Sempra Energy’s $9.45 billion bid for bankrupt Energy Future Holdings and its 80% interest in Oncor cleared a second major hurdle within a week after the California-based company reached a settlement agreement Thursday with several key Texas stakeholder groups.
The agreement represents a “significant step forward” and demonstrates “positive momentum” for Sempra’s proposed acquisition of a majority stake in the Texas utility, both companies said. Under the settlement, the parties have agreed that the acquisition is in the public interest, meets Texas statutory standards and will bring substantial benefits.
On Monday, FERC filed a boilerplate order approving the acquisition. (See “FERC OKs Sempra Acquisition of Oncor,” Company Briefs.)
Parties to the settlement agreement include the Public Utility Commission of Texas staff, the Office of Public Utility Counsel, Steering Committee of Cities Served by Oncor and Texas Industrial Energy Consumers. They will ask the PUC to approve the acquisition, consistent with the governance, regulatory and operating commitments in the agreement, the companies said.
Sempra said the agreement includes regulatory commitments that preserve the existing Oncor ring-fence and the independence of the utility’s board of directors. To protect Oncor, its customers and employees, the commitments also include extinguishing all debt currently held by EFH and Energy Future Intermediate Holding Co., the company said.
One consumer representative called the settlement a “good deal for customers,” saying Sempra agreed to a more robust ring-fence than was in place earlier for EFH or Berkshire Hathaway Energy, which appeared to have a solid $9 million all-cash offer until Sempra stepped in. (See Sempra Outmuscles Berkshire for Oncor.)
| Sempra Energy
Sempra CEO Debra Reed said she was pleased with the support from the groups. “We strongly believe that this transaction will benefit Oncor customers and the state of Texas, and we are working with the PUC to facilitate its comprehensive review of our proposal.”
The PUC now holds the key to approval. The commission said in October it would complete its review within 180 days — by early April 2018. It has scheduled a Feb. 21-23 hearing on the acquisition in Austin. (See Texas Regulators Seek More Details on Sempra Oncor Bid.)
The PUC has seen a changeover among its commissioners since the unsuccessful attempts by Hunt Consolidated and NextEra Energy to acquire Oncor. Chair DeAnn Walker and Arthur D’Andrea have replaced Donna Nelson and Ken Anderson, respectively, with Brandy Marty Marquez the only holdover.
Sempra Energy headquarters | Sempra Energy
“Our partnership with Sempra Energy will result in a strong, well-capitalized Oncor that will help Texas continue to grow and invest in a safer, smarter, more reliable electric grid in the years to come,” Oncor CEO Bob Shapard said. “This settlement agreement moves us one step closer to ending the EFH bankruptcy process.”
Sempra announced the deal in August. It was approved by the U.S. Bankruptcy Court in Delaware in September but is still subject to a confirmation hearing by the court after PUC approval.
NERC released its annual Long-Term Reliability Assessment on Thursday, calling for more efforts to preserve “essential reliability services” provided by coal and nuclear plants but saying it is agnostic as to how FERC and regional grid operators do so.
“FERC should consider the reliability and resilience attributes provided by coal and nuclear generation to ensure that the generation resource mix continues evolving in a manner that maintains a reliable and resilient” bulk power system (BPS), the 2017 report said.
NERC’s concerns that the increase in natural gas and renewable generation could endanger grid resilience puts it squarely in the middle of the debates over state nuclear subsidies and Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants in organized markets.
“The changing composition of the North American resource mix calls for more robust planning approaches to ensure adequate essential reliability services and fuel assurance,” the report said, calling for new metrics to supplement reserve margins and requirements that all new generation provide voltage support and frequency response.
“What would be a bad thing is if we bring on a lot more gas-fired generation but all that gas-fired generation … can be interrupted, especially during winter peak times,” John Moura, NERC’s director of reliability assessment and system analysis, said during a media briefing on the report. “We replaced coal and nuclear that has some resilience to extreme weather and they’re going to be there, with resources that don’t have that. That’s our responsibility to look at and call out but … we do not have the authority or really the view as to how the market should address that.”
Recommendations
The report said:
FERC should support new products and revised market rules to ensure “essential reliability services” including frequency response and ramping.
State, federal and provincial regulators must recognize the long lead times for generation, transmission and natural gas infrastructure and the difference between regulated areas with long-term integrated resource plans and organized markets that can lose a generator with as little as 60 days’ notice.
State and federal policymakers, including the Department of Energy and FERC, should consider the impact of natural gas disruptions on the BPS when evaluating infrastructure requirements. Transmission planners and operators should identify reliability concerns resulting when a large share of gas generators rely on interruptible fuel contracts.
System operators and planners should gather more data on the “aggregate technical specifications” of distributed energy resources on local distribution grids to ensure accurate planning models, coordination of system protection and real-time situational awareness. Moura said the aggregate amount of behind-the-meter resources “is generally well known,” but that bus locations and technical specifications such as protection settings and voltage operating ranges are not.
In addition, NERC said it would conduct a “comprehensive evaluation” of its reliability standards to ensure their compatibility with nonsynchronous and distributed resources. “A lot of our standards were written largely for conventional generation, and words like ‘tripping’ or ‘spinning’ that are … well known when we’re talking about conventional generation don’t completely translate when we’re talking about asynchronous machines and inverters,” Moura said. “And so, we really need to look at our standards to make sure we’re not missing anything when we have more nonsynchronous machines on the system.”
| NERC
NERC also said it will monitor reserve margins, citing projected shortfalls in ERCOT and the SERC Reliability region. The reserve margin in SERC-E, which comprises utilities in the Carolinas that aren’t part of PJM, is expected to fall below the reference margin level beginning in 2020 because of the canceled expansion of the V.C. Summer nuclear power plant. The announcement of 4,600 MW of coal and gas retirements this fall means ERCOT reserve margins will fall below targets by summer 2018.
Higher Reserve Margins, Additional Metrics Needed
“As we see the resource mix change, we’re really making a call to action to industry and regulators to increase the robustness of the planning approaches,” Moura said.
In the past, he said, planners assumed fuel would be available and that there would be generators with sufficient inertia to control frequency response. Neither is a given, he said, as the mix changes to more gas and renewable generation.
The report said increasing variable generation may require more planning reserves to maintain the one-day-in-10-years loss-of-load-expectation, boosting target reference margin levels to 17% from 15%.
Since 2008, all but one of nine regions increased their reserve margins by about 2 percentage points. The exception was SPP, which has seen its reserve margin drop from 13% to about 12% over 10 years. ERCOT and Quebec are currently below 15%, although they have increased over the last decade.
Essential Reliability Services
Moura acknowledged that NERC has made the recommendation for preserving reliability services before. “But we wanted to reiterate it here: that all new resources, no matter the fuel, need to have the capability to support voltage and frequency response.”
He said FERC’s November 2016 rulemaking proposing changes to its pro forma generator interconnection agreements seeks to address the frequency response issue but said it’s up to states to implement the interconnection requirements. And even that, he said, is not sufficient. (See FERC Has More Questions on Frequency Response NOPR.)
Interconnection requirements don’t “guarantee any performance,” he said. “It requires them to have the capability and the [ability] to provide it, but in market areas, if they’re not bidding in and being incentivized to provide that frequency response, they don’t.
“We’re not in trouble right yet with frequency response,” he added. “But we see it on the horizon.”
Similarly, he said ERCOT’s establishment of a “critical inertia” level of 100 GW/s is “a really good approach to manage this. But a long-term mechanism will be needed as even more … wind will be coming on to their system.”
Gas Supply
The report notes that on-peak natural gas capacity has increased from 280 GW in 2009 to 442 GW today, with another 32 GW of gas capacity planned for the next 10 years. It projects the Florida Reliability Coordinating Council assessment area will rely on gas for 78% of its power by 2022.
“Areas can have and can rely on large amounts of natural gas as long as they have fuel assurance mechanisms, and Florida does that very well,” Moura said. “They have dual-fuel requirements as well as firm transportation … and the pipeline was really built for the natural gas generation in that area.”
Moura also said PJM’s Capacity Performance requirements and ISO-NE’s Pay-for-Performance program is “exactly what we’re looking for.”
“But the jury’s still out as to whether or not those penalties for nonperformance will compel generators to get dual fuel. … At least in New England, states have been very clear that new natural gas pipelines aren’t wanted.”
| NERC
The report also pointed out that the 0.61% (summer) and 0.6% (winter) 10-year annual demand growth rate for North America is the lowest on record. Despite flat loads, it noted grid operators added more transmission during 2006-2015 compared to 1991-2005.
RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $34.72/MWh in November, a 5% increase from a year earlier, Senior Vice President for Market Structures Rana Mukerji told the ISO’s Business Issues Committee (BIC) on Wednesday.
Locational-based marginal prices (LBMPs) averaged $30.60/MWh for the month, up 8% from October and up 16% from November 2016. The ISO’s average daily sendout was 403 GWh/d, compared with 398 in October and a year earlier.
| NYISO
New York natural gas prices gained nearly 19% in November, averaging $2.92/MMBtu at the Transco Z6 hub. Prices were up 33.5% from a year ago.
Distillate prices gained 31% year on year, with Jet Kerosene Gulf Coast averaging $13.04/MMBtu, up from $12.30 in October. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.70/MMBtu, compared with $12.86 in October.
The ISO’s local reliability share was 20 cents/MWh, up 6 cents/MWh from the previous month, while the statewide share dropped 10 cents/MWh from the previous month to -50 cents/MWh. Total uplift costs were lower than in October.
| NYISO
RTC and RTD Efficiency
In reviewing NYISO’s Broader Regional Markets report, Mukerji highlighted the ISO’s effort to increase the consistency between real-time commitment (RTC) and real-time dispatch (RTD) modeling and identify improvements to look-ahead evaluations in order to improve scheduling and price convergence. The Market Issues Working Group reviewed staff analysis of the issue Dec. 5, and the ISO expects by the end of the year to release a whitepaper identifying efforts to further explore RTC-RTD convergence in 2018.
Mukerji also noted that PJM has asked NYISO to review the former’s proposed pro forma pseudo-tie agreement that would apply to New York Control Area generators that sell all or a portion of their capacity to the RTO. PJM would provide commitment and dispatch instructions to pseudo-tied generators, which would be committed and dispatched to meet the RTO’s — rather than NYISO’s — needs.
NYISO has expressed concerns about using PJM’s proposed pseudo-tie agreement but said it’s prepared to work with the RTO to evaluate potential alternate solutions acceptable to both grid operators. FERC last month issued an order (ER17-1138) accepting many of PJM’s proposed pseudo-tie rules. Rehearing requests on the order are due Dec. 15, and NYISO said it was still evaluating its options.
Mukerji said NYISO is also modifying the rules for documenting capacity imports across PJM AC ties. The ISO’s proposal would require load-serving entities to submit evidence that an external resource with a capacity award has firm transmission service across the ties on the same day installed capacity (ICAP) results are posted. The Installed Capacity Working Group last month reviewed sample document types that would satisfy the requirement, which is slated to become effective May 1, 2018.
NYISO is additionally negotiating with PJM on cost sharing for the Ramapo 3500 phase angle regulator that was replaced by Consolidated Edison in September and plans to hold a joint NYISO/PJM stakeholder meeting on the issue in early 2018, Mukerji said.
On/Off Ramp Rule Changes
The committee also reviewed a complete market design proposal for “on/off ramp” rules the ISO uses to decide whether to eliminate or create localities within its market. Randy Wyatt, senior market design specialist for the ISO, told the committee that the proposed methodology is based on reliability planning principles.
Wyatt said the project is designed to ensure that locality price signals allow developers to make informed and efficient investments that enhance grid reliability. The committee will take up the subject again in the first quarter of 2018.
Charter Update for Integrating Public Policy Task Force
NYISO Executive Vice President Rich Dewey presented a revised charter for the Integrating Public Policy Task Force (IPPTF), which he said incorporated “some, but not all” stakeholder comments received so far.
The charter states that the BIC will receive monthly progress reports from the task force and that “any potential changes to NYISO tariffs, agreements, manuals or any other guiding documents” will be subjected to the ISO’s governance process.
NYISO and the New York Public Service Commission jointly formed the task force in October to create a forum for stakeholders to discuss pricing carbon into the wholesale electricity market. The task force held its first technical conference on Monday. (See New York Hashes out Details of Carbon Policy.)
Dewey acknowledged that there had been some confusion about why a new group was needed and explained that planners realized that integrating the state’s policy on carbon into the power markets would require a high degree of coordination between the ISO and state agencies.
The IPPTF’s next public hearing is scheduled for Jan. 8 in Albany.
CAISO is floating a proposal that would extend many of the features of its day-ahead market into the footprint of the Western Energy Imbalance Market (EIM) while possibly averting some of the thorny governance issues related to regionalization of the ISO.
CAISO’s 2018 Policy Roadmap | CAISO
The proposal is part of a broader plan focused on improving CAISO’s day-ahead market to better deal with emerging trends in resource procurement and planning, the ISO said. CAISO is including the plan in its Draft 2018 Policy Roadmap, which will guide the ISO’s many ongoing initiatives over the next three years related to grid operations, markets, new resources and generator retirements.
But a proposed expansion of the ISO’s day-ahead market could face competition from other corners. Reliability coordinator Peak Reliability and PJM announced last week they will explore the development of markets and other services in the West. (See PJM Unit to Help Develop Western Markets.) Farther inland, Mountain West Transmission Group is advancing on plans to integrate its member utilities into SPP.
California’s efforts to regionalize CAISO’s operations have twice stalled in the State Legislature in the last two years over concerns the state would cede too much oversight of its grid to other Western states less friendly to its ambitious environmental policies. Those states, in turn, have been wary of submitting control of their transmission systems to an entity controlled by their much larger neighbor.
An industry source, who wished to remain anonymous because they were not authorized to speak publicly, told RTO Insider that several present and future EIM members were gathering in Phoenix this week to discuss changes to the ISO’s day-ahead market. But Idaho Power spokesperson Brad Bowlin could not confirm the meeting.
“Unfortunately, we are not able to respond to your questions about this,” Bowlin said. “Any information will have to come directly from CAISO.” Idaho Power is scheduled to join the EIM next spring.
ISO spokesman Steven Greenlee said he was not aware of the meeting.
Integrated resource plans, resource adequacy and CAISO markets must align to meet policy goals | CAISO
The ISO’s proposal would create something like an “RTO-lite,” allowing for each EIM balancing authority (BA) to retain its reliability responsibilities and assuring that states could maintain control over integrated resource planning. Under the plan, resource procurement would remain under the authority of local regulators that — along with BAs — would continue to direct transmission planning and investment decisions.
CAISO said its effort would target better load management, more integration of distributed resources and enhancements to the EIM. Primary among the challenges the ISO faces is a shift toward more renewable and distributed energy resources, and conflicts between resource planning and reliability planning that are driving an increased need for out-of-market reliability-must run contracts for natural gas plants. (See Board Decisions Highlight CAISO Market Problems.)
“Recent grid operations challenges [point] to [the] need for day-ahead market enhancements to better manage [the] net load curve in real time,” the ISO said in a presentation prepared for a Dec. 14 call about the roadmap.
Extending the day-ahead market to the EIM would improve scheduling efficiency and integration of renewables, and allow EIM participants to take advantage of enhancements to the market, the ISO said. The ISO re-prioritized its initiatives to focus on the day-ahead market changes as well as deferring development of some other market products.
CAISO is proposing changes to the day-ahead market to “address net load curve and uncertainty previously left to [the] real-time market.” These include 15-minute scheduling granularity and a “flexible reserve” product that pays resources for must-offer obligations in the real-time market to address load uncertainty. Also being contemplated is combining the integrated forward market and the residual unit commitment process.
Extending the day-ahead market to the EIM would require market members to align transmission access charge models, according to the ISO. It would also involve expanding congestion revenue rights across the expanded footprint and analyzing day-ahead resources so balancing areas don’t “lean on” each other for capacity, flexibility or transmission.
The ISO is also planning collaborative programs with the California Public Utilities Commission to better align resource adequacy planning with reliability planning and the changing grid.
The policy initiatives catalog lists CAISO’s many ongoing updates to market rules, the EIM, distributed resources, generation retirements and changing conditions on the grid. Part of the roadmap process is the February updating of the catalog.
The final roadmap is due to be posted on Jan. 10, and more stakeholder calls will be held prior to review by the CAISO Board of Governors on Feb. 15. The ISO will accept comments on the draft roadmap until Jan. 4.
CAISO day-ahead prices hit all-time highs for the second time this year during the third quarter, and the frequency of price spikes in the 15-minute and five-minute markets increased, the ISO’s Department of Market Monitoring said in its quarterly market performance report.
| CAISO
High temperatures in California drove up demand at the beginning and end of August and into September, according to the report. Load peaked at 50,116 MW on Sept. 1, just short of the 50,270-MW peak record set in July 2006. Trading that day also saw day-ahead system marginal prices soar over $200/MWh during a four-hour period and hit $770/MWh in one interval.
| CAISO
“These outcomes were primarily driven by tight supply conditions as a result of a number of factors in combination with high demand while a significant amount of solar production is ramping down during sunset hours,” the report said. Average 15-minute market prices increased during every month of the third quarter from about $34/MWh in June to more than $45/MWh in September because of higher temperatures and loads.
The Monitor also confirmed that software problems had caused day-ahead prices to hit record highs in the second quarter even after being mitigated. In its second-quarter report, the department had noted that prices should not rise after mitigation and said it was investigating the cause. (See Monitor: CAISO Q2 Prices Hit Record Despite Mitigation.) The third-quarter report said the error was fixed on July 22.
“The ISO has determined that a software error introduced in 2016 resulted in infeasible energy and ancillary service awards for resources in the market power mitigation run but not the binding market run in the day-ahead market,” the Monitor said in the third-quarter report. “The software error resulted in an erroneous increase in supply available in the market power mitigation run, causing prices in that run to be lower than they would have been had all awarded schedules been feasible.”
CAISO is “currently evaluating the impact of this error on the market power mitigation process on affected days,” the report said.
Day-ahead prices appeared to be competitive in most hours, the Monitor said, and total year-to-date wholesale energy costs are close to 2016 totals, after the prices are adjusted for natural gas and greenhouse gas prices. Higher gas prices resulted in larger overall energy costs for 2017.
Transmission congestion was low in the day-ahead market in the Pacific Gas and Electric and Southern California Edison service areas but caused prices to drop about 2% in San Diego Gas & Electric’s area. Congestion in the 15-minute market pushed up prices in PG&E and SCE and decreased SDG&E prices. Frequent congestion on the Doublet Tap-Friars 138-kV constraint created an export-constrained area, undercutting prices in San Diego.
The Monitor said its analysis of natural gas price volatility shows a limited need for increased bidding flexibility created by raising commitment cost and default energy bid caps. CAISO followed the department’s recommendation and reduced the Aliso Canyon real-time gas scalars to zero beginning Aug. 1, raising them again temporarily Aug. 4-7 because of hot conditions.
Congestion revenue rights auctions took in $9 million less than payments to entities purchasing those rights, increasing year-to-date ratepayer losses to $38 million and to more than $680 million since the market began in 2009. The Monitor for more than a year has been calling for CAISO to eliminate CRR auctions. (See CAISO Monitor Proposes End to Revenue Rights Auction.)
The Monitor will discuss the third-quarter report with market participants during a Dec. 20 conference call.
A Nuclear Regulatory Commission official said Tuesday that a team of the federal agency’s reactor safety engineers would likely recommend that the commission continue working on replacing a portion of its inspections with a self-assessment regime for operators of commercial nuclear power plants.
Tony Gody, NRC director of reactor safety in Region II (Southeast), said Dec. 12 that “the working group agrees that self-assessment, if implemented properly, can be very effective in finding latent conditions” and probably will be recommending further exploration of how to get there via a pilot program.
| NRC
Gody made his remarks at the end of the agency’s second public hearing in two months on the use of licensee self-assessments in the NRC engineering inspection program and other changes in the reactor oversight process.
The Director of the Office of Nuclear Reactor Regulation formed the working group in February 2017 to review the commission’s engineering inspections that verify the adequacy of facility design, operations and testing, and make recommendations on improving both their effectiveness and efficiency. The commission has a webpage with related documents, including public comment.
The Good and the Bad
“We need to collectively as an industry own our own licensing design basis and regulatory performance,” said Greg Halnon, vice president for regulatory affairs at FirstEnergy, which owns two nuclear power plants in Ohio and one in Pennsylvania. The plants are the Davis-Besse plant in Oak Harbor, Ohio, the Perry plant in Perry, Ohio, and the two-unit Beaver Valley plant in Shippingport, Pa., which collectively generate 4,000 MW.
“We’re not abdicating our responsibility; we’re maintaining and owning that licensing basis,” Halnon said.
Dave Lochbaum, director of the Nuclear Safety Project for the Union of Concerned Scientists, said the 17 years of the reactor oversight process “have resulted in safety improvements, there’s no doubt about that, but achieving success loses value if backsliding occurs. … Our concern is, some of the measures being contemplated are banking on that success at risk of undermining it.”
NRC Inspectors: (L-R) NRC inspectors Robert Krsek, Annie Kammerer and Steve Campbell check emergency diesel generators at the Kewaunee nuclear power plant in Carlton, Wisconsin in 2012, one year before the plant closed | NRC
Gody said that if whoever is doing an inspection or a self-assessment applies scientific principles, “it’s going to be a good inspection or self-assessment. And the fact that your own folks are already so familiar with your procedures, and the fact that your own folks already have computer accounts, already know the processes at the facility, already know the licensing basis, is a good thing and a bad thing.”
The good thing is they’ll be more efficient, he said.
“The bad thing is they may have preconceived conclusions,” Gody said. “It’s critical that when that checklist is developed that critical thinking is considered. If you accomplish that one thing, you potentially eliminate the human factor disposition to not challenge your own conclusions.”
Lochbaum said he wanted to push back on the “fanciful notion that there aren’t any more legacy, latent issues out there. There seem to be plenty of latent issues from long ago that we still haven’t found. Fort Calhoun [in Nebraska] is a perfect example, which shut down in 2011 and didn’t restart for 30 months. During that time, they submitted something like 18 LERs [licensee event reports], with the youngest of those being 15 years earlier, so they were at least 15 years old. Several of those involved engineering issues.”
Getting to the point of metrics, Lochbaum said “we recommended before and recommend again that the NRC should have looked at those LERs to see if the expectations were that the engineering inspections should have or may have identified those before they were found during an extended plant shutdown.”
NEI Supports
The Nuclear Energy Institute supports self-assessments, saying plant operators already do their own inspections in advance of NRC visits. “We believe that licensee self-assessments could be an important part of a modernized approach to engineering inspections. Such a solution would be rooted in our cultural value of self-identifying issues,” Greg Cameron, NEI’s senior project manager for regulatory affairs, wrote the commission in July. “We hold ourselves accountable to identify conditions at our stations early and to resolve them in a timely fashion commensurate with their safety significance; the NRC verifies that accountability through regular resident inspector interactions and the biennial Problem Identification and Resolution inspection. Transitioning from direct inspection to oversight of self-assessment activities, where appropriate, strengthens this accountability.”
Concerns in Mass.
But the self-assessment concept is unpopular with some neighbors of Entergy’s Pilgrim nuclear plant in Massachusetts, one of three plants in the country classified in Column 4 — the worst performers in NRC’s grading system.
A citizens group, Pilgrim Watch, cited an email written by the leader of a federal inspection team, who wrote that “the plant seems overwhelmed just trying to run the station.” The internal email became public mistakenly.
“Pilgrim provides the perfect example why NRC nuclear safety inspections are necessary and why industry self-assessments would be dangerous,” the group wrote NRC. “Pilgrim cannot be counted on to conduct any complete or accurate self-assessment. The NRC’s own records prove that Pilgrim has regularly and consistently failed to follow established procedures, to report problems, or to take corrective actions even when the NRC tells it to do so.”
ALBANY, N.Y. — When pricing carbon into the wholesale electricity markets, remember to keep it simple.
Also: avoid unintentional emissions increases, mind the transmission needed, incent new renewable resources, abate emissions efficiently without hurting consumers, allocate revenues fairly, and leave the legal hassles for the due processes of regulators and NYISO.
Those were some of the stakeholder comments Monday at the first technical conference of the Integrating Public Policy Task Force (IPPTF), which was established in October by NYISO and the state’s Public Service Commission to explore the carbon pricing issue as laid out in a Brattle Group report.
Paul Hibbard of The Analysis Group facilitated two roundtable discussions, each with 23 stakeholders. The morning session addressed border adjustment mechanisms to prevent “carbon leakage,” a parallel increase in emissions in regions neighboring New York.
“You don’t have to have the absolute perfect solution to leakage to go forward,” said Mark Reeder, an economist who represents the Alliance for Clean Energy New York at NYISO. “You just need to get most of the way there. Say if you can knock out 80 to 85% of the leakage problems at a $40 carbon price, you bring it down in essence to the latest we have now with a fairly small [Regional Greenhouse Gas Initiative] price and you’ve done the job.”
In looking at leakage issues in RGGI states and California, Reeder said “the unit-specific approach and the resource shuffling is a real bad idea and does create a lot of problems. The example here is that a nuclear plant in Pennsylvania that’s just selling spot-in in Pennsylvania could sign a contract to sell it to New York, and if New York declares that clean, we could work on that later, but it doesn’t work.”
Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emissions caps, while letting heavier polluters simultaneously serve customers in other regions.
“It’s important to move forward with carbon pricing principles and not use leakage as a way to delay,” said Gavin Donohue, president of the Independent Power Producers of New York. “We don’t need to reinvent the wheel.”
“You really get different answers depending on how you think about the question,” said David Clarke of the Long Island Power Authority. “For example, if you have a uniform carbon tax on all sectors, you’d be thinking about offsets; you think about where are the places where folks can make the investments that have the largest carbon reduction at the lowest cost.”
Baseline Leakage
“When you’ve got regions surrounding New York with such a wide range of marginal emissions rates, to start with a broad-brush approach, applying the New York rate to all of them will have pretty obvious unintended consequences,” said Stephen Molodetz, vice president of Hydro-Quebec. “Quebec is zero or near zero and Ontario is close to that; then you’ve got PJM, which is a higher emitter than New York.”
Don Tretheway, CAISO senior adviser for market design and regulatory policy, said some power producers outside the ISO have a resource portfolio with a significantly lower emissions profile than the default emissions rate for their region. In those cases, the ISO wants to give them the benefit of having cleaner resources.
“That’s relatively straightforward to implement from a market standpoint,” Tretheway said. “We can have each of the individual resources put their estimate of carbon compliance costs into their energy bids and we can dispatch away and everything works.”
Tretheway noted how the roll-out of the Western Energy Imbalance Market (EIM) further complicated CAISO’s treatment of greenhouse gas costs.
“The complexity CAISO introduced with the Energy Imbalance Market is that, not only did we need to solve to meet load in California that has a [greenhouse gas] program, but we had to actually solve to meet load in other states that don’t, and that’s where we had to separate those greenhouse gas costs into separate bids,” Tretheway said.
Mark Younger of Hudson Energy Economics said “what California is doing now is probably a mistake. [New York] should have a very high bar on resource-specific carbon pricing. Just because you can contract with what is nominally a clean resource, doesn’t mean that you in any way affected what the emissions were in the neighboring area other than by the fact that there was a bigger import to New York, regardless of resource.”
Allocating Carbon Revenue
The afternoon roundtable discussed how — and whether — New York would allocate revenues collected from a carbon pricing scheme.
NYISO Executive Vice President Rich Dewey said, “We’re conflating a couple issues here. First and foremost, we need to decide if there’s going to be a fund. When I think about how the NYISO settlements process works today, that revenue amount only exists for the microsecond it takes to do the calculation in the settlement itself, so there is no actual fund.
“At NYISO we’re not setting the policy, we’re administering the market,” he continued. “Be that as it may, you may have the desire, for the greater good, to create a fund in some capacity. Then we have to decide where is that fund.”
Miles Farmer of the Natural Resources Defense Council said that if the PSC determines what load-serving entities must do with carbon revenues, “that’s bounded under the legal constraints of PSC ratemaking, and you can’t have just general slush funds of money the way that it happens with RGGI.”
NYISO Senior Manager for Market Design Michael DeSocio said that when considering a carbon revenue fund, “we haven’t actually talked about what does the rate look like. And there are components of the rate that go into various funds already — a congestion rent fund, there’s a loss fund — all of that money is already allocated in some way based on various other markets. We want to do this in a way that doesn’t unnecessarily increase the cost to customers.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that making carbon pricing sustainable requires considering how RGGI moneys have been used for energy efficiency and incenting renewables in to help reduce greenhouse gases.
“The [Brattle] report assumes a certain marginal emissions rate that may not be true over time,” Joseph said. “Over time, those marginal emission rates are going to decrease and there’s probably not going to be anything left to refund because there’s not going to be a lot of carbon-emitting resources on the system.”
Scott Weiner, Department of Public Service deputy for markets and innovation, cautioned roundtable participants about getting caught up in the legal details so early in the planning process.
“It’s going to be a collaborative effort and will be vetted legally,” Weiner said. “We will subject everything to the governance processes of NYISO, so there are a lot of legal issues, and in the absence of specific facts … I urge you to leave the legal discussion to another day.”
Task force co-chair Nicole Bouchez, a NYISO market design economist, said they had decided to cancel the Dec. 18 task force meeting and will next meet on Jan. 8, 2018.
CARMEL, Ind. — While MISO sector representatives express uncertainty about the next stage in the evolution of the grid, they do think it will involve energy storage, distributed resources and heightened security measures.
But they’re hesitant to speculate about the size of future investments driven by the developments.
MISO Executive Director of Strategy Scott Wright last week said the RTO believes the grid is facing its biggest change “perhaps in a hundred years.” It envisions the grid becoming a two-way delivery system and generation becoming more distributed and intermittent, he said during a MISO “hot topic” discussion on the grid’s future during a Dec. 6 Advisory Committee meeting.
Staying ‘Happy’
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, opened the discussion with positivity, playing Pharrell Williams’ “Happy” music video and displaying screenshots featuring people dancing with transmission lines in the background.
MISO’s Advisory Committee members generally agreed that low bills are keeping customers content for now, but a changing resource mix will mean future grid investment. No stakeholders, however, are comfortable yet in guessing the cost or predicting what technology advances will reign.
“Consumers are happy because their electric bills are the lowest percentage of their income, I think, ever,” said Arkansas Public Service Commission Chair Ted Thomas. But he cautioned that consumers’ preference for renewables isn’t static in the market. “If you double electric bills and double unemployment, the number of customers willing to pay more for sustainability drops.”
Alcoa’s DeWayne Todd, representing MISO’s Eligible End Use Customers sector, said customers are generally happy and are demanding renewables for future pricing certainty and independence. However, while energy costs have decreased, the costs of transmission have “almost doubled.”
“I’ve seen my transmission percentage go from a whopping 7% to a whopping 10%,” said Wind on the Wires’ Beth Soholt of MISO’s Environmental sector. “What benefits does the grid provide to me? We need to make it clearer to our customers. I think the grid is the enabler of all of these choices and options. … I think there’s a misnomer that if you have the grid, you can’t do distributed energy options. The grid is the enabler; it ties it all together.”
‘FOG’
MISO’s Competitive Transmission Developers sector agreed that the ability of the transmission system to deliver will only become more important as customers use more types of generation. In written comments, the group warned that the energy industry may be undervaluing transmission: “Today … the transmission grid often goes unrecognized in planning and policy decision-making. This increases the risk of costly future outcomes, driven by repeated ‘just-in-time’ incremental grid investments.”
Northern Indiana Public Service Co.’s Paul Kelly said that while distribution-level changes are rapidly evolving, MISO has time to plan changes to the transmission system. He said NIPSCO is now training employees to be aware that generation installed at the distribution level may be live and not simply there for back-up purposes — a sign of the times.
“Making big bets right now about what the grid is going to look like is extremely fraught with risk,” Entergy’s Matt Brown said. “There’s definitely a balance to be struck between big-goal visions with big-goal price tags and making sure that our customers are served at the lowest reasonable cost.
“We need to realize that everyone at this table is thinking something that will prove to be wrong,” he added.
Dynegy’s Mark Volpe pointed out that, two years ago, MISO held a hot topic discussion in which members were certain the Clean Power Plan was going to become the law of the land. “None of us really know what the grid is going to look like. When you look at the phrase ‘future of the grid,’ if you shorten that up a bit and ignore the ‘the,’ you have ‘FOG.’”
Soholt also cautioned about the “cost of inaction,” where generation and transmission developers, after not adopting new technologies, will be faced with obsolescence or hurried investments.
Avangrid Renewables’ Adam Sokolski, of the Independent Power Producers sector, said MISO should look to its own interconnection queue to gauge future grid trends. “The queue is really the barometer of the grid.”
MISO’s queue currently contains about 60 GW of proposed generation, which includes about 30 GW of wind, 15 GW of solar, 12 GW of natural gas and 600 MW of other resources. The queue also holds about 140 MW of prospective battery storage capacity.
Predictions and Suggestions
The Environmental, Public Consumer Advocates and End Use Customers sectors, and sole Coordinating Member Manitoba Hydro, all predicted future penetration of clean energy, storage, distributed resources, demand-side management, home automation gadgets and energy efficiency.
End Use Customers expect that the growing prominence of demand management, self-generation, energy storage and a focus on environmental sustainability will afford customers “more independence from the utility.” Manitoba Hydro predicted use of coal will continue to decline “despite efforts to maintain its historical importance” and said state-originated carbon pricing may be enacted. The Consumer Advocates sector said it’s expecting microgrids and AC-DC transmission lines. The Transmission Owners sector said saturation of distributed resources will not be consistent across the footprint, grouped instead in states with distributed energy resource-friendly policies and incentives.
IPPs called for more customized interconnection procedures for a more diverse assortment of generation types. “MISO should be prepared to offer tailored interconnection processes based on operating parameters such as DER capability to inject energy onto the system vs. service limited to on-site only,” the sector wrote.
The one-in-10 planning standard may become obsolete as the grid and new technology accommodate a variety of energy resources that deliver energy on different schedules, Brown said. He contended that the most challenging circumstances may become a certain time of day rather than the hottest week of the summer.
“Maybe we’ll no longer plan for that one hour of that one day in August,” Brown said.
Manitoba Hydro predicted increasingly severe weather disturbances impacting the grid as well as increasingly critical cyber threats. TOs also expect security issues to increase as smart devices connect to the grid.
The Environmental sector said MISO could monitor grid reliability by using dynamic and predictive transmission line ratings, where operators see real-time data on line ratings. The sector also asked MISO to consider “the diversity exchange that could be gained” by developing transmission that connects MISO Midwest to MISO South, which would allow “MISO South states to have enhanced opportunities for economic development of new generation resources.”
NIPSCO’s Kelly pointed to Amazon’s parade of products, with some enjoying success while others have flopped, suggesting that experimental grid investment could follow a similar boom-and-bust pattern.
ERCOT staff told members of the Supply Analysis Working Group (SAWG) on Friday that the Texas grid’s summer peak demand is expected to reach 85 GW by 2027, a 22.36% increase over this summer’s peak.
But ERCOT is in good shape to meet the coming demand. The ISO’s November Generator Interconnection Status Report shows 20.6 GW worth of projects with interconnection agreements through 2020. Another 47.32 GW of capacity is being studied.
| ERCOT
And despite the pending loss of more than 4 GW of coal-fired generation, ERCOT said it has more than 80 GW of available capacity to meet load this winter and spring. (See ERCOT: Sufficient Capacity for Winter, Spring.)
Staff’s 2018 long-range load forecast sees stronger growth along the coast and in Far West and South Texas, compared to the 2017 forecast, but weaker growth in North Central and South Central Texas. Based on Austin Energy forecasts and the utility’s focus on energy efficiency, staff project a 0.5% annual growth rate for the Austin area.
ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO will have an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report incorporating the latest retirements will be released Dec. 18.
Texas is the fastest growing state in the country, having registered the nation’s largest annual population growth between 2010 and 2016, according to the U.S. Census Bureau. The state has been adding more than 200,000 people a year and will soon top 28 million.
NRG to Retire 806 MW of Mothballed Resources
Greens Bayou Unit 5
NRG Texas Power notified ERCOT last week it plans to retire Greens Bayou Unit 5 and three other previously mothballed gas-fired units with a total capacity of 806 MW.
Greens Bayou Unit 5 dates back to the early 1970s and had a reliability-must-run agreement with ERCOT — the ISO’s first since 2011 — that was terminated in May. The unit was mothballed in 2010 and 2011. (See ERCOT Ending Greens Bayou RMR May 29.)
NRG also said it would retire three gas units at its Houston-area S.R. Bertron plant. The company shut down two 230-MW units and a 13-MW quick-start unit in 2011 for economic reasons. All three units were more than 50 years old.
The retirements will be effective Dec. 31, NRG said in its Dec. 5 filing.
LITTLE ROCK, Ark. — SPP’s Board of Directors and Members Committee on Dec. 5 approved a 1-cent increase in the RTO’s administrative fee, keeping an eye on projected future reductions with the expected integration of the Mountain West Transmission Group.
Finance Committee Chair Larry Altenbaumer said the committee expects the fee to peak in 2019, “before we realize the benefits that would come from the potential integration with Mountain West.”
SPP and Mountain West have targeted Oct. 1, 2019, as the latter’s membership date.
The RTO’s administrative fee shot up 13.2% for 2017, from 37 cents/MWh to 41.9 cents, compensating for a lack of load growth. With this year’s increase, the 2018 fee will stand at 42.9 cents, just under its Tariff cap of 43 cents.
Last year it projected annual fee increases through 2021, topping out at 49.9 cents/MWh in 2021. This year’s budget forecasts flat load through 2020 and a corresponding admin fee of 47.7 cents, without assuming any benefits from Mountain West’s integration.
“We’re sensitive to the concerns of our members,” Altenbaumer said.
The 2018 increase is based on a net revenue requirement of $164 million, compared to the 2017 budget of $160.9 million. The Finance Committee said the increase is driven by the dissolution of the SPP Regional Entity and associated NERC funding — the committee assumes the RE will terminate its services after June — and by increases in various operating expenses.
| SPP
Altenbaumer said the Finance Committee would bring back another budget once a memorandum of understanding is signed with Mountain West.
SPP is budgeting 383 million MWh in annual billable energy through 2022, after having previously projected as much as 407 million MWh for 2017. The RTO saw a 1.6% year-over-year growth in average monthly peaks through July 2017 but is modeling 2% reductions in monthly peaks for August through November and a 12% reduction in December peak demand compared to 2016.
The board and stakeholders also approved the committee’s recommended budget, which reduces expenses by 2.85% to $190.8 million. Net income is forecast at $194.2 million, within $100,000 of this year’s budget and up from $176.2 in 2016.
Using SPP’s three-year budget as the basis for a five-year forecast, the Finance Committee assumed capital expenditures to be consistent with the 2020 forecast, adjusted for inflation. The committee projects income will increase to $204.2 million in 2019, and then again to $215.6 million in 2021 and $222.8 million in 2022, with expenses reaching $210.2 million in 2022.
The RTO estimates a headcount of 609 employees, reflecting the loss of the 17 RE positions.
Golden Spread Electric Cooperative’s Mike Wise, chair of the Strategic Planning Committee, told the board and members that he and his committee “fully expect” SPP to integrate Mountain West.
“Nobody’s trying to rush it. We want to get it right,” Wise said.
Wise said the SPC has met five times behind closed doors with Mountain West members since the formal integration stage began in September. Two more meetings have been scheduled: one on Dec. 19 in Dallas and another in the first week of January in Denver. Staff has developed a list of issues to be discussed, some of which are likely to drop off the list, he said.
“Some [issues] are more difficult than others, in that there is a gap between what Mountain West desires and things it needs, and what our current Tariff and members agree to,” he said. “The committee is interested in balancing the benefits and the costs, and to ensure we fully weigh those in the decisions that are made. We want to very jealously protect our culture. It’s been developed over the years, and we know what it means to be a member. It’s a very important ingredient in this discussion.”
SPP has projected a total net present value benefit to its current members of approximately $209 million, much of it from reduced administrative fees, for the first 10 years of Mountain West’s membership. Separate studies for Mountain West have determined the group could save up to $71 million annually through 2024 by participating in SPP’s day-ahead market and replacing its nine tariffs with one, along with annual net production cost savings ranging from $11.7 million to $28.8 million. (See SPP, Mountain West Integration Work Goes Public.)
Board Approves New MOPC Vice Chair, SPC Members
The board approved a consent agenda that included several nominations for stakeholder groups and their leadership positions, as submitted by the Corporate Governance Committee (CGC).
Northeast Texas Electric Cooperative’s Jason Atwood was selected from several candidates as vice chair of the Markets and Operations Policy Committee. He replaces Todd Fridley, who resigned from the position in October. His term commences Jan. 1.
Other organizational group chairs, all incumbents unanimously approved by their groups, were confirmed for two-year terms also beginning Jan. 1:
Grant Wilkerson, Westar Energy (Business Practices Working Group)
Eric Ervin, Westar (Security Working Group)
Jennifer Flandermeyer, Kansas City Power & Light (Event Analysis Working Group, Reliability Compliance Working Group)
Allen Klassen, Westar (Operating Reliability Working Group)
David Kays, Oklahoma Gas and Electric (Regional Tariff Working Group)
Jim Jacoby, American Electric Power (Seams Steering Committee)
Brad Hans, Municipal Energy Agency of Nebraska (Supply Adequacy Working Group)
Travis Hyde, OG&E (Transmission Working Group)
The committee also nominated Westar’s John Olsen and AEP’s Richard Ross to the SPC. They replace Southwestern Electric Power Co.’s Venita McCellon-Allen, who resigned from the committee, and OG&E’s Jake Langthorn, who has retired.
The CGC’s annual review of each group resulted in a name change for the Critical Infrastructure Protection Working Group, which now becomes the Security Working Group. The committee recommended the change to differentiate between NERC critical infrastructure protection standards and cyber and physical security infrastructure protection.
The committee also recommended minor tweaks to the scopes of the Finance and Human Resources committees.
Two Industry Experts Added to SPP’s Order 1000 Panel
The board and members also approved two new candidates for SPP’s Industry Expert Pool (IEP), which will evaluate and recommend competitive-upgrade projects. Joining the 12 incumbents approved in October 2016 are Sriram Kalaga, a Fellow of the American Society of Civil Engineers and holder of a doctorate in structural engineering, and Tom Bozeman, a director with civil engineering firm Atwell who has long experience designing and building transmission and substation projects.
SPP will select three to five experts from the IEP to evaluate and recommend competitive upgrades under FERC Order 1000. Two previous panels have recommended one project, which was eventually withdrawn in 2016. (See SPP Awards First Order 1000 Project — But it May Not be Needed.)
Stakeholders welcomed Jody Sundsted, vice president of market for Western Area Power Administration-Upper Great Plains Region, to the Members Committee. Sundsted gives the committee 20 members.
