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SPP CEO: Regionalization, transmission help push renewables penetration near 50%

Southwest Power Pool CEO Nick Brown says he sees solar, storage and more footprint expansion coming in the next five years

This article is the second in a periodic Utility Dive series highlighting the nation's organized electricity markets. You can find the first edition, an interview with ISO-New England CEO Gordon van Welie, here.

For some perspective on how far U.S. grid operations have come in the past few years, consider a headline:

“Western U.S. grid can handle more renewables,” the MIT Technology Review declared a few years back. “A study says 35% of electricity could come from solar and wind — without expensive new backup plants.”

That was in 2010, when utility stakeholders in the West were fretting over whether California could comply with a 33% renewable energy mandate passed eight years earlier. MIT was reporting on a hopeful study from the National Renewable Energy Laboratory that found enhanced regional integration could push renewables above that mark.

Times certainly have changed. California now has a 50% renewables mandate to meet by 2030, and to its east, one grid operator is already dealing penetrations of wind energy that approach half of its generation.

On April 5, the Southwest Power Pool, the grid operator for sections of 14 states across the central U.S., announced it got 48.32% of its electricity from wind energy in the early hours of the morning — a record for any American organized market.

“We have experienced a 48% penetration in the footprint, meaning that 48% of our capacity in a given hour was from wind generation in meeting our peak demand,” SPP CEO Nick Brown told Utility Dive. “Obviously, that occurred in a period of light load and high wind, but still, in our footprint, to have 48% of our generation being met by any single resource is phenomenal -- and for it to be by a variable energy resource is equally phenomenal.”

At present, SPP has more than 12.5 GW of wind capacity in its footprint, accounting for about 14% of its total. But the market has seen more than 10 GW of that in operation at one time, Brown said, pushing it well beyond operational assumptions about renewable energy integration at the beginning of the decade.

As SPP continues its transition from a coal-heavy region to one based more on renewables and gas, Brown said it must draw on many of the lessons that helped it get to its record wind penetration. It also needs to open new opportunities for distributed resources and demand-side management.

“Our focus has been on putting the markets in place and getting transmission built,” Brown said. “Doing one of those without the other would have been a huge mistake, so I'm glad we split our energies and focused on both at the same time. Now it's just a matter of continuing to tweak and improve.”

The SPP footprint includes portions of 14 states after its latest expansion in 2015.
 

Regionalization for renewables

According to SPP’s latest wind integration study, the grid operator can currently manage wind penetrations of up to 60%.Getting to that point was no mean feat, Brown said in a phone interview.

While SPP has been around  for 75 years, its organized market is the youngest in the nation, beginning operations in 2004. That level of renewables integration would have been impossible before consolidation of the region’s dozens of balancing authorities — smaller, local entities that are responsible for reliability in areas without an organized market.

 With a larger footprint, SPP can “forecast the wind rise and decline such that we can bring other resources to bear against the variability of wind,” Brown said.

“You just couldn't have done that when we were operating as 20-plus different balancing authorities ... committing resources on a much, much smaller scale,” he added. “They would have had to be much more conservative in their resource commitments.”

One of SPP’s largest regionalization initiatives is also its most recent. Last June, the grid operator officially incorporated the Integrated System into its footprint, including the Western Area Power Administration’s Upper Great Plains Regio, the Basin Electric Power Cooperative and the Heartland Consumers Power District. The move increased SPP generation capacity by 5 GW and added 9,500 miles of power lines.

SPP
 

Transmission buildout

Along with regional consolidation, billions of dollars of transmission investments in recent years also proved crucial in integrating more renewables.

“Let's say we did all that [regionalization], but we didn't invest the $8 billion in transmission that we have over the last decade,” Brown said. “We would not have been able to ensure deliverability of that much wind in the footprint.”

The richest wind resources in SPP are in the western areas of the grid operator’s footprint, but most of the load is in the East. In the past decade, the grid operator has put in “significant linkage” between the regions, while also finding a way to get each jurisdiction to pay its share, Brown said.

“But for our ability to reach agreement across a multi-state area on how to share the cost of that transmission expansion in an equitable way, we would not be able to deliver that wind,” he said.

For all its success in integrating variable generation, Brown acknowledges there are limits. With 4 GW of wind capacity slated to be added in the SPP footprint this year alone, that 60% wind penetration could come sooner rather than later. Many SPP members are also beefing up investments in central-station solar as well, Brown said.

“The question is how much [variable renewable generation] can we absorb just within our footprint absorb without expanding the network inter-regionally,” Brown said. “That's where we need to focus our attention going forward because we're just not there.”

The reason the power sector is “just not there” on inter-regional transmission goes back to FERC Order 1000, the SPP CEO said.

Within a region, Order 1000 “requires that if projects meet certain thresholds, they must be constructed,” Brown noted.

“Unfortunately,” he said, “Inter-regionally there's no obligation for one region to undertake a project that is shown by any number of studies to be justifiable, so the absence of that requirement alone is problematic in my view.”

The absence of a robust inter-regional transmission network means “we’ve got roughly 10% of the overall investment dollars constraining 90% — transmission being the 10%,” Bown said.

“People are so worried about overbuilding or building that which isn't needed, and I just don't have that fear,” Brown said. “My experience has shown decade after decade that when we build only that which is needed, by the time we put it into service it is usually oversubscribed."

Fossil fuel dispatch and compensation

Those new transmission lines would do more than carry renewables. While SPP is relying more and more on non-fossil resources, the bulk of the region’s capacity still comes from coal- and natural gas-fired plants.

As more intermittent generation comes on the system, SPP has seen some big changes in how its fossil fuels are deployed. Coal plants, while still providing important baseload power, are being dispatched less often, while fast-ramping natural gas plants are taking up a larger portion of the generation share to help compensate for the variability of wind power. Comparing the generation mixes on the same day in 2011 and 2016 illustrates the shift:

In both 2011 and 2016, May 20 fell on a Friday and weather conditions in the SPP region were similar.
 

“We've been very much blessed with the addition of some quick-start gas units that we can call on,” Brown said. “The challenge for us in the market is going to be to compensate them properly for that service.”

Using gas plants to compensate for the gaps in renewable generation can be tough on the machines, Brown explained, and there’s currently a debate among SPP stakeholders and the Market Monitor for the region about how best to compensate generators for this wear and tear.

“As we continue to bring them not just online, but up to full capacity in a very short period of time, and then shut them off in a short period of time, it's hard on equipment,” Brown said. “Unfortunately we've not really been able to reach agreement between our market monitoring unit and our stakeholders who have to operate these units on appropriate compensation.”

Figuring out the correct rewards for such ramping and reliability services will be crucial as renewable energy penetrations increase. Since wind and solar facilities do not have fuel costs like fossil fuel plants, big increases in their generation shares would be expected to push down prices in the day-ahead and real-time markets, especially if gas prices increase from their current historic lows.

If and when that happens, prices could dip so low that many of the larger fossil fuel plants would struggle to clear market auctions, pushing them toward retirement. That presents a challenge: Some sort of firm resource — whether gas plants or storage — will need to be kept online to compensate for interruptions in renewable generation.

ISO-New England CEO Gordon van Welie illustrated the point to Utility Dive last month: “Let’s say we’re in a world where 90% of the daily energy is coming from renewable resources. That’s kind of where policymakers want to go, right?” he said. “But let’s say one day the weather’s not cooperating … You need to jump to another set of resources. How are you going to pay for that?”

In ISO-NE, the answer comes from the capacity market, which van Welie said acts like “a natural balancing mechanism” for the energy markets, allowing large plants to earn income for providing available generation even if it is not dispatched.

But in SPP, there is no capacity market, meaning that Brown and his colleagues must provide adequate compensation in the day-ahead and real-time markets. As renewables penetration increases, Brown said the grid operator may tag some plants as “reliability must run,” meaning they will “have to run, and we will have to compensate them in order to be there.”

“The real question is when we order them to come on, are they in a position of exercising market power, where they just name their costs?” Brown said. “Our market monitor says no, you can't just name your cost. We're saying you have to run and we'll pay you what your costs are.”

Determining that cost is what the stakeholders are grappling with today.

“The bottom line is that you would allow them, in the prices that they bid into the market, to include maintenance contract expenses,” Brown said. “The real question is in day-ahead and real-time market how much of the fixed and variable costs do you include?”

The SPP CEO said he is confident stakeholders will come to an agreement with the market monitor before serious issues come to bear, but the stakes are high.

“If the forced outage rate on these [must-run] units goes up and they're not maintained properly because they aren't compensated properly, then reliability will suffer, plain and simple,” he said.

Storage, DSM and DERs

Of course, it’s not just fast-ramping as plants that can help preserve reliability at high levels of renewable energy penetration. Battery energy storage systems lack the moving parts of thermal power plants, allowing them to respond almost instantaneously to prompts from grid operators.

Brown expects deployment of batteries to accelerate within the next five years, especially in conjunction with solar.

“Batteries, particularly large-scale battery applications, are wonderfully paired with solar technology,” he said. “I don't care whether it's utility scale or residential scale, batteries and solar are just good partners … as battery tech continues to improve and the price continues to come down we're going to see more of that. Absolutely believe it.”

Demand-side resources, such as customer-sited batteries, aggregated DERs and traditional demand response, can also play a big role in ensuring reliability, Brown said.

“Load can respond to our signals quicker than big huge thermal machines can. We know that for a fact,” he said. “EPRI has done studies showing that using batteries and any number of resources on the load side of the equation — just shedding load off, or telling load to turn on — is a way to balance our job today in a way that could be done much more quickly and much more efficiently.”

But, he quickly added, “we don’t do that today.”

The reason goes back to the absence of a capacity market. Since SPP has no states with retail electricity choice in its footprint, the regulated utilities in each state are responsible for providing capacity services and managing demand-side resources.

Each state has rules over the treatment of demand-side resources in each of their footprints,” Brown said. “Those demand-side resources are not eligible to participate in our market, not because of our rules, but because of each individual state's rules.”

In the future, Brown envisions a larger role for both traditional demand response and aggregated customer-sited resources in SPP markets. While the grid operator sends signals to about 700 generators today, in the future that number could balloon to “100,000 or 200,000 devices” located all over the SPP footprint.

“It's not so much a need for technology,” Brown said. “It's a need for evaluating cost structure and recovery by our current members for the investment they've made in the transmission grid that makes those resources have access to a wholesale market.”

That task will become easier as stakeholders in the SPP footprint work toward more accurate valuation schemes for distributed resources that ensure utilities can recover grid infrastructure costs.

“It's amazing to me some of the pushback from some of the DER [developers] to pay for an allocated share or force customers to pay for an allocated share of the bulk electric transmission network when in reality it would open up the value of those resources to a much bigger footprint,” Brown said.

The next five years: Further footprint expansion

It will take time for each of the SPP jurisdictions to sort out valuations and rules for demand-side and customer-sited resources, Brown said. “I think we will be on the cusp of that in five years.”

But within that same timeframe, the SPP CEO predicted further expansions of its footprint.

I think there are a lot of utilities that have yet to embrace being in organized markets that I think will avail themselves to that,” he said. “I certainly hope SPP is considered a viable option for them … I think our footprint expansion will occur within the five year period.”

Expanding organized markets is a hot topic in the West. The California ISO is currently running an energy imbalance market with many of its neighboring utilities, including PacifiCorp, Arizona Public Service and NV Energy. CAISO is in conversations with a number of those balancing authorities to integrate the EIM into its full organized market.

Without naming names, Brown said many similar conversations are going on at SPP.

“We've already had that conversation for many years,” he said. “We've responded to requests for proposals from those entities, as has CAISO, and we'll continue working with them as they evaluate how they continue to evolve into a broader regional integration.”

“Nobody can argue against those benefits,” he added. “[Balancing authorities] will have to give up certain freedoms and controls that they've had in the past, but the benefits of regionalization are there ... I'm sure CAISO will get its share of interested parties and my hope is that we'll get our share as well.”

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Filed Under: Generation Transmission & Distribution Solar & Renewables Energy Storage Distributed Energy Efficiency & Demand Response Regulation & Policy
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