Page 1432 – RTO Insider

January 4, 2018

Cuomo Pushes Clean Energy in Annual Address

By Michael Kuser

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.

NYISO Andrew Cuomo clean energy — 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.)

NYISO Andrew Cuomo — 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.

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.”

January 4, 2018

Dominion to Buy Distressed SCANA for $8B

By Amanda Durish Cook

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.

January 4, 2018

NYISO Seeks FERC Denial on Indian Point Review Deadline

By Michael Kuser

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 Market Power Review Entergy — 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.”

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.)

January 3, 2018

Frigid Weather Tests Grid Operators

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.

cold weather peak demand — | *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.

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 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.

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.)

MISO has placed more weight on winter preparations since the 2013/14 winter, issuing winterization guidelines for generators and introducing heightened communication with gas pipeline operators. (See FERC Approves MISO Plan to Share Generator Gas Data.)

“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.

January 3, 2018

CAISO to Depart Peak Reliability, Become RC

By Jason Fordney

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.”

“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.)

CAISO peak reliability — CAISO CEO Steve Berberich said the ISO is “reluctantly” exploring becoming a reliability coordinator | © *RTO Insider*

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.)

January 2, 2018

Fast-Start Resource Pricing Adds to SPP’s Workload in 2018

By Tom Kleckner

FERC’s Dec. 21 order requiring SPP to help fast-start resources set LMPs added one more to-do for the RTO in what is shaping up to be a busy 2018.

SPP’s integration of the Mountain West Transmission Group drew much of the RTO’s attention in 2017. But it also has been working to solve underfunding issues in its financial transmission rights market, address stakeholder concerns over transmission cost allocations, identify seams transmission projects that can be built and incorporate the constantly increasing amounts of wind energy. And as they have for the last several years, stakeholders and SPP officials spent countless hours attempting to unravel the Z2 transmission project accounting mess.

Fast-Start Order

FERC gave SPP and stakeholders 45 days to file initial briefs in the Section 206 proceeding it created to drive Tariff changes to benefit fast-start resources. The commission found SPP’s approach “inconsistent with minimizing production costs” and ordered it to allow the commitment costs of fast-start resources (start-up and no-load costs) to be reflected in prices. SPP said it will decide its plan for responding to FERC’s fast-start order in early January. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

Working out the details will likely fall to SPP’s Market Working Group (MWG).

Congestion Hedging

The MWG has been spending the last few months working on improvements to SPP’s congestion-hedging process.

SPP’s Integrated Marketplace rules are intended to allow load-serving entities to translate firm transmission service reservations (TSRs) into a product that allows them to obtain credits to hedge daily congestion costs.

The RTO allocates auction revenue rights based upon firm network or point-to-point transmission reservations. But market participants have complained they are not receiving sufficient hedges.

Keith Collins, executive director of SPP’s Market Monitoring Unit, says the main area of concern is the initial transition from a physical transmission right (the TSR) to a financial right (the ARR).

SPP FERC fast-start resources LMPs — | *SPP*

Because ARRs are allocated months in advance of the day-ahead market, congestion patterns can change in the interim because of transmission outages, derates and upgrades and unexpected generation outages.

The MMU also notes that many prevailing-flow ARRs are not nominated, leaving hedges “on the table.” In addition, the availability of prevailing-flow ARRs is limited because most counterflow ARRs are not nominated.

Charles Cates, SPP’s manager of transmission services, told the Board of Directors in December that the RTO’s congestion market is about portfolios, not single-path entitlements and awards.

Staff say total congestion revenues continue to increase, with the revenues shifting from LSEs to financial entities (the non-ARR holders). Candidate ARRs associated with redispatch are contingent on completion of transmission upgrades, they say.

“Building transmission to help [create] more ARRs is an expensive answer to the problem,” Collins said.

The MMU has suggested hedging congestion from the physical day-ahead flow, taking the emphasis off day-ahead congestion prices.

Among the options SPP is considering are obligating the LSEs to nominate counterflow, reducing percentages in the annual transmission congestion rights auction, and limiting first-round ARR nominations by source and path.

The MWG will provide an update on its progress during the January board and Markets and Operations Policy Committee meetings. If the MWG can’t find a better mechanism, a task force could be created to take up the issue.

Mountain West Integration

The biggest to-do on SPP’s list is completing the integration of Mountain West, which primarily services Colorado, Wyoming and Nebraska. Mountain West announced its intention to join the RTO in January, but it had been holding discussions with SPP’s management team for almost a year prior. In September, Mountain West said it would begin public negotiations. (See SPP, Mountain West Integration Work Goes Public.)

SPP has established a Members Forum and State Commission Forum to assist with its due diligence effort. SPP’s Strategic Planning Committee spent the last quarter of 2017 conducting numerous executive sessions with Mountain West representatives. The discussions are expected to continue well into 2018.

Mountain West said it has had “significant success” resolving issues concerning rate design and cost-shift mitigation. Any changes to governing documents, such as SPP’s Tariff, bylaws and membership agreement, must go through the RTO’s stakeholder process for review before they are considered by the board. The Regional Tariff Working Group (RTWG) has primary responsibility for Tariff changes, while the Corporate Governance Committee will consider changes to the membership agreement and SPP bylaws.

SPP and Mountain West are working on an Oct. 1, 2019, target date for membership but will begin the regulatory approval process this year. FERC filings could come as soon as October, assuming the SPP board approves the integration at its July or October meetings. The RTO expects FERC review to take 60 to 180 days.

The Colorado Public Utilities Commission will play a key role in the process. The commission has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, two of the eight Mountain West members seeking to join SPP. The PUC held three informational sessions on the merger last year and could hold as many as three more in 2018. (See Colo. Regulators Talk Governance with SPP, Mountain West.)

When it’s all over, SPP will have expanded its current 14-state footprint into the Rocky Mountains, adding Colorado, most of Montana and portions of Arizona and Utah. The new SPP will grow by 165,000 square miles, adding 16,000 miles of transmission lines and 21 GW of generating capacity.

Mountain West will eliminate the pancake transmission rates that led to its search for RTO membership, while SPP members will see 10-year net present value benefits of about $209 million, according to the RTO.

Z2

In October, the board approved a cleanup of Tariff language that it hopes will help it resolve long-standing problems with Attachment Z2 of SPP’s Tariff, which details how financial credits and obligations are assigned for sponsored transmission upgrades. (See “Z2 Fix Allows Short-Term Service Agreements to Expire,” SPP Board of Directors/Members Committee Briefs: Oct. 31, 2017.)

January 2, 2018

Wind Nearing Coal as ERCOT Ponders Thinning Reserves

By Tom Kleckner

ERCOT enters 2018 facing new questions, as the growth in wind energy has begun threatening not only coal but also less efficient natural gas-fired generation.

In late November, the 155-MW Fluvanna Wind Energy Project in West Texas went online, pushing ERCOT’s wind power capacity past 20 GW. The milestone came a few weeks after the ISO approved the retirement of 2.4 GW of coal-fired generation, dropping its coal capacity to 15.1 GW in early 2018. (See ERCOT OKs Luminant Coal Retirements.)

Reserve Margin Reduced

ERCOT reserve margins wind energy — Garza | © *RTO Insider*

The retirements, along with those of several gas resources, has halved ERCOT’s planning reserve margin to 9.3% for summer 2018, leading Beth Garza, director of the ISO’s Independent Market Monitor, to proclaim an end to the “fat and happy times.”

“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” Garza told the ERCOT Board of Directors in October. “We’re looking at a much different situation going into the summer of 2018.”

The Monitor says it hasn’t seen a summer with such tight reserve margins since 2007. “Will we see coal generators making profits that justify future investment?” asked IMM Deputy Director Steve Reedy during an October conference, noting the Monitor has seen more capacity on the ERCOT system than might be justified.

“If the load doesn’t rise fast enough to justify the generation, we expect to see retirements. So, we will see [in 2018] if retirements in the market work,” Reedy said.

After bottoming out in 2016 with the lowest real-time prices ($24.62/MWh) since the nodal market began operations in 2010, the ISO has seen prices increase to an average of $28.56/MWh through November. Still, that 16% increase lags the 28% rise in natural gas prices over the same period.

Solar, Wind Dominate Queue

All the while, wind and, increasingly, solar projects continue to flood the market. More than 29 GW of wind and almost 25 GW of solar are currently going through some form of study, accounting for the bulk of ERCOT’s latest generator interconnection status report.

Joshua Rhodes, a research fellow at the University of Texas’ Energy Institute, projects ERCOT’s wind capacity to reach 24.4 GW by the end of 2018. Given current capacity factors and coal retirements, that means wind will surpass coal as a fuel source for electricity by 2019. Coal generation has accounted for 32.2% of the ISO’s production this year, compared to wind’s 17.5%. Natural gas exceeds both, at 39%.

So far, cheaper natural gas and wind have driven inefficient coal and gas plants out of the market.

“We haven’t had a true scarcity event in years, but if we have severe weather, we could have one,” said NRG Texas’ Bill Barnes, speaking on the same conference panel with Reedy. “That’s when we can all sit back and say, ‘Yes, that’s how it’s supposed to work.’ Or will there be temptation to intervene in the market?”

Market Rule Changes?

NRG Texas partnered with Calpine to sponsor a report of the ERCOT market, published in May. The report, coauthored by Harvard University’s William Hogan and FTI Consulting’s Susan Pope, recommends several market improvements, including adjusting the operating reserve demand curve (ORDC), adding local scarcity pricing and potentially implementing real-time co-optimization (RTC), to address intermittent renewables and improve incentives for generators. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)

The Public Utility Commission of Texas, which regulates ERCOT, has conducted a pair of workshops to discuss price-formation issues in the Texas grid operator’s energy-only market (project 47199). Stakeholders have suggested a wide range of market improvements, from adjusting reliability unit commitment (RUC) mitigation rules and instituting penalty curves for pricing constraints, to incorporating marginal losses’ costs into dispatch decisions and requiring locational reserve requirements.

The question of whether to defer market design changes until after the summer is yet another issue that must now be resolved.

The Monitor has called RTC the “most vital” market improvement. RTC is “foundational” to efficient pricing, it told the PUC, “especially in an energy-only market like ERCOT where participants rely on energy prices to facilitate short-term decisions to commit generation and long-term decisions to invest and retire.”

“The benefits of RTC would be substantial, as supported by the results seen by other [ISOs] where RTC is implemented,” the Monitor said.

ERCOT staff have been working on a study of the costs and time it would take to implement RTC or marginal losses in the wholesale market. A July report indicated it would take at least $40 million and four to five years to make the changes. A September report lowered those figures to at least $10 million and 18-24 months.

In December, the ISO filed a proposed plan to further assess the benefits of implementing RTC and marginal losses. Staff suggest using IMM software code to run a simulation of RTC in historical security constrained economic dispatch (SCED) cases to estimate the cost savings on an interval-by-interval basis, a process they expect to take six months.

ERCOT said introducing RTC into the market would provide additional flexibility in the real-time market in locating ancillary services, which would require modifying the RUC engine “to ensure a reliable operating plan.”

Staff predicted it would take about six months to complete a benefits assessment of marginal losses. ERCOT and the Monitor have promised another status update by the end of the first quarter.

New Loads, Oncor Deal

In the meantime, the PUC will hold a hearing Jan. 17-18 on Lubbock Power & Light’s proposed migration of 430 MW of load from SPP into ERCOT. The commission is also waiting on the results of a joint study on Rayburn County Electric Cooperative’s proposed transfer of another 150 MW of load from SPP to ERCOT.

In February, the PUC is scheduled to conduct a hearing on California-based Sempra Energy’s proposed $9.45 billion acquisition of Oncor and its bankrupt parent, Energy Future Holdings. Sempra and Oncor on Dec. 14 filed a settlement they had reached with key Texas stakeholder groups. (See Sempra, Oncor Reach Deal with Texas Stakeholders.)

January 2, 2018

MISO in 2018: Storage, Software, Settlements and Studies

By Amanda Durish Cook

CARMEL, Ind. — MISO’s 2018 to-do list includes continuing efforts to expand energy storage participation, extensive software upgrades, a tardy five-minute settlements rollout and studies on its changing resource mix.

Storage Dialogue

In August, MISO stakeholders determined that creating energy storage market definitions and rules was the single biggest market issue for 2018. (See “Stakeholders Give Energy Storage Top Spot in Roadmap,” FERC Rule Would Boost Energy Storage, DER.)

In January, the task force plans to create a list of how storage currently participates in MISO markets and when it is and isn’t compensated to identify “gaps,” according to American Transmission Co.’s Bob McKee. Fernandes said that he didn’t want to simply roll storage benefits into a fixed transmission charge “on the backs of ratepayers.”

MISO Executive Director of Market Design Jeff Bladen said the RTO will work on storage attribute compensation “to the extent to which we can identify appropriate uncompensated attributes.” He warned that not all stakeholders will agree that certain attributes ought to be compensated.

External Capacity Zones

MISO hopes in 2018 to conclude yearslong efforts to introduce external capacity zones into its Planning Resource Auction. In response to the increase in intermittent generation and an aging baseload fleet that’s more prone to outages, the RTO also is considering setting capacity procurement requirements for load-serving entities. MISO predicts it will require just more than 17% of reserves for the 2018/19 planning year, a requirement that’s been steadily increasing year-over-year.

5-Minute Settlements Deferment

Some of MISO’s 2018 capital spending will be devoted to a delayed execution of FERC-ordered five-minute settlements.

In mid-November, MISO asked FERC to delay the settlements’ go-live date to July 1, instead of March 1 (ER18-314), after stakeholders said the RTO’s behind-schedule replacement of its overall settlements computer system would result in a rushed process for members to make their own software adaptions to accommodate the new process. The extra time will be used for software testing for both MISO and its member companies. (See MISO Members Seek Delay on Five-Minute Settlements.)

Raising the Offer Cap

The RTO also must regroup and plan direction on a revised Order 831 compliance filing after its energy offer cap design was rejected by FERC (ER18-300) in November.

FERC turned down MISO’s $1,000/MWh soft cap and $2,000/MWh hard cap, saying it would prohibit resources from submitting cost-based offers above the hard cap. (See MISO to Seek Waiver After FERC Rejects Offer Cap Plan.)

Queue Discussion Lined Up

MISO’s new interconnection queue design was accepted by FERC at the beginning of 2017, but there may be more changes coming.

Although the new queue design is meant to reduce the amount of time spent on studies, a very full queue project line-up has MISO staff warning stakeholders of delays.

Some stakeholders have already asked FERC to force additional rule changes. (See EDF Asks MISO to Revisit Queue Overhaul.)

“We just went through a rather exhaustive queue reform, but now that we’ve got the process and implemented it, there are a certain number of stakeholders that don’t believe it’s working,” said Wisconsin Public Service’s Chris Plante during the December Advisory Committee meeting.

MISO energy storage software upgrades — December Advisory Committee | © *RTO Insider*

MISO President Clair Moeller said the last time that the queue was this packed was in 2007.

About 60 GW of proposed generation is seeking interconnection, including 30 GW of wind, 15 GW of solar, 12 GW of natural gas and 600 MW of other resources. The queue also holds about 140 MW of prospective battery storage capacity.

“There’s a lot of capacity in the queue, and a lot of it won’t come online, but a lot of it will,” MISO CEO John Bear said during a Sept. 21 Board of Directors meeting.

Market Platform Replacement

MISO’s information technology department and vendor General Electric will begin in 2018 a seven-yearlong replacement of its market platform, the system responsible for operation of the day-ahead and real-time markets.

“These systems were designed in the late 90s and began operation in the early 2000s, and you think about all the technology advancements since then and how the cybersecurity threat landscape has changed,” Kevin Sherd, MISO director of forward operations planning, said at a December Market Subcommittee meeting.

The RTO expects to spend $21.7 million in 2018 on the project, one-sixth of its planned total spending over the next seven years. (See MISO Makes Case for $130M Market Platform Upgrade.)

MISO is looking for a system that “will best position us for the future,” Sherd said. The RTO’s current inflexible system, which has become increasingly challenged by market changes, will be swapped for a modular market platform allowing programs to be changed without impacting others. “Building something that is more adaptable is our core principle,” he said.

New Website

MISO will fully launch its new external website in the coming weeks. Sometime after January, MISO’s current site will shift to the web address old.misoenergy.com. The RTO will maintain its old public website through the first quarter to make certain that it still has a website in the event of a failure of the new website.

A beta version of the new website has been up since October at beta.misoenergy.org, where the RTO recently added log-in capability for meeting registrations.

Competitive Bidding in 2018

MISO will oversee the competitive bidding of the yet-unapproved $130 million Hartburg-Sabine 500-kV line market efficiency project in eastern Texas this year. (See MISO Board Approves $2.6B Transmission Spending Package.)

The Hartburg-Sabine project will be MISO’s second-ever competitively bid transmission project and the first such project to include a substation. The RTO plans to add two new staff members to oversee the competitive process. The line is intended to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area spanning Texas and Louisiana.

Meanwhile, work is underway on the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky, MISO’s first competitively bid project. For most of 2018, LS Power subsidiary Republic Transmission will work on project design, environmental permitting and securing rights of way. Construction is slated to begin the fourth quarter of 2018. MISO selected Republic’s $49.8 million proposal for the new, 30-mile, 345-kV line last December. (See LS Power Unit Wins MISO’s First Competitive Project.) Republic said it expects to encounter “construction risks and challenges,” most notably acquiring federal permits to cross the Ohio River.

The PJM Relationship

MISO and PJM also hope to implement a two-part fix in early 2018 to remedy their double-charging of congestion fees on pseudo-tied generation. The RTOs are facing five complaints concerning overlapping congestion charges for pseudo-tied generators. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

The fix has been complicated by the discovery that PJM has been making errors on market-to-market calculations.

For years, PJM has been overstating its own transmission loading relief (TLR) because of a calculation error and its failure to order mandated tests required to define M2M constraints between the two RTOs. (See MISO Board, Monitor Seek Response to PJM M2M Missteps.)

“We’re going to explore with PJM what needs to happen retroactively and maybe what needs to happen going forward,” Bladen said during a Dec. 14 Market Subcommittee meeting.

Sign-of-the-Times Studies

MISO is planning studies in 2018 on how to respond to increasing natural gas and renewable generation. One study will gauge how the natural gas supply affects MISO’s dispatch ability.

Vice President of System Planning Jennifer Curran said the RTO and stakeholders will work throughout 2018 to “recognize the impact large gas pipeline contingencies have on the MISO system.”

Curran said MISO already has a good idea of where pipelines are located, but it wants to analyze the footprint’s gas supply and the potential consequences if some infrastructure were to fail.

MISO’s 2018 Transmission Expansion Plan will seek to identify where wind generation is likely to grow the fastest.

At the Annual Stakeholders’ Meeting in June, Board Chairman Michael Curran said he had confidence MISO could scale future obstacles, including portfolio evolution, renewable penetration and future federal and state regulations.

“It’s a very unsettling time. It’s almost as if the earth is moving from under us. And that may be the case in Oklahoma with fracking ― unproven of course,” he quipped.

January 2, 2018April 30, 2025

CAISO Bid for Western RTO to Face Competition in 2018

By Jason Fordney

The Western Energy Imbalance Market (EIM) expanded its footprint and ambitions in 2017 while new suitors lined up to compete with CAISO as the vehicle for a Western RTO.

Current and pending members of CAISO’s Western EIM | CAISO

Idaho, Washington, Arizona, Nevada and Canadian provinces are considering how to access regional markets while protecting the financial health of their resources and keeping costs reasonable for consumers.

The EIM has been recognized as a success story. The increased efficiency of regional dispatch and having more offramps for generation are attractive not only for renewables, but also for coal, hydro and natural gas generation in the market’s balancing authorities.

Five utilities have joined the EIM since its inception in 2014, including Portland General Electric in 2017. Six others have announced plans to join: Idaho Power and Powerex in 2018; Los Angeles Department of Power & Water and the Sacramento Municipal Utilities District in 2019; and the Salt River Project and Seattle City Light slated for 2020. In December, CAISO announced plans to expand its EIM offerings with a day-ahead market. (See CAISO Plan Extends Day-Ahead Market to EIM.)

Mountain West, Peak Reliability

But CAISO faces competition in its bid to expand into a RTO.

Last January, Mountain West Transmission Group said it would begin talks to join SPP. Mountain West, a partnership consisting of seven different transmission-owning entities within the Western Interconnection, covers most of Colorado and Wyoming with smaller areas of Arizona, Montana, New Mexico and Utah. The potential move has been of keen interest to regulators in the affected states. (See Colo. Regulators Talk Governance with SPP, Mountain West.)

In December, reliability coordinator Peak Reliability announced it would work with a unit of PJM to develop new market structures for the West. “We are continuing our review with PJM Connext of potential reliability services and markets in the West and our outreach with western industry leaders and stakeholders,” spokeswoman Rachel Sherrard told RTO Insider last week. (See PJM Unit to Help Develop Western Markets.)

Legislation Stalls

The California State Legislature ended its 2017 session in September after failing to pass bills that would have advanced CAISO’s regionalization efforts.

AB 726 and AB 813, which were returned to the Senate Rules Committee, would have repealed a section of the Clean Energy and Pollution Reduction Act of 2015 governing the transformation of the ISO into an RTO and created a Commission on Regional Grid Transformation. The bills would authorize the transformation if the CAISO Board of Governors and the commission took certain actions by the end of 2018.

Lawmakers say they will reconsider the legislation after they return to Sacramento this month. The debate over regionalization in California involves issues of state control over resources and policy, and highlights concerns over energy costs and the influence of labor groups worried over exporting energy jobs.

The legislature also is under heavy pressure to pass zero-carbon legislation that also fell short in 2017. California’s policies to phase out fossil fuels in favor of renewables and new technologies have raised cost concerns and forced changes to long-standing engineering approaches to accommodate more variable renewable output and the complexities of smaller, distributed resources. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.)

Governor Jerry Brown

Gov. Jerry Brown has taken a defiant stance against President Trump’s environmental policies, recently traveling internationally to evangelize for fighting climate change.

Brown attributed the recent wildfire devastation in California to climate change, saying the state’s fire season is now months rather than weeks. Fire investigators are focused on utility infrastructure as a possible cause, setting up complicated and contentious proceedings at the Public Utilities Commission over penalties and cost recovery. (See CPUC Targets Wildfires, Multifamily Solar, RMRs.)

During an interview on “60 Minutes,” Brown discussed Trump and climate change in religious terms. “I don’t think President Trump has the fear of the Lord, the fear of the wrath of God, which leads one to more humility,” he said. “And this is such a reckless disregard for the truth and for the existential consequences that can be unleashed.”

This summer, Brown signed a bill that extended the state’s carbon cap-and-trade program until 2030. (See California Lawmakers Extend Cap-and-Trade.) The program will help the state meet its goal of reducing GHG emissions to 40% below 1990 levels by 2030.

Other CAISO, PUC Initiatives

In addition to its regionalization efforts, CAISO has more than a dozen other initiatives underway, with day-ahead market enhancements and resource adequacy at the top of the list in its 2018 roadmap. The conflict between state resource adequacy programs and CAISO’s reliability management are another priority because of the increasing number of reliability-must-run agreements.

The growth of community choice aggregators led the PUC to propose that they be subject to the same resource adequacy requirements as electric utilities. (See California Proposes Resource Adequacy Obligations for CCAs.)

In December, the board of the Western Electricity Coordinating Council, the NERC-designated Regional Entity for 14 Western U.S. states, Alberta, British Columbia and a small portion of Baja California, Mexico, endorsed a new three-year operating plan. The plan continues the transformation that began in 2014, when Peak Reliability split off from WECC as the Reliability Coordinator for the Western Interconnection, except Alberta. (See WECC Finding New Direction in Old Mission.)

January 2, 2018January 17, 2024

CORRECTED: New England Leads East in Renewables Transition

By Michael Kuser

ISO New England will open the new year by filing with FERC a two-settlement market construct to integrate state-sponsored renewable energy resources into the wholesale electricity market.

The New England Power Pool’s Participants Committee voted Dec. 8 on the two-tier market concept called Competitive Auctions with Sponsored Policy Resources (CASPR), but with 57.75% of the vote, the proposal failed to reach the 60% mark needed to be considered supported by the PC. Nonetheless, the RTO plans to file the proposal with FERC this month, according to spokesperson Matt Kakley. (See New England Strives to Find CASPR Consensus.) [Editor’s Note: An earlier version of this article incorrectly stated that the vote would be taken in January.]

Under CASPR, ISO-NE would conduct the Forward Capacity Auction in two stages, allowing existing resources that have capacity obligations and a desire to retire to trade out their obligations with incoming state-sponsored resources in a manner that doesn’t affect price formation in the primary auction.

In the primary FCA, resources would clear based on current rules, including those designed to mitigate offers below competitive prices such as state-sponsored resources. In the secondary or substitution auction, existing resources that cleared in the FCA would be able to transfer their capacity obligations to new sponsored policy resources that did not clear, with the existing resource agreeing to retire early in exchange for a “severance” payment.

CASPR, which arose from the Integrating Markets and Public Policy (IMAPP) process begun in 2016, is just one of the electricity policy issues facing New England.

State-Sponsored Renewable Energy

In January, Massachusetts will select the winners of last July’s solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage). Contracts with the winning bidders under the MA 83D request for proposals are due to be completed in late April.

The proposals include an HVDC transmission line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada; a 375-mile submarine HVDC transmission line extending from New Brunswick to Plymouth, Mass.; and a submarine cable under Lake Champlain to bring 1,000 MW of hydropower, solar and wind from Canada. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

Offshore Wind in Mass.

Three developers submitted proposals Dec. 20 in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.

The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027.

The state’s first RFPs (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal is superior to and more economical than the others.

The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

The state will announce the winners of the offshore wind solicitation on April 23, and contracts are to be submitted at the end of July.

Storage Coming on Strong

As of December, ISO-NE reported more than 470 MW of energy storage in the interconnection queue, a nearly six-fold increase in one year.

Massachusetts is funding incentives to include energy storage in solar installations, as well as grants for peak demand reduction. Pairing energy storage with solar panels is meant to enhance grid resiliency by reducing the need for traditional generation to ramp up when the sun goes down. Peak reduction grants cover a wide range of projects, from utilities improving the efficiency of substations, to municipalities working to reduce the energy consumption of big-box retail stores, to a thermal energy storage project on Nantucket that will delay the need for a new undersea transmission cable. (See Massachusetts Awards $20M in Energy Storage Grants.)

The state in 2017 launched its Solar Massachusetts Renewable Target (SMART) program to provide incentives for “long-term sustainable … cost-effective solar development.” The program provides incentives based on location, and to projects that provide unique benefits, including community solar and energy storage

Massachusetts’s new Alternative Energy Portfolio Standard is the only one of its kind in the country. The final draft regulations, released Dec. 29, include combined heat and power, flywheel storage, renewable thermal, fuel cells and waste-to-energy thermal technologies. The regulations oblige all retail electric suppliers to acquire a percentage of their power from eligible technologies, starting at 4.25% in 2017 and increasing by 0.25% each year through 2020, and by the same amount each year thereafter, subject to DOER review.

Millstone Debate

Opponents of Dominion Energy’s bid to win state subsidies for its Millstone nuclear plant were cheered in December as consultants hired by Connecticut said the plant is likely to remain profitable through 2035 even under low natural gas prices. The report by Levitan & Associates concluded “there is no ‘missing money’ required to ensure Millstone’s financial viability through the existing term of Millstone’s Unit 2 operating license” in 2035. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)

The report projected that in 2022 the plant would earn after-tax net cash flow of $100 million under a low gas price/high operating cost scenario, to more than $200 million under the reference case that assumed “business-as-usual” conditions.

Connecticut Gov. Dannel Malloy ordered state regulators in July to assess the economic viability of the plant and determine whether the state should provide it financial support. Malloy’s executive order also directed the state Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output. (See CT Gov Orders Financial Analysis of Millstone Plant.)