The US$1.6 billion Northern Pass transmission line that could tap into 1,096 MW from Canada’s largest hydropower producer, HydroQuebec, was approved Dec. 7, by a 6-0 vote of New Hampshire’s Site Evaluation Committee [SEC].
Issues remain, but if a federal permit is issued and the state SEC approves the plan, construction could begin in 2017 and the power to start flowing in spring 2019.
Once the SEC issues its written decision on the completeness question, expected by Dec. 18, a one-year clock starts ticking for the SEC to complete its review. Steps along the way include more public hearings in each of the five counties touched by the project.
The panel accepted the application by Hartford, Connecticut-based Eversource to run a 192-mile transmission line from Pittsburg to Deerfield, carrying energy from Canada to Southern New England markets.
Sixty miles of the line will be buried and project supporters say it will create jobs and lower costs in a region that routinely pays the nation’s highest average cost for electricity. The U.S. Energy Information Administration reports New England consumers will pay 19.29 cents per kWH in 2015, more than 50% higher than the national average of 12.56 cents.
“The SEC’s [Site Evaluation Committee’s] thorough review process continues with a series of public information sessions and other hearings early in the year that will allow people from across the state to comment and directly participate,” the company said. “We look forward to continuing our conversations with New Hampshire residents, and working together to secure our energy future.”
Opponents have argued the project will hurt property values, tourism and the environment.
The Society for the Protection of New Hampshire Forests and New England Power Generators Association had asked the SEC to declare the Eversource application incomplete, saying the company has not provided supporting data it has full control of land intended for the power line.
The forest society has also sued, claiming Eversource does not have the right to use a highway right-of-way that goes through land owned by the society. The state’s Department of Environmental Services also submitted comments saying it believed the application was incomplete.
“The SEC’s action was disappointing but not altogether unexpected,” society spokesman Jack Savage said. “As they acknowledged, certain property rights are in dispute. The question is when and how those property right issues are taken into consideration by the SEC, and the answer to that question remains.”
This article was originally published in Utility Dive on October 29, 2015 by Herman Trabish.
Expansion of renewable resources and new gas generation under the Clean Power Plan is expected to require thousands of miles of new transmission infrastructure in the coming years, and increasingly utilities are getting in on the race to build it.
The first wave of competitive transmission developers has already emerged, mostly spawned by utility affiliates, partnerships, and joint ventures. But new ones keep appearing, as evidenced by three recently green-lighted by the Federal Energy Regulatory Commission (FERC).
Ameren-affiliate ATX Southwest Ameren, Westar Energy-affiliate Kanstar Transmission, and Midwest Power Transmission Arkansas, a joint venture of Westar and Berkshire Hathaway Energy, were approved by FERC to compete to build transmission in unregulated markets in August.
Competitive transmission developers have the advantage of being able to work outside specific utility service territories and to access capital either from the utility balance sheet or market equity,” observed former FERC Chair James Hoecker, now the WIRES Group Counsel and Husch Blackwell Senior Counsel & Energy Strategist.
“These are ways to improve the utility’s bottom line by engaging in infrastructure development outside the service territory,” Hoecker said. “It is not a new line of business because utilities are about building infrastructure. But it is a departure.”
As indicated in the three new entries’ FERC filings, MTP Arkansas will enter the competition for projects planned by the Midcontinent Independent System Operator (MISO) and ATX Southwest and Kanstar will take part in the Southwest Power Pool (SPP) market.
“Both regions are talking about the need to strengthen their grids, so we believe there is a lot of opportunity as they go through their planning processes and identify needed projects,” said Westar Energy Spokesperson Gina Penzig of her company’s MTP Arkansas and Kanstar affiliates’ intentions.
FERC opens the transmission building market
The opportunity for utility-affiliated and independent providers to compete in this way is largely the result of FERC’s landmark Order 1000 rule, intended to bring market forces to bear in transmission building. The final version of the rule was issued in 2011.
“The new TransCos see Order 1000 as giving them the opportunity to compete,” said SPP Engineering VP Lanny Nickell.
Order 1000 opened that opportunity by removing the right of first refusal for transmission building previously held by incumbent utilities, Nickell said.
Order 1000 also required transmission providers to revise their rules to make clear which entities are eligible to propose transmission projects, what information a developer must have to support a proposal, and what the process is for project selection.
In response to FERC’s guidance that the process can be through competitive bidding, both MISO and SPP created criteria to qualify transmission developer participants and initiated solicitation and bidding procedures.
The annual MISO transmission expansion planning (MTEP) process, Patel said, is aimed at identifying projects that “maximize the value of the transmission to our customers by minimizing the energy, capacity, and transmission costs.”
FERC’s effort to open the transmission business to more competition is based on the assumption that competition “means more new ideas, more efficient capital structures, and more efficient construction,” said Clean Line Energy Partners (CLEP) Founder and President Michael Skelley. “But transmission is more complicated than the generation space so it has been slow to take off.”
CLEP, backed by National Grid and private investors, has five long-distance, high-voltage direct current lines in development that would interconnect renewables resources with MISO, SPP, and other regional systems. It has benefitted from Order 1000 provisions, but Skelly believes FERC’s intent has yet to be fully realized.
“More than half the new transmission being built in the U.S. now has for at least one of its goals greater access to wind and solar,” he said. “But most new transmission is still built by incumbent utilities. It is slowly evolving but it will take a few years.”
MISO put its transmision planning procedures in place over the last year and expects to issue its first competitive solicitation as part of its 2015 Transmission Expansion Plan. In that solicitation is what could be MISO’s first competitively bid project, the 345 kV Duff-Rockport-Coleman line.
It has 48 qualified developers among its stakeholders. The list includes developers that are competitive transmission companies (TransCos) wholly or in part affiliated with utilities, incumbent utility developers, and independent developers. At least two-thirds are utility affiliates.
“All transmission developers have to meet the same criteria to be qualified,” Patel said.
Transmission planning is about the project, she said. It can be “bottom-up,” with load serving entities or transmission owners recommending projects, or “top-down,” with MISO making project recommendations and working with stakeholders on approaches to them.
“Not all the projects we select will be competitive,” Patel said. “A baseline reliability project would not be considered competitive. A market efficiency project (MEP) or a multi-value project (MVP) would, and could be built by a competitive transmission developer.”
Bids are evaluated on multiple criteria, including their cost and specificity, the degree of cost, performance, and operations predictability they provide, and the extent to which the developer’s guarantees, commitments, and assurances minimize risk.
The May 5 SPP request for proposals included its first competitive upgrade, the 115 kV North Liberal-Walkemeyer project in Kansas.
From his perspective at SPP, Nickell agrees with Hoecker’s point that many competitive companies were formed to seize market opportinities created by FERC Order 1000 and earn FERC-guaranteed returns on infrastructure builds beyond regulated territory boundaries.
“We can structure financial products to best fit the need for each project without impacting the companies’ vertically integrated regulated activities,” Penzig acknowledged. “We think it is best to keep both activities separate and distinct.”
Some regional organizations limit competition to the planning process, and some limit it to the build out, but SPP uses competition in both phases, said Nickell.
“We identify transmission expansion needs and developers are given the opportunity to propose solutions,” he explained. “After SPP chooses the best plan, we solicit their construction proposals, giving bonus credit to the developer who made the planning proposal.”
SPP continues to build. Since its official designation from FERC, it has invested over $5.5 billion in regional transmission and has $5 billion more in early development stages, Nickell said.
It has completed only one round of transmission planning studies since Order 1000 went into effect, with only the North Liberal-Walkemeyer project in the works. From this limited experience, it has started to learn.
“The number of independent transmission developers who are members of SPP or qualified RFP participants in planning has nearly quadrupled to 23 since before 1000,” Nickell said. “And there will be more. Some companies are probably waiting for our process to prove itself before they come in.”
The increased activity has demanded much due diligence from SPP but also creates stakeholder buy-in, which is important to the organization, he said. “It has expanded the number of good new proposals and good ideas we get to evaluate.”
There will also likely be the need to assure that competitive transmission builders meet SPP’s standards for construction quality and customer service, Nickell said
“We have had a pretty steady slate of projects year after year until it spiked with MTEP 11,” the MISO exec said. “That included our first MVP slate of projects. It was a $5 billion to $7 billion investment and included 17 MVPs.”
By contrast, the MTEP 10 called for a $1.2 billion investment. With MTEP 12, investment returned to $1.5 billion, but the draft MTEP 15’s proposed investment jumped to $2.6 billion.
Patel believes the factors driving utilities to move to competitive transmission development subsidiaries could cause another spike.
“We anticipate that as we assess the system needs for compliance with theClean Power Plan (CPP) and other environmental regulations there will likely be a transmission buildout spike that will be of some significance, though it is too early to say how much,” Patel said.
Investment at the state and regional levels in transmission over the last few years has paid off in new wind and solar projects, Skelly said. In addition, “the two biggest proposed transmission projects in the country in many decades are currently up for federal review this year.”
The Anschutz Corporation-backed TransWest Express would deliver 3,000 MW of Wyoming wind through Las Vegas to load centers in the Southwest. The CLEP-developed Plains & Eastern line would deliver 4,000 MW of Oklahoma wind through Memphis to the Southeast.
With the CPP and other environmental regulations, “things are changing and companies are adapting to the new playing field,” Patel said. Regional planning authorities and forward-thinking utilities are preparing, she acknowledged.
The general expectation is that implementation of the CPP, whether throughstate or regional compliance, “will change the resource mix enough that new transmission development will be necessary,” Nickell agreed.
SPP’s study on transmission needs for compliance in its region will be completed in January 2017. “Until we see the results, we won’t fully know but there is a general anticipation,” he added.
“To the extent that SPP and MISO are looking at how the Clean Power Plan will affect their need for new transmission, it could very well have an impact,” Penzig said.
Between environmental regulations and the CPP, Westar expects the generation make-up will change more rapidly in the future than it has in the past,” she added. “These changes to the generation fleet will require additional build-out of the transmission system.”
The three filings for the new transmission utility affiliates represent a response to FERC’s longtime effort to increase competition in the transmission building space but not the response it intended, Hoecker said.
Instead of “truly independent transmission developers, it is getting TransCos that are basically affiliates of integrated utilities. That makes a lot of sense, but the FERC may not have expected these to be so potentially dominant in this market.”
Competition has not reduced the transmission building needs for protracted time and ample money that make utility-affiliates among the few with resources enough to play, he said. It has, however. brought utilities into a competitive market.
“All the old guarantees are disappearing but they are learning to take different kinds of risks in exchange for the potential of greater reward,” Hoecker said.
Pressure from new technologies and private players is precipitating change that is forcing utilities to evolve, he said. “The disturbing thing is that even though the utility business model is changing, the regulation of it isn’t changing much at all, and that is slowing things down.”
The cost of producing wind power is now competitive with coal and natural gas. Wind farms accounted for a third of total power installations nationwide since 2007. And, bolstered by President Barack Obama’s carbon-cutting scheme, the towering turbines will likely comprise a greater share of American’s electricity production in the future. A recent Department of Energy report estimated wind would make up 20 percent of U.S. power generation by 2030, up from around 5 percent today.
But in Wyoming, one of the breeziest states in the country, no new wind capacity has been added since 2010. Moreover, no new additions are expected in the near term, as projects already on the planning board work their way through a lengthy permitting process.
The main constraint facing the industry in the state remains transmission, analysts said.
Wind generation boomed last decade, as projects near existing power lines flourished. The building binge abruptly stopped when the existing lines reached capacity and demand for additional power stagnated.
“Wind has hit the point where, if you site it in the right place, it’s the cheapest form of electricity,” said Robert Godby, a professor who studies power markets at the University of Wyoming. “But in Wyoming, it comes down to that transmission. Transmission lines can be as expensive as the project.”
The uncertainty over the industry’s future in Wyoming has been compounded by a series of recent developments, threatening further delays and adding layers of doubt on wind farms already stalled for years. Those impediments range from concerns about avian deaths to federal tax subsidies and the length of contracts offered to small-scale renewable projects.
“I don’t think wind development is for the meek,” said Jonathan Naughton, director of the Wind Energy Research Center at the University of Wyoming.
A federal judge in California recently struck down the U.S. Fish and Wildlife Service’s decision to offer wind developers a 30-year eagle take permit, which would have allowed companies to kill a certain number of federally protected raptors each year without fear of prosecution. The service failed to conduct the appropriate environmental review associated with the 30-year permit, the judge ruled. The take permit is now limited to five years.
The court ruling could have a dampening effect on investment in new wind farms. Bankers might be less likely to lend to projects that could be prosecuted for eagle deaths, the thinking goes. Duke Energy became the first wind developer to be prosecuted for avian deaths in 2013, when it agreed to a $1 million settlement with the U.S. Department of Justice for raptor kills caused by two of its central Wyoming wind farms.
“I don’t think it is a project killer,” Naughton said. “It is just another thing that adds uncertainty when you’re developing a wind farm.”
A Fish and Wildlife spokeswoman declined comment on whether the service would appeal, saying it is reviewing the ruling.
Wind developers shrugged off the decision. The Power Company of Wyoming, which has proposed a 3,000-megawatt wind farm in Carbon County, said the environmental review associated with its take permit will continue. If the Denver-based firm is granted a permit, it will be for five years, a company spokeswoman said.
Eagles are not expected to be a problem for Pathfinder Renewable Wind Energy’s 2,100 megawatt wind farm near Chugwater, said Jeff Meyer, Pathfinder’s managing partner.
And sPower said it would continue to work with the Fish and Wildlife Service to minimize eagle deaths around the planned Pioneer Wind Park, its 80 megawatt wind farm proposed near Glenrock. The company declined to say whether it would seek a take permit.
The American Wind Energy Association, the industry’s chief lobbying group, cast the ruling as hypocritical, noting that other industrial developments are able to apply for permits that cover a project’s lifespan under the Endangered Species Act.
“Somehow a species like eagles that are less imperiled you can only get a permit for five years,” said Tom Vinson, AWEA vice president of regulatory affairs. The lobbying group intervened in the case against the Fish and Wildlife Service, arguing the lengthier permit provided developers economic certainty.
Opponents contend the 30-year permit offers a blank check to industry, allowing wind farms to kill eagles for an extended period of time. The American Bird Conservancy, which brought the case against the service, did not respond to a request for comment.
The eagle ruling is just one piece in a wider puzzle of uncertainty facing the industry. A 2.3-cent-per-kilowatt-hour tax credit expired in 2013. A provision in the tax code allows developers who began work in 2014 to qualify for the credit, helping drive a boost in installations in 2015.
Many projects being proposed today are larger than their forebears and do not need the tax credit to be economical, Naughton said. Both Chokechery and Pathfinder’s developers said they were not relying on the tax credit to move forward.
Lazard, an investment bank, estimates that wind power is often cheaper than coal and natural gas — even without the subsidy. The cost of wind power now ranges from $37 per megawatt hour to $81 per megawatt hour. Coal, by contrast, has a cost range of $66 to $151 per megawatt hour while combined cycle natural gas plants boast costs between $61 and $81 per megawatt hour, Lazard found.
Still, political debate over the tax credit’s plight creates uncertainty for developers who don’t know whether they can rely on the subsidy, Naughton said. Congress passed a one-year extension of the credit in 2012, then declined to extend it in 2013. Debate over whether to reinstate the credit in 2016 is ongoing.
“If you go out to the lobbyists, they will say we need it. If you go to the industry, they say we like it but we don’t need it,” Naughton said. “I think what you’re seeing is the maturing of the technology.”
Meanwhile, in Wyoming, small-scale producers face a new challenge. Rocky Mountain Power, the state’s largest utility, is seeking to limit the length of contracts granted to small-scale renewable developments from 20 years to three. Utilities are required under the Public Utility Regulatory Act to take electricity from projects that generate less than 80 megawatts of renewable power, provided they do not increase electricity rates. The legislation was crafted during the Arab oil embargo and meant to spur renewable power production.
But Rocky Mountain Power, in a filing to the state Public Service Commission, argued PURPA projects are now overwhelming its system. The Salt Lake City-based utility said it is facing 713 megawatts in proposed PURPA projects, in addition to 413 megawatts in existing PURPA development. Combined, the small scale renewable power developments would be enough to supply 96 percent of its retail electric load.
The flood of proposals comes at a time when Rocky Mountain Power predicts “no need for any system resource until at least 2028,” the utility wrote.
Rocky Mountain Power’s application follows a ruling from the Idaho Public Utilities Commission last month, which saw regulators limit the length of PURPA contracts in that state to two years. Three utilities, including Rocky Mountain Power, argued they had been swamped by proposed PURPA projects, thanks in part to an Idaho regulation providing fixed-price contracts to small-scale renewable projects.
sPower, which plans to finalize a proposed PURPA project in the Pioneer Wind Park, said it would not be affected by a change. The proposal would apply only to proposed PURPA projects, the Salt Lake City-based developer said, noting its contract with Rocky Mountain Power has already been signed.
A company spokeswoman nonetheless defended the long-term contracts offered to small-scale renewable projects.
“Fuel sources for renewable energy projects like solar or wind are unlimited and not volatile like fossil fuels. Long-term contracts allow for stable and predictable energy prices as compared to the variability in natural gas pricing,” said Naomi Keller, the spokeswoman.
Still, transmission remains the greatest hurdle to the industry in the Cowboy State. Wyoming exports far more energy than it consumes, meaning its primary markets are beyond its borders.
TransWest Express is illustrative of the challenge. The 730-mile transmission line, which would run from the Power Company of Wyoming’s Chokecherry Sierra Madre Wind Farm near Saratoga to Las Vegas, was first proposed in 2005. The U.S. Bureau of Land Management is expected to issue a record of decision on the transmission line later this year.
Given the lengthy permitting process, Power Company of Wyoming had to take a giant leap of faith to propose Chokecherry and TransWest Express, said Godby, the University of Wyoming professor.
But until those new lines are built, no new wind farms are expected.
“There is no way to get their energy out of the state the way they want to,” Godby said.
This article was originally published on September 2, 2015 on the AWEA Blog and written by Michael Googin
2014 saw record high wind output in the U.S., most notably when wind energy provided large amounts of extremely valuable power that helped keep the lights on during extreme cold in January 2014. However, the downside of 2014’s record high output is that it makes 2015 wind output appear to be drastically lower. Several recent news articles have used the comparison against 2014 output to build the narrative that 2015 wind output has been concerningly low.
While the first half of 2015 has seen below average wind speeds, a more meaningful comparison against a longer-term average shows 2015 wind output to be within the normal bounds of inter-annual wind output variation. Moreover, several months of below average wind output are not a reason for concern, as they fall within the band that grid operators and power plant investors expect because many sources of energy experience variability in fuel supply.
The EIA data in the table below show that the first six months of 2014 and 2015 both depart from the more typical wind output in 2013, with 2014 being a few percentage points higher and 2015 a few percentage points lower. Moreover, each datapoint covers only a narrow six month period, and the anomalies seen during those periods were offset by more normal levels of wind output during the latter six months of the year, as shown in the chart further below and as one would expect due to the statistical principle of regression toward the mean.
With that full context provided, it is clear that a few percentage point difference in wind output over a few months is not a reason for concern. However, if one focuses solely on the change from 1H 2014 to 1H 2015, as several recent articles have done, then one can get the mistaken impression that the wind output seen during the first few months of 2015 is a cause for concern.
The green line in the chart below shows that the wind resource was extremely high in 2014, significantly higher than any other year in the last 15 years. Even 2013 fell in the top four wind resource years over the last 15 years, so 2015’s wind output would look even less unusual if it were compared to a more typical year than 2013 in the table above.
The following chart shows that the average capacity factor for the first half of 2015 is still higher than that seen in the first halves of 2007, 2009, and 2010, based on an estimate calculated from EIA capacity and January-June generation data for all U.S. wind projects. In addition, total wind energy production in the first half of 2015 is higher than that seen in the first half of any year except 2014.
Inter-annual variations in wind output are not a concern, as variability in fuel supply affects nearly all sources of energy. Last year one-third of Midwest coal plants had their fuel supplies curtailed due to railroad constraints, while natural gas pipelines experience congestion or even supply shortages. Natural gas prices have varied by a factor of five over the last 10 years due to fluctuations in supply and demand, resulting in large fluctuations in electricity prices and consumer costs. In contrast, wind plants have no fuel costs, so utilities that diversify their fuel mix with stably-priced wind protect their consumers from electricity price volatility. In addition, all power plants experience failures from time to time, which are a far larger cost for grid operators than the gradual and predictable changes in wind energy output. As another example, the hydropower resource varies more from year to year than the wind resource, yet the Pacific Northwest has successfully relied on hydropower to provide the majority of its electricity for several generations.
The main reason why the United States built an interstate power system 100 years ago was so that a large number of power plants and sources of electricity demand, each of which is inherently unreliable, could be combined to make a reliable power system.
A strong transmission system plays a key role in accommodating the fluctuations in the availability and price of all fuels. For example, transmission lines like the Pacific DC Intertie in the Western U.S. allow wind and hydropower to be delivered from the Pacific Northwest to California when output is high in the Northwest, while the line can flow in reverse when hydropower, wind, and solar generation is high in California and total generation supply is low in the Pacific Northwest.
AWEA Manager of Industry Data and Analysis John Hensley contributed to the analysis included in this post.
Clean Line Energy believes it can develop long-distance high-voltage direct current (HVDC) transmission lines that will inexpensively move gigawatts of cheap wind (and solar) power — and still allow competitive pricing at the end of the line.
There are wind projects in the Midwest that generate power at 1.5 cents to 3 cents per kilowatt-hour. (That equates to 3 cents to 4.5 cents without the Production Tax Credit.) Yet while these regions might actually be curtailing wind at times and are limited by transmission capacity, other regional grids are hungry for low-cost power or renewable power. Demand is being driven by renewable portfolio standards, the Clean Power Plan, and the retirement of 50 gigawatts’ worth of coal power.
The problem is getting that cheap wind power to where it’s needed.
The founder and president of Clean Line Energy, Michael Skelly, wants to connect low-cost wind resources to major demand points.
He believes that transmission is the key ingredient to getting more renewable energy on-line. “That’s why we started Clean Line,” Skelly said during a webcast hosted by Julien Dumoulin-Smith of UBS Securities equity research. Dumoulin-Smith called the concept “wind by wire.”
Skelly said, “We believe that an independent [company] is suited for the job,” suggesting that most utilities are mandated to meet local needs and are not thinking of the challenge of interstate transmission or providing “the development capital required to get a project like this going.”
The founder of the aspiring merchant-model transmission company said that bigger blades, taller towers and lighter materials mean the central part of the country provides a “deep supply base for the resources we want to tap.” He notes that there are developers active in the region and what they need is “access to markets.”
“We believe our product will be a valuable addition to the grid in the Southeast,” said Skelly.
Skelly’s firm suggests that DC, unlike AC, “allows complete control of power flow and prevents cascading outages.” A Clean Line ±600 kilovolt DC bipole transmission line will have a 3,000 megawatt to 4,000 megawatt capacity.
As Jeff St. John has reported, China is by far the biggest consumer of HVDC technology, spending billions and building tens of thousands of kilometers of new 330-kilovolts-and-up transmission lines. According to earlier reports, HVDC could make up 40 percent of the country’s 300 gigawatts’ worth of new transmission capacity.
Clean Line notes, “The last long-distance HVDC transmission line in the U.S was completed in 1989.”
According to market analysts, there is strong demand for HVDC transmission. Siemens reports on its website, “In the last 40 years, HVDC transmission links with a total capacity of 100 gigawatts [have been deployed.] Another 250 gigawatts will be added in this decade alone.”
An HVDC line requires a converter station on each end; one at the windward end, where the AC voltage of the conventional power grid is converted into DC and one at the delivery end, where the DC voltage is converted back into AC. HVDC equipment vendors include ABB, Siemens, Alstom, AMSC and Schweitzer Engineering Laboratories. Converter stations represent about a third of the total project cost, according to Skelly.
2 cents per kilowatt-hour to get to market
“It will cost producers about 2 cents per kilowatt-hour to get to market,” and that’s an “all-in delivered cost,” according to the company founder.
Skelly suggests that the best business model for a transmission build-out is the “merchant model,” where Clean Line would contract with large wind producers looking to get to market. The energy suppliers would buy capacity from Clean Line — similar to the way the gas pipeline industry works, according to the Clean Line founder.
Typically, most transmission is built through a cost allocation process — PJM or MISO would get together with various utilities and PUCs and cost would be spread among all users of the grid. Skelly notes, “Because we don’t have an inter-regional cost allocation process, we depend on a participant-funded merchant model.”
One of the “biggest parts of our job,” according to Skelly is to get regulatory approval for the 200-foot-wide, 750 mile-long route. He said “having been at this for six years — we are working our way through different regulatory processes” and working with the PUC or federal transmission siting authority. He notes that the routing process requires tremendous levels of stakeholder approval.
One of the big challenges in handling this much power, said Skelly, is the interconnect process “that requires a lot of studies” to make sure these lines don’t cause issues on the rest of the grid. “We spend a lot of time looking at wind integration,” said Skelly. Most high-penetration renewable scenariosemploy HVDC.
Potential offtakers for the delivered power include utilities in the Western U.S., Southeastern U.S., and PJM.
Skelly is confident that wind power can be delivered 750 miles from the source at a cost of under 6 cents per kilowatt-hour without the PTC — making it cheaper than fossil fuels or solar.
Skelly said it can take “years for things to unfold” in the space, adding, “The cost of capital for that is reasonably high because it’s a really risky business.” But once a project is built or contracted, “then there’s a tremendous amount of low-cost capital. That’s the piece of the value chain investors prefer to focus on.”
Clean Line is backed by National Grid, Ziff Brothers Investments and Bluescape Resources.
GTM just reported on the recently released Department of Energy/Lawrence Berkeley National Laboratory’s 2014 Wind Technologies Market Report, which sees the wind industry facing policy and supply chain challenges — but projects that the trajectories of capacity growth, blade-size growth and falling prices for wind will continue. (Here’s a link to the slide deck summary in PDF.) Large rotor machines are being used at both low- and high-wind-speed sites. Turbine scaling is boosting wind project performance, even as project costs continue to drop. Annual wind capacity additions rebounded in 2014, with 4,854 megawatts of new capacity — and there’s a great deal of evidence pointing toward a strong 2015 and 2016 to come.
Skelly emphasizes that the transmission development process requires “patience and tenacity” but adds that each of his projects could bring 4 gigawatts of wind to market that previously could not get there due to lack of transmission.
This article was originally published in SLATE and written by Daniel Gross.
One of the raps on big renewable energy projects, such as solar plants and wind farms, is that they rely on federal subsidies and tax credits to get off the ground. That’s obvious. Here’s something less obvious: Taxpayers may have subsidized the boom in emissions-free energy, but that’s triggered a whole lot of unsubsidized private investment in turn. Someone has to pay to build the infrastructure that conveys the power from the empty places where it’s produced to the populated places where it’s consumed.
This is particularly evident in wind energy. Developers needs the federal production tax credit—2.3 cents for every kilowatt-hour produced by a wind farm for 10 years after its construction—to justify the nine-figure investments to plant clusters of turbines in the plains. But just as oil needs pipelines and coal needs railroads, wind power needs transmission lines to reach cities. A report by the Edison Electric Institute, a trade group for investor-owned utilities, highlighting some $47.9 billion worth of transmission lines in the works through 2025, found that about $22.1 billion in funds will be spent on transmission projects aimed at integrating renewable energy into the grid.
And there could be much more to come. In Houston, the global capital of the fossil fuel industry, a startup, Clean Line Energy, is aiming to replicate the feats of 19th-century railroad barons, erecting audacious, expensive tracks that will turn farmland and fallow space into economically useful terrain. The company wants to spend about $10 billion in private capital to wire the plains with direct current electricity wire. The names of its proposed lines evoke the age of the iron horse: There’s the Rock Island Clean Line, which would ferry juice 500 miles from Iowa to Illinois; the Grain Belt Express, traversing 780 miles from Kansas to points east; and the Plains & Eastern, which would convey power from the windy Oklahoma panhandle to Memphis, Tennessee. (Here’s a map of Clean Line’s proposedprojects.) Farther to the west, billionaire Philip Anschutz is plotting the TransWest Express, a 730-mile line from Wyoming to Las Vegas. That effort, along with Clean Line’s Plains & Eastern—both of which could get federal approval to proceed this year—“may be the two most ambitious transmission lines ever built in this country,” says Michael Skelly, president of Clean Line Energy. (The Pacific Intertie, which connects Oregon hydropower to Southern California, is actually longer than both of these proposed lines.)
Skelly has some experience tilting at windmills. He was chief development officer of Horizon Wind Energy, a Texas-based development firm bought by Goldman Sachs in 2005. (In 2008, in another quixotic quest, he ran for Congress in Texas’ deep-red 7thdistrict as a Democrat and lost.) The wind industry boomed in Texas in part because the state, which has its own grid, pushed through a plan that enabled the construction of massive wind farms in the western and northern parts of the state, encouraging about $6 billion in new transmission lines to bring the power to population centers.
Outside of Texas, however, the electricity grid is highly balkanized. Utilities in Oklahoma aren’t particularly interested in figuring out how to convey wind power from the Oklahoma panhandle (where it could be produced in massive quantities) to Atlanta (where it would be consumed in massive quantities). And the federal government has long since gotten out of the business of backing big interstate power highways. (The last major electricity interstate highway it supported was the Pacific Intertie, completed in 1970.) That means a large chunk of America’s wind resources remains stranded.
In 2009, Skelly helped found Clean Line, which has raised more than $100 million in capital from investors including National Grid. The idea: build a series of long-haul transmission lines—400-, 500-, 700-miles long—and rent capacity to wind developers so they can send their power to market. (Rule of thumb: It costs about .3 cents to send a kilowatt-hour of power 100 miles.)
It sounds like a simple business model. But as pipeline builders have found (hello, Keystone XL!), building energy infrastructure that crosses several state lines requires negotiating a maze of state regulators, federal authorities, and private landowners. And for a host of reasons—economic, political, regulatory, environmental—people aren’t always psyched about big projects coming through their proverbial backyards. For example, while Indiana and Kansas have given approval to the Grain Belt Express, which would connect Dodge City, Kansas, to southern Indiana, Missouri has said no. (In certain circumstances, transmission developers can appeal such denials to the federal government, which Clean Line has done.) “A wise person said that anything worth doing takes a decade,” said Skelly. “And we are going to prove them right. We haven’t done this before in this country. We haven’t built four-state transmission lines.”
Skelly is confident that Clean Line can raise the $10 billion needed to build its five proposed lines and that construction could start as early as 2017 if approvals start to come through.
Clean Line’s ambitions highlight the complexities of the arguments surrounding energy subsidies. Yes, Clean Line’s customers—developers of wind plants—rely on subsidies. And those subsidies cost real money. According to the Energy Information Administration wind accounted for 4.4 percent of U.S. electricity production in 2014, or about 180 billion kilowatt-hours. Assuming every one of those kilowatt-hours is eligible for the 2.3 cents per kilowatt-hour (and they’re not—wind farms more than 10 years old can’t get the credit, for example), the production tax credit would amount to a maximum of about $4.2 billion year.
The American Wind Energy Association argues that every form of energy production is subsidized to a degree and that the U.S. is getting a lot in return for whatever subsidy wind receives. The burgeoning wind industry has accounted for some $100 billion of investment since 2008 (a period in which the U.S. suffered a big shortfall in investment), created tens of thousands of permanent jobs, and stimulated the creation of a domestic manufacturing sector. It also funnels $195 million a year in lease payments to farmers, ranchers, and other landowners.
But as Clean Line’s ambitious plans show, the wind boom has also inspired people and businesses to do something they didn’t do much before 2008—think big and funnel private capital into infrastructure projects. And when private firms erect new platforms that encourage other private companies to invest and build, that’s a form of economic stimulus worthy of a few lofty railroad metaphors.
If you had to choose one word to sum up EPA’s 1570-page Clean Power Plan (CPP) Final Rule, released on August 3rd, “interconnected” would be it. According to EPA, the key to cutting the carbon footprint of America’s electric system by almost one third over the next 15 years is the nation’s interconnected high voltage transmission system. The final rule uses some form of the word “interconnected” more than 80 times – mostly in the first few hundred pages that explain the rationale for the overall approach of the regulation. EPA seems determined to remind us that despite recent growth in distributed generation and lots of talk about “going off the grid”, the “interconnectedness” of our grid is, in fact, indispensable to cutting carbon emissions in the fastest, most economical, and least disruptive possible manner. Why?
Transmission networks allow vast, but remote, wind and solar resources to be developed and delivered to customers reliably and at large scale and low cost.
The interconnected grid is infrastructure for markets that fosters competition and resource diversity over large regions – cutting prices and improving reliability.
States connected by transmission lines can work together to achieve their emissions targets much faster and at lower cost than they could by working alone.
To reap the full benefits of the interconnected grid, EPA strongly encourages states to cooperate on multi-state compliance strategies. Those benefits are very large, according to recent studies by three of the nation’s largest regional transmission organizations (RTOs) – which together provide electricity to 124 million people in 28 states. “For a state-by-state compliance approach, the capital investment cost and energy production cost totaled about $3.3 billion per year. The total capital investment cost and energy production cost for a regional approach is about $2.4 billion,” said Lanny Nickell, Engineering Vice President for the Southwest Power Pool (SPP), “It is almost a 40% savings associated with complying on a regional basis.” SPP’s July 27 State-by-State Compliance Assessment Report concludes that “state-by state compliance plans will be more costly and will present more uncertainty and complexities for SPP stakeholders,” and further that “a regional approach to compliance would be more cost effective and less disruptive than a state by-state approach and may provide mutually beneficial opportunities that are not available within state boundaries.”
Previous studies by the Midcontinent Independent System Operator (MISO) and PJM Interconnection reached remarkably similar conclusions. MISO’s November, 2014 Analysis of EPA’s Proposal to Reduce CO2 Emissions from Existing Units found that “regional compliance is approximately 40% less expensive: $55 billion (regional) vs $83 billion (sub-regional),” equivalent to savings of $3 billion per year during the compliance period. The PJM Interconnection’s March, 2015 Economic Analysis of the EPA Clean Power Plan Proposal concluded that “state-by-state compliance options, compared to regional compliance options, likely would result in higher compliance costs for most PJM states. This is because there are fewer low-cost options available within state boundaries than across the entire region.”
EPA’s CPP Final Rule embraces precisely the same reasoning as the RTO studies: “The final rule more realistically recognizes that emission reduction opportunities, like other aspects of the interconnected electricity system, are regional and are not constrained by state borders.” In other words, regional compliance is cheaper and faster for the simple reason that working together gives states access to more inexpensive compliance options. Regional transmission makes this type of cooperation possible; regional markets enhance it further.
Interstate transmission networks are critical infrastructure for complying with the CPP’s 2022 and 2030 targets, but even more important for achieving the long term emissions cuts – 80 percent or more by 2050 – needed to avert catastrophic climate change impacts. Numerous recent studies show that it’s economically and technically feasible to power the U.S. electric system with 80 to 100 percent renewable resources, but only if transmission networks are expanded and upgraded to accommodate new resources. The mismatch between the timelines for building new and upgraded high voltage lines – 8 to 10 years or more – and the timelines for building utility scale renewable energy facilities – 1 to 2 years – has been well documented by ACEG and many others over the past several years. Building this infrastructure will take time, unprecedented cooperation among states and federal agencies, and perhaps even additional policy reforms. The CPP provides states with a framework and new incentives to start planning and building the interconnected clean energy grid we need sooner rather than later; policy makers, regulators, utilities, clean energy developers, ratepayers, and environmental advocates all have an interest in making sure that they use them.
Powering everything in America with renewable energy by 2050 – including transportation – is economically and technically feasible using existing and proven technologies, according to a new study by Mark Jacobson and colleagues at Stanford University. As scientific evidence grows that avoiding catastrophic climate change impacts might actually require the U.S. and other countries around the world to transition to a 100% renewable energy system (or something very close to it), Jacobson’s study provides a much needed, practical, and high level vision of how the U.S. could achieve it. Three findings of the study stand out:
More than 90 percent of renewable generating capacity is utility-scale – including a large majority of solar PV; virtually all generation is connected to the grid.
Transmission and non-battery storage balance the natural variability of wind and solar to provide 24/7/365 power to everyone, everywhere.
Electrifying everything, including transportation, together with energy efficiency, demand response, and distributed generation make are essential to the ultimate goal.
Bigger is Better and Cheaper
The welcome and highly visible recent explosion of rooftop solar sometimes obscures powerful economies of scale at work in renewable energy. Utility scale photovoltaics (PV) produce power at half the cost of rooftop installations. Wind power is only economical at large scales. The overwhelming majority of solar and wind power produced in the U.S. today comes from grid-connected, large scale facilities owned by or under contract with utilities.
Jacobson’s vision of the future is no different, with large scale renewables providing about 93 percent of the power: 50 percent wind (30.9% onshore; 19.1% offshore); 30.7% utility-scale (PV), 7.3% concentrated solar power (CSP) with storage, 7.2% rooftop PV, 1.25% geothermal power, 0.37% wave power, 0.14% tidal power, and 3.01% hydroelectric power.
Transmission and Non-Battery Storage Smooth Out Variability
How does Jacobson turn myriad variable renewable generators into smooth and reliable 24/7/365 power in all 50 states? Transmission and storage – batteries not included. Transmission lines slash natural variability by blending diverse wind and solar resources over large regions:
“. . . while the study bases each state’s installed capacity on the state’s annual demand, it allows interstate transmission of power as needed to ensure that supply and demand balance every hour in every state. We also roughly estimate the additional cost of transmission lines needed for this hourly balancing.”
More transmission, Jacobson notes, would make it even easier and cheaper to achieve 100% renewable energy, by allowing the best quality, least cost resources to serve more customers in more states:
“ . . . if we relax our assumption that each state’s capacity match its annual demand, and instead allow states with especially good solar or wind resources to have enough capacity to supply larger regions, then the average levelized cost of electricity will be lower than we estimate because of the higher average capacity factors in states with the best WWS resources.”
Storage and demand response take care of the remaining variability – but not batteries – which are exclusively reserved for their higher value use in transportation:
“Solutions to the grid integration problem are obtained by prioritizing storage for excess heat (in soil and water) and electricity (in ice, water, phase-change material tied to CSP, pumped hydro, and hydrogen); using hydroelectric only as a last resort; and using demand response to shave periods of excess demand over supply. No batteries (except in electric vehicles), biomass, nuclear power, or natural gas are needed.”
Small is Still Beautiful – and Essential
Despite outsized roles for utility scale renewables and transmission, energy efficiency, distributed generation, and smart technologies to enable demand response remain as large and essential elements of Jacobson’s vision. Efficiency alone reduces projected 2050 electricity demand by 39.3% – even as every end use, including transportation, converts to electricity. Power supplied by distributed rooftop solar explodes from a fraction of one percent today to more than 7 percent in 2050. Demand response plays a critical role in balancing variability. Finally, Jacobson deploys a suite of flexible low-cost resources to maintain high power quality:
“Frequency regulation of the grid can be provided by ramping up/down hydroelectric, stored CSP or pumped hydro; ramping down other WWS generators and storing the electricity in heat, cold, or hydrogen instead of curtailing; and using demand response.”
And It’s All Free
A 100% renewable energy system is actually better than free – a lot better. The study estimates that by 2050, converting the U.S. to 100% renewable energy would, compared to business-as-usual:
Save the average U.S. consumer $260 per year in total energy costs (including transportation);
Produce a net gain of 2 million, 40-year energy sector jobs (accounting for fossil fuel job losses);
Eliminate 46,000 to 62,000 premature deaths or $600 billion per year due to air pollution; and
Avoid $3.3 trillion in worldwide global warming costs due to U.S. emissions.
The future energy system for the U.S. and the world looks clearer every day – all electric, all renewable, and all running on robust and sophisticated continental grids. No it’s time to start building it.