CAISO last week experienced its first “Stage 1” grid emergency in nearly a decade, days after Southern California Gas warned that continued restrictions on its Aliso Canyon storage facility could deprive the region’s natural gas-fired generators of enough fuel to avoid blackouts this summer and winter.
The ISO on May 3 issued an emergency notice from 7 to 9 p.m. after grid operators determined that they could not meet load and operating reserve requirements. At the time, load was 2,000 MW above forecast and nearly 800 MW of imports never materialized, compounded by the outage of a 330-MW gas-fired plant.
About 800 MW of demand response was “critical” in meeting grid needs, according to CAISO.
“It was unusual that the issues began developing around the peak, and demand wasn’t ramping down much, but solar was ramping off faster than what the thermal units online at the time could keep up with in serving load,” CAISO spokesperson Steven Greenlee told RTO Insider.
That forced the ISO to dip into reserves and slip below required reserve margins, prompting it to declare a Stage 1 emergency.
“This stage allows us to trigger the demand response interruptible programs, which are managed by the investor-owned utilities,” Greenlee said.
It was the first such emergency notice issued since an extremely hot day in August 2007. In a Stage 3 emergency — the most serious — utilities are warned of load curtailments.
Relief Well 2 at Aliso Canyon | SoCalGas
While the ISO has drawn no link between the emergency and ongoing constraints within the pipeline system that feeds Southern California’s gas fired generation, the timing was uncanny. The event came less than a week after SoCalGas cautioned state and ISO officials that it might be unable to meet system needs during peak seasons for electricity demand. The gas utility contended that a recent state-directed reliability assessment of its network relied on overly rosy assumptions.
SoCalGas said a prohibition on gas withdrawals from its Aliso Canyon facility and limited injections there might prevent it from responding to gas supply and demand imbalances. The leak at the gas storage facility, discovered in October 2015 and plugged in February 2016, led to increased use of the La Goleta, Honor Rancho and Playa del Rey storage facilities, where reserves are now 40% lower than a year ago.
“The state was lucky this past year to have experienced a mild summer and winter,” SoCalGas said in an April 28 letter to CAISO, the California Public Utilities Commission and the California Energy Commission. “For the upcoming summer and winter seasons, Californians cannot rely on luck, and energy reliability should not depend upon mild weather conditions.”
In response, the agencies have requested that SoCalGas present its findings at a May 22 workshop on summer reliability to be held in conjunction with the Los Angeles Department of Water and Power.
“The issues raised by SoCalGas are part of ongoing data requests the joint agencies have made of the utility,” the agencies said in a joint statement. State officials “are working in close coordination to address the importance of natural gas and electricity reliability for Southern California as we look forward to the summer and next winter.”
The National Oceanic and Atmospheric Administration says there is a 60 to 70% chance that temperatures will be above normal this summer.
SoCalGas also warned state agencies of safety concerns stemming from operating its pipeline system at maximum pressure. The availability of storage injection capacity reduces the risk of over-pressurization on natural gas lines.
“Operating close to a pipeline’s maximum pressure is a pipeline safety and compliance concern,” the company said.
The natural gas utility said that the state had assumed “perfect operating conditions and optimal market conditions” when asking it to do a recent reliability assessment. This could lead the agencies to be overly optimistic and put gas and electricity supply at risk.
The analysis assumed full utilization of gas receipt points, a theoretical maximum that is not reasonable for operational planning and is dependent on the behavior of suppliers, shippers and customers. An assumed 1.5 Bcfd withdrawal rate would require significantly higher inventory at Playa del Rey and is not possible if storage inventories are not replenished.
The assessment also assumed that Aliso Canyon would not be used this summer, but held in reserve, which the utility said is “not prudent.” The facility’s low inventory, new well configuration and prohibition on injection will likely reduce withdrawal capacity. The assessment also used daily average capacity that does not address hourly customer demand fluctuation, SoCalGas said.
The company also pointed out recent events that increased natural gas demand without warning. In July, high temperatures and humidity pushed up electricity demand and cloud cover limited solar generation, leading to natural gas demand 11 to 25% above plan. Storage withdrawals were needed to handle the variability. In August, a fire in the Cajon Pass affected transmission lines and caused a 25% spike in natural gas demand from generators over a five-day period.
Still, state officials still considered that Southern California’s grid weathered last summer without any major incidents, attributing the success to measures taken after the 2013 shutdown of the San Onofre nuclear plant, deployment of new energy storage and increased use of automated DR. (See Sandoval: Nuke Shutdown, Auto-DR Aided Aliso Canyon Response.) CAISO also relied on temporary tariff provisions meant to improve schedule coordinating, which FERC last November extended by another year. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)
The fact that one broken pipe at Aliso Canyon led to widespread reliability concerns over an extended time demonstrates the precarious balance between fuel supply and electricity scheduling, weather and unforeseen events with which grid operators must continually grapple.
WASHINGTON — D.C. Circuit Court of Appeals appeared sympathetic to FERC’s request to dismiss a challenge to its ruling on SPP’s Order 1000 rules, questioning the standing of the plaintiffs.
The court heard oral arguments Friday in a dispute over provisions in SPP’s Tariff that recognize state and local right-of-first-refusal laws (15-1157).
LSP Transmission, a subsidiary of independent transmission developer LS Power, sued FERC in June 2015 over three Order 1000 compliance filings submitted by SPP (ER13-366). LSP argued that the commission’s acceptance of the state ROFR provisions illegally excludes certain projects from the competitive process that SPP established in response to Order 1000.
Lack of Standing?
While LSP attorney Michael Engleman of Squire Patton Boggs and FERC attorney Holly Cafer were given the chance to argue the merits of LSP’s complaints, much of the hour-plus hearing was taken up by Judges David Tatel and Nina Pillard’s questions over FERC’s argument that the company lacked standing in the case. (Judge Robert Wilkins, who was not present in the courtroom because of a death in his family, listened in by phone.)
Tatel and Pillard seemed sympathetic to FERC’s argument that, because LSP had not suffered direct harm as a result of the commission’s orders on the compliance filings, it lacked standing to challenge them. Before Engleman could get into the details of his argument during his opening remarks, Tatel interrupted him, asking him to address the standing argument.
Tatel said FERC’s orders may be illegal, but they have to cause injury in order for LSP to have standing. He repeatedly asked what sort of relief the court could provide to LSP. Pillard said that LSP might not like the regulatory regime set up under Order 1000, but that that was a separate argument.
Engleman argued that LSP is harmed because it is excluded from bidding on certain competitive projects that SPP determines are subject to an incumbent developer’s ROFR under state and local laws. He said the court could provide relief by remanding the orders on compliance back to FERC for review or vacating the commission’s acceptance of the provisions in the RTO’s Tariff.
Engleman admitted, however, that LSP had not been denied being selected for a project under SPP’s competitive process. Cafer agreed with the judges when they asked her if LSP would have standing had it been denied a project, as it then would have suffered direct injury. But she also said the company wouldn’t be harmed if SPP determined that a project would not be competitively bid because of a local ROFR law.
“This court has held, in circumstances also involving compliance with a commission rulemaking that reformed transmission planning processes, that the petitioner must ‘have an active application for a transmission project’ to demonstrate an injury-in-fact for the purpose of constitutional standing,” Cafer said in a brief to the court. “LS Power has not made this showing.”
Engleman also stopped short of arguing that state ROFR laws are unconstitutional under the dormant Commerce Clause, something that former Chairman Norman Bay alluded to in a concurrence with the commission’s acceptance of SPP’s second compliance filing.
“State laws that discriminate against interstate commerce — that protect or favor in-state enterprise at the expense of out-of-state competition — may run afoul of the dormant Commerce Clause,” Bay said. “The commission’s order today does not determine the constitutionality of any particular state right-of-first-refusal law. That determination, if it is made, lies with a different forum, whether state or federal court.”
State vs. Federal
The judges were skeptical that they could vacate FERC’s acceptance of SPP’s Tariff provisions. They seemed sympathetic to Cafer’s argument that “Order 1000 wasn’t as expansive as LS Power hoped it would be.”
Engleman, in fact, had argued on behalf of FERC before the court in March 2014, with LS Power supporting Order 1000’s elimination of federal ROFR policies. (See Appellate Court Skeptical of Order 1000 Challengers.)
A three-judge panel including Pillard upheld the order, including against challengers who said that it did not mandate that load-serving entities’ input on transmission projects be heeded — an argument to which Pillard had seemed sympathetic.
Cafer said Order 1000 only eliminated federal ROFRs and does not pre-empt state law. Here, however, there seemed to be some skepticism from the judges, especially Pillard, who said if the order did pre-empt state law, it would be redressable by the court.
While federal law pre-empts state law when the two conflict under the Constitution’s Supremacy Clause, there are limited circumstances when rulemaking by federal agencies can do so.
Pillard asked Cafer if Order 1000 “effectively” pre-empts state laws — even if FERC didn’t intend to — by making the competitive process, with its regional cost sharing, the only choice for utilities. She wondered under what circumstances an incumbent developer would choose recovery through ratepayers over cost allocation to the beneficiaries of the project.
Cafer responded that state laws vary. Some states simply allow a ROFR to projects within a utility’s service area; others confine it to existing rights of way.
Engleman, however, argued that FERC has been inconsistent over whether RTOs can exclude projects subject to state ROFRs from the competitive process. He pointed out that FERC had denied SPP’s first compliance filing in 2013 but later reversed its position — without Commissioner John Norris — in October 2014 with SPP’s second filing. Norris had dissented in a similar, earlier order regarding PJM, saying the commission’s recognition of state ROFRs undercut Order 1000’s purpose. (See Order 1000 Reversal: Reality Check or Surrender to Incumbents.)
E Barrett Prettyman D.C. Circuit Courthouse
If the D.C. Circuit rules in favor of FERC, it is unclear whether LSP would appeal to the Supreme Court: The company lost a similar case regarding state ROFR provisions in MISO’s Tariff before the 7th U.S. Circuit Court of Appeals — a case the Supreme Court declined to hear on appeal in March. (See Supreme Court Refuses to Hear ROFR Challenge.)
The Supreme Court, however, would be much more likely to hear an appeal if the D.C. Circuit ruled in LSP’s favor.
OGE Energy hopes that a proposed legislative review of the Oklahoma Corporation Commission will relieve some of the company’s frustration regarding the regulator.
The state Senate in April unanimously approved a bill to create an executive-level task force to examine the OCC’s structure, mission, budget and staffing. OGE has complained recently about commission delays in approving rate cases, forcing the state’s utilities to implement interim rates that often have to be refunded following final regulatory approval.
The legislation still faces a final vote in the House of Representatives before it can be sent to Gov. Mary Fallin for her signature.
OGE is “fully supportive” of the bill, CEO Sean Trauschke told financial analysts during a May 4 first-quarter earnings call.
“It is not intended to undermine the OCC, but it’s a legislative effort to make it work better,” he said. “I am confident Oklahoma’s regulations will improve, but it won’t happen overnight.”
Trauschke said this would be the first full review of the OCC since its creation in 1970. The task force would consider whether commissioners should be appointed rather than elected, and whether to increase the commission’s seats from the current three.
“Are they funded properly? Are they regulating the right industries?” he said, noting the OCC currently oversees oil and the electric, gas and telecommunications utilities. “I do think the legislation will really address the efficiency and speed in which things are completed.”
Oklahoma State Legislature
As currently written into the bill, the seven-member review group would be led by Oklahoma’s secretary of energy and environment and include two legislative members, the state treasurer, attorney general and an appointee from the OCC. The task force would file a final report by September 2018.
Trauschke deferred several questions on Enable Midstream, its gas gathering and processing joint venture with Texas’ CenterPoint Energy, to its majority partner. CenterPoint has been looking to sell or spin off its 55.4% share of the venture, in which OGE holds a 25.7% limited-partnership interest in addition to its 50% management interest in Enable’s general partnership.
OG&E linemen | OG&E
Enable on May 3 reported a first-quarter profit of $120 million, up from $86 million in the first quarter of 2016. Revenue increased to $666 million from $509 million a year ago.
Better margins at Enable and lower depreciation expenses at Oklahoma Gas & Electric boosted OGE’s profits for the first quarter. The company had net income of $36 million ($0.18/share), compared to $25.2 million ($0.13/share) in the first quarter of 2016.
OG&E contributed earnings of 8 cents/share, up from 3 cents/share the year previous, and Enable pitched in with 10 cents/share, compared to 9 cents/share a year ago.
Wall Street reacted by driving OGE’s shares down 66 cents from Wednesday’s close of $34.62 to $33.96 in after-hours trading Friday.
CenterPoint Says Wait on Enable Update
CenterPoint is still on track to provide an update on its Enable ownership stake in August, when it will report second-quarter earnings, CEO Scott Prochazka told analysts during a May 5 call.
“We have talked about the list of options being a sale, a spin or keep,” Prochazka said. “And even under the keep situation, we continue to work on things that would reduce the variability associated with our ownership of Enable.”
The Houston-based company said Enable contributed 10 cents/share in the first quarter, compared to 9 cents/share the year prior. Prochazka said daily volumes of gas gathered, processed and transported were all up from the previous year, and noted the business recently announced a new project in the Texas-Oklahoma Panhandle’s Anadarko basin that adds 400 Mcfd of processing capacity.
“We continue to believe Enable is well positioned for success in [its] industry,” Prochazka said. “I think it’s fair to say … that improvements in the industry and changes that are occurring at Enable are both favorable for us, from an ongoing ownership perspective.”
CenterPoint reported earnings of $192 million ($0.44/share) for the first quarter of 2017, as compared to a profit of $154 million ($0.36/share) over the same period last year.
The company has asked for electricity and gas rate hikes to help recoup $480 million spent on transmission infrastructure in 2016 and $16.5 million spent on its natural gas distribution business.
CenterPoint’s share price closed at $27.98 on May 4 and dropped to $27.72 shortly after the earnings call the next day, before finishing at $28.05 in after-hours trading.
WASHINGTON — Last week’s FERC technical conference focused on tensions between state clean energy policies and RTO/ISO markets in the East. Yet witness after witness cited California to make their points — often in a context unflattering to the Golden State.
Exelon cited the closing of the San Onofre nuclear plant — and the resulting increase in carbon emissions — to defend the subsidies of its nuclear plants in New York and Illinois.
Charles River Associates consultant Robert Stoddard said California’s duck curve is the result of “a pricing failure.”
“Out-of-market subsidies have been growing in the East. If not addressed, these subsidies will undermine the competitive wholesale markets, turning the Eastern markets into a command-and-control structure much like California is today — i.e., the states mandate when and where new generation will be built and the technology type that will be used for that generation,” Hill said.
“In California, essentially all investment, including investment in new conventional generation, is supported by mandate-driven long-term contracting schemes. Because the policies that bring about this substantial investment are divorced from competitive wholesale markets, it has led to the paradox that while retail rates are rising rapidly to reflect the costs of mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources without long-term contracts, many of which are critical for reliability) is increasingly threatened. Addressing the revenue shortfall for existing units that are needed for reliability likely will entail additional out-of-market mechanisms.”
Independent consultant Roy Shanker also called out California, saying the state Public Utilities Commission has “explicitly stated that while a transparent, open and competitive central capacity market might be more efficient in the long run, it preferred to maintain a less efficient bilateral capacity market structure because of short run cost savings.”
“Similarly it expressed concerns that a centralized market under the CAISO might open the door to undesirable FERC jurisdiction and authority,” he added.
Shanker cited California’s increase in negative energy pricing, which nearly doubled to 1,000 hours in 2016 from 588 in 2015.
“In general the state subsidized or mandated units under long-term contracts participate as price takers in both energy and/or capacity markets, driving down prices, often below zero in the energy market,” he said.
Innovation
Hogan (left) and Lawrence Makovich, IHS Markit | RTO Insider
Some witnesses, however, looked to California for innovation and leadership.
PJM officials said they are considering use of a “border adjustment” similar to that approved by FERC for CAISO to add carbon constraints for states that want to pursue climate goals.
And Harvard University’s William Hogan said the success of CAISO’s Western Energy Imbalance Market in reducing curtailments of solar and wind “is a case in point that reinforces the vibrancy and the importance of real-time markets organized around the principles of economic dispatch.”
WASHINGTON — ISO-NE presented its proposal for a two-tiered capacity auction at last week’s FERC technical conference, saying it would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax.
The RTO released a 33-page description of the Competitive Auctions with Subsidized Policy Resources (CASPR) proposal a week before the conference.
The proposal, developed with Market Monitor David Patton, would provide financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and permanently exit the capacity market through a two-stage, two-settlement process. The RTO said it could be in place for Forward Capacity Auction 13 in February 2019.
Although it is not the only short-term proposal being considered by policymakers in New England, it appears to be the clear front-runner. It survived the technical conference without coming under attack and is the “farthest along” among the stakeholder initiatives in the three Eastern grids, said acting FERC Chair Cheryl LaFleur at the close of the two-day conference (AD17-11).
Although the New England Power Pool has not taken a position on the proposal as a group, Participants Committee Chair Tom Kaslow in January presented a similar “paired retirement election” concept on behalf of his company, FirstLight Power Resources.
The proposal arose out of NEPOOL’s Integrating Markets and Public Policy (IMAPP) initiative, launched last August in response to state officials’ concerns that consumers could end up facing excessive costs for meeting state renewable procurement mandates and to generators’ fears that out-of-market resources will suppress capacity prices.
The CASPR proposal was designed to address the concern that consumers would end up “paying twice” for capacity — once for resources that clear in the FCA, and a second time for subsidized state-mandated renewables that could be prevented from clearing by the minimum offer price rule.
Failing to coordinate ISO-NE’s capacity market with state renewable procurements would lead to a “train wreck … [that] would probably be the end of the markets as we know them today,” said Jeffrey W. Bentz, director of analysis for the New England States Committee on Electricity.
Drivers and Goals
New England states are set to procure more than 3,600 MW of nameplate renewable generation:
Connecticut is negotiating out-of-market contracts for 375 MW of nameplate clean energy capacity.
State regulators in Massachusetts, Connecticut and Rhode Island are considering out-of-market contracts for 460 MW of nameplate clean energy capacity resulting from their three-state solicitation.
Massachusetts’ 2016 energy bill required its utilities to purchase about 1,200 MW of new renewables, including onshore wind and hydropower and 1,600 MW of offshore wind. The state issued its first solicitation March 31; a second is expected by June 30.
‘Cash for Clunkers’
ISO-NE said it developed its proposal with a goal of avoiding excessive capacity spending and cross-state cost shifts while continuing its Forward Capacity Market and minimizing the price-suppressive effect of out-of-market subsidies.
In the first stage, ISO-NE would clear the auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the new second “substitution” auction, generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR.
Because the substitution auction will not use the MOPR, it will clear at lower prices than the primary auction, enabling existing resources to buy out their obligations at a lower cost in return for retiring.
The savings would in effect be a “severance payment” to the retiring resources, ISO-NE said. “The substitution auction might reasonably be viewed as an auction-based ‘cash for clunkers’ secondary market,” the RTO said, referring to the Obama administration’s 2009 program to encourage the retirement of older, gas-guzzling autos.
ISO-NE said it believes it can implement the proposal before March 2018, when the retirement window opens for FCA 13, which will acquire capacity for the delivery year beginning June 2022. “This timing is important given the anticipated schedule for substantial new state-sponsored resources to enter service in 2022,” the RTO said.
Questions about CASPR
CASPR attracted little opposition at the technical conference.
New Hampshire Public Utilities Commissioner Robert Scott said pointedly in his written testimony that he was taking no position on the proposal. “What I want is not to pay for Massachusetts’ and Connecticut’s policies,” he told FERC during live testimony.
CASPR was based on an idea submitted by NRG Energy last October, one of two two-tier proposals that consultant James Wilson evaluated for NESCOE. Wilson said that NRG’s proposal was an improvement on one submitted by public power representatives that he concluded would result in excessive costs and distort the incentives to submit competitive offers.
Wilson said the NRG proposal addressed the problem with public power’s handling of “tweener” resources — those that don’t clear because their offer prices fall between stage 1 and 2 clearing prices. But he said that comes at a cost: The scaling of capacity awards means all resources, including competitive and self-supply resources, receive reduced awards. Because of the reduction, “resource owners that need a certain minimum revenue may be inclined to raise their offer prices to make up for the pro rata quantity reduction,” Wilson said.
Other Proposals
NEPOOL says stakeholders have reviewed more than 17 proposals during the IMAPP sessions, many of them designed to “achieve” state policy in the wholesale market (long-term proposals), and “a few other” proposals such as CASPR to “accommodate” state-sponsored resources while addressing capacity market pricing concerns (near-term proposals).
Aside from the two-tier/paired retirement options, NEPOOL said the proposals fell into three categories:
Carbon pricing in the energy market: A carbon adder would be included in energy offers and reflected in clearing prices. The adder would be collected from carbon emitters and redistributed to ratepayers.
Carbon-Integrated Forward Capacity Market (FCM-C): A new zero-emission credit market would be integrated with the FCM to incorporate a forward signal for clean/renewable energy into the market.
Forward Clean Energy Market (FCEM): A new forward market for commitments to deliver clean energy that would support new or existing clean energy resources.
No to Carbon Pricing
Although New York and the New England states have been participating in the Regional Greenhouse Gas Initiative cap-and-trade carbon market since 2009, the RGGI emissions limits would have to be substantially reduced to make the resources sought by the states economic in the RTO markets, Patton said.
“We do not believe it is likely that the states will rely on the RGGI market or a carbon tax to achieve their public-policy objectives, although this would likely be the most efficient and effective approach,” Patton said.
Other New England stakeholders agreed with Patton’s prediction.
In an April 7 memo to NEPOOL, NESCOE outlined its opposition to “a FERC-jurisdictional tariff reflecting carbon pricing.”
“These concerns include risks to states’ ability to make their own determination regarding the implementation of their carbon-reduction laws. For example, as illustrated in recent years, a few market participants with an appetite and budget to litigate matters could seek to disrupt a design over which ISO-NE, NESCOE and NEPOOL find agreement. FERC could also seek to direct changes on its own initiative,” Bentz said.
“Conceptually, assessing a price for each ton of carbon emitted by an electric generator, and crediting those revenues to load that would be paying higher energy prices, seems simple to understand,” said Brian Forshaw, who appeared at the conference on behalf of public power agencies in Connecticut, New Hampshire and Vermont. “In a practical sense … there are substantial challenges associated with deciding on the initial carbon price and figuring out how to adjust the price over time to achieve desired carbon reduction levels, deciding who will get the rebates and in what form, and legal questions over whether the ISO has the authority to charge generators for carbon emissions.”
CLIPR
Charles River Associates senior consultant Robert Stoddard, who testified on behalf of the Conservation Law Foundation, briefed the commission on his proposed Carbon-Linked Incentive for Policy Resources (CLIPR). Under CLIPR, load-serving entities would pay state “policy” resources an energy price premium that would fluctuate based on the “marginal carbon intensity” (MCI) of the dispatch, “a direct analog to the LMP but computed as lbs-CO2/MWh instead of $/MWh.”
Stoddard said the proposal would address most of the problems with the carbon adder, with the clearing price determined by the market, “simultaneously removing administrative discretion and assuring that the prices paid are supporting the particular policy resources demanded.”
The incentive would likely be zero in hours with negative prices because the marginal resource is likely to be zero-emitting. CLIPR delivery rights could be traded bilaterally.
Bentz was intrigued by the idea and said he plans to discuss it in detail with Stoddard.
NextEra Energy and RENEW Northeast, a group of renewable energy companies and environmental interest groups, offered the proposal to create a FCEM.
RENEW Chair Seth Kaplan, EDP Renewables’ senior manager for regional government affairs, outlined the group’s proposal to FERC, in which he said the RTO, electric distribution companies and states would cooperatively manage resource procurements.
ISO-NE would study the network upgrades needed to connect renewable generation in the interconnection queue. When there is a competitive clean energy solicitation, EDCs and state regulators could consider competitive transmission solutions to address the network upgrades, agreeing to bear the cost under a public policy designation. The cost allocation would be identified by the opting-in EDCs and filed for FERC approval by the participating transmission owners as a participant-funded project.
In January, public power representatives presented a proposal to amend the FCM to ease bilateral contracting by LSEs with generation assets.
Next Steps
On April 7, NESCOE issued a memo saying that the states needed additional time to further study the long-term proposals presented to date.
NEPOOL said it will consider ISO-NE’s near-term proposal at its regular meetings beginning with the June Markets Committee meeting. In addition, NEPOOL said it expects discussions to continue at events over the next two months:
SPP stakeholders last week unanimously approved what could be the first MISO-SPP interregional transmission project, but hurdles still remain.
The Interregional Planning Stakeholder Advisory Committee’s May 3 endorsement of the 115-kV project in South Dakota matches a thumbs-up from MISO’s Planning Advisory Committee. (See MISO Stakeholders Give Go-Ahead on SD Interregional Project.) That leaves only approval from the SPP-MISO Joint Planning Committee — composed of representatives from the two RTOs — followed by an IPSAC review of a final report before the project can enter the regional review process.
The $5.2 million project would relieve congestion on a tie line shared by the Western Area Power Administration in SPP’s footprint and Xcel Energy in MISO. The project loops a Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence-Sioux Falls 115-kV line.
| MISO & SPP
The project was the only one of seven proposals to survive a coordinated system plan study conducted by the RTOs last year. Some of the projects failed to pass muster because of a $5 million threshold for interregional projects, a metric both RTOs are open to changing. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)
Much of the cost (81.48%) for the South Dakota line shifted to MISO with the recent approval of projects in its generator interconnection queue. The project has a 20-year benefit-to-cost ratio of 4.42.
Adam Bell, SPP’s interregional coordinator, told the IPSAC that the project’s cost estimate is study-level, and that a few specific outstanding details could change the final figure.
Several stakeholders raised concerns that the economic project may not address reliability issues, but Bell assured them the regional review would be “very much stakeholder-driven.”
“We used the most up-to-date power-flow models we had,” Bell said. “We ran it in every season and year and didn’t detect any reliability concerns.”
Bell also expects the final regional review to be ready for board-level action in October.
MISO, SPP Agree to M2M Improvements
SPP and MISO have reached an agreement on improvements to the market-to-market coordination process across their seam, David Kelley, SPP’s director of interregional relations, told the Seams Steering Committee last week.
Pending executive signoff, a memorandum of understanding will document the agreement, which Kelley stressed is not a “wholesale redesign.”
The RTOs’ M2M process is modeled after a similar process between MISO and PJM, and is designed to economically relieve congestion and align border prices. Under the current model, which began in March 2015, MISO has paid almost $20 million to SPP for creating congestion on the other side of the seam.
“Almost immediately, we noticed there were some issues we needed to deal with,” Kelley said. “Price convergence should be a result of effective market-to-market. You do market-to-market because the other market potentially has generation it can dispatch at a lower cost than the monitoring market.”
The MOU will target “ineffective real-time congestion management” on some of the 135 permanent M2M flowgates between the two RTOs, errors in settlement data calculations and difficulties in finding a common interpretation of certain sections of the interregional coordination process of the RTOs’ joint operating agreement.
| MISO & SPP
SPP and MISO staff have developed an alternate M2M procedure in which the monitoring RTO relies on ”market flow control” (redispatching generation within its footprint to a targeted level of market flow) rather than “total flow control” (redispatching generation within its footprint to maintain total flow on the flowgate) to help address volatility and “power swings” on certain flowgates. The process is limited to instances where M2M “does not resolve, or even aggravates, reliability concerns.”
Kelley said the monitoring RTO’s control of a flowgate’s total flow works best when it has the predominant flow.
“There are situations where we experience power swings, where a renewable wind resources swings flow on a flowgate back and forth,” he said. “One way SPP has found [to mitigate power swings] is market flow control.”
Other improvements in the MOU include forming a technical committee to address issues as they arise and following a standardized process for future resettlement requests.
SPP, MISO Studying Overlapping Charges on the Seam
SPP and MISO are currently studying a year’s worth of data to analyze overlapping charges along their seam. The result, covering the period between the March 2015 open of M2M through February 2016, will be presented at a May 31 JOA meeting.
“The research could help with market-to-market,” SPP’s Gerardo Ugalde said. “We’re doing extensive analysis to ensure the interface picked is the most accurate representation of imports in and out of SPP.”
Ugalde told the seams committee that each market should charge for congestion based on the redispatch of their respective generation resources. When a host market dispatches a resource, that resource should get either a charge or a credit based on the flowgate it is affecting.
When the host market pseudo-ties out a resource, the host market will charge or credit for the congestion from the source to the interface, covering any congestion charges to export the power out of the market. The attaining balancing authority will dispatch the resource, and the resource will get either a charge or a credit based on the flowgate it is affecting.
Ugalde said MISO and PJM have proposed a solution in which the attaining market refunds the marginal congestion component (MCC) between the interface and the resource. Under that plan, the host charges the transmission customer from the resource to the host border, the attaining market charges the MCC from the resource to the attaining market load, and the attaining market then rebates the MCC from the resource to the host border.
“If you have a resource, the interface is the border,” Ugalde explained. “If you go resource-to-border, and border-to-load, you’ve minimized the amount of overlap.”
March’s M2M Bill: $3.98 Million for MISO
SPP recorded its second highest month of M2M payments from MISO, collecting $3.98 million for congested flowgates between the two RTOs in March. The month accounts for slightly more than 20% of the $19.3 million MISO has paid SPP since the two began the M2M process in March 2015.
Most of the March payment ($3.2 million) came from a congested SPP flowgate in southeastern Kansas, caused by high winds and several line outages in the area, including a 345-kV line from Neosho County, Kan., into Oklahoma. The permanent flowgate was binding for 365 hours, representing almost half the 741 hours for all binding temporary and permanent flowgates between the two RTOs.
SPP Director Wins Illinois Volunteerism Award
SPP Director Larry Altenbaumer was honored recently with a Governor’s Volunteer Service Award for his community efforts in his hometown of Decatur, Ill. The ceremony took place April 25 at Illinois’ Old State Capitol with Gov. Bruce Rauner.
Altenbaumer was honored for his leadership of Grow Decatur, a collaborative growth and development effort transforming the city through improved economic and quality of life. Through the initiative, the community identified 10 areas as imperative to the city’s resurgence and has since formed community teams to address the issues.
“I accept this award on behalf of the dozens of other Decatur community volunteers who I have had the privilege of working with over these past several years on the Grow Decatur initiative,” he said.
Altenbaumer is vice chair of SPP’s Board of Directors, on which he has served since 2005, and chairs the Finance Committee. He retired in 2004 as president of Illinois Power.
Exelon is encouraged by Energy Secretary Rick Perry’s order to study if government regulations and policies are forcing baseload power plants into early retirement and thinks courts will uphold the programs that provide zero-emission credits benefiting its nuclear power plants, executives said during the company’s first-quarter earnings call Wednesday.
The executives also said Exelon’s bids in PJM’s upcoming capacity auctions will reflect the economic needs of its plants, even if that leads to some of its plants not clearing the auction.
Exelon CEO Christopher Crane said Pepco Holdings Inc., which the company acquired a year ago, has only rate cases in D.C. left from its first planned cycle of rate filings under Exelon and has started the second cycle at its Maryland and Atlantic City Electric subsidiaries.
Crane also said Exelon is not concerned that the bankruptcy of Westinghouse, which is one of the suppliers of fuel for its nuclear plants, will impact its ability to get fuel for the plants.
“We continue to competitively bid our reactor fuel suppliers … and we move that around based off of pricing,” Crane said.
Exelon’s first-quarter results exceeded earnings and revenue estimates. Its adjusted operating earnings of 65 cents/share beat the Zacks consensus estimate of 61 cents but were down from 68 cents the year prior. Its net income was $1.07/share, up from 19 cents/share in 2016. The company’s revenue was $8.76 billion, beating the Zacks consensus estimate of $8.48 billion, and up 16.5% from $7.48 billion a year ago.
“We’re off to a great start in 2017,” Crane said.
Crane and Joseph Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, made positive comments about Perry’s recent memo directing department staff to conduct a 60-day inquiry into “the extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.”
The memo has been interpreted by foes of coal-fired and nuclear power plants as an attempt to find reasons for the department to support both.
Exelon has the nation’s largest nuclear generation fleet and its plants have faced pricing pressure from cheap natural gas and the plunging costs of utility-scale solar arrays and wind farms.
“Energy Secretary Perry’s recent directive to look at the importance of preserving baseload generation is early but encouraging,” Crane said. “We appreciate the secretary’s focus to promote needed market reforms to compensate these assets.”
Exelon has argued that its nuclear plants need to be compensated for their ability to provide emissions-free power, and New York and Illinois have established zero-emissions credits to do that. The programs have been challenged by other power providers and some environmental groups, although other environmental groups have backed them.
On March 31, Exelon assumed ownership and management of operations of the James A. FitzPatrick Nuclear Power Plant in Scriba, New York, which is eligible for zero-emission credits. | Entergy
Crane said a New York federal judge heard oral arguments March 29 on Exelon’s motion to dismiss a lawsuit challenging ZECs. “We made strong arguments at this hearing and believe the law is clearly on our side,” Crane said. (See Federal Suit Challenges NY Nuclear Subsidies.)
The judge has not said when he would rule on the motion, Crane said, and that if Exelon prevails, it expects its opponents to appeal the judge’s decision. If it doesn’t prevail, he said, it will proceed with the case.
In Illinois, two groups of plaintiffs have challenged the ZECs in federal court. The cases have been combined before one judge, who has delayed action on a motion for a preliminary injunction against the ZECs while he receives a full briefing on Exelon’s motion to dismiss the cases. (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Crane said the briefing will be completed by May 15 and the judge is scheduled to let the parties know his intention concerning the cases on May 22.
Exelon began recognizing ZEC revenues in New York on April 1, Crane said. In Illinois, he said, it has filed tariffs to begin collecting the ZEC payments on June 1 but doesn’t expect the actual procurement process to conclude until fall.
The earnings call came the day after the conclusion of a two-day technical conference at which independent power producers asked FERC to take action to prevent the ZECs from undermining the NYISO and PJM markets. (See related story, NYISO See Carbon Adder as Way to Link ZECs to Markets.)
Crane said he expects clearing prices in the upcoming PJM capacity auction to “come down to bidding behavior.”
“You have seen us bid our assets in recent auctions to reflect the underlying economic needs of the individual plants, which in turn has led to some of our plants not clear[ing]. You should expect us to bid our assets in the same responsible fashion in this next upcoming auction.”
Exelon expects a ruling on Pepco’s D.C. rate case in July, CFO Jonathan Thayer said. It expects rulings in the Maryland and Atlantic City Electric cases in the fourth quarter of 2017 and the first quarter of 2018, respectively, Thayer said.
WASHINGTON — More than 50 stakeholders from PJM, NYISO and ISO-NE made their cases to FERC last week on how to resolve the increasing conflicts between state energy policies and wholesale markets.
Many of those who testified also had appeared at the commission’s September 2013 technical conference, which was billed by then-Commissioner Tony Clark as a “check-up” on the capacity markets six years after the inception of PJM’s Reliability Pricing Model. Participants at that time differed on the health of the markets and whether major changes were needed. (See Capacity Market Attracts Praise, Criticism at FERC and Old Issues, New Technologies in Capacity Debate.)
Last week, however, virtually everyone was calling for change — the disagreements being over how much, how fast, what kind and whether it should be directed by FERC or come from stakeholders.
The diagnosis: The patient is running a fever and will only get worse without treatment.
“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.
“Is there a role for the markets? Absolutely,” said Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service. “The energy markets will always be there. The capacity market may not be.”
FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).
“There are three ways this could go,” acting FERC Chair Cheryl LaFleur said at the opening of the two-day conference May 1. “A designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct — or unplanned and piecemeal regulation, is one that I think we should avoid because I think it would be a bad outcome for customers and market participants in terms of cost, reliability and regulatory certainty.”
“All options, in my mind, are on the table,” added Commissioner Colette Honorable.
Factions
The witnesses fell into several camps.
Public power representatives said they should be relieved of participation in the capacity markets, which they say are too expensive and inflexible. Unlike in 2013, they had lots of company in calling for change.
Independent power producers called for FERC to act decisively to protect markets from out-of-market contracts and subsidies.
The grid operators differed on their preferred role for FERC, with PJM and NYISO urging the commission to set deadlines and provide direction.
Officials from New England said they will continue to pursue their states’ clean energy mandates with or without cooperation from the wholesale markets.
Carbon Adder
Economists have been telling FERC and others for years that the simplest way to reconcile the markets with environmental policies is to incorporate the cost of carbon into LMPs and generation dispatch. While New York and PJM are exploring ways to do so, New England policymakers said differences in state policy goals make it politically unpalatable despite its economic elegance.
IPPS: FERC Should Act Decisively Against Subsidies
Independent power producers NRG, Calpine, Dynegy and Eastern Generation, and their trade group, the Electric Power Supply Association, called for FERC to act quickly and firmly.
“A policy approach that lets any given action prevail at all costs in the name of a ‘state preference’ regardless of the detrimental impact on federally regulated wholesale markets would be the exception that swallows the rule of law in the” Federal Power Act, EPSA CEO John Shelk said. “If the commission wishes to continue delivering the benefits of wholesale markets, it needs to direct steps be taken by the Eastern ISOs/RTOs by specific deadlines to ensure that wholesale markets are protected and not undermined.”
FERC’s “hands-off approach” to date “rightly allowed states to experiment on the edges of the wholesale market with a variety of new programs and to avoid over-burdening these fledgling initiatives with federal intervention,” said Abe Silverman, vice president and deputy general counsel at NRG.
Now, however, the commission must develop “rule-of-reason” tests “to delineate how state programs are harmonized with competitive markets,” he said. “Wherever the line is eventually drawn, there clearly must be a line if the Federal Power Act is to have meaning.”
Calpine CEO Thad Hill also called for swift action.
“The legal process is lengthy, and it will take the courts considerable time to work through these issues. The commission should not wait for the courts to act, but instead the commission should be prepared to act quickly and decisively when viable proposals are brought before it,” he said.
Joining the IPPs in calling for action was Seth Kaplan, EDP Renewables’ senior manager for regional government affairs, who cited the D.C. Circuit Court of Appeals’ April ruling in Emera Maine v. FERC. That ruling upheld FERC’s Order 1000 finding that FERC-regulated transmission planning must accommodate state public-policy requirements. (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
“The Emera decision reaffirms once again that FERC and the entities it regulates have the ability — and I would argue obligation — to recognize state policies, like renewable portfolio standards and procurements, as cost drivers that must be recognized in the transmission planning and cost-allocation process,” Kaplan said.
Aleksandar Mitreski, senior director of regulatory affairs for Brookfield Renewable, agreed, saying “the time is ripe for public-policy objectives to be incorporated into the wholesale markets.”
Independent consultant Roy Shanker said FERC must take a leadership role because stakeholder negotiations will not prevent litigation. “The fundamental differences among parties … make any cooperative solutions unlikely,” he said. “In the presence of such fundamental differences, any path forward requires the commission to exercise its full authority over wholesale markets in order to find a resolution that does not cannibalize markets.”
New England: Butt Out, FERC
State officials from New England were equally forceful in saying they don’t want FERC interfering with ongoing stakeholder processes.
“Our work with the National Council [on Electricity Policy] supports the idea that states are well suited to collaboratively working out answers to the policy questions addressed by this technical conference,” said Vermont Public Service Board Commissioner Sarah Hofmann, a member of the NCEP’s executive committee.
“The New England states have shown the ability to work collaboratively to address climate change through [the Regional Greenhouse Gas Initiative], which is a program under state control,” New Hampshire Public Utilities Commissioner Robert Scott said. “Addressing carbon emissions through a federally controlled tariff based on state policies raises significant concerns not only about the potential for unreasonable allocation of costs but also states’ rights. If the federal government wishes to regulate carbon emissions in the wholesale electric sector, Congress should pass a law giving the appropriate agency such authority.”
The Beginning of the End of RPM?
Public power representatives reiterated their longstanding complaints about mandatory capacity markets, saying they could provide resource adequacy more cheaply through bilateral contracting and self-supply.
Lisa McAlister, general counsel for regulatory affairs at American Municipal Power, said FERC should eliminate the mandatory participation requirement in PJM’s capacity market. “RPM is a ‘market’ in name only, and, as time has gone on, fewer and fewer PJM market participants use that term to describe it,” she said.
“With respect to meeting adequacy needs, the markets have been a success,” said Cliff Hamal, managing director at Navigant Economics, who has consulted for AMP in PJM’s new capacity initiative. (See PJM Capacity Task Force Debates the Value of Price Transparency.) “With respect to doing so at a reasonable cost to consumers and consistent with meeting other legitimate policy goals, I think we can do better.”
Hamal said the capacity market’s cost of capital is increased by a “volatile, fickle and frail price mechanism that relies more on regulatory nurturing than the fundamentals of supply and demand.”
While RTOs should continue to set capacity obligations for load-serving entities, Hamal said, the LSEs should be allowed to meet their obligations independently.
“I believe the most promising option would be to allow state policies to be implemented through a formal commitment to bilateral markets. States would withdraw from the RTO centralized auctions and meet their capacity objectives bilaterally,” he said. “Energy markets will continue to function and capacity markets will return to providing the ‘missing money’ in the sense of a supplemental payment needed to ensure supply adequacy after consideration of all other revenue streams.”
Deadlines for Stakeholder Processes
Silverman said the commission should “direct each of its ISO/RTO markets to set forth a comprehensive plan to integrate state goals into its wholesale market outcomes in a sustainable manner. Unless the commission mandates such a process — by a date certain — I fear that states will continue to pursue carbon mandates outside of the organized markets, and society will be deprived of the benefits of competitive markets.”
PJM and NYISO officials said they would welcome FERC deadlines to pressure stakeholders to compromise on rules for incorporating state initiatives into the markets.
“We don’t want to run a 50% market. … We want to be the market that all resources depend on … for entry decisions, and we will work with the state to achieve those goals,” said Rana Mukerji, senior vice president of market structure for NYISO. “The stakeholder process … is long and contentious. Having deadlines works miracles.”
“Yes, there are compromises that come out [of the stakeholder process]. Yes, they can lead to maybe suboptimal … approaches,” said PJM Senior Vice President for Operations and Markets Stu Bresler. “But I can say without reservation [that] almost universally what comes out of a detailed stakeholder vetting of an issue is better than what went into it.
He added: “Deadlines and guidance from the commission are always helpful with respect to the efficiency of how that stakeholder process works.”
ISO-NE and the New England Power Pool, however, urged FERC to give them breathing room. Matt White, chief economist for ISO-NE, said the RTO will file a proposal with FERC by late this year or early 2018.
“The house is not burning down so fast that we must make an exigent circumstances filing with you within a week,” he said. “Coming up with something we can do and you will not be tweaking it again and again and again and again is probably worth six to nine months of our time.
“We have a very active stakeholder process that is deeply engaged on these issues,” he continued. “A deadline would not be terribly helpful.”
Not everyone saw the value of stakeholders’ participation, however.
“FERC should immediately begin a formal inquiry to rationalize the capacity and energy market constructs with the long-term financial needs of different operational categories of electric generation,” said John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents large U.S. manufacturers. “We strongly oppose any attempt to solve this problem via negotiated settlements in ISO or RTO stakeholder processes.”
Now What?
The “crossroads” for the markets, as multiple speakers called it, comes at a time when FERC has never been less prepared to act. With three empty seats, it has been without a quorum since February; Honorable announced last month that she won’t seek a new term when hers expires in June.
So, as the participants wheeled their suitcases to cabs outside FERC headquarters at the end of the two-day hearing, the commission’s policy direction could hardly be more uncertain.
With President Trump — who has moved to dismantle his predecessor’s climate change policies — in a position to fill four of the five seats, at least some of the new members could be hostile to Northeast states’ climate policies. At press time, there were numerous reports that Trump will nominate Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) to fill two Republican vacancies on FERC. Chatterjee was described in a Bloomberg profile as “the McConnell adviser determined to stop the Clean Power Plan.” (See related story, Trump Nominates Republicans Powelson, Chatterjee to FERC.)
Even if the commission did support an RTO-administered carbon adder, would it have the authority to do so?
Certainly someone will ask the courts that question.
VALLEY FORGE, Pa. — PJM’s proposed problem statement and issue charge on whether states can control energy-efficiency participation in the capacity market drew heated debate on two issues — one expected and the other not — at last week’s Market Implementation Committee meeting.
Because of the ongoing debate, a vote on endorsing the proposal was delayed until next month with one objection and one abstention.
The proposal was developed in response to a current proceeding before the Kentucky Public Service Commission on energy-efficiency requirements, said Denise Foster, PJM’s vice president of state and member services. PJM’s rules on load-modifying resources offering into the market, such as demand response, don’t address whether energy efficiency should be treated the same as DR, so the RTO is considering how and whether to add it.
However, PJM is specifically limiting the scope to avoid discussing whether state jurisdiction factors into the discussion, despite stakeholder suggestions to include it. The issue charge would establish requirements for energy efficiency entering the market, rules around those requirements and how to handle energy-efficiency resources that have already cleared past capacity auctions.
Tom Rutigliano, representing Electric Market Connection, expressed concern that the proposal would ostensibly grant state regulators new power to restrict energy efficiency participation in wholesale markets. He pointed to the Supreme Court case EPSA v. FERC as confirming that FERC has jurisdiction over retail customer participation in the wholesale markets.
“We appreciate that Kentucky may have claims, but we feel at this point, it’s not really appropriate to put PJM and its stakeholders in the position of deciding if those jurisdictional claims are correct or not,” he said. “This is really not at this point a stakeholder issue.”
His concerns were echoed by Rick Drom, an attorney with Eckert Seamans Cherin & Mellott, who offered a presentation titled “A Flawed Solution Seeking a Problem.” He said any discussion on PJM deferring to state regulatory authorities is premature and that the proposal risks balkanization of the energy market.
Drom’s arguments, however, were overshadowed by his unwillingness to name whom he represented at the meeting. He said his client, whom he said is one of the largest energy efficiency providers in the PJM footprint and operates in Kentucky, fears reprisal from opponents. Drom said he met with senior PJM staff to explain the situation, and they agreed to let him speak without naming his client.
Bruce Campbell of CPower noted that Eastern Kentucky Power Cooperative is seeking a declaration from the Kentucky PSC that the utility has the authority to “terminate electric service to any energy-efficient resource provider who violates Kentucky law, a commission order, rule or regulation or commission-approved tariff.” Drom acknowledged that was part of his client’s desire to keep its name hidden.
When Drom refused to identify whom he represented, Calpine’s David “Scarp” Scarpignato requested a point of order, citing Manual 34 rules that require speakers to identify whom they represent. Other stakeholders supported the request, noting that it would create a bad precedent.
Chantal Hendrzak, the chair of the MIC, called a short recess for Drom to explain the situation to Scarp. Scarp maintained his request, which led Hendrzak to acknowledge that PJM would take greater care considering similar requests in the future.
DR Open Registration Under Consideration
PJM is considering changes to when DR can be registered. Currently, all registration must be completed prior to the beginning of the delivery year, so new customers who wish to enter after June 1 are barred from participating and those who leave can’t find new customers to take over their responsibility.
The RTO is offering three options. The first would move the deadline to Dec. 1. The second would have no registration deadline. The third would also have no deadline but would require registered DR to test prior to the delivery year and new registrations to test on the first active day. All three would allow for the daily deficiency penalty to change daily, and the test commitment would change from the daily average during summer period to daily average for delivery year. The third solution, proposed by the Independent Market Monitor, would instead use the peak commitment day for the delivery year.
Stakeholders who don’t handle DR asked if there was a strong preference among stakeholders who do regarding which option they supported. Bruce Campbell of CPower said he generally supported the second option. A stakeholder poll produced identical support of 51% for the first and second options and minimal support for the third one. However, there was greater support (69%) for the status quo.
WASHINGTON — If the economists who testified at FERC’s technical conference last week agreed on nothing else, it is that a carbon adder is the simplest way for the power markets to value emission-free generation.
New York is going to try and translate the theory into practice as a way of addressing the impact of the state’s zero-emission credits (ZECs) for its upstate nuclear plants, officials told FERC.
On the first day of the two-day conference (AD17-11), state and NYISO officials asked FERC for time to develop their plan even as merchant generators called for immediate action to block the subsidies or respond to their effects on the wholesale markets.
The ZECs are part of New York’s Clean Energy Standard, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. The CES also calls for renewables to meet 50% of the state’s energy needs by 2030.
The subsidies will support Exelon’s two-unit Nine Mile Point, and the single-unit R.E. Ginna and James A. FitzPatrick plants for more than 12 years at a cost estimated as high as $7.6 billion. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.) At a legislative hearing into the ZEC program in Albany on May 1, however, New York Public Service Commission interim Chair Gregg Sayre said he expects the actual cost may be much less, perhaps as low as $2.86 billion.
NYISO CEO Brad Jones told FERC that while the ISO supports the ZEC program, it wants to find a way to incorporate the payments into the wholesale market.
The ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Generating units that emit carbon would incur a penalty based on their level of carbon emissions; the penalties collected by the ISO would be “returned to customers in some equitable manner.”
Jones said the project was in its “initial stages” and that implementation could take three years.
That is too long for other stakeholders.
“I was shocked to hear [Jones] say yesterday that he doesn’t think the rates are just and reasonable but we have three years to work out a solution,” said Abe Silverman, vice president and deputy general counsel for NRG Energy. “No, this is something that needs to happen almost immediately.”
John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in New York, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.
“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”
The Independent Power Producers of New York argued that the state’s goals and its energy markets have reached a crossroads, saying that out-of-market solutions threaten the ability of the wholesale market to meet system needs at the least cost.
“Retail electricity customers are required to pay for renewable energy credits to support new large-scale renewable resources, as well as zero-emissions credits to support nuclear facilities which might otherwise retire from the market — both of which are out-of-market valuations for environmental attributes,” IPPNY CEO Gavin J. Donohue said. “The implementation strategies used to meet those [CES] goals conflict with the competitive market principles that have produced unparalleled reliability and record-low electricity prices.”
The NYISO discussion focused on several questions, some of which will also be central to challenges to the ZECs in court and before FERC: state vs. federal jurisdiction; the price suppressive impact of ZECs; and the efficacy of saving at-risk nuclear plants versus replacing them with renewables.
Dynegy, Eastern Generation, NRG and the Electric Power Supply Association filed a federal court suit in October claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order them withdrawn from the CES. (See Federal Suit Challenges NY Nuclear Subsidies.)
The same companies filed suit in February challenging Illinois’ ZECs for Exelon’s Quad Cities and Clinton nuclear plants and have also asked FERC to reject the subsidies (EL16-49). (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Do ZECs Interfere with the Wholesale Markets?
The Supreme Court has attempted to draw the lines between state and federal jurisdiction over the power industry in a series of rulings, most recently the January 2016 ruling in EPSA v. FERC, in which the court upheld FERC’s jurisdiction over demand response, and the April 2016 order in Hughes v. Talen, which rejected Maryland’s subsidy of a generator that could have undermined PJM’s capacity auction.
New York regulators took pains to ensure the ZEC program complied with the court’s advice in the latter case. “Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation,’” the court said.
Scott A. Weiner, deputy for markets and innovation at the New York State Department of Public Service, made an impassioned defense of the ZEC program, saying it was permitted by states’ “settled jurisdiction over environmental policy, resource adequacy, fuel diversity and reliability.”
“Rather than opening this discussion with the question of how state policies can be implemented through federally regulated wholesale markets, we should ask, ‘should they?’ An attempt to select resources through the federally regulated wholesale markets to achieve individual state policies may undermine, even if unintentionally, those very state programs,” he said. “By incorporating state policy into the wholesale markets, the state would have to seek a tariff change to reform its own policy.
“This changing role of the state’s utilities must be harmonized by federal and state regulators acting in respectful collaboration without one seeking to subsume the other.”
Rather than attempting to “absorb” state policies into the federal wholesale markets, Weiner said, FERC should consider removing barriers to new entry by state-supported resources by eliminating buyer-side mitigation.
“It is essential to recognize that policies addressing legitimate state interests may have incidental impacts on wholesale market prices without raising the specter of price suppression or undermining markets.”
NY, Exelon: ZECs not Intended to Suppress Prices
“New York, like other states, does not seek to suppress wholesale market prices. Ending application of this false assumption eliminates the need for market rules based on that presumption,” Weiner said.
Exelon also insisted that ZECs are not vehicles for price suppression, comparing them to the renewable energy credits (RECs) issued in support of state renewable portfolio standards.
“Buyer-side mitigation rules are aimed at large buyers seeking to suppress market prices by introducing new, uneconomic supply. But environmental programs like ZEC programs do not fit that description,” Exelon said. “First, in ZEC and REC programs, the state is purchasing a separate environmental attribute, so ZECs and RECs are not tied to energy or capacity sales.”
Impact, not Intent, is What Matters
Others counter, however, that it is the impact of state policies on prices — not policymakers’ intent — that is at issue.
David Patton, president of Potomac Economics, which provides market monitoring in NYISO and ISO-NE, said nuclear subsidies can be much more damaging to wholesale price formation than renewable subsidies because solar and land-based wind have low capacity values.
Former FERC Commissioner Tony Clark, now a senior adviser at Wilkinson Barker Knauer, said at a conference in March that while FERC hasn’t seen harm to the markets from state REC programs, the scale of the nuclear generation covered by subsidies — 20% or more of the market in some regions — may make them more vulnerable. (See Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)
And even renewables are having a significant impact on prices, Lawrence Makovich, chief power strategist for IHS Markit, told FERC.
He presented analysis that he said demonstrated that wind output suppressed PJM prices by about 24% during the top net load hours in 2015, when peaking units were setting the price. Wind suppressed prices by 4% when net loads were average and by about 9% during minimum load, he said.
“On the cost side, compensating for the impact of wind … [caused] load-following generators to increase output ramping and starts and stops, causing less production efficiency and higher [operating and maintenance] costs,” he said.
Is Preserving Nukes the Best Policy Choice?
Exelon says ZECs are justified because it would take too long and be too costly to replace the zero-emission capacity of at-risk nuclear plants versus renewables. “When a nuclear facility retires, it cannot feasibly be replaced by renewable generation in the time necessary to avoid a spike in emissions. Instead, it will be replaced predominantly by fossil fuel-fired plants emitting significant carbon and other air pollution,” Exelon said.
The company cited Germany’s retirement of its nuclear fleet following the 2011 Fukushima nuclear accident, which resulted in “a massive increase in emissions despite investing in new renewable generation to such a degree that its electricity rates are now among the world’s highest.”
Similarly, the closure of the San Onofre nuclear plant in early 2012 “resulted in an increase in emissions that more than offset all of California’s investment to date in wind, solar and biomass generation,” Exelon said.
New York concluded replacing its nuclear fleet would require that it triple its energy-efficiency targets or construct 9,000 MW of onshore wind or 22,000 MW of solar.
NRG’s Silverman, however, said New York chose an expensive path.
“For $3.5 billion — or approximately half the price of the bailout in New York — the state could have purchased enough renewables to replace the output of all of its at-risk nuclear fleet with 100% new renewable power. Additionally, New York’s Independent Market Monitor found that a new combined cycle on Long Island is a far cheaper means of reducing carbon in New York than the nuclear bailout.”
The impact of state mandates on load-serving entities was the key concern of James Holodak Jr., vice president of regulatory strategy and integrated analytics for National Grid, which owns LSEs in New York and New England.
Holodak said National Grid’s Niagara Mohawk Power subsidiary was forced to absorb $2 billion in stranded costs as a result of New York legislation that required utilities to buy electricity from independent power producers for at least 6 cents/kWh, a price higher than utilities’ production cost.
Holodak said the law forced Niagara Mohawk to sign contracts for output in excess of its actual demand and helped increase the utility’s rates by 25% between 1990 and 1995, causing many industrial and commercial customers to seek alternative suppliers or lower-cost locations.
Holodak said New England states with mandates should adopt a structure similar to that in New York in which each LSE is required to purchase the ZECs from the New York State Energy Research and Development Authority while recovering the costs from its customers. “In this instance, NYSERDA acts as the middleman, which advances the state’s policy goals and presents less risk for utilities than under a mandatory contracting model between the generator and the utility,” Holodak said.
He also made a case for allowing utilities to own renewables rather than being required to purchase them.
“Long-term bilateral [power purchase agreements] with developers equate to ‘virtual ownership’ with utilities and their customers absorbing project risks without the benefits of ownership,” he said, acknowledging that support for utility ownership will depend on utilities’ ability to “produce demonstrable customer savings.”
“We further recognize that this position may seem inconsistent with our broader support for market-based solutions where circumstances permit. However, today’s RTO/ISO markets do not adequately incentivize new entry from zero-emitting resources and it is not clear how or when they will evolve to do so.”
FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:
ER16-1404 Power Producers of N.Y. v. NYISO re. buyer-side capacity market power mitigation
CAISO last week experienced its first “Stage 1” grid emergency in nearly a decade, days after Southern California Gas warned that continued restrictions on its Aliso Canyon storage facility could deprive the region’s natural gas-fired generators of enough fuel to avoid blackouts this summer and winter.
