WASHINGTON — More than 100 transmission developers, consultants, RTO officials and utility executives attended Infocast’s 19th Annual Transmission Summit. Here’s some of what we heard.
Curt Bjurlin, an environmental services manager for Stantec, asked whether there are too many transmission developers chasing too few competitive opportunities under FERC Order 1000.
“I’m reminded of a story of a guy who comes to town and wants to play in a poker game and someone says ‘Why do you want to play in that game? Don’t you know it’s rigged?’ He says, ‘Yeah, but it’s the only game in town.’”
Bjurlin said he expects developers to employ more rigorous go/no-go decisions on bidding in the future.
Southern Co. is one utility that’s not entering the game. “We’ve looked at that business continually and feel that there’s enough players in that market and not a lot of projects to go after,” said Bruce Edelston, vice president of energy policy. “So we decided to stick to our knitting in our own service area.”
Lack of Interregional Transmission Projects
Edelston said the planning process isn’t the reason for the lack of interregional transmission projects.
“It’s whether there’s somebody who is benefiting from that line who’s willing to pay for it. … There are very few interregional lines that are going to be economic when you look at the alternatives available to the purchasing region — the region that would be receiving the renewable energy. They often have local alternatives or closer alternatives that don’t require transmission fixes, and these long distance interregional lines can be very, very expensive — and as we’re seeing with the Clean Line Energy Partners lines up in Illinois — very, very difficult to build.”
“In our case, with the price of solar having come down so far, it turns out to be much more economic to build utility-scale solar within our service area than it is to build long-distance transmission to access wind in the Midwest. And I think that’s true for a lot of East Coast load centers. You also have the opportunity these days to buy RECs — or renewable energy certificates — to meet any renewable portfolio standards that you have.”
Jared E. Alholinna, regional transmission planning strategist for Great River Energy, recalled MISO’s joint study with PJM, which identified up to 75 different “quick hit” transmission projects along their seam. (See MISO, SPP Considering Second Joint Tx Study.)
“Not one of them showed economic benefits. Many stakeholders thought this was a failure — you know, they’re saying ‘0 for 75.’”
The real reasons for not finding a viable project, he said, included the success of MISO’s multi-value projects in reducing congestion and low natural gas prices that make it cheap to redispatch around congestion.
“There have been projects on the border that are on the cusp of meeting criteria, but when you have two different RTOs, you have two different needs and you have two different approval processes. And trying to get all those stars aligned we’re finding is very, very difficult.”
Xcel Seeking Larger Dispatch Areas in the West
Gerald R. Deaver, manager of regional transmission policy for Xcel Energy, said although his company’s operators have developed expertise in making their systems more flexible, the increasing penetration of renewables is creating operational challenges.
“Xcel has been pushing the development of regional markets in the West because we think geographic diversity is the best way to deal with some of this imbalance between regions or areas with renewables. And it seems to be getting more traction in the West.”
“We’re trying to develop along the Front Range [in central Colorado and southeastern Wyoming], a common dispatch area with a number of entities, both [FERC] jurisdictional and non-jurisdictional, to try and widen that footprint. … I doubt you could go Western Interconnection-wide with, for example, an RTO, but we’re really pushing for bigger geographic areas for dispatch. That’s going to require probably some additional transmission interconnections.”
Xcel has reduced its carbon emissions by 20% since it began adding renewables in 2005, and its Colorado Public Service unit now gets 60% of its energy from wind during some hours of the day, Deaver said. “We’ve been able to line up long-term purchases of wind at steadily decreasing prices.”
Distributed Energy Resources
Eric Ackerman, director of alternative regulation for the Edison Electric Institute, said the planning for distributed energy resources will require granular data regarding both customer energy use and system status that few utilities currently capture, even though some 65 million interval meters have been deployed.
“But even if we have the data, the next issue is … do we want to give the data to the market? Because in California and in New York the preference is to have market-based third-party suppliers deliver the distributed energy. So the market is endlessly hungry for this data. They’d like it in real time. They’d like it constantly updated. And utilities — my members — are pushing back. They think their distribution franchise requires them to plan the system. And if they give too much of the data to the market, guess what? The market’s going to run away with that and they will lose control of their plan.”
Stuart Nachmias, vice president of energy policy and regulatory affairs for Consolidated Edison, said, however, there is a win-win opportunity for utilities and new entrants. “The [cost of] solar technology is coming down. But if you talk to the solar companies, their biggest cost is customer acquisition. And to the extent that utilities together with solar companies or battery providers ultimately can help reduce that acquisition cost and share in those savings there’s tremendous value.”
Nachmias also gave an update on his company’s plan to use distributed generation and demand-side management to address overloads in Brooklyn and Queens and delay the need for a $1 billion substation upgrade for a decade. (See NYPSC OKs Con Ed’s Demand Management Program to Relieve NYC Overloads.) “Stitching together the solution [is] really complex — much more than we thought,” he said. “And getting customer engagement is very difficult.”
Market for Grid-Scale Storage
Philippe Bouchard, vice president of business development for Eos Energy Storage, said that frequency regulation has been good for energy storage — responsible for about 80% of the 200 MW deployed last year.
“However the challenge with that market and application is … it’s a pretty shallow market. If you compare the amount of money that flows through FR in PJM relative to the energy market or the capacity market, it’s tiny. And the more assets that get built to provide that service are essentially cannibalizing the revenue streams that they can monetize.
“To me the real drivers of the market are going to be projects more like [Southern California Edison’s request for four hours of locational capacity] — large-scale longer duration projects that are providing services under long-term contracts with creditworthy off-takers. These are projects that are easily financed, that are providing a reliability service to the grid and which offer flexibility too.”
Alex Ma, senior manager of regulatory affairs for Invenergy, said grid operators will need to change their interconnection process in order to realize the potential storage has for supplementing variable energy resources.
“From an interconnection standpoint, it seems very difficult to get past the fact that you have two different technologies at the same [point of interconnection],” he said, recommending changes to “fast-track some of the resources — not necessarily based on size as they are today with small and large generation — but on technology.”
Brad Jones, CEO of NYISO, said storage is central to New York’s effort to create a more resilient grid following Superstorm Sandy. “The best technology for meeting resiliency at the distributed grid is having storage located there — having storage located at all the major substations to serve that load if they get disconnected.”
But, citing a Brattle Group study, he said only 40% of storage’s value is in resiliency. “The remainder of the value of storage comes from operating in the market. Recognizing that they can store energy at nighttime when it may be zero or negatively priced and can release the energy in the day when it’s positive. I’d like to see a way if we can figure out a way to capture those other benefits as well — perhaps allow the utility companies to auction off the energy value that exists in the wholesale market and then let others take that to market.”
John Jung, CEO of Greensmith Energy Management Systems, said the number of companies seeking a share of the energy storage industry will decline in the future. “There’s going to be a lot of consolidation in this space. It’s very natural. I’ve seen it in a lot of other spaces where there’s a lot of [venture capital] money. There was some $270 million in VC money that poured into this industry.”
Clean Power Plan
Gil Rodgers, senior managing director for natural gas markets at Energyzt, said he thinks the Clean Power Plan will likely survive legal challenges. “So it would be a mistake, it would really be foolish, not to consider the fact that this is something that’s coming down the road.”
Missouri Public Service Commissioner Scott Rupp said RTOs “can use [the CPP] to start making cases to build more transmission. Most of the people that make up them that have a lot of weight are the transmission companies.”
“I think it’s uncontestable” that the Clean Power Plan will be “a big driver for transmission,” agreed Larry Eisenstat of law firm Crowell & Moring.
Michael Ferguson, director at Standard & Poor’s, said states should not wait to respond to the rule. “We all know that when it comes to building a generator profile, building the transmission lines tends to be the long pole in the tent. … So if you’re a state that’s relying really heavily on new transmission build, it’s something that you probably don’t want to put off for too long.”
Kerry Worthington, a program officer for the National Association of Regulatory Utility Commissioners, also had advice. “My message to you today is to not depend on your assumptions and leave your options open,” she said. “It’s very difficult to predict with accuracy what the Clean Power Plan will look like after the stay.”
David Treichler, director of modeling and analytics at Oncor, predicted it would not be long before overnight load in Texas was served entirely by wind energy. “Things are going in this direction. CPP is not going to be the major driver for a clean Texas. Economics will be. … Government is not always the provocateur of our pain.”
Despite the CPP and competition from wind and cheap gas, some coal generation will be around for decades, said Todd Williams, a partner with ScottMadden. He noted that the average lifespan of a coal plant is 55 years and the newest one was built a year ago. “We’re going to have coal in the portfolio through at least 2070, if not beyond. … Coal’s not going away completely. Reminds me of the Monty Python skit ‘Not Dead Yet.’”
Improving Gas Infrastructure
“I would like to see going forward, in the next five years, coordinated planning discussions between the gas industry and the RTOs,” said John Lawhorn, MISO’s senior director of policy and economic studies.
“We have found that if you have a good fuel assurance program, like New England ISO has for several years, you don’t have electric reliability problems,” said Henry Chao, NYISO vice president of system resource planning.
“Ensuring that gas gets to the generators is definitely not currently in the job description of the ISOs or RTOs, as it’s currently written,” said Tanya Bodell, executive director at Energyzt. “Ensuring … reliability is; creating market-based incentives … to maintain that reliability most certainly is available.”
— Rich Heidorn Jr. and Michael Brooks