Page 1093 – RTO Insider

December 17, 2018

New England Talks Solar, Storage and Public Policy

By Michael Kuser

BOSTON — Growing solar generation will be able to meet a third of peak load in Massachusetts in a few years, but as the grid is reaching the saturation point in certain areas, policymakers are looking to energy storage to help address some of the challenges.

“The grid was not initially designed for this much distributed energy … and we never envisioned 90,000 power plants out there,” Commissioner Judith Judson of the Massachusetts Department of Energy Resources said Friday at the 160th New England Electricity Restructuring Roundtable run by Raab Associates.

The 160th New England Electricity Restructuring Roundtable drew a standing-room-only crowd in Boston on Dec. 14. | © *RTO Insider*

Judson said the state now has more than 89,000 installed solar projects totaling more than 2,300 MW in each of its 351 cities and towns.

On Nov. 26, it launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. “SMART provides a fixed revenue stream to reduce the cost of the program, and we are the first state in the nation to have a solar-plus-storage incentive,” Judson said.

It took the state a long time to launch the program because “we have a regulatory process in DOER and in the Department of Public Utilities, plus heavy stakeholder engagement,” Judson said. “But we’ve had over 2,850 applications for 650 MW in capacity submitted so far and $4.7 billion in cost savings to ratepayers compared to earlier solar programs, so I think it’s made for a better program.”

On Dec. 12, the state issued its Comprehensive Energy Plan (CEP), including a provision for the state’s utilities to procure a combined 200 MWh of energy storage by 2020. (See Massachusetts Deploys Utility-Scale Energy Storage.)

Transition in Connecticut

“The grid modernization proceeding [Case 17-2-03] in Connecticut is a really promising opportunity,” said Mary Sotos, deputy commissioner of the state’s Department of Energy and Environmental Protection.

“I think it’s the first time utilities have laid out for the public … how they’re doing manual, back-end system work for stuff they want automated at scale,” Sotos said. “It’s not just the cost of the meters for them; the concern is managing the data … putting it in the right format, which is all part of this broader shift in information availability.” (See Connecticut Explores its Energy Future at CPES Event.)

Sotos highlighted “opportunities to align policy objectives, customer objectives and developer objectives.”

Connecticut’s solar programs are all in transition, including ones that limit virtual net metering for state, municipal and aggregation customers by capping the amount that could be reflected into rates, she said.

Connecticut last spring passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensured rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.)

“Net metering was available to all these customers in the past on the energy side to compensate solar energy … and each of those solar programs had a statutory spending cap, but we found that municipalities were reaching that cap very quickly,” Sotos said. “For each of these groups we also had a separate program to help facilitate the deployment of behind-the-meter solar by focusing on the RECs [renewable energy credits].”

The state’s Green Bank ran “an incredibly successful” residential solar investment program to focus on the RECs from installations with storage, she said.

“However, under the current monthly net metering model, there isn’t an obvious incentive for customers to do storage, because any energy that is excess or used in real time, it’s all valued at the same level,” Sotos said. “From our perspective, to really value storage for dynamic peak reduction or other benefits … there needs to be an additional financial signal, whether that’s a time-of-use rate or some other type of adder.”

Field Experience

Jonathan Raab of Raab Associates, who has been convening the roundtables since 1995, said he was lucky in his selection of two of last week’s panelists: Evan Dube, senior director of policy at SunRun, represented the most megawatts bid in the under-25-kW category in the SMART program, while Ilan Gutherz, senior director of strategy and policy at Borrego Solar, represented the most megawatts bid in the over-25-kW category.

“Having a robust [distributed energy resources] market, both behind-the-meter and in front, is going to be critical for sustaining the grid in the future,” Dube said. “We hear an awful lot about how rate design must be sustainable … but in so doing, we have to keep in mind the benefits that building out these resources will have in the long term, and how that’s going to make us more sustainable in the future.”

More granular rate design such as time-of-use rates is preferable because it is fairer to customers, but that rate structure is contingent on penetration levels and their location, which affect the price of electricity, Dube said. The availability of metering infrastructure and data also influence how exact electric power billing can get.

The future of compensation for zero-marginal-cost resources like wind and solar depends on getting regulators to “think about how PV and batteries can avoid the need for long-term transmission investment,” Gutherz said.

New York’s Value of DER tariff that large-scale solar and other resources are now on has been testing value-based compensation as opposed to cost-based compensation alone, he said.

“New York’s an interesting experiment; in our opinion, they went a little bit too fast, so if you watch the recent filings from the commission there, you’ll see there’s been a lot of back-pedaling on certain aspects of that tariff,” Gutherz said.

“Solar plus storage is a game-changer,” said Juliana Mandell, director of market development and policy at ENGIE Storage. “You’re transforming solar into a dispatchable, reliable renewable energy resource that’s no longer time-constrained, and that fundamentally shifts the conversation.”

Energy storage can flatten load and generation, be used to reduce peak demand, or to shift generation and load depending on grid system needs and economic signals, she said.

“And you can use storage to mitigate locational constraints and congestion [and] improve capacity supply, and storage can participate at a high level in the wholesale market,” Mandell said. “You can see that coming out of the recent FERC orders if you’re looking [at] how do we pay fairly for resources that provide a different level of performance.”

“The questions is not why solar, but why distributed solar?” said Jesse Jenkins, postdoctoral fellow at Harvard’s Kennedy School and one of the contributors to the MIT Utility of the Future study. “Solar and storage are technologies and means that deliver value, so what we need to focus on is the ends that we have in mind and the value that we want to capture. … Solar and storage are not the only ways to deliver any of the values we’re talking about.”

Mark LeBel, an attorney with Acadia Center, said that solar, peaking in summer, has to be balanced with winter-peaking wind, but that balance is also needed to value societal concerns.

Rooftops almost certainly have to be part of the answer for solar, because there are little or no siting issues, he said.

“Where are we going to put 20 GW of solar?” LeBel said. “Does New England want to pave over paradise?”

December 17, 2018

Soapbox: Large Buyers – Don’t Stop Our Renewable Purchases

By Jeff Dennis and Caitlin Marquis

In response to FERC’s directive to address the impacts of state policies on capacity prices, PJM has proposed a sweeping approach that could put at risk a broad set of transactions for renewable energy that have nothing to do with any state policy or mandate. On behalf of the Advanced Energy Buyers Group, a collection of large companies ranging from technology to retail to manufacturing, we urge FERC to avoid disrupting the voluntary market for renewable energy by rejecting PJM’s approach.

Companies involved in the Advanced Energy Buyers Group are committed to increasing their use of advanced energy, with many entering into contracts to develop renewable energy projects to meet their own business needs, completely independent of state mandates or incentives. We are concerned that PJM’s proposal, if adopted by FERC, would unfairly apply to some of these voluntary transactions the same measures intended to “correct” a market distortion supposedly caused by so-called “material subsidies” provided by states. This could threaten the continued growth of the quickly expanding voluntary market for renewable energy in the PJM footprint, and the jobs and other economic benefits that growth brings to states and communities in the region even as it gives companies the clean energy they seek.

According to FERC, generating resources that receive revenue as a result of state renewable portfolio standards or zero-emissions credit (ZEC) programs are able to submit offers in PJM’s capacity auctions at a lower price than they would otherwise. FERC claims that these offers result in “artificially” lower prices, harming other suppliers that do not receive such revenue. To address this alleged price suppression, FERC ordered PJM to expand its minimum offer price rule (MOPR) — which requires capacity suppliers to make offers at or above a predetermined minimum value — to apply to any capacity resource receiving revenues from state policy programs.

To its credit, PJM correctly acknowledged that voluntary renewable energy purchases should be exempted from the expanded MOPR because any revenue received from such purchases aren’t the result of any state mandate or policy. PJM goes on, however, to state that any renewable energy certificates (RECs) purchased through brokers or intermediaries will be assumed to be serving state policy needs rather than meeting voluntary market demand. This means that only those RECs that are purchased by voluntary buyers through direct, bilateral transactions would be exempt from MOPR requirements. Other renewable energy transactions that use different structures would face the possibility that they could be subject to the MOPR. That matters because application of the MOPR could force certain renewable energy projects out of the capacity market, depriving them of legitimate revenue.

Applying the MOPR in such a broad fashion would fail to satisfy FERC’s legal obligation to narrowly tailor such mitigation to the market harm it identified, i.e., the supposed price-suppressive impacts of state-directed revenues. Equally important, it would fail to account for how the voluntary market actually works, especially the variety of transaction structures and market actors, including REC brokers and intermediaries, that support voluntary renewable energy purchases.

Direct REC purchases from renewable energy projects are an important segment of the voluntary market, to be sure. But so too are “unbundled” RECs purchased through brokers or intermediaries. Renewable energy buyers range from residential consumers to small businesses to large international corporations. Many of these buyers rely on unbundled RECs to some degree, and in 2017 unbundled REC sales accounted for nearly half (46%) of all voluntary market sales of renewable energy. The voluntary purchase of these unbundled RECs by buyers who (unlike utilities and other electricity suppliers) have no state-imposed obligation to purchase renewable energy does not contribute to the state’s RPS or other policy mandate. These RECs are effectively retired, rather than used for compliance with state requirements — which is why they can be counted toward corporate sustainability goals.

Even for large companies that pursue direct contracts with renewable energy projects, unbundled RECs purchased from brokers or other intermediaries can play an important part in an overall renewable energy strategy. Unbundled RECs allow companies to purchase renewable energy without a long-term, large-scale commitment to a single project, as part of a diversified renewable energy portfolio. Unbundled RECs also allow companies to meet renewable energy goals while they pursue direct renewable energy contracts, which takes time.

Many companies and other renewable energy buyers rely heavily on RECs purchased through brokers or intermediaries — to the tune of 51 million MWh across the country last year. These RECs have contributed to a rapid expansion of voluntary corporate renewable energy deals in the PJM region in just the past few years. One voluntary REC getting swept up in mitigation that is, by the terms of FERC’s directive, supposed to be narrowly focused on material subsidies provided by states is one too many, and PJM’s approach could sweep up nearly half the market.

Accordingly, we urge the commission to ensure that any changes to PJM’s capacity market do not, even inadvertently, unfairly cripple the voluntary market for renewable energy.

Caitlin Marquis is manager of federal and state policy for the Advanced Energy Buyers Group, a business-led coalition of large energy users engaging on policies to expand opportunities to procure advanced energy to meet their operational needs.

Jeff Dennis is general counsel, regulatory affairs, for Advanced Energy Economy, a national association of businesses making the energy we use secure, clean, and affordable. AEE facilitates and supports the work of the Advanced Energy Buyers Group.

December 17, 2018

Mass. Offshore Lease Auction Nets Record $405 Million

By Michael Kuser

Offshore wind in the U.S. hit a new milestone Friday when the eighth federal lease auction brought in $405 million for three sites — about six times the revenue from all previous auctions combined.

Eleven companies participated in 32 rounds of bidding. The winners were Equinor, a Norwegian state-controlled company formerly known as Statoil; Mayflower Wind Energy, a joint venture of Shell and EDP Renewables; and Vineyard Wind, a joint venture by Iberdrola and Copenhagen Infrastructure Partners.

A BOEM simulation of what the offshore wind turbines might look like from Wasque Point on Martha’s Vineyard. | *BOEM*

The three lease areas are located 19.8 nautical miles from Martha’s Vineyard and 16.7 nautical miles from Nantucket. The areas total 388,569 acres and, if fully developed, could support 4.1 GW of wind generation, or enough electricity to power about 1.5 million homes.

“Wow … we are truly blown away by this result,” Walter Cruickshank, acting director of the Bureau of Ocean Energy Management, which conducted the auction, said on a press call.

“The intense competition we’ve seen in this offshore wind lease auction is completely unprecedented,” said Nancy Sopko, director of offshore wind for the American Wind Energy Association.

“To anyone who doubted that our ambitious vision for energy dominance would not include renewables, today we put that rumor to rest,” Interior Secretary Ryan Zinke said.

To illustrate the pace of the bidding, a BOEM webpage shows the winning bids — each $135 million — at more than 500 times the size of the opening bids, which started at less than $260,000.

The new industry has gained momentum on the East Coast this year. Massachusetts and Rhode Island in May awarded 1,200 MW of offshore wind energy contracts. Vineyard Wind will supply Massachusetts with 800 MW, while Deepwater Wind won the contract to supply Rhode Island with 400 MW, which Connecticut expanded soon after with a 200-MW award. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

New Jersey committed in May to build 3,500 MW, and New York in July authorized procurement of at least 800 MW or more in offshore wind energy, the first part of a two-phase plan to develop 2,400 MW by 2030.

The U.S. Department of Energy in June awarded an $18.5 million grant to the New York State Energy Research and Development Authority to lead a nationwide research and development consortium for the offshore wind industry, with the state to match the federal funds. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)

Massachusetts officials hope to develop supply chains for the nascent industry in the Port of New Bedford, where they have funded a terminal, but are also working to avoid interfering with fishing operations there, the No. 1 fishing port in the U.S. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

BOEM said it now has 15 active wind leases for nearly 2 million acres in federal waters.

BOEM map shows the leases won Dec. 14 by three developers: Equinor Wind US in pink; Mayflower Wind Energy in purple; and Vineyard Wind in green. | *BOEM*

Before the Dec. 14 lease sale, the highest price for an offshore wind lease was slightly more than $42 million paid by Statoil two years ago for an area in the New York Bight. New York is expected to issue its first offshore request for proposals this month.

The U.S. Department of Justice and Federal Trade Commission will conduct a competitiveness review of the auction, and the provisional winner will be required to pay the winning bid and provide financial assurance to BOEM.

Upon BOEM approval of a site assessment plan in a lease’s first year, the developer then has four and a half years to submit a construction and operations plan (COP).

After the bureau receives a COP, it will conduct an environmental review, with public input, and if BOEM approves the plan, the developer will then have 33 years to build and operate its project.

December 16, 2018

NYPSC Expands Storage, Energy Efficiency Programs

By Michael Kuser

New York regulators on Thursday approved measures that will sharply increase the state’s energy storage and efficiency targets.

The rulings by the Public Service Commission will double New York’s existing 2025 storage goal to 3,000 MW by 2030 and require the state’s utilities to reduce building energy use by an additional 31 trillion British thermal units (TBtu) to meet an energy efficiency target of 185 TBtu by 2025.

The PSC held its regular monthly session in New York City on Dec. 13, 2018.

“As the federal government continues to ignore the real and imminent dangers of climate change, New York is aggressively pursuing clean energy alternatives to protect our environment and conserve resources,” Gov. Andrew Cuomo said in a statement. “These unprecedented energy efficiency and energy storage targets will set a standard for the rest of the nation to follow, while supporting and creating jobs in these cutting-edge renewable industries.”

The commission’s Dec. 13 storage order (Case 18-E-0130) accepted with modifications the state’s six major utilities’ proposed “hybrid tariff” for storage systems paired with eligible electric generating equipment, directing each utility to distinguish between renewable and non-renewable energy injected into the grid.

The PSC’s March 2017 Value of Distributed Energy Resources Phase I order (Case 15-E-0751) directed utilities to compensate distributed energy resources through the “value stack,” a methodology that bases compensation on benefits provided. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

The investor-owned utilities (Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas and Electric) now must file tariff amendments incorporating the value stack compensation for a hybrid facility and explaining how they will manage appropriate metering and controls under four potential usage models.

The commission said that “non-renewable energy is only eligible for compensation for energy value, demand reduction value, locational system relief value” and other capacity value, “while renewable energy is also eligible for compensation for environmental value, a market transition credit if applicable to the project” and other capacity value.

Blended energy storage cost forecasts for behind-the-meter storage site with load and front-of-the-meter storage connected at the distribution or bulk transmission level. | *NYSERDA*

Market Acceleration

The commission’s order also authorized $310 million in market incentives to be administered by the New York Energy Research and Development Authority for pairing storage with solar projects, in addition to the $40 million announced in November. The order also directs the utilities to hold competitive procurements for 350 MW of bulk-sited storage systems.

PSC Chair John B. Rhodes said, “Energy storage is the key to unlocking renewables and reducing bottlenecks and costs on the grid. Today’s orders ramp up New York’s commitment and achievement, delivering bill savings for all New Yorkers while driving down carbon emissions.”

NYSERDA and the state’s Department of Public Service developed the PSC-mandated energy efficiency targets (Case 18-M-0084), which now include a 3% annual reduction in electricity sales by 2025 and 5 TBtu of savings from the installation of heat pumps, which help reduce emissions from the heating and cooling of buildings.

The commission also required that at least 20% of any additional public investment in energy efficiency go to help poor and middle-class New Yorkers gain access to renewable energy.

“New York’s clean energy industry welcomes today’s actions by the commission as important steps forward for energy storage and energy efficiency policy. Both are critical as New York continues its transition to a cleaner, more renewable and more efficient electricity system,” Anne Reynolds, executive director of the Alliance for Clean Energy New York, said in a statement.

In a separate ruling, the PSC approved Con Ed’s pilot smart meter pricing program (Case 18-E-0397) for customers in Staten Island, Westchester County and Brooklyn to be recruited by both opt-in and opt-out enrollment strategies and provided a one-year price guarantee. The program runs through March 2022.

December 16, 2018

MISO to Continue Resource Adequacy Talks in 2019

By Amanda Durish Cook

MISO will enter discussions with stakeholders in 2019 on long-term fixes to improve resource availability.

RTO staff said last week that the Resource Adequacy Subcommittee will focus on improvements to the Planning Resource Auction, loss-of-load expectation (LOLE) study and resource accreditation, including the possibility of seasonal resources. Since 2017, resource availability and need solutions have been discussed only in the Reliability Subcommittee. Now, MISO is ready for the RASC’s ideas on increasing generator availability as the baseload fleet ages and more renewable resources come online.

The discussions will be aimed at making available resources in addition to the 5 to 10 GW of supply MISO hopes to free up with a trio of near-term FERC filings.

Speaking during a Dec. 13 RASC conference call, MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO and stakeholders may examine how it calculates the planning reserve margin. Stakeholders asked if MISO would consider using something other than the summertime peak for the annual LOLE study, as the most recent emergencies and maximum generation events have occurred in shoulder months.

“That’s a good point. … We’re starting to see these max gen emergencies in non-peak time frames. What changes could we make to inputs to the PRA and the LOLE study to mitigate those risks?” MISO planning adviser Davey Lopez asked stakeholders.

Lopez said MISO will begin talking about improvements to the LOLE study next month. He said any changes to the study need to take place before June 2019, when the study kicks off for the 2020/21 PRA.

RASC Chair Chris Plante said MISO may need to coordinate discussion between the RASC and the LOLE Working Group — charged with reviewing and recommending changes to the LOLE study methodology — so stakeholders don’t suggest infeasible changes to the LOLE study process.

Customized Energy Solutions’ Ted Kuhn said MISO should issue a report that shows when it has fallen below 10 GW in reserves during recent emergencies, saying it would help stakeholders make suggestions for longer-term Tariff filings.

Lopez asked for stakeholder feedback and suggested adjustments to LOLE studies, capacity accreditation and PRA structure by Jan. 4.

MISO staff asked stakeholders to comment on changing the modeling of outages in LOLE studies, the modeling and accreditation of LMRs in the PRA, and whether the RTO should validate generator submissions to the Generating Availability Data System.

Near-term Filings

Talk also turned to MISO’s three near-term filings.

Earlier in December, stakeholders criticized MISO’s short-term solutions, which include requiring more data from certain load-modifying resources (LMRs) and imposing stricter notification times for planned outages. (See MISO, Stakeholders at Odds over Resource Availability Filings.) MISO’s LMR and outage filings are aimed at obtaining an additional 5 to 10 GW in resources during the spring maintenance season. MISO expects a large spring maintenance season and said that available spots for planned outages are going fast.

In all, MISO will make three Tariff filings aimed at short-term fixes: for demand response capability testing, LMR seasonal availability documentation and a new 120-day notice time for planned outages.

Rauch said some stakeholders have balked at MISO’s 120-day requirement, which would prohibit scheduling changes unless they don’t pose increased reliability risks. As a result, Rauch said MISO will defer the outage filing until no later than Jan. 31, still in time for a transition to the new rules in spring. The other two filings are expected to be submitted to FERC this week.

But Consumers Energy’s Jeff Beattie said the LMR filing still needs work. He said while MISO is proposing a two-year transition period for new testing for LMRs operating under non-retail tariff contracts, the RTO should also allow the same two years for Public Utility Regulatory Policies Act contracts. He said such PURPA contracts should be held harmless from the new rules until they expire. Staff said they would consider the request.

December 16, 2018

FERC Clears Cleco to Buy NRG Generation in South

By Amanda Durish Cook

FERC last week approved Cleco’s $1 billion acquisition of eight NRG Energy generation assets in MISO South, ruling the transaction will not have an adverse impact on rates or create market power concerns (EC18-63).

The deal is pending approval by the Louisiana Public Service Commission (U-34794).

Louisiana-based Cleco announced the acquisition early this year. NRG South Central Generating will hand over eight generating assets totaling 3,555 MW; transmission operations; and wholesale power contracts to nine Louisiana cooperatives, five municipalities in Arkansas, Louisiana and Texas, and one investor-owned utility.

Most of the plants will be operated by Cleco, except the 1,279-MW, natural gas-fired Cottonwood Generating Station in East Texas, which will be leased back to NRG, who will operate it until May 2025. NRG purchased the Cottonwood plant in 2010.

Cleco plans to create a new affiliate, Cleco Energy, to oversee NRG South Central Generating’s assets. Cleco had targeted a year-end close for the sale.

In issuing the decision, FERC considered that Cleco and NRG South Central Generating both own generation in MISO’s West of the Atchafalaya Basin (WOTAB) narrowly constrained area that frequently binds. FERC previously issued a deficiency letter over the transaction, requesting additional transmission constraint and price separation analyses for MISO South and the WOTAB load pocket. However, FERC concluded that the acquisition is “unlikely to have an adverse effect on competition … in any relevant market.”

In addition to the Cottonwood plant, the sale also includes the Big Cajun, Big Cajun II, Bayou Cove and Sterlington power plants in Louisiana.

In related orders issued the same day, FERC approved a change in upstream ownership to NRG plant operating subsidiaries for the Louisiana plants (ER14-2080-001) and the Cottonwood plant (ER14-1619-004). While FERC accepted informational filings on both, it opened an investigation and settlement proceeding into the plants’ reactive power rates, saying the rates may not reflect the degradation of the facilities’ capability. FERC also said Cottonwood’s reactive service schedule uses an outdated federal income tax rate.

December 16, 2018

PG&E Grapples with Line Safety After Camp Fire

By Hudson Sangree

PG&E last week reported additional problems with its transmission lines prior to the deadly Camp Fire, vowed to enhance its grid safety and asked state regulators to approve a more than $1 billion rate hike, largely to help it harden its grid against wildfires.

“We are acting decisively now to address these real and growing threats, and we are committed to working together with our regulators, state leaders and customers to consider what additional wildfire safety efforts we can all take to make our communities safer,” company CEO Geisha Williams said in a news release.

PG&E filed a supplemental report Dec. 11 with the California Public Utilities Commission, detailing problems with its lines near the Camp Fire on the morning the fire started. It also released the report to the public.

The Camp Fire killed 85 people and leveled the town of Paradise, Calif., making it by far the deadliest wildfire in state history. It started at 6:33 a.m. on Nov. 8 near Tower :27/222 on PG&E’s Caribou-Palermo 115 kV transmission line, the California Department of Forestry and Fire Protection (CAL FIRE) and PG&E reported.

NASA mapped damage to Paradise, Calif., from the Camp Fire, the deadliest wildfire in state history. | *NASA/JPL-Caltech*

For the first time publicly, PG&E in its report provided detailed information about the problems it experienced on that line and in other areas of rural Butte County preceding the Camp Fire.

“On Nov. 8, 2018, at approximately 6:15 a.m., the PG&E Caribou-Palermo 115-kV transmission line relayed and de-energized,” the company told the PUC. “At approximately 6:30 a.m., a PG&E employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by PG&E employees.

“In the afternoon of Nov. 8, PG&E observed damage on the line at Tower :27/222, located near Camp Creek and Pulga Roads, near the town of Pulga. Specifically, an aerial patrol identified that on Tower :27/222, a suspension insulator supporting a transposition jumper had separated from an arm on the tower. The suspension insulator and the transposition jumper remained suspended above the ground.”

State fire investigators denied PG&E access to the site for a week but eventually requested the company’s help collecting evidence from Tower :27/222 and the adjacent Tower :27/221, with PUC staff observing, the utility said.

“At the time of the collection at Tower :27/222, PG&E observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point,” PG&E wrote. “In addition, PG&E observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator.

“At Tower :27/221, there was an insulator hold-down anchor that had become disconnected. The insulator hold-down anchor is not an energized piece of equipment. After the evidence collection, CAL FIRE released the site. PG&E has not yet made repairs at either tower or restored service.”

Another incident occurred nearby on Nov. 8 at 6:45 a.m., when “the PG&E Big Bend 1101 12-kV circuit experienced an outage. Four customers on Flea Mountain were affected by the distribution outage,” the company said. The next day, a PG&E employee “observed that the pole and other equipment was on the ground with bullets and bullet holes at the break point of the pole and on the equipment.”

After the Camp Fire tore through Paradise in a single day, there was speculation that the Flea Mountain site or another site may have been a second ignition point for the Camp Fire, but so far those reports remain unverified.

PG&E said it’s continuing to investigate the Pulga Road and Flea Mountain incidents and two other reported problems with its equipment in the week following the Camp Fire.

“The cause of these incidents has not been determined and may not be fully understood until additional information becomes available, including information that can only be obtained through examination and testing of the equipment retained by CAL FIRE,” the utility said. “PG&E is cooperating with CAL FIRE.”

PG&E outlined its efforts to deal with wildfire threats in a report to the CPUC. | *PG&E*

In the meantime, PG&E said it would implement additional safety measures to decrease fire risks to threatened communities. The measures include inspections of more than 5,550 miles of transmission lines and 50,000 transmission poles and towers in risk-prone areas, increased vegetation management along its lines and more real-time monitoring of fire conditions.

By 2022, the company said, it will add 1,300 new weather stations, with one every 20 miles in high-risk areas, and install 600 high-definition cameras. The proposed steps align with measures already undertaken by San Diego Gas & Electric to prevent fires and avoid pre-emptive shutoffs of transmission lines in its service area. PUC President Michael Picker praised SDG&E’s long-term efforts Thursday and touted them as a model for the state’s other investor-owned utilities ahead of a commission vote to examine the practice of de-energizing lines in fire-prone conditions. (See Calif. Regulators to Scrutinize Line De-energization.)

PG&E is facing a snowballing number of lawsuits for the Camp Fire, billions of dollars in financial exposure for its role in 2017’s devastating wine country fires and talk of the state stepping in and breaking up the IOU and makings its pieces public. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.) It watched its stock price plummet in November before recovering some ground. (See Destructive Fire Drives Down PG&E Stock.)

The PUC said recently it would expand its probe into PG&E’s safety practices following the Camp Fire. That investigation started after the fatal explosion of a PG&E gas line in San Bruno, Calif., in 2010. (See CPUC Expands Probe into PG&E Practices After Deadly Fire.)

On Thursday, the company asked the PUC to approve a $1.1 billion rate hike to help pay for those additions and other upgrades as part of its 2020 General Rate Case before the commission.

“PG&E is asking for a $1.1 billion increase over currently adopted revenues for 2019” ($8.506 billion), the company said on its website. “More than half of PG&E’s proposed increase would be directly related to wildfire prevention, risk reduction and additional safety enhancements.”

Part of its Community Wildfire Safety Plan, the changes would include installing stronger poles and covered power lines across 2,000 miles of high-risk fire areas.

“As noted, this rate case calls for $1.1 billion in 2020, $454 million in 2021 and $486 million in 2022, respectively, to capture inflation and other cost escalation,” PG&E wrote. “If approved by the CPUC, this proposal would increase a typical residential customer bill by 6.4% or $10.57/month ($8.73 for electric service and $1.84 for gas service).”

The proposal doesn’t cover potential liability for the wine country fires or the Camp Fire, PG&E said.

December 16, 2018

MISO Prepping for Growth in Dynamic Line Ratings

By Amanda Durish Cook

MISO staff are considering how to respond to transmission owners’ adoption of dynamic line ratings, acknowledging that changes in systems and operations would likely be necessary with widespread use.

Acting on a recommendation from the RTO’s Independent Market Monitor, staff broached the topic with a presentation during a Dec. 13 conference call of the Market Subcommittee.

Operations engineering manager Jay Dondeti said MISO already allows TOs to submit dynamic line ratings, though most don’t. Dynamic line rating technology provides real-time data on environmental conditions near transmission lines, including ambient temperature, solar radiation and wind speed, allowing lines more capacity in cooler conditions.

Currently, TOs can provide line ratings to MISO through one of four ways: a seasonal ratings table with ratings for up to four seasons; a ratings lookup table based on temperatures; supplying specific ratings through the Inter-Control Center Communications Protocol; and submitting hourly and current day ratings through direct data files.

MISO staff and systems would not be able to process dynamic line ratings if every TO in its network decided to use them, and it’s unclear how much dynamic data the RTO can handle.

Widespread use is a long way off. Dondeti said about 93% of MISO TOs currently use seasonal ratings, with the “vast majority” of them providing ratings for two seasons, not four. He said less than 1% of line segments in the Midwest use some form of temperature-based ratings. In MISO South, however — where Entergy has adopted some temperature-based ratings using the filing approach — the percentage goes up to 5%.

Some stakeholders are echoing the Monitor’s calls to adopt dynamic line ratings. (See “Dynamic Line Ratings,” MISO Market Subcommittee Briefs: Oct. 11, 2018.)

“We see the transmission system as underutilized in the day-ahead and real-time markets because of static line ratings,” WEC Energy Group’s Chris Plante said.

Kevin Murray, representing the Coalition of MISO Transmission Customers, said dynamic line ratings might have helped the RTO mitigate some of its recent maximum generation events by transporting additional capacity stranded by static line ratings.

Entergy’s Mark McCulla said his company provides temperature-adjusted line ratings using historical and forecasted weather conditions near a facility to help increase the carrying capability of static line ratings. The company does not factor wind speeds into its more detailed ratings, instead using a 2-feet/second estimate. Entergy provides dynamic ratings to MISO on an hourly, daily and two-day-ahead basis.

“There can be a large swing in ambient temperatures in the Entergy region regardless of season. As a result, Entergy does not use seasonal ratings but instead uses the more granular temperature-adjusted ratings,” McCulla said.

Of Entergy’s more than 2,300 69-kV and above transmission facilities, 978 are in Entergy’s temperature-adjusted ratings database and 140 have short-term emergency ratings.

Entergy said it has experienced a 11% average increase over base facilities ratings when using temperature-adjusted ratings and a further 13% rating increase when coupled with short-term emergency ratings.

Plante asked if Entergy has experienced reliability risks since using the ratings. Entergy representatives said they have yet to experience an overload.

IMM staffer Michael Wander said the Monitor supports using temperature-adjusted ratings, saying MISO’s static line ratings are often conservative.

Wander agreed to appear at future MSC meetings to discuss the economic benefits of dynamic line ratings. He said the Monitor is not advocating a “one-size-fits-all” approach to ratings, but an RTO review process.

Dondeti said MISO will likely have to assess how it would handle the volume of ratings adjustments if dynamic line ratings become routine among TOs. He said it would need to figure out how often line ratings would be changed and how many staffers would need to process them.

RTO officials said they would report on the benefits and potential cost of processing dynamic line ratings in the first half of 2019. MSC Chair Megan Wisersky told stakeholders to expect discussion on the topic at upcoming subcommittee meetings.

December 16, 2018

NYISO Business Issues Committee Briefs: Dec. 12, 2018

By Michael Kuser

NYISO, PJM Win JOA Waiver Request

FERC last month granted NYISO and PJM a waiver of their joint operating agreement, allowing the two grid operators to add the East Towanda-Hillside tie line as a market-to-market flowgate (ER18-2442), Rana Mukerji, senior vice president for market structures, told the Business Issues Committee on Wednesday in presenting the monthly Broader Regional Markets report.

The temporary waiver permits NYISO Business Issues Committee Briefs: Oct. 10, 2018.)

The commission’s ruling also required the grid operators “to submit quarterly reports regarding the status of JOA revisions to implement a long-term solution.”

Reference Level Manual Changes

The BIC approved changes to three sections of the Reference Level Manual to comply with FERC Order 831.

Mitigation References Supervisor Giacinto Pascazio told the BIC the sections dealt with fuel-cost adjustments (FCAs), FCAs with generator bids in excess of $1,000/MWh and reference level development for demand-side resources.

The changes provide generators the ability to reflect updated fuel information to the ISO, which then automatically screens the FCA.

The ISO will reject energy offers above $1,000/MWh that lack FCAs. The changes also establish an FCA process for generators that do not burn oil or natural gas.

Validated cost-based reference levels from $1,000 to $2,000/MWh will serve as the bid cap, and any demand-side resource wishing to bid in excess of $1,000/MWh must initiate a consultation with the ISO 30 days prior to the start of the capability period.

A demand-side resource’s cost to reduce load should align with its discounted net revenues in the immediate future.

Real-time Market Settlements Clarifications

The BIC unanimously approved Tariff changes clarifying real-time market settlements and their interaction with energy storage resources (ESRs). ISO staffer Christopher Brown told the BIC that the changes — which are subject to approval by the ISO’s Management Committee later this month and by the Board of Directors in January — do not affect calculations or require software modifications.

Energy imbalance payments and charges address the differences among actual energy injections or withdrawals and real-time and day-ahead energy schedules.

The changes apply to ESRs injections and withdrawals and include terms that were introduced and defined in the ISO’s FERC Order 841 compliance filing submitted Dec. 3 (ER19-467). (See RTOs/ISOs File FERC Order 841 Compliance Plans.)

Natural Gas Prices Up 45% in November

NYISO locational-based marginal prices averaged $43.15/MWh in November, up just over 20% from October and 52% from the same month a year ago, Mukerji said in his monthly operations report. Day-ahead and real-time load-weighted LBMPs came in higher compared to October.

Year-to-date monthly energy prices averaged $45.11/MWh in October, a 30% increase from a year ago. November’s average sendout was 411 GWh/day in November, compared with 399 GWh/day in October and 403 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $4.23/MMBtu for the month, an increase of 45.4% over October and 44.8% from a year ago.

Distillate prices dropped compared to the previous month but were up 9.3% year-over-year. Jet Kerosene Gulf Coast averaged $14.50/MMBtu, down from $16.65 in October. Ultra Low Sulfur No. 2 Diesel NY Harbor was down to $14.72/MMBtu, from $16.66 the previous month.

November uplift increased to -27 cents/MWh from -30 cents in October, while total uplift costs, including the ISO’s cost of operations, were -30 cents/MWh, lower than -11 cents in September.

The ISO’s 25-cents/MWh local reliability share in November dropped slightly from 27 cents the previous month, while the statewide share climbed from -56 cents/MWh to -52 cents.

The Thunderstorm Alert cost in New York City was $0/MWh, compared to 75 cents/MWh in October.

December 14, 2018

CAISO Rev Requirement Shrinks, Despite RC Role

By Hudson Sangree

FOLSOM, Calif. — CAISO’s 2019 revenue requirement will be less than this year’s, despite hiring and costs associated with its planned new role as reliability coordinator for most of the West, staff members told the ISO’s Board of Governors on Thursday.

CAISO’s Board of Governors met Thursday in Folsom, Calif., to vote on the 2019 budget and to hear updates on next year’s policy initiatives. | © *RTO Insider*

The ISO’s proposed revenue requirement for 2019 is $193.5 million — $3.7 million less than in 2019. That’s within “the tight range that the ISO has maintained over the past 13 budget cycles and beneath the FERC-approved cap of $202 million,” CFO Ryan Seghesio wrote in a memo to the board.

Total outlays will grow to $230.9 million from $217.4 million in 2018, but new revenues from the RC business as well as increased gains from the Western Energy Imbalance Market and other increased revenues will offset that spending rise by $7.2 million. A $13.5 million operating cost reserve adjustment for overcollection this year will provide an additional offset.

April Gordon, CAISO’s director of financial planning and procurement, briefed the ISO’s Board of Governors on the 2019 budget Thursday. | © *RTO Insider*

Operations and maintenance costs will rise by $10.5 million, April Gordon, director of financial planning and procurement, said at the board meeting. CAISO CEO Stephen Berberich added that the additional spending was primarily from “adding headcount” for the ISO’s new RC component.

The ISO is set to take over RC services from Peak Reliability for the bulk of Western Interconnection states, starting in California in July. (See RC Transition Fraught With Pitfalls, WECC Hears.)

CAISO’s telecommunication, outsourcing and contract costs also will increase in 2019 because of the RC transition, Gordon told the board.

Another cost driver is the expansion of the EIM, with new entities joining the market and increasing administrative expenses, Gordon said. Powerex and Idaho Power began trading in the EIM this year, and the Sacramento Municipal Utility District will join in April 2019, she noted. (See Idaho, Powerex Began Trading in Western EIM.)

The board unanimously passed the ISO’s 2019 budget proposal. It also heard about 2019’s policy initiatives from Greg Cook, CAISO’s director of market and infrastructure policy. A major effort involves proposed changes to the day-ahead market, including 15-minute scheduling and flexible ramping.

Greg Cook, director of market and infrastructure policy, outlined 2019’s policy initiatives at the CAISO Board of Governors meeting Thursday. | © *RTO Insider*

“We’re looking at significant enhancements to our day-ahead markets,” Cook said.

CAISO Governor Angelina Galiteva asked Cook whether ISO staff were aligning their policy initiatives with outside developments, particularly California’s adoption of a rule requiring all new homes to have rooftop solar panels starting in 2020. The state Building Standards Commission approved the rule, the first of its kind in the U.S., on Dec. 5.

“It may catch up with us before we even know what’s going on,” Galiteva said.

In addition to solar panels, many households will eventually get in-home electricity storage units, she said. “My sense is people are going to start installing storage and a lot of it,” she said.

Berberich responded, “Governor, I think you’re probably appropriately worried.” He said behind-the-meter storage, linked to home solar panels, would complicate CAISO’s forecasting.

“Storage is going to be the biggest issue for us to sort out,” the CEO said. Policies may be needed to govern the charging and discharging of storage units, including financial incentives for homeowners, he said.

“I’m not suggesting we send real-time prices to retail customers,” he said. “I’m not sure that works.”

But policymakers may need to “signal to the retail level as best we can,” he said. “Then you can shape the behavior and usage.”