This article was originally published on March 06, 2016 on PRI and written byAdam Wernick.
A new study from NOAA shows that, by building new high-tech transmission lines, the US could slash energy sector global warming emissions by 80 percent within 15 years, while keeping consumer costs low and meeting increased demand.
Alexander MacDonald, a co-author of the study and the recently retired director of NOAA’s Earth Systems Research Laboratory in Boulder, Colorado, says studying the national weather map gave him the idea.
“I heard people talking about how renewable energy doesn’t work because it’s intermittent, and I remember saying, ‘It’s intermittent if you just have it over a really small area, but weather is big,’” MacDonald recalls. “If you look at a weather map, you see, for example, a giant high [pressure system] in the western United States and a low [pressure system] that’s windy in the east, and you can kind of deduce that if you can share the power over a large area, then it’s not intermittent. So I wanted to find out if that was true.”
MacDonald’s study, called NEWS, the National Electricity with Weather System, began six years ago. It uses a complicated optimization model based on weather forecasting to analyze the cost of energy production.
“I decided, with my team, that we would do a ‘cost minimization,’ MacDonald explains. “In other words, we would allow wind, solar and other sources, like natural gas, and even nuclear and coal, to be part of the study and we would minimize the total cost of the system, with the requirement that it supplied electric energy to 250 places over the United States every hour for a year.”
The team found that the larger the geographic area, the more effectively wind and solar can compete with other energy sources — for the exact reason MacDonald hypothesized. He explains it this way:
“In a small area, if the wind stops in part of the area, it stops over most of the area. Take the state of Kansas: if it’s not blowing on one side of Kansas, it’s probably not blowing on the other side. However, if you take the whole [lower] 48 states, you can always find places where it is pretty windy. That’s essentially what the study showed us.”
The study had another intriguing result: It showed that renewable energy can compete on price even without a major breakthrough in battery storage technology.
“We included storage as one of the things we could use,” MacDonald says. “We included transmission where we could move power over a small area or we could move it over the whole country. We basically said to this optimization [program], ‘You choose what is the best option.’”
The optimization chose transmitting power across the country as the least expensive way to use wind and solar energy. “It showed that we could have costs of electricity about the same as today, but it would reduce carbon dioxide up to 80 percent — so I think it’s a pretty important result,” MacDonald says.
There is a possible downside to the findings. In order for the system to work as efficiently as MacDonald and his team calculate, the nation would have to build massive transmission lines that would send high voltage direct current from coast to coast.
These lines can transmit “huge amounts of electric energy a long ways, but still within the cost envelope of the studies that we looked at,” MacDonald says.
But recent history has shown that people strongly oppose these powerful transmission lines passing through their neighborhoods or across their farms.
“I think people are going to have to weigh it like everything else,” MacDonald says. “If we want to preserve the future, this shows policymakers a way to do it — and it’s not for free. You might have to have overland lines; you might have to pay extra money — say, add a penny per kilowatt hour to your electric bill to have underground lines. But it gives us an option to have a low-carbon and low-cost energy economy, and we think that’s a pretty valuable possibility.”
There’s enough untapped wind howling across the vast plains of Oklahoma and Kansas to generate more electricity than a dozen nuclear power plants. What’s missing are transmission lines to ship it from spinning turbines to faraway homes and businesses.
That’s why Clean Line Energy Partners LLC plans to spend $9 billion on power transmission across the Great Plains, Midwest and the Southwest, including a 720-mile (1,158-kilometer) proposal awaiting approval from the U.S. Energy Department. It would be one of the longest high-voltage direct current lines built in a generation, and is among at least 11 proposed projects that may open up vast expanses for wind and solar farms with more than 26 gigawatts of capacity.
Renewable energy advocates say long-distance transmission will tap the wind and solar potential of the Great Plains and Sun Belt the way pipelines opened up once-inaccessible oil fields in Alaska and Siberia. These projects are seen as essential to helping states comply with President Barack Obama’s Clean Power Plan, which requires them to reduce emissions from power plants, and will help the U.S. meet its goals of getting 20 percent of its electricity from renewable sources by 2030.
“It doesn’t take a genius to say that the challenge is on the transmission side,” said Michael Skelly, president of Houston-based Clean Line. “That would enable a lot of renewable energy projects.”
It’s not easy to build transmission lines across vast regions of the country. The permitting process varies by state and can take a decade. Opposition can be fierce from landowners who don’t want high-voltage lines lines cutting through their farms or backyards. And officials can be leery of supporting projects that ships power through their jurisdiction only to deliver it to another state.
Clean Line, which is proposing five separate lines, asked Iowa regulators to suspend review of its 500-mile Rock Island line last year as the company plots its course through the approval process amid opposition from landowners. In July, Missouri’s Public Service Commission voted to block the company’s 780-mile Grain Belt Express line, saying the developer hadn’t proven the need for the $2 billion project.
“Transmission is the industry’s biggest long-term opportunity,” said Rob Gramlich, a senior vice president at the American Wind Energy Association, a Washington-based trade group. “But it’s also its biggest challenge.”
Clean Line was founded in 2009 by Skelly, a veteran of Horizon Wind Energy, which Goldman Sachs Group Inc. sold to EDP-Energias de Portugal SA in 2007. Clean Line is backed by ZBI Ventures, the investment firm controlled by the Ziff family.
The project awaiting final approval from the Energy Department, the Plains & Eastern Clean Line, will cost as much as $2.5 billion. It will be able to carry as much as 4,000 megawatts of power, linking wind farms in Oklahoma, Kansas and Texas with utilities in Tennessee, Arkansas and elsewhere in the Southeast.
The company plans to break ground next year and expects to complete it by 2020. East Texas Electric Cooperative agreed in May to buy 50 megawatts of capacity on the line.
Other developers are planning long-haul lines to move clean power across the country.
Anbaric Transmission is developing two projects in New England with National Grid Plc. A 250-mileline from wind farms in Maine to Boston is awaiting state approval. A 60-mile link from upstate New York wind farms to Vermont may be complete by 2020 and the Chicago developer Invenergy LLC and the Canadian utility Hydro-Quebec have both agreed to use it. Anbaric hasn’t determined costs for either project.
Vermont, New York
Transmission Developers Inc., backed by Blackstone Group LP, has proposed two lines to ship energy from Canadian hydro plants to Vermont and New York City, with a total estimated cost of $3.4 billion. And SunZia Transmission LLC is awaiting state approval for a pair of 515-mile lines that will cost $1.2 billion and will carry power from solar and wind farms in New Mexico to customers in Arizona and California.
Amy Grace, Bloomberg New Energy Finance’s lead wind analyst, said the question remains whether it would be cheaper to build wind farms on the outskirts of cities, where land prices are higher but transmission is easier.
“Will the cost of building wind in the central regions be so much cheaper than building wind closer to demand centers?” Grace said.
Filling a Gap
“Up until the last 10 years, no one had given much consideration to long-haul transmission,” says Bill Miller, president and CEO of TransWest Express LLC, which is planning a 730-mile line from Wyoming to Las Vegas. The Denver-based company plans to start construction in 2017 on the $3 billion project, which needs federal approval.
Most recent transmission projects are shorter lines designed to increase the reliability of grids, rather than send power long distances, said James Hoecker, counsel to Wires, the transmission industry’s Washington-based trade group. Utilities typically don’t have much motivation to build long lines that extend beyond their service areas.
Clean Line and the other developers are seeking to fill that gap. Because local power companies are usually state-based and state-regulated, Skelly said they don’t focus on how to serve entire regions, or how to run wires from wind-whipped plains to energy-hungry cities.
“Utilities don’t wake up thinking, ‘how do I get power to Atlanta?’” he said.
This article was originally published by Enerknol on January 4, 2016.
Transmission investments are becoming increasingly important to deliver electricity from new renewable generators, as the most productive areas for wind, solar, and geothermal locations are often located far from population centers. Retirement of coal plants and nuclear plants also contribute to shifts in power flows across the transmission system. However, lengthy, complicated, and costly siting and permitting processes continue to hinder installation of new transmission lines and upgrading existing ones. Since multiple federal, state, and local government agencies are involved in right-of-way authorizations and environmental permitting, inter-agency coordination is critical. Utility decisions to make long-term investments and investors’ decisions to commit capital to facilitate such investments rely on stable and predictable regulations.
The location of large-scale wind farms in remote areas creates a need for additional transmission capacity, which has been difficult to achieve due to planning and permitting hurdles that can cause delays and cost increases for new transmission projects. As solar plants increase in size, they, too, will face increasing transmission challenges. While regulatory efforts allow for inter-agency and inter-regional coordination to encourage transmission development, increased regulatory certainty to ensure adequate returns and timeliness of reviews will facilitate implementation of planned investments.
An upgraded, reliable and efficient transmission system is critical to maximize the use of lower-emitting sources and renewable resources to meet the emissions reduction goals under the Environmental Protection Agency’s (EPA) Clean Power Plan (CPP). The United States has approximately 642,000 miles of high-voltage (34 kV and greater) transmission lines, running from generating plants to step-down substations, which reduce the voltage and connect the transmission network to the distribution grid serving retail customers. Transmission upgrades will support the growing use of distributed resources to improve the flexibility and resilience of the system. These grid upgrades will also facilitate wholesale market competition and include advanced monitoring systems and technologies to ensure grid resiliency and flexibility.
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.