SACRAMENTO, Calif. — CAISO officials on Wednesday urged California lawmakers to pass legislation that would convert the grid operator into an RTO, saying a regionalized grid would benefit the state.
CAISO executives told Assembly Utilities and Energy Committee Chairman Chris Holden (D) that they support his regionalization bill (AB 813), which represents a third attempt to regionalize the ISO. The bill is getting opposition from some quarters.
“A regional grid will be good for California,” CAISO Director of Regional Integration Phil Pettingill told the committee. He said a “major evolution” is occurring in the West, with utilities looking for ways to procure more renewables, in alignment with California’s goals.
Mark Rothleder, CAISO vice president of market quality and renewable integration, pointed out that the West is an interconnected system with 38 balancing authority areas. He said the state’s goal of generating 50% of its electricity with renewables by 2030 is achievable but faces challenges dealing with the “duck curve” load shape of California energy demand.
The curve shows that the state’s load dips in the middle of the day as solar resources increase output, then ramps up steeply in the evening as the sun sets. The steep ramps require CAISO to lean on fast-ramping generation to meet evening demand, which regionalization supporters say could be tapped more easily from inland renewables under a regional grid. The arrangement would also allow California to export more of its surplus solar during the day.
State Assemblyman Bill Quirk (D) acknowledged there are reservations across the region about “getting in bed with the 800-pound gorilla we call California.” But despite the misgivings and the complications, “I am convinced we can come up with a fair way of doing this.”
Quirk recently proposed separate legislation on the committee’s April 4 agenda that would require California utilities to procure power from gas-fired plants that cannot make sufficient profit in CAISO markets.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said regionalization would help lower California’s costs for reaching its carbon reduction goals.
“The rest of the West isn’t going to decarbonize because California tells them to, but they will buy cheap electrons,” he said. He said California will continue to have control over its resource decisions, CO2 policy, generation siting, and retail rates and programs.
“All of those things you do today, you can continue to do in the future, and that is important to recognize,” he said.
But Matt Freedman, attorney for The Utility Reform Network, warned that regionalization could force California to conform to policies of the Trump administration, which he said is hostile to the state and its clean energy goals. He also suggested that FERC would exert more control over the new RTO, and that “this is not your father’s FERC.”
Holden is taking a cautious tack on the regionalization effort, saying the hearing was “an opportunity to look at the contours of AB 813.” He added that he is trying to make the process as transparent as possible after the regionalization skeptics raised many issues during last year’s effort, including concerns by labor groups about the exporting of energy-related jobs.
“We recognized that an issue of this magnitude required a little more conversation on a broader scale,” Holden said.
As of Thursday, AB 813 was not listed on the agenda for the committee’s April 4 hearing.
WASHINGTON — FERC on Thursday ordered 48 electric utilities to revise their transmission rates to reflect the recently enacted Tax Cuts and Jobs Act, which reduced the corporate income tax rate from 35% to 21%.
The utilities required to file changes — which include Portland General Electric, West Penn Power, New York State Electric and Gas, NorthWestern Corp. and Pacific Gas and Electric — all include a fixed line item of 35% in their transmission tariffs. Most utilities use formula rates that include an annually adjusted input for their tax payments, so they do not need to file any changes, FERC staff said at the commission’s monthly open meeting.
FERC issued its directive in two separate, nearly identical orders: one in which the full commission participated, and the other in which Chairman Kevin McIntyre recused himself. The latter order is addressed to 15 utilities, including several American Electric Power subsidiaries, Baltimore Gas and Electric, Black Hills Power, San Diego Gas & Electric and UNS Electric.
Most of the utilities in the orders have their own docket; the commission grouped three FirstEnergy subsidiaries into one docket and two NV Energy subsidiaries into another.
The utilities are required to file their changes, or show why they should not be required to, within 60 days of the dates of the orders.
FERC also granted two requests to lower transmission rates to reflect the new law: one from Public Service Company of Colorado (ER18-840) and another from multiple MISO transmission owners, including Ameren Illinois, ITC Midwest, Montana-Dakota Utilities and Northern Indiana Public Service Co. (ER18-783).
MLPs, Gas Pipeline NOPR
The commission also issued a revised policy to no longer permit master limited partnerships (MLPs) to recover an income tax allowance in their costs of service (PL17-1).
In its 2016 ruling in United Airlines v. FERC, the D.C, Circuit Court of Appeals found the commission had failed to demonstrate that MLPs were not double recovering when they receive both an income tax allowance and a return on equity based on the discounted cash flow methodology, remanding the case back to FERC.
Reflecting its new policy, FERC issued an order on the remanded case, denying SFPP, a Kinder Morgan subsidiary, an income tax allowance for its West Line, a 515-mile oil pipeline that runs from the Los Angeles Basin to Phoenix, Ariz. (IS08-390).
Shortly after the commission issued its orders, shares for multiple MLPs took a sharp downturn, news outlets reported.
FERC’s revised policy statement also directed oil pipeline MLPs to reflect the elimination of income tax allowance in their Form No. 6 filings, which the commission will use in its 2020 review of the oil index pipeline level.
For natural gas pipelines, FERC issued a Notice of Proposed Rulemaking that would require them to make a one-time informational filing to allow the commission to evaluate whether their rates are just and reasonable under the new tax law and its new policy statement (RM18-11). However, gas pipelines would also be able to simply file reduced rates.
Notice of Inquiry
FERC also opened a broad inquiry into the effects of the tax law on all the industries it regulates (RM18-12).
Commissioners and staff said they were particularly interested in accumulated deferred income taxes — money that companies collect from ratepayers in anticipation of paying income tax — and bonus depreciation, a tax incentive that allows companies to immediately deduct the purchase of certain business properties.
Comments on the Notice of Inquiry are due 60 days after its publication in the Federal Register.
Democratic FERC Commissioners Cheryl LaFleur and Richard Glick have split with the Republican majority over its refusal to consider greenhouse gas emissions in two pipeline orders, the first skirmishes in what may be an escalating debate before the commission and in the courts.
The split came first in Wednesday’s order on remand confirming as in the public interest the 685-mile Southeast Market Pipelines Project, which will supply four gas-fired generators in Florida (CP14-554, et al.).
In August, a split D.C. Circuit Court of Appeals panel remanded FERC’s February 2016 approval of the pipeline, ruling 2-1 that FERC must consider the impact of greenhouse gas emissions when licensing gas pipelines (16-1329). (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
The court ruled in favor of a petition by the Sierra Club, ordering FERC to quantify and consider the project’s downstream GHG emissions or explain why it could not do so. The court also directed the commission to explain whether it still adheres to its prior position that the social cost of carbon tool is not useful in performing its review under the National Energy Policy Act.
Glick opposed the pipeline in Wednesday’s vote. LaFleur — the only current commissioner who took part in the 2016 order — supported the approval along with the three Republican commissioners but issued a partial dissent.
FERC’s ruling affects the Southeast Market Pipelines Project, including the nearly 500-mile Sabal Trail pipeline between Alabama and Florida | Sabal Trail Transmission
The project involves three pipelines, including the nearly 500-mile Sabal Trail, which will connect the other two pipelines between Tallapoosa County, Ala., and Osceola County, Fla., south of Orlando. Scheduled for completion in 2021, the project has a capacity of more than 1 Bcfd. It will supply two new plants — Florida Power & Light’s Okeechobee Clean Energy Center and Duke Energy’s Citrus County Combined Cycle Plant — and FPL’s existing Martin County Power Plant and Riviera Beach Clean Energy Center.
LaFleur: ‘Causal Relationship’
LaFleur said she agreed with the court that the downstream GHG emissions that result from burning gas transported by the pipelines are an indirect impact of the project and that those emissions are “reasonably foreseeable.”
The final Supplemental Environmental Impact Statement (SEIS) estimates that the project will indirectly result in annual gross downstream GHG emissions of 14.5 million metric tons of carbon dioxide-equivalent units (CO2e). Reflecting the reductions in GHG emissions that will occur as the gas-fired generators replace coal-fired units and displace oil as an alternate fuel, the SEIS calculated annual net downstream GHG emissions of 8.36 million metric tons CO2e. (See table.)
| FERC
The majority contended that the emissions data cannot “meaningfully inform” the commission’s public interest determination.
“We are required by NEPA to reach a determination regarding the significance of all environmental impacts, including downstream GHG emissions. It is our responsibility to use the best information we have to make that determination,” LaFleur said. “In this case, we can gauge significance by comparing the gross and net GHG emissions of the SMP Project to the total state and national emission inventories to calculate how the SMP Project increases those GHG inventories,” she continued. “Here, I believe that a net increase of 3.6% of the Florida inventory for a single pipeline project is significant. Due to the need of the project, I believe that increase is acceptable but should be disclosed and assessed.”
LaFleur also parted with the majority view that the social cost of carbon is not an appropriate tool for evaluating the impact of GHG emissions. “That is precisely the use for which the social cost of carbon was developed — it is a scientifically derived tool to translate tonnage of carbon dioxide or other GHGs to the cost of long-term climate harm.”
She said concerns over the lack of consensus on the appropriate discount rate could be addressed by calculating it using a range of rates.
LaFleur said the commission should conduct a detailed cost-benefit analysis of the project, “including more information on the need for a project, the likely end-uses of the transported gas and the alternatives.” She said she would press the issue in the “generic” pipeline review proceeding announced by Chairman Kevin McIntyre in December. (See FERC to Review Gas Pipeline Approval Process.)
Glick: ‘Willful Ignorance’
Glick said the order failed to properly address either of the two issues raised by the court “and, as such, does not adequately respond to the court’s mandate.”
“Climate change is the single most significant threat to humanity, fundamentally threatening our environment, economy, national security and human health. It is difficult to understand how NEPA’s demand that an agency take a ‘hard look’ at the environmental impacts of its actions can be satisfied if the impacts of GHG emissions are ignored,” he wrote.
Glick said the commission “is engaging in a collateral attack on the court’s decision by suggesting that it is not the commission’s ‘job’ to consider whether emissions from ‘the end use of the gas would be too harmful to the environment.’
“It is absurd to even contemplate NEPA not applying to the most significant environmental issue of our time,” Glick continued.
He said the commission’s “willful ignorance of readily available analytical tools” undermines public confidence in its consideration of pipeline applications. “I fear that today’s order, by limiting analysis of the environmental impacts of a proposed pipeline, will both increase the commission’s litigation risk and contribute further to the cynicism of the pipeline siting process.”
Previous D.C. Circuit rulings had found that FERC did not have to consider the climate-change effects of exporting natural gas in its licensing of LNG terminals. If the circuit court again rejects FERC’s Southeast Markets order, it could be up to the Supreme Court to settle the inconsistency.
Majority’s Comments
The majority said its staff “had no basis for determining the significance of impacts from these emissions” because “there is no widely accepted standard to ascribe significance to a given rate or volume of GHG emissions.”
“There are no conditions the commission can impose on the construction of jurisdictional facilities that will affect the end-use-related GHG emissions,” the majority continued. “The only way for the commission to reflect consideration of the downstream emissions in its decision-making would be, as the court observed, to deny the certificate. However, were we to deny a pipeline certificate on the basis of impacts stemming from the end use of the gas transported, that decision would rest on a finding not ‘that the pipeline would be too harmful to the environment,’ but rather that the end use of the gas would be too harmful to the environment. The commission believes that it is for Congress or the executive branch to decide national policy on the use of natural gas and that the commission’s job is to review applications before it on a case-by-case basis.”
The commission said the social cost of carbon tool is more appropriate for regulators whose responsibilities are tied more directly to fossil fuel production or consumption, such as the Bureau of Land Management and the Bureau of Ocean Energy Management.
It noted that the Council on Environmental Quality does not require agencies to conduct a monetary cost-benefit analysis for NEPA review.
The majority also rejected as outside the scope of the SEIS and the court’s mandate issues regarding GHG emissions from upstream production of natural gas, environmental justice and the project’s effect on the supply and demand for natural gas and substitute energy sources.
Second Pipeline Dissent
Glick and LaFleur also dissented in part Thursday on an order granting a certificate of public convenience and necessity to DTE Midstream’s proposed 14-mile Birdsboro Pipeline, which will supply up to 79,000 dekatherms per day of firm transportation service to the 450-MW Birdsboro Power Facility in Berks County, Pa. (CP17-409).
As in the Southeast Market order, LaFleur and Glick dissented over the commission’s refusal to use the social cost of carbon to consider the significance of the project’s environmental impacts.
They also cited concerns over the commission’s “‘new policy’ approach towards motions to intervene out of time,” articulated in a Feb. 27 order involving Tennessee Gas Pipeline (CP16-4-001).
“Today’s order suggests that good cause for late intervention does not exist where an entity seeking to participate as a party in the proceeding submits a motion on the same day it learned that the application had been submitted,” they wrote in their DTE Midstream dissent. “While we agree that late interventions should be limited to parties that demonstrate good cause, we are concerned by the potential consequences of the commission’s pronouncement, particularly as it would apply to landowners and community organizations that lack sufficient resources to keep up with every docket.”
Dissent in Hydro Case
LaFleur and Glick also joined in a partial dissent in a case involving two small U.S. Army Corps of Engineers hydropower projects in West Virginia: the 5-MW Morgantown Lock and Dam and 6-MW Opekiska Lock and Dam (P-13753-003, P-13762-003).
The majority denied rehearing requests of staff’s Sept. 29, 2017, orders authorizing the dams on the Monongahela River, upholding staff’s determination that the West Virginia Department of Environmental Protection waived its Clean Water Action Section 401 water quality certification authority by failing to act on the licensee’s applications within one year of receipt.
LaFleur and Glick said that although the state missed its deadline, they would have included the state’s “modest requests to enhance recreational use of the project lands” — including a permanent public restroom instead of a portable restroom, trash receptacles and fishing piers — which were not opposed by the Army Corps.
“It is commission practice to consider incorporating the late-filed conditions into the license as recommendations … as long as they do not interfere with the licensee’s safe and effective operation of the hydroelectric facility for electric generation,” they wrote.
In a case pending before a federal court early next month, Michigan regulators have joined with load-serving entities to challenge a 2016 FERC order that reallocated most costs for the Presque Isle system support resource (SSR) agreements to consumers in the state’s Upper Peninsula.
Presque Isle Power Plant
Under the suit filed with the D.C. Circuit Court of Appeals late last year, the parties contend that FERC decided to change the longstanding allocation of costs within MISO’s American Transmission Co. pricing zone covering northern Michigan and Wisconsin without substantial supporting evidence. The change saddled Michigan LSEs with surcharges that amount to retroactive rate increases, a practice prohibited by the Federal Power Act, the parties argue (15-1098).
The complainants include the Michigan Public Service Commission, Constellation Energy, Cloverland Electric Cooperative, Tilden Mining Co., the cities of Mackinac Island and Escanaba, Upper Peninsula Power Co., the Sault Ste. Marie Tribe of Chippewa Indians and Verso Corp.
Dueling Presque Isle Proceedings
In a separate but related proceeding, FERC last year ordered Presque Isle owner Wisconsin Electric Power Co. to refund Michigan LSEs $23 million in overcharges stemming from the SSRs over 2014/15. The commission last month accepted MISO’s plan to distribute those refunds. (See FERC Approves Presque Isle Refund Calculation.)
But in their case, the Michigan parties argue that the refunds are only part of the equation, considering that ratepayers now bear nearly all SSR costs for the coal-fired plant, which represents a break from MISO precedent. Under the original 2014 SSR agreement, costs to keep the plant running for reliability were allocated across the ATC zone, with Upper Peninsula ratepayers paying 8% and Wisconsin ratepayers responsible for the rest.
After two years and a complaint by Wisconsin’s Public Service Commission that the state was paying for a majority of the SSR but not receiving a majority of the benefits, FERC allowed MISO to shift 98% of the SSR costs to LSEs in the sparsely populated Upper Peninsula. That change in part stemmed from NERC’s 2014 decision to separate the Upper Peninsula from Wisconsin into its own local balancing authority. FERC at the time said it was unjust to allocate SSR costs on a pro rata basis to all LSEs in the ATC footprint, deciding that costs instead must be allocated to LSEs that require the operation of the plant for reliability purposes.
But the Michigan parties argue that, in reassigning the costs for the SSR, FERC improperly relied upon a preliminary load-shed study that showed Wisconsin receiving only 42% of the reliability benefits from Presque Isle, while a final study showed the state receiving 86% of the benefits.
The reallocation applies retroactively — back to 2014, which means that after receiving $23 million in refunds for the overpayment, Upper Peninsula ratepayers could then owe more than $20 million in retroactive surcharges to implement the change in SSR allocation. The Michigan parties contend that any surcharge is unlawful, but MISO has been cleared by FERC to begin assessing surcharges this month according to the same 10-month schedule for disbursing the refunds.
The D.C. Circuit will hear oral arguments in the case on April 6, with a decision expected by summer. The Michigan PSC and other complainants have filed for a temporary stay of MISO’s assessment of the surcharges while the case is being argued, contending that the “immediate implementation of surcharges to reallocate Presque Isle SSR costs threatens to impose significant irreparable harm on some Michigan LSEs.”
“If MISO begins to invoice surcharges this month, it is anticipated that LSEs paying such surcharges will include the surcharge amounts in their bills to retail ratepayers, assuming that is even feasible,” the PSC said.
‘Middle of the Game’
“This is a reallocation of costs where the surcharges arising from the reallocation will exceed the refunds due to the reduction in permissible SSR costs,” Bill Demarest, an attorney representing Tilden, said in an interview with RTO Insider. “The surcharges are to pay for reallocation of the SSR costs after the substantial reduction in costs ordered by FERC.”
Cloverland attorney Christine Ryan said the reallocation is unfair to Upper Peninsula ratepayers that have for years contributed to grid costs with Wisconsin.
“We can’t just change the rules in the middle of the game. Upper Peninsula customers have shared the costs of this system over the years,” Ryan said.
Demarest agrees, contending that Upper Peninsula ratepayers have subsidized transmission upgrades in the past that have benefited only Wisconsin ratepayers.
Complicating matters is whether Upper Peninsula ratepayers can afford to shoulder all Presque Isle SSR costs over MISO’s 10-month schedule.
“Our client Cloverland is a good example of the problem,” Ryan said. “They are small; they serve a rural population. That part of Michigan is economically depressed. This will be a significant charge that Cloverland will have to pass on to its customers. Administratively, this is a very difficult thing to manage.” If Michigan ratepayers are found to be almost exclusively responsible for the retroactive surcharges, LSEs face the prospect of calculating customer responsibility and tracking down those customers that have relocated during the intervening four years.
The two attorneys also argue that, in changing the historical allocation pattern for the purposes of the Presque Isle SSR, FERC ignored its own finding in Order 1000 to treat generation and transmission-based reliability solutions comparably.
“FERC was going against their own policies here, we pointed that out and they ignored that,” Demarest said.
Robb, who has led WECC since 2014, has more than 30 years of experience as a power sector engineer, consultant and senior executive. He formerly served in senior roles at both Northeast Utilities (now Eversource Energy) and Reliant Energy.
“The board took this duty very seriously by engaging in a comprehensive, nationwide search culminating in the unanimous selection of Jim Robb,” NERC Board of Trustees Chairman Roy Thilly said in a statement. “We are confident that Jim will provide the combination of strong leadership, vision and commitment to the reliability and security of the bulk power system across North America that is essential to NERC’s continuing success.”
NERC has been without a CEO since Gerry Cauley stepped down last November after being arrested for allegedly assaulting his estranged wife, who told police he had been involved in a sexual relationship with a female employee at the agency. (See Cauley Resigns; NERC Launches Search for Replacement.)
Cauley had served as NERC CEO since January 2010 and was often the face of the reliability agency in hearings before FERC and Congress. NERC General Counsel Charles Berardesco has been serving as acting CEO.
As head of WECC, Robb led NERC’s largest Regional Entity, “where he improved member relations, strengthened the management team and expanded collaboration with NERC and other Regional Entities,” NERC said. WECC’s territory covers all or part of 14 Western states, Alberta and British Columbia in Canada, and the northern portion of Baja California in Mexico.
“I have been fortunate to lead WECC and be a part of the NERC-enterprise family for the past four years, and I look forward to the next chapter of my career leading the” FERC-certified Electric Reliability Organization, Robb said. “This experience, combined with my past industry knowledge, has prepared me for this exciting opportunity at NERC.”
WECC said it will search for a replacement for Robb over the next several months. It has appointed Vice President and General Counsel Steven Goodwill as interim CEO. Goodwill is not a candidate for the top job.
In a written statement, WECC Board of Directors Chair Kristine Hafner said Robb’s “unrelenting focus on effectively and efficiently reducing risks to the reliability and security of the bulk power system in the Western Interconnection has been vital to the 80 million people within our footprint who rely on power for their day-to-day lives.”
Salt Lake City-based WECC is in the midst of revamping its operations following its 2014 restructuring into the current WECC and Vancouver, Wash.-based Peak Reliability. (See WECC Finding New Direction in Old Mission.) Among the changes in the works to refocus the RE on its reliability functions is a renaming to Reliability West. Other changes in the organization’s bylaws are proposed for a possible June vote by WECC members.
PJM’s Board of Managers last week assured Pennsylvania legislators that the state has ample power generation for its needs and cautioned that fuel diversity will not ensure reliability.
The RTO was responding to a Feb. 9 letter from the state legislature’s Nuclear Energy Caucus with its own letter that seemed intended to assuage lawmakers’ fears about of blackouts and grid interruptions caused by inadequate resources. While the caucus’s message referred only to “baseload” units, it did voice support for several FERC and PJM initiatives that would benefit coal and nuclear plants.
Peach Bottom Nuclear Generating Station in 1974
“We are losing confidence in the ability of wholesale electric markets to ensure Pennsylvania maintains a diverse supply of baseload generation resources that ensure stable prices for our citizens and a reliable and resilient electrical grid,” the caucus wrote. “Pennsylvania’s baseload power plants continue to face the risk of premature retirement, and we do not see expeditious and sufficient action being taken by PJM or the Federal Energy Regulatory Commission to correct the market flaws at the heart of this problem — flaws that PJM itself acknowledges.”
PJM’s Independent Market Monitor noted last week in its 2017 State of the Market report that just 52% of coal-fired plants in the RTO recovered their avoidable costs in 2017. All of Pennsylvania’s five nuclear facilities made enough money to cover their costs last year, although none did in 2016, the report showed. Three Mile Island has seen negative revenues since 2015 and will continue to through 2020 unless market changes occur, while the other four will remain profitable through that year. (See IMM Report Says PJM Prices Sufficient.)
Adequacy Assured
PJM CEO Andy Ott penned the response to the caucus, which defended the RTO’s operations. Ott noted that Pennsylvania has built more than 12,000 MW of new generation over the 20 years that the RTO has managed its grid, calling it “a direct result of the investment signals sent by the PJM wholesale market.”
In the past six years, Pennsylvania has produced between 18 and 27% more energy than it needed, equating to about 6,500 MW of generation, or nearly two-thirds of the Keystone State’s nuclear fleet, Ott said.
While the caucus’s letter never mentioned costs, Ott remained focused on them, noting that “PJM markets have yielded reliability at the lowest cost for Pennsylvania.”
“The dramatic increase in wholesale power prices during that period highlight the risk of overreliance on any single fuel source, a risk we believe PJM can and should avoid by swiftly enacting reforms,” the legislators wrote. “We believe that [PJM’s price-formation proposal] is an important first step in recognizing the benefits of fuel diversity within this market, and one that will help keep our grid — and power prices — stable for many years to come.”
Ott noted in his response that both the RTO and Pennsylvania are more fuel-diverse today than ever, but downplayed the significance of that fact.
“Fuel diversity, however, is not a metric with which PJM can measure reliability,” he said. “Instead, fuel security — the certainty of fuel availability for power production — affects reliability.”
Market Changes
The caucus supported PJM’s efforts to revise its energy price-formation methodology, calling the current process “a flaw in its market rules that unfairly disadvantages certain low-cost baseload generation resources” by not allowing them to set clearing prices. As a result, “market prices are artificially low and do not reflect the true cost of meeting customer demand.” It gave PJM “credit” for developing “a potential solution.”
The RTO’s solution is a controversial plan to allow large, inflexible units like coal and nuclear to set clearing prices. Currently, those plants’ bids are often among the highest of dispatched units, but only “flexible” units that can regulate their output in response to price signals are allowed to set prices. The inflexible units receive subsequent “uplift” payments to cover their operating costs. In PJM’s plan, those units would set price and the flexible units would be paid additional revenue to back down their output to avoid oversupply.
Critics of the plan argue that plants that don’t receive enough revenue in the competitive market should take that as a signal to shut down, not change the rules.
The caucus called the proposal “an important first step” but said it “will not fully correct the existing market flaws nor fully provide the compensation necessary to maintain baseload resources.” Still, a failure to implement the plan “will continue to inequitably exacerbate the financial challenges” those units face, the lawmakers said.
While Ott did not specifically address PJM’s price-formation proposal, he acknowledged “there is room for markets to more sharply define power grid requirements.”
“Efforts are underway to improve wholesale market price efficiency for all the resources that rely upon the wholesale market to compensate them for their services, and appropriately to provide transparent investment signals,” he assured the legislators.
In his market report, Monitor Joe Bowring said the changes were not based on market flaws. Nearly 79% of the $24.7 million in uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.
“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.
FERC Resilience
The caucus also applauded PJM’s proposal as “entirely consistent” with the state legislature’s resolution in October calling on FERC to address the U.S. Department of Energy’s Notice of Proposed Rulemaking to financially support baseload generation. FERC denied the NOPR request in January but opened a docket to investigate concerns about the resilience of the nation’s energy grid.
The caucus endorsed the new docket as “an early step” and said it plans to press for any recommended changes that emerge from it.
“We are encouraged that FERC valued our concerns,” the caucus wrote. “You should know that as elected lawmakers ultimately responsible for our commonwealth’s energy policy, we will engage in the discussion and strongly support urgent implementation of critical findings.”
CARMEL, Ind. — After six months of little progress, stakeholders are now asking MISO to consider changing its billing practices to reflect how behind-the-meter resources use the transmission system.
But the RTO says it’s still collecting stakeholder input before it develops an official stance on multiple BTM measures.
“In large part, we’re still in listening mode here,” MISO Director of Planning Jeff Webb said at a March 14 Planning Advisory Committee meeting.
The RTO is still working with stakeholders to determine whether it should account for net or gross BTM load when it assesses network integration transmission service.
“I think that’s the debate here: whether behind-the-meter uses the transmission system for load, uses it sufficiently enough or uses it on peak,” Webb said. “Under what circumstances are costs incurred [from load typically served by BTM generation] when building the transmission system?”
The RTO must also settle on planning study assumptions for both registered and unregistered BTM generation and determine whether BTM retirements should be subject to a formal Attachment Y notice and subsequent reliability studies.
Last year, WEC Energy Group proposed that all resources be required to register with MISO as a network resource before being authorized to fulfill capacity obligations. That proposal aligns with an existing RTO plan to implement a one-time deliverability test for BTM generators that could trigger a requirement to acquire network service in an upcoming capacity auction. (See WEC Takes Stab at MISO Behind-the-Meter Definition.)
Webb said MISO will continue to discuss how to plan for BTM generation at the PAC’s April meeting and that the conversation would likely extend until the end of the year.
“We’ll make some sort of strawman proposal and let people beat up on that for awhile until we get something,” Webb said. “Let’s keep the dialogue going here.”
Stakeholders: Tx Charge Rewrite?
The question of how to bill BTM generation for transmission use sparked a larger conversation on revising transmission use charges in the face changing load shapes in MISO.
Veriquest Group’s David Harlan said MISO is headed for a future of more complex and “spiky” load shapes attributable in part to BTM generation, possibly requiring the RTO to reassess how it bills for transmission use.
“In the past we’ve expected load shapes to be fairly predictable and planned around peak. I think what we’re increasingly seeing is that when you connect to the transmission or distribution system, there’s an option value. You can either inject or withdraw. What’s the proper way of accounting for that option right?”
Wisconsin Public Service’s Chris Plante said his company has also been discussing a more nuanced approach to transmission billing.
“I think more and more we’re not just building transmission for the peak, but for energy withdrawal,” Plante said.
Representing Illinois Industrial Energy Consumers, Jim Dauphinais said he’d like to see the transmission charge issue contained within the broader BTM subject, noting that MISO’s Regional Expansion Criteria and Benefits Working Group is responsible for proposing transmission cost-sharing policies.
Webb said he supported limiting the issue to how MISO plans for and bills for BTM generation ― for now.
“I think maybe we bite off what we can here,” Webb said. “I think we’re in a — every generation says this — but we’re in a transitional period. There’s growing uncertainty about the load that we plan for.”
LOS ANGELES — CAISO’s proposal to extend its day-ahead market across the Western Energy Imbalance Market (EIM) could be tailored to uniquely fit a region historically resistant to organized markets, a key participant in the roll-out of the EIM said.
The ISO’s Extended Day-Ahead Market (EDAM) proposal could also be done without the political and economic entanglements involved with an RTO, Portland General Electric Director of Transmission Services Sarah Edmonds said during a March 9 public meeting of the EIM Regional Issues Forum (RIF). It could strike a balance between an ISO transmission access charge and a full RTO construct, she said.
“It is possible that with EDAM, a different construct will be born,” Edmonds said, adding that her comments reflected her own opinions, but they are “illustrative of the kinds of questions and issues the EIM community would be looking at” to determine their interest in day-ahead market participation.
In her previous job as general counsel for PacifiCorp, Edmonds served on the EIM’s Transitional Committee, which advised CAISO’s Board of Governors on the development of the market’s governance structure.
A “winning feature” of the EIM has been that participating balancing authority areas retain their responsibilities and control, Edmonds said, pointing also to the benefits of voluntary participation and no exit fee. But as they explore EDAM, industry participants will need to address the many issues around how excess transmission capacity is shared. (See CAISO Plan Extends Day-Ahead Market to EIM.)
As for an RTO, the issue of governance — which was still being debated in the California legislature when last year’s regionalization effort stalled — is “center stage,” Edmonds said. Lawmakers are working on new legislation this session. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
Governance is important because “the power of who gets to decide what issue is a big deal when you are talking about what comes with a full regional ISO,” Edmonds said.
Industry stakeholders still have many questions about transmission development and costs in a Western RTO because of the longer transmission lines, distance between loads and other planning considerations such as increased adoptions of distributed energy. Other complications include state roles in resource adequacy planning, transmission access charges and a regional transmission planning framework, she said.
“These issues really come up and are of particular concern in a regional ISO context,” she said, adding that there is also a “deeply ingrained culture of self-determination in the West.”
‘A Lot of Work’
Kathy Anderson, Idaho Power systems operations leader, told the RIF that her utility has been working on EIM implementation for two years and is due to go fully live on April 4, having shifted the date from April 1 because of the Easter holiday. One of the uses of the market will be to market renewable energy from qualifying facilities under the Public Utilities Regulatory Policies Act.
Anderson told the forum that the two-year process to integrate into the EIM has not been easy.
“I don’t think I really appreciated it until I was right in the middle of it. It was a lot of work,” Anderson said. “There were very few places in the company that we didn’t touch with this.”
The company employed three full-time external contractors and hired 6 employees to work directly on the EIM. It also required new software applications and outage management system.
Idaho Power and Canadian marketer Powerex have been in parallel operations with the EIM, in preparation for going live early next month. (See EIM Participants Seek Resource Test Tweaks.)
SPP’s Board of Directors and Members Committee on Tuesday approved a set of conditions that will guide Mountain West Transmission Group’s pending membership into the RTO.
SPP said the board’s endorsement during a special meeting in Dallas represents “a vote of confidence in the value of Mountain West’s membership and the benefits it will bring to SPP’s existing members, the Mountain West entities” and their customers.
COO Carl Monroe, who has been leading the RTO’s team during the negotiations, told RTO Insider he has been pleased with the work so far.
“We have been able to alleviate some of [Mountain West’s] concerns with joining SPP,” Monroe said Wednesday. “We’ve been able to work together and move forward. We’re pleased to come to this point, where we have general agreement of the things that are required to have Mountain West join SPP.”
The board approved 18 policy statements and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. The RTO’s Corporate Governance Committee and working groups will coordinate the work through the normal stakeholder process.
Changes to SPP’s Governing Documents Tariff will be presented for approval by stakeholder groups prior to going to the Members Committee and board.
The policies govern the terms of SPP membership, governance, the cost to operate the four DC ties in the SPP footprint, transmission planning and resource adequacy, and rates and revenue. SPP’s Regional State Committee would be expanded to include state commissioners from the Mountain West region.
SPP has scheduled a webinar on March 22 to provide further detail on the policies.
SPP and Mountain West members have been meeting behind closed doors since October to discuss the move. Monroe told stakeholders in January that a small negotiating team had been working to resolve a subset of “real contentious” issues. The Mountain West entities have suggested several governance changes important to their side of the footprint. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
Mountain West has said studies have shown participating in SPP’s markets and efficiently using the DC ties between the two footprints would yield annual savings of $80 million to $154 million for its members. The entities also expect to realize additional benefits from regional transmission planning and SPP’s other services.
SPP has estimated its current members could receive more than $500 million in total net benefits over the first 10 years of Mountain West’s membership through reduced administrative costs because of a larger customer rate base, adjusted production cost savings from east-west energy exchanges and capacity cost savings from increased load diversity.
The RTO projects it will take about two years to fully integrate the Mountain West entities as members, but it plans to begin reliability coordination services in late 2019.
SPP currently serves a 546,000-square-mile, 14-state region. Mountain West’s membership would add 165,000 square miles, 16,000 miles of transmission lines, 21 GW of generating capacity and parts of three more states (Arizona, Colorado and Utah) to the RTO’s footprint.
Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 it was pursuing membership in SPP, and discussions entered a public phase in October. (See SPP, Mountain West Integration Work Goes Public.)
New York stakeholders on Monday wrestled with the complex issue of how to evaluate the impact of a carbon charge on the dispatch of energy resources — especially in neighboring regions.
It was part of an ongoing effort by the Integrating Public Policy Task Force (IPPTF) to determine how to price carbon emissions into NYISO’s wholesale electricity market.
The group, a joint effort between NYISO and the state’s Department of Public Service, also discussed a method for calculating marginal emission rates, the allocation of carbon revenues and the effect of carbon pricing on customer bills — all part of “Track 5” of the carbon pricing initiative.
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The group also touched on issues related to “Track 4,” which covers the interaction of carbon pricing with other state and regional programs, such as the renewable energy credit and zero-emissions credit programs, as well as the Regional Greenhouse Gas Initiative.
Assumptions and Metrics
“We are interested in looking at not just the financial impacts but also at what happens to emissions,” said task force co-chair Nicole Bouchez, NYISO market design specialist.
“How do we assume the cases?” Bouchez asked. “Do we assume there’s a change in RGGI or not? In realization that we’re not going to be able to run dozens of permutations, what are the key assumptions?”
If the group “ends up modeling emissions in neighboring regions, for example in Ontario, which trades with MISO, then you have to model all of MISO’s resources,” she said. “While Ontario may look like a low-carbon import … if all it’s doing is causing MISO coal use to go up, then not so much.”
Marc Montalvo, representing the DPS Utility Intervention Unit, said, “If we’re designing a policy and implementation, if success is highly dependent on having perfect or near-perfect information about our neighbors’ emissions rates and those kinds of things, then it’s probably not a good policy in the first instance.”
Bouchez said the group’s May 7 and 21 meetings would focus “on how to structure the analysis, what questions, what metrics we’ll be reporting, etc.”
Defining Impacts
During a discussion of the impact of carbon pricing on consumer costs, Bouchez said the ISO’s locational-based marginal pricing (LBMP) represents “only the beginning of impacts on consumers because we’re also going to be looking at the return of these residuals associated with a carbon charge to consumers, so you can’t just look at the LBMP increase on its own.” The “residuals” refer to leftover money refunded to load under a carbon pricing scheme.
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Representing a coalition of large industrial, commercial and institutional energy users, Couch White attorney Michael Mager said his clients were seeking “two big things” from the impact analyses. First, “a thorough, unbiased analysis” of the impacts on market prices and what consumers are paying.
“And the second piece is, what are the emission reductions, if any, that reasonably could be anticipated if this were to be done,” Mager said.
New York could see some really material carbon reductions if it starts retiring unused RGGI allowances, he said.
“On the other hand, if nothing is being done to RGGI whatsoever, and it’s just going to simply reduce the price of allowances that are going to be then used up by other states such that there’s little to no reduction in carbon throughout the RGGI region, then this whole effort strikes us as somewhat symbolic and not getting much for any price impacts,” he said.
Howard Fromer of PSEG Power New York asked, “Consumer impacts compared to what?
“And the what is not identified here,” Fromer said. “Obviously, the what, in my mind, has to include the fact that New York state right now is already spending and writing checks on a monthly basis and potentially, over the period that we’re talking about, could be spending billions of dollars.”
Fromer said that, aside from considering dispatch issues, the task force process also needs to consider the impact of a carbon charge on price signals, demand response and investment in the state’s 40,000-MW generation fleet.
No Pot of Money
Stakeholders asked how the trend of increasing electrification — in the transportation sector, for example — should affect pricing carbon into the wholesale market.
Bouchez said many experts have told her the price of electricity has very little to do with electrification.
Bob Wyman of Dandelion Energy countered that electricity prices definitely affect consumer choices in New York City, where Consolidated Edison learned that city residents who install heat pumps use them for air conditioning but simply turn them off in winter because of high electricity prices for heating.
“Whether this approach is complementary or designed to supplant the mandated programs [such as the state’s Clean Energy Standard] … to the extent that you are supplementing the existing programs, the issue is always about what are the incremental benefits, does it affect dispatch, new investment, how are the effects by zones, and you have to address those transition overlap and windfall revenue questions as part of the impact analysis,” said James Brew of Nucor Steel Auburn.
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He said New York is relatively unique in trying to pursue both mandated and market programs, which means any analysis has to examine how the two programs interact.
David Clarke, director of wholesale market policy at the Long Island Power Authority, said carbon revenue collections within RGGI states would be a useful metric for examining the cost of abatement.
“I know we’re going to be looking at how much folks are paying for carbon allowances within New York as kind of the pot of money that we’re going to be splitting, but it would also be useful, depending on what scenario you are running, to find out what folks are collecting in terms of RGGI revenues within the other RGGI states,” Clarke said.
“There will be no pot of money,” Bouchez said. “I’ve been talking about them as residuals, which is how NYISO sees them, residuals being the difference between what we collect and what we pay out. How you allocate that within the wholesale settlements is a question. Do you give it back on a per-megawatt-hour basis? Do you give it back based on the impact of the increase in the LBMP?”
Warren Myers, DPS chief of regulatory economics, said that the joint staff are “nowhere near having an answer” on how to integrate multiple analyses into something useful but that “the work would get done by rolling up our sleeves” over the next few months.
The task force will next meet on March 19 to discuss Track 5 at NYISO headquarters.
