MISO’s summer planning reserve margins will remain firmly above requirements even after it shaved nearly half a percentage point from an initial assessment for the season.
Reserve margins could range anywhere from 14.1 to 19.7% throughout the summer, and MISO sees a high probability (79.3%) for calling up load-modifying resources and a much lower one (12%) for exhausting its 10.2 GW of LMRs and dipping into operating reserves. The chance of load shedding stands at 5%.
| MISO
Based on forecasts for above-normal temperatures in its footprint this summer, the RTO expects peak demand to hit 125.1 GW, with 148.5 GW of available capacity on hand to meet it. Summer demand peaked at 120.7 GW last year.
“We are expecting to have sufficient resources in the footprint,” Todd Ramey, MISO vice president of system operations, said during an annual summer readiness workshop on May 8.
While forecasts for declining demand are driving up the base reserve margin, the increased Midwest-South regional transfer limit is providing extra wiggle room, the RTO said.
“We appreciate the ongoing efforts of load-serving entities and states to ensure adequate resources are in place,” Ramey said in a press release.
The forecasted above-normal summer temperatures “can pose some operational challenges,” said Darius Monson, MISO resource adequacy adviser. “It’s worth noting, in a high-load scenario, we are planning to rely heavily on demand response resources.”
The summer reserve estimates include total firm imports, DR and energy efficiency resources based on cleared megawatts in the 2017/18 capacity auction. Non-firm deliveries were excluded from the summer assessment.
“In reality, there might be additional non-firm support,” Monson said.
The RTO also assumed that planned and forced outages would be consistent with the previous five years, and that no MISO South capacity would be stranded in a post-outage situation.
MISO will also hold realistic hurricane simulations with MISO South operators May 23-24 and June 20-21, a first for the RTO, which ordinarily holds less-detailed hurricane drills, according to Marty Sas, senior manager of South reliability coordination. The exercise will start with an intact system and simulate a 31-hour storm that takes nearly 200 transmission lines and 25 generators out of service.
ALBANY, N.Y. — Gov. Andrew Cuomo has nominated John Rhodes, CEO of the New York State Energy Research and Development Authority, to chair the Public Service Commission, NYSERDA Chairman Richard Kauffman said Wednesday.
Rhodes | NYSERDA
“John represents continuity,” Kauffman told several hundred attendees at the Independent Power Producers of New York annual meeting. “If you know his background, he’s someone committed to markets.”
The PSC has been operating with only interim Chair Gregg Sayre and Commissioner Diane Burman since March, when Chair Audrey Zibelman resigned and Commissioner Patricia Acampora retired. The commission also has had a two-year-long vacancy. (See NY REV Won’t Lose Momentum, Departing Zibelman Says.)
The Cuomo administration has taken a position that the two existing commissioners are sufficient for a quorum, but that interpretation “hasn’t been tested,” said state Sen. Joseph Griffo (R), chairman of the Senate Committee on Energy and Telecommunications, who spoke to the IPPNY conference before Kauffman.
Kauffman said Cuomo, a Democrat, intends to name nominees for the other two vacant seats soon enough to ensure their confirmation before the end of the current legislative session in June.
But Griffo said that the Senate will “carefully vet” Cuomo’s nominees. “It’s not going to be a pro forma type of submission,” he said.
Rhodes has run NYSERDA since September 2013, following stints as director for the Center for Market Innovation at the Natural Resources Defense Council and chief operating officer at Good Energies, an investment firm focused on renewable energy and energy efficiency.
He is a former partner at Booz Allen Hamilton and has also worked as a trader and general manager at Metallgesellschaft, a German mining, metals and engineering firm. He has a bachelor’s degree in history from Princeton University and a master’s degree in management from Yale.
CAISO’s wholesale costs to serve load last year fell by 9% to $7.4 billion, the lowest nominal expense since 2008, according to an annual market performance report from the ISO’s internal Monitor.
The Department of Market Monitoring also used the report to signal its growing support for lifting FERC-imposed bidding restrictions on some participants in the Western Energy Imbalance Market (EIM).
The Monitor attributed much of the drop in wholesale costs to a 9% decline in prices for natural gas, with increased output form solar and hydroelectric resources and decreased transmission congestion also contributing. Electricity prices averaged $34/MWh over the year, down $3 from 2015.
The report noted the impact of CAISO’s growing number of low-cost solar resources, which accounted for about 83% of the 2,300 MW of new summer peak generating capacity installed in the ISO during 2016, along with 300 MW of newly built gas-fired peaking generation and 50 MW of additional energy storage.
“Solar energy is expected to continue to increase at a high rate during the next few years as a result of projects under construction to meet California’s renewable portfolio standards,” the Monitor said in its report. “This continues to increase the need for flexible and fast ramping capacity that can be dispatched by the ISO to integrate increased amounts of variable energy efficiently and reliably.”
Renewable integration efforts during the first half of 2016 drove sharp increases in ancillary services costs, which nearly doubled to $119 million, accounting for 1.6% of total wholesale energy costs, compared with 0.7% in 2015.
During the second quarter, ancillary services costs averaged 81 cents/MWh, more than 50% above the yearly average. The increase in large part stemmed from the ISO’s expanded seasonal procurement to manage a growing surplus of solar and hydro during California’s spring run-off. (See CAISO: Forecasting Challenges Drove Increased Regulation Requirements.)
CAISO’s ancillary services costs rose last year after the ISO expanded its regulation procurement to accommodate the increased volume of variable solar resources on its system.
The Monitor estimates about 1.6% of solar generation was dispatched down in the real-time market last year, with the largest reductions — about 3.4% — occurring during March as a result of low seasonal loads coinciding with relatively high solar output.
“More solar generation was economically dispatched down in 2016 compared to 2015 primarily because there was more inexpensive hydroelectric generation available throughout the year,” the Monitor said.
Just 0.3% of forecasted wind output was dispatched lower in real time throughout the year, which the Monitor attributed to the tendency of wind resources to bid into the market at relatively lower prices than solar.
Non-economic curtailments of renewable resources declined last year, the Monitor noted, likely because of the expansion of the EIM, the West’s only real-time energy market. The EIM’s inclusion of NV Energy in late 2015 and Arizona Public Service last fall significantly increased imbalance transfer capacity out of California, increasingly turning the state into an exporter of renewable generation to other areas of the West. (See EIM Report Show Continued Growth in CAISO Exports.)
The Monitor said improved transfer capability helped ensure competitiveness in the EIM, with mitigation of bids triggered by congestion occurring in the market’s participating balancing areas during only 1 to 4% of intervals.
“This increased structural competitiveness provides a basis for DMM to support removing special bidding restrictions currently placed by FERC on some Energy Imbalance Market participants,” the Monitor said, referring to Berkshire Hathaway Energy affiliates PacifiCorp and NV Energy.
FERC last year rejected a request by the two companies to rehear a 2015 decision prohibiting them from bidding generation into the EIM at market-based rates. The commission determined that both companies must provide market power analysis for EIM sub-markets as well as the market as a whole, a condition that would apply to any EIM member (See Berkshire Denied Rehearing on Market Power.)
The Monitor said that analysis it performed last year indicates that the inclusion of NV Energy’s transfer capacity “dramatically” reduced PacifiCorp’s potential to exercise market power in the EIM by significantly improving the links between the ISO and PacifiCorp’s balancing area.
“This structural competitiveness mitigates the potential for the exercise of market power through both economic and physical withholding during most intervals,” the Monitor said.
CAISO has “partially” addressed some of the Monitor’s own recommendations for improving competitiveness in the EIM, the Monitor noted, including increased enforcement of measures meant to account for internal transmission constraints and improved modeling of PacifiCorp transmission limits to better reflect the congestion impact of contracted line capacity.
The Monitor said it would support eliminating the bidding restrictions once all the concerns in FERC’s orders have been addressed.
Three public interest groups say they were shut out of last week’s FERC technical conference on tensions between state energy policies and wholesale markets (AD17-11) and called on the commission to improve the transparency of RTOs.
In a letter to the commission, Public Citizen, the Public Utility Law Project of New York and the Pennsylvania Utility Law Project complained that the technical conference did not include any public interest consumer advocates, although Public Citizen had submitted an application to speak.
Although the Consumer Advocates of PJM States testified on one PJM panel, “neither government nor public interest consumer advocates” were included on any of the ISO-NE or NYISO panels, the letter said. “FERC’s failure to include any public interest consumer advocates decidedly leaves one of the most important stakeholders in the outcome with no voice,” they wrote.
The groups also said they were concerned that the Trump administration will appoint new FERC commissioners who subscribe to a “new, radical administration baseload electricity policy” as articulated by Energy Secretary Rick Perry’s memorandum announcing a study of policies affecting baseload power. (See related story, Exelon Encouraged by Perry’s Memo, Thinks ZECs Will Hold Up.)
“While the Department of Energy actually lacks clear authority to implement the sweeping proposals suggested in the memo, FERC likely does have the power to do so,” the groups said.
FERC has lacked a quorum since February. The five-member commission has three open seats, and Commissioner Colette Honorable announced last month she will not seek reappointment when her term expires in June.
The groups also called on FERC to improve RTO governance and transparency, criticizing FERC’s December order dismissing Public Citizen’s complaint that it was denied a right to fully participate in PJM. The order said that government consumer advocate offices, which have the right to vote, can represent Public Citizen’s interests (ER17-249). “That is akin to the U.S. Environmental Protection Agency representing the views of the Sierra Club,” they wrote.
“Although some describe the RTOs as ‘quasi-public’ institutions, given the power FERC has bestowed upon them, there is nothing public about them. All of the FERC-jurisdictional RTOs … are private, membership corporations. None are subject to federal or state transparency or other governance requirements imposed on government institutions, such as open meeting laws or federal/state freedom of information act statutes.”
The groups said individuals that are not members of the New England Power Pool can only attend stakeholder meetings through a “sponsorship” from an existing member. “But even after being ‘sponsored,’ the decision to approve participation is made by the chair of the Participants Committee — a position currently held by a for-profit power company executive. Such a privatized model of controlling civil engagement is inappropriate.”
The letter also renewed the March 2016 request by Public Citizen and more than two dozen environmental and public interest groups that FERC provide public funding for interventions before the agency, as it says is required by the 1978 Public Utility Regulatory Policies Act (RM16-9). (See Citizens Groups Seek Public Funding for FERC Interventions.)
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 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 — 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 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
WASHINGTON — The minimum offer price rule came up frequently at last week’s FERC technical conference exploring tensions between state clean energy policies and RTO/ISO markets in the East, with some witnesses calling for its expansion and others seeking its relaxation or abolition.
Robert Erwin, general counsel of the Maryland Public Service Commission, called on FERC to help states achieve their energy policy goals by simplifying the “unduly complex” capacity market rules and reducing “the chilling effects” of the MOPR on state innovation.
He was one of several MOPR critics who invoked the words of former FERC Chairman Norman Bay to buttress their case. (See Bay Blasts MOPR on Way Out the Door.)
MOPR ‘Cudgel’
“State policy decisions over new generation — previously exempted under the [PJM Reliability Pricing Model] settlement — have become subject to the cudgel of the minimum offer price rule,” Erwin complained. “We believe that the putative threat of state initiatives that the MOPR was devised to counter is overblown. Accordingly, the Maryland commission agrees with former Chairman Bay that the MOPR, as currently utilized, ‘places [FERC] in constant tension with the states’ and inhibits valuable state policies.”
The Sierra Club also quoted Bay’s comments in calling for “curtail[ing]” the use of the MOPR, citing his criticism that “‘MOPR not only frustrates state policy initiatives, but also likely requires load to pay twice — once through the cost of enacting the state policy itself and then through the capacity market.’”
“We agree that it is essential to mitigate actual buyer-side market power, but encourage the commission to undertake a more careful examination of the evidence as to whether buyer-side market power is exercised in capacity or energy markets and develop appropriate screens to be applied whenever a mitigation mechanism is premised upon the existence of such power,” said Mark Kresowik, deputy director of the eastern region of the Sierra Club’s Beyond Coal Campaign. “As former Chairman Bay observed, ‘the commission simply assumes [buyer-side market power] exists. The commission has not explored or tested these assumptions in its orders, and it does not know whether they are true.’”
Angela M. O’Connor, chairman of the Massachusetts Department of Public Utilities, said that in addition to the short- and long-term policies being discussed by stakeholders in the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, “we hope to explore other potential solutions, including a further examination of the minimum offer price rule, which presents a significant challenge to the participation of state-supported resources in the Forward Capacity Market.”
O’Connor (left) and Scott | RTO Insider
“Any IMAPP proposal that substantially increases the amount of clean energy resources entering the FCM will likely involve either the elimination of or modification of the minimum offer price rule,” said New Hampshire Public Utilities Commissioner Robert Scott, who added that his state has not taken a position on any potential changes to the rule. “Such a change in market design should be accomplished in a thoughtful manner and certainly not without a full understanding of the likely long-term implications for electric rates.”
Harvard University’s William Hogan also quoted Bay in urging FERC to minimize the role of the capacity markets.
“In his last comments about the minimum offer price rule, Commissioner Bay summarized: ‘The premise of the MOPR appears to be based on an idealized vision of markets free from the influence of public policies. But such a world does not exist, and it is impossible to mitigate our way to its creation. The fact of the matter is that all energy resources receive federal subsidies, and some resources have received subsidies for decades.’
“The factual premise is well founded. They are myriad subsidies, many beyond the commission’s jurisdiction,” Hogan continued. “It is also true that the commission cannot, by itself, unwind all these subsidies to create the idealized vision of pure markets.”
While the capacity markets exist, however, Hogan said FERC should “strengthen anti-manipulation efforts such as the MOPR.”
“The avowed purpose of capacity markets is to correct for defects in energy pricing. If this is the case, the commission should have no obligation to accommodate subsidized resources that, in effect, make the problem worse. The commission can and should limit access and discriminate against those subsidized resources that are adding to the problem of inadequate pricing in energy markets.”
PJM Independent Market Monitor Joe Bowring and Dynegy CEO Robert Flexon both told FERC it should expand the rule to include existing generation as well as new resources. PJM officials also have called for such an expansion. (See PJM: MOPR Could be Improved, but not by BRA.)
Flexon said FERC should require “adequate minimum bids for all existing and new resources that receive revenue or revenue certainty (e.g. long-term multiyear contracts, ZEC payments) from sources other than the competitive marketplace. All resources, new and existing, should be required to bid at least the level they would have bid if they were being supported solely by the competitive market.”
“The MOPR should be expanded to address subsidies for all existing and proposed units, and this should be done expeditiously,” Bowring said. “An inclusive MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”
VALLEY FORGE, Pa. — Even as PJM moves into a heavy outage season, its balancing authority area control error limit (BAAL) remains lower than usual, PJM’s Ken Seiler said at last week’s Operating Committee meeting.
PJM’s excursion minutes dropped to 177 in April, from 257 in March and 224 in April 2016. PJM posted a 99.6% BAAL score for April, improving 0.1 percentage point from a year ago and 0.2 percentage points from March. (See “Inconsistent Weather Contributes to Operational Inaccuracies,” PJM Operating Committee Briefs.)
Seiler said generators beyond PJM’s control but that tied into the RTO’s grid are still overgenerating, which is unbalancing the system. The excursions are mostly happening in “the valley period” between 1 and 3:30 a.m., he said, during light-load conditions when generation is mostly baseload units and wind turbines. He said PJM is working with neighboring grid operators to identify the causes of the issues, beyond large temperature swings.
“Our actual numbers are very good, actually,” Seiler said. “But when we look outside, we’re starting to see some excursions outside that are starting to have more of an impact on us.”
With new transient-shortage pricing set to go into effect on May 11, PJM’s Chris Pilong said system operators are being trained in how to best maintain lowest-cost generation, but that operations will largely remain the same.
“It’s an awareness issue,” Pilong said. “We need operators to understand these changes, which they do. They’re prepared for them.”
Calpine’s David “Scarp” Scarpignato, who raised the issue, said he agrees with the way PJM is handling the transition.
PJM Considering Compensation in Frequency Response Study
Stakeholders endorsed by acclamation PJM’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s problem statement and issue charge suggest that the RTO might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “Stakeholders Push Back on Paying for Frequency Response,” PJM Markets and Reliability and Members Committees Briefs.)
John Farber of the Delaware Public Service Commission acknowledged it might be “reaching for belt and suspenders,” but he requested that the compensation issue be separated into another phase of the study from the main discussion.
This was received coolly by both stakeholders and PJM staff. “I think separating it too much may complicate the solution space that we come up with,” PJM Vice President of Operations Mike Bryson said. “I think separating it too much may predetermine the solution probably more than we’re willing to.”
