr Worley gave an overview of Nevada’s NEVI progress. In the first year of funding, NDOT will focus on the state’s six interstates: I-15, I-80, I-11, I-580, I-215 and I-515.
Two new charging stations are planned — in Carson City and in either Jean or Primm along the I-15 corridor. Three other stations, in Moapa, Carlin and Wells, will be upgraded to meet NEVI standards. The program requires at least four charging ports per station with a power output of at least 15 kW each.
The second year will focus on U.S. highways 50, 395, 95 and 93. Those highways, along with the interstates, are designated alternative fuel corridors, which are the NEVI program’s priority.
In some cases, NDOT is requesting exceptions from NEVI program requirements to space charging stations 50 miles apart and locate them no more than a mile away from the highway. Bahr Worley noted that Nevada highways run through some unpopulated areas.
“Not only do we not have population, we do not have electricity at certain areas,” she said.
And NDOT is concentrating its efforts on areas outside of NV Energy territory. The utility, whose territory covers much of the state, has its own transportation electrification plans, mandated by Senate Bill 448 of 2021.
Nevada is also talking to Tesla about its plans, announced last month, to open some of its charging stalls to non-Tesla EVs.
One listener asked whether NEVI funds would be available for charging stations along state highways, some of which are heavily traveled.
Bahr Worley said that’s a possibility, if money is leftover after the charging network along U.S. highways and interstates is built out.
CFI Flexibility
The newly launched CFI discretionary grant program is another possible funding source for charging sites on state highways.
The program has two components. In the Corridor Program, funding is reserved for EV charging infrastructure along alternative fuel corridors, such as interstates and U.S. highways.
But the Community Program provides more flexibility, with funding available for EV charging stations on any public road, at public buildings or parks, or at publicly accessible parking facilities owned or managed by a private entity.
Entities that are eligible to apply include states, local governments, MPOs, special districts or authorities with a transportation function, public and state colleges and universities, and tribal governments.
In the first round of CFI funding, $700 million will be available. The application deadline is May 30. A webinar on March 22 will cover more details.
Both the NEVI and CFI programs were established through the Infrastructure Investment and Jobs Act (IIJA). Other programs expanded under IIJA also offer funding for EV charging, infrastructure planning and workforce development.
To help sort out the various federal funding options, the Electrification Coalition has developed a tool called the EV Funding Finder.
Webinar speaker Will Drier, a policy manager with the Electrification Coalition, said the tool includes information such as matching-fund requirements and whether money from different funds can be combined or “stacked.”
The tool includes case studies on different transportation electrification scenarios, such as a city that plans to electrify its fleet.
More information on the EV Funding Finder is available here.
The U.S. must change its permitting processes to deploy the $2 trillion allocated for energy in last year’s industrial policy bills and ensure the emissions reductions needed to avoid the worst impacts of climate change, speakers said during a webinar hosted by Our Energy Policy Wednesday.
Rep. Pete Stauber (R-Minn.), whose Northeast Minnesota district is home to the nation’s biggest reserves of key clean energy industry minerals such as nickel, cobalt and platinum, said a proposal to speed up approval of mining permits has made it into House Republican bill HR 1, which is expected to move to a floor vote in the coming weeks. (See Republicans’ Opening Offer on Permitting is Missing Electric Tx.)
“We have yet to move earth at all on those resources,” Stauber said. “In fact, we have one mining proposal on year 20 of permitting and litigation. Think about that: a proposal to mine the minerals needed for clean energy is being held up for 20 years.”
Without tapping those resources and many others, renewable energy goals will not be attained, he said.
“We are dealing with an incredibly complex permitting landscape that’s influenced by an extraordinarily dynamic regulatory landscape that is — across federal, state [and] local levels — often uncoordinated,” said Karen Hanley, senior vice president at the Permitting Institute. “And when we’re talking about ‘rising tides lift all boats,’ we’re looking for good governance in the permitting process itself.”
Much of the conversation on the Hill has been dominated by the National Environmental Policy Act, which Hanley noted is just one of 65 federal laws and regulations that impact permitting, on top of many more rules from the states and local government.
“Where policy comes into play, we consider that to be a separate discussion; the process itself should not be used subjectively to pick winners and losers,” Hanley said.
The permitting process must weigh the benefits of an infrastructure project against its impact on the area where it is built, other speakers said.
“It’s all just a matter of trade-offs,” said Paul Phifer, director of permitting and development at Attentive Energy. “I mean, all permitting to me is an expression of our values. So, it’s an expression of risk management.”
Phifer’s firm is a subsidiary of French oil major TotalEnergies, which is developing an offshore wind project off the coast of New York. It would make sense for Congress to change the permitting laws to reflect some of the new tradeoffs faced by energy development now, he argued.
Setting the Tone
Much of the conversation on rule changes has focused on “categorical exclusions” that would give energy projects of preferred types or in specific areas an easy path through the process if they have limited environmental impacts, said Hanley. The Coast Guard must review some offshore projects, but it has a checklist it can apply to execute such categorical exclusions that ensure it has double checked that its oversight is not needed for specific projects, she added.
Accelerating the permitting process does not necessarily require a raft of new laws but rather Congress being clearer about how they are to be implemented, Phifer said.
“That’s the kind of thing that sets the tone that I would say that filters down … through the federal agencies even to the states, as opposed to tweaking and making minor regulatory revisions across the 65 laws that Karen mentioned,” Phifer said.
Getting any changes through Congress this year will require bipartisanship, with both chambers closely divided and controlled by different parties.
“I think there’s interest on both sides of the aisle, in particular, in long linear projects,” Hanley said. “I think there’s a recognition that where our energy needs are, isn’t necessarily the same places where the sources are, or the generation can be.”
Communities located between areas with energy resources and bigger sources of demand must often deal with projects that provide them little benefit, which brings up many complexities.
The issue of permitting has been debated for years, and Hanley expects lawmakers to insert many of their older proposals into the package. But she thinks there is opportunity to move forward on a package that addresses “fundamental process corrections” that do not eliminate necessary environmental protections.
“Obviously, all industries have their own little pet asks that they would like to see included in a package like that,” said Emily Wong, American Petroleum Institute’s director of federal relations. “But I think it’s been pretty clear from our discussion today, that we’ve all identified a lot of the same big-picture issues. And it’s certainly our hope, at API at least, that there’s enough agreement there for us to see something move across the finish line.”
December’s winter storm and early February’s cold snap challenged the New York grid, causing outages and operational flow orders, but they did not cause any emergencies, NYISO told the Operating Committee last week.
Temperatures this winter were higher than normal, with the average temperature in Central Park during January being 43.5 degrees Fahrenheit, nearly 10 degrees over the 1991-2020 average. This January ranked highest in terms of average hourly temperature (37.5 F) among all years since 2011, and there were only 11 days in the month with a peak load of more than 20,000 MW, with the average since 2011 being 26.
But the two extreme weather events caused temperatures to drop rapidly. Aaron Markham, NYISO vice president of operations, noted that on Dec. 24, it was 50 F at noon in both Albany and New York City; by 8 p.m. that night, it was 15 F. Both natural gas pipelines and gas-fired generators experienced forced outages during the December storm because of frozen production wells and compressor stations.
Still, peak load only reached 22,004 MW during the storm, partly because, Markham said, it coincided with the Christmas holidays, which happened to be over the weekend. Conditions were tighter during the February cold snap, with the peak load of the season occurring on Feb. 3 at 23,369 MW, just shy of NYISO’s forecast of 23,893 MW. Temperatures dropped to as low as ‑2.3 F on Feb. 4, averaging 16.5 and 9.5 on Feb. 3 and 4, respectively.
However, Markham noted that there was little precipitation during the February event, and gas supply interruptions and plant outages were less than during the storm.
Markham also highlighted that significant amounts of stored fuel was burned during the two events, concerning the ISO about replenishments for next winter. NYISO also heavily relied on oil-fired generation during the peak periods, with oil supplying 23% of power during the peak hour; gas supplied 24%. Gas prices in Iroquois Zone 2 reached $135.50/MMBtu on Feb. 5.
Nevertheless, NYISO was able to operate through the two events without calling on demand response resources or issuing any emergency actions, such as voltage reductions or public appeals for conservation.
Ann Arbor City Council voted unanimously Monday to begin negotiations with DTE Energy (NYSE: DTE) immediately on a new gas franchise agreement aligned with the city’s A2ZERO plan to reach carbon neutrality by 2030.
DTE’s 30-year franchise agreement, which allows the utility to use the city’s rights of way and provide gas service to its residents, expires in 2027 but can be revoked by the city before then.
The resolution authorizing the renegotiation process (R-23-101) directs city staff to “ensure that any new or amended proposed franchise is aligned, to the fullest extent possible, with the city’s A2ZERO goals and best practices regarding uses of the city’s rights of way, without compromising the ability of community members to heat or cook in their homes and businesses.”
It notes that local governments, including Chicago, Salt Lake City and San Diego, have “successfully advanced affordability, equity, and clean energy goals” in their franchise negotiations.
City Sustainability Director Missy Stults has said the city is also watching efforts in Massachusetts to replace gas service with district-level geothermal systems to provide heating and cooling.
Ann Arbor Mayor Christopher Taylor said negotiating a new agreement made sense, and is, “consistent with the wishes of Ann Arbor voters who overwhelmingly passed a proposal in November to provide more clean energy choices and reduce dangerous pollution. Using clean, renewable energy to heat our homes and businesses will improve public health, reduce dangerous pollution that causes asthma, cancer and lung diseases, and save lives.”
City officials also said they will hold public listening sessions to get feedback from city residents as officials move forward with the negotiations. No dates for those public meetings have been set.
DTE spokesman Chris Lamphear said the utility “looks forward to having productive discussions with Ann Arbor leaders as we plot a course toward a cleaner energy future, which is a goal we both share. We are pleased to see the city continuing to collect feedback from its residents and businesses on the best paths forward, and we believe we can explore a range of possibilities that ensure the Ann Arbor community continues to have the safe and affordable energy it needs for decades to come.”
Lamphear said the company is working to reduce carbon dioxide and methane emissions in natural gas by 80% by 2040. With its renewable energy sources and local participation in the company’s MiGreen program, Lamphear said DTE has helped Ann Arbor reach 30% of its overall carbon reduction goal.
Ann Arbor has taken the most aggressive actions to reach carbon neutrality in Michigan. It has considered a local ordinance prohibiting new buildings from using natural gas but not acted on the proposal.
The city finds itself in a bit of a conundrum because it also is looking to develop new housing and has given initial approval for plans for a major housing development that would use natural gas for heating, drawing opposition from some city residents opposed to continued gas use.
DTE has said it would oppose a city ban on using natural gas in new construction, and Republicans in the Michigan legislature have introduced a bill barring local governments from preventing the use of natural gas.
FERC on Tuesday approved a MISO system support resource (SSR) agreement that will keep a Wisconsin coal plant operating for reliability purposes.
Under the agreement, Manitowoc Public Utilities will continue to operate its Lakefront Unit 9 coal-fired unit, effective Feb. 1 (ER23-914).
In a separate order, the commission questioned Manitowoc’s request for $1.03 million in monthly compensation for the plant, saying it might be overcharging customers for the one-year SSR. FERC established hearing and settlement judge procedures to settle the matter (ER23-977).
MISO told the commission that it would face unresolved thermal overloading and steady-state voltage issues on 12 constraints if Lakefront 9 was permitted to suspend operations as scheduled. The 63-MW unit began operations in 2006 and serves load in Manitowoc, Wis. MISO said there weren’t any nearby resources available to redispatch, viable transmission reconfiguration options, or enough demand-side management to avoid an SSR. (See MISO Proposing 2nd SSR Agreement for Retiring Coal Unit.)
FERC found that the RTO had no “feasible alternatives that could resolve the identified reliability problems … to avoid the need for the Lakefront Unit 9 SSR agreement.” The grid operator uses the agreements to keep generators online past their retirement dates as a last-resort measure for system reliability.
Manitowoc intended to suspend the unit and convert it for renewable fuel sources. It said it plans to bring the unit back to full commercial operation by the end of January 2026 “when the alternative fuel source becomes available in sufficient quantity.”
The municipal utility said it needs more than $1 million to cover operations and maintenance labor expenses, administrative expenses, non-labor maintenance expenses, site security, insurance, carrying charges and various fees and taxes.
Wisconsin Public Service and WPPI Energy protested Manitowoc’s proposed amount, arguing the utility showed no basis for its cost projections and estimates.
WPPI said Manitowoc used “unsubstantiated forecast inputs” in its cost-of-service model, “impeding the commission and consumers from undertaking a proper evaluation of the proposed charges.”
FERC agreed. It said its preliminary analysis indicated that Manitowoc’s requested amount might be unreasonable.
The SSR designation is MISO’s second within a year. In October, it received FERC permission to instate an SSR agreement for Ameren Missouri’s 1.2-GW Rush Island coal plant. The commission also cast doubt on the reasonableness of the monthly compensation in that proceeding. (See FERC: Rush Island Plant’s Extension Essential to MISO Reliability.)
House Republicans this month are moving a package aimed at changing the country’s energy permitting processes, but it lacks changes to a key area backed by Democrats and many in the power industry: electric transmission.
House Speaker Kevin McCarthy (R-Calif.) introduced HR 1, the Lower Energy Costs Act, last week, which includes a package of reforms to the National Environmental Policy Act and is largely aimed at oil and gas production and mining.
McCarthy gave the bill the number HR 1 because it is the House GOP’s top priority this Congress, he said last week. The Committee on Rules is already taking amendments on the package and could move the bill onto the floor by next week.
“Every time we need a pipeline, road, or dam, an average of almost 5 years and millions of dollars in costs get added to the project to comply with Washington’s permitting process,” McCarthy said. “That’s too long. We can streamline permitting and still protect the environment. That’s a goal worthy of the number one.”
American Petroleum Institute President Mike Sommers last week wrote a letter to House leaders from both parties in favor of the Republican package.
“One particular focus of API and our members is enacting serious, bipartisan permitting reform,” Sommers said. “Too many projects have been scuttled because of onerous regulations and uncertainty. The delays and denials of permits, stemming from lengthy regulatory reviews and drawn-out judicial proceedings, have stifled needed investments and increased costs.”
American Clean Power said HR 1 includes “important provisions and reforms” that will speed up the deployment of clean energy in the U.S.
“Failure to enact critical permitting reforms and lift barriers that are hindering our ability to build much-needed transmission puts an estimated 150,000 clean energy jobs at risk,” ACP President Jason Grumet said in a statement. “We look forward to working with Congress to build on this important effort.”
The package is full of ideas Republicans have been debating in recent Congresses and represents what that caucus wants to see happen on energy, said former FERC chairman and Hogan Lovells Senior Adviser Neil Chatterjee. The bill is likely to pass the House with Republican support and maybe a few Democrats too.
“It’s also an opening offer to negotiation with the Senate,” Chatterjee said in an interview. “And I think, ultimately, to the extent that something gets done specifically on permitting reform, I think the Senate is going to drive that. So, we just have to see what can get the votes in the Senate and also get a majority in the House.”
Any permitting reform that passes both chambers is likely to be narrower and will require some tradeoffs between Democrats who want to focus on expanding clean energy and Republicans who favor fossil fuels. Chatterjee said that partisan split does not make sense, but recent events have only solidified it.
‘Easier Said Than Done’
The Inflation Reduction Act (IRA) included a number of provisions that Chatterjee supported as a Republican, but he was always critical of the fact that Democrats passed it without Republican support.
“My frustration was that it was done in a partisan manner,” Chatterjee said. “This is what this is, what I was concerned about, is that to the extent it became a political football, you wouldn’t get a whole lot of cooperation to make sure it’s implemented properly.”
Republicans did not include any provisions aimed at transmission in HR 1 because it would only help to implement the IRA and they have no incentive to help Democratic policy become a reality, he added.
“I think there is some willingness on the Republican side in both chambers to pursue transmission as part of a bipartisan bill,” Grid Strategies President Rob Gramlich said in an interview. “But I don’t I don’t think people are seeing HR 1 as really the bipartisan effort that includes transmission.”
Any bipartisan bill would have to include provisions that speed up the pace of transmission development significantly, and many climate hawk Democrats will have to decide whether any deals they cut lead to long-term emissions cuts, Gramlich said.
“I think there’s a lot of interest in more of a bright line authority for FERC on their permitting, something similar to Sen. [Sheldon] Whitehouse’s SITE Act, which has 1000-MW bright line,” said Gramlich.
Sen. Whitehouse (D-R.I.) in the last Congress introduced the Streamlining Interstate Transmission of Electricity Act, which would give FERC new siting authority for large, interstate lines.
FERC and DOE currently split some backstop siting authority, but that process requires NEPA reviews at both agencies and can take a long time. The arrangement has been in place since 2005 and has never been used to successfully site a transmission line.
Sen. Kevin Cramer (R-N.D.) is a former state regulator who knows the transmission issues well and will likely be key to getting Republican support for any reforms in that area, Chatterjee said. But there is still a question of whether FERC would have the appetite to use that authority.
“I’ve heard both former Democratic and Republican commissioners say this: that even if FERC had enhanced authority in this area, I think they’d be reluctant to do it,” Chatterjee said. “It’s just easier said than done to roll over the states on something this sensitive and this complicated.”
The Gulf Coast Power Association (GCPA) named former interim ERCOT CEO Brad Jones as the 2023 recipient of its Pat Wood Power Star Award in recognition of his significant contributions toward the advancement of Texas’ competitive energy markets, the organization said Tuesday.
Jones has been credited with righting the ERCOT ship after the deadly February 2021 winter storm that nearly brought the Texas grid to its knees and killed more than 200 state residents during the ensuing dayslong power outages. Coming out of retirement, he led the grid operator’s implementation of several legislative changes and leaned on a package of 60 initiatives designed to improve the Texas Interconnection’s reliability and regaining the public’s trust. (See ERCOT Board Chooses Jones as Interim CEO.)
Asked by legislative leaders to come out of retirement and lead ERCOT after the storm, Jones returned to his couch last October after 18 months. He received awards from Texas’ governor, both of the state legislature’s houses and the Public Utility Commission.
“All Texans owe Brad an enormous debt of gratitude for stepping up during a time of unprecedented challenge and urgency,” PUC Chair Peter Lake said in a statement. “His steady hand and deep experience in grid operations were critical in providing the clear leadership necessary to move ERCOT forward. … Because of Brad’s selfless and tireless efforts, the Texas grid is more reliable than it’s ever been to the benefit of Texans today and for generations to come.”
Jones is “not shy about doing tough, necessary things for improvement. … His confidence in the future of the grid and of ERCOT was contagious,” said Paul Foster, chair of ERCOT’s Board of Directors. “Brad left ERCOT in much better shape, both economically and in reliability.”
The award is named after former FERC and PUC Chair Pat Wood III, the first honoree. Winners are selected by the GCPA’s board of directors; Wood will present the award to Jones during the GCPA’s annual spring conference April 18-19 in Houston.
“I have long been a Brad Jones fanboy,” Wood said. “He is genuine. He is smart. He is decisive. His passion and optimism are matched only by his competence and leadership. His parents raised him right. What a gift he has been to Texas and to our industry.”
Jones has more than 30 years of experience in the industry. He oversaw TXU’s (now Vistra) development of the 1.8-GW Oak Grove facility and represented the company on Wall Street during a volatile time in TXU’s history.
He left TXU to become ERCOT’s COO, leaving the state only to serve as NYISO’s CEO in 2015. He abruptly returned to Texas to retire in 2018. (See Brad Jones out at NYISO.)
The office of California Gov. Gavin Newsom has proposed legislation that would establish a central procurement authority to ensure the state has sufficient electricity resources to avoid shortfalls as it struggles with extreme heat, tight supply and a changing resource mix across the West.
The proposal is contained in budget trailer bill language that follow’s Newsom’s fiscal year 2023/24 budget released in January. No lawmaker has yet signed on to carry the bill in the current legislative session.
The governor’s proposal would give the California Public Utilities Commission (CPUC) the option to name the state Department of Water Resources (DWR) or an investor-owned utility to procure energy for the state’s load-serving entities, including public utilities and community choice aggregators.
“For California to achieve its long-term greenhouse gas emission reduction goals, while maintaining a reliable electrical system and providing customers with greater choice in electricity retail providers, the state must establish a new central procurement function within the [DWR] that enables the development of a more diverse portfolio of renewable and zero-carbon energy resources,” it says.
The state has directed investor-owned utilities to procure for other LSEs in the past, but DWR has not performed that function. The governor’s legislative language would authorize it to do so if called upon by the CPUC.
The department’s State Water Project is a major producer of electricity through its hydroelectric projects and the state’s single largest consumer of electricity, which it uses to operate pumping plants that deliver water throughout the state.
Under the proposal, DWR could issue bonds and recover costs through ratepayer charges approved by the CPUC as long as the charges “[do] not unreasonably increase costs to customers … compared with the procurement of diverse clean energy resources by an electrical corporation.”
DWR would have to conduct a competitive procurement process and “prioritize investments that do not compete with the procurement of diverse clean energy resources already planned for development and disclosed by load-serving entities or local publicly owned electric utilities.”
LAO Report
In a March 10 report on the governor’s proposal, the state Legislative Analyst’s Office says that “according to the administration, the DWR procurement is intended to be for long lead‑time resources such as offshore wind, geothermal, and long duration storage. The proposed statutory changes, however, do not explicitly limit this procurement option to those types of resources.”
“DWR would utilize its new Strategic Reliability Reserve office and staff to manage the procurement,” the LAO report says.
The department administers the state’s Electricity Supply Strategic Reliability Reserve Program (ESSRRP), a $5.2 billion fund sought by Newsom in last year’s budget and enacted in June to pay for new generation and storage, to keep older natural gas plants online and to provide emergency backup generation through DWR. (See California to Pass Sweeping Energy Policy Changes.)
California has experienced blackouts and near misses the past three summers as it tries to shift its resource mix from fossil fuels to renewable power amid extreme heat, wildfires, drought and strained supply in neighboring states.
Another component of the governor’s legislative proposal is a requirement that load-serving entities pay for failing to obtain sufficient resources to meet demand by making payments to the strategic reserve fund. The move is intended to “discourage LSEs from over-relying” on the ESSRRP, the report says.
“The state would assess a payment if an LSE does not meet its reliability obligations in a month when the state had to access the ESSRRP,” it says. “Specifically, the payment would be based on a calculation that factors in the cost of the energy resource provided by the ESSRRP and the LSE’s deficiency in meeting its monthly resource adequacy or planning reserve requirements. The payments would be calculated by the CPUC and the California Energy Commission.”
The payments would be in addition to fines for resource inadequacy imposed by the CPUC.
Questions for Lawmakers
The LAO report proposes questions for lawmakers to consider when weighing the governor’s proposal, including the potential impact on ratepayers of adding DWR procurement costs to their already-high electricity bills.
It also questions the market effects of central procurement by DWR.
“The current market for energy resources is strained, with a large number of LSEs competing for a relatively small pool of projects that often will take years to develop,” it says. “How the entrance of DWR — a large, well‑resourced entity with the backing of the state — would influence the market for new energy resources is unclear.”
The report also questions whether the state needs new central procurement authority or whether current resource planning processes and the ability of IOUs to procure for other LSEs is enough.
Having DWR in charge of long-lead time resources poses risks, the report says.
“The administration has expressed concerns that LSEs might be hesitant to procure large, long‑lead time resources because of their high cost and risk as newer technologies,” it says. “The Governor’s proposal to have the state pursue procuring these resources instead essentially shifts this risk from the privately owned utilities (and their investors) to ratepayers and taxpayers. While this could help facilitate the development of these important resources, additional information is needed about the types of risks involved and their magnitude for the Legislature to determine if they are worth the potential benefits.”
Finally, the LAO asks whether the energy policy changes should be considered as part of the budget process.
“The Governor’s proposals represent significant policy changes for the state, and they do not have a particularly strong nexus with the budget,” the report says. “The Legislature will want to consider the most appropriate venue for discussing and deliberating these proposed changes. For example, the Legislature could consider these proposals through the policy process, rather than as part of the budget process.”
