SPP will partially sate its hunger for expansion this year when it begins providing reliability coordinator (RC) services to more than a dozen entities in the Western Interconnection.
At the same time, the RTO continues to reinvent itself with a pair of stakeholder-led initiatives that may change the way it allocates transmission costs and recovers its administrative fee.
A year ago, SPP was well on its way to adding Mountain West Transmission Group participants as members, following much the same process as it did in adding Nebraska’s public utilities in 2009 and the Integrated System in 2015. However, those plans were blown up in April by Xcel Energy’s surprise decision to leave Mountain West, taking almost half the group’s load with it. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
Opportunity soon presented itself again several months later, when Peak Reliability, the RC provider for much of the Western Interconnection since 2011, announced it would cease operations by the end of 2019. (See Peak Reliability to Wind Down Operations.)
While CAISO signed RC contracts with the bulk of Western load, SPP picked up about 12%, including most of the original Mountain West members. Among the entities: Xcel’s Public Service Company of Colorado subsidiary. (See CAISO RC Wins Most of the West.)
“We’ve worked hard over the last several months to demonstrate the quality and breadth of our service in terms of technical expertise, a customer-centric approach to doing business and the integrity of our people and processes,” SPP COO Carl Monroe said at the time.
The contracts will add two more states — Arizona and Utah — to SPP’s now 16-state footprint. The current timetable has SPP assuming Peak’s RC services on Dec. 3, though the Western Electricity Coordinating Council would like to see that pushed up to Nov. 1 to coincide with CAISO’s transition date. SPP stakeholders are resisting the move.
SPP’s Western RC footprint | SPP
HITT Squad
The events out West are just some of the dramatic changes that have taken place within the industry and the markets over the last decade. To accommodate those changes and plan for a changing future, SPP last year created the Holistic Integrated Tariff Team (HITT), comprising RTO directors, state regulators and members, to determine the best way to align its planning processes, cost-allocation methodologies, and market products and services.
The HITT spent much of 2018 listening to presentations from staff, market participants, consultants and stakeholders, hashing over ideas that have been discussed in other working groups or brought up by stakeholders time and again.
“There’s certainly a lot of work that’s been going on through the different groups in SPP … we don’t want to overlap that or re-digest those things,” said Nebraska Public Power District’s Tom Kent, HITT chair. “We want to build off the work that’s already being done and make sure we can account for the work that’s being done in those other groups and support them. We don’t want to retrace ground other groups are working on.”
The team is only now discussing how to organize a report with its final recommendations. The report is due to the Board of Directors and Members Committee in April, but the HITT has also scheduled an educational session before the Markets and Operations Policy Committee’s January meeting in New Orleans.
The HITT was modeled after the 2008/09 Synergistic Planning Project Team, which resulted in SPP’s Integrated Transmission Planning process and the highway/byway cost allocation methodology. Under the methodology, “highway” projects rated at more than 300 kV are allocated 100% systemwide on a load-ratio-share basis. “Byway” projects (100 to 300 kV) are funded two-thirds within the transmission zone and one-third systemwide.
The RTO has approved or built $6.3 billion in transmission infrastructure since 2010, with another $2.9 billion to be completed by 2022.
SPP’s Western RC timeline | SPP
Spreading the Fee
The Schedule 1A Task Force’s objective is slightly less daunting: determine whether there is a better way to recover SPP’s administrative fee.
The fee, which is being reduced this year to 39.4 cents/MWh from 42.9 cents/MWh, is collected under Schedule 1A of SPP’s Tariff on transmission contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak.
The problem is, different state regulators use different calculations and rely on historical data for current-year costs. The Integrated Marketplace has also required additional staff and IT costs, which has increased the amount to be collected.
SPP CFO Tom Dunn has proposed using energy metrics to reduce the fee, as financial-only players not currently paying Schedule 1A fees would also be contributing.
The task force is currently evaluating how best to recover costs in SPP’s transmission congestion rights market. The group was to present its recommendations during the January governance meetings, but it has a meeting scheduled for Feb. 5.
WASHINGTON — A year ago, the electricity policy-sphere was on pins and needles over how FERC and its new Chairman Kevin McIntyre would respond to the Trump administration’s bid to bail out coal and nuclear generators.
McIntyre won plaudits in January when he led a 5-0 vote rejecting the Department of Energy’s Notice of Proposed Rulemaking and instituting a new resilience docket (AD18-7).
FERC begins 2019 with a new chairman and renewed questions about whether it will resist the president’s efforts to deliver on his campaign pledges to coal country.
Republican Bernard McNamee — who helped author the DOE NOPR and who has complained that renewables are disruptive to “the physics of the grid” — was sworn in as commissioner after winning Senate confirmation on a 50-49 party-line vote. At his first open meeting, days before Christmas, McNamee was greeted by protests and questions over whether he would recuse himself from the resilience debate.
In two rounds of filings in the new docket, RTO officials and other commenters generally agreed that FERC should let stakeholder processes work and not issue broad and costly new mandates. The commission has given no indication how soon it will rule or what it will do with the information.
McIntyre gave up the chairmanship in October after revealing that he had suffered a “serious setback” in his battle with a brain tumor. The chairman’s health had become the subject of increasing speculation since a fall that left him visibly uncomfortable at the July open meeting, the last he attended. Although he remains on the commission, he is unable to come to FERC headquarters and is not participating in any decisions.
Pipeline Inquiry, Storage Rule, ROE
Before relinquishing the chairmanship, McIntyre and the commission approved several important rulemakings. In January, McIntyre announced the commission would open a Notice of Inquiry to consider changes to its 1999 policy statement on the permitting of natural gas pipelines, drawing praise from Democratic Commissioner Cheryl LaFleur (PL18-1).
In May, however, the commission’s Republican majority narrowed the circumstances under which FERC will estimate greenhouse gas emissions from natural gas pipeline projects, sparking dissents by LaFleur and Democrat Richard Glick, who said the decision effectively eliminates any consideration of GHG emissions associated with a project (CP14-497-001).
In February, the commission also approved Order 841, which required regional grid operators to remove barriers to electric storage in their capacity, energy and ancillary services markets. Dylan Reed, head of congressional affairs for Advanced Energy Economy, said the compliance filings by grid operators in December “could lead to a minimum of 7 GW of storage deployment in the RTO markets and potentially could lead to 50 GW across the country. For scale, the rule’s impact is essentially the equivalent of 86% of all installed solar capacity to date,” Reed said during AEE’s year-end webinar. “So, this really is a monumental rule.”
The commission’s NOPR had also proposed giving aggregated distributed energy resources the same treatment as storage, but the panel concluded it needed more information before it could act, ordering a technical conference and new dockets for the issue (RM18-9, AD18-10).
In April, the commission revised its pro forma large generator interconnection procedures and large generator interconnection agreement (LGIA) to increase the transparency and timeliness of the interconnection process (RM17-8). The rulemaking, which was prompted by a complaint by the American Wind Energy Association, applies to generators larger than 20 MW.
Days before McIntyre gave up the gavel, the commission issued its response to the D.C. Circuit Court of Appeals’ 2017 ruling vacating FERC’s 2014 order on calculating return on equity rates. The commission said it would no longer rely solely on the discounted cash flow (DCF) model it has used since the 1980s; instead, it said it will give equal weight to results from the DCF and three other metrics, a change likely to result in higher ROEs (EL11-66-001, et al.).
McIntyre also navigated two controversies in his brief chairmanship. The first came when Commissioner Neil Chatterjee disclosed in January that former FERC General Counsel Bill Scherman had improperly contacted him “indicating his concern that the commission would shortly issue an order adverse to the interests of” his client, FirstEnergy. At a press conference, McIntyre declined to say whether the commission would investigate the ex parte communication by Scherman, whom he called a “good friend.”
Later, McIntyre came to the defense of Chief of Staff Anthony Pugliese, who came under fire for partisan comments at a speech and in an interview with right-wing media outlet Breitbart.
Chatterjee, who had held the chairmanship on an acting basis for more than four months in 2017, was appointed McIntyre’s replacement Oct. 24. Chatterjee said his priorities as chairman will be grid resilience and reliability, cybersecurity, processing LNG facility applications and eliminating barriers to entry for new technology.
A former energy adviser to coal state Senate Majority Leader Mitch McConnell (R-Ky.), Chatterjee praised McIntyre for helping him understand “that politics could not be allowed to interfere with the work of the commission,” advice he said aided his transition “from formerly partisan legislative aide to independent regulator.”
After the commission’s Dec. 20 meeting, Chatterjee told reporters he was confident that McNamee would similarly transition from a fuel-wars partisan to an impartial adjudicator. “So, all I would ask is that he be given an opportunity to demonstrate that, like myself, [McNamee] will be an earnest public servant.”
Chatterjee comes in with numerous pieces of unfinished business, including the pipeline policy review and the rulemaking on DERs.
With the arrival of McNamee, “it’s unclear where [the DER ruling] is going to go in 2019,” said AEE’s Reed. “Fortunately, we do know that Chairman Chatterjee is committed to innovation and removing barriers to technologies as he’s now said in numerous public speeches over the last few months.”
After winning a third term in November, Gov. Andrew M. Cuomo last month announced 2019 plans that include tackling climate change with a program reminiscent of Franklin D. Roosevelt’s first 100 days as president during the Great Depression.
“New York must be the most progressive state in the nation moving to renewables,” Cuomo said Dec. 17. “There is new economic growth potential, and New York will launch the Green New Deal to make New York’s electricity 100% carbon neutral by 2040 and ultimately eliminate the state’s entire carbon footprint.”
Con Edison CEO John McAvoy (right) leads New York Gov. Andrew M. Cuomo on a tour of a substation in Astoria Queens where an electrical fault on 138,000-volt equipment caused a sustained electrical arc flash visible across a wide area of the city on Dec. 27. Cuomo asked state regulators to investigate the incident, which disrupted operations at LaGuardia Airport and a nearby subway line. | Gov. Cuomo
Cuomo’s effort will build on the state’s energy-related progress over the past year, which included a draft carbon pricing proposal, energy storage programs and new targets for offshore wind and energy efficiency.
The same day Cuomo spoke, the state’s Integrating Public Policy Task Force (IPPTF) met for the last time before handing over its final carbon pricing proposal to IPPTF Hands off Carbon Pricing Proposal to NYISO.)
NYISO and the New York Public Service Commission created the task force in 2017 to explore ways to price carbon into the wholesale electricity markets to align them with state decarbonization policies, including the zero-emission credit program for uneconomic nuclear plants.
NYISO published the IPPTF Carbon Pricing Proposal on Dec. 7 after recommending it no longer require emissions-free resources with existing renewable energy credit contracts pay the carbon component of locational-based marginal prices (LBMPc). The requirement would create “a distortion in the market … that places the ISO in the position of picking winners and losers,” an ISO official said. (See IPPTF Updates Carbon Charge Analysis, Treatment of RECs.)
Emissions reductions from a carbon charge in New York | Brattle Group
Offshore Wind is Coming
2018 should prove to be a watershed year for the development of offshore wind, now poised to become a significant source of New York’s energy over the next decade. Early last year, Gov. Cuomo released the comprehensive New York State Offshore Wind Master Plan, which calls for 2.4 GW of offshore resources by 2030.
In July, the New York Public Service Commission authorized state agencies to procure 800 MW by this year. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.) In consultation with the New York Power Authority and the Long Island Power Authority, the New York State Energy Research and Development Authority on Nov. 8 followed up with a request for proposals for 800 MW of offshore wind energy (ORECRFP18-1).
NYSERDA expects to announce the first offshore wind contract award in the second quarter of 2019 and, if needed, issue a second solicitation this year to meet the 800-MW goal of the first tranche.
The U.S. Department of Energy last year awarded a NYSERDA $20.5 million grant to lead a nationwide research and development consortium for the offshore wind industry, with the state matching the federal funds. The consortium in November issued its R&D Roadmap, and in December published its first report, an examination of several technical challenges facing the industry.
The consortium will issue a series of RFPs throughout the four years of federal funding, with the first R&D solicitation planned for next month. Initial project awards are expected to be selected by the end of March.
Energy Storage
New York regulators last month approved measures that will sharply increase the state’s energy storage and efficiency targets. The state’s Department of Public Service and NYSERDA in June issued New York’s Energy Storage Roadmap, and the PSC adopted many of its recommendations.
Rulings by the PSC last year doubled New York’s existing 2025 storage goal to 3,000 MW by 2030 and require the state’s utilities to reduce building energy use by an additional 31 trillion British thermal units (TBtu) to meet an energy efficiency target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)
The commission’s Dec. 13 storage order (Case 18-E-0130) said that the targeted deployment of energy storage “will result in reductions in system peak load demand during critical periods, increases in the overall efficiency and resiliency of the electric grid, and displacement of fossil fuel-based generation.”
Deployment scenario resulting in 1,500 MW of energy storage by 2025 | NYSERDA
Resulting public benefits include more than $3 billion in gross lifetime benefits to New York’s utility customers, creation of approximately 30,000 jobs, about 2 million metric tons of avoided greenhouse gas emissions and improved public health by avoiding air-pollutant emissions such as nitrogen oxides, sulfur oxides and particulates.
The order also authorized $310 million in market incentives to be administered by NYSERDA for pairing storage with solar projects, in addition to the $40 million announced the previous month. It also directed the utilities to hold competitive procurements for 350 MW of bulk-sited storage systems.
NYSERDA and the DPS also developed the state-mandated energy efficiency targets (Case 18-M-0084), which now include a 3% annual reduction in electricity sales by 2025 and 5 TBtu of savings from the installation of heat pumps, which help reduce emissions from the heating and cooling of buildings.
CEO Transition
NYISO CEO Brad Jones left the organization abruptly in mid-October and was replaced — at least temporarily — by General Counsel Robert Fernandez. The ISO declined to elaborate on the reason for the departure, except to say it was “a personal decision by Brad.” (See Brad Jones out at NYISO.)
Stakeholders told RTO Insider that senior ISO officials at the time told them the news was a surprise to them. “It’s a really big mystery … it came out of nowhere,” said one stakeholder who asked not to be identified.
The ISO’s Board of Directors has yet to say whether it will initiate a search for another chief executive. Fernandez was named the ISO’s general counsel and chief compliance officer in 2000 after stints at Long Island Lighting Co. and independent power producer Sithe Energies.
CAISO will tackle its new role as reliability coordinator for much of the West in 2019, and California lawmakers will struggle with preventing wildfires sparked by power lines.
Major events in 2018 prompted both efforts.
CAISO will oversee reliability coordination in much of the West from its headquarters in Folsom, Calif. | CAISO
In July, Peak Reliability stunned the West by announcing it would end its RC operations across the Western Interconnection by the end of 2019. That set off a competition between CAISO and SPP to sign up clients for their own RC services.
Then in November the deadliest wildfire in state history leveled the town of Paradise, Calif., killing 85 residents in the Sierra Nevada foothills. Suspicion quickly fell on PG&E for the Camp Fire, prompting talk of state action to reform or break up the utility.
Other challenges that faced California and the West in 2018, and will continue in 2019, include making CAISO’s congestion revenue rights more equitable to ratepayers and continuing efforts to establish a Western RTO led by CAISO.
Keeping Reliability Coordination Reliable
Peak Reliability stunned the electricity sector in July when it announced it would wind down its role as reliability coordinator for the West and withdraw from its effort to develop a regional electricity market competing with CAISO. The Vancouver, Wash.-based company said it would shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs. (See Peak Reliability to Wind Down Operations.)
Several months before the announcement, CAISO, a Peak RC customer, said it would “reluctantly” leave Peak, develop its own RC services and offer them to others at reduced costs. Most of the Western Interconnection signed nonbinding letters of intent to take advantage of CAISO’s RC services.
CAISO’s move was seen as a reaction to Peak entering a partnership with PJM to form a Western RTO to compete with the ISO’s expansion.
FERC approved a set of Tariff revisions covering CAISO’s new RC services in November, clearing the way for about 72% of the region’s load to sign on with CAISO, compared with 12% for SPP. BC Hydro is proceeding with plans to provide RC services for its own territory in British Columbia, representing about 7% of load in the region overseen by the Western Electricity Coordinating Council. (See CAISO RC Effort Gets FERC Go-ahead.)
CAISO, SPP and BC Hydro are scheduled to take over Peak’s duties in four handoffs through 2019. CAISO will assume the RC role for its existing territory on July 1. BC Hydro will become the RC for a large swath of southwestern Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other regions of the West on Dec. 3, although NERC is encouraging the RTO to accelerate its timeline to match CAISO’s.
The process provides ample opportunities for errors and shortcomings, including staff attrition at Peak, those involved say. Some employees have already left Peak, and others could follow. The company is hoping that severance packages will encourage most others to stay until they’re no longer needed.
CAISO and SPP will become the reliability coordinators for the Western Interconnection in 2019. | WECC
Jim Shetler, general manager of the Balancing Authority of Northern California and chair of Peak’s Member Advisory Committee, briefed WECC board members on the transition process in December, saying he had concerns about whether Peak would remain in business until the transitions are completed at the end of 2019.
“What keeps me up nights [is worry over] whether Peak is a going concern in the next 12 months,” Shetler said during the board meeting at WECC headquarters in Salt Lake City. (See RC Transition is Fraught with Pitfalls, WECC Hears.)
Others have said they’re confident the transition will go as planned, but all agree it will be important keep a close eye on the RC switchovers in 2019 to avoid lapses in critical services.
“This is a risky year, and I think everyone’s posture is really focused on this,” Linda Jacobson-Quinn, regulatory compliance manager for the Farmington Electric Utility System in New Mexico, told WECC in December. “At the end of the day, it’s the customers that must have an RC.”
Wildfire Policy Could Target IOUs
When the California State Legislature reconvenes Jan. 7, one of its first orders of business will be dealing with the problem of catastrophic wildfires, particularly those sparked by electrical equipment operated by investor-owned utilities.
Lawmakers thought they’d made significant progress in 2018 when they passed SB 901, a 71-page bill of wildfire prevention measures that included new vegetation management and reporting requirements for the IOUs. The measure, signed into law by Gov. Jerry Brown in September, also provided a means for IOUs to issue long-term bonds to cover wildfire liability costs. (See California Wildfire Bill Goes to Governor.)
PG&E’s costs have been estimated in the billions of dollars for a series of devastating fires in Northern California wine country during the 2017 fall fire season. State fire officials have declared the utility at fault for at least 16 of the fires, though the Tubbs Fire, which wiped out part of the city of Santa Rosa, remains under investigation.
Brown and other policymakers worried about PG&E’s solvency following the 2017 blazes and enacted the bond provision, but that measure didn’t cover fires in 2018, and the Camp Fire’s estimated costs could equal or exceed all the wine country fires combined. PG&E’s stock price took a pounding in the days after the Camp Fire and remains less than half of what it was before the blaze.
The Camp Fire started at 6:33 a.m. on Nov. 8 near Tower :27/222 on PG&E’s Caribou-Palermo 115 kV transmission line, the California Department of Forestry and Fire Protection (CalFire) and PG&E reported in December. PG&E told the California Public Utilities Commission it had experienced a fault and fire near Tower :27/222 shortly before the Camp Fire ignited. (See PG&E Grapples with Line Safety After Camp Fire.)
If CalFire investigators eventually find PG&E equipment caused the fire, the utility could be held liable for all resulting damage, even without a showing of negligence, under the controversial legal doctrine known as “inverse condemnation,” the strict liability standard California applies to utilities for fires sparked by power lines.
During their 2019/20 session, state lawmakers likely will consider clean-up legislation that allows utilities to issue bonds to pay for 2018 fires. With public anger high, however, elected officials may fear a backlash for any bill deemed a bailout for PG&E or other IOUs.
Another possibility being discussed is state action to break up PG&E and hand over control of some of its parts to cities such as San Francisco. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.)
Changing PG&E’s corporate governance also is on the table.
National Guard soliders searched through rubble in November after the Camp Fire tore through Paradise, Calif., killing 85 and casting suspicion on PG&E. | California National Guard
Sen. Bill Dodd, one of the authors of SB 901, has called for a management shakeup at PG&E in the wake of the fatal 2010 San Bruno gas line explosion and the massive fires of 2017/18.
“PG&E has demonstrated a pattern of poor management and illegal conduct that has shattered lives across California,” Dodd said in a Dec. 20 news release. He called for “systematic change, which must include change on the board of directors and in the executive suite.” The utility currently has a “bunker mentality” that prevents improvement in its safety practices, Dodd said.
“This is the kind of thing that keeps me awake at night,” Picker said at the time.
On Dec. 21 the commission released a ruling regarding the investigation that asked whether the company’s management should be replaced, whether members of its board of directors should resign, and whether the company should be broken up into separate gas and electric divisions.
In the meantime, PG&E has vowed to do better. “We are acting decisively now to address these real and growing [wildfire] threats, and we are committed to working together with our regulators, state leaders and customers to consider what additional wildfire safety efforts we can all take to make our communities safer,” company CEO Geisha Williams said in a December news release.
CRR Shortfalls and Regionalization
CAISO’s other priorities in 2019 will include its continuing efforts to rein in congestion revenue rights insufficiencies that have left ratepayers footing a bill of about $100 million per year, according to the ISO’s Department of Market Monitoring.
The chronic shortfall in CRR revenues, which are allocated based on power consumption, has been an ongoing problem for CAISO. This year the ISO sought FERC’s approval for changes it hoped would help in 2019, but the commission only gave CAISO part of what it wanted.
In November, FERC accepted an ISO revised proposal, providing for CRR holders to be paid for their entitlements “only to the extent the CAISO collects sufficient revenue through day-ahead market congestion revenues and other sources to fund those entitlements.” (See FERC OKs CAISO Plan to Deal with CRR Shortfalls.)
CAISO may also continue to pursue its efforts to form a Western RTO, despite the failure of several proposals in recent years to begin the process. The latest, AB 813, failed to make it out of a legislative committee in 2018. The bill would have started the process of turning CAISO into an RTO by initiating changes in its governance structure to allow for out-of-state members.
California lawmakers have been opposed to relinquishing state control. CAISO’s governors are now appointed by the California governor and confirmed by the Senate. At the same time, industry leaders from other Western states don’t want to cede authority to a CAISO board controlled from Sacramento.
As Ralph Cavanagh, co-director of the energy program at the Natural Resources Defense Council, put it to a Northwest industry group in October: “We need a big bipartisan win, and I don’t think we’ll get it on carbon tax in the short term, but I’ll tell you a place where we can get it … enhanced regional grid integration.”
ISO-NE closed out 2018 like a trucker wheeling a wide load down a twisting service road on the flanks of Mount Washington. Despite a few bumps, scrapes and scares along the way, it delivered on time — in this case dispatching key market initiatives.
The RTO’s most important issues are winter fuel security and addressing the states’ desire to bring in more carbon-free resources, but it also must plan to operate a grid that is already experiencing a surge in renewable energy resources — with massive amounts of offshore wind energy now visible on the horizon. (See Mass. Offshore Lease Auction Nets Record $405 Million.)
The bumps and scrapes last year came in a contentious stakeholder process over both issues and in FERC approvals accompanied by criticisms, dissents and partial dissents by various commissioners.
FERC last month approved the ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security in a region heavily reliant on natural gas and in March approved its two-stage capacity auction to accommodate state renewable energy procurements. (See Split FERC Approves ISO-NE CASPR Plan.)
Controversy in the Details
Soon after a severe cold snap last January, ISO-NE published an operational fuel security analysis that found the New England grid is vulnerable to a season-long outage at any of the region’s major energy facilities. (See Report: Fuel Security Key Risk for New England Grid.)
In a related issue, Exelon in March said it would retire its 2,274-MW Mystic Generating Station in Massachusetts after the facility’s capacity obligations expire in May 2022.
FERC in July denied an ISO-NE a Tariff waiver to enter a cost-of-service agreement to keep Mystic Units 8 and 9 running after the expiration, instead directing the RTO to revise its rules to allow such agreements to address fuel security.
The commission last month finally approved a Mystic agreement, including payments to the Exelon-owned Distrigas LNG facility that supplies the plant with fuel, while also ordering a paper hearing on the issue of return on equity for the units. (See FERC Approves Mystic Cost-of-Service Agreement.)
Winter LNG deliveries to New England interstate pipelines | ISO-NE
Reserve Energy Bank
In a concurring opinion in last month’s fuel security order, FERC Commissioner Richard Glick said “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” (ER18-2364).
“Winter energy security is a good problem for markets,” said a report on fuel security prepared by Brattle Group on behalf of NextEra Energy Resources. “New England’s energy security challenge can be converted into demand for clearly defined products that many, diverse resources can compete to provide at least cost … [but it’s] essential that any chosen solution will provide planners/operators with the certainty that winter reliability will be maintained, thus avoiding any need for out‐of‐market intervention.”
In a related effort to address fuel security issues holistically, ISO-NE Vice President for Market Development Mark Karl said in November that the RTO is proposing to incorporate into the real-time market an additional constraint that looks at the ability to provide energy storage — or an energy bank.
“I want to be careful here because it’s easy to think about this from the standpoint of conventional generator fuel, but this will apply to any sort of resource that has the ability to maintain essentially a reserve bank of energy that can be converted into electricity when needed,” Karl said.
The idea is to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day, he said. (See New England Talks Energy Security, Public Policy.)
New Renewables
ISO-NE proposed the Competitive Auctions with Sponsored Policy Resources (CASPR) construct last January to address state regulators’ concerns about ratepayer costs for policy-driven resources and generators’ fears that out-of-market procurements would suppress capacity prices.
In the commission’s March ruling on CASPR (ER18-619), Commissioner Robert Powelson dissented, while commissioners Cheryl LaFleur and Richard Glick criticized the minimum offer price rule (MOPR) included in the measure.
Under CASPR, ISO-NE will clear the Forward Capacity Auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction generators with retirement bids that cleared in the primary auction will transfer their obligations to subsidized new resources that did not clear because of the MOPR. The RTO will phase out the renewable technology resource exemption, which has allowed it to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
Integration of new renewable resources is not a problem for the RTO and likely won’t be for the next decade, ISO-NE Vice President of Market Operations Robert Ethier told industry stakeholders in November. It’s a two-fold economic challenge involving the energy and capacity markets.
“Bring in these zero-marginal-cost resources and insert them into our real-time supply stack, and it lowers energy prices for everyone … [and] when the states contract for these resources, they don’t just affect the energy market, they also affect our capacity market,” Ethier said.
Having new state-sponsored resources buy out old resources in the market will help manage and ration the entry of these resources into the market and prevent price suppression, he said. (See Canada, New England Talk Trade, Politics and Clean Energy.)
The CASPR filings include proposed Tariff revisions to allow a renewable technology resource to be located out of state — such as in federal waters offshore — and still qualify for a MOPR exemption.
Renewable energy advocates RENEW Northeast supported the RTR revision, as did Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners that last May won the contract to supply Massachusetts with 800 MW of offshore wind energy. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
Progress on Emissions
The RTO last month issued its draft 2017 ISO New England Electric Generator Air Emissions Report, which showed that since 2001 sulfur-dioxide emissions have declined 98%, nitrogen oxide by 74% and carbon dioxide by 34%.
Regional emissions of SO2, NOX and CO2 declined in 2017 compared to the previous year, according to preliminary data, with lower emissions due largely to a decline in electricity generation by power plants that use fossil fuels, said the report. The year-over-year declines continued long-term reductions in the emissions produced by New England power plants.
ISO-NE Total System Emissions: 2016 and 2017 New England system emissions (ktons) and emission rates (lb/MWh) (all figures are preliminary). | ISO-NE
NEPOOL Press Ban Proceeding
In August, the New England Power Pool asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings (ER18-2208). The group drafted the revisions after RTO Insider reporter Michael Kuser applied for membership in NEPOOL’s Participants Committee as an End User customer in March.
RTO Insider responded to NEPOOL’s filing with a Section 206 complaint asking the commission to overturn the organization’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
RTO Insider’s filed response included letters submitted by six U.S. senators and 12 members of the House of Representatives calling on FERC to open the meetings. (See New England Senators Urge FERC to End Press Ban.)
It also included a copy of a Sept. 6 RTO Insider article quoting former FERC Commissioners Pat Wood and Nora Brownell as saying they were unaware of NEPOOL’s closed-door policy when they approved it as ISO-NE’s stakeholder body. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)
Public Citizen filed comments challenging NEPOOL’s claim that its members “voted overwhelmingly against having press reporters as NEPOOL members” at the June 26 Participants Committee meeting. Only 115 of NEPOOL’s more than 500 members were present or had proxies at the meeting.
While 32 votes were cast in favor of the press ban, 24 members were opposed and 59 abstained. In addition, NEPOOL records show that six officers or their associates represented companies that provided 21 of the 32 votes for the ban.
The six have conflicts of interest in voting for the ban because they earn income selling “intelligence” about NEPOOL proceedings, said Tyson Slocum, director of Public Citizen’s Energy Program.
MISO will spend much of 2019 working on how it can prevent the increasingly frequent emergency conditions it experienced in 2018.
In spring, CEO John Bear said 2018 marked “13 years in standing up what is one of the world’s largest energy markets.” But that undertaking didn’t come without challenges, and the RTO zeroed in on efforts exploring how it can temper them in 2019.
Last year roared in with an extreme cold snap and multiple generation outages in MISO South that forced the RTO to call a maximum generation event, later prompting MISO: Sept. Emergency Response Improved by Jan. Event.)
By then, MISO had decided to file expected Tariff changes earlier than planned, hoping to free up an additional 5 to 10 GW of capacity in time for the spring 2019 outage season. (See MISO, Stakeholders at Odds over Resource Availability Filings.)
“There’s some discomfort with where we are, so some were asking what we could do before … the spring outage season,” Director of Resource Adequacy Coordination Laura Rauch said during a Nov. 7 Resource Adequacy Subcommittee meeting.
MISO made two FERC filings Dec. 21 that will require load-modifying resources (LMRs) to produce seasonal availability documentation and subject demand response to annual capability testing (ER19-650, ER19-651). A filing for a new 120-day notice time for planned outages will follow in January.
“The MISO region is transitioning from a generation portfolio dominated by coal and nuclear generation resources to a portfolio that relies on an increasing quantity of intermittent and emergency-only resources — even to meet MISO’s planning reserve requirements,” the RTO explained in both filings. “Baseload generation retirements have increased the pace of this transition and have caused MISO to operate with actual capacity margins that have consistently been decreasing towards minimum resource requirements. … Operating at or near minimum reserve margin requirements exposes the MISO region to greater impacts from correlated risks (e.g., extreme weather events and natural gas availability).”
Almost 12 GW (about 9%) of MISO resources are classified as LMRs, accessible only as part of emergency load management. The RTO had not called on LMRs for a decade after a localized Wisconsin emergency in February 2007 but has relied on them three times since 2017.
Independent Market Monitor David Patton has suggested “deep-sixing” the RTO’s current forced outage calculations in favor of a four-season capacity auction that will use generators’ averaged economic maximums during a season. That way, he argued, outages will be better anticipated, and MISO can dispense with members’ questionable outage reporting.
“Outage reporting is just not that reliable,” Patton said during an Oct. 11 Market Subcommittee meeting.
In addition to the three smaller FERC filings, MISO will this year focus on developing long-term fixes to keep its fleet more available during peak demand times. The RTO aims to implement the longer-term solutions throughout the first half of 2021.
MISO will also dedicate time in 2019 to devising a new load forecasting process. The RTO hopes to implement an approach that would have both Purdue University’s State Utility Forecasting Group and consulting firm Applied Energy Group working with 20-year forecasts provided by load-serving entities. (See MISO Presents Load Forecasting Compromise.)
Low Capacity Prices
In his 2017 State of the Market report issued last June, Patton said the “fundamental problem” with diminishing capacity can be traced to “the relatively low net revenues generated in MISO’s markets.” (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
By Patton’s count, MISO lost 3.8 GW of resources in 2017, mainly comprising gas-fired resources in MISO South and coal-fired resources in the Midwest. In contrast, the RTO added just 1.2 GW of new resources.
Patton continues to call for a more “functional” capacity market in MISO and has also blamed FERC for not issuing a rule set on RTO capacity markets.
“I think we may have to wait for this to play out in court,” Patton said during a June meeting of the MISO Board of Directors’ Markets Committee, predicting that competitive asset owners would soon sue. They have just as much right to recover costs as regulated utilities, he contended.
“I don’t think it’s right to ignore the competitive suppliers and think their issues are immaterial,” Patton added.
Some stakeholders have said MISO’s recent auction clearing prices do not reflect the tighter operating conditions that it claims, with many pointing out that for the past three years, clearing prices never come close to the RTO’s $25/MW-day conduct threshold. The 2019/20 capacity auction will be the first to use external capacity zones. (See FERC OKs MISO External Capacity Zones, Dispute Deadlines.)
Packed Queue and Storage Beginnings
MISO fuel mix under MTEP 18 futures | MISO
MISO might find some future capacity relief in its brimming interconnection queue and new rules that will open its markets to storage resources.
But the interconnection queue poses its own complications, as most of the proposed assets are intermittent resources.
During the June board meeting, MISO President Clair Moeller said that bringing on all the 90 GW then in the queue would lead to 40% renewables in the RTO’s resource mix. According to an ongoing MISO study on renewable penetration, such a mix would result in an “inflection point” where it becomes more difficult to manage the system.
“We’re going to need some pretty significant transfer capability or we’re going to be curtailing,” Moeller said.
Since then, the queue has shrunk to about 82 GW because of drop-outs.
MISO also filed to comply with FERC Order 841 in early December, outlining a participation model requiring storage resources commit to the market through four main modes: discharging, charging, continuous and outage status (ER19-465).
The first three modes carry must-run designations and will be cleared between a resource’s minimum and maximum discharge limits. The plan also allows for emergency commitments. For metering purposes, withdrawals will be treated as negative generation and categorized as wholesale. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) MISO is requesting its plan become effective Dec. 3, 2019.
“Allowing electric storage resources to participate fully in MISO’s markets will enhance competition, promote greater market efficiency and help support the resilience of the bulk power system,” Executive Vice President Richard Doying said in a release.
Meanwhile, MISO is accelerating storage-as-transmission rules. So far, the RTO is only considering pared down rules that would allow storage to function simply as transmission into the MTEP 19 cycle, buying it time to consider broader rules for resources that serve both market and transmission functions. To include storage projects in its 2019 Transmission Expansion Plan, MISO will make a limited Tariff filing in February — if it is “aggressive” enough to meet the timeline, Director of Planning Jeff Webb said during a Nov. 14 Planning Advisory Committee meeting.
“If we have storage projects in the MTEP, but no rules for them, then we won’t accept them because there is no policy,” Webb said.
MISO interconnection queue as of December 2018 | MISO
Hartburg-Sabine in the Books
MISO this year bid out its second-ever competitive transmission project, awarding construction of the proposed Hartburg-Sabine line in East Texas to NextEra Energy.
NextEra proposes to spend $115 million on a new 23-mile 500-kV line, four short 230-kV lines and a new Stonewood 500-kV substation, crossing Orange, Newton and Jasper counties in East Texas. The company estimates the project will have a 2.2:1 benefit-cost ratio and will be in service by June 2023. It said NextEra’s proposal had the third-lowest cost per mile of 500-kV line at $3.2 million. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
“NextEra thoroughly identified, considered and discussed environmental risks and mitigation and was among the most thorough in completion of supporting design studies for the project,” MISO said in a selection report. The company took into account the high-water mark during Hurricane Harvey and ensured the substation site will not be within a 100-year or 500-year floodplain, according to the RTO.
So Long, and Thanks for the Metairie
By the end of 2019, MISO will have shuttered one of its four office spaces, closing its Metairie, La., office late in the year at a cost of about $900,000, saving the RTO about $500,000 every year thereafter. (See MISO to Turn out Lights on Louisiana Office.)
The RTO is also one year closer to overseeing market operations on a new modular market platform. By the end of 2019, it will announce its chosen vendor to construct the platform, which will be pieced in gradually from 2020 to 2024. (See “Market Platform Replacement Enters Year 3,” MISO Board of Directors Briefs: Dec. 6, 2018.)
The NYISO Board of Directors on Thursday issued a mixed decision on the ISO Management Committee’s selections for the AC Public Policy Transmission Project.
While the board accepted the committee’s recommendation for one segment, it switched the other to a competing proposal by National Grid and New York Transco.
AC Public Policy Transmission Need in NY | NYISO
The Management Committee — along with ISO staff — had backed two joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects to address persistent transmission congestion at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. (See NYISO MC Supports AC Transmission Projects.) Cost estimates for both projects ranged from $900 million to $1.1 billion.
Advised by consultant Substation Engineering Co., ISO staff recommended Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A. For Segment B, it endorsed Project T029, a standard 345-kV line from Knickerbocker to Pleasant Valley, despite claims from one bidder that there was a “virtual” tie in benefits among competing projects.
But the board concluded that “the most efficient or cost-effective solution” for Segment B is Project T019, proposed by National Grid’s Niagara Mohawk Power and NY Transco.
“In evaluating Segment B projects, the Board concludes that Project T019’s additional transfer capability drives superior performance across a number of important selection metrics,” the board wrote in its decision.
The board directed ISO staff to modify the draft report for the project accordingly.
Listening to Stakeholders
NYISO staff had analyzed seven proposals for Segment A and six for Segment B before making their choices. However, when the Business Issues Committee recommended the projects last June, several losing bidders protested the ISO’s selection process. (See NYISO BIC Backs AC Tx Projects; Losing Bidders Protest.)
At the June BIC meeting, New York Transco general counsel Kathleen Carrigan read comments the company submitted jointly with National Grid, arguing NYISO’s own metrics showed the National Grid/NY Transco proposal paired with T029 would produce consistently better performance than the ISO’s favored project.
Based on updated transfer limits, project T019 has the lowest cost/MW ratio of all the Segment B projects ($/MW). | NYISO
Project T019 includes “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings,” the comments noted.
When combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW, the companies contended.
“This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325 MW,” Carrigan told RTO Insider after the June meeting.
“Projects T027 and T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029. And finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.
Additional analysis ordered by the board supported Carrigan’s assertions, finding that when paired, T027 and T019 produced the lowest cost per MW, at $228k/MW.
The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency, while T019 is estimated at $479 million.
The board’s conclusions are summarized in an Addendum to the Draft AC Transmission Public Policy Transmission Planning Report, which goes back to the MC for further review and comment before board members can make their final determination on project selection.
VALLEY FORGE, Pa. — PJM CEO Andy Ott attended last week’s Markets and Reliability Committee meeting to respond to concerns about the Board of Managers’ recent ultimatum around price formation — and members were more than happy to offer additional ones.
Under the gun of the board’s Jan. 31 deadline to revise six characteristics of PJM’s energy market price formation, stakeholders last week heard first reads of three alternative proposals. (See PJM Moving Quickly to Make Board’s Price Formation Deadline.)
Ott said the board felt several of the revisions for which it intends to request FERC approval are “no-brainers” in that they have already proven successful in solving other problems for PJM.
“We feel we are correctly criticized as a region for not addressing known price anomalies,” Ott said. “There is a very strong opinion by the board that we are long overdue for these changes.”
He said PJM staff could provide additional data for stakeholder analysis after the revisions have been implemented, but “we’re not in that mindset right now” to wait for additional data to validate the revisions. “As a board, we felt that these issues had been discussed for years.”
Responding to concerns about whether the board was fully apprised of activity in the Energy Price Formation Senior Task Force (EPFSTF), Ott said they are “well aware” and have had a “complete discussion of where the stakeholders were.” Instead of asking to slow down changes, stakeholders should be helping PJM speed them up, he said.
“The pace of the industry is not going to slow down for us. In fact, it’s going to accelerate,” he said. “On some of the very big and broad issues, we struggle on how to get them through in a way that’s timely. … These are so obvious that we need to get it through to FERC. … We don’t feel it’s rushed; we feel it’s actually delayed.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he is fielding questions from his members asking why this is happening now when major changes are already imminent for other PJM markets, including capacity and financial transmission rights.
“It seems like everything is happening at once,” he said.
“The fact that the votes haven’t happened, it’s not delay. It’s truly trying to do the right things by the market,” said Susan Bruce, representing the PJM Industrial Customer Coalition. “We have almost a fiduciary responsibility” to understand the full impacts of the proposal before going to FERC, particularly if stakeholders are going to be asked to endorse it.
Ott acknowledged that some issues, such as alignment of day-ahead and real-time reserves, haven’t been discussed and hoped that they could be addressed in January.
Collapse the Process
The call to immediate action left some stakeholders questioning the value of debating the issues within PJM.
“You have stated that the stakeholder process is antiquated and of no real use to you,” said Ruth Ann Price of the Delaware Division of the Public Advocate. “Perhaps we need to collapse the stakeholder process and just go directly to FERC.”
Ott admitted that the board did discuss making a unilateral filing under Section 206 of the Federal Power Act rather than issuing its Dec. 5 letter to stakeholders, but he said he “feels very strongly that stakeholder input is vital.”
“Time and time again, the stakeholder process has improved proposals, and we believe that,” he said. “I think it’s of tremendous value.”
While PJM comprehensively outlined its proposal to meet the board’s demands, it was unclear which member company would be motioning or seconding it for consideration. The proposal includes increasing the penalty factor for pricing reserve scarcity in the operating reserve demand curve (ORDC) to $2,000/MWh.
Still a work in progress, a second proposal from the D.C. Office of the People’s Counsel mainly focuses on maintaining the current $850/MWh ORDC penalty factor.
PJM’s Independent Market Monitor presented its alternative, which remained unchanged from its EPFSTF proposal that would, among other things, delineate smaller subzones and create an ORDC “based on analysis of actual operator demand for additional reserves.” Monitor Joe Bowring said the ORDC is “overstated” in PJM’s proposal.
Finally, Calpine’s David “Scarp” Scarpignato proposed to implement PJM’s proposal without a “transitional mechanism for the energy and ancillary services (E&AS) revenue offset to reflect expected changes in revenues in the determination of the net cost of new entry.” Spark spreads have been “coming down,” Scarp said, but a “high variance” remains between expected and actual E&AS revenues.
Stakeholders will vote on the issue at the Jan. 24 MRC meeting.
A Government Accountability Office report on geomagnetic disturbances released last week found a lack of consensus on how much of a risk they pose to the U.S. electric grid, in part because of limited modeling capabilities.
GMDs, which occur when the sun ejects charged particles that change Earth’s magnetic fields, can cause geomagnetically induced currents (GIC) that produce voltage instability and damage connected equipment.
Although such coronal mass ejections occur regularly, GAO said there have been only four GMDs worldwide since 1932 that significantly affected the grid with large-scale service disruptions or equipment damage. The only instances in the U.S. were GMDs in March and September 1989 that damaged four single-phase transformers at one power plant, with no loss in electric service.
Coronal mass ejection (CME) approaching Earth | GAO-19-98
‘Key Gaps’
“The magnitude of potential damages from a large GMD is not fully understood, in part because there have been few examples worldwide of GMDs that have caused equipment damage or large-scale blackouts,” GAO said. “Determining how GMDs will interact with and harm the electric grid is challenging because the magnitude of the ensuing GIC is influenced by several factors. The reaction of specific components of the electric grid to GIC and its secondary effects is also challenging to accurately model.”
GAO said there are “key gaps” in the understanding of variables that impact severity, such as data on local geoelectric fields. The U.S. Geological Survey has only 14 ground-based observatories measuring local magnetic fields.
“The relatively sparse coverage of magnetic observatories, particularly in the contiguous United States, limits the ability to monitor GMD in areas without magnetic observatories,” GAO said. “Even when the GMD is measured at nearby magnetic observatories, Earth resistivity required to calculate the geoelectric field … is often the dominant source of uncertainty in GIC calculations. … Earth resistivity varies by about a factor of 10,000 within a Midwest region otherwise described by a single, one-dimensional ground resistivity model.”
Because extreme GMDs are rare, researchers have attempted to extrapolate the impact of extreme events from available data on moderate events. But GAO said, “Researchers at Los Alamos National Laboratory found that the probability of extreme events is not accurately described by statistical models of historical records.”
Worst Case?
The worst-case scenarios from a solar-induced GMD — or an electromagnetic pulse produced by the detonation of a nuclear device 25 to 250 miles above Earth’s surface — sound like the stuff of disaster movies.
“A large GMD might have long-term, significant impacts on the nation’s electric grid,” GAO said. “Given the interdependency among infrastructure sectors, such a disruption to the electric grid could also result in potential cascading impacts on fuel distribution, transportation systems, food and water supplies, and communications and equipment for emergency services, as well as other communication systems that utilize electrical infrastructure.”
But the auditors said recent research suggests that the worst GMDs might have only limited impact. “The most persuasive studies we reviewed concluded that the most likely effects of a large GMD would be service interruptions that are neither long-term nor large-scale,” GAO said.
Coronal mass ejections cause geomagnetic disturbances that may interact with the electric power grid. | GAO-19-98
Two National Laboratory studies that evaluated the impact of an extreme GMD event on the Eastern and Western interconnections concluded “that the disconnection or loss of transformers experiencing high GIC would avoid equipment damage and maintain grid stability. … It is possible to use operating procedures or GIC-blocking technologies to protect transformers and grid stability.”
NERC cited operational procedures such as increasing operating reserve margins, modifying protective relay settings and removing vulnerable equipment from service.
A study by an unnamed electric power supplier “concluded that failures in generators or capacitors are unlikely during a 100-year storm,” GAO added.
NERC’s Geomagnetic Disturbance Task Force concluded that the most likely worst-case system impacts from a severe GMD event would be voltage instability and potential blackouts. But GAO noted that “blackouts that originate in the transmission grid in the absence of substantial equipment damage are generally restored within three days and often much sooner.”
GAO’s findings on the limited data echo frustrations FERC and the Department of Energy have expressed.
In 2016, DOE said traditional power system planning models are flawed because they do not include substation grounding or transformer configuration details, which are essential to modeling GIC flows.
In November, FERC approved NERC’s revised GMD reliability standard, which broadens the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions (RM18-8, RM15-11-003). (See Revised NERC GMD Standard Approved.)
The standard seeks to create a benchmark for estimating the impact of a large GMD. But GAO said “conducting such estimates is challenging because the wide variety in transformers, including model, age and power capacity, could lead to significant variability in the effects [of] GIC on specific transformers.”
At FERC’s direction, NERC has joined with the Electric Power Research Institute to develop a research plan to improve the benchmark GMD event and Earth resistivity models.
Technological Fixes?
An October 2016 executive order by President Barack Obama directed DOE and the Department of Homeland Security to develop a plan to test and evaluate technology that could mitigate the effect of GMDs. The GAO report came in response to a request by the Senate Committee on Homeland Security and Governmental Affairs to examine the availability of such technologies and the challenges of using them.
DOE told the auditors that it completed a plan for a pilot program to test commercially available technology in April and has hired contractors to implement the plan.
The GAO researchers reported that three-phase transformers may be less vulnerable than single-phase units, but it said the larger, heavier three-phase units present shipping challenges.
GAO said series capacitors, used to improve the transfer capability of long transmission lines, can also block GIC. “However, care must be exercised in placing series capacitors in the electric power transmission system because blocking GIC in one section of the grid can affect GIC flow in other sections of the electric power transmission system. Therefore, it is necessary to evaluate the effect of series capacitors in sections of the electric power transmission system on other sections of the electric power transmission system before they are installed,” GAO said.
The Public Utility Commission of Texas last week preliminarily approved a certificate of convenience and necessity for CenterPoint Energy’s proposed 345-kV project in the industrial Freeport area south of Houston, but not before quibbling over the wide range of cost estimates (Docket 48629).
CenterPoint provided ERCOT a revised estimate of $481 million to $695 million for a new 345-kV double-circuit transmission line over its preferred route connecting two substations and upgrading an existing 345-kV double circuit line. The grid operator filed a revised study with the PUC on Dec. 14 that still recommends CenterPoint’s preferred route.
“The range of cost estimates is still not terribly satisfying,” Commissioner Arthur D’Andrea said. “It’s no one’s fault but the ambiguity and uncertainty of doing these [studies].”
“Unsatisfying is an understatement for me,” PUC Chair DeAnn Walker said, “especially when the low end — the $481 million — depends on using state land that I’m not sure is even an option.”
In September, the commission had asked ERCOT to take a second look at the project in the face of rising costs.
ERCOT reviewed five options in its original study and 10 in the second. Its Board of Directors approved the project, which was estimated at $202 million, in December 2017. (See “Board Approves $246.7M Freeport Transmission Project,” ERCOT Board of Directors/Annual Meeting Briefs.)
PUC Slashes NRG’s Nuke Decommission Costs
The commission approved a 65.2% reduction in the decommissioning costs for NRG South Texas’ share of the South Texas Project (STP) nuclear plant (Docket 48447).
With the order, NRG’s annual funding amounts will drop from $758,791 to $264,351.
The PUC “substantially reduced” the annual funding requirement in its last review in 2013, assuming a 20-year license extension for STP’s twin units from the original 2027 and 2028 expirations. The Nuclear Regulatory Commission approved the extensions last year.
NRG’s share of the decommissioning fund was $691.8 million at the end of 2017. The plant faces total decommissioning and dismantling costs of an estimated $2.5 billion.
The company owns a 44% share of STP. The plant’s other two owners are the city of San Antonio (40%) and the city of Austin (16%).
The nuclear plant’s two units have a combined capacity of almost 2.6 GW. They have been online since the late 1980s.
Hearing Schedule Set for Sempra-Oncor-Sharyland Deal
The commission will hold hearings April 10-12 on proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services (Docket 48929).
Staff filed a procedural schedule following a Dec. 18 prehearing conference.
In October, the parties announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
The transactions would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in central, north and west Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest. The real estate investment trust (REIT) structure that holds Sharyland and Sharyland T&D would be terminated.
InfraREIT and Sharyland are both owned by Hunt Consolidated, which failed in a 2016 attempt to acquire Oncor.
