The new year’s frigid temperatures resulted in a new winter peak demand for ERCOT Wednesday morning.
The ISO recorded a preliminary peak of 62.86 GW between 7 and 8 a.m., when freezing temperatures covered much of the state, exceeding Tuesday’s evening peak of 61.95 GW. Both broke the previous winter mark of 59.65 GW, set almost a year ago on Jan. 6, 2017.
South Texas snow | Goliad Farms
ERCOT had more than 70 GW of capacity available during the morning hours. The ISO in November projected a winter peak of just over 61 GW and said it would have as much as 81 GW of total resource capacity on hand to meet demand.
South Texas snowstorm | National Weather Service
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. Tuesday’s prices peaked at $72.26 during the interval ending at 6 p.m.
ERCOT has not taken any extreme measures in meeting the winter demand.
Frigid conditions on the East Coast also brought PJM a peak load of 136.13 GW, the RTO’s highest winter demand since 2015. After a slight warming trend PJM, expects the extreme cold to return again later this week and has issued cold weather alerts for Friday and Saturday.
Lubbock Power & Light filed testimony with the Public Utility Commission of Texas in support of its proposal to move about 430 MW of load from SPP into ERCOT.
LP&L power plant | LP&L
The move would make LP&L the first to join ERCOT’s deregulated competitive market since it was created in 2002.
The PUC has scheduled a hearing on LP&L’s migration Jan. 17-18 in Austin.
Meeting Tuesday’s deadline, LP&L filed testimony from former FERC and PUC Chair Pat Wood III, Lubbock Mayor Dan Pope, LP&L Director of Electric Utilities David McCalla and three industry experts.
Wood, who was integral in helping create the ERCOT market and now runs his own energy infrastructure development business, said he felt compelled to speak out on the ISO’s benefits for LP&L’s customers. He said he was concerned “that the focus on selected details of this proposal is obscuring its significance.”
“We have in this proceeding the state’s third largest municipal utility requesting to move three-fourths of its load to ERCOT, and further, evidencing its intent to open its retail franchise to competition — something no other municipal utility has yet elected to do,” Wood said.
Pope said he is frequently asked by Lubbock citizens “to bring back competition for retail electric service.”
“Personally, I believe in the principles of competition, and there is no question in my mind that the citizens of Lubbock desire to be given the right to freely shop the Texas retail electric market for a provider,” Pope said.
The Lubbock City Council is expected to vote Jan. 11 on whether to conduct a study analyzing the effect of opening the retail market.
In his testimony, McCalla said giving customers a choice of retail providers was not a part of LP&L’s original proposal.
| LP&L
“Customer choice is about more than simply economics,” he said. “It is about allowing customers to decide what percentage of renewable energy they purchase, to choose whether they want long- or short-term service, and to select from many other features and options that are available from a multitude of different retail electric providers.”
In September, LP&L filed its intention to integrate 430 MW of load with ERCOT by June 2021. That load is currently served through a wholesale contract with SPP member Southwestern Public Service; the contract expires May 31, 2021. ERCOT, SPP and LP&L have all filed studies in the case (Docket 47576), which began in 2015 when the municipality announced it intended to move 430 MW of its approximately 600 MW of load into ERCOT. LP&L is hoping for a decision before March, which will enable it to maintain its plan to integrate with ERCOT by June 2021, after extending a power purchase agreement with SPS. (See “LP&L Study: Production Costs Increase,” ERCOT BoD Briefs: June 13, 2017.)
New York Gov. Andrew Cuomo on Wednesday made clear that clean energy and the jobs it can create will continue to be a key part of his vision for the state’s future.
Governor Andrew Cuomo giving his State of the State speech | NY DPS
In his annual State of the State address, Cuomo called for the approximately $200 billion New York State Common Retirement Fund to “end any investment in fossil fuel-related activities,” saying “the future of the environment, the future of the economy and the future of our children is all in clean technology, and we should put our money where our mouth is.”
“Last year we announced one of the largest offshore wind projects in the nation,” Cuomo said. “This year I’m proud to announce we will be putting out at least two [requests for proposals] for at least 800 MW in offshore wind power, enough wind power to power 400,000 New York state households with clean energy. That’s a great and clean step forward.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, said the “announced commitment to a procurement in 2018 is a great step forward for growing this industry in New York. … A 2018 solicitation makes this real for New York.”
In his address last January, Cuomo set an offshore wind target of 2,400 MW by 2030. State policymakers are embracing offshore wind for both its utility-scale generation and its ability to be developed close to the major load centers of New York City and Long Island — as well as for its potential jobs. (See New York Seeks to Lead US in Offshore Wind.)
Statoil Wind Lease Area | Statoil
Norway-based Statoil in December 2016 bought the first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens large enough to generate up to 1 GW of power. Statoil dubbed the project Empire Wind and is working to sign a power purchase agreement with a U.S. utility.
South Fork Wind Farm | Deepwater Wind
Long Island could see the first offshore wind project in the state with the 90-MW South Fork Project off Montauk, which was approved by the Long Island Power Authority a year ago. Developer Deepwater Wind says construction could start as early as 2019, and the wind farm could become operational as early as 2022.
Easier Storage
The governor’s office on Tuesday released Cuomo’s clean energy jobs and climate agenda, which includes cutting emissions from high-polluting peaking plants and directing the NY Green Bank to invest $200 million toward meeting an energy storage target of 1,500 MW by 2025. Cuomo’s Reforming the Energy Vision policy includes a Clean Energy Standard mandate to generate 50% of the state’s electricity from renewable sources by 2030.
In November, Cuomo signed legislation requiring the Public Service Commission to establish targets for energy storage by early 2018. Cuomo is now also directing the New York State Energy Research and Development Authority to invest at least $60 million in storage demonstration projects and efforts to reduce barriers to deploying energy storage, including permitting, customer acquisition, interconnection and financing costs. (See NYISO Readies Market for Energy Storage, State Targets.)
A NYISO report in December laid out a three-phase plan for opening its wholesale markets to storage through integration, optimization and aggregation with other distributed energy resources. The ISO distinguishes between storage in front of the meter and behind the meter, with the former more likely to participate in wholesale market transactions, although BTM storage could become a wholesale player when aggregated with other distributed resources. (See New York Sees Storage in Retail and Wholesale Markets.)
In his speech, Cuomo also announced a zero-cost solar program for 10,000 low-income New Yorkers and directed the establishment of a state energy efficiency target by April 22 (Earth Day).
New York State of the State speech audience | NY DPS
He also said New York will reconvene a scientific advisory committee on climate change that was disbanded last year by the Trump administration, and also adopt regulations to close all coal-fired power plants within the state. As cochair of the U.S. Climate Alliance and in collaboration with partners, Cuomo said he will reconvene the advisory committee to “continue its critical work without political interference and provide the guidance needed to adapt to a changing climate.”
Clean Jobs, Clean Air
NYSERDA also plans to invest $15 million in clean energy job development and infrastructure advancement to train workers for offshore wind construction, installation, operation, maintenance, design and associated infrastructure. Cuomo is directing NYSERDA to work with Empire State Development and other state agencies to promote development of offshore wind port infrastructure to jumpstart development.
New York is one of the nine Regional Greenhouse Gas Initiative states that set out in 2013 to cut power plant emissions 50% by 2020. Last August, other RGGI states agreed to answer Cuomo’s call to lower the emissions cap by an additional 30% by 2030.
Cuomo will direct the state’s Department of Environmental Conservation to regulate beyond RGGI requirements in order to cover power plants under 25 MW, many of which are smaller but highly polluting peaker units that operate intermittently during periods of high electricity demand. The department will also adopt regulations banning coal-fired generation in the state’s power plants by 2020.
Heather Leibowitz, director of Environment New York, said, “The message in today’s State of the State was clear: By reducing pollution and shifting to clean energy, we can grow our economy while leaving a healthier, safer planet for our children.”
Dominion Energy on Wednesday said it will buy SCANA for $7.9 billion in a stock-for-stock transaction, securing a utility troubled by a botched nuclear project.
SCANA, which owns South Carolina Electric & Gas, has been under financial pressure since it scrapped the two-reactor expansion of its V.C. Summer nuclear plant last July after spending about $9 billion on the effort. The nearly decade-long project fell victim to design flaws, cost overruns, construction delays and the bankruptcy of lead contractor Westinghouse Electric.
Dominion’s $7.9 billion acquisition will include an additional $6.7 billion in assumed debt, valuing the sale at about $14.6 billion. The Virginia-based utility is offering reduced rates to SCE&G customers and a partial refund of the incomplete expansion at the Summer plant.
SCANA shareholders will receive slightly more than two-thirds of a Dominion share for each share they own, valuing the stock at about $55.35. SCANA shares lost almost half their value over the past year, falling to under $40/share early this week. Hours after the deal was announced, SCANA shares rallied from $39 to $48, while Dominion fell from $80 to $77.
Dominion Goes South
The resulting company would operate in 18 states, serving about 6.5 million regulated customers. The companies said the sale would be a strategic union that would help Dominion solidify a presence in expanding Southeast markets.
“SCANA is a natural fit for Dominion Energy,” Dominion CEO Thomas Farrell II said. “Our current operations in the Carolinas — the Dominion Energy Carolina Gas Transmission, Dominion Energy North Carolina and the Atlantic Coast Pipeline — complement SCANA’s … operations. This combination can open new expansion opportunities as we seek to meet the energy needs of people and industry in the Southeast.”
SCANA has about 1.6 million electric and natural gas residential and business accounts in the Carolinas. Dominion currently operates two solar farms in South Carolina and a 1,500-mile network of gas pipelines purchased from SCANA two years ago for $497 million.
SCANA would become a Dominion subsidiary, with Dominion pledging to maintain the utility’s South Carolina headquarters and protect SCANA’s 5,000-plus existing jobs until 2020. Dominion has also promised to take up SCANA’s plans to complete the purchase of the $180 million, 540-MW Columbia Energy Center natural gas-fired plant in Gaston, S.C., to fill energy needs expected to be met by an expanded V.C. Summer.
V.C. Summer project | South Carolina Electric & Gas Co.
“Joining with Dominion Energy strengthens our company and provides resources that will enable us to once again focus on our core operations and best serve our customers,” said SCANA CEO Jimmy Addison, who until Monday was SCANA’s chief financial officer. He replaced former CEO Kevin Marsh, who retired in the face of federal and state scrutiny of the failed V.C. Summer project.
In response to concerns about the nuclear project, Dominion is offering $1.3 billion in refunds to SCANA customers, amounting to about $1,000 each. Dominion also claims the sale will cut the time that customers will be on the hook for paying for the unfinished reactors from 60 years to 20 years. The company has also promised to reduce rates for SCE&G customers by about 5%, or $7/month.
Customers are currently paying about $27/month — or 18% of their monthly bills — to finance the unfinished reactors.
Dominion is proposing to cut refund checks to customers based on 2017 electricity usage within 90 days of the finalized sale. Farrell said the move will “guarantee a rapidly declining impact from the V.C. Summer project” and called the proposed refunds as the “largest utility customer cash refund in history.”
However, consumer advocates are contending that at least some of the proposed 5% rate reduction is already guaranteed to customers to reflect company gains from the corporate tax cuts recently passed by the U.S. Congress. Last week, the South Carolina Office of Regulatory Staff requested that state utilities draw up plans to share their tax savings with customers.
Sale Requires Continuation of Base Load Review Act
Another possible sticking point: Some South Carolina lawmakers claim the proposed deal is meant to compel South Carolina lawmakers to preserve the controversial Base Load Review Act, the 2007 law that allows SCE&G to continue to pass onto customers the costs of nuclear reactors that will never produce a kilowatt of power. The deal presumes that SCANA customers will continue to pay the reduced rate under the law for 20 years.
Meanwhile, federal and state investigators are reviewing whether the law’s provision to charge customers for abandoned generation projects is reasonable, and South Carolina lawmakers next week will begin deliberating legislation that could halt customer collection altogether on the scuttled project (S 0754).
Last month, SCE&G formally asked the Nuclear Regulatory Commission for permission to withdraw its operating license for the reactors, a move intended to show the company has entirely given up on the project and is eligible for a $2 billion tax write-off.
The South Carolina Public Service Commission last week denied SCE&G’s request to dismiss two proceedings related to the failed attempt to expand V.C. Summer. One case sought to eliminate charges that the SCANA subsidiary’s customers are paying for the failed project, while the other sought refunds for what customers have already paid. The PSC has said it will hold a hearing this year to determine the merits of eliminating the charges and granting refunds.
Governor Reacts
South Carolina Gov. Henry McMaster, who has supported complete customer refunds of the nuclear project costs, said the proposed transaction represented “progress” but that there was “more work to be done,” namely selling off state-owned electric and water utility Santee Cooper, SCANA’s project partner in the unfinished reactors.
“Under the proposed agreement between SCANA and Dominion Energy, SCE&G ratepayers will get most of the money back they paid for the nuclear reactors and will no longer face paying billions for this nuclear collapse. But this doesn’t resolve the issue,” McMaster said in a statement. “Over 700,000 electric cooperative customers face the prospect of having their power bills sky rocket for decades to pay off Santee Cooper’s $4 billion in debt from this. The only way to resolve this travesty is to sell Santee Cooper.”
Dominion and SCANA expect the deal to close this year, although the companies still require approval from several agencies, including FERC, NRC, the Federal Trade Commission, the Department of Justice and South Carolina, North Carolina and Georgia regulators.
The companies have set up a special website explaining the acquisition to SCANA customers at dominionenergysouth.com.
NYISO on Tuesday asked FERC to deny Entergy’s request that the commission clarify the deadline for the ISO to complete a final market power review for the deactivation of the Indian Point nuclear plant (ER16-120, EL15-37).
At issue is the commission’s acceptance in November of NYISO’s revisions to its reliability-must-run program, adding a 365-day notice period for a generator to notify the ISO that it plans to retire. (See FERC Approves NYISO Reliability-Must-Run Plan.)
Indian Point Nuclear Plant | Entergy
In a Dec. 18 filing with FERC, Entergy noted that NYISO failed to include a 120-day market power review deadline that was in an earlier filing. The company contended that without a clear deadline for review, its 2,311-MW Indian Point plant lacked certainty about authorization to exit the market. (See Entergy Asks FERC to Clarify Indian Point Retirement Process.) The company is seeking a March 13 deadline for NYISO to complete a market power study for the closure. Units 2 and 3 at the plant are slated to close in 2020 and 2021, respectively.
In its Jan. 2 response, NYISO said that requiring it “to complete physical withholding analyses years in advance of generator deactivation would clearly be unreasonable and unjustified on equitable or policy grounds.” The ISO argued that market conditions could change “dramatically” over a two- or three-year period, “as could a generator owner’s business plans as well as the plans of other generators.”
Indian Point Nuclear Plant Control Room | Entergy
NYISO also contended that its previous references to completing market power studies within 120 days only applied to generating units closing within one year of providing notice.
“This focus on generators deactivating in 365 days, and the NYISO’s rationale for proposing this time frame as the minimum notice period, is made abundantly clear in all of the NYISO’s stakeholder presentations and all of its filings in this proceeding,” the ISO said.
The Independent Power Producers of New York also on Tuesday filed in support of Entergy’s request for clarification. IPPNY argued that without a clear deadline for the final market power assessment, “a generator owner will have difficulty planning when its generator will be able to deactivate. … NYISO’s completion of the final market power assessment may effectively operate as a bar on a generator’s deactivation, which is entirely contrary to [FERC’s] goal that generator owners know with certainty when they can deactivate their resources.”
An ISO report in December 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 be enough to maintain reliability after Indian Point shuts down completely. (See New Builds to Cover Indian Point Closure, NYISO Finds.)
By Michael Kuser, Rory Sweeney, Amanda Durish Cook and Tom Kleckner
Power prices surged along with demand across much of the U.S. on Tuesday as a blast of Arctic air sent temperatures plunging to record lows in an area extending from the Great Plains to the Deep South.
| The Weather Channel
ISO-NE Internal Hub real-time prices pushed past $170/MWh during the RTO’s evening peak load, occurring around 6 p.m. At about the same time, PJM’s RTO zone price hit $160/MWh, while the Eastern and New Jersey hubs broke $200/MWh. ERCOT said it might break its record for winter demand on Wednesday.
So far, the 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.
Northeast Fuel Switch
The New England grid was operating normally Tuesday despite an unusually high level of oil-fired generation due to a spike in natural gas prices, according to ISO-NE spokesperson Marcia Blomberg. Gas-fired plants normally account for about half the region’s generation but on Tuesday comprised only 25% of the fuel mix.
| ISO-NE
With the cold weather forecast to stretch into next week, the RTO expects to continue relying heavily on oil-fired generators, some of which are operating around the clock and are already running short on fuel. In addition, some of the plants are reaching air emissions limitations, Blomberg said.
Each of the six states comprising New England sets its own emissions standards. Massachusetts, for example, set 2018 CO2 emissions limits from power plants at 7.45 million metric tons for existing facilities and 1.5 million metric tons for new ones.
Nuclear power, coal, LNG and dual-fuel units running on oil are also helping the grid endure the squeeze on natural gas pipelines.
“ISO-NE will increase the frequency of generator fuel surveys and continue its close communication with oil-fired power plants, natural gas pipeline operators and neighboring power systems,” Blomberg said.
NYISO
The deep freeze in New York caused the ISO’s marginal cost of energy to spike to $229.62/MWh on Tuesday, up from $15.87/MWh on Dec. 24. NYISO’s real-time LMP zonal map showed power from Hydro-Québec priced at $226.87/MWh, compared with $15.41/MWh a week earlier, while ISO-NE shot up to $278.14/MWh from $36.56/MWh.
| NYISO
NYISO had sufficient generation capacity and reserves to meet Tuesday’s projected peak demand of 24.5 GW, said ISO spokesman David Flanagan. Rising demand pushed natural gas prices higher, resulting in increased wholesale electricity prices and leading some dual-fuel units in New York to switch to oil, he said.
| NYISO
PJM Prep Pays Off
PJM said it has been preparing for cold weather since the fall when the National Weather Service in the fall noted 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.
Tuesday’s expected peak demand of 134.31 GW remained outside of PJM’s top 10 winter daily peaks, he said, but was “getting close” to the 10th-place peak of 135.06 GW on Jan. 22, 2014. Wednesday’s peak is expected to be 130.53 GW.
“We’re seeing temperatures starting to moderate a little bit,” Pilong said.
Four of the 10 highest winter peaks — including the all-time record of 143.13 GW — occurred in 2015. The remaining six are from 2014, when a similar dip in the polar vortex caused even colder temperatures, resulting in supply issues when 22% of the RTO’s generation capacity failed to respond to dispatch signals.
Pilong said changes implemented since then, including Capacity Performance and fuel-switching procedures, have been effective.
“We’re seeing from a generator performance perspective outage rates are cut in half,” he said.
Gas-fired generation made up about 25% of PJM’s fuel mix Tuesday, down from about one-third during normal operations. Pilong attributed the decline to fuel switching. At one point, more than 8,000 MW of oil-fired generation was online, almost all of which represented gas units that had been switched.
The RTO’s LMP hovered around $175/MWh near its peak. Pilong attributed the jump to “competition for natural gas.”
“It really just has to do with fuel prices,” he said.
MISO Exceeds Winter Peak Outlook
The extended cold snap prompted MISO on Tuesday to issue a conservative operations order until Jan. 5. A cold-weather alert will remain in place until Sunday “due to very cold temperatures, high system load and uncertainties in gas pipeline fuel supplies.” An unofficial Tuesday peak load of 104.6 GW exceeded the RTO’s winter forecast by 1.2 GW.
“As we have throughout the past several days, MISO continues to work closely with members and neighboring system operators to prepare and take appropriate steps to protect the bulk electric system,” spokesperson Mark Brown said.
MISO’s all-time winter peak demand was 109.3 GW on Jan. 6, 2014.
During a winter readiness workshop in November, MISO predicted a 103.4-GW winter peak would be handled easily by 142 GW of projected capacity. The forecast relied on National Oceanic and Atmospheric Administration projections, which predicted a warmer-than-normal winter in the Central and South regions and normal to below-normal temperatures in the North region. (See MISO in ‘Good Shape’ for Winter Operations.)
“As part of lessons learned from the polar vortex, MISO increased communications and coordination with gas pipeline operators. MISO has a complete database of pipeline connections and dual-fuel capability for all gas generators,” Brown said.
On Tuesday, coal generation comprised 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, ERCOT Manage Response
SPP, whose 14-state footprint reaches from East Texas to the Dakotas, issued a cold-weather alert for Dec. 29 to Jan. 4. RTO spokesman Dustin Smith said member companies are experiencing “slower-than-normal” start times and other temperature-related start-up issues at some units.
While the cold temperatures have had some impact, SPP has not “encountered anything unmanageable,” Smith said.
Some SPP gas units have been unable to procure fuel, resulting in outages and switches to more costly oil, Smith said.
The cold weather has reached as far south as the Texas Gulf Coast. Houston is expecting a freeze Wednesday morning and has seen temperatures in the 20s since New Year’s Eve.
ERCOT, the grid operator for 90% of Texas, said it has managed the winter weather so far and has sufficient generation and transmission resources available to keep up with the frigid forecasts. Demand Tuesday peaked at slightly more than 59 GW between 11 a.m. and 12 p.m. and is expected to approach 62 GW Wednesday morning, which would break the winter record of 59.65 GW set in January 2017.
The ISO issued a notice before the cold snap asking generators to take necessary steps to prepare their facilities for the expected cold weather by reviewing fuel supplies and planned outages, said ERCOT spokesperson Leslie Sopko.
“We also worked with transmission operators to minimize outages that impact generation,” Sopko said.
TVA Asks Customers to Conserve
Early Tuesday morning, the Tennessee Valley Authority reported an average temperature of 10 F across its footprint, about 20 degrees lower than average. The government agency reported that the frigid temperatures pushed power demand to 32 GW on Jan. 2, TVA’s highest level since 2015.
“Power demands are high. Help us maintain a reliable supply of energy ― and help yourself save money on your next power bill ― by lowering your thermostat 1-2 degrees during the peak hours of 6 am to 9 am,” TVA tweeted.
Testing the Limits of Fuel Switching
While fuel switching has helped grid operators in the short run, the possibility of exceeding oil supplies and air emissions limits is a particular concern in New England.
“They’re burning a lot of oil out there,” Northeast Gas Association CEO Thomas M. Kiley told RTO Insider.
The gas association’s market outlook for this winter predicted such a scenario.
“The rising demand for natural gas within the region’s electric market has not been sufficiently matched by a commitment to securing adequate reliable natural gas supplies and firm pipeline capacity contractual obligations,” the report said. “The electric power sector has not participated sufficiently in terms of investments in securing natural gas supplies for their generating units.”
Kiley said nothing has changed since the group issued that report in October, but the grid operator’s winter reliability program is helping to keep generators operating. The reliability program provides incentives for oil-fired units to buy adequate oil supplies before winter begins and to restock their fuel regularly throughout the season.
“Our organization has been monitoring this with ISO New England since the middle of last week and they’ve done a good job with the fuels program,” Kiley said.
A Thaw?
Some relief should come in the second half of January when NOAA is calling for above-average temperatures across much of the continental U.S.
CAISO officials said Tuesday they “reluctantly” plan for the ISO to become a reliability coordinator (RC) by spring 2019 and will depart from the ISO’s current RC, Peak Reliability, which recently emerged as a potential market competitor.
The ISO cited as the reasons for the move Peak’s decision to partner with PJM to provide market services and Mountain West Transmission Group’s likely departure from Peak after it joins SPP. (See PJM Unit to Help Develop Western Markets.) CAISO said in a press release it could provide reliability services “at significantly reduced costs.”
| CAISO
“The ISO reluctantly takes these steps and will collaborate with the rest of the funding parties to ensure continuity of reliability services and to avoid any party being adversely affected financially,” CAISO CEO Steve Berberich said. Services would include outage coordination, day-ahead planning, and real-time reliability monitoring.
The ISO said it will hold a call on the proposal Jan. 4 and conduct public meetings later this month in Folsom, Calif.; Phoenix, Ariz.; and Portland, Ore.
CAISO last month proposed to extend its day-ahead market into the territory of its regional Western Energy Imbalance Market (EIM), setting up a possible competition with Peak to provide an organized market to other areas of the West. (See CAISO Bid for Western RTO to Face Competition in 2018.)
RCs monitor compliance with NERC and regional standards, including monitoring risks, taking actions to preserve reliability and leading power restoration efforts.
Vancouver, Wash.-based Peak said it will have a business plan for its market offering in place by the end of March. The organization said last year it held more than 130 meetings, including some with public utility commissioners in Washington, Montana and Nevada; FERC; and the office of California Gov. Jerry Brown.
Peak in 2014 split off from the Western Electricity Coordinating Council, a NERC Regional Entity based in Salt Lake City, Utah. WECC recently began its own realignment toward core reliability functions. (See WECC Finding New Direction in Old Mission.)
Advanced meters have reached a 43% penetration rate but demand resources’ contribution to meeting RTO/ISO peak demand has decreased, FERC reported in its 12th annual report on demand response and advanced metering.
DR in the organized wholesale markets dropped to 5.7% in 2016 from 6.6% in 2015 according to RTO/ISO reports, as demand resource participation fell 10% while peak demand grew by 3%.
The decreased participation was largely because of a 24% (3,030 MW) drop in DR enrollment in PJM, which lost 2,900 MW in its reliability program (limited, extended summer and annual DR) and 900 MW in its economic program. The drops were partially offset by 600 MW of DR entering the market as Capacity Performance resources.
CAISO saw DR participation fall by 8% because of decreased enrollment in price-responsive demand programs administered by California’s three investor-owned utilities. ISO-NE and NYISO saw 4% drops while MISO saw a 1% increase.
Retail DR, by contrast, showed growth. Potential peak demand savings from retail DR programs nationwide increased by 5.4% between 2014 and 2015, according to the Energy Information Administration. Industrial customers were responsible for 52% of potential savings, while residential customers contributed 26% and commercial customers 21%, a breakdown that FERC said has “remained fairly stable over time.”
FERC also cited EIA data showing that 64.7 million advanced meters were deployed nationwide in 2015 out of a total of 150.8 million meters.
The report also took note of states’ grid modernization efforts, including deployment of time-of-use rates. The annual report, released Dec. 28, was mandated by Congress in the Energy Policy Act of 2005.
Con Ed ‘Value Stack’ Approved
Consolidated Edison last week won FERC approval to recover its payments to distributed energy resources customers under the New York Public Service Commission’s Reforming the Energy Vision initiative (ER18-214).
The PSC created a “value stack” describing the services provided by DERs: capacity; environmental value; demand reduction value; and locational system relief. (See NYPSC Limits ESCO Service, Sets New DER Compensation.) Con Ed agreed to New York City’s request that its annual accounting to FERC include an itemization of the four DER cost components.
Other Rulings
In other rulings last week, the commission:
Ordered a Section 206 proceeding to determine reactive service rates for Allegheny Energy Supply’s 80-MW coal bed methane-fueled facility located in Buchanan, Va. (ER17-2575, EL18-46).
Approved transmission rate incentives for Dairyland Power Cooperative’s share of the Cardinal-Hickory Creek 345-kV transmission project (ER18-193). The commission approved a hypothetical capital structure of 45% equity/55% debt and recovery of 100% of prudently incurred costs if the project is canceled for reasons beyond Dairyland’s control. The 125-mile project will run from the Cardinal substation in Middleton, Wis., to the Hickory Creek substation in Dubuque County, Iowa. Dairyland will own 9% of the project with American Transmission Co. and ITC Midwest each owning 45.5%. Pending regulatory approval, the companies expect to begin construction in January 2022 with an in-service date of June 2023.
Ordered hearing and settlement procedures on proposed revisions to the transmission formula rate templates of Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission and AEP Southwestern Transmission (ER18-194, ER18-195). Oklahoma Municipal Power Authority, East Texas Electric Cooperative and Northeast Texas Electric Cooperative protested that the AEP filings failed to justify the proposed changes, which AEP said were needed to transition from a historic basis to a forward-looking accounting method. The commission said the resolution of the dockets is subject to the outcome of East Texas’ complaint over the AEP companies’ 10.7% base return on equity (EL17-76).
Set hearing and settlement proceedings on Southwestern Public Service’s proposed revisions to the formula rate implementation protocols in its power supply agreements with Central Valley Electric Cooperative, Lea County Electric Cooperative, Farmers Electric Cooperative of New Mexico, Roosevelt County Electric Cooperative, Tri-County Electric Cooperative and West Texas Municipal Power Agency (ER18-228). The revisions update the depreciation rates for the two units at SPS’ Tolk generating station based on a 2032 retirement date and the retirement of its Carlsbad generator at the end of 2017. The commission cited protests by several co-ops that SPS had not presented proof it had made a legally binding decision to retire Tolk or Carlsbad earlier than previously indicated. They said that could allow SPS to change its decision after having benefited from recovering accelerated depreciation. Chairman Kevin McIntyre did not participate in the ruling.
Approved an uncontested settlement on Alliant Energy’s revenue requirement for providing reactive supply and voltage control at its Interstate Power and Light and Wisconsin Power and Light generating facilities (EL17-60, ER17-980-001). The settlement will pay IPL $3.58 million and WPL $3.77 million. Alliant had requested an annual revenue requirement of $4.23 million for IPL, a decrease from the $4.89 million it received in 2015, and $4.45 million for WPL, an increase from $2.41 million in 2015.
FERC last week ordered hearing and settlement proceedings on Southern California Edison’s proposal to revise its transmission formula rate, while approving an incentive for RTO participation over the objections of new Commissioner Richard Glick (ER18-169, EL18-44.)
The commission accepted the company’s filing effective Jan. 1 subject to refund. Although SCE proposed a reduction in its transmission revenue requirement, the commission said “a further decrease may be warranted.”
SCE proposed a base return on equity of 10.3%, saying the range resulting from FERC’s two-step discounted cash flow model — 6.97 to 9.15% — was too low.
The commission approved a 50-basis-point ROE adder for SCE’s participation in CAISO over the objections of the California Public Utilities Commission, which said the incentive is “an unjust and unreasonable windfall to SoCal Edison shareholders because SoCal Edison’s participation in CAISO is required by state law and the state of California determines whether SoCal Edison remains a member of CAISO.”
“The CPUC’s arguments … have been considered and rejected by the commission in earlier orders, and we reject them for the same reasons here,” the commission said. “We also note that companies continue to confront decisions about whether to form and join ISO/RTOs, and we believe the stability of the incentive adder for ISO/RTO participation (albeit capped by the top of the zone of reasonableness) is important to the congressional and commission policy of promoting ISO/RTO membership,” it added.
| Southern California Edison
Glick sided with the CPUC, saying, “I do not believe that this summary approval is the product of reasoned decision-making.”
“SoCal Edison’s membership in CAISO is not voluntary and, therefore, awarding a 50-basis-point RTO participation adder does nothing to harness for consumers the benefits of RTO membership,” Glick wrote in a dissent.
Glick said the ruling belied the commission’s “repeated statements that the RTO participation adder is not a ‘generic’ adder awarded to all public utility members of an RTO.
“Although I do not question the benefits of membership in an RTO — and I support using an RTO participation adder where it incentivizes RTO membership — I believe that the commission’s approach in this proceeding essentially transforms the ‘case-by-case’ evaluation of a request for an RTO participation adder that the commission described in Order No. 679 into exactly the type of generic determination that the commission forswore in Order No. 679 and subsequent orders.”
FERC ordered hearing and settlement procedures in a dispute over reliability-must-run agreements filed by Calpine for its Yuba City, Feather River and Metcalf generators in CAISO.
Yuba City power plant | Calpine
Map identifying the need for Yuba City and Feather River plants | CAISO
The commission’s Dec. 29 orders approved the Yuba City and Feather River (ER18-230) and the Metcalf RMRs (ER18-240) effective Jan. 1, 2018, subject to refund.
The ISO and Pacific Gas and Electric filed protests over the RMRs filed by Calpine’s Gilroy Energy Center subsidiary for the Yuba City and Feather River plants. CAISO designated the units as RMR in March, but the ISO told FERC that Gilroy had not supported provisions related to scheduling coordinator charges, greenhouse gas emissions and gas prices. (See PG&E, CAISO Protest Calpine RMR Terms.)
CAISO also protested Metcalf’s proposed changes to its cost-of-service schedules, arguing that they are unsupported or reflect errors in implementation of applicable formulas.
The ISO is increasing its use of out-of-market RMR payments to keep units online, raising concerns that its market is not producing the price signals sufficient to support units needed to provide reliable electric service.
