KANSAS CITY — Infocast’s first SPP and MISO Markets Summit last week faced tough competition at its hotel, which was also hosting the U.S. women’s national soccer team, the Detroit Tigers, Journey and Def Leppard.
Still, the July 24-26 conference attracted participants and industry representatives from the RTOs’ footprints for panel discussions on resource mix, gas builds for reliability, competitive wind pricing, unlocking solar energy’s potential, demand response and energy efficiency initiatives, and the future of the Western grid.
Much of the focus was on the RTOs’ interconnection queues, which have ballooned in recent years as renewable developers chase expiring federal tax credits.
Renewable projects account for 78 GW of the almost 90 GW in MISO’s queue, and about 74 GW of the 77 GW in SPP’s queue. Neither RTO has a coal project on the books.
MISO and SPP are used to the growth of wind power, which supplies about 17-18 GW of energy for both RTOs. But the explosion of solar and battery projects (36 GW in MISO, 20 GW in SPP) has come as a surprise.
Vikram Godbole, MISO’s director of resource utilization, said solar projects now outnumber wind projects in a queue with an “historic” amount of generation. He said the generation is almost 7 GW higher than the “most extreme” staff forecasts of a year ago.
“I never thought that would happen,” Godbole said. “At what point does it end, I don’t know. We’ll continue to see a rise in solar the next few years, especially as the projects with wind [production tax credits] drop out.”
“The reason you’re seeing solar is because of the tax credits,” said Ameren’s Jeff Dodd. “That’s not a shock.”
“It’s mind-boggling when you look at it,” said Steve Purdy, SPP’s manager of generator interconnection. He compared the queue with the RTO’s summer peak load of 50 GW, saying, “You can see the challenge we have in squeezing that enormous amount of generation into a relatively small amount of load.
“That’s led to areas where we don’t have enough load to absorb all the requests,” Purdy said. “We’ve resorted to creative engineering and engaged our stakeholder group to help with those challenges, both in technical issues and the process issues.”
SPP stakeholders in April approved an overhaul of the generator interconnection process, leading to a simpler three-stage process that mimics MISO’s. (See “Members Approve Three-Stage Process for GI Requests,” SPP Markets and Operations Policy Committee Briefs.)
The grid operators say they hope recent changes to the GI process will help them work through the backlog of requests and weed out developers trying to manipulate the process. Godbole said MISO is just now processing 2016 February and August cycles.
“A lot of GI customers are getting anxious about being able to start construction on time,” Godbole said. “They need some idea of whether they’ll get a [GI agreement] before the summer of 2019.”
“It’s going to be very difficult for anything in the 2017 cycle to get a GIA in time, just based on the cycles,” Dodd said.
The simpler, three-stage study processes include heftier security deposits at each stage. That helps ensure only the most serious developers are involved, as studies have to be redone when a project is withdrawn.
“The interconnection process is becoming the long-delaying issue in the development cycle. We have to put more thought into how we enter these queues as a customer,” said Tradewind Energy’s Derek Sunderman. “We’re trying to stay ahead of those changes so that we can continue to have a pipeline of projects. Security deposits … have become the No. 1 driver on the budget side of this business.”
Sunderman said the changes seem to indicate the three-stage study process “is moving forward.” He said a Tradewind analysis of MISO’s recent study results showed fewer customers dropped out at the later stages, an indication of the more favorable results they were getting for their projects.
“That tells us the interconnection customers are becoming very educated,” Sunderman said. “The problem is the study length. It’s just not working as fast as we would like.”
Western Grid Hears the Markets Call
David Kelley, director of seams and market design for SPP, said improved renewable technology is not only evident within RTOs, but in the efforts to create markets and new services in the Western Interconnection.
“Many of the states and utilities are looking at integrating more renewables,” he said during a panel on Western grid regionalization. “RTOs and markets are very capable of providing the type of environment and economies of scale that facilitate that type of development. It’s hard to argue against how broader regions plan the system than individual companies doing it on their own.”
Kelley noted SPP had 3 GW of wind energy on its system in 2008. “Now, it’s 17 gigs,” he said. “Our robust transmission planning system helped do that.”
“The biggest hurdle of getting renewables to the market is the tariff’s ways [through pancaked rates] it takes to get the power to a load-serving entity,” said Swaraj Jammalamadaka, a former MISO staffer, now director of transmission for Apex Clean Energy. “MISO, SPP, PJM … they are definitely a benefit for integrating low-cost generation in the system.”
Markets also provide transparency into price, costs and benefits, said Kelley and Pat McGarry, managing director of The Energy Authority.
“The transparency is real in RTO markets,” McGarry said. “It can cause issues, because now, everybody can see what the prices are. If you self-commit a generating unit when the prices are low, it’s, ‘Why are you running?’”
“For us, the biggest struggle is the market no longer depends upon fixed [power purchase agreements],” Jammalamadaka said. “A significant enabler in markets like SPP’s is people are able to sell their power through very intelligent financial instruments. They can only be made available if you have a liquid market.”
SPP is among those attempting to offer market services in the West, having been working to integrate the Mountain West Transmission Group, a collection of eight Rocky Mountain-area entities, since January 2017. That deal has been on life-support since Xcel Energy, which accounts for 40-50% of Mountain West load, announced in April it was withdrawing from the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
“That certainly changes things from the cost-benefit perspective,” Kelley said. “[The remaining entities] are in a very deliberate process of calculating the benefits and costs of participating in SPP. We expect that process to take place over the next few weeks before they make a final decision.”
Grappling with Adding Value to Coal Resources
Without new coal-fired generation in their futures and with increasingly large amounts of renewable energy disrupting their fuel mix, how are SPP and MISO to incent new coal resources?
Casey Cathey, SPP’s manager of operations engineering analysis and support, said while the RTO is fuel agnostic, it does value flexibility. To ensure coal resources are valued, he said the grid operator is evaluating two products that may provide benefits for their generation: a multi-day economic commitment and a de-commitment enhancement.
“Coal unit parameters are too expensive for the day-ahead engine to pick up. It can cost $200,000 to start, so maybe we can disperse that cost over a period greater than 24 hours,” Cathey said. “A multiday economic commitment would be better able to assess coal and compensate it, instead of having to self-commit.”
He said a de-commitment enhancement isn’t as easy as it sounds, with day-ahead positions and financial obligations that must be accounted for.
“It will help coal in two ways. It will help to further optimize commitments instead of coal having to self-commit; it will help … maximize its revenue in the de-commitment process,” Cathey said of an action that’s up to the market participant. “It’s basically placing that decision in the hands of the RTO, which theoretically should make a little more money [for coal resources], through optimal cycling. If other resources completely de-commit, it could potentially inflate prices for those resources that stick around.”
“The real question may be how we incent the right resource characteristics,” said Laura Rauch, MISO director of resource adequacy coordination. “We commonly think of coal as the resource we know and love because of these attributes, but as Casey said, it’s about making sure we have the market signals to go and motivate people to build resources with the right characteristic. We have to have the forward projections with the states and load entities, so that we’re not just reacting, but that we’re getting the generation built to replace some of these retired units with the transmission to support it, and with the general attributes we need to keep the system reliable.”
Lincoln Electric System’s Dennis Florom, whose company owns interests in several coal plants, said there’s still a place for new coal generation, although “it’s going to be a tall order.”
“We need to look at new ways to clean it; we need to look at ways to change public perception. It’s not a resource people want to build,” he said. “As we bring in new resources such as storage, it’s actually going to have an interesting play. You’re going to see those storage resources placed in areas of high congestion … where prices are typically high. As you bring in resources that will eliminate congestion, you’re going to see a flattening of prices.
“That makes me wonder if, out in the distance, somewhere, maybe the next 10 years, we see prices flatten,” Florom said. “People will recognize that resources with higher fixed costs, but low variable costs, will be able to take advantage of those flattening prices.”
Gas Generation No Ordinary Bridge Fuel
Appearing on a panel discussing gas-fired generation’s role in grid resilience and reliability, Vectren Director of Regulatory Policy and MISO Affairs Justin Joiner asserted that gas is not a bridge fuel but, rather, “a highway.”
“[Gas units are] foundational to the adoption and use of the latest technological advances to meet load needs,” he said. “Gas is cost effective, flexible, reliable, resilient and fast ramping. Additionally, resiliency is a regional matter. How one meets its load needs in a resilient manner is a system-by-system consideration, unique to each LSE.
“If you look at the MISO queue and the amount of baseload retirements [20 GW recently, 12-20 GW forthcoming], there is a need for fast-ramping, dispatchable generation. Gas will meet that need,” Joiner said.
Scott Wright, MISO’s executive director of strategy, agreed with the critical role gas-fired generation can play. He pointed to the 10 GW of gas projects in the ISO’s queue, noting most will be used to address continued retirements of legacy resources.
“Due to its reliability and flexibility attributes, gas-fired generation will support future change,” Wright said. “Preliminary studies from our planning scenarios indicate that we’ll be calling on a comparable amount of total gas capacity in the future to provide ramping that is at least two to two-and-a-half times the amount of today’s gas ramping. This means we’ll need more capability, not less, from gas-fired generation, despite and related to the large growth expected in renewable resources.”
Natasha Henderson, who manages regulatory and market affairs for West Texas-based Golden Spread Electric Cooperative, said all generation types will continue to contribute to resilience. But given quick-start gas units’ ability to cover sudden drops in renewable energy, she said gas-fired generation should be compensated accordingly.
“At this juncture, gas generation is the most critical type of generation to meet reliability and resiliency needs, and flexible gas generation will become increasingly important as we see more and more renewables added to the system,” Henderson said. “As technology advances and the resource mix continues to change, wholesale market structures will need to not only react but proactively adjust. It’s critical that we both define the attributes of reliability and resiliency and ensure that markets properly compensate these attributes to incent the correct future generation mix.”
MISO, SPP Improving the Interregional Process
Cathey also engaged Jeremiah Doner, MISO’s director of seams coordination and membership services, in a friendly discussion over improvements to the interregional planning process and January’s “Big Chill.”
Having failed to agree on a single interregional project so far, the two grid operators are working to reduce hurdles, such as building a joint model and eliminating the $5 million threshold to qualify as an interregional project. To save time, SPP and MISO will now study potential projects within their own regional models. They have also added new benefit metrics, such as the avoided cost of other projects. (See MISO, SPP Loosen Interregional Project Requirements.)
“It doesn’t take an engineering power flow model to determine projects need to be built. We have artificial human barriers … because of the model build and barriers like the $5 million threshold,” Cathey said. “There’s no reason we shouldn’t build a $4 million project if it leads to benefits. SPP stakeholders are getting a little bit tired of talking about interregional projects. We should be building transmission across the seam.
“But give MISO kudos as well. They recognize the same thing,” Cathey said.
“We’re both on board and at the table working on these problems,” Doner said.
The two also talked about the Jan. 17 severe weather event, when generation shortfalls in MISO South led to heavy north-south transfers across SPP’s system and a maximum generation alert in the region.
Cathey, a Louisiana native, noted temperatures in his home state were 30 degrees Fahrenheit lower than they should have been. Older generating units, without proper cold-weather packaging, tripped offline, costing MISO 5 GW of capacity.
“It was a challenging day,” he said. “There are a number of things that could have been done differently that day. We could have been a little more proactive. We’re discussing with [MISO and neighboring Southern Co. and the Tennessee Valley Authority] how we can learn from it and better forecast these issues.
“We practice load shedding, but we don’t practice emergency purchases, which prevents load shedding. We’re working on that with the neighboring reliability coordinators. That alone would have helped MISO,” Cathey said.
“That’s a very accurate description of what happened that day,” Doner said. “It’s important to remember we kept the lights on. MISO is very appreciative of the emergency energy we had to purchase on that morning. We’re in this together to keep the lights on. We should support each other, and we did that day.”
Wind Developers Argue for Level Playing Field
A pair of wind developers said that while technological improvements continue to improve wind energy’s competitiveness, the loss of the PTC threatens to tilt what they say is now a level playing field.
“Yes, wind energy has evolved to where it’s cost competitive,” EDP Renewables’ Rorik Peterson said when asked what harm the PTCs’ expiration would cause. “But there’s no form of electric generation that doesn’t receive some sort of federal support. If the PTCs expire, that leaves wind without any form of support. As to fairness in the marketplace aspect, I take exception to that.”
“On a level playing ground, we compete quite well,” said Apex’s Mark Mauersberger. “Having us be the only generation that doesn’t benefit from a subsidy is unfair.”
Peterson said solar energy’s increasing competitiveness, as evidenced by its growing presence in the MISO and SPP interconnection queues, “will certainly change the landscape.”
“I would expect with the phaseout of the PTCs and the loss of their full value after 2020, the tariffs on solar panels rolling off, that solar will consume a greater share of the renewables market,” he said. “I would expect to see a decline of consumption of wind after 2020, but I still expect to see wind be a viable component of the generation mix going forward.”
If so, then technology will continue to play a key role.
“One of the largest cost components of the wind project is the turbine,” said Mauersberger, whose company’s Dakota Range Wind project in South Dakota will use 72 turbines to generate 300 MW of energy. “Using [fewer] turbines shrinks the footprint, reducing the cost of cabling, roads and other civil costs. That trickles down to really reasonable pricing. We’re seeing pricing down south [in Texas and Oklahoma] in the $15/MWh range. I think that’s where we’re headed pretty quickly.”
— Tom Kleckner
