FERC on Thursday conditionally approved NextEra Energy’s acquisition of Florida utility Gulf Power as being “consistent with the public interest” (EC18-117).
Separately, the commission granted Gulf Power’s request to make limited market-based rate sales of capacity and energy during the transition ownership period (ER18-1952) and accepted the utility’s new, standalone tariff, effective upon the transaction’s closing (ER18-1953). The latter order also established hearing and settlement judge procedures addressing Gulf Power’s proposed base return on equity and protocols.
Gulf Power service truck | Gulf Power
Gulf Power, a subsidiary of Southern Co. in the Florida Panhandle, serves about 450,000 customers in eight counties. The utility owns or controls approximately 2,277 MW of generating capacity, a 2,700-mile transmission system and a 7,700-mile distribution system, and service over its transmission system is currently covered under Southern’s tariff.
NextEra announced in May it had reached an agreement with Southern to acquire Gulf Power, Florida City Gas and two gas-fired plants in Florida for almost $6.5 billion. NextEra completed acquisition of the gas plants in December.
Gulf Power will continue to operate in the Southern Company Pool and in Southern’s balancing authority area during the transition period, until it can operate on a standalone basis.
FERC said it found no adverse effect to generation markets in its analysis of Florida-based NextEra’s acquisition of Gulf Power. It said the applicants’ commitment to “indefinite rate de-pancaking” addressed any horizontal market power concerns that might arise, and it noted that Southern-affiliated generation would continue to compete in the Gulf Power balancing authority area, and vice versa.
The commission determined vertical competition would be unaffected as well, pointing to an unconcentrated upstream natural gas delivery market in the existing Southern balancing authority.
It also accepted the transaction’s proposed ratepayer protections, which included extending a rate cap period beyond five years, should the transition period take longer than five years, and charging grandfathered transmission customers the lower of Southern’s or the new Gulf Power rates during the transition.
In allowing Gulf Power to continue to make limited market-based rate sales of capacity and energy during the transition period, FERC also designated the utility as a Category 2 seller in the Southeast region and a Category 1 seller in the Northeast, Southwest, Northwest, SPP and Central regions.
The commission defines Category 1 sellers as wholesale power marketers and power producers that:
own or control 500 MW or less of generation in aggregate per region;
do not own, operate or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid (or have been granted waiver of the requirements of Order 888);
are not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the seller’s generation assets;
that are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and
that do not raise other vertical market power issues.
Sellers that don’t fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses.
FERC accepted Gulf Power’s proposed tariff, which included a 10.5% ROE, but ordered a public hearing on its justness and reasonableness. The commission held the hearing in abeyance to provide time for settlement judge procedures.
Commissioner Kevin McIntyre did not vote on the orders, while Commissioner Bernard McNamee, who was only sworn in Dec. 11, voted present on each one.
NextEra’s share price lost $2.27 at one point during another bloody day on Wall Street, before recovering to close up 16 cents, at $174.91/share, in after-hours trading.
FERC on Thursday approved new ISO-NE penalties for market participants that fail to cover their capacity supply obligations (CSOs) when a new resource is delayed.
The commission’s Dec. 20 order agreed with the RTO “that the failure-to-cover charge rate mechanism establishes a just and reasonable penalty rate for capacity resources that do not cover their CSO in advance of a capacity commitment period and fail to demonstrate the ability to fulfill all or part of their CSO” (ER19-169).
The new Tariff provisions go into effect Dec. 24.
The rule changes are designed to shift the responsibility for covering CSOs to market participants, which ISO-NE says have the best information about project development schedules and potential delays. (See NEPOOL OKs Penalty for Delayed Capacity Resources.)
The changes stipulate that for delivery years before June 1, 2022, the monthly dollar/kilowatt-month failure-to-cover charge will be the higher of the capacity clearing price and the clearing price in any Annual Reconfiguration Auction (ARA) for that year. After that time, the charge will be based on the outcome of a second run of the third ARA, using the unproven CSO quantities as a demand bid. Market participants will still be compensated for their CSOs and continue to face Pay-for-Performance risk.
Two Protests Denied
Public Service Enterprise Group filed a protest seeking “staggered effective dates” to incorporate a three-month grace period beginning in June 2019, June 2020 and June 2021 for resources awarded CSOs in the Forward Capacity Auctions associated with those capacity commitment periods.
The general timeline for Forward Capacity Market events for a single capacity commitment period. The specific dates for 2019 can be found by clicking the image. | ISO-NE
The company argued that allowing the filing to take effect this month would impose new and unexpected risks and costs on resources that obtained CSOs under the existing rules, in particular its Bridgeport Harbor 5 plant scheduled to go into operation next June.
The commission disagreed “that the proposed effective date violates the filed rate doctrine and rule against retroactive ratemaking. … PSEG fails to quantify or detail the extent to which the risk profile for Bridgeport Harbor 5 is altered or otherwise to support its argument that any such change is unjust and unreasonable.”
Northeastern Massachusetts Consumer-Owned Systems (NEMACOS) also filed a protest expressing concern that load-serving entities may be paying arbitrage margins to suppliers that obtain a higher clearing price in the FCA and cover their capacity obligations in the reconfiguration auctions at a lower price.
The commission found the Tariff provisions that NEMACOS addresses in its protest are not at issue in the proceeding, but it noted that “under both the current Tariff and the proposed revisions, a resource that obtains a CSO in the FCA would have an opportunity to cover its CSO in a subsequent reconfiguration auction and potentially garner an arbitrage margin.”
“Because the failure-to-cover charge rate is designed to always be greater than or equal to the third Annual Reconfiguration Auction clearing price, the proposed revisions will offer no additional arbitrage incentives beyond those already available to resources under the current Tariff,” the commission said.
The Bonneville Power Administration on Tuesday continued its series of discussions with stakeholders about joining CAISO’s Western Energy Imbalance Market, with a possible activation date in 2022.
Tuesday’s talks revolved around EIM settlements, with detailed presentations about invoices, charges and metering. The calculations may have appeared daunting but ultimately came down to familiar math, said Steve Kerns, BPA’s director of grid modernization.
“I want to make sure you don’t find this to be too scary,” Kerns told the dozens of stakeholders on the call and in BPA’s Rates Hearing Room in Portland, Ore. “There’s a lot of stuff going on here, but at the end of the day, it’s adding, subtracting [and] multiplying.”
Prior meetings that were part of BPA’s EIM stakeholder initiative have covered subjects such as market power, transmission and governance. Future meetings will deal with resource sufficiency and carbon obligations, with the next session scheduled for Jan. 16 in Portland.
BPA is targeting next September for issuing a final record of decision authorizing it to sign an implementation agreement with the EIM, which would allow the agency to begin spending on implementation projects without obligating it to join the market.
So far there has been little opposition among BPA stakeholders to joining the EIM, though details of the move are still being worked out. Joining would ease short-term trading of Pacific Northwest hydro power for solar energy from the desert Southwest and wind power from Rocky Mountain states.
BPA controls the Pacific Northwest’s largest hydroelectric resources — including the Grand Coulee, The Dalles and Chief Joseph dams on the Columbia River — and operates about 70% of the region’s transmission. Its balancing area covers most of Oregon, Washington, Idaho and western Montana, along with smaller portions of California, Nevada and Wyoming.
If BPA signs an agreement with the EIM, it would bring a territory the size of France into CAISO’s real-time market. The EIM has been expanding rapidly, with entities joining or seeking to join from Canada to the Mexican border.
Idaho Power and Powerex began transacting in the market in April, bringing the number of members participating to eight. (See Idaho, Powerex Began Trading in Western EIM.) That expansion equipped the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO.
NV Energy, Arizona Public Service, PacifiCorp, Puget Sound Energy and Portland General Electric are already participants.
The Energy Imbalance Market currently has seven participants in addition to CAISO. | CAISO
The Sacramento Municipal Utility District plans to begin participating in the EIM in April 2019. The Los Angeles Department of Water and Power, Arizona’s Salt River Project and Seattle City Light are scheduled to go live in April 2020. Public Service Company of New Mexico recently received state regulators’ permission to join the EIM by 2021. (See PNM Seeks to Join Energy Imbalance Market.)
In debates about establishing a Western RTO led by CAISO, the EIM often has been held up as a better alternative because, unlike an RTO, the market’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.
The EIM has conferred a half-billion dollars of benefits on participants since its founding five years ago, with $100 million realized in the third quarter of 2018 alone, CAISO officials said in October. (See Western EIM Reports Record Benefits.)
Moreover, the EIM’s board consists of members from multiple states, while CAISO’s board is appointed by California’s governor and confirmed by the State Senate. Industry leaders and officials from other Western states don’t want to cede control to California, and California politicians don’t want to give up authority over CAISO.
A series of CAISO regionalization measures that would have broadened its governance to include out-of-state representatives have failed in the State Legislature in recent years, largely because of this impasse. Proponents of a single RTO for the West say they will likely introduce another bill in January when California lawmakers reconvene for the start of another two-year session. (See Western RTO Proponents Vow to Keep Trying.)
In the meantime, CAISO officials and EIM participants have been pushing ahead to add day-ahead trading to the EIM’s current real-time-only market, bringing it closer to conferring many of the benefits of a regional RTO without the perceived drawbacks.
NYISO must revise its rules governing the installation and reading of demand response meters for participants in its Installed Capacity (ICAP) market, FERC ruled Thursday (EL18-188).
The commission partly granted NRG Curtailment Solutions’ July complaint alleging the ISO’s Tariff provisions are unjust because they require curtailment service providers (CSPs) and responsible interface parties (RIPs) seeking to participate in the ICAP market to use the services of meter service providers (MSPs) or meter data service providers (MDSPs) certified by the New York Department of Public Service to install and read non-revenue grade interval meters.
The New York PSC told FERC that the future of competitive metering services is presently in question in New York.
The ruling denied NRG’s request for waiver of the rules, instead convening a paper hearing to determine replacement provisions.
The commission found the rules unduly discriminatory to the extent they require CSPs and RIPs that are not transmission owners to be certified by the DPS, which certifies only entities that also provide metering services for the state’s retail electric market.
“The result, even if not so intended, is that retail market participation is a prerequisite for demand response resource participation in NYISO’s wholesale market,” the commission said. “Indeed, in this proceeding, the New York [Public Service] Commission disavows the role ascribed to it through NYISO’s requirements and explicitly states that its certification program was designed to facilitate retail billing service, not for participation in wholesale markets or for measuring load reductions.”
FERC noted the PSC “has issued a notice proposing to eliminate the state MSP and MDSP programs and the certifications related to these programs.”
The PSC filed comments in favor of granting NRG the relief it sought, saying “the future of competitive metering services is presently in question in New York. Upon information and belief, there are no known utility customers today who avail themselves of competitive metering services, nor have there been for some time.”
NYISO answered NRG’s complaint Aug. 13 and filed a supplemental answer Oct. 22, saying it is examining its metering requirements as part of its broader DER Roadmap. But FERC found the current metering requirements “in need of immediate remedy.”
The commission established a paper hearing with initial briefs due within 45 days of the order and reply briefs due within 30 days thereafter. It ordered parties participating in the hearing to address the following issues:
What metering requirements could be implemented in NYISO, would not be unduly discriminatory and yet would effectively evaluate, measure and verify customer meter data?
How would such metering requirements address the verification of meter data and auditing of metering service providers?
How would such metering service eligibility criteria ensure that metering services are available to customers in all geographic areas of NYISO?
Would such metering requirements allow self-certification for DR providers in NYISO? If not, please explain why.
FERC said it expects to be able to render a decision within four months of receiving reply briefs, or by May 31, 2019.
NERC on Tuesday warned that faster-than-expected coal and nuclear plant retirements could jeopardize reliability if grid operators are not prepared.
“If these retirements happen faster than the system can respond with replacement generation, including any necessary transmission facilities or replacement fuel infrastructure, significant reliability problems could occur,” NERC said in a special reliability assessment report. “Therefore, resource planners at the state and provincial level, as well as wholesale electricity market operators, should use their full suite of tools to manage the pace of retirements and ensure replacement infrastructure can be developed and placed in service.”
Projected retired capacity as a percent of total capacity in 2022, both currently confirmed and under NERC’s “stress test” scenario | NERC
Calling it a “stress test” of the bulk power system, the organization used data from the U.S. Energy Information Administration to identify generators set to retire through 2025 in 10 areas where coal-fired and nuclear generation make up a significant portion of the resource mix. It then analyzed the impacts of those generators retiring earlier, in 2022.
The analysis found four areas — SPP, SERC-East, WECC-RMRG and WECC-SRSG — in which currently planned generation resources would not be sufficient to make up for the accelerated retirements. NERC determined this by comparing projected planning reserve margins for 2022 under the scenario to projected peak load levels for the year. The organization used data from its 2017 Long-Term Reliability Assessment to determine projected reserve margins under currently confirmed retirements through 2022, to which it factored in the accelerated retirements. It also used the LTRA to determine the projected peak loads.
NERC analyzed the 10 regions where coal-fired and nuclear generation make up a significant portion of the resource mix. | NERC
‘Unlikely’ Scenario
Both the report and John Moura, NERC director of reliability assessment and system analysis, repeatedly emphasized that the analysis was not a prediction.
“I think it’s really important that stakeholders understand that this is a stress-case scenario,” Moura said in a conference call with reporters Tuesday morning. “We’re not necessarily making any recommendations or calls for any additional financial support beyond that which market operators think are required. We completely acknowledge that the scenario as tested is unlikely.”
He noted the organization also analyzes the impacts of geomagnetic disturbances and simultaneous, highly coordinated physical and cyberattacks on the grid. “These are things that we don’t believe will happen, but we think it’s instructive, when we break a system, to understand what are the potential mitigations and see how to get it working.”
“NERC’s stress-test scenario is not a prediction of future generation retirements nor does it evaluate how states, provinces or market operators are managing this transition,” the report says. “Instead, the scenario constitutes an extreme stress-test to allow for the analysis and understanding of potential future reliability risks that could arise from an unmanaged or poorly managed transition.”
Moura also noted that the report doesn’t criticize capacity markets or out-of-market subsidies. “We’re simply saying that these tools need to be monitored and tested in planning,” he said.
Under the “stress-test” scenario, SPP, SERC-East, WECC-RMRG and WECC-SRSG would not have enough new generation to make up for the accelerated retirements. PJM, MISO and ERCOT are just slightly above or equal to the reference levels. (SERC-East and WECC-RMRG’s margins are actually zero or in the negative.) | NERC
Fears of Politicization
NERC was criticized by some stakeholders, including FERC Commissioner Cheryl LaFleur, in early November, when it briefed its Members Representatives Committee on a draft of the report. They feared it would be politicized, and that the press and public would misunderstand it as a warning of things to come. (See LaFleur, Stakeholders Anxious over NERC Retirement Study.)
“Policymakers and regulators should not interpret this study as justifying interventions to artificially retain unprofitable power plants, as these actions deter the economic transition in the power generation fleet, undermine innovation and raise costs to America’s businesses and families,” Devin Hartman, CEO of the Electricity Consumers Resource Council, said in a statement Tuesday.
“As NERC itself states, the report looks at unlikely scenarios that go far beyond either announced or projected power plant retirements to determine at what point there might be some risk for reliability,” said Jeff Dennis, general counsel for regulatory affairs at Advanced Energy Economy. “The report does not provide evidence of any imminent threat to the reliability of the bulk power system. Nor does it suggest that competitive wholesale energy markets aren’t up to the job of ensuring reliability as the resource mix changes.”
The report “relies on too many extremes to be enlightening about real-world grid reliability,” the Natural Gas Supply Association said.
At FERC’s open meeting Dec. 20, LaFleur repeated her criticism, saying the report has a “fundamental flaw” in assuming baseload retirements beyond that currently anticipated but only counting new resource that have been announced. “So there’s an asymmetry in what’s coming out and what’s coming on,” she said. “It’s like saying, ‘What if I gave up 45% of my income and I kept my expenses the same. … You’d have a mismatch by definition.”
LaFleur said it was “noteworthy” that even under NERC’s extreme scenario “there’s not that many resource problems [that] pop up.”
“It’s a big deal … making sure we have enough resources in the future,” she concluded. “But I think we have to make sure that we rely on fact and not projections.”
NERC spokesman Marty Coyne declined to respond to LaFleur’s comments. “We don’t have anything further to say other than what’s in our media release,” he said.
Speaking to reporters after the open meeting, FERC Chairman Neil Chatterjee said he thought “NERC put a lot of work into it, and it was a thorough document. It is one data point amongst many, and I think as it pertains to our actions here at the commission and our resilience docket, my colleagues and I will analyze the myriad of data points that we have before us.”
Tuesday’s report did not include a detailed analysis of natural gas infrastructure; however, NERC said “additional midstream natural gas infrastructure could be required” to respond to early retirements.
In a November 2017 assessment, NERC had recommended industry consider the loss of key natural gas infrastructure in their planning studies under NERC reliability standard TPL-001-4. (See NERC: Natural Gas Dependence Alters Reliability Planning.)
Although NERC sees risks to increasing dependence on renewables and gas-fired generation, Tuesday’s report said that “successfully managed, the changing resource mix can provide … potential benefits to reliability and security of the BPS. Less reliance on large, centralized generation stations and greater use of dispersed networks comprised of smaller diversified generation resources can provide operating and planning flexibility. Additionally, some fuel assurance risks diminish with the changing resource mix. The effects of adverse weather on coal stockpiles or fossil fuel resupply infrastructure may be reduced when natural gas pipelines supply a greater proportion of the generating fleet. Attaining reliability enhancements associated with the changing resource mix is possible when the different challenges to fuel assurance and [essential reliability services] are addressed.”
Natural gas-fired generation’s contribution to the fuel mix in each region. | NERC
Recommendations
NERC included several suggestions to stakeholders, regulators and policymakers in the report, among them a recommendation to incorporate fuel assurance analyses in generator retirement assessments. This would mean factoring in fuel supply infrastructure, new infrastructure requirements for replacement resources, and firm vs. non-firm fuel delivery contracts.
It also recommended that regulators and policymakers consider ways to speed up approvals of infrastructure. “When a generator’s planned retirement is delayed to allow for completion of transmission system upgrades, expedited regulatory proceedings can help minimize the delay,” the report says. “Where more natural gas generation is needed, more natural gas pipeline capacity will likely also be needed.”
But Moura also noted that the report doesn’t make any specific recommendations for the four areas identified by the report as being at risk under the scenario. “We have a lot of confidence in how these areas plan their systems,” he said.
NERC offered a mostly upbeat report on the long-term health of the nation’s grid Thursday, celebrating results from its first interconnection-wide frequency response studies while highlighting the need to model the increasing volume of distributed resources and supplement variable generation with ramping resources.
The 2018 Long-Term Reliability Assessment, NERC’s 10-year outlook for the North American bulk power system, found that frequency response will remain adequate through 2022 despite the loss of synchronous generators and the increase in inverter-based renewables.
“That gives us some confidence in the resource mix and also the ability to … see whether that performance is degrading out in the future — which is really important, so that if there are issues, you can put [in] policies or build new resources,” said John Moura, director of reliability assessment and system analysis, during a press briefing on the report.
Moura noted that FERC Order 842, issued in February, requires all new resources seeking interconnections be able to provide frequency response, calling the requirement “really, really important for reliability.” (See FERC Finalizes Frequency Response Requirement.)
The report said dynamic stability analysis showed both the Eastern and Western interconnections’ generation “sufficiently supports frequency after simulated disturbances despite reductions in inertia” from the loss of synchronous generation. It said ERCOT has operational procedures to address risks from “degraded inertia.”
“My optimism is not only based on the current mechanisms in place but the ability of the industry to respond and adapt to the changes. And so, while today we don’t have really what I would call excellent frequency response modeling capability, we’ve got pretty good [capability]. We’re able to see it,” Moura said. “And I have confidence that we’ll be able to have that excellent frequency response model in by the time we really need it.”
Load & Reserves
The report predicts North America will see compound annual load growth of only 0.57% for summer and 0.59% for winter, with five areas — New York, New England, the Maritimes, Manitoba and the California-Mexico region (most of California and a northern sliver of Baja California) — expecting reductions in peak demand. The fastest growing regions are ERCOT and the Rocky Mountains region of the Western Electricity Coordinating Council, both projected to grow about 1.8% annually.
The report did identify concerns, noting that ERCOT’s anticipated reserve margins are below targets for the next five years, with MISO and Ontario foreseeing reserve shortfalls beginning in 2023. (See ERCOT Predicts Tight Reserve Margin for 2019.) But it said the shortfalls could be filled by accelerating construction of additional Tier 2 resources — those that have met milestones such as completing feasibility, system impact or facilities studies.
The report includes new probabilistic evaluations — loss-of-load studies that evaluate all hours of the year — which found the California-Mexico assessment area of WECC at risk of 2.3 loss-of-load hours in 2022, with an expected 152 MWh of unserved energy. “These are not significant numbers … but it’s a faint signal that tells us about risk that may not be occurring in the peak hour,” Moura said.
Following Florida, California
The report projects 100 GW of new generation in the next decade, including about 41 GW of gas and 60 GW of solar. ERCOT and the California-Mexico region expect gas generation to contribute more than 60% of on-peak capacity, while Florida expects gas’ share to rise from 70% to 80%.
“When you do have this level of natural gas resources, you have to plan differently,” Moura said. “There are things that, for example, Florida does that other areas may need to do in the future, such as procuring more firm gas … or ensuring we have more dual-fuel capabilities.”
California is leading the way in addressing reliability risks from increasing solar, with CAISO’s three-hour ramping needs hitting a record 14,777 MW last March and expected to rise to 17,000 MW by 2022.
“As solar generation continues to increase in California and elsewhere across North America, system planners should ensure sufficient flexible ramping capacity, including large-scale energy storage,” the report said.
More than 30 GW of new distributed solar PV generation is expected by the end of 2023, with California expected to reach 18 GW of capacity, almost 40% of its projected peak. New Jersey, Massachusetts and New York are projected to each have 3.5 to 4 GW of distributed solar by 2023.
“There’s more [distributed energy resources] coming online faster than we’ve really ever seen any type of resource coming on. … If that’s not represented in models, we’re going to be modeling the system completely inaccurately. And if we don’t have flexibility in our resources, we really won’t be able to meet the challenges of the daily demand curves,” Moura said.
“In areas that may not have a lot of DER, or only starting to get DER, it’s perhaps common for planning studies to negate them or net them out or mostly ignore them. However, as we get a larger penetration of DERs, it’s really important that their characteristics are modeled,” Moura said. “Engineers and planners need to prepare data specifications and data exchanges that are needed now so that we have a better understanding of what the system’s going to look like in the future.”
This fall, NERC created a new working group to guide its efforts: System Planning Impacts of DER (SPIDER).
Recommendations
Among the report’s recommendations was a call for NERC’s Reliability Assessment Subcommittee to lead development of common metrics to assess energy adequacy. “Additional analysis is needed to determine energy sufficiency, particularly during off-peak periods and where energy-limited resources are most prominent.”
Similarly, it urged NERC’s Planning Committee to develop a common framework for assessing fuel disruptions, saying “system planners should identify potential system vulnerabilities that could occur under extreme, but realistic, contingencies and under various future supply portfolios.” The assessments could be used to develop regulations or market mechanisms to promote fuel assurance.
“A common approach for what kind of contingencies to study would be very valuable to the industry,” Moura said.
Environmental groups asked Tuesday that new FERC Commissioner Bernard McNamee recuse himself from the commission’s resilience dockets because of his advocacy for coal and nuclear plants during his time at the Department of Energy.
The motion by the Natural Resources Defense Council, Sierra Club and Union of Concerned Scientists echoed concerns Senate Democrats expressed during McNamee’s confirmation hearing in November (RM18–1,AD18-7). McNamee was sworn in on Dec. 11 after winning confirmation on a 50-49 party line vote.
McNamee’s role in DOE’s Notice of Proposed Rulemaking and the agency’s second proposal, to save at risk generators under the Defense Production Act, “create the appearance that Commissioner McNamee has prejudged central matters of law and fact that remain at issue in these proceedings,” the environmental groups wrote.
As Deputy General Counsel for Energy Policy at DOE, McNamee signed the NOPR, which asserted that “[t]he resiliency of the nation’s electric grid is threatened by the premature retirements of power plants that can withstand major fuel disruptions caused by natural or manmade disasters.” The NOPR proposed eligible fuel-secure units within PJM, NYISO, MISO and ISO-NE receive “full recovery of costs,” including a return on equity, arguing wholesale pricing in organized markets “does not adequately consider or accurately value” resiliency benefits of fuel-secure generators.
McNamee also worked on DOE’s second proposal, which asserted that “retirements of fuel-secure electric generation capacity across the continental United States are undermining the security of the electric power system because the system’s resilience depends on those resources.”
The environmental groups cited a series of court rulings outlining the circumstances in which recusal is required. “Due process considerations require that an adjudicator `who participates in a case on behalf of any party, whether actively or merely formally by being on pleadings or briefs, take no part in the decision of that case by any tribunal on which he may thereafter sit,’” they wrote, quoting from a 1958 D.C. Circuit Court of Appeals ruling.
The groups also noted FERC’s rejection of the DOE NOPR (RM18-1) is still subject to rehearing request by the Foundation for Resilient Societies. “McNamee’s participation in these rehearing requests would violate the venerable prohibition against a man standing in judgment of his own cause, and due process,” the groups said, adding that McNamee also should recuse himself from the resilience docket the commission opened in January when it rejected the NOPR (AD18-7).
‘Same Factual Questions’
“The resilience docket therefore encompasses the very same factual questions that were answered by the department, and by Commissioner McNamee on behalf of the department, in the DOE NOPR: whether the grid is threatened by retirements of so-called `fuel secure’ power plants and whether and to what extent such `fuel secure’ resources are necessary to the reliability and resiliency of the grid… The mere technicality that the two proceedings have different docket numbers, where the substantive matters at issue are materially the same, does not make the resilience docket a sufficiently distinct matter for the purposes of the due process inquiry.”
The groups cited comments filed Dec. 6 by the Harvard Electricity Law Initiative, which also questioned McNamee’s impartiality. “His recusal must extend beyond these two dockets,” wrote Ari Peskoe, the director of the law project. “The NOPR’s sweeping conclusions prejudge issues that could appear before the commission in ratemaking proceedings. This prejudgment is substantially different from a commissioner’s public statements about policy issues, which the commission has recently determined were not a basis for recusal.”
Democrats also were alarmed by comments McNamee made in a videotaped speech in February after briefly leaving DOE and working for a conservative think tank’s project to “reframe the national discussion” about fossil fuels. McNamee said renewables are disruptive to “the physics of the grid” and described environmentalists’ activism against fossil fuels as a “constant battle between liberty and tyranny.”
After the video became public, Sen. Maria Cantwell of Washington, the ranking Democrat on the Energy and Natural Resources Committee, questioned McNamee in writing about his comments, asking: “How can environmental groups possibly expect a fair shake from you as a FERC commissioner?”
McNamee responded: “I understand the difference between being an advocate and an independent arbiter.”
McNamee and FERC Chair Neil Chatterjee declined to comment on the recusal motion.
Comments Filed
McNamee replaced former Commissioner Robert Powelson, who joined in FERC’s 5-0 vote rejecting the DOE NOPR and opening the new resilience docket in January. The commission has received two rounds of comments in the new docket, including a June request by FirstEnergy for an emergency order to preserve fuel-secure generating resources. (See RTO Resilience Filings Seek Time, More Gas Coordination and Don’t Rush on Resilience, Commenters Urge.) The commission has given no indication of what it will do, if anything, in response.
It’s the end of an era at PJM: Following the Dec. 20 Markets and Reliability Committee meeting, GT Power Group’s Dave Pratzon will call it a career after 45 years.
Over that time, Pratzon has seen many of the biggest changes to the electricity industry from the trenches, having been involved in developing a number of the processes and rules that would eventually make up the grid and its markets as they are today.
“I care about the success of the enterprise. I want to deploy myself to the end,” said Pratzon, who turns 68 later this month.
A Fate-full Career
Pratzon describes his career as “an accident of fate,” or more accurately, a series of them, starting with how he got into the power business in the first place. While he went to college to become an electrical engineer, he spent his summers laboring at a local steel mill near his home in Wallingford, Conn. However, the job was threatened each year by union unrest or overproduction at the mill. He took the suggestion of a college friend from Philadelphia to join him in seeking summer employment with the Philadelphia Electric Co. (now PECO) and found himself working on substations.
Upon graduation, he attempted to land a full-time position at the utility, only to have the offer rescinded at the last moment. Scrambling, he found work near San Francisco as a field engineer for nuclear submarines. On a trip back East to propose to his fiancée, Gail, and pick up a car,he happened to swing back through Philadelphia and stop in PECO’s offices.
“You got my letter!” a former supervisor said upon greeting the bewildered Pratzon.
“I’m just driving through,” he responded.
The boss said they were trying to contact him about a job opening and asked if he had time to interview.
“Sure,” Pratzon said, “as long as it’s today.”
The company’s response traveled faster to his West Coast home than he did.
“By the time I got there, there was the letter with my official offer,” Pratzon said.
He quit the submarine job, partially to move back closer to home but also because part of his job would have involved “sea trials” of the ships, and he realized he’s claustrophobic.
“I could never survive out there for a week or two under water in steel containers,” Pratzon said. “I was happy to come back. … It was kind of a step back to the East Coast that I figured would be another temporary position on my way back to New England.”
It would be his last major move.
“My wife and I, being New Englanders, thought this would be a temporary job before moving [back] up there, but 45 years later, we haven’t left yet,” Pratzon said.
Gail became a librarian and helped found the public library in their town, Lower Providence Township.
“Opportunities have come for both of us,” he said.
PJM Work
From his first day at PECO, Pratzon was heavily involved with PJM. PECO supplied PJM’s staff for the first several decades after its founding, and Pratzon worked for the grid operator from 1973 to 1991 before being transferred to PECO as a “broadening” assignment. He was the first secretary of PJM’s cost-development subcommittee in the mid-1970s and helped develop the initial market rules that he jokes PJM Independent Market Monitor “Joe Bowring may or may not like right now.”
Pratzon’s career was a period of change for both the industry and PJM, which began transitioning to an independent organization in 1993. In 1997, it opened its membership to non-utilities and elected an independent Board of Managers.
“The market was very different when it was just the eight companies dealing with each other,” he said, referring to PECO, Public Service Electric & Gas, Pennsylvania Power & Light, General Public Utilities (GPU), Baltimore Gas & Electric, Potomac Electric, Atlantic City Electric and Delmarva Power and Light.
The first major transition occurred during the Three Mile Island crisis, when plant owner GPU began searching for power supplies outside of the other seven utilities in PJM at the time. Up until then, the companies had bought and sold amongst each other with PJM determining which plants would run to provide all of the power necessary at the cheapest overall cost.
Each day, the companies would submit their projected costs to run each plant the following day. If one company’s plant would cost more to run the next day than those of other companies, PJM would dispatch the cheaper plant to cover the demand and charge the company with the more expensive plant half of the difference between the plants’ costs in an accounting method known as “split savings.”
But GPU’s alternative during the TMI crisis was combustion turbine plants, which were experiencing a crisis of their own during the oil shortages of the 1970s. Using the expensive CTs as the baseline cost under the split savings method would have cost GPU a fortune, so the company sought alternatives outside of the PJM ring. It was controversial and “unheard of at the time,” Pratzon said, at least partially because the other companies anticipated the profits they might make from GPU’s problems.
GPU, however, saw external tie lines that weren’t being used. “They were the first PJM utility to go out on their own,” he said.
Another blow to split savings occurred when merchant generators entered the market thanks to open-access transmission lines and subsequently refused to share their cost information.
By the time PJM began working on its locational marginal pricing proposal, Pratzon had left the grid operator and was working at PECO.
From 1992 through 2002, he advocated for PECO’s interests, including testifying at FERC in opposition to LMP. PECO at the time thought a bilateral-contracting approach would be more profitable. Pratzon was also involved with developing the wholesale market participation rules for competitive suppliers in Pennsylvania, the first state in PJM to adopt retail customer choice.
While “in the beginning, a lot of [his work at PECO] was reactionary” to what was happening in the industry, the company soon started to notice opportunities, such as selling the excess generation from its Limerick 2 nuclear plant into PJM’s markets after its failed effort to get Pennsylvania Public Utility Commission approval to include it in ratepayers’ bills.
Those experiences precipitated PECO forming a Power Team to market the excess power. “If you can’t beat them; join them,” said Pratzon, who was on the team from 2002 to 2012.
Exelon’s merger with Constellation in 2012 moved the Power Team to Baltimore. Instead of moving further from his New England roots, Pratzon lit out on his own and eventually joined with former Pennsylvania PUC Chair Glen Thomas’ GT Power Group, which already represented the PJM Power Providers group known as P3.
While Pratzon did testify at the PUC during Thomas’ tenure as the commission’s chair, they had never met.
“I don’t remember him being there; he doesn’t remember me testifying,” Pratzon said. “He heard about me through mutual acquaintances.”
Enjoying Every Minute of It
Even as his time has been wrapping up, Pratzon has remained active and vocal in stakeholder meetings.
“I’ve loved every minute of it,” he said. “It’s never the same thing twice. … I’ve invested so much of my work career into PJM and trying to help and resolve [issues].”
He hopes to have brought an attitude to the process of “trying to understand and respect the views and positions and needs of the many stakeholder groups and trying to find solutions that will help the market thrive.”
“I think … there is maybe now less of the collaborative spirit than there has been [at] times in the past. I’m not sure I can put my finger on why,” he said. “I’ll miss being part of the hopeful solution.”
PJM is a “good atmosphere to try to resolve the new issues as they come up” because while the RTO “has the hammer” to implement rules as it sees fit, it “respects and listens to stakeholder input.”
“It happens in PJM more than perhaps in any other RTO,” Pratzon said.
So why leave now?
“I feel like I have to be all-in” to do this work, he said, and to do less “would feel like dabbling.”
Instead, he’s becoming a “full-time project manager” for three months to renovate his kitchen and plans to spend more time with his three- and six-year-old grandchildren.
Traveling is in the works “to get around and see more of the world than we have in the past,” and he’ll be volunteering with an elder support group in town to meet more people and aid those who might otherwise be lonely.
Still, the stakeholder process and what it means won’t ever be far from his mind. In breaking the news of his retirement to industry colleagues, Pratzon has become fond of making a final request:
“Just remember: Keep the lights on for me now that I’m just a retail customer!”
MISO this week opened the floor to stakeholders’ ideas on transmission projects to relieve congestion in MISO South and near the SPP-MISO seam.
During a Dec. 18 South Subregional Planning Meeting, MISO Planning Manager Matt Ellis asked for stakeholder help in identifying project candidates for the South region as part of MISO’s annual Transmission Expansion Plan (MTEP) cycle. The MTEP 19 solution submission window will close March 1.
MISO has compiled a preliminary list of four congested flowgates with upgrade potential in and around MISO South and the MISO-SPP seam, though the RTO is telling stakeholders to expect lower congestion in 2019 and beyond.
MISO Economic Studies Engineer Karthik Munukutla said several top congested areas in MISO South have already been addressed with MTEP projects, coming online as early as this month and as late as mid-2023. Munukutla also said congestion will subside due to low energy demand and potential distributed resources further reducing those needs. However, he said some local resource zones expecting high renewable penetration may experience higher congestion.
MISO predicts future flowgate congestion at the Bullshoals-Midway Jordan 161-kV line near the Missouri border in northern Arkansas and the Fulton-Patmos 115-kV line in southwestern Arkansas. The RTO also predicts seams congestion around the Raun-Tekamah 161-kV line on the Iowa-Nebraska border and the Neosho-Riverton 161-kV line on the eastern Kansas-Nebraska border.
Top congested flowgates in MTEP 19 | MISO
MISO officials said a complete list of MISO South and MISO-SPP issues and a formal request for ideas will be sent via email to stakeholders in early January.
Project ideas will be analyzed under the MTEP’s 2019 Market Congestion Planning Study (MCPS), the first such footprint-wide study since Entergy’s five-year transition period began in 2013. The transition period, which expires at the end of 2018, has limited the cost-sharing of transmission projects.
Going forward, the RTO will discontinue its practice of creating separate studies for MISO Midwest and MISO South, though the MCPS will continue to focus on subregional needs. In another first, the MCPS will also contain MISO-PJM and MISO-SPP congestion analyses that could produce an interregional congestion-relief project.
RENSSELAER, N.Y. — Interim NYISO CEO Robert Fernandez told the Management Committee on Wednesday the Board of Directors this month had “reached a unanimous decision” on the AC Public Policy Transmission Project approved by the committee last summer and would release its decision no later than Dec. 27.
The MC in June backed joint proposals by North America Transmission (NAT) and the New York Power Authority (NYPA) to build two 345-kV transmission projects that could cost $900 million to $1.1 billion and would address persistent transmission congestion at the Central East interface and Upstate New York/Southeast New York interface. (See NYISO MC Supports AC Transmission Projects.)
Potomac Economics, NYISO’s Market Monitoring Unit, said the AC Public Policy Transmission Projects will be economic if the state Clean Energy Standard is satisfied with high levels of intermittent renewable generation upstate. | Potomac Economics
The MC selected project T027, a double-circuit 345-kV line from Edic to New Scotland, along with project T029, a standard 345-kV line from Knickerbocker to Pleasant Valley.
Winter Outlook
Vice President of Market Operations Emilie Nelson reprised the winter outlook, saying the ISO will have adequate capacity on hand to meet its forecasted peak demand of 24,269 MW for the 2018/19 winter season, well under last winter’s peak of 25,081 MW. (See NYISO Forecasts Adequate Capacity for Winter.)
Balancing Energy Tariff Revisions Okd
The MC approved Tariff changes clarifying real-time market settlements and their interaction with energy storage resources (ESRs), subject to approval by the Board of Directors in January.
ISO staffer Christopher Brown told the committee the changes do not affect calculations or require software modifications. (See “Real-time Market Settlements Clarifications” in NYISO Business Issues Committee Briefs: Dec. 12, 2018.)
Energy imbalance payments and charges address the differences among actual energy injections or withdrawals and real-time and day-ahead energy schedules. The changes apply to the injections and withdrawals of ESRs and include terms introduced and defined in the ISO’s FERC Order 841 compliance filing submitted Dec. 3 (ER19-467). (See RTOs/ISOs File FERC Order 841 Compliance Plans.)
