Page 1291 – RTO Insider

August 4, 2017January 3, 2024

Stakeholders Hash out Future of DER at OMS Workshop

By Amanda Durish Cook

MADISON, Wis. — MISO state regulators and industry officials gathered this week to discuss how the region’s electricity sector will accommodate the budding growth of distributed energy resources within the RTO’s footprint.

While the outlook of participants at the Organization of MISO States’ Aug. 1 DER workshop ranged from cautious to optimistic, nearly all agreed that the industry could be confronting a profound transformation as energy resources become increasingly decentralized.

“DER, this is really just a fad, right? We don’t need to concern ourselves with this,” joked Wisconsin Public Service Commissioner Mike Huebsch. “In all seriousness, that’s what some were saying a few years ago, but it’s clearly not a fad.”

Missouri Public Service Commission Chairman Daniel Hall said DER is fast becoming a national policy issue.

“We are witnessing technological advances to accommodate the growing demand for DER,” he told a crowd of utility executives, regulators, renewable energy advocates and RTO officials at the workshop, sponsored by the Wisconsin Public Utility Institute and the Wisconsin Energy Institute.

“I think of this as potentially the creation of a new industry,” said Suedeen Kelly, a partner at the law firm Jenner & Block. DERs and microgrids are introducing electricity to far-flung regions of developing countries, she said.

“Is it going to be as dramatic a change in the U.S.? I don’t know yet. Are we going to move to a country of microgrids? Personally, I doubt it — but maybe,” Kelly said. “I think most of the decisions that state regulators have to make can fall into three categories: Who’s going to be allowed to own them? Who’s going to be allowed to dispatch them? How are they going to be compensated?”

Kelly said each state would likely tackle these questions on its own.

“We have a lot of time to figure out the dispatch question — who and how and all that,” said Mike Bull, director of policy at the Center for Energy and Environment.

Bull said he expects DER owners, rather than regulators, to come forward with policy ideas, noting that regulators are often reactive rather than proactive.

DER: Enemy — or BFF?

“DERs are advancing at a pace that I’m not sure any of us grasp,” said Lauren Azar, a former Wisconsin PSC commissioner, and current energy consultant and attorney.

Azar said states must work together to take the lead on policy issues and set aside regional differences. “It’s not surprising that whenever a huge new region comes into MISO, that it’s going to take some time to build some trust,” she said, referring to the integration of MISO South.

MISO Vice President of System Operations Todd Ramey said DERs could reach 20 GW in the RTO by 2030. MISO underestimated the adoption of customer DERs in its past modeling, he noted, and the RTO’s main concern remains forecasting substation-level requirements as early as possible, anywhere from two or three days to five minutes ahead ― a schedule MISO intends to maintain even with the increased penetration of DERs.

When Azar asked if anyone in the audience was surprised at the rate of electric vehicle adoption, she was met with a scattered raising of hands.

“OK, well you guys are more prescient than I am,” she said to laughter.

Azar said the grid is remarkable in its dynamism and ever-changing flows. “This year’s enemies are next year’s BFFs,” she said. “As state regulators, you have the luxury of taking the economic long view. You should not be driven by what your utility’s dividends are right now.”

Azar expressed regret about her 2011 vote against allowing aggregated demand response in Wisconsin and said she now realizes DR strengthens the nation’s grid and economy. She advised states against becoming too wrapped up in their own needs to notice what is good for the nation as a whole.

She noted that last year’s Notice of Proposed Rulemaking requiring RTOs to remove market barriers for storage and DERs indicates that FERC is inclined to allow for state regulation of aggregated DERs and energy storage above 100 kW. The NOPR is reminiscent of FERC Order 719, she said.

She advised states to encourage a regulatory structure in which new technologies are allowed to “bubble up” in non-discriminatory fashion and are properly monetized.

The Elvis Paradox

Tim Noeldner, WPPI Energy vice president of rates and special projects, said his company expects “slow and steady growth” in DERs and will leave a small planning gap for the resources to fill. “We go into the future a little bit short,” he explained.

Entergy Director of Regulatory Research Andrew Owens said 4% of New Orleans households with rooftop solar are spread throughout all socioeconomic corners of the city, a result of falling costs and generous tax credits.

“Is that an opportunity or a threat? Right now, we have no grid visibility of it other than locations and zip codes. We can do desktop modeling of it, but it’s not real,” Owens said. He said a mix of policy, pilot projects and partnerships are needed for a steadier transition, and can help scale New Orleans Mayor Mitch Landrieu’s lofty climate action goal of 255 MW of solar capacity within the city in the next decade, up 215 MW from today.

Owens also cautioned against the simple extrapolation of present DER trends, referring to the “Elvis Presley Paradox,” which he said holds that the number of Elvis impersonators increased from about 30 at the singer’s death in 1977 to around 50,000 by the mid-1990s — a growth rate that would translate into every third person in the world being an Elvis impersonator by now.

At some point, Owens said, there won’t be usable space for solar, and a willing tide of customers will abate.

Former FERC Commissioner Tony Clark, now a senior adviser with law firm Wilkinson Barker Knauer, said DERs could affect the future in one of three ways.

“You can make a case that things will look not much different than today ― I don’t think that’s the case,” he said. On the other hand, one could assume the “Elon-Musk-on-steroids version of the world takes over,” and electric vehicles are in every garage and residential heaters are able to store energy, making houses self-contained units.

Future reality is likely to be found somewhere in the middle, according to Clark.

“I personally think the most likely scenario is, moving forward, you literally have more power at the edges of the grid and figuratively more power in the hands of the consumers. … It’s still a network grid, but a more nimble grid,” Clark said. “I’d think that’s the most likely scenario. … Distribution services will still play an extraordinarily important role.”

University of Wisconsin engineering professor Bob Lasseter, who studies the penetration of DERs, said that microgrids provide the most promising means of integrating substantial amounts of distributed sources. However, a decentralized grid works best autonomously — not micromanaged by grid operators — and spared from extensive communications and controls.

“I believe that this bottom-up model is really going to work,” Lasseter said. “Microgrids are getting killed because there’s too much managing of loads.”

Supersized Battery

Residential DERs can help grid planners avoid costly transmission projects by lowering demand, said Amy Heart, director of public policy at solar advocacy group SunRun. “Imagine having customers excited about rate cases because they’re helping to generate savings,” she said.

Kelly said that the electric industry has traditionally rewarded investment because expansion has long been necessary. “Now? Not so much,” she said, adding that the industry needs to find methods to reward avoiding costly investments.

Grid investment is still paramount, Michigan Public Service Chairman Sally Talberg said, and new technologies to accommodate DERs could be incorporated into the upgrade of Michigan’s aging infrastructure.

“We’ve got breakers that are 70 years old. … It’s like driving a car without a steering wheel ― and this is not an autonomous car,” Talberg said. She envisioned grid upgrades that accommodate two-way energy flows and the grid itself upgraded to become “a large storage battery.”

More Visibility, Please

RTO executives, meanwhile, are seeking historical and operating data to plan for DERs.

Resource visibility is the key to modeling grid planning, MISO’s Ramey said. “I need to know where it’s at, what size and dynamic impacts,” he said. “Today, MISO has no role in integration [of DERs], but we need that data to ensure reliability.”

CAISO Manager of Transmission Planning Jeff Billinton said DER information needs to be incorporated into transmission planning and NERC reliability models years in advance. ERCOT Chief Operating Officer Cheryl Mele said RTOs need to know whether it will be the resources or the distribution companies that will provide production data.

Utility executives are also calling for more DER visibility.

Joe McGovern, Alliant Energy’s director of electrical engineering, said DER use is no longer a simple issue of interconnection. “It went from an engineering problem to a broader market issue very quickly,” he said. Stakeholders, generation owners, customers and developers must be educated on the potential impacts. He said he’d like to see a distribution system that runs like a software platform and is easily accessible.

Commonwealth Edison Director of Energy Policy Chris Foley said his company is giving “a lot of thought to the utility of the future” but is not yet moving to a distribution system operator model in which the utility co-optimizes distributed resources.

Baked-in Distribution Costs?

Clark said he said he would attempt to make attendees “uncomfortable,” reminding them that FERC could intervene and issue regulations for DERs if their growth went unchecked and had an adverse impact on rates.

“Consider me the Scaramucci of the workshop,” he joked, referring to the foul-mouthed former White House communications director.

“I thought he was going to cuss like Scaramucci did,” Arkansas Public Service Commission Chair Ted Thomas teased.

“That was the Midwestern version,” Clark replied.

Noeldner said WPPI supports a retail rate in which distribution costs are built in.

EnerNOC Director of Regulatory Affairs Greg Geller added that DER-owning customers need to reap the financial benefit of the value they are helping to create and suggested attaching a value to “peak shaving,” when customers help reduce demand at peak times.

State regulators must recognize the “push and pull” of customers influencing policy, said Tyler Huebner, executive director of Renew Wisconsin. “What we see is, the worse the net metering policies are [in a state], the bigger rush there is to install storage,” Huebner said.

OMS Executive Director Tanya Paslawski said the DER workshop served as a “good starting point” for future discussions within her organization. RTO officials last month asked OMS for policy ideas on a common DER definition and market rules. (See “MISO Asks OMS for DER Ideas,” OMS Issues EE Market Participation Opinion.)

“We’re not in any emergency situation in MISO ― or any RTO for that matter ― but this is something that is picking up steam … and there are a lot of moving parts to consider,” Paslawski said.

MISO participants will resume their DER conversation again in September at a full board meeting in which stakeholders will debate DER treatment as a “hot topic” discussion item. The RTO also continues to develop a common definition and market rules for the participation of energy storage in its markets. (See MISO Rules Must Bend for Storage, Stakeholders Say.) MISO’s Steering Committee last month voted to approve the creation of an energy storage task force, which will report its findings and discussions back to the committee.

August 3, 2017

Solar Eclipse Prep Nearly Complete at CAISO

By Robert Mullin

CAISO is nailing down its final preparations for the Aug. 21 solar eclipse, which is expected to take about 5,600 MW of utility-scale and rooftop solar generation off the California grid during morning hours when those resources would typically be ramping up output.

Still, the grid operator expressed confidence in its ability to avoid service outages stemming from the event, despite having to support an upward ramp of about 70 MW/minute heading into the eclipse and a downward ramp of 90 to 100 MW/minute coming out.

“We will ramp up generation to compensate for lost solar production, and there is plenty of capacity to meet need,” the ISO said in a FAQ published on its website. “It is not unusual for the ISO grid operators to manage ramps this large on certain days.”

CAISO currently has about 10,000 MW of utility-scale solar interconnected into its system, and its typical morning ramps average about 29 MW/minute.

The extra capacity will mostly come from traditional generating resources. (See CAISO Solar Eclipse Prep Relies on Conventional Mix.) With California’s water levels still relatively high after a wet winter, CAISO expects to have access to about 6,000 MW of flexible hydroelectric capacity in mid-August. The ISO has also been working with gas pipeline companies, utilities and generators to procure additional reserve and regulation capacity, both of which will be needed to grapple with the potential for oversupply and frequency regulation issues after the eclipse, as solar rapidly ramps up its output.

Tasks Completed

Begun last year, CAISO’s preparations for the eclipse have been extensive.

The ISO said it has consulted with the forecasting team that helped grid operators in Europe prepare for a 2015 eclipse, which especially affected Germany’s 40 GW of installed solar capacity. The ISO has developed its own event-day forecast using Aug. 22, 2016 — also a Monday — as the basis for projecting expected demand the morning of the eclipse. The ISO’s model assumes full sun, no “extraordinary” conservation measures and higher obscuration rates (representing the proportion of the sun obscured by the moon) in Northern California, along with a corresponding loss with rooftop solar output there.

caiso eclipse rooftop solar — The eclipse will have its greatest impact on solar generation in Northern California, where “obscuration” rates will be above 75%. | *CAISO*

The ISO has also completed a market simulation for the day of the eclipse and conducted “tabletop exercises” and training for real-time grid operators. It has also refined its renewable forecasts — in part by comparing them with third-party forecasts — and coordinated with natural gas companies to plan for increased output from gas-fired power plants.

The grid operator is also working with Western Energy Imbalance Market (EIM) participants to “incorporate eclipse impacts in their power schedules, maintain full operational energy transfers, and collaborate on forecasting.” CAISO expects the eclipse to have some impact on 1,700 to 2,000 MW of solar generation in neighboring EIM areas.

Still to Come

A week ahead of the eclipse, CAISO plans to “refine” its resource and load forecasts and update market participants about any changes to its reserve needs. Two days before the event, it will hold a conference call with market participants “to facilitate coordination and transparency,” the FAQ said.

Finally, on the morning of the eclipse, the ISO will ensure that its real-time forecasts are transferred into the ISO system in order to prepare generation and optimize the transmission network.

And while the ISO is not expecting the need for conservation measures, it did encourage electricity consumers to keep those measures in mind on the day of the eclipse.

“The ISO predicts the typical consumer will not notice the grid management challenges and balancing strategies,” CAISO said. “However, energy efficiency is always helpful to curb spikes in need for power and to lower consumer electricity bills during times of high demand.”

August 3, 2017

Va. Data Centers, Residential Growth Boost Dominion Demand

By Rich Heidorn Jr.

Data centers and residential customer growth are driving increased electric demand for Dominion Energy in Virginia, with weather normalized sales up about 2% for the first half of the year.

New customer connections in the first six months jumped 7% over 2016, and the company connected five new data centers between April and June, company officials said in their second-quarter earnings call Wednesday.

CEO Thomas Farrell said an anticipated increase in federal defense spending under the Trump administration would “provide strong support for the Virginia economy, which is the largest recipient of defense dollars in the nation.”

“All of these factors support our expectation that annual electric sales growth of at least 1% will continue,” Farrell added.

The company reported second-quarter earnings of $390 million ($0.62/share), a drop from last year’s $452 million ($0.73/share). Operating earnings for the quarter were $421 million ($0.67/share) versus $441 million ($0.71/share) for 2016. The main difference between reported and operating earnings were costs related to Dominion’s acquisition of Questar.

Operating revenue was $2.81 billion, up 8% from almost $2.6 billion a year earlier. The company is predicting earnings growth of at least 10% in 2018.

Transmission spending will contribute to that growth. Dominion added $327 million in transmission assets in the first half of the year, and the company plans to invest $800 million in transmission annually for at least the next decade.

Extensions for Va. Nukes, Subsidy for Millstone Sought

dominion energy virginia — Cove Point Liquefaction Project | *Dominion Energy*

Farrell said company officials are “working very hard” to win financial support from Connecticut lawmakers for its Millstone nuclear plant. He did not respond to an analyst’s question on whether the company would share Millstone’s financials to rebut criticism that the plant is already profitable and doesn’t need assistance.

However, he said the company will participate in the study ordered by Gov. Dannel Malloy last month. The state’s Department of Energy and Environment and Public Utilities Regulatory Authority are to report to the legislature on the plant’s financials in January 2018. (See CT Gov Orders Financial Analysis of Millstone Plant.)

Paul D. Koonce, CEO of Dominion’s Power Generation Group, said that the timing of legislative action depends on the resolution of the Connecticut budget, which he hopes lawmakers will complete by Labor Day.

Meanwhile, the company has begun the process for winning license extensions for its North Anna and Surry nuclear plants in Virginia. Officials said state legislation will allow the company to recover through a rate rider the costs of extending the plants’ lives, which could be as much as $4 billion.

Company officials also provided updates on several projects:

Farrell reiterated the company’s plans to add as much as 2,000 MW of offshore wind if two test offshore wind turbines planned for 26 miles off Virginia Beach “demonstrate that they work well in these waters and produce the kind of capacity that we expect.” (See Dominion Plans 12-MW Offshore Wind Project, 2nd in US.)
The Cove Point Liquefaction Project is 95% complete, on target for the beginning of commercial service later this year.
Construction of the Atlantic Coast Pipeline project should begin in November, assuming FERC restores its quorum by the end of September. “There’s certainly some vocal opposition in some isolated localities, but overall, folks in Virginia support the pipeline as they do in West Virginia [and] North Carolina, and we expect to get all the necessary permits later this fall,” Farrell said. Dominion won’t discuss potential expansion of the pipeline until it has the FERC permit in hand, he said.
The 1,588-MW Greensville County combined cycle plant is almost half complete and is on time and on budget with commercial operations expected late 2018.
The company said it expects to select sites later this year for one or more pumped-storage facilities in Southwest Virginia. The General Assembly approved recovery of the facilities’ costs through a rider.

dominion energy data centers virginia — Greensville County combined cycle plant construction | *Dominion Energy*

Solar

The company said data centers, military installations and the state government are driving demand for renewables. Three facilities totaling 119 MW went into commercial operation in the second quarter. In total, the company expects to add 438 MW of solar this year and another 200 MW by the end of 2018, bringing its total to 1,800 MW. The company’s integrated resource plan calls for up to 5,000 MW of solar by 2032.

“Solar uses a lot of land, and that’s beginning to become obvious to people as maybe not quite as obvious to folks in the West, where vacant land is abundant,” Farrell said. “So we’re exploring all of our options to meet our customers’ demands for decades to come. That’s part of why we’re looking at the relicensing of North Anna and Surry as well, and pump storage in the Virginia mountains.”

On Thursday, the company announced it has acquired two 5-MW solar facilities and plans to purchase two other solar farms totaling 10 MW later in the third quarter from Strata Solar, of Chapel Hill, N.C.

[Editor’s note: Quotes from the earnings call are according to a transcript by Seeking Alpha.]

August 3, 2017

Entergy Q2 Earnings Beat Expectations

By Tom Kleckner

With its merchant nuclear power plants all but part of history, Entergy reported second-quarter earnings Wednesday that almost doubled investor expectations.

The New Orleans-based company said second-quarter profits were $409.9 million ($2.27/share), compared with $567.3 million ($3.11/share) a year ago. A Zacks Investment Research survey of Wall Street analysts had forecasted earnings of $1.20/share.

Entergy took a $152.3 million loss related to its plans to sell or close its five Entergy Wholesale Commodities nuclear plants. (See Entergy, Consumers Announce Closure of Palisades Nuke and Entergy to Shut Down Indian Point by 2021.)

At the same time, the company has received final regulatory approval to build a pair of nearly identical 990-MW combined cycle gas-fired plants in Louisiana and Texas. The Lake Charles Power Station in Westlake, La., is expected to go online in 2020, while the Montgomery County Power Station near Houston should begin operations in 2021.

entergy earnings q2 2017 — Entergy’s Vermont Yankee nuclear plant, closed in 2014.

“These projects will contribute to our portfolio transformation efforts to replace older, less efficient plants with new generation,” Entergy CEO Leo Denault told analysts during a Wednesday earnings call, pointing to state-of-the art emission controls that capture and use waste heat to boost generation. “They are an important part of our strategy to meet our voluntary commitment to develop an electric system that is well-positioned to operate in a carbon-constrained economy.”

Denault said the two plants are expected to provide Entergy’s Louisiana and Texas customers at least $3 billion in combined net benefits and lower production costs. The plants are also expected to provide thousands of jobs during construction and generate more than $2 billion in economic activity for their local communities, he said.

Entergy has also amended its application for the proposed New Orleans Power Station, which has encountered opposition from the City Council. Denault said the company has renewed its request for the original 226-MW combustion turbine but also proposed a 128-MW unit as an alternative.

August 3, 2017

Exelon Confident on ZECs; Will Seek PJM Changes

By Rich Heidorn Jr.

Exelon officials said Wednesday they will press PJM to enact rule changes boosting off-peak prices and are confident nuclear subsidies in New York and Illinois will survive court challenges.

The comments came as Exelon reported second-quarter earnings of $80 million ($0.09/share), a drop from $267 million ($0.29/share) a year earlier, as its generation division saw a $250 million loss.

Adjusted operating earnings for the quarter were $509 million ($0.54/share), down from $604 million ($0.65/share) in 2016, reflecting the end of the reliability support services agreement for its R.E. Ginna nuclear plant in New York, increased nuclear outage days and lower realized energy prices. Those negatives were partially offset by rate increases that boosted utility earnings and zero-emission credit revenue ($0.05/share) for the Ginna, Nine Mile Point and James A. FitzPatrick nuclear plants beginning April 1.

Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy, said federal district court rulings rejecting challenges to the New York and Illinois ZEC cases suggested opponents will have a difficult time prevailing on appeal.

“The district court decided these cases at a very preliminary stage, whereas a legal matter the courts had to assume all the facts that the plaintiffs pled were accurate. Those facts were not accurate, but even under the plaintiffs’ versions of the case, the courts found that they had no legal claim whatsoever,” Dominguez said. “In both decisions, the district courts rejected the entire waterfront of the plaintiffs’ claims beyond the … procedural issues. That speaks to how high a hill they will need to climb on appeal to reverse those decisions.”

David Gaier, spokesman for plaintiff NRG Energy disagreed. “We don’t think we’re down for the count at all,” he said.

Initial briefs are due Aug. 28 in the plaintiffs’ appeal of the ruling on the Illinois ZECs, pending before the 7th U.S. Circuit Court of Appeals. The plaintiffs plan to ask the 2nd Circuit Court to review the New York ruling.

Lobbying Position Improved

Dominguez said the court rulings have helped Exelon’s lobbying posture in other states considering ZEC-type programs. He said opposing lobbyists have cited the legal questions as risks for policymakers, saying “‘Why would you take a tough vote on this only to have it overturned in the courts?’ These decisions resolve that issue.”

CEO Chris Crane said “we remain hopeful” that Pennsylvania officials will enact similar subsidies to prevent the closure of Three Mile Island. (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)

Dominguez said, however, that pricing carbon emissions in the wholesale markets would be preferable to ZECs. “It’s more clear to us now than ever that federal wholesale markets need to evolve to fully incorporate attributes like resiliency, fuel diversity and the environmental qualities of the generation resources. If the markets don’t evolve, then the markets are going to have a diminished role in energy policy going forward. We are committed [to markets] but the markets should be well-functioning. Our commitment to markets only extends so far as it provides the best outcomes for our customers.”

Dominguez said the company was heartened by PJM’s plan for energy market changes that would allow baseload generators such as nuclear plants to set clearing prices in off-peak hours. The RTO has said it will file the changes with FERC by the first quarter of 2018, with implementation targeted by summer 2018. “We are going to push very hard to make sure that happens,” promised Dominguez, who said the changes should increase off-peak energy prices and reduce capacity prices. (See RTOs to Congress: Don’t Lose Faith in Markets.)

Not Considering GenCo Spin-off

Crane said that although Exelon believes it is undervalued by Wall Street, it is not considering spinning off its generating unit into a separate company. He cited the “synergies” between its generation fleet and its distribution utilities. Exelon noted that all its utilities scored in the top quartile of the Customer Average Interruption Duration Index and that Baltimore Gas and Electric and Commonwealth Edison achieved their best-ever System Average Interruption Frequency Index scores.

“We are differentiating ourselves from any other merchant generator in the business. [We have] strong balance sheets, a different class of assets, very well run and fairly matched to our load books. So, we like where we’re at and wouldn’t speculate on anything else,” he said. We “really can see the value creation and want the market to recognize it as we do execute on what we say.”

CFO Jack Thayer told analysts Exelon believes future power prices will be higher than suggested by forward curves, whose liquidity has declined over the past year. Trades for 2020 and beyond represent only 6% of the futures volume at the PJM West hub on the ICE and NASDAQ exchanges, he said.

“We would note that our fundamentals group has a more constructive view on power markets than these illiquid forward curves suggest, but we appreciate that there is perceived safety in using the forwards,” he told the stock analysts on the call. “However, when running your numbers, we would just encourage you all to appreciate what is underpinning those forward prices.”

August 2, 2017

CAISO Leads EIM Q2 Benefits, Exports

By Robert Mullin

CAISO hauled in the largest share of the $39.52 million in benefits produced by the Western Energy Imbalance Market (EIM) during the second quarter, the grid operator said in a report released Monday.

The ISO was also the market’s dominant exporter of energy over the period as California coped with combined surpluses of solar and hydroelectric output on its system after a wet winter.

CAISO took in $15.49 million in benefits, compared to $8.81 million for PacifiCorp, $8.13 million for Arizona Public Service and $2.47 million for Puget Sound Energy. NV Energy’s estimated $4.62 million in benefits did not include data for June, which is still pending verification.

EIM CAISO exports pacificorp puget sound — | *CAISO*

The EIM’s total benefits increased by $8.52 million — or 27% — over the first quarter. (See CAISO EIM Exports Rise With Spring, Report Shows.) That spread will increase with the addition of NVE’s June figures.

The gross benefits represent either cost savings for serving load or increased profits from merchant operations within the EIM’s participating balancing authority areas (BAAs). The market’s ability to reduce curtailments also enables participants to collect renewable energy credits that would not otherwise be issued.

The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.

CAISO exported more than 1.11 million MWh of electricity in the EIM’s five-minute market during the quarter, the report shows. Most of that energy was transmitted into NVE’s territory to be wheeled into the PacifiCorp-East area, but APS also absorbed a significant portion. The inclusion of APS and PSE last October greatly increased the transfer capability within the EIM, improving California’s ability to move its solar surpluses into other areas of the West.

That export capability enabled CAISO to avoid curtailing 67,055 MWh of renewable output from April to June, displacing 28,700 metric tons of CO₂emissions , the report said. The ISO estimates that, since 2015, avoided curtailments from EIM operations have reduced carbon emissions by 204,941 metric tons, the equivalent of removing more than 43,000 passenger cars off the road for a year.

CAISO’s exports are likely to decline sharply this summer as California absorbs more of its own renewable output in the face of increased summer loads, a pattern seen last year. (See PacifiCorp Increases Share of EIM Benefit in Q3.)

The report also noted the EIM’s impact on the procurement of flexible ramping capacity, which represents resources capable of responding to the variable output of renewable generators.

Because variability can decrease in one BAA at the same time that it’s increasing in another, the EIM enables participants to share flexible resources — allowing each BAA to procure fewer resources than would have been necessary on a standalone basis. These “flexible ramping procurement savings” during the second quarter represented about 39% of what would have been the total requirement of the participating BAAs absent the EIM, the report showed.

The EIM has yielded $213.24 million in gross benefits since commencing operation in November 2014 with PacifiCorp as its first member.

August 2, 2017

Day-ahead Prices Going Negative in CAISO

By Jason Fordney

Negative day-ahead prices surged in CAISO during the first quarter as combined surpluses of solar and hydroelectric output frequently left the market upside-down.

Prices went negative during 51 hours in the day-ahead market over the three-month period, compared with just three hours in all of last year, the ISO’s Department of Market Monitoring said.

“This is something we first just started seeing in this quarter,” Senior Analyst Gabe Murtaugh said during a July 31 call to discuss the department’s first-quarter report.

Negative prices indicate that the cost to procure wholesale power was at or below $0/MWh, which happens when there is an oversupply of solar power and other renewables while demand is relatively low.

Negative prices occurred in the day-ahead market during about 10% of the hours in the 11 a.m. to 3 p.m. time frame during the first quarter. They also happened more frequently during weekends when electricity loads were lower.

day-ahead prices caiso day-ahead market — | *CAISO*

Real-time prices also dipped frequently into negative territory during the quarter, occurring at about 10% of intervals in the 15-minute market and 13% of intervals in the five-minute market.

The negative pricing has become central to the debate around renewables in California, with some arguing that it is the result of a rush to integrate renewables without completely accounting for or understanding their impact on reliability and markets.

CAISO average energy prices decreased sharply in the first quarter, from about $35/MWh in December 2016 to about $23/MWh in March. This coincided with increased renewable output and low loads, the Monitor said. Prices in the 15-minute market are consistently lower than day-ahead prices and moved in about the same direction and magnitude each month.

“On average, five-minute market prices in March were notably low at about $17/MWh. This was the lowest average monthly five-minute market price during the past several years,” the Monitor said in the report.

CAISO also curtailed more renewable generation in the quarter, rising to a high in March of nearly 6%, compared with peak curtailment less than 3% a year earlier. Renewable curtailment rose above 80,000 MWh in both February and March, compared with less than 60,000 MWh in March 2016, according to ISO data.

During nearly all first-quarter intervals when prices were negative, the market economically dispatched generation down and CAISO did not have to curtail self-scheduled generation.

day-ahead market day-ahead prices caiso — Rooftop solar and other renewables pushed up negative prices in CAISO in the first quarter

Prices at times surged above $750/MWh at certain times because of generator ramping limitations when solar resources rolled off the system at sunset.

“During these intervals, steep increases in net load exceeded flexible ramping capacity procured through the flexible ramping product and required the power balance constraint to be relaxed because of insufficient available incremental energy,” the Monitor said.

Congestion in the Western Energy Imbalance Market (EIM) continued to isolate PacifiCorp-West (PACW) from CAISO and PacifiCorp-East (PACE), the Monitor said. This drove down prices in PACW and Puget Sound Energy compared with the ISO and the rest of the EIM.

Arizona Public Service and PSE joined the EIM in October 2016, adding new transfer capacity. This reduced congestion between APS, CAISO and PACE, the Monitor said. EIM market prices in the APS area were close to those in NV Energy, PACE and CAISO.

The Monitor earlier this month said that bid limits placed on PacifiCorp, NVE and APS are no longer needed because of increased transfer capacity in the EIM. (See CAISO Monitor Says EIM Bid Limits No Longer Needed.)

The report reiterated the Monitor’s recommendation that the ISO’s congestion revenue rights auction be eliminated and replaced with a market or locational price swaps based on bids for CRRs. (See CAISO Monitor Proposes End to Revenue Rights Auction.) CAISO is in the midst of an initiative to investigate the efficiency of the auction.

August 1, 2017

PSEG Sees Support for Nuclear, to Seek Revenue Decoupling

By Peter Key

Public Service Enterprise Group CEO Ralph Izzo said last week that the company has received “just about universal support for the continued operation” of its nuclear plants.

Speaking during the company’s second-quarter earnings call on Friday, Izzo also revealed that PSEG’s Public Service Electric and Gas plans to ask the New Jersey Board of Public Utilities to decouple its distribution revenue from its sales volume to enable it to support large-scale investments in energy efficiency.

PSEG — which owns the Hope Creek Generating Station and 57% of the adjacent Salem Nuclear Generating Station in New Jersey, and 50% of the Peach Bottom Atomic Power Station in Pennsylvania — wants financial compensation for its emissions-free generation, which it says is at risk from low power prices.

PSEG nuclear power — Salem & Hope Creek Nuclear Reactors on Artificial Island

Izzo said it’s good that the Department of Energy recognizes a challenge “with baseload generation and fuel diversity,” which will be the subject of a report the department plans to release soon. He called “the recent PJM proposals on how to deal with inflexible units … potentially quite helpful.” (See New York ZEC Suit Dismissed.)

Still, Izzo said, “the problem, according to the forward price curve, is at New Jersey’s doorstep, and there’s no denying it.” As a result, he said, PSEG will “continue to educate stakeholders at the state level about the need to preserve the diversity and resiliency of our electric generating mix.”

PSE&G will make the decoupling request in a rate case it plans to file no later than Nov. 1. A growing number of utilities are seeking to decouple their revenue from their sales. The move enables them to get the money they say they need to maintain their infrastructure even if their sales are flat or declining. In California, for example, utilities receive incentives to encourage their customers to use renewables and conserve electricity.

PSEG earned $109 million ($0.22/share) in the quarter, down from $187 million ($0.37/share) in the second quarter of 2016. The company said its most recent figures were affected by accelerated depreciation associated with the June 1 retirement of its last two coal-fired generating stations. PSEG’s revenue in the most recent quarter was $2.13 billion, up from $1.91 billion a year ago.

August 1, 2017

Texas Heat Leads to more ERCOT Demand Records

A Central Texas heat wave is leading to surging demand for electricity, helping ERCOT continue its streak of breaking demand records.

The Texas grid operator’s latest record came Friday when it reported 69,525 MW of demand between 4 and 5 p.m., the fifth time in July it exceeded last year’s mark of 67,469 MW.

ercot texas demand records — ERCOT operators monitor the Texas grid. | © *RTO Insider*

Temperatures in Austin, where ERCOT is headquartered, hit 105 F on Sunday, breaking a 60-year-old record for the date and marking the 13th straight day of triple-digit heat. Nearby San Antonio broke heat records Saturday and Sunday with temperature readings of 105 and 104 F, respectively. The previous records were set in 1950 and 1946, respectively.

On Saturday, ERCOT broke the weekend peak demand record by nearly 1,500 MW when it recorded a preliminary total of 68,413 MW between 4 and 5 p.m. — after hitting 67,728 MW in the previous hour.

And the ISO has set new monthly demand records for nine of the past 12 months, including the last four.

“The system has performed well so far this summer,” said ERCOT spokesperson Robbie Searcy. Unable to resist the use of a pun, she said, “We have kept up with monthly record demand in June and July, and blazed past the previous weekend record without any reliability concerns.”

ERCOT’s final resource adequacy seasonal assessment projected demand to peak this summer at 72.9 GW in August, above the all-time high of 71.1 GW set in August 2016.

Area heat indices have been as high as 109 F, but temperatures are expected to drop into the high 90s for much of this week.

— Tom Kleckner

August 1, 2017

Texas Commission Rejects SPS ROFR Request

By Tom Kleckner

AUSTIN, Texas — The Public Utility Commission of Texas agreed Friday that Southwestern Public Service does not have the exclusive right to build transmission facilities in its service territory, signaling a final order will be considered at its next meeting.

The PUC’s decision was not the answer SPS was looking for when it filed a request asking the commission to determine whether Texas law includes a right of first refusal that overrides FERC Order 1000. (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.)

ERCOT PUCT Right of first refusal ROFR — Audience at last week’s PUCT Meeting | © *RTO Insider*

Wes Reeves, spokesman for SPS parent Xcel Energy, said the company “is disappointed with this ruling and will seek rehearing and appeal.” The PUC’s next meeting is scheduled Aug. 17 (Docket No. 46901).

SPS contends that the state’s Public Utility Regulatory Act (PURA) allows it, as the incumbent utility operating outside ERCOT, the ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.

The commission disagreed, sticking to its staff position that “an incumbent utility’s expertise in providing service within its certificated service area does not confer an exclusive legal right to construct transmission facilities within the utility’s certificated service area.”

Commissioner Ken Anderson offered little of his own reasoning but noted ERCOT’s Competitive Renewable Energy Zone (CREZ) project backed his position.

“The fact is, whether it’s CREZ lines or non-CREZ lines, we have transmission lines owned by different service providers inside and outside ERCOT that crisscross each other’s distribution service territory,” he said.

SPS filed a lawsuit in state district court in January, seeking approval to build the project and an injunction prohibiting SPP from issuing a notification-to-construct. The two parties agreed to suspend the proceeding to give the PUC an opportunity to decide how to interpret PURA.

Parties to See LP&L Contested Case After Aug. Meeting

All parties involved in Lubbock Power & Light’s planned migration of its load from SPP to ERCOT agreed they are ready to move on to a contested case, but not until after the PUC’s Aug. 17 meeting (Project No. 45633).

Commissioner Brandy Marty Marquez said the delay would give her and PUC staff more time to study data compiled by ERCOT and SPP in a joint study on the potential move’s financial and reliability impacts.

“Everybody’s ready to go but me,” said Marquez, requesting a hearing schedule be set at the commission’s next open meeting.

Anderson agreed, saying he hasn’t yet “completely digested” the studies.

“There’s a lot of good data in the SPP and ERCOT report,” he said. “It’s not brought together in [a] bottom line, but you can derive it with little work.”

The study indicated SPP would see small production cost decreases in all of its transmission zones except for SPS, which serves LP&L’s 430 MW of load in a contract that has been extended into 2021. ERCOT would see production cost increases but hopes to balance that out by unlocking wind energy in the Texas Panhandle. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)

LP&L has said it intends to complete a study similar in scope and scale to the grid operators’. It wants to begin the contested case in May 2018, allowing it to successfully integrate with ERCOT before its “bridge agreement” with SPS expires.