One man’s failed attempt to build a transmission line illustrates a unique American obstacle to clean energy.By Peter R. Orszag July 10, 2019, Bloomberg, “Guess What’s Holding Back Wind Power in the U.S. “
Peter R. Orszag is a Bloomberg Opinion columnist. He is the chief executive officer of financial advisory at Lazard. He was director of the Office of Management and Budget from 2009 to 2010, and director of the Congressional Budget Office from 2007 to 2008.
The cost of wind energy has dropped drastically over the past several decades as the technology has advanced, especially in the size of turbines. Since 2009, the unsubsidized average cost of onshore wind-energy production has fallen to 4.2 cents per kilowatt hour, from 13.5 cents in 2018, according to an analysis by Lazard, the company I work for. After including U.S. tax subsidies, the cost of building wind capacity is often lower than the marginal cost of generating electricity with existing coal-powered plants. Thus wind energy now offers great opportunities for lowering carbon-dioxide emissions.
But a surprisingly difficult challenge remains: how to move the wind energy from the places where it is produced — often remote areas — to the population centers where it is needed. One reason wind accounts for a greater share of energy produced in Europe — it represents 12% of electricity in Germany and 19% in Spain, compared with just 7% in the U.S. — is not that more wind blows there. It’s partly that European infrastructure facilitates transmission of the power to the places where people live.
One big reason the U.S. lags in such transmission is dramatically illustrated by the experience of Michael Skelly, who was a founder of one of America’s largest wind-power companies, and is now an adviser at Lazard. Beginning almost a decade ago, Skelly tried to construct a 700-mile high-voltage direct-current line to carry wind energy from the Oklahoma panhandle to Tennessee. In the end, he was stymied by opposition from property owners and government officials who refused to allow the line to cross their land. As Wall Street Journal reporter Russell Gold tells the story in his new book, “Superpower: One Man’s Quest to Transform American Energy,” Skelly worked tirelessly to navigate the difficult local politics.
The underlying policy issue here involves eminent domain, the power that governments use to force local property owners to seal easements across their land for some broader public purpose. Unlike interstate natural gas pipelines, which have been able to exercise eminent domain under federal law since Congress passed the Natural Gas Act in 1938, interstate electricity-distribution lines lack any such authority. In virtually every jurisdiction along the path of Skelly’s proposed wind-energy line, he faced substantial local opposition.
This problem theoretically could have been prevented. Back in 2008, President-elect Barack Obama’s transition team, of which I was part, discussed the idea of adding federal eminent domain for electricity lines to the economic stimulus bill. Obama rejected the idea because it was controversial enough to endanger the urgent stimulus package. In so doing, the former president lost a crucial opportunity to transform the electricity industry, argues Reed Hundt, a former chairman of the Federal Communications Commission, in another recent book, “A Crisis Wasted.” It’s true that if Obama had tried and succeeded, Skelly’s story would have turned out differently. Yet Skelly’s experience also confirms that the politics of this issue are heated enough to have posed a threat to the stimulus bill itself.
So what now? Other efforts are being made to build lines in the same way Skelly tried, proceeding on the theory that, as Gold puts it, the “second mouse gets the cheese.” Two other approaches might get around the local difficulties detailed in “Superpower”: developing offshore wind farms near population centers (with underwater transmission lines), and laying high-voltage lines along existing highways or railroad lines.
Another way to substantially alter the trajectory of wind energy in the U.S. is to attach a price to carbon-dioxide emissions, so that wind energy becomes more cost-effective even in less windy areas, thereby making the transmission problem less severe. Many approaches to such pricing are possible. And although political obstacles make Congress unlikely to adopt any of them in the foreseeable future, some state governments aren’t waiting. Today 11 states, accounting for about a quarter of the U.S. population, have carbon pricing policies in place.
“Superpower” concludes on a somewhat discouraging note. But if turbine technology continues to advance, new ways are found to move wind energy to population centers, and states are able to set a price on carbon, Skelly’s story may one day be seen as merely a hiccup in the greater rise of wind power in the U.S.
This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.
Solar + wind + storage developers ‘gearing up’ as hybrid projects edge to market, Herman K. Trabish, Utility Dive, July 9, 2019
A “wave” of new projects is coming to use wind, solar, and battery storage in ways that will stabilize grids, increase efficiencies and lower power costs.
Renewables are shedding their individual identities as wind and solar become clean energy MWhs.
Though no full-scale hybrid projects co-locating both resources and energy storage have been built in the U.S. and few are online around the world, the U.S. renewables industries are taking on barriers such as interconnection, dispatch and compensation challenges, according to speakers at the 2019 American Wind Energy Association’s Windpower conference.
“It’s like the storm is brewing. It hasn’t coalesced yet, but hybrid projects are absolutely the future.” – Rhonda Peters, Consulting Principal, InterTran Energy
For the first time, the conference featured multiple sessions on the trials and opportunities of these hybrid renewables projects. In line with the ambitious resource partnerships among renewable energy groups, next year’s conference will be rebranded Cleanpower 2020.
Developers of hybrid projects “are gearing up,” InterTran Energy Consulting Principal Rhonda Peters, who has long worked on regulatory obstacles to hybrid projects, told Utility Dive. “It’s like the storm is brewing. It hasn’t coalesced yet, but hybrid projects are absolutely the future.”
Academic studies show the theoretical value of co-located wind and solar when characteristics like resource intensity are complementary. Pilot projects in the U.S. and other countries have validated the research. Power purchase agreements (PPAs) for utility-scale hybrid projects are in place in Oregon and Arizona. But the concept may not become a marketplace reality until regulatory and policy barriers are overcome.
Hybrid projects are defined as two or more fuel sources that share a point of interconnection and are dispatched “as a single generation entity,” according to Peters. Theoretically, such projects could allow renewables to participate in capacity markets and be stored for use during peak demand periods that would otherwise require natural gas peaker plant generation.
“Wind and solar are the two cheapest options for new generation, but their production is variable and they don’t always generate when the grid needs it most,” Rice University Associate Professor of Civil and Environmental Engineering Daniel Cohan told Utility Dive.
Wind’s nighttime generation and solar’s daytime output can address some of those limitations, Cohan’s research on the Texas grid showed.
Co-located wind-solar projects, sited at or near the same substation, are also technically feasible and can be economically viable, he said. But sites needs adequate wind and solar resources, suitable land and available transmission capacity, and those three conditions “won’t be everywhere,” he added.
“Utilities from coast to coast, in places that would never be expected to be interested in solar-storage hybrids, are going after” hybrid projects. – Derek Price, VP of Storage, Invenergy
Adding low priced solar to wind projects in places with high wind capacity like West Texas and Iowa makes sense because transmission capacity is likely to be available for solar during the day, he said.
Wind-solar-storage would also likely be economically viable in those places, because those projects would require less storage, which is still not as cheap as wind and solar.
Though there are not many co-located hybrid projects in service, such projects do exist at different levels of development and operation across the U.S., Asia and Australia, Global Wind Energy Council (GWEC) Director of Market Intelligence Karin Ohlenforst told Utility Dive.
A key to growth will be demonstrating that the unique values of hybrid projects, like delivering capacity when it is most needed, are not just theoretical, she added.
Utilities and developers are beginning to move those values from theory to practice, starting with solar-storage hybrids.
In practice – utilities
“Utilities from coast to coast, in places that would never be expected to be interested in solar-storage hybrids, are going after” hybrid projects, Invenergy VP of Storage Derek Price told Utility Dive. “The solar-storage hybrid is going to explode in the marketplace.”
“We have a large number [of hybrid projects] under development for 2020 to 2023 delivery,” Price said at the conference. “As the cost of solar drops, greater acceptance of the technology by utilities will follow quickly.”
Invenergy expects almost all of its installed solar to be retrofitted with storage, he added. Arizona Public Service (APS) “calls it ‘solar after sunset’ and sees it as having a big impact on its cost curve.”
APS announced a groundbreaking 65 MW solar plus 50 MW battery storage hybrid project in February 2018, which is scheduled to come online in 2021, replacing natural gas peaker generation. The price remains undisclosed, but came out of a competitive all-source solicitation.
The utility doubled down on solar-storage hybrids in its February 2019 Clean Energy Initiative, which will add 850 MW of battery storage at new and existing solar projects by 2025, APS spokesperson Jenna Rowell emailed Utility Dive. And another APS solar-storage solicitation was issued April 3 for 100 MW of solar and 100 MW of storage, the next stage of a build-out toward 1 GW of solar-storage capacity by 2025.
“[I]n futures with low technology costs and high renewable development across the West, batteries may be cost competitive with traditional thermal resources.”
PGE Draft 2019 IRP
In Oregon, Portland General Electric (PGE) announced an even bigger breakthrough in February. Wheatridge, the first co-located U.S utility-scale wind-solar-storage hybrid project, will include 300 MW of wind, 50 MW of solar and 30 MW of 4-hour duration battery storage, and is expected to be fully online by 2021, PGE spokesperson Steven Corson told Utility Dive.
PGE will pay $160 million to own 100 MW of the wind. NextEra Energy Resources will build and operate Wheatridge, own the balance of the project, and sell the output to PGE under a 30-year PPA. Offers, including NextEra’s undisclosed winning bid in the all-renewables solicitation, came in at prices “competitive with conventional resources,” Corson said.
“The levelized cost of energy (LCOE) from new wind resources is expected to be below the LCOE of a combined cycle combustion turbine,” PGE’s draft 2019 integrated resource plan reported. And “in futures with low technology costs and high renewable development across the West, batteries may be cost competitive with traditional thermal resources.”
To maximize the return on the federal investment tax credit, the PGE project’s solar generation will charge the batteries, Corson said. “That will allow the solar-storage component to smooth the wind’s variability. The draft plan may lead to another all-renewables solicitation for non-emitting capacity resources.”
With both the APS and PGE flagship U.S. hybrid plants yet to come online, they do not take the hybrid concept far beyond theory. But developers are making big plans.
In practice – developers
GE has built and tested two hybrid projects over the past five year as part of subsidiary GE Renewables’ focus on integrated hybrid projects. The company recently estimated the global market for hybrid power to be at least $1.47 billion by 2024.
In Minnesota, it paired a 2.3 MW turbine with 500 kW of solar and in India, paired a 1.6 kW turbine with 223 kW of solar.
Efficiency is key to development. Each project had an approximately 5% energy production improvement over projections for individual resources. “Even a small increase warrants the investment,” Jean-Claude Robert, GE’s hybrid solutions lead, told Utility Dive.
To further drive hybrid project efficiency, GE also developed a “hybrid plant control solution.” The digitally-based technology enables the hybrid system to produce “renewable MWhs” rather than “wind MWhs or solar MWhs,” Robert said.
Countries “leading the charge on hybrids have less technically advanced systems[and] want as much renewable energy as they can get to meet their growing demand, but need steadier delivery.” — Jean-Claude Robert, Hybrid Solutions Lead, GE
La Plana, a comparable Siemens Gamesa hybrid pilot built in Spain, combines an 850-kW wind turbine with 245 kW of solar, the company’s head of hybrid systems for the Americas Christine Grey told the Windpower session. Batteries were added to further test Siemens’ Hybrid Plant Controller.
Hybrids are attracting worldwide interest, with India leading, Robert said. A January 3 solicitation from the Indian state of Andhra Prahdesh would procure 5,000 MW of wind-solar hybrids through 2023. The solicitation specified the resources must “be configured to operate at the same point of grid connection.”
“Large, grid connected wind-solar PV systems” increase the “optimal and efficient utilization of transmission infrastructure and land,” the solicitation said. They also create “better grid stability” by reducing “the variability in renewable power generation.”
Countries “leading the charge on hybrids have less technically advanced systems [and] want as much renewable energy as they can get to meet their growing demand, but need steadier delivery,” Robert said. “GE is working with customers around the world to develop scale projects in real time, as we speak. In the U.S., the emergence is likely to be in solar-storage hybrids in California to address solar over-generation.”
U.S. developer Enel Green Power expects wind-storage growth in Texas to similarly address over-generation from wind, Enel Business Development Director Chris Hickey told Utility Dive.
The developer is also considering where it may be practical to add solar at existing wind sites, “especially in Texas and other high wind production areas in the Midwest,” Hickey said. It is “an emerging solar market” because “grid operators dealing with transmission congestion when wind production rises have ample transmission capacity at times of high solar production.”
Both Enel’s 497 MW High Lonesome wind project and its 450 MW Roadrunner solar project, now under construction in Texas, are candidates for storage additions, he said. “And every new Enel project is being evaluated for storage, whatever the renewable technology, because utilities looking for renewables plus storage is a growing trend.”
It is clear “this can be done technically and there is value in it,” GE’s Robert said. “A hybrid wave is coming. The only missing piece is regulations to drive development by rewarding project developers for delivering that value.”
Barriers such as interconnection, dispatch and compensation are “the big issue,” but there are “paths forward,” InterTran’s Peters said at the Windpower conference.
“Many places do not have an interconnection process for hybrids,” she said. And the grid operator needs a model for dispatch in real-time operations, “which often does not exist or, if it does, may not be optimized.”
Additionally, “most systems do not have a hybrid project capacity accreditation,” Peters said. “They have accreditation for solar and wind and many operators are developing a capacity accreditation for battery storage, but it is nonexistent for hybrid projects.“
Some system operators are more progressive than others, she said. The MidContinent Independent System Operator (MISO) “has good rules on hybrid interconnection” and on “additions to existing projects.” In contrast, PJM’s rule requires any fuel source change to “go back through a years-long queue process,” even if “it will not require a modification to the interconnection.”
“I can’t do any projects until the policy and regulatory issues are settled. But if we can overcome at least some of these challenges, there will be more hybrid projects built.” — Christine Grey, Head of Hybrid Systems for the Americas, Siemens
MISO’s generator replacement policy and surplus interconnection policy, both under review by the Federal Energy Regulatory Commission, also represent current best practices, Peters said.
The surplus policy allows a project not using its full interconnection capacity to add more nameplate generation without going through the queue process again, she said. Its generator replacement policy can allow “a new resource to replace an existing one” without a burdensome re-application delay.
Session speakers Jack Kiroff, the Enel Green Energy VP of Regulatory Affairs, and Siemens’ Grey endorsed Peters’ assessment.
Hybrid-specific revisions of federal tax credits for wind and solar are also needed, Kiroff said. And “the Clean Peak Standard, which provides compensation for generation delivered to the grid during peak demand periods, should be implemented more broadly to recognize the value of clean electricity delivered when it is needed most.”
“I can’t do any projects until the policy and regulatory issues are settled,” Grey said. “But if we can overcome at least some of these challenges, there will be more hybrid projects built.”
If obstacles to “a more unified national policy on hybrids” are resolved, wind-solar-storage hybrids “can be built in six months and the shift to low-cost, zero-carbon resources can happen much faster,” Peters added.