Page 1091 – RTO Insider

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, 2018November 13, 2023

ERCOT Board of Directors/Annual Meeting Briefs: Dec. 11, 2018

By Tom Kleckner

Staff Revisiting 2018 Playbook in Planning for 2019’s Slim Reserve Margins

AUSTIN, Texas — ERCOT is repeating many of the preparations it took before last summer — and adding others — as it looks ahead to even tighter reserve margins in 2019.

CEO Bill Magness told the Board of Directors on Dec. 11 that meetings have already begun with stakeholders as the grid operator begins preparations to take on summer load with an 8.1% reserve margin. Staff and stakeholders collaborated similarly last year to minimize generation downtime and ensure the availability of resources during the high-demand periods.

ERCOT’s 2017 year-end capacity, demand and reserves report revealed a 9.3% reserve margin. A 525-MW increase in generation capacity helped improve that margin to 11% before the summer season began. The grid operator met 14 new demand peaks above the previous record without resorting to emergency measures.

“As we did last summer, and with tight reserves expected, we’re going in and talking with all of you … on the things we can be doing and the things we can be doing together to make sure that we’re ready for a tight summer,” Magness said.

DeAnn Walker, chair of the Texas Public Utility Commission, has already coordinated meetings between the electric sector and gas pipelines.

Separately, ERCOT has made distributed energy resources and switchable units — interconnected to other regions but available to ERCOT — a point of emphasis. The board’s recently approved Nodal Protocol revision request (NPRR869) requires certain behind-the-meter generators over 1 MW to provide modeling information. Staff has also been working to clarify operating agreements with SPP and MISO over the use of switchable units.

“It’s incredibly important that your model reflect what is on your system when you have tight conditions, and you really need to know what to expect,” Magness said.

Another measure, NPRR901, part of the board’s consent agenda last week, adds a new resource status code for switchable resources operating in a non-ERCOT control area. Magness said a staff proposal, NPRR912, which is currently before the Protocol Revision Subcommittee, “will address the compensation issue for when units move back and forth.”

“That discussion has begun,” Magness said.

Addressing the shrinking reserve margin, Magness said there were no major retirements akin to 2017’s 4-GW loss of coal-fired capacity. He said a change in the calculation of emergency response reserve service, capacity deratings and delayed renewable and gas projects accounted for 2.5 percentage points of the 2.9-point drop in the reserve margin.

A 564-MW increase in the load forecast for the Far West Texas weather zone, fueled by oil and gas production in the reserves-heavy Permian Basin, represented almost a percentage point decrease in the reserve margin.

The growth has been fueled by the Permian Basin’s rich petroleum reserves, the largest in the U.S. Production has nearly doubled in the last three years, to 3.4 million barrels/day.

“We’ve been talking about Far West Texas load at every board meeting for at least a year, because we continue to see accelerating load growth in that area, an area with very little load until recently,” Magness said.

He noted the board has approved transmission projects in recent years to meet the growing demand. (See ERCOT Board of Directors Briefs: June 12, 2018.)

Revenues Up

ERCOT is looking at a $26.1 million favorable variance in net revenues, Magness said, mostly because of an $11 million gain in interest income and a $7.5 million jump in system administration fees.

“I wish I could credit that to our financial wizardry, but it is more that revenues have increased substantially over what was originally budgeted,” Magness said.

Staff used an interest rate of about 0.37% when they drafted the biennial 2018-19 budget. Magness noted rates have increased to a “shocking” 1.73% since then.

“That’s something, as we budget for 2020, we see ourselves correcting as we align that more with current interest rates,” he said.

New World of Gas Prices for Market

Beth Garza, executive director of ERCOT’s Independent Market Monitor, warned stakeholders that the market is “heading into a very different natural gas world.”

“We’re starting to see some very different gas prices than we’ve seen the last few years,” she said during her regular board report.

The Monitor uses Houston Ship Channel prices as its underlying index price. Garza said the index’s November prices are at $4.10/MMBtu after almost two years in the $2/MMBtu range.

The increase in gas prices has resulted in an accompanying 24% increase in average real-time energy prices, to $35.90/MWh through October. Prices were at $29/MWh a year ago, on their way to finishing 2017 at $28.30/MWh.

Forward prices for summer 2019 are also on the rise, Garza said, with $173/MWh prices for August as of Nov. 23.

“That’s not as high as we saw heading into July and August of last [summer], but we’re in December,” she said.

ERCOT Staff Share 5-Year Strategic Plan

Staff delivered an overview of the 2019-2023 strategic plan, telling the board and stakeholders that ERCOT’s leadership is setting up the organization to “quickly adapt to those changes that may come to us.”

“What we are required to do as an organization has not changed, but we must proactively change how we do things so that we can keep up with those things that are happening to us,” said Kristi Hobbs, ERCOT’s director of enterprise risk management and strategic analysis, who led the team.

The team solicited feedback from 200 stakeholders in drafting a plan that lists four objectives:

Enhancing operating capabilities to maintain reliability in an increasingly complex system;
Improving information exchange to facilitate collaboration;
Advancing competitive solutions to industry changes; and
Optimizing the use of ERCOT resources to “continuously provide high-value services.”

In an opening message, Magness wrote that there is no magic to the five-year time horizon, but that it “does require us to think far enough into the future to consider potential technological, economic and policy changes.”

2019 Board Members, TAC Reps Approved

Members approved and confirmed directors and segment alternates to the board for 2019 during ERCOT’s 48th Annual Membership Meeting.

Exelon’s Bill Berg and Direct Energy’s Ned Ross will join the board as segment alternates in the Independent Generator and Independent Retail Electric Provider segments, respectively. Berg replaces Luminant’s Amanda Frazier, and Ross steps in for VEH’s Mohsin Hassan.

Two board positions are vacant. The Consumer-Texas Office of Public Utility Counsel position is empty, following the recent departure of Tonya Baer, who has become the deputy director for the Texas Commission on Environmental Quality’s Office of Air.

The board also has a vacancy in the Unaffiliated segment.

The board previously confirmed the Technical Advisory Committee’s members for 2019.

The TAC will welcome Brandon Whittle (Calpine), Marty Downey (Electranet Power) and David Kee (CPS Energy) as new members. They replace Thresa Allen (Avangrid Renewables), Read Comstock (Source Power & Gas) and John Bonnin (CPS), respectively.

TAC will hold its meetings on the fourth Wednesday of the month next year, a switch from Thursdays.

Board Approves Staff Recs, 31 Change Requests

The board unanimously approved ERCOT’s key performance indicators for 2019 staff compensation and Schellman & Co.’s 2018 system and organization control audit report, which found no exceptions. It also approved two TAC-endorsed staff recommendations: an increase from 5% to 7.5% of the boundary threshold used in calculating load forecasts for Far West Texas, and removing a 1,375-MW floor on non-spinning reserves, part of the annual review of ERCOT’s methodology for determining ancillary service requirements. (See ERCOT Technical Advisory Committee Briefs: Nov. 29, 2018.)

The board also unanimously passed a consent agenda that included 14 NPRRs, a Load Profiling Guide revision request (LPGRR), two changes to the Nodal Operating Guide (NOGRRs), three Other Binding Document revisions (OBDRRs), four changes to the Planning Guide (PGRRs), a Retail Market Guide change (RMGRR), two revisions to the Resource Registration Glossary (RRGRR) and a system change request (SCR):

NPRR878: Emergency response service obligation report for transmission and/or distribution service providers.
NPRR879: Security-constrained economic dispatch base point, base point deviation and performance evaluation changes for intermittent renewable resources (IRRs) that carry ancillary services.
NPRR881: Reduces the residential validations requirements from an annual process to a triennial market event.
NPRR882: Procedures for wind and solar equipment change. (Related to PGRR067.)
NPRR884: Introduces systems changes needed to manage cases when ERCOT issues a reliability unit commitment instruction to a combined cycle resource that is already a qualified scheduling entity committed for an hour. The resource will operate in a configuration with greater capacity for that same hour.
NPRR887: Creates a new market information system certified area posting that provides insight into the potential risk associated with each counterparty’s default uplift charges.
NPRR892: Places a $75/MWh floor on energy for units carrying non-spinning reserve and responsive reserves and/or regulation up service concurrently to ensure the non-spin capacity is priced above the floor.
NPRR893: Clarification of fuel index price and incorporation of systemwide offer cap and scarcity pricing mechanism methodology into protocols.
NPRR894: Corrects the formula for allocating unaccounted for energy (UFE) to UFE categories by removing obsolete components.
NPRR895: Removes the current exclusion for IRRs that are not wind-powered in calculating the real-time ancillary services imbalance payment or charge. Photovoltaic generation resources are currently excluded in both the methodology for implementing the operating reserve demand curve to calculate the real-time reserve price adder and the process for settling the real-time ancillary services imbalance payment or charge.
NPRR897: Adjusts the black start service procurement and testing process timeline, adds a weather limitation disclosure form and aligns the load-carrying test procedure with actual practice.
NPRR898: Allows the electronic return of ERCOT-polled settlement metering site certification documents to the transmission and/or distribution service provider.
NPRR899: Creates a new process by which qualified market participants can opt out of receiving digital certificates and having to appoint a user security administrator (USA); clarifies ambiguous requirements certificate holders must meet to receive and continue to hold digital certificates; and clarifies that a USA may be responsible for managing access to certain ERCOT computer systems that do not require digital certificates.
NPRR901: Proposes a new resource status code (“EMRSWGR”) for switchable generation resources operating in a non-ERCOT control area to provide additional transparency for operations and reporting.
LPGRR065: Related to NPRR881, this change reduces the residential validations requirements from an annual process to a triennial market event and removes unnecessary load profile model approval process language.
NOGRR178: Clarifies language relating to automatic load shedding.
NOGRR182: Harmonizes the transmission operator emergency operations plan submittals with NERC reliability standard EOP-011-1 by clarifying that TOP plans should be received by Feb. 15 as part of the annual effort to review them within 30 days.
OBDRR006: Aligns language with NPRR884’s changes.
OBDRR007: Changes the ORDC’s methodology to consider curtailed PV resources in determining the ORDC price adders.
OBDRR009: Revises the online and offline capacity reserves for ERCOT out-of-market actions related to DC ties.
PGRR065: Documents and clarifies existing processes by including transmission project information and tracking report and data requirements.
PGRR066: Creates an inactive status generation interconnection or change request (GINR) projects that won’t be listed in ERCOT’s monthly generation interconnection status report but will retain the interconnection request numbers. Also defines a process that can be used to cancel interconnection requests that have failed to meet requirements.
PGRR067: Describes how wind and solar facility equipment changes are treated throughout the generation interconnection process and clarifies language for GINR-related fees.
PGRR068: Lays out the process for adding a DC tie to ERCOT’s planning models and associated requirements; related to the Texas PUC’s directive to determine how to model the proposed Southern Cross DC tie in its planning cases (Project 46304). (See “Staff’s Determination on DC Tie Flows, Pricing Gets OK ,” ERCOT Board of Directors Briefs: Oct. 9, 2018.)
RMGRR155: Related to NPRR889, the change uses the new term, settlement-only distribution generator (SOG), to replace references to non-modeled generator and registered distributed generation.
RRGRR018: Also related to NPRR889, uses the SOG term to replace glossary references to non-modeled generator.
RRGRR019: Adds a modeling designation for switchable generation resources (SWGRs) to the resource asset registration form, indicating that SWGRs can potentially operate in another control area.
SCR797: Allows ERCOT to automatically share current operating plans with a transmission service provider upon request by that provider.

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.”

December 14, 2018

Calif. Regulators to Scrutinize De-energization

By Robert Mullin

The California Public Utilities Commission (CPUC) on Thursday voted to examine its rules allowing the state’s investor-owned utilities to de-energize power lines in cases of dangerous wildfire conditions “that threaten life or property.”

The practice of de-energization will get a dedicated proceeding, separate from another rulemaking effort set out in Senate Bill 901 to address utility wildfire mitigation. De-energization will be discussed in the SB901 proceeding as one of a broader set of fire prevention measures.

“We can’t not act” on the de-energization issue, Commissioner Carla Peterman said during the Thursday voting meeting, her last with the commission. De-energization “is an option we don’t want to exercise often, but we do want the option to exercise.”

Commissioner Cliff Rechtschaffen said the issue was “worthy” of its own proceeding because de-energizing a line is a “significant event [with] significant consequences.”

“I support having this as a separate proceeding. … It is a requirement as part of the wildfire mitigation plans that the utilities now have to submit yearly that they include their de-energization protocols,” Rechtschaffen said. “[CPUC] President [Michael] Picker and I are the assigned commissioners partnered on the wildfire safety plans, and we’re committed to making sure that this proceeding is closely coordinated with that proceeding as we go forward.”

Proactive

The CPUC adopted the de-energization rules in July in response to the growing threat of wildfires throughout the state, especially in the expansive Pacific Gas and Electric and Southern California Edison service areas. Regulations around “proactive” shutoffs had previously applied only to San Diego Gas & Electric, which serves a historically highly fire-prone area.

“Since then, the topic of proactive power shutoff has reached a lot of people and has become a [hot] point of discussion,” CPUC Director of Safety and Enforcement Elizaveta Malashenko told the commission.

Among other mandates, the July rules require all IOUs to notify customers before de-energizing facilities and report to the commission after the fact (Res ERSB-8).

But Malashenko noted that industry stakeholders and members of the public have raised “a range of concerns” about the program, and that utilities are increasingly “proactively de-energizing” their lines. (See Fire Season Becomes Blackout Time in California.)

“In my mind, the type of issues that would come up in [this] rulemaking as related to de-energization is how much the utilities should be using that as a tool, as opposed to mitigating wildfires in other ways, such as introducing coated conductors or undergrounding lines, or increasing their ability to detect faults faster, and things like that,” she said.

A CPUC staff report on the new rulemaking indicates the proceeding will focus on:

Examining conditions under which planned de‑energization is practiced;
Developing best practices and ensuring an orderly and effective set of criteria for evaluating de‑energization programs;
Ensuring electric utilities coordinate with state and local level first responders, and align their systems with the Standardized Emergency Management System framework;
Reducing the impact of de‑energization on vulnerable populations;
Examining ways to reduce the need for de‑energization;
Ensuring effective notice to affected stakeholders of possible de‑energization and follow‑up notice of actual de‑energization; and
Ensuring consistency in notices of and reporting of de-energization events.

Digitize the Landscape

During the meeting, Picker emphasized the importance of learning from SDG&E’s experience from de-energization — without leaning too heavily on it.

“Utilities have always de-energized,” Picker said. “We have so far required them to plan a little ahead and to provide notification, but what could we learn from San Diego? What should be applied elsewhere? And how do we know what will work in other parts of the state?”

Picker pointed out that in order to avoid de-energizing lines, SDG&E “digitized the landscape” in its service territory.

“They put sensors in a number of places,” he continued. “They put weather monitors, wind monitors, moisture monitors and cameras in places you wouldn’t expect to see that. They began to collect information. They began to look carefully at very granular conditions in specific parts of their service territory at a much finer level than has ever been modeled before.”

Picker said SDG&E over time developed “a much finer sense of where and when to de-energize, and what were the consequences.” But he also acknowledged that SDG&E has a much smaller service territory than either PG&E and SCE.

“When you begin to look at the service territories of the other regulated utilities … we may be able to expedite their processes, but they’re still going to have to go through that data-monitoring, data collection, analysis, modeling and eventual testing process,” Picker said.

“I want to be honest about what we’ll be able to achieve. I don’t think we’ll have a perfect set of rules right away.”