RENSSELAER, N.Y. — NYISO on Friday announced that it had completed the final interconnection studies for its Class Year 2021 (CY21) group of projects.
The 27 wind, solar, energy storage and transmission expansion projects, which total 7,452 MW, had gone through multiple rounds of decision-making. (See “Class Year 2021,” NYISO Operating Committee Briefs: Dec. 15, 2022.) Assuming NYISO sticks to its timetable, Class Year 2022 will begin the week of Feb. 12. (See “Decision Process and Timeline,” NYISO Class Year 2021 Cost Allocations Advance to OC Vote.)
“These projects will help move the state closer to the ambitious clean energy mandates of the Climate Leadership and Community Protection Act,” Zach Smith, vice president at NYISO, said in a statement. “As pleased as we are with this major accomplishment, we’re already preparing to begin the next class year.”
In an accompanying white paper, NYISO has sought to accelerate the Class Year process by balancing flexibility with grid reliability because of the influx of new projects in the interconnection queue.
These efforts have included eliminating elements of the system reliability impact study, engaging stakeholders in the interconnection process more and improving the management of “material modification” requests from developers.
NYISO said it is also investing in its engineering, legal and technical teams to ensure projects move quickly through the interconnection process without sacrificing critical analysis needed to support grid reliability.
AUSTIN, Texas — Texas regulators last week continued their deliberations of proposed ERCOT market redesigns, narrowing their focus to the favored performance credit mechanism.
To the disappointment of some, however, the Public Utility Commission did not take a vote on whether to recommend the market mechanism to lawmakers as its preferred design. The Texas Legislature opened its 88th session Jan. 10 and has been openly skeptical of the PCM, as it is known, and wants to see new dispatchable generation (i.e., thermal) added to the system. (See ERCOT Survives One Test, Faces Another.)
Michele Richmond, who leads a trade association representing ERCOT generators and wholesale marketers that supports the PCM, said she found the long day’s discussion to be “very good,” but still wanting.
“A decision is what gets movement on new investment. A recommendation to the legislature is not a decision. It’s a recommendation,” she told RTO Insider following the Jan. 12 meeting. “The commission should adopt a decision on [the market design]. And then, if the legislature wants to weigh in, if they want a new direction, then that’s what should happen.”
Following the 2021 deadly winter storm, lawmakers directed the PUC to establish a reliability standard to ensure operations during extreme heat and cold weather and when output is reduced from weather-dependent wind turbines and solar panels. The commission has promised to send its preferred market design to the legislature for its feedback, as PUC Chair Peter Lake reminded his fellow commissioners and those listening.
“If implemented. We still have to hear from the legislature,” Lake said of one suggested market change. “Subject to consideration by the legislature,” he said of another.
“Today’s discussion was a deliberation, not making a decision on anything or recommending anything,” Lake said in concluding the day’s discussion.
The commissioners agreed to return to their open meeting room Thursday to continue their deliberations, with the goal of selecting a “policy direction” to fulfill their statutory obligation and ensure “reliability during periods of low non-dispatchable power.” They will return on Jan. 26 to issue a final order.
That would be just fine with Richmond. Her Texas Competitive Power Advocates (TCPA) organization has said its members are committed to adding 4.5 GW of additional thermal generation to the ERCOT system if the PCM is adopted under the “right framework.”
TCPA members have banded together to create a website that points out it takes time and regulatory certainty to build new power plants. It includes a countdown clock that indicates a new power plant could come online as soon as April 25, 2025, assuming the PUC reaches a policy decision Thursday.
“I heard some pretty good consensus that something needs to be done,” Richmond said. “I think the point that was made is that [the PCM] does get new investment.”
The PCM, one of six alternatives studied by a San Francisco consulting firm, rewards generators for performance credits based on their performance during a determined number of scarcity hours. Those credits must be bought by load-serving entities based on their load during those same hours or exchanged by LSEs and generators in a voluntary forward market to hedge against negative outcomes in the retroactive settlement process. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
Katie Coleman, who represents Texas Industrial Energy Consumers, said the PCM is nothing more than a capacity market, anathema to many ERCOT stakeholders. Commissioner Will McAdams appeared to wince as one speaker mentioned “capacity market” in his testimony.
“It’s got all the problems a capacity market usually has,” Coleman said of the PCM while preparing to return from a weekend getaway. “It’s purely an administrative way for the government to order certain dollars to generators. The only difference with the PCM is that it’s backward looking.
“It diverts dollars to generators. It’s going to cost consumers billions of dollars,” Coleman added. She said that given most reliability events are caused by operational issues such as unpredictable weather or outages, the PCM won’t materially improve reliability.
The consultant’s own report to the PUC argues the PCM would result in an extra $460 million in annual system expenses by 2026, about a 2% increase over projected system costs. The firm, Energy and Environmental Economics (E3), did not recommend the mechanism, saying it was too complex. Instead, it put forth a forward reliability market as a “more suitable fit.”
E3’s Zach Ming, defending the firm’s report, said that under the PCM, generators receive credits “by being available, not by being dispatched.”
Stoic Energy’s Doug Lewin, a dedicated follower of all things ERCOT, said the PCM’s biggest problem is that it is “convoluted and extremely complicated.”
“That makes it hard to finance,” he tweeted. “Few investors, if any, will put money into long-term assets based on this. But existing generators will get a windfall.”
State Sen. Charles Schwertner (R), who chairs the powerful Business and Commerce Committee, reiterated his committee’s “serious concerns” with the PCM in a Jan. 11 letter to the PUC.
“Given … the clear absence of consensus among energy experts, advocates, and industry, unilaterally moving forward with a market design change such as the [PCM] option without consultation and collaboration with both the Texas House and Texas Senate is imprudent,” he wrote.
The PCM does have its supporters in Texas Gov. Greg Abbott and ERCOT CEO Pablo Vegas. Abbott, who has appointed all five commissioners in the last two years, said in his own filing that the mechanism “must be given strong consideration.”
“The fact that generators have already publicly committed to build thousands of new megawatts of dispatchable generation resources if the PCM is adopted and implemented by the PUC further supports this point,” he wrote.
Vegas said the mechanism “seems to offer the best combination of incentives that move our grid from a system characterized by extreme pricing, physical scarcity and conservation notices” by incenting generators to be available.
He said it will take staff as much as three and a half years to develop the PCM market system.
So, what will happen in the meantime? Vegas and the commission agree a bridge is needed for ERCOT to get by until the PCM is implemented. For the time being, that will consist of additional ancillary services and continued use of reliability unit commitments. RUCs have been in place since the summer of 2021 and raised concerns over the stress imposed on older generators.
The PUC raised the use of reliability must-run resource deployments, which haven’t been issued since 2017. ERCOT ended NRG Energy’s Greens Bayou Unit 5 RMR contract in 2017; the unit was retired shortly thereafter. (See “NRG to Retire 806 MW of Mothballed Resources,” ERCOT Briefs: Week Ending Dec. 11, 2017.)
“I would strongly encourage this commission to avoid any type of policy path that relies on RMR in any way,” NRG’s Bill Barnes said. “An RMR contract means that you’re putting new dollars into one of the oldest, most inefficient resources on our grid. It is literally one of the worst uses of capital.”
“It concerns me that the only options we have are continued RUC and RMR,” Commissioner Lori Cobos said.
Richmond said a phased-in PCM could be installed quicker than other proposed bridge mechanisms, pointing to TCPA’s comments. She said that would signal the market when to self-commit, reducing the need for RUCs and “would provide economic incentives for existing dispatchable resources to remain in service.”
“It has a number of components that exist in the market and are familiar to everybody, so it should be fairly easy to phase that in,” she said.
ERCOT: December Storm ‘Non-event’
ERCOT’s Dan Woodfin, vice president of system operations, called the December winter storm a “non-event,” despite the repeat of thermal outages and gas supply problems that were reminiscent of the 2021 winter storm.
He told the PUC that nearly 6 GW of coal and gas energy came offline after the cold weather swept through the state. Woodfin said global weather models predicted a significant cold weather event for Dec. 22, but the cold was “deeper and quicker” than the forecasts. ERCOT is reaching out to other grid operators who suffered similar under forecasts, he said.
Staff is also contacting generators that went offline to learn what happened. Woodfin said the weatherization requirements now in effect were effective in maintaining supply.
“We can see the grid we have now. The generators we have now are reliable. We just need more of them,” Woodfin told the commission, promising a full report in several weeks.
The PUC also approved its biennial report to the Texas legislature. The report highlights the previous two years since the commission was reorganized after the 2021 winter storm, going from three members to five, and documents in actions in regulating the state’s electric, telecommunications and water industries.
The PJM Planning Committee on Jan. 10 endorsed a proposed solution for capacity accreditation of intermittent resources under the effective load-carrying capability process.
Out of the five proposals before the committee, PJM’s Package I received 82.4% of stakeholders’ support. The proposal’s central feature is a transitional mechanism to allow resources seeking higher capacity interconnection rights (CIRs) to temporarily receive a higher capacity rating. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)
Only Package I cleared the 50% support threshold to advance to the Markets and Reliability Committee. PJM’s Package D received the next highest degree of support, with 34.9%. LS Power’s Packages K and E received 29.3% and 24.1% support, respectively, while Package G from E-Cubed Policy Associates was endorsed by only 7.1%.
How to define existing resources’ capacity rating until a permanent solution can be implemented remained the main sticking point throughout the PC’s discussions of the issue. Most of the proposals, including Package I, would require resources seeking a higher accreditation to re-enter PJM’s interconnection process at the end of the queue, which has been mired in a backlog spanning years.
Package I would also allow resources to utilize existing headroom on the transmission system through a transitional system capability study, though it would also cap the actual accreditation at the facility’s existing CIR. That headroom would be available so long as it is not claimed by another resource’s CIRs and until PJM has completed the process of transitioning to its new methodology of studying interconnection requests.
To be eligible to participate in a transitional study, the additional capacity must be deliverable without any physical modifications made to the generation resource, and an uprate request must be submitted to PJM.
During a special MRC meeting to “page turn” the proposal Friday, PJM’s Jonathan Kern said the RTO’s goal is to open a 30-day window for submitting uprate requests that would close on March 3.
Stakeholders noted that if the proposal was to be approved by the MRC and the timeline implemented, the window would be opening prior to FERC approval of the changes. Kern said the timing is envisioned to allow PJM to jump on implementation following a prospective commission approval and have everything ready to be included in the 2025/26 Base Residual Auction (BRA) scheduled in June.
“One of the primary goals here is to accomplish all of this in time for the 2025/26 BRA,” he said, noting that the target was part of the package approved by the PC. “We’re committed to making this happen, and this 30-day window is essential, PJM believes, to make this goal.”
The second-highest vote getter, Package D, was the only proposal that would have granted higher CIRs outside of the interconnection process. New deliverability tests would been conducted and been the basis for granting the higher CIRs for existing wind and solar resources starting with the 2023 Regional Transmission Expansion Plan. It was also the only proposal that would have allocated the cost of any transmission upgrades necessary to accommodate the higher capacity ratings to load rather than the generators.
LS Power’s Package K was built off PJM’s prevailing proposal but included a request that the RTO’s Board of Managers direct staff to submit a filing with FERC clarifying that the Reliability Assurance Agreement establishes CIRs as the hourly upper limit for unforced capacity accreditation starting with the 2025/26 BRA.
The company’s other proposal would have immediately limited accreditation to a generator’s CIR level and required those seeking higher accreditation to re-enter the interconnection process at the end of the queue.
While Package E received the highest share of support in an October poll at the PC, PJM overhauled its Package I to include the transition studies and later expanded eligibility to all resources; originally only intermittent generation would have been permitted to utilize the existing headroom.
Package G would have also required resources to re-enter the transmission queue to receive higher accreditation, while also expanding deliverability testing into the shoulder months to capture increasing reliability concerns being seen in those seasons.
Stakeholders Endorse Changes to Generator Deliverability Test
VALLEY FORGE, Pa. — The Planning Committee endorsed by acclamation a PJM proposed slate of modifications to the generator deliverability tests to reflect the higher variability in dispatch as renewable resources continue to be added to the grid.
“We feel this set of changes is necessary to move in the right direction. It needs to be included in the planning process sooner rather than later,” said PJM’s Jonathan Kern.
The changes include merging the summer, winter and light load testing methods, redefining the light load period to reflect solar and wind output, and harmonizing the dispatch procedures. The proposal is intended to take a procedure that is fairly prescriptive and make it more reflective of the reality of what is being seen on the grid.
“We feel that this approach is going to provide a more realistic and conservative stress level than the existing procedure,” Kern said.
PJM will also be providing a software program that will allow for PJM’s results to be replicated by market participants. Kern said that is expected to roll out in the spring and should prevent the changes from causing additional work for transmission owners.
The proposal is set to go before the Markets and Reliability Committee on Jan. 25 for endorsement. If approved at that meeting, it could be implemented as part of the 2023 Regional Transmission Expansion Plan (RTEP).
Load Forecast for Northern Virginia Data Centers Continues to Climb
During the Jan. 10 Transmission Expansion Advisory Committee meeting, Sami Abdulsalam, senior manager of transmission planning, said the region set a summer 2022 peak of 21,156 MW, exceeding the forecasted 20,424 MW. The 2023 load forecast is showing a significantly sharper trend through 2040 than the past two annual forecasts. It’s anticipated that Dominion will see 4.2% to 5% annual load growth for the next 10 to 15 years and could nearly double by 2040. While PJM is still able to maintain voltages in the area, Abdulsalam said it’s becoming increasingly difficult to schedule outages.
The data center growth extends to the north into FirstEnergy’s APS zone, which is expected to see its load grow from an 8,412-MW peak last year to 9,568 MW in the 2028 RTEP, based on the 2023 forecast.
Though the latest forecast goes out to 2040, Abdulsalam said the RTO is only making recommendations on work needed to meet the load growth expected through 2028, which PJM feels is a proper balance between the lead time needed for projects and the risk in forecasting.
Director of System Planning Dave Souder said the Load Analysis Subcommittee worked with data center developers and operators to develop the forecast, including by visiting the region where the development is occurring.
“We have had the ability to actually go down to the Dulles Airport area, and the amount of construction is amazing,” he said.
PJM Reviews Baseline Reliability Projects
PJM reviewed three proposed packages of baseline reliability projects to address violations found in the first window, second cluster of the 2022 RTEP: 26 thermal and 25 voltage flowgate violations in the APS, BGE, MetEd and PECO areas.
Abdulsalam told the TEAC Tuesday that the preferred Option 1 solution has a $154.29 million price tag, less than half the cost of the other two proposals.
Option 1 resolves all violations by making upgrades to existing facilities, whereas both alternatives include the construction of new infrastructure or major rebuilding of existing facilities. The most significant portions of Option 1 are the reconductoring of 27.3 miles of the Messick Road–Morgan 138-kV line and replacing equipment at the two substations at a $49.23 million cost.
Option 2 includes the rebuilding of the Hunterstown–Carroll 115/138-kV corridor as a double circuit 230-kV line and equipment at each substation to handle the higher voltage. At a $148.83 million cost, the work to that line would constitute nearly half of the proposal’s $332.85 million cost
With the highest cost, Option 3 includes constructing a new 500/230-kV station named Rice, tapping the existing Conemaugh–Hunterstown 500-kV line and building 29 miles of new double circuit 230-kV lines from the Ringgold substation to the new Rice substation. A second new 500/230-kV substation designated Furnace Run would be built off the Peach Bottom-TMI 500-kV line. Altogether the package would cost $389.78 million.
VALLEY FORGE, Pa. — While fuel inventories fell during the cold snap accompanying last month’s winter storm, PJM’s Brian Fitzpatrick told the Operating Committee on Thursday that they are on track to recover.
Coal inventories remain within PJM’s forecast, albeit at the lower end, after falling below the five-year range for much of 2022. Appalachian coal production rates are down nearly 30% relative to the last two weeks of December, though Fitzpatrick noted that end-of-the-year drop-offs are not uncommon.
Natural gas production has recovered from a freeze-off during the storm, though inventories remain within the five-year range at 2.7% below the average. Pipeline issues contributed to nearly one-third of the natural gas generation in PJM’s fleet being unavailable during the storm. With those units offline, oil inventories took a significant hit: Stocks of distillate fuel oil have been far below the five-year range since 2022, and an uptick toward recovery was halted during the storm.
PJM Seeks to Close DLR Task Force
Stakeholders indicated support for a proposal to sunset the Dynamic Line Ratings Task Force given the conclusion of much of the group’s work.
PJM’s Natalie Tacka Furtaw presented two paths forward for the task force: putting it on hiatus and reconvening when needed, or sunsetting the group and issuing a new problem statement and issue charge should future issues arise.
The task force served an educational role for stakeholders, providing information on current rules from PJM and experience from transmission owners and technology vendors. (See “Dynamic Line Ratings,” PJM MRC/MC Briefs: April 27, 2022.)
No new requests for information had been received by PJM since the task force’s December meeting, leading to this month’s meeting being canceled. Furtaw said Thursday’s presentation is being considered a first read, and she will be returning to the OC next month for endorsement of sunsetting the task force.
WASHINGTON — The National Blueprint for Transportation Decarbonization lays out a bold vision for ensuring that by 2030, 50% of all new passenger cars and pickup trucks hitting U.S. roads will be zero-emission vehicles.
But, getting there won’t be easy, said Transportation Secretary Pete Buttigieg and Energy Secretary Jennifer Granholm, tag-teaming their way through the challenges ahead for a packed hall of transportation professionals at the annual meeting of the Transportation Research Board (TRB) on Wednesday.
“We know that what we’re seeking to do here is of such proportions that it is testing the productive capacity of the U.S. economy,” Buttigieg said, citing the key issue of building out an electric vehicle workforce. “We are going to need so much, not just in terms of steel and concrete, but in terms of every form of talent from engineering to brick laying.
“And what that means,” he said, “is we have to call everybody into this. … So, from a perspective of equity and justice, but also just from a perspective of getting this done, we cannot afford to leave any talent on the table.”
Another big barrier — cost — is being attacked on multiple fronts, Granholm said, from the EV rebates for new and used cars in the Inflation Reduction Act, to federal research initiatives aimed at driving down the price of batteries.
An EV supply chain is emerging in the U.S., Granholm said, drawn by the combined effects of IRA incentives and other initiatives from the Department of Energy and the White House. More than 70 companies in the battery supply chain have announced plans for new U.S. operations, she said.
“I’m talking about manufacturing the batteries or manufacturing a piece of the supply chain — the anode, the cathode, the separator material, the electrolyte or the critical mineral processing,” Granholm said. “All of these companies [are] coming to the United States, whereas before we were relying on economic competitors in Asia, China.
“So, policy really does make a difference,” she said. “It makes a difference for the climate. It makes a difference for communities on the ground.”
The National Blueprint calls for a range of policies that look beyond vehicle electrification to transforming the way people and materials move within communities, across the country and around the world. A collaborative effort between DOE, the Department of Transportation, the Environmental Protection Agency and the Department of Housing and Urban Development, the Blueprint looks at issues like community design and land use policies that could cut the need for vehicle travel by placing businesses and services near where people live. (See Biden Admin Releases Blueprint for Transportation Decarbonization.)
Increasing convenience, efficiency and clean options for transportation are the plan’s overarching goals. But, while decarbonization is already underway, “the trend needs to accelerate dramatically both in scale and scope. It is essential to make meaningful reductions in emissions this decade to reach near-term emissions reductions goals and enable a pathway to reach net-zero emissions economywide by 2050,” the report says.
The enormity of the transition ahead “will continue to require solutions that leverage market forces and private sector investments, which government policies and investments should jumpstart and guide,” the report says.
Transportation now accounts for 33% of U.S. greenhouse gas emissions, with about half of that amount coming from light-duty vehicles, such as passenger cars and pickup trucks, according to the U.S. Energy Information Administration.
Echoing Granholm, Buttigieg said the role of policy in cutting those emissions is to fill the gaps where “some things don’t happen on their own.” Transforming mobility in the U.S. raises questions that will require making sure “the answer turns out to be ‘yes,’” he said.
“One, will it happen fast enough to help us meet our climate imperatives? Two, will it happen in a ‘Made in America’ fashion, because just because the EV revolution is coming doesn’t mean it will be a ‘Made in America’ manufacturing revolution.” Buttigieg said. “And then, three, will this develop on equitable terms, especially knowing that many of those who might stand to benefit the most from the savings that could come with EV ownership are also those who might face the steepest barrier in terms of that upfront cost.”
The stereotypical EV owner today may be a well-off, latté-sipping urbanite, Buttigieg said, “but if you think about it, in rural areas, you have longer distances [to drive], which means better potential gas savings, and you have more people living in single-family homes, which means the opportunity to charge [EVs] at home. So, we really need to continue to have a strategy that fits all of these different geographies, meets them where they are and makes the possibilities clear.”
Integrating EV batteries and charging infrastructure into the grid is yet another challenge, with both utilities and technology developers exploring potential opportunities, Granholm said. She pointed to a new Virtual Power Plant Initiative, launched by General Motors, Google Nest and Rocky Mountain Institute, which aims to aggregate energy from thousands of EVs or other distributed energy sources to quickly respond to supply fluctuations on the grid.
At the same time, Granholm said, the improvements in grid resilience that virtual power plants can provide will need to be balanced by major increases in clean energy — as much as 2,000 GW of wind and solar, according to a 2021 study from the National Renewable Energy Laboratory.
“We have to increase the capacity on both fronts, using the vehicles to be able to make the grid more resilient, as well as adding renewable energy capacity on the grid because you don’t want to charge your electric vehicle and then have that energy come from a carbon pollution-producing source,” she said.
Race to the Bottom
The cabinet officials’ appearance at the TRB meeting was the second phase of the National Blueprint rollout at the event, following a broad round table discussion with administration officials, industry executives and other key stakeholders on Tuesday. TRB is a research-oriented spin-off of the National Academies of Sciences, Engineering and Medicine.
While the reception of the Blueprint was generally positive, industry representatives saw both near- and long-term obstacles to be overcome and gaps to be filled, as both technologies and markets shift.
Electric vehicles will provide the majority of near-term emissions cuts, the report says, and the auto industry is approaching decarbonization as both an environmental and economic imperative, said John Bozzella, CEO of the Alliance for Automotive Innovation.
Electrification is a “big opportunity for our economic competitiveness [and] our ability to compete with economies around the world,” Bozzella said. He predicted that by the end of the decade, the auto industry will pour more than a trillion dollars into electrification.
But, he said, even though “[electric] vehicle sales have doubled year over year, it’s 7% of new vehicle sales. To get to 50% by the end of the decade, it’s going to require not only an all-of-government approach at the agencies here today. … We also need to pair that with an all-of-the-economy collaborative approach.”
Volvo Group North America is focused on decarbonizing heavy-duty trucking, said Jonathan Miller, the company’s senior vice president for public affairs. In addition to battery electric Class 8 semis — used at ports and for local and regional trips — Volvo has fully electric garbage trucks on the road in New York and other cities, Miller said.
“The battery chemistry is getting better,” he said, but “we need a lot bigger batteries … much, much bigger, and our customers are very concerned about their ability to haul freight, and that’s where we look at hydrogen as an option as well, especially as we get into long-haul trucking.”
Volvo has partnered with Daimler — “our biggest global competitor,” Miller said — in a joint venture, cellcentric, that is developing hydrogen fuel cells for the two companies.
The development of low- or no-carbon fuels for maritime transportation and aviation will be longer-term needs, but also requires immediate support and collaboration with industry partners. The innovations still to be developed for maritime shipping may be particularly hard to scale, the Blueprint says, because of uncertainty about safety and operational standards for new technologies and the 30-year lifespans of most international shipping fleets.
On the aviation side, Lauren Riley, chief sustainability officer for United Airlines, said the industry is only responsible for about 3% of global GHG emissions, but doesn’t have “the solutions at scale, commercially available to deploy today to actually make a difference in our emissions.”
What’s keeping Riley up at night these days is aviation’s “dependencies,” she said. Developing sustainable aviation fuel, whether biofuels or renewable diesel, will “depend on access to abundant, cost-effective renewable power, and that’s going to take time, and that’s something that’s a bit out of our control,” Riley said.
The challenge ahead will be primarily a matter of speed, she said. “How do we go faster? We have solutions. We understand the technology. We just don’t have the scale. … We’re in a race to the bottom not just with conventional jet fuel but with renewable diesel.”
FTR Bid Limit Increase Endorsed Under Fast Track Pathway
The PJM Market Implementation Committee on Wednesday endorsed a proposal to increase the maximum number of bids a single corporate entity can place in the RTO’s financial transmission rights auctions from 15,000 to 20,000.
PJM is seeking to make the change under its “quick fix approach” — which allows a proposed solution to be endorsed concurrently with its issue charge and problem statement — with the aim of having the change in place for the April 2023 auction. (See “PJM Considering Increasing FTR Bid Limit of 15,000 per Entity,” PJM MIC Briefs: Dec. 7, 2022.)
The increase is being considered based on requests from market participants and following the transition to weekend on-peak and daily off-peak class types, which effectively required traders to submit two bids to acquire or sell the same number of hours of an FTR as prior to the transition, according to the problem statement.
“We did feel this is sufficient for the type and volume of bids that we are seeing today,” PJM’s Emmy Messina said.
The proposal is set to go before the Markets and Reliability Committee on Jan. 25 for a first read, with a vote on endorsement slated for Feb. 23.
Stakeholders Disagree on Approach to Combined Cycle Modeling
Stakeholders deferred action on an issue charge and problem statement addressing the performance impact of expanding multi-schedule modeling to combined cycle generators in the market clearing engine (MCE).
Committee members were divided over what should be considered in the scope of the proposal, as well as whether the effort should continue before PJM releases a white paper it’s currently drafting outlining the bounds of a technically feasible solution.
PJM has an ongoing MCE software contract with General Electric, which is currently in the process of overhauling the programs it provides based on feedback and goals from the RTO, including the effort to expand multi-schedule modeling to combined cycle units. Currently those generators must mimic their operating characteristics in their offers.
Most of the division centered on PJM expanding the out-of-scope topics in its issue charge to include offer structures in its day-ahead and real-time energy markets and to the three-pivotal-supplier test. Those changes were sought by some stakeholders at the MIC’s December meeting and supported by PJM staff seeking to keep the discussion on a tighter time frame. (See “Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling,” PJM MIC Briefs: Dec. 7, 2022.)
PJM’s Rebecca Carroll said GE is seeking guidance on how to proceed with making changes to the MCE by the third quarter of 2023. If stakeholders have not endorsed a system for multi-schedule modeling of combined cycle units by that point, GE will not proceed, she said. Under the current Next Generation Markets framework, the number of permutations that would have to be modeled for combined cycle units would not be solvable.
Paul Sotkiewicz, president of E-Cubed Policy Associates, who pushed for many of the changes PJM had made to its issue charge, said he would also like to see education from other system operators who have attempted multi-schedule approaches for combined cycle units and abandoned the effort because of the amount of time it would take.
David “Scarp” Scarpignato noted that this has been an issue discussed since PJM created a task force on generator modeling nearly a decade ago. Many of the questions raised in recent meetings have been answered in the materials created there, he said.
The Independent Market Monitor also presented its own proposed issue charge with a scope defined as pertaining to the process where software automatically chooses parameters where resources have local market power or during emergency and hot/cold weather alerts.
Ask 10 experts whether RTO markets and electricity deregulation lead to lower prices and you are liable to get 10 different answers.
Debates around the benefits of restructuring have been going on since the states started unbundling monopoly utilities a quarter century ago. A new skirmish arose on #energytwitter earlier this month in response to a New York Timesarticle provocatively headlined “Why Are Energy Prices So High? Some Experts Blame Deregulation.”
Citing an analysis of Energy Information Administration data by energy researcher Robert McCullough, the article says “California and the 34 other states that have deregulated all or parts of their electricity system tend to have higher rates than the rest of the country.” (See sidebar, A ‘Deregulation’ Debate by the Numbers.)
Rorschach Test
RTO Insider reached out to a range of sources to get their thoughts on whether deregulation and organized wholesale markets have benefited customers.
Competition “is a Rorschach test,” energy consultant Alison Silverstein told RTO Insider. “And you can manipulate numbers, particularly electric rates, to say anything you want to.”
Silverstein’s old boss Pat Wood — who took over as chairman of FERC during the California Energy Crisis and chaired the Texas Public Utility Commission when that state started its journey to a fully deregulated, or restructured, wholesale and retail power market — is firmly in the pro-market camp.
“Competition on its worst day is better than I ever could be as a regulator on my best day,” said Wood, who is now CEO of energy storage developer Hunt Energy Network.
Rate regulation is intended to ensure utilities with monopoly territories earn enough to attract investment while keeping prices affordable. No matter how talented regulators are, Wood said, “there’s no way you can really substitute for the efficiencies and discipline of a market on pricing for customers.”
RTOs were created to lower costs to end-use consumers but have failed to do so, said Public Citizen’s Energy Program Director Tyson Slocum. The states that did restructure started with higher prices to begin with for a variety of reasons.
“But those prices remain just as high or higher today than they did 20 years ago, compared to other states,” Slocum said. “So, what’s clear is that RTOs are failing to deliver the promise of lower prices and that should be of great concern to FERC. If the entire purposes for doing something isn’t happening, then you should probably investigate as to why.”
Severin Borenstein, U.C. Berkeley | U.C. Berkeley
Plenty of others are somewhere in the middle with Severin Borenstein, a professor at the University of California Berkeley’s Haas School of Business and a member of CAISO’s board, whose work has found that it depends on other factors entirely.
“The reality is that if you procure power through a deregulated wholesale market, the marginal supply sets the price,” Borenstein said in an interview. “Now, if gas prices are really low, you end up getting much better prices in a [competitive] wholesale market than you do in a regulated market.”
Natural gas is the most common marginal fuel in ISO/RTO markets around the country, which means that generators burning it most often set the locational marginal price (LMP) for other generators. If gas prices are high, then the vertically integrated states have cheaper prices because their generation is not paid a single price, Borenstein said.
The issue of whether RTOs lead to consumer savings was a hot topic before the shale revolution, when gas prices were trading at $7-8/MMBtu some 15 years ago.
“PJM was in absolute crisis,” said Public Citizen’s Slocum. “There was serious consideration of whether or not it had all failed because gas, which was setting the marginal cost, was punishingly high.”
The RTO model got “bailed out” by cheap natural gas from fracking, said Slocum. But now the markets are under strain again as gas prices were higher last year on average than any year since 2008, according to EIA.
Slocum and others also argue that the markets are under strain as renewables are growing, but many who spoke with RTO Insider argued that RTOs and their abilities to efficiently dispatch generation across a wide footprint are going to be key to making that transition happen affordably and reliably.
Economies of Scale
“I think ISOs have led to huge reductions in cost,” FTI Consulting’s Scott Harvey said in an interview. “Particularly in MISO, SPP and the Western EIM, where there was no power pool before. Having the coordinated dispatch of the ISO allows the region to use all of the transfer capability of the transmission system.”
Under the old rules, the available transfer capability used was a fraction of the total available — not because the people running the old utility balancing authorities were trying to keep the resource themselves, but because they had very limited views of where power was flowing, Harvey said. They had to make worst case assumptions because once the power started flowing, they had very limited abilities to change it even if they need to for reliability.
ISO-NE, NYISO and parts of PJM were already in tight power pools before their ISOs developed, but Harvey said PJM’s expansion has led to major improvements.
“If you think back to the polar vortex of 2014, PJM actually got through it without any load shedding,” Harvey said. “I doubt they could have if it was the old world with a bunch of fractionated utilities in the Midwest and Ohio.”
The benefits of stitched together balancing authorities came up again in the recent cold snap over the Christmas holiday when PJM was again stressed but did not shed load while individual utilities in the Southeast did, Harvey said. (See PJM Gas Generator Failures Eyed in Elliott Storm Review.)
Former FERC commissioner and North Dakota regulator Tony Clark, who is now a senior adviser at Wilkinson Barker Knauer, agreed that a clear benefit of RTOs is that they drive scale, which is hugely important in the electric industry.
Time for a Change in the Pricing Model?
The other common feature that is often credited with driving savings is security constrained economic dispatch, but Clark has doubts about the benefits of the ISO/RTO pricing model.
“LMP pricing was designed around a system where most resources had very similar attributes,” Clark said. “They weren’t exact, but more resources were basically dispatchable, they were basically on demand. They might have longer, or shorter lead times, ramp times, things like that. But they tended to be dispatchable, and they tended to have a fuel cost, which is to say they have marginal costs.”
Weather-dependent renewables are not dispatchable, and they have free fuel so they have no marginal costs. But under the current structure they get paid whatever the most expensive plant needed is paid, which tends to be a natural gas unit.
“Under that scenario, do consumers still benefit?” Clark said. “Or would they benefit from some sort of average cost pricing? It’s a really interesting question.”
The idea of average pricing in wholesale power markets, and any other commodity market, is based on a misunderstanding of how bidding works, said U.C. Berkeley’s Borenstein.
“They wouldn’t bid lower if they knew they were going to be paid their bid,” he said. “They’d try to bid whatever the market clearing price is. The idea that everybody gets paid a uniform price is how commodity markets work, not just for electricity — for natural gas, for gold, for oats, for everything. There’s a market price, and people will get paid that market price because they’re selling a homogeneous good.”
ISO/RTOs Share Some Things in Common, But Have Many Differences
While RTOs have some common characteristics, they also have marked differences. ERCOT also helps administer a fully deregulated wholesale power market, while ISO-NE, NYISO and PJM are dominated by states that have also opened their retail markets, though none have gone as far as Texas.
MISO and SPP are largely dominated by traditionally regulated utilities, while CAISO is somewhere in between with community choice aggregation and capped retail competition for large commercial, industrial and institutional customers.
Beyond those regulatory issues, the markets have very different resources, and that can muddle the studies claiming to find savings or increased costs from ISO/RTOs, said NRG Energy Vice President of Regulatory Affairs Travis Kavulla.
“It wouldn’t matter whether New England was open to competition, or economically regulated at the moment; the fact of the matter is under either of those models it would be substantially exposed to the wholesale gas market,” Kavulla said. “New England happens to be a place where policymakers have decided not to build a lot of gas pipelines to domestic sources of gas, and so they have effectively exposed themselves to the European gas market, the global natural gas LNG market.”
Studies will take those effects and impute them to competition, when it really has more to do with the policies of the New England states, Kavulla said. California is another odd duck to squeeze into studies, he said.
“I don’t think any reasonable person would look at the amount of regulation and the amount of government policy related to the energy sector in California and conclude that it’s quote, unquote deregulated,” he added.
Retail Deregulation
Experts who spoke with RTO Insider were split on the benefits of full “deregulation” — where states have also opened their retail power markets.
Wood, who helped design the ERCOT market, still supports retail competition. The wide-open retail market in most of ERCOT is able to flow through the savings from wholesale competition to end-use customers. But in other states where utilities are still providing default retail service to customers it can be more of a muddle.
“I’ve definitely been on the record for 20 years or so about making sure these default providers don’t suffocate retail competition,” Wood said. “So, you either stick with wholesale competition only and you have a very clear way of passing those benefits of low-cost generation, or lower cost generation, being passed through … or you have robust retail competition, like we have here, where retailers compete with the other ones to get your business, and so, they have to pass through those [lower] costs through.”
In between those two worlds, some middleman is likely to keep a share of any of the purported benefits of competition, he added.
The Natural Resources Defense Council’s Ralph Cavanagh was against the idea of retail competition when California was considering deregulating in the late 90s, and he recalls a debate with an executive at Enron on the issue.
“I asked the question publicly: What is in this for my mother?” Cavanagh told us. “To which his response was, ‘for the first time in history, your mother is going to be able to hedge her fuel price risks in the marketplace.’ Mercifully, people laughed at that.”
Cavanagh said small customers generally do not want to spend the time to learn about fuel price risks, though large commercial, industrial and institutional customers can benefit from such options.
“It is worth recalling that even large, sophisticated customers got swamped by the collapse of the California retail markets in 2000 and 2001,” he added.
Coordination Can Help Green the Grid
But when it comes to wholesale competition, Wood and Cavanagh are on the same page. The elimination of utility monopolies over generation has been going on since the 1970s, and no one is seriously considering reversing that, said Cavanagh.
The West outside of California is one of the two main areas, along with the Southeast, that lack an organized market. But in the former that is changing, and Cavanagh said it must do so to reliably transition the grid to a cleaner future. The West would not have made it through the massive heatwave this past September without major cooperation, where Arizona helped California and California helped Idaho maintain reliability.
“It became obvious to everyone that nobody cared what the political color of the state was,” Cavanagh said. “There’s a common interest to a fully functioning regional grid to which we are all connected.”
The CAISO-run Western Energy Imbalance Market has already expanded to cover most of the Western Interconnection, and it has saved billions of dollars so far.
“The most important thing we have to do now is to get the California legislature to open a path to fully independent governance for the California ISO,” Cavanagh said.
CAISO covers roughly one quarter of the generation and demand for power in the Western grid. Cavanagh said it was the best positioned entity to run the entire interconnection. SPP, however, is also fighting for a role in the Western Interconnection. (See SPP Makes Moves Out of the Southwest.)
The New York Times article that started a fresh round in this old debate spent a lot of time focusing on ballooning transmission and distribution bills that have little to do with markets.
Among the causes the Times cited for the higher prices in “deregulated” states are transmission and distribution costs and power company profits. “Deregulated states may spend more on transmission,” R Street Institute energy adviser Josiah Neeley acknowledged in a rebuttal published in Reason. “But that part of the market is still heavily regulated.”
Of the three big categories that feed into customers’ bills — transmission, distribution and generation — transmission is the smallest of the three. By opening up new resources to serve load, it puts downward pressure on prices, said Cavanagh.
“The entire country is now linked by high voltage interstate transmission, which is regulated on the provision of non-discriminatory access,” he added. “That’s the American model. We’re not divided on that; we’re divided on lots of other things, but not that.”
Transmission and distribution spending will need to increase to ensure the industry can reliably and affordably transition to the kind of cleaner grid needed to avoid the worst impacts of climate change.
“The impact of broader transmission is to create lower wholesale power prices, which is the whole point,” Wood said. “You want to have broader markets to get access to the most cost-effective power, which is a bigger percentage of the customer’s bill than the wires charges are.”
Texas saw the benefits of expanding transmission with its Competitive Renewable Energy Zone lines, which were planned 15 years ago and came with a $7 billion price tag to bring wind from the resource-rich areas of the state to its cities. They wound up producing benefits that were five times their cost, Wood said.
The distribution system is going to need investment as well, to ensure that it can handle all the new sources of demand, such as plug-in vehicles and heat pumps, as well the growing distributed resources such as solar panels and batteries, he added.
Do Markets Help with Greening the Grid?
Silverstein argued that beyond transmission, wholesale competition has helped to weed out old, inefficient coal plants and replaced them with cleaner, more efficient natural gas — and in more recent years, renewable power.
“God forbid, thinking about what we might have had for the rate of climate change and extreme weather if we hadn’t been enabling competition to shut out older and natural gas plants that were emitting even more carbon and were highly inefficient,” she said.
While most experts support the idea that transmitting renewables around a large, centrally managed grid helps, some questioned whether the competitive markets were really helping renewables. Public Citizen’s Slocum argued that the shift to renewables has put the system under strain, as seen with efforts from FERC under the Trump administration to block their impact on the market through the minimum offer price rule.
“Renewables are coming into the system in spite of the market design,” Slocum said. “They’re coming into the system because of regulatory mandates and financial incentives, which are not the markets. And as a result, it’s upending the market-based pricing system.”
CAISO on Friday released a draft report on Western regionalization that is intended to restart talks on the ISO becoming an RTO and bolster a likely legislative effort this year to open its governance to residents of other states.
The report examined 41 regionalization studies in response to last year’s Assembly Concurrence Resolution 188, by State Assemblyman Chris Holden (D), chair of the Assembly Appropriations Committee and a proponent of CAISO expansion. ACR 188 asked the ISO and the state’s eight other balancing authorities to report to the legislature on recent and relevant studies of regional market impacts by Feb. 28.
“It’s time for California to revisit a broader regional market,” Holden said in a message accompanying the bill, which passed unanimously in the State Senate and Assembly.
Prior attempts by Holden in 2017-2018 to allow CAISO to become an RTO failed, but circumstances in California and the West have changed significantly since then. (See Plans Revive to Make CAISO a Western RTO.)
“Expanding CAISO to become a multistate regional transmission organization is an option that ACR 188 calls out specifically,” the report notes.
To avoid appearances of bias, CAISO commissioned the National Renewable Energy Laboratory (NREL) to write the report. “As a national laboratory of the U.S. Department of Energy, NREL is independent of any particular stakeholders and state policies,” the report says.
NREL researchers examined dozens of studies that concluded California and most other Western states would benefit from increased collaboration in terms of cost savings, resource adequacy and meeting climate goals. They included a June 2021 study that found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons.
The study, funded by the U.S. Department of Energy, was led by Utah Gov. Spencer Cox’s Office of Energy Development and energy offices in Colorado, Idaho and Montana. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
A “large, multistate RTO is one of several options,” the report says. “It could provide the largest margin of benefit, including the greatest visibility into operational performance, efficient dispatch and lower-cost reliability. Other forms of enhanced regional cooperation, such as a regional energy market, a regional mechanism for resource adequacy or even the expansion of an RTO to only a few neighboring states, would also provide some measure of cost savings, reliability improvements and reduced carbon emissions for the benefit of all participants.”
However, “some of the technical studies included in this review suggest that the benefits of more comprehensive forms of regional cooperation might not be spread evenly across participating states and their utilities,” the report said. A section detailing the “distribution of benefits among states” in one or more Western RTOs is still being drafted.
“The CAISO is working with NREL to expand this section to be responsive to the legislation,” the report says.
The state-led study found “that a single RTO would provide California and all other states greater capacity savings than two Western RTOs. For a day-ahead market, all states except Colorado would see greater capacity savings with one market rather than two.”
A separate study conducted by the Colorado Public Utilities Commission at the behest of Colorado lawmakers determined that the state would benefit more if there were two RTOs: one led by CAISO, and another by SPP that includes most utilities in Colorado and some in Wyoming.
“This study found significant cost savings to Colorado if its utilities were to join a regional RTO,” the report says. “Interestingly, the benefits were slightly greater for joining SPP: a 9% savings in total system costs over the status quo reference case, compared to 8% for a [WECC-wide] RTO and 7% splitting Colorado between SPP and a WECC RTO.”
If Colorado participates in a WECC-wide RTO, “higher power prices in the West [especially California] lead to slightly higher prices in Colorado,” it said. “The marginal cost of serving demand in Colorado under a WECC RTO was about 16% higher than it would be if Colorado utilities were in SPP. Colorado also retired more coal capacity under the SPP RTO.”
In the past two years, a handful of Colorado utilities decided to join SPP’s real-time Western Energy Imbalance Service instead of CAISO’s larger Western Energy Imbalance Market, with some exploring membership in SPP’s RTO. (See Colorado Utilities Choose WEIS over WEIM.)
The ACR 188 report comes as CAISO and SPP continue to vie for Western market share in a region primed for one or more organized electricity markets.
SPP plans to launch its Markets+ offering with many of the services of an RTO and later to introduce a Western version of its Eastern RTO called RTO West. CAISO intends to add a day-ahead market to its successful real-time WEIM, which could eventually develop into an RTO. The Western Power Pool (formerly the Northwest Power Pool) is seeking FERC approval for its Western Resource Adequacy Program, a possible RTO launchpad. And Colorado and Nevada have ordered transmission-owning utilities to join an RTO by 2030.
The retirement of coal generation and increase in wind and solar resources in remote parts of the West is a major factor driving the need for regional transmission planning, the report notes. Strained grid conditions during heat waves have shown the need for better a resource adequacy framework, and a growing number of states are adopting clean-energy goals, requiring more interstate transactions, it said.
CAISO has scheduled a stakeholder call for this Friday to discuss the report.
“The ISO values stakeholder input on this preliminary draft and plans to incorporate feedback received during the Jan. 20 stakeholder call, and in written comments submitted by the deadline on Feb. 3, into future iterations to ensure the accuracy and value of the final report,” the ISO said last Friday in a message to stakeholders.
PORTLAND, Ore. — When energy economist Robert McCullough greeted this reporter at a wine shop and deli in our shared Southeast Portland neighborhood, he joked about recently contributing to “quite a stir” in the electricity industry.
McCullough was referring to a high-profile article published in TheNew York Times Jan. 4 under the headline “Why Are Energy Prices So High? Some Experts Blame Deregulation,” which set off a wave of criticism from industry insiders — much of it on #energytwitter.
“On average, residents living in a deregulated market pay $40 more per month for electricity than those in the states that let individual utilities control most or all parts of the grid. Deregulated areas have had higher prices as far back as 1998,” the Times said.
Times Article Misses the Mark, Critics Say
Critics faulted the Times for conflating “deregulation” with organized RTO/ISO wholesale markets.
While 13 states and the District of Columbia allow most of their electric customers to choose their electric supplier, the Times appeared to be including as “deregulated” 21 states whose utilities participate in organized wholesale markets but do not allow retail choice, said R Street Institute energy adviser Josiah Neeley in a rebuttal published in Reason.
The Times “seems to say that the label ‘deregulation’ applies even in places like Minnesota, where no customer exercises a choice in provider, and where the industry simply has been restructured to be part of a larger grid with two different regulators (FERC and the state),” tweeted former Montana regulator Travis Kavulla.
Kavulla, now vice president of regulatory affairs for NRG Energy (NYSE:NRG) also rejected the characterization of California as “deregulated,” saying it “stands as the foremost example of a jurisdiction where policymakers treat utility balance sheets as playthings for various policy ends.
“There is no such thing as ‘deregulation’ or a ‘free market’ in this industry anywhere — which remains regulated everywhere,” Kavulla added.
A power and gas trader who tweets under the name “King of Power” called the piece a “master class in how not to do power market analysis,” adding that “the article is so full of bad methodology and blatant falsehoods that it would make a utility blush.”
Other critics pointed to a lack of supporting data in the piece.
McCullough, who was prominently quoted by Times reporter Ivan Penn, also produced the data that was cited in the article but conspicuously absent from it. In an interview with RTO Insider, McCullough acknowledged that omission, but said he thought the piece was “generally a good article” that just required more “column inches” to do the subject justice. He said he may have “overwhelmed” Penn “on this whole question of competition.”
“Of course, one of the evocative things about electricity — evocative in that it attracts a lot of confusion — is it is complicated, and so it’s very hard to get some of the concepts across,” McCullough said.
Penn did not respond to a request for comment.
Some of that confusion may have stemmed from the article’s use of the term “deregulated.” In our interview, McCullough said the analysis he provided the Times wasn’t really a comparison of retail electricity prices in deregulated versus regulated states, but between states operating inside and outside of organized markets.
McCullough’s staff sourced the price and volume data from the U.S. Energy Information Administration’s Electric Power Monthly reports, and calculated weighted price averages to show differentials between RTO and non-RTO states.
“Is that exact? No, because of course, some of the states are split between two [markets]. But was it honest? Yeah — it’s a pretty straightforward calculation,” McCullough said.
The data does not control for differences in fuel costs or resources across regions, because, McCullough said, the Times only requested retail price numbers. A spreadsheet he provided to RTO Insider includes a retail price data series covering January 1998 to October 2022, showing average monthly prices and total electricity consumption by state. That data is then distilled into a comparison of prices between RTO and non-RTO states over the entire period.
The first entry, January 1998, before widespread implementation of retail choice, shows an average retail price of 6.33 cents/kWh in non-RTO states and 7.41 cents/kWh for states that would eventually join RTO states. During the Western energy crisis in 2001, the spread increased sharply, with non-RTO states averaging of 6.47 cents/kWh and RTO states 9.35 cents/kWh.
During a period of relatively high natural gas prices from 2002 to 2009, retail prices averaged 8.35 cents/kWh in non-RTO states versus 9.99 cents/kWh in RTOs. In the 2012-15 period of lower gas prices, average non-RTO and RTO state prices were 9.52 and 10.47 cents/kWh, respectively.
A graph included with the data illustrates trends across the time series, with callouts for events in which RTO price spikes outpaced those in non-RTO areas. The events include the commodities price bubble of 2008, the ERCOT outages accompanying February 2021’s winter storm and Russia’s invasion of Ukraine in February 2022.
McCullough contends that prices in RTO areas can be more sensitive to such events because RTOs rely on the single market clearing price mechanism to set prices, as opposed to the “price-as-bid” nature of the traditional utility model.
“For states served at the market clearing price — ERCOT comes to mind — the swings are greater because the entire market is priced at the market clearing price,” he said. “And, of course, for ERCOT the reserve margin price adjustment, as well as the ERCOT-administered emergency price cap, creates quite a ‘bump.’ A peculiarity of the ERCOT rolling outages is that the prices crossed the ERCOT border and extended all the way north to North Dakota in the SPP market. This is somewhat peculiar given the limited transmission, but [it] did affect retail rates.”
McCullough was among the first industry watchers to identify the manipulation that sparked the Western energy crisis of 2000-01, when energy traders such as Enron exploited adverse market conditions and design flaws in California’s organized electricity market to drive up wholesale prices. Their actions caused rolling blackouts, bankrupted Pacific Gas & Electric and nearly sunk Southern California Edison. He has long been a vocal critic of RTOs and ISOs, which he refers to as “administered” markets, compared with what he calls the “competitive” bilateral wholesale markets that still predominate in most of the West.
“Northwest power markets are large and competitive and low-price, but we don’t have a central administrator to tell us what to do. How valuable is the central administrator on energy markets and prescheduled energy markets? I suspect the answeris: pretty irrelevant,” he said.
McCullough thinks the Northwest has “maintained a very successful, large, efficient market for many years … with very few abuses, no blackouts, [and] guys who actually call each other on the phone and buy and sell.
“Exceedingly transparent. Far more transparent than in the California ISO because you know everyone’s prices every day,” he said.
Impact of Markups
R Street’s Neeley also challenged the Times’ contention that competition leads to higher prices because of “profits taken in by energy suppliers.”
“Based on reading the Times article, you might be surprised to learn that monopoly utilities also make profits,” Neeley wrote. “Indeed, utility rates are typically set to give the utility a set percentage of profit based on their past investments. This, needless to say, does not encourage utilities to find ways to lower costs.”
The Times article might have strengthened its thesis if it gave more than passing mention to a Harvard working paper published last month that does in fact focus on the impact of electricity deregulation on ratepayers.
The authors of the paper, Alexander MacKay, assistant professor of business administration at Harvard Business School, and Ignacia Mercadal, assistant professor of economics at University of Florida,say their work seeks to fill a gap in the academic discussion on electricity restructuring by addressing the question of whether deregulation of wholesale (as opposed to retail) markets has resulted in lower electricity prices for end consumers.
Their findings suggest the opposite: that consumers in markets subject to wholesale deregulation have seen greater increases in retail prices compared with those in fully regulated environments.
“The goal of our analysis is to evaluate the effect of electricity restructuring on markups and prices. For this, we compare utilities in restructured states to those that remained vertically integrated and regulated, and we examine the evolution of costs, wholesale prices, and retail prices over time,” MacKay and Mercadal explain in the paper.
While the study does not specifically focus on differentials based on RTO markets, it does address the influence of those markets on price outcomes, in part because nearly every retail choice state featured in the study — except Oregon — participates in an RTO or ISO. That study also relies on EIA retail price data sets.
The study examines the period between 1994 and 2016, using 1999 as the “baseline” for retail prices and relying on a “difference-in-differences” approach that measures the price movements in deregulated states relative to the those in the “control” group of states that did not implement retail choice. It finds that states that unbundled their monopoly utilities started with a higher baseline for retail prices (averaging $79/MWh — or 7.9 cents/kWh) than those in the control group ($59/MWh), which is attributed to higher fuel prices in the deregulated states at the time.
From 1994 to 1997, the analysis showed prices were stable for both groups, followed by a convergence over 1998-2000 as prices in deregulated states declined while those in control states held steady. “Starting in 2001, prices in both states began to rise. Deregulated prices outpaced control prices until 2005, when the gap between the two widened further,” the authors write.
From 2000 to 2005, deregulated utilities saw average price increases of $3.90/MWh, followed by a sharper rise of $12.60/MWh from 2006 to 2016 (a 16% increase from the baseline), for an average increase of $7.60/MWh over 2000-2016.
“We reiterate that these changes are difference-in-differences effects, i.e., increases above and beyond the price trends occurring in control utilities,” the authors wrote.
Another key finding: while retail prices rose in deregulated markets, generation costs declined, with average fuel prices falling by $6.90/MWh over the study period. The authors say that indicates generators were earning higher “markups” for their power — the difference between the selling price for power and the cost for generating it. The study finds that markups were “modest” from 2000 to 2005, but spiked to $20/MWh over 2006-2011 (See graph).
Figure displays difference-in-differences matching estimates of changes in (a) retail prices and (b) fuel costs for deregulated utilities. Each deregulated utility is matched to a set of three control utilities based on 1994 characteristics. The estimated effects are indexed to 1999, which is the year prior to the first substantial deregulation measures. The dashed lines indicate 95 confidence intervals, which are constructed via subsampling. | Alexander MacKay and Ignacia Mercadal
MacKay and Mercadal attribute that development to a combination of factors present in deregulated markets, including an increased concentration of power suppliers and a larger pool of buyers that now includes utilities, power marketers and industrial customers. They contend that when the wholesale price caps that states implemented to smooth the transition to deregulation began to expire around 2005, bargaining power for distribution utilities declined while the market power of generators increased.
“For a utility, obtaining electricity from the wholesale market was more expensive than [providing its own generation], as wholesale prices reflect a markup. … With deregulation, utilities effectively paid a market-based markup to generation facilities that they had previously owned,” they say.
At the same time, incumbent utilities increased their regulated retail rates to reimburse average variable costs, which “went up due to the introduction of this markup.”
The study also contends that the specific characteristics of electricity make wholesale markets “particularly prone to market power.”
“Both demand and supply are inelastic, yet supply must meet demand at every moment since large amounts of electricity cannot be stored efficiently. Transportation is expensive, constraining the degree to which generators compete across local markets. Entry is limited due to large sunk investments, long planning horizons, and high risk. As a result of these factors, only a few generators are typically competing to serve demand for a certain area at a particular moment, and the relative scarcity can give them substantial market power. Deregulation did not fundamentally change these factors,” the authors say.
Tyson Slocum, director of Public Citizen’s energy program, said the Harvard study indicates that the efficiency gains from wholesale markets “are all being vacuumed up by these sophisticated traders and other market participants” who exploit arbitrages and take the profits, leaving no savings to end consumers.
“It’s a who’s who of sophisticated financial traders,” Slocum said. “Those guys are parked in those markets, not because, you know, ‘Gosh, we need to work every day to deliver value to end users.’ They’re like: ‘We’re going to be heavily in these markets to exploit the arbitrage and make enormous and unregulated profits.’ That’s what’s driving RTO activity.”
‘Likely Wrong’
But criticism of the study came from a different corner, setting off an exchange that illustrates the difficulty of reaching consensus on the impacts of electric restructuring.
Scott Harvey, an energy consultant with FTI Consulting and member of CAISO’s Market Surveillance Committee, picked apart the paper in an email to RTO Insider. Among other complaints, Harvey contended that its finding of declining fuel costs for generators from 2002 to 2015 was “incomprehensible” and that there must be something “fundamentally flawed” in how those costs were measured.
He also argued that the wholesale electricity prices used in the paper do not reflect prices in the spot markets, but the higher prices since 1994 for various types of contracts, including those for securing renewables to meet state environmental mandates.
“Hence the fuel cost measure is wrong and the wholesale price measure is wrong. All of the results in the paper are likely wrong,” Harvey wrote.
MacKay and Mercadal defended their approach for measuring fuel costs and noted that their analysis checked for variables such as environmental regulations.
Mercadal also said it would’ve been incorrect to just focus on spot prices in their analysis.
“A big point of our paper is that most of the purchased electricity (>80%) comes from contracts (not spot markets), and these prices are indeed often higher. We can’t just ignore these prices … they really do matter for the prices that consumers pay!” she wrote.
“We would be happy to see evidence supporting other explanations for our findings. We tried competing hypotheses but were not supported by the data,” Mercadal said.
