BOSTON — Three developers submitted proposals Wednesday in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.
The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
| BithEnergy
The state’s first request for proposals (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management.
Bay State Wind
Bay State Wind, a joint venture between Ørsted and Eversource, proposed a 400-MW or 800-MW wind farm 25 miles off of New Bedford. It would be paired with a 55-MW battery storage facility, “the largest battery storage system ever deployed in conjunction with a wind farm,” it said.
Ørsted, formerly DONG Energy, is the No. 1 offshore wind generator in the world. The company would use New Bedford as the staging area for construction and the base of its operations and maintenance through the wind farm’s lifetime. The storage facility and an onshore substation would be located in Somerset.
Deepwater Wind
Deepwater Wind’s proposal would firm its project’s wind output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
Interior of Northfield Mountain pumped storage facility | Northfield Mountain
Deepwater proposed two versions of Revolution Wind, a wind farm of approximately 25 turbines to generate 200 MW, or double that size to generate 400 MW. The company had proposed an initial 144-MW phase of the project in response to the state’s 83D solicitation for 9.45 million MWh of clean energy. The state is due to announce winners of that RFP on Jan. 25.
Deepwater is the developer of the Block Island Wind Farm off Rhode Island, the nation’s first commercial offshore wind farm. It also partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)
The company’s project would connect to land at the Brayton Point substation in Somerset.
Vineyard Wind
Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, is betting that its promise to deliver an operating project by 2019 will win the state’s favor. It submitted proposals for 400-MW and 800-MW wind farms, with approximately 50 and 100 turbines, respectively. Avangrid owns Unitil.
| BOEM
Vineyard Wind said it has already submitted applications with BOEM and the state Department of Public Utilities’ Energy Facilities Siting Board for the wind farm, about 15 miles south of Martha’s Vineyard. “By filing for construction permits, Vineyard Wind is on track to complete the permitting process in time to begin construction in 2019,” it said.
Deepwater said if it is selected it would begin construction in 2022, with the project in operation in 2023. Bay State did not mention a timeline in its press release.
The state will announce the winners of the offshore wind solicitation on April 23, 2018, and contracts are to be submitted at the end of July.
This month saw an early offshore wind project, Cape Wind, exit the stage. It announced Dec. 1 that it had notified BOEM it was stopping development of its proposed wind farm project in the Nantucket Sound and filing to terminate its offshore lease issued in 2010.
Nevertheless, the state’s solicitation has been a cause for optimism among green energy advocates, who note the attractiveness of the Atlantic’s strong winds and shallow waters. (See ‘Momentum’ Seen for U.S. Offshore Wind.)
Entergy on Monday asked FERC to clarify the deadline for NYISO to complete a final market power review for the deactivation of the Indian Point nuclear plant, or grant the company’s request to rehear the commission’s approval of a previous ISO compliance filing (ER16-120, EL15-37).
| Entergy
At issue is FERC’s November conditional acceptance of NYISO tariff revisions to implement a new reliability-must-run program. (See FERC Approves NYISO Reliability-Must-Run Plan.) The ISO in September submitted a compliance filing to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. The commission had accepted an earlier compliance filing for the proposal, but in April 2016 directed NYISO to make further changes to the program.
In its Dec. 18 filing with FERC, Entergy said that while NYISO’s second compliance filing contained a 90-day deadline for completing reliability studies related to plant shutdowns, it did not contain a provision for a 120-day market power review deadline included in the first compliance filing. As a result, the commission’s Nov. 16 order was “arbitrary, capricious, unsupported by substantial evidence and not a result of reasoned decision-making” because FERC conditionally accepted the ISO’s compliance filings without requiring it to establish a clear deadline early in the process for deactivating generators, the company argued.
Entergy contended that without a clear deadline for review, the 2,311-MW Indian Point plant lacked certainty about its authorization to exit the market in accordance with NYISO’s tariffs.
“At the very least, the NYISO should be held to its own assertions,” Entergy said. “Here, the NYISO has emphasized the need to perform any necessary market power review at the start of this process and has expressly confirmed its ability to complete this analysis in the first four months after receiving a completed generator deactivation notice … [and] a final market power review both in presentations to stakeholders and pleadings before this commission.”
The company is seeking a March 13, 2018, deadline for NYISO to complete a market power study for the closure of the Indian Point.
Artist’s rendering of the Cricket Valley 1020 MW plant | Cricket Valley Energy
An ISO report earlier this month found that new gas-fired and dual-fuel generation coming online in the next few years, led by the 1,020-MW Cricket Valley plant in Zone G, will provide sufficient capacity to maintain reliability after Indian Point shuts down completely in 2021. (See New Builds to Cover Indian Point Closure, NYISO Finds.)
TRENTON, N.J. — If opponents of nuclear subsidies in New Jersey had an opportunity to sway the opinions of state legislators on the issue, it didn’t last long.
During a joint meeting Wednesday of the state Senate Environment and Energy Committee and Assembly Telecommunications and Utilities Committee, members early on indicated their support for a bill that would provide hundreds of millions of dollars in financial support to state nuclear plants. (See Nuke Bailout Bill Introduced in NJ Senate.)
After five hours of testimony, their opinions had not changed. Both committees unanimously voted to move the bill to their respective legislative bodies. ClearView Energy Partners, an energy research firm, said in a statement that the legislature could vote on the bill before the end of next week. It predicted Gov. Chris Christie would sign the bill into law before he leaves office on Jan. 16.
“There’s this constant question about ‘why now?’ The answer is: It’s one of the greenest bills we’ve run into in a long time, and No. 2, we can get it done,” said Sen. Bob Smith, who chairs the Environment and Energy Committee.
Opponents argued that the bill required no commitments from Public Service Enterprise Group, such as a plan for a transition to renewable energy when the plants are eventually decommissioned or a mechanism for the company to pay back any money if market conditions change to make its nuclear plants profitable again.
“You’re feeding the problem that this country faces right now with Donald Trump. We are losing faith in government, and if you [approve] this bill during lame duck, you are part of the problem,” said Doug O’Malley, director of Environment New Jersey. “So hold the bill. Let’s do this right in January, February and March.”
PSEG CEO Ralph Izzo opened the hearing by assuring legislators that enacting the bill was a vote of confidence for his company to commit years ahead of time to investing as much as $200 million annually for the plants’ supply chains.
“There’s been a lot of discussion about this being an automatic handout to utilities. That is not true,” Izzo said, noting that it will be at least 300 days until PSEG will know if its plants qualify for the subsidies proposed under the bill. “Over that time, we will have to decide whether or not to invest between $100 [million] and $200 million in those plants and make an estimate as to whether or not those plants will continue to operate for the remaining 20 or 30 years of their life to make that money back.”
PSEG currently has $275 million in commitments for fuel-related expenses until 2025, he said, and must decide over the next year whether it will commit to keeping the plants open through 2021.
“This is not a rush. This has been an eight-year discussion,” Izzo said. “I encourage you to recognize that driving the vehicle by exclusively focusing on the rear-view mirror is not the safest way to proceed. Most companies look forward on the prospects of their assets.”
Izzo’s comments were rebutted by Stefanie Brand, director of the New Jersey Division of Rate Counsel, who argued that the bill is unclear on how much money PSEG should make or how unprofitable the plants will be without support. Izzo said they will remain profitable at least until next year when a number of PSEG’s energy contract hedges expire.
“There are offramps for the company. There are no offramps for the ratepayers,” she said. ““I’m not advocating for [the plants] to close. I’m advocating for a system that doesn’t allow a single company to hold us hostage in this way.”
Senate President Stephen Sweeney grilled Brand on her concerns, asking whether she thought the state Board of Public Utilities, which would oversee distribution of the plan’s nuclear diversity certificates (NDCs), is capable of fulfilling that role. Brand said it was impossible to know because eligible plants could submit information confidentially without public review. She noted that the subsidized plants would also likely be subject to PJM’s minimum offer price rule (MOPR).
“The rest of us don’t have the information that PSEG does to claim they’ll close. … The consumer protections in this bill are really a delusion,” Brand said. PSEG is “deregulated, so there is no set cost of capital that they are set to earn.”
She added that out-of-state plants, such as Exelon’s Three Mile Island plant in Pennsylvania, might be eligible for the subsidy the way the bill is currently written.
Industry analysts also traded opposing studies on the issue. Dean Murphy with The Brattle Group outlined a study sponsored by PSEG and Exelon that argues it would be cheaper to pay to keep the plants running than to develop replacement power. Tanya Bodell with Energyzt said that report is “flawed” and includes substantial “uncertainty.” She challenged Izzo’s assertion that they might close within two years if they become uneconomic.
“The plants are committed to operate through 2021,” she said. “It would be more costly to retire before 2021.”
Joe Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, said that while his company can’t decide whether to close the nuclear plants, it can stop investing in them. Exelon can nix any investment over $5 million into the plants, he said, and has come to an agreement with PSEG to begin deferring capital projects “in anticipation of the closure of” the Salem facility.
“As we looked at the market forwards … our concern was that we could no longer invest in the machine given what we were looking at in terms of future energy prices,” he said. “We are already acting on the belief that if adequate attribute payments aren’t provided for nuclear energy in New Jersey, we’re going to take the unit out of service, or at least from Exelon’s perspective, stop investing in the machines.”
One significant opponent to the bill received short shrift from legislators.
After calling NRG Energy CEO Mauricio Gutierrez to testify, Smith referred to him as “Maurice” and declined to attempt his surname, asking him to instead introduce himself. Gutierrez argued that the bill “creates only one winner and many losers, including my company.”
NRG owns no nuclear assets in New Jersey and has a portfolio of mostly gas-fired units. Substantial supplies of natural gas have kept commodity prices low and helped gas-fired generation offer into PJM’s markets at prices below nuclear units. The shift in generation economics has prevented some nuclear units from clearing auctions and denied them payments they say they need to remain profitable.
Gutierrez told the committees that had the subsidies existed before he decided to base his company in Princeton, N.J., he would have placed the headquarters elsewhere. The legislators asked no questions about his testimony, and Gutierrez appeared visibly frustrated as he returned to the audience.
NERC is offering SPP’s 128 registered entities a chance to comment after assigning them all to a new Regional Entity.
The reassignments became necessary when the SPP RE announced its dissolution in July, addressing NERC and FERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.) Responses are due back to the organization by Jan. 5.
NERC said it received 122 transfer requests spanning five REs, with six entities expressing no preference for a “transferee” RE. The organization placed most of the registered entities into the Midwest Reliability Organization (MRO), with 13 Arkansas, Louisiana, Mississippi and Missouri entities assigned to SERC Reliability.
Arkansas Electric Cooperative Corp., which provides power to Arkansas’ 17 distribution cooperatives, was placed in both MRO and SERC.
In a message to the registered entities, RE President Ron Ciesiel said it was the RE’s “understanding” that NERC is on target to present final transferee recommendations to the organization’s Board of Trustees at its February meeting.
“We believe there is a high probability the transfer can be completed in the July time frame,” Ciesiel said.
After an initial review and analysis of entity requests, NERC said it determined that granting all the requests “would neither result in effective and efficient administration of compliance and enforcement activities, nor a cohesive functional alignment to support and promote BPS [bulk power system] reliability and security.”
In reviewing the requests, NERC considered the location of an entity’s BPS facilities in relation to the geographic and electrical boundaries of the transferee RE. The agency also assessed the impact of a proposed transfer on other BPS owners, operators and users, including affected reliability coordinators, balancing authorities and transmission operators, as appropriate.
NERC said it recognized that its procedural rules do not contain criteria for “the allocation of multiple registered entity transfers” when an RE dissolves, so it used criteria from another rule for considering requests. The organization reviewed each transfer request using that criteria and other “entity-specific circumstances.”
When NERC’s recommendations differed from the entities’ requests, it contacted the entities and explained its rationale, the agency said.
Created in 2007, the SPP RE is responsible for auditing and enforcing NERC reliability rules in three balancing authorities: SPP, the Southwestern Power Administration and parts of MISO.
SPP said it is dissolving the RE in part because the RTO’s expanded footprint no longer aligns with the RE’s territory. However, FERC criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO.
Calling 2017 a “tumultuous year for SPP RE,” Ciesiel told its registered entities that RE staff, while working at reduced levels, achieved its highest ever metrics performance.
“A good way to close out the year for us,” he said.
The dissolution is expected to be completed by the end of next year.
ERCOT’s reserve margins may be tightening, but executives on Monday assured reporters that all is well with the Texas grid.
The ISO’s year-end Capacity, Demand and Reserves (CDR) report projects a 9.3% planning reserve margin for 2018, half of what it was in the May report and 4 points below the 13.75% target ERCOT established for itself in 2010. But during a conference call with media, staff described the CDR report’s reserve margin projections as a “snapshot in time” and detailed a list of tools available to handle any emergencies.
“The reserve margin that comes out of the CDR is a snapshot,” said Warren Lasher, senior director of system planning. “Reserve margins are expected to fluctuate in the current market design.”
The May CDR reported an 18.9% reserve margin for next summer. Since then, Vistra Energy has said it would retire about 4 GW of coal resources and ERCOT has reported a year’s delay in completing construction of almost 4 GW of planned capacity. (See Vistra Energy to Close 2 More Coal Plants.)
| ERCOT
Lasher pointed out that since 2010, the Public Utility Commission of Texas has directed ERCOT to develop a new standard for determining the planning reserve margin, similar to a 2014 Brattle Group study on estimating “economically optimal” margins that minimize total system and operating costs. The ISO is currently conducting its own study, which it intends to complete in the third quarter of 2018 before reporting back to the PUC, Lasher said.
| ERCOT
“I wouldn’t call [the CDR] cause for concern,” he said.
ERCOT expects 14 GW of resources to be in service by 2020 and will still have 77.2 GW of capacity on hand to meet a 2018 summer peak demand forecast of almost 73 GW. That would break the August 2016 record peak of 71.1 GW.
Demand is expected to grow at a 1.7% average annually over the next 10 years. The reserve margin is expected to increase to 11.7% by summer 2019, peaking at 11.8% in 2020 before dropping to 9% in 2022. Total capacity is expected to reach almost 83 GW in 2022.
“We see these types of shifts as the ERCOT market experiences cycles of new investments, retirement of aging resources and growing demand for power,” CEO Bill Magness said in a statement.
If the worst comes to worst, Lasher said ERCOT can always request emergency assistance across DC ties with Mexico or the Eastern Interconnection, or fall back on interruptible customers and switchable units obligated to other regions.
The December CDR report includes information about existing and planned generation resources and expected energy needs over the next 10 years. The report does not include the potential additional migration of nearly 600 MW of load should Lubbock Power & Light and Rayburn Country Electric Cooperative eventually migrate customers from SPP into the Texas grid. (See “ERCOT, SPP to Coordinate Second Load-Migration Study,” PUCT Briefs: Aug. 17, 2017.)
MISO is reviewing an expedited project request from American Transmission Co. to connect a massive Foxconn manufacturing plant that would be Wisconsin’s largest power user.
ATC’s proposed $140 million Mount Pleasant Tech Interconnection Project is one of the first two expedited review requests for MISO’s 2018 Transmission Expansion Plan. Along with a small substation upgrade in Minnesota that the RTO has approved, the project was presented to stakeholders at Tuesday’s Planning Advisory Committee conference call, days after MISO’s Board of Directors approved MTEP 17.
ATC has proposed a new 345/138-kV substation, 14 miles of new 345-kV line and four short 138-kV underground lines to connect a southwestern Wisconsin manufacturing plant proposed by Foxconn to We Energies supply.
Foxconn, headquartered in Taiwan, is the world’s largest electronics manufacturer, responsible for building Apple mobile devices, Amazon Kindles and video game consoles.
Its factory will be similarly outsized. Wisconsin Gov. Scott Walker has framed the $10 billion plant, which is expected to create as many as 13,000 jobs, as a “once-in-a-century opportunity” and called for it to be operating by 2020. ATC has said the plant will require up to six times as much power as the next-largest manufacturing facility in Wisconsin.
ATC hopes to get the $10 billion plant connected to the grid by the end of 2019 and plans on ordering some long-lead time equipment beginning in February. It said MTEP 18 approval would arrive too late for its planned construction timeline.
The company said it received the load interconnection request from WE on Oct. 12. MISO posted ATC’s expedited request on its website Dec. 6, although it is not clear when the RTO received it.
MISO is still studying the implications of the request and will convene a Technical Study Task Force meeting in January to go over study results with stakeholders, according to Lynn Hecker, manager of expansion planning.
ATC plans to seek project approval with the Wisconsin Public Service Commission in February, with hope for approval in August.
In addition to the new substation, ATC plans to string a new 12-mile, 345-kV circuit from Pleasant Prairie to Mount Pleasant, Wis., and create two 1.2-mile, 345-kV loops into the new substation on existing transmission structures. The project also includes the construction of four new 138-kV underground lines at less than a mile apiece connecting the Mount Pleasant substation to the manufacturing plant.
Minn. Capacitor Bank
Meanwhile, MISO has already studied and approved a much smaller substation upgrade in Minnesota, making it the first expedited project approval in the 2018 package.
The project — a $500,000, 14.4-MVAR capacitor bank addition to a substation in southern Minnesota — is expected to be in service by the end of January, according to developer Great River Energy. Capacitor banks counteract a power factor lag or phase shift in a power supply.
MISO recommended the project be granted expedited status in MTEP 18 as a baseline reliability project because the substation is currently susceptible to low voltages when a generator outage is followed by a line outage, a NERC-defined contingency. The project will also improve local area voltage performance in general, Hecker said.
Developers of renewable energy and emerging technologies are predictably supportive of CAISO’s vision for the grid of the future, but operators of more traditional resources say the proposal drifts outside the ISO’s purpose of assuring reliability and managing markets.
The nearly 200 pages of comments on CAISO’s Vision 2030 paper illustrate concerns about the ISO’s changing grid mix, laying out arguments that the transition is coming at the expense of reliability, fair markets and reasonable costs to ratepayers.
CAISO’s Board of Governors and management published the discussion paper in October, saying it was “intended to help focus discussion on both technical and policy issues involved in decarbonizing and decentralizing electric service.” The document identified California energy trends over the next 12 years, including more efficient energy use, a significant decline in gas-fired generation, more variable energy resources, decentralized service, regional collaboration and integration of electric vehicles. (See CAISO Symposium Panelists Talk Grid of the Future, Western RTO.)
The Independent Energy Producers Association, which includes both fossil fuel and renewable interests, suggested that CAISO had wandered from its core mission and is picking winners and losers by focusing on decarbonization and distributed resources.
“Overall, we find the Vision Paper not particularly helpful in illuminating what, if anything, the CAISO management will be ‘tasked’ to accomplish over the near term, e.g. one to five years, related to the CAISO’s primary function to maintain 60 Hz on the electric transmission grid and administer just and reasonable wholesale markets,” said IEPA CEO Jan Smutny-Jones, a former CAISO board chair.
The group urged the ISO to focus on accessing low-cost, transmission-connected renewables. It also complained that while the California Public Utilities Commission’s integrated resource plan assumes that about 30,000 MW of gas-fired generation will not be subject to retirement because of environmental rules by 2030, CAISO’s paper makes no accommodation for sustaining those resources.
“The evidence clearly recognizes a need for this type of generation (flexible capacity), yet the market provides little if any means to ensure that competitive resources that can provide these necessary services are available to the CAISO when and where needed. Importantly, the Vision Paper is silent on what, if anything, CAISO intends to do to address this matter,” the group said.
The California Municipal Utilities Association (CMUA) filed brief comments saying that issues identified in the paper, such as energy efficiency, vehicle electrification and economic impacts, “may all have an indirect impact on how the CAISO operates the grid. But the policies and choices inherent in each of these issues are not the CAISO’s core function, which is critical and complex [in its] own right without these additional challenges.”
CMUA Executive Director Barry Moline mentioned reliability-must-run agreements, the congestion revenue rights auction and the fact that most load-serving entities in the Western U.S. are vertically owned utilities that regulators want to remain in business.
“The CAISO should be cautious when opining on these issues of industry structure, rather than focusing on its core functions, as it seeks to expand collaboration beyond California,” Moline said.
NRG Energy, which operates some fossil fuel plants, said that relying on natural gas plants in constrained areas “is environmentally preferable to spending large amounts of money to eliminate those resources.” CAISO recently determined that NRG’s proposed Puente power plant would be the cheapest alternative out of a mix of alternative resources, but the company suspended its application after the California Energy Commission indicated it would not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)
NRG also noted that many topics in the paper are outside of CAISO’s traditional role, such as developing a new zero-energy building plan and shaping the state’s resource adequacy plan, which is under CPUC jurisdiction.
In Powerex’s comments to the ISO, CEO Teresa Conway promoted “forward arrangements” for flexible capacity and renewable integration. The Canada-based power marketer is due to join the CAISO-run Energy Imbalance Market (EIM) in April 2018. (See FERC Approves Powerex EIM Agreement.)
“We believe the pursuit of forward arrangements, along with expanding short-term energy markets like the EIM, can be an effective strategy for unlocking the capabilities of existing clean resources outside of California, and in particular the unique capabilities of northwest hydro systems,” Conway said. She said the state is at a “critical point” in the transformation of its energy grid and “the initial approaches responsible for the state’s success cannot be scaled indefinitely, and signs of renewable integration challenges are already present.”
Increased regional electricity trade and coordination will provide economic and environmental benefits by meeting customer needs with the cheapest resources, Powerex said, but increased coordination must accommodate differing and sometimes conflicting policy goals.
Powerex proposed establishing a “clean” resource adequacy requirement, aggressively pursuing storage, expanding forward commitment and procurement, and accurately measuring California’s greenhouse gas emissions associated with out-of-state resources.
Southern California Edison said it is not sure it agrees with CAISO’s assessment that, by 2030, demand-side resources will be as important as supply in balancing the system. About 4,500 MW of San Diego peak load will need to be met with supply sources, and “similar conclusions apply to loads in the SCE and [Pacific Gas and Electric] distribution service areas.”
| CAISO
SCE said it supports a “well-designed” carbon cap-and-trade program and properly implemented regionalization, including a Western states committee advisory body.
The Public Generating Pool, which represents 10 publicly owned utilities in Oregon and Washington, gave a regional perspective as other states look to possibly join markets operated by CAISO. California’s neighboring states have more hydro and coal resources and traditional cost-based utility regulation.
“The broad nature of this document and the numerous recommendations for policy, however, do not seem to fit the expected role of the CAISO as an independent system operator,” the group said. “If there are future versions of this document, it would be helpful for the CAISO to be more specific about its role relative to California legislature and state agencies.”
But the ISO’s vision did get solid support from some corners. The California Electric Transportation Coalition said, “We agree with and support Cal ISO’s emphasis on transitioning from fossil fuels to electricity in the transportation sector.” The group said that EVs will be increasingly important to manage load and store excess renewable generation. The ISO’s plan stated that California cannot reach its greenhouse gas reduction goals without electrifying the fossil energy now used in buildings and vehicles.
Arizona-based First Solar, which develops utility-scale photovoltaic modules, offered praise for the CAISO board’s effort to provide a “guiding vision” for strategic planning. And while the company agreed with the “trends and solutions” offered in the paper, it also urged the ISO to consider transmission needs for renewable integration goals.
“Again this year, the CAISO is not addressing additional policy-driven transmission projects in its Transmission Planning Process, creating potential problems for the increased interconnection of renewables required to meet California’s policy goals,” First Solar said.
The CAISO board issued a statement of appreciation for the comments Tuesday, saying they “will be valuable input into the ISO’s ongoing strategic planning process.”
California regulators have approved new measures aimed at wildfire prevention, as utilities face growing scrutiny over fires that have occurred in the state over the last decade.
At its meeting in San Francisco on Thursday, the California Public Utilities Commission also approved a solar incentives program targeting low-income residents, among other decisions. But the CPUC deferred a vote on the retirement of the Diablo Canyon nuclear plant, which has sparked disagreements around the recovery of shutdown costs. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
Focus on Wildfires, Utilities
The CPUC approved more stringent wildfire protections for utilities, creating a “high fire-threat” district where correction of fire safety hazards will be prioritized.
“This is one of the areas where we are working hard to be at the forefront of utility safety programs” and represents “a major rewrite of the fire prevention rules for utility poles,” CPUC President Michael Picker said.
“Most of the elements here are not specifically driven by climate change, but they accept and acknowledge that the scope of the problem is changing,” Picker said, noting that high-hazard fire zones have grown to 44% of the state landscape. The decision requires new vegetation management and more stringent wire-to-wire clearances, among other measures.
Speaking during the public comment period, Southern California Edison President Ronald Nichols told the commission that the Thomas Fire in the Los Angeles area is threatening transmission lines and has caused some outages, but only about 500 customers have been affected. The company issued a press release Dec. 11 saying that state investigations “now include locations beyond those identified last week as the apparent origin of these fires. SCE believes the investigations now include the possible role of its facilities.”
Recent fires in California, including the massive Thomas Fire, have been particularly destructive and increased the focus on utilities over their possible role. (See California Fires Spark CAISO Transmission Emergency.) The CPUC recently denied San Diego Gas & Electric’s request to recover the costs of 2007 fires from ratepayers. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Pacific Gas and Electric is also facing investigation and lawsuits over the October fires in Northern California.
Low-income Solar Program
The CPUC passed a measure that implements the framework for a solar incentive program for multifamily housing, including goals, funding, administration and creating a new statewide program administrator. The program is to be financed by $100 million annually from PG&E, SDG&E, SCE, Liberty Utilities and PacifiCorp’s greenhouse gas auction proceeds.
The measure implements Assembly Bill 693, passed in 2015, which creates the Multifamily Affordable Housing Solar Roofs Program. The incentive program will be run by the new administrator and subsidize the costs of solar generation on certain types of multifamily affordable housing. It will allocate net energy metering tariff credits associated with the system’s generation to tenants and common areas of the property. The bill established the program for low-income households that would otherwise be unable to install on-site solar generation.
Picker expressed concerns over the long-term viability of the program because of tax proposals currently under consideration in Congress. Commissioner Martha Guzman Aceves was assigned the initiative.
Guzman Aceves cast the lone “no” vote against a proposed statewide marketing and outreach program for residential rate reform, which was assigned to Picker. The CPUC opened a rulemaking to examine investor-owned utilities’ rate structures, the transition to time varying and dynamic rates, and other statutory obligations.
CPUC Resolutions on CCAs, RMRs
The decisions at the CPUC’s regular meeting came in a week when the agency separately issued several new resolutions that received attention in the industry.
Another resolution sets up a vote next month in response to controversial reliability-must-run agreements signed between CAISO and Calpine to keep the company’s Yuba City and Feather River natural gas units online. The CAISO Board of Governors expressed reservations about the agreements, funded by ratepayers, when it approved them last month. (See Board Decisions Highlight CAISO Market Problems.) The increasing use of RMRs is drawing negative attention for keeping natural gas units operating when they would otherwise retire.
Finally, the CPUC on Friday issued a proposed resolution that would place a moratorium beginning Jan. 11, 2018, on new commercial and industrial customer gas connections in the Los Angeles County area that would rely on Southern California Gas’ Aliso Canyon storage facility.
VALLEY FORGE, Pa. — American Municipal Power last week continued its criticism of PJM’s grid spending, grilling utility officials during a marathon Transmission Expansion Advisory Committee meeting.
Scheduled for four hours, Thursday’s meeting lasted closer to five as Ryan Dolan, AMP’s director of transmission planning, asked technical questions about nearly every project presented and at one point accused American Electric Power of attempting to increase its revenue by overbuilding.
“The reason I was hired at AMP was to control their transmission costs,” said Ed Tatum, AMP’s vice president of transmission, who joined the company two years ago from Old Dominion Electric Cooperative. In September, he hired Dolan — from AEP — to aid his effort.
“AMP has put in place the human and transmission modeling resources to enable us to review and assess PJM and the Transmission Owners’ plans and ask the necessary technical questions to support the need for a project,” Tatum said.
‘Minimum’ Information Required
The TEAC session followed a Planning Committee meeting at which AMP presented templates illustrating the “minimum” information it needs to evaluate projects.
Tatum said he did not “try to orchestrate” the long meeting or “filibuster” to make his point. Without the information requested, he said, “we’re not going to have any choice but to ask those questions” and “we’re probably going to be here until 6 o’clock” next month as well, he said. “The meetings could be done in a couple hours if the information on the examples we provided was available sufficiently in advance.”
The TEAC meeting was surprising for its length, but not its content. Dolan and Tatum have led a customer pushback on the more than $1 billion in transmission projects that get discussed at monthly TEAC meetings before being authorized for construction by PJM’s board through the Regional Transmission Expansion Plan. Their frustration is also on display at meetings of the Transmission Replacement Processes Senior Task Force, where they argue for increased engagement with TOs on when to determine that transmission infrastructure needs to be replaced and how to do it. (See New Wave of PJM Transmission Upgrades Rankles AMP.)
TOs argue that their networks are theirs to maintain as they see fit, but AMP, ODEC and other customers contend that as the ones paying the bills, they should have a say.
Tatum had proposed presenting the project information templates at the TEAC, but PJM moved it to the PC because that is where all discussions on the planning procedure take place. Tatum hopes the move indicates that PJM will organize a discussion on the topic.
“At this point, I’d like to see how that discussion goes,” Tatum said after the meeting. “We would hope that we be able to get more transparency.”
PJM appeared amenable to discussing AMP’s information demands. Staff agreed to add the issue to next month’s PC agenda.
“Clearly what we’re doing now is not sustainable,” said Paul McGlynn, PJM’s administrator of the TEAC.
Confidentiality
TOs have previously raised legal concerns with discussing confidential details of transmission projects in open meetings and did so again on Thursday. Alex Stern of Public Service Electric and Gas said that because issues involving PJM and TO compliance with FERC Order 890 are awaiting a FERC decision, there is a limit on how much TOs can discuss. (See Load Blocks TO Effort to Extend Hiatus of PJM Transmission-Replacement Talks.)
“All of this raises some legal issues as well, so before we go back to the PC, you might want to confer with” PJM’s legal team, he said.
Dolan and Tatum said they understand confidentiality and security concerns and suggested that when there are multiple projects with Critical Energy Energy/Electric Infrastructure Information (CEII) information, PJM could hold meetings restricted to stakeholders with CEII clearance so that the information can be discussed.
Layering Impacts
The pair said several AEP and PSE&G projects discussed at the TEAC highlight their concerns.
AEP is planning to replace its Tidd 345/138-kV transformer on the Ohio-West Virginia border, about 45 miles west of Pittsburgh. The 150-MVA unit, which was manufactured in 1957, was taken out of service in March. The new unit will be increased to 450 MVA and include a series reactor on the low side to mirror a parallel transformer, at a cost of $7.8 million.
Dolan said the project description failed to explain whether the proposal sizes the reactor appropriately for future short-circuit changes. “Are we going to see an issue in five years? Four years? Two years?” he asked. Tatum later questioned whether AEP planned ahead when it replaced the facility’s breakers to account for a second breaker.
AMP argues that TOs’ supplemental projects — which are based on their internal criteria and don’t require PJM authorization — can create reliability issues that necessitate baseline projects, which are directed by the RTO’s criteria and do require board authorization. The lack of information makes it impossible to evaluate how a supplemental project impacts individual equipment on the system because stakeholders are only made aware after a piece of equipment is overloaded, AMP said. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“The lack of this information concerns us because by putting in a bunch of supplemental projects, the transmission owners can be bringing the system up to a point where the [NERC criteria] would soon require baseline reliability upgrades,” Tatum said.
| PJM
PJM has said its abiding principle in planning for increased grid resiliency is “do no harm.”
“What do you consider ‘do no harm’?” Dolan asked. “The only organizations that are aware of the impacts, power-flow-wise, of these supplemental projects are the TOs that are submitting them and PJM.
“Stakeholders are not getting an opportunity to review the impact of these projects. The only time that there is any sort of review done is if those projects actually create overloads,” he said. “What we are interested in is to understand the incremental [system power flow changes associated with these projects]. … We have concerns about the layering of projects … which change system impedances and responses that drive [future baseline] overloads.”
Selective Criteria
At the Broadford station in southwestern Virginia, AEP is planning to spend $102 million installing six new breakers and replacing seven breakers, a reactor and two transformers that are showing signs of imminent failure. Dolan argued the additional breakers were unnecessary and will protect nothing that isn’t already protected by the existing breakers.
AEP has similar situations at its Kenzie Creek, Cloverdale and Desoto stations, he said, but chose not to increase protection there. Kenzie Creek is in Michigan about 20 miles north of South Bend, Ind., Cloverdale is in Virginia and Desoto is northeast of Muncie, Ind.
“You’re willing to spend money when you’re able to get away with it,” Dolan said to AEP representatives who called into the meeting. They denied the accusation and said they use discretion when applying their criteria.
“Even though the projects involve circuit breakers’ replacement, the optimal solution for each is unique,” AEP’s Kamran Ali said in an email to RTO Insider.
The difference, he said, is that nearly all the 138-kV breakers need to be replaced at Broadford, so it makes sense — from a cost, reliability and outage perspective — to build a new 138-kV yard. Adding the “separation of protection zones” at that time is both cost effective and efficient, whereas the other projects only require individual equipment replacements that make separation of protection zones “neither prudent nor cost effective,” Ali said.
Dolan wasn’t satisfied.
“They are not being consistent, and they are not being consistent about information they do not provide to the public,” Dolan said. “I’m starting to notice that this is unique to certain states.”
Dolan said AEP is planning similarly excessive breaker installs at the Axton station, also in Virginia.
“It is most cost-effective to tailor the asset replacement solution to the scope of the project and the specific site conditions. This is not the result of inconsistent approaches, but a commitment to deliver solutions that address the need in the most cost-effective manner for our customers,” Ali said in his email. “Applying a rigid approach that does not recognize the differing situations could lead to higher costs, lower reliability, and less efficient projects for our customers.”
Maintenance Questioned
Other stakeholders joined Dolan in questioning PSE&G’s $546-million rebuild of its 53-mile Roseland–Branchburg–Pleasant Valley corridor. David Mabry, who represents the PJM Industrial Customer Coalition, noted that two of the photos of degraded equipment included in PSE&G’s documentation were date-stamped September 2013. Stakeholders questioned why PSE&G waited four years to present the violation of its FERC Form 715 criteria, which allow TOs to determine what factors indicate when its facilities should be replaced.
Roseland — Branchburg — Pleasant Valley Transmission Tower Damage | PJM
Dolan argued it might be because the shortened repair timeline designates the project as “immediate need,” which ensures PSE&G will be able to replace the infrastructure itself and the project won’t be eligible for competitive bidding.
“One of two things is happening: We’ve either chosen not to address it back then and customers could have been put at risk [of service interruptions], or we waited until we could make the determination that it is immediate need,” Dolan said. “By driving everything to immediate need … you’re preventing opportunities for competition. … When we have a lack of competition, we have an excessive amount of costs.”
Stern and PSE&G colleague Esam Khadr disagreed with the “immediate need” characterization, saying it went through a condition assessment as outlined in Form 715 procedures, including independent analysis by an outside consultant.
“These particular pictures may have been from 2013, but the line continued to be maintained and provide service while condition assessments per the FERC Form 715 procedures were only recently completed,” Stern explained.
Dolan said this is a pattern with PSE&G projects.
“I have yet to see a [Form 715] project come forward that is not immediate need when they bring it forward,” he said.
In an email to RTO Insider, Stern responded that “AMP can’t have it both ways.”
“They can’t profess to want TOs to maintain facilities for as long as viable, performing assessments and maintenance for as long as possible and then when condition assessments indicate that that is no longer viable, assert that the project should have been brought sooner. The Roseland-Branchburg-Pleasant Valley line is one of the original lines dating back to the formation of PJM 90 years ago. It has been maintained for decades and provided steady, reliable service on behalf of customers through that entire time. It has certainly done its job. However, condition assessment clearly reveals that it is in need of replacement, and replacement under these circumstances is the correct and cost-effective approach for customers.”
Sharon Segner of LS Power also questioned the timing of the proposal, saying the project should be opened for competitive bidding under FERC Order 1000.
“It very well may be the solution,” she said. “What I’m questioning is the process.”
Stern later noted that “FERC Form 715-driven projects are exempt from competitive bidding processes pursuant to FERC orders.”
AMP’s proposed project information templates received endorsement from Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS).
“The consumer advocate offices are well aligned with AMP,” Poulos said.
PJM Response
PJM staff attempted to divert project questions to its newly formed online Planning Community, providing a refresher on the group’s purpose.
“It’s not a dead letter office,” PJM’s Fran Barrett said.
But Dolan disagreed, complaining that he hasn’t received responses in that forum.
“I’ve submitted a whole slew of questions [to both the planning community and directly to PJM], and just writing them down doesn’t get them answered. My question is: Even if we write them down are they going to get answered?” he said. “I have not received a response to everything [asked], and in fact, we’ve been told we’re not getting an answer” to some questions.
PJM presented several charts documenting transmission projects including one that showed AEP, Dominion Energy and PSE&G proposing many supplemental projects, which are not competitively bid.
| PJM
“I understand the visuals here, but I don’t think this is enough information to draw conclusions about individual transmission owners and their [Form] 715 criteria,” PJM’s Sue Glatz said.
I’d like to thank Energy Secretary Rick Perry for granting, albeit ungraciously, new FERC Chair Kevin McIntyre’s request for 30 days to clean up one of the biggest piles ever dumped on FERC’s doorstep. As The Economist said last week: “In the fierce competition for the federal government’s worst policy, this is a contender.”[1]
Perry’s letter came the same day coal magnate Bob Murray said two totally opposite things: One, he can sell all his coal to China no problem.[2] Two, “we must have” the Perry plan immediately.[3] Setting a new bar for cognitive dissonance.
Perry’s letter included a lot of saber rattling. Like maybe he’s going to do something before or even after FERC acts.
Perry’s Legal Authority is Slim to None, and Slim Left Town
The saber rattling is interesting because those pesky lawyers already told Perry that Federal Power Act Section 202(c) can’t support what he’d like to do on his lonesome to prove his fealty to Donald Trump and Trump acolytes like Murray.
Apparently, Perry is contemplating ignoring the lawyers after all, going ahead with destroying competitive markets and imposing a carbon tax on consumers.
Now you may be thinking: “Steve, the last thing the Trump administration would impose would be a carbon tax.”
But, Kemosabe, this is not a tax on carbon; this is a tax for carbon. A new kind of carbon tax — accelerating climate change.
Of note, FPA Section 202(c) has three prerequisites: (1) emergencies, (2) shortages and (3) temporary situations.[4]
So Perry would need to prevaricate about all three.
It would be the energy equivalent of the Holy Roman Empire, which, as Voltaire quipped, wasn’t holy, Roman or an empire.
FirstEnergy, the 2003 Blackout and the Davis-Besse Catastrophe
I have some space left and don’t want to neglect the co-cheerleader for the Trump-Perry tax: FirstEnergy, the utility primarily responsible for the 2003 Northeast Blackout.
Yes, the same FirstEnergy that used the words “resilience,” “resilient” and “resiliency” 2,031 times in its comments to FERC.
A prior column talked about how FirstEnergy’s Sammis coal plant isn’t baseload, nor retiring prematurely, no matter how many hundreds of times FirstEnergy abused the words “baseload” and “premature” in its FERC comments.
Today, let’s talk about FirstEnergy’s Davis-Besse nuclear plant. Another of the power plants that FirstEnergy wants bailed out yet again, after its plants first got billions in “stranded cost” payments and then got even more money to support FirstEnergy’s credit rating.
Did you know Davis-Besse was down during the 2003 blackout that FirstEnergy caused? Yes it was.
And it was down for two years. So much for nuclear plant resiliency — 90 days fuel supply and all that poppycock.
Why was it down? Boric acid corrosion had eaten a cavity completely through a 6.63-inch-thick carbon steel reactor pressure vessel (RPV) head down to a 3/16-inch inner liner of stainless steel cladding, which miraculously held until the cavity was finally discovered. Had that last 3/16 of an inch been eaten away or collapsed before detection and shutdown, it could have been really bad news.
Close up view of boric acid corrosion | NRC
The corrosion had occurred over a number of years. As the Nuclear Regulatory Commission stated: “The licensee allowed accumulations of boric acid to remain on the RPV head even though Procedure NG-EN-00324 directed their removal.”[5]
This became a poster child for nuclear negligence, and the basis for NRC fines of $5.5 million[6] and Securities and Exchange Commission fines of $28 million.[7]
Here’s where things get relevant for today. Repairs and replacement power cost hundreds of millions of dollars. How much of that was “capitalized,” i.e., added to Davis-Besse’s rate base upon which FirstEnergy now wants a return? I ballpark that at $100 million based on the increase in total plant costs between the end of 2001 and end of 2004, relative to the increase for the Perry nuclear plant that didn’t share the Davis-Besse experience.
This $100 million is the tip of the iceberg. More recently, FirstEnergy spent another $600 million on Davis-Besse.[8]
If that $600 million had turned out to be a good investment, FirstEnergy would have kept mum and kept the money. But it hasn’t turned out so good, so FirstEnergy wants customers to bail it out. Yet again.
Heads I win, tails you lose. Hugely.
Wrapping Up
Remember the Wisconsin utility executive who famously said the utility business is the only one where you can make more money from redecorating your office?[9] If the Trump-Perry tax happens, we’ll know a utility can make even more money from causing a near nuclear catastrophe, and making more bad investments after that.
