In Texas last week, a massive winter storm froze the state’s electrical grid and left millions without access to reliable electricity, natural gas or even clean drinking water for days.

In California and across the southwest, a scorching heat wave six months ago contributed to an overstressed grid that knocked out the power supply for millions, leaving them without air conditioning as temperatures soared into the triple digits.

Nevada is not Texas, nor is it California. The state avoided rolling blackouts during the August 2020 heatwave (though NV Energy still issued a rare voluntary request for customers to curtail power use during times of peak demand), and hasn’t seen similar severe winter weather that knocked out many grid operations in Texas last week.

But 2020 wasn’t an anomaly. Issues of grid management and resource adequacy — having enough power to meet demand, the same issue that befell California last year and Texas this year — aren’t going away anytime soon. The future for the planet is an increase in extreme weather events, and Nevada is in the bullseye of states most likely to experience massive temperature swings and the full effects of climate change. 

Over the past six months, NV Energy officials have been answering questions about the August near-crisis through an investigatory docket opened by regulators at the Nevada Public Utilities Commission, focusing on both what exactly drove the utility to request customers curtail power use on Aug. 18 and 19, but also on broader issues of resource adequacy and how best to avoid a California or Texas-style grid disruption.

The electric utility company has also taken steps to prepare for next summer beyond answering those questions. In late December 2020, it filed an amendment to its Energy Supply Plan that proposes to spend an additional $61.3 million to help prepare for an expected hot summer and additional demand in 2021.

The dollars will help fund projects or infrastructure developments aimed at increasing capacity during hot summer months, budgeting for a hotter-than-normal summer in internal supply planning and raising the required reserve percentage to help with any temperature variances or unexpected increases in demand.

But that additional spending will still leave the utility continuing to rely on open market purchases to meet expected demand — around 900 megawatts per month between June and August 2021. (A megawatt represents enough power for several hundred residential homes, though exact figures vary on source of energy and average residential electrical use).

But that reliance on market purchases to meet expected demand for next summer could be a potential cause for concern: PUC staffers wrote in an investigatory docket that they were concerned a similar seasonal heat wave and subsequent curtailment of open market power in 2021 “may not be a plan for success.”

The investigatory docket also revealed another stress factor on the grid: unexpected load demand from large casinos and businesses that previously filed to leave utility service, but whose alternative electric providers faced the same constraints on electric power and were unable to deliver the promised load, leaving NV Energy to fill in the gaps.

And while NV Energy has invested in expanded large-scale battery storage technology, its move to adopt higher standards of renewable energy over the next decade will also add stress to the grid, because of the simple fact that solar energy is intermittent. 

Dealing with that combination of factors is a problem that the PUC, NV Energy and other interested parties will likely deal with in future utility planning filings and will be affected by NV Energy’s moves to sizably increase its reliance on renewable energy and a proposed major, billion-dollar transmission upgrade.

Dylan Sullivan, a senior scientist for the National Resource Defense Council, said that smart grid management planning would avoid any potential or perceived conflict between an increased reliance on renewable energy and the reliability of the state’s power supply.

“Sometimes it's presented as we have to make a choice between renewables and reliability,” Sullivan said. “We really don't have to make a choice if we plan. We can have an affordable, reliable and highly renewable energy system, but we do have to plan for it, we do have to look at what happens when a bunch of things go wrong.”

Open positions and limits on the market

There are three ways that NV Energy creates or obtains electrons that power homes and businesses throughout the state.

The utility company owns a group of about a dozen generating stations (26 actual generating units) — largely natural gas-powered, but with some solar projects in southern Nevada and the coal-fired Valmy power plant near Battle Mountain.

NV Energy also contracts with about 43 generating projects through Power Purchase Agreements, which are long-term contracts with private-party developers to build and generate a certain amount of electricity for the utility company. Many of NV Energy’s recent investments into large-scale solar projects have come through these agreements, also known as PPAs.

But to meet demand requirements, especially during summer months where normal capacity isn’t enough to meet the heightened demand, NV Energy (and other utilities) rely on market purchases of electricity to fill those gaps.

Market purchases fall into three categories: real-time, day-ahead, and term. Term refers to open market purchases that are typically negotiated months in advance, while real-time and day-ahead are what they sound like, closer to real-time needs. NV Energy said in PUC filings that it prefers “firm energy products,” which means there is a commitment placed on the seller of the electricity products to deliver the goods.

Resource planning isn’t like horseshoes or hand grenades; getting close but falling short of meeting actual demand means serious system reliability issues and blackouts. That’s why the utility overshoots its expected demand with a planned reserve margin over expected demand, which last summer was around 13 percent system-wide. 

NV Energy plans resource adequacy in a few ways. It’s required by law to file an “Energy Supply Plan,” which is the utility’s strategy and estimates of how much electricity it will need to procure for customers, and how it plans to obtain that electricity. The last Energy Supply Plan was approved in November 2019, but the utility regularly files amendments to the plan.

The utility also uses a seasonal “laddering” approach for market purchases, meaning it discusses and makes further adjustments to planned market purchases every quarter based on more timely weather forecasts and other more up-to-date market conditions.

A near-disaster in August

That normal strategy of relying on open market purchases to fill the gap between supply and demand almost failed during the week of Aug. 17.

A blistering, record-setting heat wave blanketed the Southwest, putting enough stress on the electric grid for California to implement rolling blackouts for the first time in two decades.

The heat wave and grid pressures didn't stop at state boundaries; Nevada saw similar scorching temperatures that week in August, and similar pressures on the grid because of the above-average temperatures and smoke from California wildfires.

NV Energy took many steps to try and lower electric demand: the request for voluntary lower power use, asking large customers to cut electric use, asking large independently owned power generators within the state to help address the demand and issuing a “no touch” order on generation equipment to avoid any inadvertent interruptions.

But the state’s electric market came close to the precipice of disaster. NV Energy reported in the PUC investigatory docket that it reached the third and highest level of an Energy Emergency Alert (utility parlance for power blackouts) for several hours on the afternoon of Aug. 18.

During that afternoon at around 4 p.m., NV Energy fell short of its required operating reserves — the required contingency backup that the utility typically plans for. Twelve minutes into that hour, the company tapped into power provided by the Northwest Power Pool reserves — a grid oversight body covering power networks in eight states and two Canadian provinces.

Tapping into resources from the Northwest Power Pool was like cashing in an insurance policy — helpful to have in place for times of emergency, but evidence that something went wrong. (Again, no NV Energy customers, residential or commercial, experienced outages.)

In its filings, NV Energy said that the issue wasn’t in company-owned generation or any of the (primarily solar) PPAs — all performed between 90 to 100 percent of expected capacity. The company also said there weren’t any transmission issues with moving electrons around the grid.

Instead, the issue was with limitations on market purchases and curtailment — decisions by grid operators (largely in California) to stop the flow of electricity out of the area to ensure that adequate electricity is available in their service area.

During the week of Aug. 17, 2020, NV Energy reported that there were 76 hours (an average of 11 a day) where market purchases were curtailed, meaning the “actual delivered energy was less than the confirmed term, day ahead, or real time purchases.” The largest curtailment happened at 7 p.m. on Aug. 18, when 1,243 megawatts of purchased open market power were curtailed; the company said “NV Energy has never experienced a curtailment of that size.” Many of the curtailments occurred in real time “with little to no notice.”

Between Aug. 17 and 23, NV Energy saw more than 7,100 megawatts of purchased electricity curtailed. 72 percent of that curtailed energy were day-ahead or real-time purchases.

Those curtailments couldn’t have come at at a worse time. The above-average temperatures drove NV Energy and other power providers to rely on market purchases to keep lights on throughout the state, driving the price of a megawatt hour to obscene levels.

Electricity that the week prior had cost around $70 per megawatt hour skyrocketed amid the incredible demand — hitting a real-time peak of around $2,600 per megawatt hour on Aug. 18. That’s a more than 3,600 percent increase, or like a gallon of milk going from $2.99 one week to more than $100 a few days later.

704B issues

The docket identified another stress factor that affected the state’s grid during those hot August days — servicing many of the large businesses that had previously filed to leave utility service and work with providers on the open market.

These “704B” customers (named after the provision in state law) are some of the most well-known entities in the state: MGM Resorts, Switch, Wynn Resorts, Caesars Entertainment, Sahara Las Vegas and the Peppermill Resorts in Reno. Before state lawmakers in 2019 added new limits, those companies would generally file an application and agree to pay a seven-to-eight figure “exit fee” in return for the right to buy power (presumably cheaper) on the open market.

But those businesses aren’t totally free of NV Energy. As the balancing authority or grid operator, NV Energy still manages transmission for 704B customers, meaning they’re obligated to provide balancing services and manage the flow of electricity for those customers. The utility also acts as a provider of last resort, meaning that the customers pay a tariff (fee) to ensure that NV Energy will provide power if any of their normal providers had a disruption in service. 

That’s exactly what happened in August. Four electric providers for 704B companies failed to fulfill their obligations to their customers on the afternoon of Aug. 18, leaving some of the state’s largest casino companies to once again lean on NV Energy to keep the lights on and power running. 

The alternative power providers experienced varying levels of failure; Caesars’ shorted power supply from provider Tenaska never exceeded 10 percent, while the Peppermill in Reno had to 100 percent rely on NV Energy power for several hours on Aug. 18.

In a filing, staff for the PUC wrote that while NV Energy still provides electricity transmission service to 704B customers and is expected to make up imbalances in power supply, the level of failure to provide power well exceeded any imbalance authority and instead worked essentially as a standby service.

“This creates a riskless paradigm under which certain NRS 704B customers shift supply risk and the obligation to NV Energy and its remaining customers with little risk to the NRS 704B customers,” PUC staff attorney David Noble wrote in a filing.

Noble wrote that NV Energy was supposed to write-off the load of 704B customers once they left utility service, but “clearly that is not the case” given what happened in August. He suggested that the PUC and NV Energy in future proceedings explore ways to charge 704B customers for what essentially worked as standby service.

“If NV Energy and remaining customers are going to have to backstop some or all of these departed customer loads when the market gets tight, then NV Energy and remaining customers need to be compensated for that service, and NV Energy needs to start planning for the possibility of such events in its ... filings,” Noble wrote in the filing.

Tenaska and other alternative providers pushed back, saying that the 704B customers already pay a fee for the transmission provider (NV Energy) to backfill load in the event of “system contingency.” They wrote that the system worked as intended, and that 704B customers paid NV Energy for any electricity the utility had to provide.

During times of peak demand on Aug. 18, NV Energy was required to make up a shortfall that varied between 131 and 85 megawatts of power for transmission-only customers (the 704B companies). That amount of power diverted to those customers was smaller than the curtailment amount NV Energy was dealing with at the same time, but the utility wrote that the two issues combined had exacerbated supply issues to the near-crisis level.

“If firm purchases had been delivered and transmission customers avoided leaning on NV Energy’s resources, the shortfall would have largely been avoided,” NV Energy executive Michael Greene wrote in a filing.

Planning for next summer

Even if NV Energy was to sit on its hands and not do anything to prepare for the 2021 summer, past contracts for large-scale solar and battery resources are scheduled to be operational before summer strikes.

That includes 70 megawatts of solar energy at the Techren Solar Project near Boulder City, a 50-megawatt solar plant earmarked for an Apple data facility and a 101-megawatt solar field and 25-megawatt battery storage facility near Battle Mountain.

But even with that expanded capacity, NV Energy is still planning to rely on market purchases during summer months of 2021 to meet anticipated demand goals.

That is largely due to a change in energy supply planning for the remainder of 2021. The amended Energy Supply Plan filed in late December makes several changes, including:

• Implementing a “hot summer” weather scenario, which estimates hotter temperatures in the summer and raises anticipated demand levels
• Raising the utility’s planning reserve margin up to 15 percent system-wide
• Upgrading two of four existing natural gas-fired turbines at the Lenzie Generating Station that will add an additional 37 megawatts of capacity, at a cost of $46.3 million
• Installing a “wet compression” water injection system on two existing combustion turbines at the Higgins Generating Station for an additional 32 megawatts of capacity, at a cost of $6.5 million
• Fulfillment of a contract with the British Columbia Hydro and Power Authority for a hydropower PPA, adding 209 megawatts of capacity over the summer

While the utility wrote in PUC filings that it doesn’t believe any policy changes are necessary to meet demand this summer, it said the above proposed changes to its energy supply plan are necessary as the current plan is “inadequate to address the potential for extreme weather power demand due to climate change and provide adequate planning reserves.”

In future planning proceedings before the PUC, the utility also suggested revisiting its formula for weather predictions and correlated demand planning. NV Energy uses a rolling 20-year average in guessing weather and demand, but said the formula doesn’t fully capture the warming trend in recent years.

PUC staff also suggested that the utility hold more frequent meetings to determine if “firmer” market purchases can be made ahead of expected hot weather, as opposed to relying on real-time or day-ahead energy markets.

Sullivan, who often testifies on clean energy issues before the Nevada Legislature and in PUC dockets, said that policymakers can take other steps to shore up grid reliability and reduce the impact of major weather events on the grid.

His group is supporting legislation in the 2021 Legislature to raise energy efficiency standards — a concept that he said reduces the demand strain on the grid by keeping indoor temperatures less variable on the weather.

Overall, Sullivan said that the best way to ensure reliability on the grid while increasing the utility’s share of renewable energy resources was diversity — solar in Southern Nevada, geothermal in Northern Nevada, and tapping into hydropower or wind energy from other states where possible.

“One of the ways to have a highly renewable, resilient, reliable, affordable energy system is to have a diversity of renewable energy resources,” he said.