FERC has allowed MISO to waive its $1,000/MWh offer cap for the fourth straight winter, two months after the commission rejected the RTO’s plan to permanently double its hard offer cap.
The commission on Friday said it had “good cause” to allow resources with incremental energy costs above the current $1,000/MWh offer cap to recover costs from Dec. 1, 2017, through April 30, noting that “some resources could face the untenable position of being forced to offer electricity at levels below their actual cost” if MISO wintertime demand spikes occurred when gas supplies were pinched (ER18-300).
A truck responds in snowy conditions Jan. 2, 2018 | Entergy Louisiana
MISO announced it would seek the waiver in November, days after FERC rejected MISO’s Order 831 compliance filing, saying it wrongly prohibited resources from submitting cost-based offers above the required $2,000/MWh hard cap. (See MISO to Seek Waiver After FERC Rejects Offer Cap Plan.) The commission last week acknowledged that once MISO files an acceptable “long-term solution,” it will no longer need temporary waivers.
Linemen respond on Dec. 27, 2017 | Consumers Energy
FERC issued Order 831 in response to the unusually cold winter of 2013/14 that sent natural gas prices soaring and left generation owners complaining they could not recover fuel costs. MISO claims that offers above $1,000/MWh are a possibility when natural gas prices climb above $67/MMBtu.
In mid-December, the RTO asked FERC for clarification and rehearing of its offer cap filing, arguing that it should be permitted to exempt proxy offers of fast-start resources from the required offer caps because such offers are only used during emergency operating procedures. It contended that applying a raised offer cap to those resources is “inconsistent with previously adopted and articulated commission policies on price efficiency and reduction of uplift” (ER17-1570).
MISO’s markets have yet to experience an energy offer exceeding $1,000/MWh. However, in March 2014, generation resources offered approximately 900 MW at the $1,000/MWh offer cap in both the day-ahead and real-time markets, “indicating that the offer cap may have constrained those offers,” according to the RTO. Last week, the RTO’s Midwest and South regions were tested with temperatures about 20 to 25 degrees below normal, and it issued a cold-weather alert and conservative operations instructions that it kept in place for most of the week. (See Frigid Weather Tests Grid Operators.)
FERC has given a small Michigan hydropower company until March 1 to correct serious violations of federal safety regulations or once again face an order to shut down.
Boyce Hydro Power last month filed an emergency motion for a permanent stay of FERC’s November order that the 4.8-MW Edenville Dam in northern Michigan cease operation. On Friday, the commission denied the motion, citing Boyce’s “lengthy, extensive record of noncompliance” with safety and other regulations, but it did hand the company a March deadline, allowing flows to continue through the powerhouse in order to safely control reservoir levels in the face of heavy ice (10808-057).
FERC said the violations for the dam, located between Wixom Lake and the Tittabawassee River, include failing to increase spillway capacity to address the increased likelihood of more frequent flooding; performing unauthorized dam repairs and excavation; neglecting to file a public safety plan or follow its own water monitoring plan; failing to acquire all property rights; and failing to construct required recreation facilities near the dam. The commission said it has spent more than 13 years trying to get Boyce, which has owned the dam since 2004, to increase spillway capacity, the most serious of the safety violations. The company only began abiding by its water quality monitoring plan last July.
Edenville Dam spillway
The Office of Energy Projects’ Division of Dam Safety and Inspections “has determined that the failure of the project dam could result in the loss of human life and the destruction of property and infrastructure,” FERC warned. It has repeatedly asked Boyce to construct two auxiliary spillways to reduce the risk of flooding. In return, Boyce last month filed a proposed funding plan for spillway construction and new draft maintenance plans.
The commission was unimpressed: “Boyce has repeatedly failed to comply with requests by the regional engineer and other commission staff to develop and implement plans and schedules to address the fact that the project spillways are not adequate to pass the probable maximum flood, thereby creating a grave danger to the public. … The public interest in ensuring that the dam is safe outweighs the potential economic harm to Boyce. We take our duty to protect the public extremely seriously.”
A Milwaukee city official is questioning why We Energies ratepayers must pick up the $140 million tab to interconnect electronics manufacturer Foxconn’s proposed plant to the southeastern Wisconsin grid — and the city could attempt to block the plan in the state approval process.
Bauman at the Jan. 4 hearing | Milwaukee Common Council
Milwaukee Alderman Robert Bauman and other city legislators are asking why ratepayers should pay for the Taiwan-based company’s interconnection upgrades (137-CE-188) when it is the sole beneficiary. American Transmission Co. (ATC) has proposed constructing a 14-mile 345-kV transmission line, a new 345/138-kV substation and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the proposed $10 billion manufacturing plant. (See MISO Studying Tx. Upgrade for Massive Foxconn Factory in Wisc.)
“Is it reasonable for ratepayers to pick up a portion of the costs when they’ll see some economic benefit? Sure … [but] this is being built to serve one entity — a privately owned, for-profit foreign corporation. … It’s a basic fairness issue,” Bauman said in an interview with RTO Insider.
Bauman said not many customers are aware that the project will become part of We Energies’ rate base. “It’s very complicated, and it’s inside baseball,” Bauman said.
At a Jan. 4 Milwaukee Common Council hearing, Assistant City Attorney Tom Miller said Bauman’s criticism boils down to a question of: “Is the project proposed for the needs of the public or for a single customer?”
“Bingo,” Bauman replied.
If the project does not satisfy the reasonable needs of the public, Miller continued, the Wisconsin Public Service Commission could withhold project approval.
Alderman Michael Murphy said he has not yet seen a state plan to expand public transit in Milwaukee to grant the city’s unemployed access to some of the 13,000 promised jobs at the Foxconn plant, which will be located about 26 miles south of the city.
Murphy also said he supported Bauman’s arguments and a Milwaukee-led stand against We Energies customers paying for the upgrades.
“Admittedly, I think all of us know the PSC is really a stacked deck, but I still think we should make that legal argument based on the facts,” Murphy said.
Despite what appears to be a majority consensus in opposing the Foxconn project, the council has yet to decide whether to object to the cost allocation. Any objection would be made through a resolution, then passed to the city’s attorney, who could either intervene or lodge an objection to ATC’s request for certificate of public convenience and necessity at the PSC. ATC will file its application sometime in February; a PSC hearing on the project is not expected until June.
Costs for the Foxconn interconnection project will be passed from ATC to We Energies and then embedded in ratepayer bills. Milwaukee-based We Energies is a customer of ATC, which is not beholden to the ratemaking regulation of the PSC but is subject to PSC approval for facility construction.
‘Pennies’
ATC spokesperson Alissa Braatz contends that the typical residential customer across the company’s service area would pay “pennies each year over the projected lifespan of the line,” noting that transmission charges average less than 10% of monthly electric bills. She said the line and substation are meant to “help meet the growing electric demands of current electric users and accommodate the expected growth in businesses and homes in Racine County.”
“In regard to the comments made by Alderman Bauman, any party has the right to file an intervention with the Public Service Commission of Wisconsin, and ATC encourages public input on proposed projects,” Braatz told RTO Insider.
Braatz further pointed out that based on federal tariffs, it’s common for a transmission-only utility like ATC to charge all customers in a service area for transmission projects that “improve the reliability and efficiency of the grid.” By spreading the cost of the Foxconn project among all 5 million customers in ATC’s service area, the “impact is minimal,” she said.
The Streetcar Effect
In his arguments against ratepayers footing the bill for Foxconn’s project, Bauman is drawing parallels to Milwaukee’s new electric streetcar line, approved in 2015.
“In the political context of what’s happened here, I’m absolutely opposed to ratepayers bearing any cost,” Bauman said, referencing a two-year dispute over utility line relocation costs as part of the streetcar project. We Energies first estimated the cost to relocate utility lines at more than $50 million. The amount was later reduced to anywhere from $10 million to $25 million, and a judge in 2016 determined that the city — not We Energies — should fund the relocation. Bauman argues that We Energies essentially got “free infrastructure,” and that because the city must pay for its streetcars’ utility needs, Foxconn must finance its own utility needs associated with its manufacturing plant.
Foxconn manufacturing plant | Hon Hai-Foxconn
“There were these estimates grossly overstating this relocation,” Bauman said. He sees history repeating itself with ATC’s “pennies” promise. Similar promises were made on the streetcar project, he said.
However, at least one of Milwaukee’s 15 aldermen supports the Foxconn interconnection plan.
“There is absolutely no comparison between Foxconn and our streetcar,” Alderman Mark Borkowski said. “Ten years from now, whoever is still around, can see what the difference is. My money is on Foxconn.”
Alderman Nik Kovac replied that he’d be surprised if Foxconn’s Wisconsin plant was still open in a decade.
MISO Still Considering Expedited Request
Meanwhile, MISO still has yet to render a decision on ATC’s request to grant the Foxconn interconnection project expedited status, which would ensure approval several months ahead of the RTO’s 2018 Transmission Expansion Plan finalization in December.
On Friday, MISO spokesperson Mark Brown said the RTO has not reached any conclusions in studying the proposed project. The RTO will schedule a Technical Studies Task Force meeting in late January and set aside time at its February Planning Advisory Committee meeting to discuss granting the project an accelerated approval process.
Brian Lloyd is only the PUC’s second executive director and has held the position for slightly more than seven years. In a letter to staff, Lloyd said his departure would ensure a smooth transition to a new director and allow the commissioners “sufficient time to be deliberate in considering the applicants they will have for this position.”
“I have felt very strongly over the past several months that God has something else that he wants me to move onto, and while it is scary having absolutely no idea what that is, I’ve been comforted much over the holidays with reminders to place my trust there,” Lloyd wrote.
“The most difficult part of this decision is how much I enjoy working with all of you on issues critically important to Texas and the high degree of integrity and ethical standards that I believe is ingrained in our culture here,” he said.
Lloyd’s resignation creates two vacancies among the PUC’s senior leadership. Communication Director Terry Hadley retired from the commission just before the new year. Hadley had been with the PUC since Texas’ electric restructuring legislation was signed into law in 1999.
The PUC is also entering 2018 with a new chair (DeAnn Walker) and a new commissioner (Arthur D’Andrea), who replaced the commission’s longest-serving commissioners (Donna Nelson and Ken Anderson) last fall.
As executive director, Lloyd oversees the PUC’s day-to-day operations and management, including developing its strategic plan, directing staff analysis of contested proceedings and rulemakings, and developing and implementing the agency’s budget. Lloyd also coordinates the commission’s interaction with other state agencies and represents it at the Texas Legislature and other forums.
Lloyd has served in roles of increasing responsibility during his 19 years in electricity and telecommunications market design, restructuring and deregulation, as well as areas of electric reliability and assessing the impacts of federal environmental policy on competitive and regulated electricity markets. Before joining the PUC in September 2010, he was Gov. Rick Perry’s deputy director of budget, planning and policy.
Lloyd holds a bachelor’s degree in economics from Louisiana State University and a master’s degree in economics from the University of Texas at Austin.
California regulators will this week vote on a proposal to replace out-of-market contracts between CAISO and Calpine, saying the ISO failed to follow its established procurement process and possibly distorted its electricity markets.
The California Public Utilities Commission’s proposed Jan. 11 decision would replace the reliability-must-run contracts for Calpine’s Metcalf, Yuba City and Feather River power plants in Northern California with energy storage and fast-acting “preferred resources” by 2019. Pacific Gas and Electric would procure the resources, which must be eligible to come online before the RMR contracts are renewed for 2019, the proposed decision says.
The commission noted that the RMR contracts were developed outside of its resource adequacy (RA) process and that CAISO’s backstop Capacity Procurement Mechanism (CPM) was not initiated before awarding the contracts.
“Lack of competition … can lead to market distortions and unjust rates for power,” the CPUC said. “It is because of this concern that the commission is exercising its broad procurement authority with this resolution to authorize PG&E to conduct the solicitation for resources that can effectively fill local deficiencies and address issues identified.”
The CAISO Board of Governors in November reluctantly approved the Metcalf RMR agreement, which was developed in an expedited timeline. (See Board Decisions Highlight CAISO Market Problems.) The board approved the Yuba City and Feather River RMRs last March, drawing some stakeholder criticism because such out-of-market payments indicate the market might not be sending appropriate price signals. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Additionally, in a Dec. 22 market notice, CAISO said it had used its CPM backstop authority for PG&E’s 510-MW Moss Landing plant in the South Bay-Moss Landing sub area and for two units at San Diego Gas & Electric’s Encinas plant in Carlsbad.
The South Bay-Moss Landing Sub Area near Silicon Valley | CAISO
An RMR contract differs from a CPM designation in that it is involuntary for the generator, which receives a negotiated contract rate for a year. The voluntary CPM falls under a market-based price up to a cap and is riskier because the contracted megawatts can vary from month to month.
Calpine says RA capacity prices and CPM are not sufficient to sustain the plants, a claim that the CPUC has questioned. The company told CAISO in November 2016 that it planned to terminate generator interconnection agreements for the Feather River, Yuba City, King City and Wolfskill plants. In June, it told CAISO it was considering taking the 580-MW Metcalf off ISO dispatch.
In the case of Metcalf, Yuba City and Feather River, “Calpine did not enter into any bilateral RA contracts for 2018,” the CPUC said. “Instead, the company elected to communicate to the CAISO that it was planning to make these resources unavailable for CAISO dispatch unless it was awarded an RMR contract.” According to the CPUC, Calpine has said that RA capacity prices are not adequate, and that the CPM planning period does not allow sufficient time for maintenance, budget and other planning considerations.
Further complicating the situation is the fact that CAISO and Calpine are butting heads over the terms of the Metcalf, Yuba City and Feather River RMRs. CAISO and PG&E filed protests regarding the contract terms Calpine filed with FERC, which last month set the matter for settlement talks. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)
Having noted misalignments between its processes and the CPUC’s RA program, CAISO last October launched an initiative to collaborate with the CPUC to address possible reforms. In its 2017 policy catalog, the ISO said that a rapid transformation of the fleet to more variable energy resources “is exposing inadequacies in the current resource adequacy framework.”
“I always call this a tale of two RA programs,” Carrie Bentley of Resero Consulting — which frequently represents the Western Power Trading Forum in ISO matters — told RTO Insider. She noted that the CPM model has more risk than an RMR, and that the CPUC prefers market-based outcomes rather than RMRs.
Bentley noted that the growth of community choice aggregators (CCAs) has also compounded the problem because they procure resources on an incremental basis, rather than for the full output of a plant, which is not preferable for power plant owners. CCAs allow local governments to do their own electricity procurement and have been marketed heavily in the San Francisco Bay Area as clean energy alternatives to traditional utilities.
“I think it’s a huge issue,” Bentley said. “You can’t count on building a book that way if you are a power plant owner.”
The CPUC is expected to address the CCA issue at its Thursday meeting with a recently drafted decision that would make CCAs subject to RA requirements. The proposal would better align CPUC and CAISO resource planning, the commission said. (See California Proposes Resource Adequacy Obligations for CCAs.)
CCAs have grown rapidly in California since the launch of Marin Clean Energy in 2010. Over the five following years, two new CCAs were launched serving 135,000 customers. In 2016 and 2017, 12 communities either launched new CCAs or filed implementation plans, the CPUC said.
SPP’s market-to-market (M2M) process with MISO again resulted in a large payment to SPP for November operations. The SPP Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the payment.
Including November’s total of $3.9 million, the permanent flowgate has resulted in $15.3 million of M2M payments to the RTO from MISO, accounting for almost half of the $32.7 million SPP has or will receive since the M2M process began in March 2015.
The flowgate was binding for 296 hours in November after binding for 329 hours in October, when it racked up a $5.1 million charge to MISO. The flowgate is responsible for more M2M payments between the two RTOs than the next seven flowgates combined.
| SPP
RTO staff told the Seams Steering Committee on Jan. 3 that they are analyzing data to determine what kind of project would address the historical congestion in the area and whether it would be worth forgoing the M2M payments.
“We may be getting $5 million a month from MISO, but how is that impacting load in the area?” SPP’s Will Ragsdale said. “We want to understand the impact on the market as a whole, not just this one piece of data.”
Ragsdale promised to bring results of the analysis to the February meeting.
As was the case in October, loading because of high wind combined with nearby outages produced the constraint. The flowgate is in the Empire District Electric and Westar Energy control zones.
With no joint study scheduled this year, the SPP-MISO Interregional Planning Stakeholder Advisory Committee (IPSAC) will conduct an annual issues review with stakeholders Feb. 27 in Little Rock, Ark.
SPP Interregional Coordinator Adam Bell told the SSC that the IPSAC will review transmission issues identified by the RTOs or stakeholders, regional expansion plans and regional planning coordination. SPP and MISO have yet to agree on a single interregional project in two attempts.
Bell invited stakeholders to submit transmission issues and feedback on the RTOs’ joint planning by Jan. 29.
“It’s not limited to transmission issues,” Bell said. “We’ll listen to process improvements, lessons learned from joint studies and ideas on future planning.”
Under terms of the RTOs’ joint operating agreement, the IPSAC will meet every year that there is no joint study.
SPP staff will also meet with Associated Electric Cooperative Inc. in the first quarter to review the scope for a 2018 joint study.
SPP Sets New Winter Peak Demand Record
Last week’s frigid temperatures across the nation and in SPP’s footprint resulted in a new winter peak demand for the RTO of 41,014 MW on Jan. 2.
The RTO, with a 14-state footprint that stretches from East Texas to the Dakotas, issued a cold weather alert through Jan. 4. Some of the RTO’s gas units had difficulty procuring fuel and switched to more costly oil, but a spokesman said SPP had not “encountered anything unmanageable.”
Clean Line Energy Partners said Thursday that market realities led the company to sell its Oklahoma assets to NextEra Energy and put a temporary halt on its Plains & Eastern Clean Line project.
In the meantime, Clean Line founder and president Mike Skelly told RTO Insider, the company will focus on its four other long-haul HVDC projects.
“We’re adapting to the headwinds,” Skelly said. “You have to adapt.”
Clean Line announced in December that NextEra had purchased the assets of the Oklahoma portion of its $2.5 billion Plains & Eastern project, which was to deliver 3.5 GW of wind energy to Memphis, Tenn., and the Tennessee Valley Authority. (See Clean Line Sells Okla. Portion of Plains & Eastern to NextEra.)
The deal was sealed after it became apparent to Clean Line that TVA had little appetite to complete a six-year-old memorandum of understanding to purchase the project’s wind power. Late last year, just weeks after TVA said it was still studying whether to sign the contract, agency President Bill Johnson said the Clean Line project didn’t make economic sense, given TVA’s flat demand and ample generating capacity.
“We fund these projects with investor dollars, not ratepayer dollars,” Skelly said. “We were sort of hoping TVA would anchor this line by buying energy.”
Skelly said Clean Line began considering its options when it was approached by renewable energy powerhouse NextEra regarding its Oklahoma assets. The purchase includes Clean Line’s Oklahoma right of way.
“While getting that piece of the line built wasn’t everything we wanted to get done, it’s a significant thing,” Skelly said. “Now, the biggest renewables provider in the country owns this [400] miles of right of way. We believe that will enable them, or them working with others, to build a few gigawatts of wind. Our goal has always been to get more gigawatts on the grid, and that’s a positive outcome.”
Clean Line had intervened in Public Service Company of Oklahoma’s (PSO) $4.5 billion Wind Catcher project, which is currently before the Oklahoma Corporation Commission (Docket 17-267). Clean Line Executive Vice President Mario Hurtado called the Wind Catcher proposal “a good idea” in written testimony and suggested that PSO could take advantage of the easements his company has already secured.
“Schedule delays could jeopardize the size of the benefit to ratepayers from the production tax credit,” Hurtado said. “The Plains & Eastern project could substantially mitigate the cost and schedule risks for Wind Catcher.”
NextEra did not respond to a request for comment on its plans.
Plains & Eastern Clean Line Project Schematic | Clean Line Energy Partners
Clean Line has not entirely given up on Plains & Eastern, which has approval from the Tennessee Regulatory Authority and a “record of decision” from the U.S. Department of Energy to participate in its development under Section 1222 of the 2005 Energy Policy Act. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
Clean Line has held on to the project’s Arkansas right of way, although the company has encountered heavy opposition from lawmakers and landowners in the state. However, in the waning days of 2017, it also received a favorable ruling from a federal judge in a lawsuit that confirmed DOE’s participation in the project.
“We’ve been working on this thing for eight years,” Skelly said. “We’ve been working with and trying to convince the TVA and other Southeastern utilities of the merits of low-cost renewable energy. It’s been a long, slow process.”
Asked whether the decision to sell its Oklahoma assets was driven by a combination of TVA’s reluctance and the need for funding, Skelly said, “That’s not an unfair conclusion.”
“It’s more the market than the financing,” he said. “Our read of the market is that … it doesn’t appear [the Southeastern utilities] are going to do large renewable purchases in the short term. We would argue their customers want it, it’s cost effective, it’s technically feasible … we think there’s demand, but they don’t want to [meet it], and that’s their choice.”
Clean Line will now turn its attention to the proposed 780-mile Grain Belt Express, a $2.3 billion initiative that would deliver 4 GW of wind power from western Kansas through Missouri and Illinois to the Indiana border. The project is working its way through the appellate court process in Missouri, aided by former Gov. Jay Nixon. (See Unfazed by Obstacles, Clean Line’s Skelly Focuses on Future.)
“It’s been a somewhat protracted legal process, but we anticipate that will be sorted out second quarterish,” Skelly said.
Clean Line’s other three projects include:
The Rock Island Clean Line, a 500-mile project from northwest Iowa to Illinois, delivering 3.5 GW of wind energy. The project was originally expected to be operational in 2017. But on Sept. 21, the Illinois Supreme Court rejected the Rock Island application because Clean Line held only an option agreement on a parcel for a converter station — rather than a completed purchase agreement — when it applied to the Illinois Commerce Commission. The company said the ruling will cause “great delay” for the project.
The Centennial West Clean Line, a 900-mile project delivering 3.5 GW of renewable energy from New Mexico and Arizona to California. The company had expected construction to begin in 2017 and be operational in 2019. Development has slowed down while the company works on its other projects.
The Western Spirit Clean Line, a 140-mile project complementing the Centennial West project, delivering 1 GW of renewable power from east-central New Mexico to markets in the western U.S. Clean Line acquired the project, originally named Power Network New Mexico, in 2013. Construction, which will take about one year, could begin by the end of 2018.
SACRAMENTO, Calif. — Energy issues appeared to get the back burner on the opening day of the California State Legislature as allegations of sexual harassment and workplace retaliation dominated the beginning of the 2018 session.
State Senate President Pro Tempore Kevin de Leon (D) spent most of Wednesday’s session meeting with fellow Democrats about allegations against Sen. Tony Mendoza (D), who agreed to temporarily step down. An aide to Mendoza filed a complaint with the state saying that she was fired after telling Senate officials he sexually harassed another female subordinate, a claim that Mendoza denies, TheSacramento Bee reported this week.
Since the 2017 session, the State Capitol has become a point of focus in a national debate on sexual harassment after nearly 150 women signed a letter complaining of inappropriate behavior in an elected body dominated by Democrats and known for progressive policies. De Leon, a former roommate of Mendoza, is tackling the controversy as he launches a campaign for the U.S. Senate seat held by Dianne Feinstein, another possible distraction from the energy policies he has championed. Senate Democrats say that in January they will elect San Diego Democrat Toni Atkins as the body’s first female president pro tempore.
Committee chairman Chris Holden told RTO Insider on Wednesday to refer questions on the status of the bill to de Leon’s office, which did not respond to emails and phone calls regarding the status of the bill.
“It is his bill,” Holden said. “We are waiting for him to come back with some amendments to address the issues that opposition had raised.” Speaking of the opposition last year, Holden said, “It was intense.”
Peter Miller, Western energy project director for the Natural Resources Defense Council, told RTO Insider that he thinks there is a good chance the bill will pass this year.
“There is uncertainty inside the building as to when it might move and how much attention de Leon might be able to pay to it,” he said. But he added there is a “tremendous grassroots effort” and public campaign taking shape in 2018 and “a lot of pressure” to approve the legislation.
“There is broad support, and that is going to show up in offices around the Capitol,” he said.
The two CAISO regionalization bills Holden sponsored last year, AB726 and AB813, are currently in the Senate Rules Committee and would likely not be be taken up until May or June, according to an Assembly staff member.
“We are still formulating what that bill should look like,” Holden said of the legislation that would explore regionalization. “It is important, and it is something we will be responding to with clear language, but right now we are formulating the language.”
There are many issues around CAISO regionalization, and complicating the picture is an effort by CAISO to extend its day-ahead market to the Western Energy Imbalance Market (EIM). (See CAISO Bid for Western RTO to Face Competition in 2018.) But an RTO would be different, including other states in its leadership and creating worries among some lawmakers that California’s aggressive pursuit of renewable energy could be diluted by other states with different goals and resources.
In a day that included several ceremonies, upon convening on Wednesday, the Assembly read the names of the victims of the 2017 wildfires, which have led to investigations into possible role of California utilities in the disasters.
The three grid operators serving the East Coast have so far weathered the extended cold snap gripping the region and are preparing to confront another round of plummeting temperatures — along with surging energy demand.
NYISO on Thursday reported strong performance on the 10th straight day of intense cold, with Arctic temperatures forecast for Upstate into the weekend.
“We’ve had no forced outages of the high-voltage direct current transmission system,” Vice President of Operations Wes Yeomans told reporters during a teleconference Thursday afternoon.
“The transmission system between central and eastern New York is fully loaded, as expected, bringing the less expensive energy from the western parts of the state to the high demand zones in and around New York City,” Yeomans said. In addition, the ISO was reaching out to transmission owners in the southeastern part of the state, which was bearing the brunt of a blizzard. (See NYISO Reports Adequate Capacity for Winter.)
Gov. Andrew Cuomo on Jan. 4 declared a state of emergency for the city, Long Island and Westchester County as a strong storm system barreled up the Atlantic Coast. Meanwhile, Upstate saw lake-effect snow, which the National Weather Service expects will be followed by subzero temperatures. A wind chill advisory warned that temperatures could feel as low as -42 F.
| N WS
PSEG Long Island on Thursday reported that about 3,818 of its approximately 1.1 million customers across Long Island and the Rockaways were without service. As of 4:20 p.m., the utility had restored service to more than 76% of the more than 16,574 customers affected by the storm.
NYISO Executive Vice President Rich Dewey said during the press conference that Albany had endured six consecutive days during which the low temperature fell below zero and the average was 10 F. Such weather is not unusual, but extended periods of it are, and the next couple of days could be the coldest, he said.
“We’re already predicting that we’ll be a couple hundred megawatts above Friday’s projected peak demand of 24,340,” Dewey said. All six nuclear units in the state were online and the storms were keeping the 100 MW of nameplate wind running strong, he said.
Nearly 50% of the New York’s generating fleet is able to switch to oil, which helps grid reliability, Dewey said, adding that operational enhancements made after the 2013/14 cold snap include increased surveys of generators to ensure they have adequate fuel supplies.
| NYISO
Yeomans said the ISO had seen very few generator outages so far and “thankfully no issue yet of a lack of fuel or emission limitations.”
Different generators have different rules and permits with the state’s Department of Environmental Conservation, and “some of the more binding restrictions are 30-day averages, so a generator can be using many of their credits but then turn around and start building them again when the weather turns normal,” Yeomans said.
New England Issues Cold Alert
New England’s bulk power system was also operating reliably on Thursday, ISO-NE spokesman Matt Kakley said.
As a precautionary measure, the RTO on Wednesday issued a Master/Local Control Center No. 2 alert in light of the impending winter storm as well as the expected extreme cold after the storm. The alert requires generation and transmission owners to stop any routine maintenance, construction or test activities on their equipment.
| ISO-NE
ISO-NE also issued a Cold Weather Watch for Friday and Saturday as forecasts showed the return of extreme cold temperatures seen earlier in the week. The RTO issues a watch when extreme cold weather is in the forecast but it still expects a capacity margin of 1,000 MW or greater. (See New England Grid Prepared for Winter Reliability.) A slimmer capacity margin spurs a Cold Weather Warning, while a Cold Weather Event is called when a margin of less than or equal to 0 MW is forecast, warranting an emergency response.
| NWS
“Through this weekend, we expect to have sufficient capacity and fuel available to meet demand, barring unexpected outages,” Kakley said.
The cold weather continued to affect wholesale energy prices as well as the types of power plants being used to meet demand. High heating demand for natural gas causes pipeline constraints, resulting in high gas prices, which are driving the need for both oil- and coal-fired generation and boosting clearing prices. As a result, New England Internal Hub prices topped $300 on Thursday.
In general, a snowstorm doesn’t affect forecasted demand for power, unless there are local power outages caused by stormy conditions.
“In New England, we expect to have sufficient capacity and fuel available and expect to be able to weather the storm without running up against significant emissions limits, but concerns remain the same regarding fuel availability and emissions limits throughout this protracted cold spell and the rest of the winter,” Kakley said.
Snow and Ice in PJM
PJM issued a heavy load voltage schedule warning Thursday as a precautionary measure to help maximize power transfer capability and reactive reserve for the evening peak. Despite the warning, the RTO reported having maintained adequate power supplies and operating reserve margins during the cold weather. (See Frigid Weather Tests Grid Operators.)
The RTO reported no concerns with fuel availability and expected no reliability issues through the weekend. Extreme cold temperatures continued across its footprint Thursday, along with snow and ice in its eastern portion.
As of noon, PJM reported the preliminary peak demand for the cold snap as 136,125 MW set the morning of Jan. 3, which was projected to be the peak for the week.
PJM expects lower temperatures heading into the weekend and projects peak load will exceed 135,000 MW Friday morning.
Exelon and Public Service Enterprise Group will have to wait until the next session of the New Jersey Legislature for a vote on a bill to provide payments to the state’s nuclear fleet (S3560).
Several sources have confirmed that Rep. Vincent Prieto (D) declined to post the bill for a vote Thursday in one of his final acts as speaker of the Legislature’s lower house. The bill would provide upward of $300 million annually to operators of approved nuclear facilities for producing power.
PSEG has lobbied for the payments throughout the year, but the bill only materialized in December during Gov. Chris Christie’s lame duck session. Opponents — including business, consumer, environmental and power generation interests — feared it would be rushed through before Governor-elect Phil Murphy, a Democrat, takes office. (See NJ Nuclear Subsidy Bill Moves Swiftly out of Committee.)
PSEG has three nuclear reactors between the Salem and Hope Creek facilities, while Exelon owns 43% of the Salem units. PSEG says the units’ current profitability is attributable to sales hedges that expire within two years and that it will shut down the plants once they become unprofitable.
Opponents Cheer
Opponents cheered the news that the bill had stalled, calling it a victory for the state and praising Prieto, but keeping the door open for the issue to return later.
“Delaying action not only stands up to Chris Christie, it allows a new legislative session and a new governor to take the time necessary to carefully plan next steps and implement best practices if a bailout is needed,” Dale Bryk, chief planning officer at the Natural Resources Defense Council, said in an emailed statement. “It’s critical that any nuclear subsidies be done right so that New Jersey consumers, workers, communities and the environment are protected.”
“We applaud the Legislature for seeing through PSEG’s scare tactics and protecting our state’s future,” NJ Coalition for Fair Energy spokesman Matt Fossen said in an email. “The bottom line is that financial assistance should only be issued if it’s necessary, and the last few months proved that there was no reason to provide hundreds of millions of dollars to these already-profitable plants.”
The coalition, which includes Calpine, Dynegy, NRG Energy and the Electric Power Supply Association, on Wednesday released a sponsored economic study indicating the plants “have always been extremely profitable and will continue to be so through at least 2021 under current conditions.” The study foresees market rules changing and New Jersey returning to the Regional Greenhouse Gas Initiative “that will more than cover [the plants’] costs of production going forward” before the sales hedges roll off.
That study was performed by Energyzt, which last year produced a similar report showing that Dominion Energy’s Millstone nuclear plant in Connecticut would remain profitable into the next decade even without the state financial support being sought by the company. A Levitan & Associates study commissioned by Connecticut and released last month backed up that assessment. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)
The Return of the Bill
But the New Jersey bill is likely to return in the next legislative session, NJ Spotlight reported, with new incentives for renewable and clean energy programs designed to win over current opponents who would stand to benefit.
Proponents aren’t giving up the fight and argue the issue needs to be addressed sooner rather than later.
“The fate of New Jersey’s nuclear generation is an urgent concern,” PSEG spokesman Michael Jennings said. “PSEG will continue to educate New Jersey’s legislators and policymakers on the economic threat facing the nuclear plants that serve our state — and the risk of increased air pollution, reduced resiliency, lost jobs and higher energy bills. These risks warrant greater attention.”
