A “long-term systemic failure” of regulatory and industry practices caused the Oroville Dam crisis in February 2017, an independent forensics team said in a new report that recommends a reworking of broader dam safety practices across the country.
Oroville Dam on February 17, 2017 | California Department of Water Resources
There was no single cause or chain of events that provoked the failure of the dam’s spillway, which was completed in 1968, the report says. The California Department of Water Resources (CDWR) was forced to use the dam’s emergency spillway on Feb. 12 after the dam’s main spillway failed, requiring the evacuation of 188,000 residents near Oroville in Butte County, about 75 miles north of Sacramento.
“The incident was caused by a complex interaction of relatively common physical, human, organizational and industry factors, starting with the design of the project and continuing until the incident,” the report said.
FERC required CDWR to engage with a forensic team to study the incident, with members recommended by the Association of State Dam Safety Officials and the United States Society on Dams. The team studied design and construction records, inspections, maintenance reports, investigations and other records.
Physical factors contributing to the failure included inherent vulnerabilities in spillway designs and construction of the dam, and the poor condition of the foundation rock underneath some spillway locations. There has also been inadequate attention paid to spillways, the report said, because spillway incidents don’t usually lead to loss of life and spillway incidents have been under-reported. CDWR might have also become complacent because of a lack of previous failures outside of the state, but the department should have been aware of accidents in other states and countries, the report said.
The main spillway had problems right after construction, according to the report, including a large crack in the concrete chute slab, and high underdrain flows were observed. The cracking and underdrain flows were considered normal, but repairs were “ineffective and perhaps detrimental.”
Ultimate damage at the service spillway | California Department of Water Resources
“The seriousness of the weak as-constructed conditions and lack of repair durability was not recognized during numerous inspections and review processes over the almost 50-year history of the project,” the report said.
It faulted the dam safety culture and program within CDWR, overconfidence and complacency regarding the dam’s condition, inadequate usage of industry knowledge, and bureaucratic constraints on staffing and expertise. The report suggested CDWR was also under pressure from the State Water Contractors, a group of 29 California public agencies, to control costs.
Environmental groups had warned CDWR and FERC about the facility, requesting during its 2005 relicensing that the hillside below the spillway be paved, but those pleas were rejected.
The report said CDWR has been too dependent on regulators and the regulatory process, and more broadly, the report recommends a strong “top down” safety culture at dams, with one executive charged with condition awareness and new expert staffing. More frequent physical inspections are not always sufficient, and CDWR has been a “somewhat insular” organization, inhibiting technical expertise, it said.
The report also recommended periodic reviews of original designs, construction and performance — more in-depth than the current reviews mandated by FERC every five years. It noted that in regular inspections by CDWR, FERC and others, the spillway was observed only from the headgate structure where only the upper, flat portion of the spillway could be seen. Repairs conducted in 2009 and 2013 were seen as routine and were not submitted for regulatory approval.
Corroded and ruptured steel reinforcing bars at a slab crack | Independent Forensic Team Report by Association of State Dam Safety Officials
“The [independent forensics team] believes that both the California state and FERC dam safety regulations have been somewhat ambiguous regarding how comprehensive the five-year reviews were intended to be, which likely contributed to these reviews being overly relied upon but not sufficiently funded to serve as comprehensive reviews,” the report said.
It also said that prior to the incident, “the geology of the right abutment of the dam, including the hillside downstream of the emergency spillway crest structures, was fundamentally misunderstood by DWR, its consultants, [the California Division of Safety and Dams] and FERC.”
The 770-foot-high dam is part of the Oroville-Thermalito complex, which includes the Hyatt and Thermalito power plants totaling 933 MW, which had to be shut down during the incident, as well as power canals, afterbays and other facilities. The dam is part of the State Water Project, which provides water to 25 million people and 750,000 acres of irrigated farmland in California. It is the tallest in the U.S. and impounds one of California’s largest manmade lakes.
FERC has an open proceeding on the incident and in June ordered inspections of dam spillways to be completed by the end of 2017.
Grid operators turned to coal- and oil-fired generation last week as Arctic air sent temperatures plunging to record lows from the Great Plains to the Deep South.
The frigid temperatures caused a spike in demand for electricity, with ERCOT and SPP recording new winter demand peaks.
The most severe test of the grid since 2014, the cold blast came a week before FERC is set to respond to Energy Secretary Rick Perry’s call for price supports for struggling coal and nuclear plants in organized markets. Grid operators have managed to endure the cold weather and pinched fuel supplies, thanks in part to rule changes and winter preparations put in place after the cold snap of 2013/14.
The weather brought snow as far south as Florida and Texas, and a Nor’easter at the end of week caused blizzard conditions and coastal flooding from New Jersey to New England.
This VIIRS thermal infrared image, from the NOAA-20 polar-orbiting satellite on January 4, 2018, captured the cold clouds (blue and white) of the blizzard striking the eastern U.S. | NOAA
Temperatures were as low as minus 45 F, in Minnesota and North Dakota. The weather broke low-temperature records in several areas of the country. Wind chill records were also shattered. Mount Washington, N.H., recorded a temperature in the minus 30s, but with hurricane-force winds in place, wind chills were in the 80s and 90s below zero on Saturday morning. Wind chill warnings were in effect through Sunday morning in parts of the Northeast, with values expected as low as 45 degrees below zero.
On Thursday, natural gas prices at Transco Zone 6 New York hit a record $175/MMBtu, according to Natural Gas Intelligence, and averaged $140, up almost $92 from the day before. Prices at other trading hubs in New York and New England also exceeded $100 on Thursday, Bloomberg and NGI reported, with New England Internal Hub prices topping $300.
By contrast, gas futures have averaged less than $3 on the New York Mercantile Exchange this winter.
The New England grid was most challenged by the low temperatures. A combination of factors led ISO-NE to begin “posturing” generation units, in which the RTO staggers their operation in an effort to conserve fuel.
Nonetheless, the grid operated reliably throughout last week, according to spokesperson Marcia Blomberg.
From Friday to Sunday, ISO-NE sent out Cold Weather Watches, issued when extreme cold weather is in the forecast but the RTO still expects a capacity margin of 1,000 MW or greater.
By Monday, temperatures in the Mid-Atlantic and Northeast began to normalize and are expected to continue rising to above-average levels later this week. ISO-NE reported 1,381 MW of surplus capacity to meet Monday’s expected peak of 20,000 MW.
But the cold, and the high demand for heating, led to pipeline constraints and a spike in natural gas prices, forcing the RTO to rely on oil-fired and dual-fuel resources. Oil was providing one-third of ISO-NE’s electricity as of Saturday afternoon, with natural gas at 24%, nuclear 22% and coal at 5%. For all of 2016, by contrast, coal and oil generation together accounted for 3% of total energy production, with capacity factors of 15% for coal and 2% for oil. Gas-fired plants normally account for about half the region’s generation.
“During this extreme cold, some power plants have either tripped offline or had to reduce their output, while other oil-fired and dual-fuel generators are quickly depleting their fuel supply,” Blomberg said Sunday.
One of those plants was Entergy’s Pilgrim Nuclear Power Station in Plymouth, Mass. It went offline Thursday after one of its interconnections failed during the storm, but the outage did not affect reliability, ISO-NE said.
Some oil units were also nearing their emission limits Sunday, Blomberg said.
As a precautionary measure before the storm, the RTO on Wednesday issued a Master/Local Control Center No. 2 alert, which requires generation and transmission owners to stop any routine maintenance, construction or test activities on their equipment.
NYISO experienced similar conditions as ISO-NE: increased natural gas prices and a reliance on oil generation. But the ISO also said it did not have any reliability problems, and it did not experience concerns of fuel scarcity or emission limits.
“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 TOs in the southeastern part of the state, which was bearing the brunt of a blizzard.
NYISO’s marginal cost of energy spiked to $229.62/MWh last Tuesday, up from $15.87 on Dec. 24. The ISO’s real-time LMP zonal map showed power from Hydro-Québec priced at $226.87/MWh, compared with $15.41 a week earlier.
Gov. Andrew Cuomo on Thursday declared a state of emergency for the city, Long Island and Westchester County because of the storm. Meanwhile, Upstate saw lake-effect snow, followed by subzero temperatures. A wind chill advisory warned that temperatures could feel as low as minus 42 F.
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. By Monday, that figure had dropped to about 100.
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, he said.
Nearly 50% of 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. The storms also kept the 100 MW of nameplate wind running strong, he said.
PJM
PJM’s peak demand hit 138,465 MW at 7 p.m. Friday, the fourth-highest peak on record. The RTO said demand was about 2,500 MW above the forecast because temperatures and wind chill factors were lower than expected.
Demand had hit 136,206 MW Friday morning and 136,125 MW on Wednesday, the eighth- and 10th-highest, respectively.
Coal supplied 39% of PJM’s generation between Jan. 1 and 6, with a peak of 44% early Jan. 4. Nuclear provided 29%, with natural gas kicking in 21%, oil 5%, wind 3%, hydro 1% and other renewables 1%.
| PJM
During all of 2017, nuclear led with 36% of generation, with coal representing 32%, and natural gas and oil at 27% and 0.3%, respectively.
Real-time LMPs were consistently above $250/MWh during the week and briefly exceeded $750/MWh in some zones.
PJM said it had been preparing for cold weather since the fall, when the National Weather Service noted that a dip in the polar vortex, which caused an unseasonably mild August, would likely return during the winter. Chris Pilong, who manages PJM’s dispatch, said the long-range forecast called for a mild winter overall with periods of extreme cold.
The RTO started issuing cold-weather alerts prior to the holiday break to ensure generators and transmission operators were prepared for frigid conditions. Communication is central to PJM’s response, Pilong said.
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.
The RTO reported no concerns with fuel availability or reliability issues through the weekend.
ERCOT
ERCOT reported a new winter peak demand of 62.86 GW between 7 and 8 a.m. Wednesday, when freezing temperatures covered much of the state, exceeding last Tuesday’s evening peak of 61.95 GW. Both broke the previous winter mark of 59.65 GW, set a year ago on Jan. 6.
ERCOT had more than 70 GW of capacity available during the morning hours. The ISO in November projected a winter peak of slightly more than 61 GW and said it would have as much as 81 GW of total resource capacity on hand to meet demand.
Wholesale prices peaked at $70.02/MWh during the interval ending at 9:30 a.m. but were as low as $32.40 in the early morning hours. Last Tuesday’s prices peaked at $72.26 during the interval ending at 6 p.m.
ERCOT did not take any extreme measures in meeting the winter demand.
MISO
MISO on Monday said it navigated the extreme weather event without a single reliability issue. The RTO recorded a peak load of 104.7 GW during the week, set on Jan. 2.
“Lessons learned and applied since the polar vortex — including increased electric-gas coordination — improved MISO’s ability to respond to challenging situations,” spokesperson Mark Brown said.
The extended cold snap prompted MISO last Tuesday to issue a conservative operations order until Jan. 5. A cold-weather alert remained in place until Sunday “due to very cold temperatures, high system load and uncertainties in gas pipeline fuel supplies.”
MISO’s all-time winter peak demand was 109.3 GW on Jan. 6, 2014.
Last Tuesday, coal generation made up a 48% share of MISO’s fuel mix, with natural gas supplying 22% and nuclear and wind generation contributing about 14% each. The RTO’s mix is typically 34% coal, 41% gas, 8% nuclear and 14% renewables.
SPP
SPP on Monday reported a new winter peak demand record of 41,014 MW, set the morning of Jan. 2. The previous record was 40,322 MW.
The RTO issued a cold-weather alert for Dec. 29 to Jan. 4. Spokesman Dustin Smith said member companies were experiencing “slower-than-normal” start times and other temperature-related start-up issues at some units.
While the cold temperatures had some impact, SPP has not “encountered anything unmanageable,” Smith said. Some gas units have been unable to procure fuel, resulting in outages and switches to more costly oil.
Michael Kuser, Rory D. Sweeney, Amanda Durish Cook, Tom Kleckner, Rich Heidorn Jr. and Michael Brooks contributed to this report.
Although electric utilities will see their tax rate fall from 35% to 21% under the Tax Cut and Jobs Act signed by President Trump last month, few are making plans to spend their savings.
State officials across the country are calling for utilities to pass the savings to their ratepayers, and some utilities already have said they will.
The Organization of PJM States Inc. (OPSI) said in a letter to FERC that it has “unanimously and continuously advanced the need to ensure cost containment in transmission rates, which should directly benefit ratepayers.”
“The large reduction in the corporate tax rate effective Jan. 1, 2018, provides an opportunity to reduce rates to customers,” OPSI said in its letter. “While the commission examines whether the tax changes will impact FERC accounting forms/procedures and how these changes might affect transmission formula rates in PJM, OPSI unanimously supports all efforts by the commission to flow this cost reduction back to consumers.”
Of the 14 utility regulatory commissions in OPSI, at least three (Kentucky, Michigan and West Virginia) have started proceedings related to the tax bill, and at least one other (Indiana) is evaluating how the bill will affect utilities.
In Delaware, more than two dozen General Assembly members have sent the Public Service Commission a letter saying it should grant “in its entirety” a petition filed by the Division of the Public Advocate that utilities should pass their tax savings on to ratepayers.
Regulatory bodies have opened proceedings or taken other actions related to the tax bill in at least eight states outside PJM — Connecticut, Louisiana, Michigan, Minnesota, Missouri, Montana, Oklahoma and South Dakota.
In Oklahoma, the Corporation Commission’s administrative law judges have recommended that utilities pass the savings along to their customers. South Dakota’s Public Utility Commission has determined that investor-owned power and natural gas utilities should share the savings from the tax bill with customers.
Regulators have opened proceedings in Connecticut and Missouri, while the Louisiana Public Service Commission is reviewing utilities’ rates to see if they can be cut in light of the bill. The Michigan Public Service Commission ordered utilities to study the tax cuts’ impact and how they will pass the savings along to consumers. The Minnesota Public Utilities Commission plans to analyze how the law affects utilities and said it could undertake proceedings based on its findings. And the Montana Public Service Commission ordered utilities to calculate the change in their tax liabilities and come up with proposals for applying their savings.
In at least two other states, elected officials have called on regulators to take action.
Massachusetts Attorney General Maura Healey asked the Department of Public Utilities to recalculate rate increases it had granted Eversource | Massachusetts Attorney General’s Office
Massachusetts Attorney General Maura Healey asked the Department of Public Utilities to recalculate rate increases it had granted Eversource Energy in November. The company responded by saying it would pass on almost $56 million in savings from the tax bill to its 1.4 million customers in the state. That inspired Rhode Island Lt. Gov. Dan McKee to send his state’s Public Utilities Commission a letter saying National Grid should use its savings to lower its rates.
Rhode Island Lt. Gov. Dan McKee sent the Public Utilities Commission a letter saying National Grid should use its savings from the tax bill to lower rates | Rhode Island Lt. Governor’s Office
In New Hampshire, Consumer Advocate Maurice Kreis filed a complaint with the Public Utilities Commission to make sure the savings that the state’s 13 IOUs realize from the tax bill flow back to their customers.
In some states, utilities are taking it upon themselves to proclaim they’ll pass their savings from the tax bill on to ratepayers. The Edison Electric Institute called the tax bill “a huge win for customers as the drop in the corporate rate is mostly flowed back to them over time in rates.”
In Maryland, Exelon’s Baltimore Gas and Electric, Pepco and Delmarva Power subsidiaries said they intended to file requests with the Public Service Commission to cut their rates.
In Illinois, Commonwealth Edison, also an Exelon subsidiary, asked the Commerce Commission for approval to pass along approximately $200 million in tax savings to its customers this year.
In Utah, Rocky Mountain Power said it will pass the benefits of the tax bill on to customers, though it wouldn’t commit to doing so by cutting rates.
And in Oregon, the Public Utility Commission said four electric and gas utilities had applied with it to track the tax bill’s impacts so they could be accounted for in ratemaking, and two other utilities are expected to join.
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.
