This article originally appeared on RTO Insider on February 12, 2017.
By Wayne Barber
WASHINGTON — Modest optimism about the Trump administration’s infrastructure plans was tempered with questions about leadership at FERC and other federal agencies at a gathering of transmission developers, RTO officials and environmentalists last week.
The first National Electric Transmission Infrastructure Summit, held Feb. 9-10 by Americans for a Clean Energy Grid, also heard concerns over how to pay for grid modernization in a time of anemic load growth. The organization, an initiative of the Energy Future Coalition, has held regional transmission conferences, but this was its first national event.
The coalition was formed in 2002 by former Sen. Tim Wirth, a Colorado Democrat; Republican C. Boyden Gray, who served as White House counsel to President George H.W. Bush; and Democrat John Podesta, a former aide to Presidents Bill Clinton and Barack Obama who chaired Hillary Clinton’s 2016 presidential campaign.
“I’d love to have more load growth. It ain’t going to happen,” Craig Glazer, PJM’s vice president for federal government policy, told the gathering.
Weak load growth will make it more complicated to finance upgrades for aging transmission, and the lack of a federal carbon tax or renewable mandate is making it difficult to integrate renewable generation, Glazer said.
Much of the current grid was built during the 1950s, 60s and 70s, with the deployment of coal and nuclear power plants, said ITC Holdings Executive Vice President and COO Jon Jipping. Now that many of those big baseload stations are being retired, much of the new generation — mostly natural gas or renewable energy — is in different locations that require new transmission, Jipping noted.
From the podium and on the sidelines, speakers said that while they like the Trump administration’s pro-growth rhetoric, they are also anxious to see FERC restored to full strength and who will be the key lieutenants to energy secretary nominee Rick Perry.
Speakers also cited concerns over cost allocation, regional planning and the shortcomings of FERC Order 1000.
Wade Smith, senior vice president of grid development for American Electric Power, said his company has made transmission a higher investment priority than generation in recent years as it focuses more on regulated utility operations.
Modernization is needed because much of the AEP grid is 70 years old, and yet it integrates 9,000 MW of wind, Smith said.
While much of the U.S. electric transmission system was built in the mid-20th century, the infrastructure components are inspected every year, said Rudy Wynter, National Grid’s president of FERC-regulated businesses. The grid was built in big chunks and it will largely be rebuilt in large chunks, Wynter said. This includes not only renewable integration but also preparing for more electric vehicles and offshore wind power, he added.
During one session, SPP CEO Nick Brown was interviewed by former FERC Chairman James Hoecker, now senior counsel for WIRES Group, which represents transmission developers and utilities. Hoecker stressed the importance of adding three commissioners to get FERC back to full strength. With only two commissioners since the Feb. 3 resignation of former Chairman Norman Bay, FERC lacks a quorum. (See FERC OKs Pipelines, Delegation Order Before Losing Quorum.)
Hoecker and Brown discussed FERC’s inability to gain “backstop” siting authority, saying it’s still very difficult to prevent individual states from blocking a project. The Energy Policy Act of 2015 amended the Federal Power Act to give FERC the authority to site electric transmission lines blocked by states, but court rulings have blocked the commission’s attempts to use it, prompting some in Congress to propose additional legislation strengthening FERC’s authority.
Brown said that Order 1000 hasn’t really helped SPP much with large regional projects.
“We need to decide what we want this grid of the future to look like,” Glazer said. For example, should it be a “localized grid” that can harness distributed generation? he asked. “There’s an added complication; it’s not even clear who is in charge,” Glazer said. FERC, state utility commissions and governors all have a say in siting decisions, he said.
If each governor is asked what infrastructure projects they want, the country will end up with a lot of state-based projects, not interstate ones, Clean Line Energy Partners President Mike Skelly said.
Perhaps the new mantra is “we’re going to make transmission great again,” Skelly said. The power to select infrastructure projects should not be taken away from transmission planners and placed in the hands of Congress, he said.
Skelly and others cautioned the Trump administration not to skimp on project reviews or stakeholder input. The key is that all projects must have “timelines” for regulatory approvals to avoid infinite delays, he said.
The executive director of the AFL-CIO’s Industrial Union Council, Brad Markell, said the labor movement agrees with the need for “hard timelines” to shorten the permit process.
Markell said that labor unions have been in contact with the Trump administration on potential infrastructure efforts.
“From our point of view, more power for the federal government and less power for the states [on electric infrastructure] would be a good thing,” he said.
Others deemed that unlikely. “I think we’re stuck with the system we have,” Glazer said.
Environmentalists Weigh In
Liese Dart, senior energy advisor for The Wilderness Society, said her organization favors prescreening certain public lands for development suitability.
Mary Anne Hitt, executive director of the Sierra Club’s Beyond Coal campaign, said that — contrary to what conference participants may have heard — her organization doesn’t oppose all power lines, only those that appear aimed to “prop up fossil fuels.”
The environmental group opposed the abandoned “coal by wire” Potomac-Appalachian Transmission Highline (PATH) project in PJM. On the other hand, it has backed the Plains and Eastern Clean Line Project, designed to move renewable energy from Oklahoma to Tennessee.
Hitt said she was concerned that President Trump’s nominee for EPA administrator, Scott Pruitt, opposed Clean Line in 2015 as Oklahoma attorney general.
Hitt also said the Sierra Club has concerns about the Gateway West project, a proposal by PacifiCorp and Idaho Power to build about 1,000 miles of high-voltage transmission through Wyoming and Idaho. She said PacifiCorp has been slower than some Western utilities in reducing its coal use and slower than the Sierra Club would like in expanding its renewable resources.
When it comes to protecting the grid, Brown said much of the discussion seems to be centered on preventing cyber intrusions. Perhaps the discussion should be less about how to keep cyber intruders out than to minimize the damage and restore order once they disrupt the system, the SPP official said, likening the approach to “insurance.”
But he said winning regulatory approval for equipment such as spare transformers may be difficult.
“I believe we are going to have to spend much more money on spare equipment, and that’s going to be tough to sell,” Brown said. “We are unwilling to spend that kind of money for spare equipment because it is not ‘used and useful.’”
SPP Chief Reticent on Mountain West
Brown declined to reveal much about the status of the Mountain West Transmission Group’s discussions about joining SPP.
Mountain West, a partnership of seven transmission-owning entities within the Western Interconnection, revealed the discussions in January. It said if the talks with SPP are not successful, it would likely explore joining another RTO. (See Mountain West to Explore Joining SPP.)
In response to a question about whether Mountain West was attracted by SPP’s cost-allocation system, Brown replied, “You’d have to ask them.”
“We’re excited about it,” Brown said of the talks, before cautioning, “Nothing is signed.”
A new assessment of the Eastern U.S. grid shows it will theoretically be able to handle 30% renewables within ten years, but only with serious upgrades to the bulk power system.
The Eastern Interconnection (EI), the world’s biggest power system, delivers electricity to 270 million customers. By 2026, system operators will be able to maintain power reliability with more than ten times the current amount of wind and solar on the system today, according to the recently-released Eastern Renewable Generation Integration Study (ERGIS).
That forecast takes into account only existing technologies, but that doesn’t mean the capability will be automatic. Increasing on today’s 40 GW of wind and solar in the EI region will only make sense if there’s adequate transmission to deliver the electricity to offtakers, the study found.
But developing that dramatic increase of today’s estimated 35 GW to 40 GW of wind and solar resources will only make sense if there is adequate transmission to deliver the output to EI region off-takers.
Whether that will happen remains up in the air, experts told Utility Dive.
“The resource is not the issue. It is the delivery system that is the issue,” said Wind on the Wires (WOW) Executive Director Beth Soholt, who has spent over 15 years working for new transmission throughout the Midwest.
Veteran transmission authority Roger Rosenqvist, now a vice president at ABB, agrees the lack of new wires is a real barrier.
“With the necessary renewables so remote from load centers, I doubt there is any way to integrate 30% renewables into the Eastern Interconnection without some expansion of existing transmission,” he said. “The problem is how to pay for it.”
The Eastern Interconnect at 30% renewables
The EI is a 50,000 line, alternating current (AC) system served by over 5,600 generators. Its footprint spans the U.S. and Canada, from Nova Scotia to Florida and from the Atlantic coast to the foot of the Rocky Mountains.
The study’s “one big insight” is that 30% renewables can reliably integrated into the EI in either of two scenarios, study author Aaron Bloom said.
“It can be done with an intra-regional transmission expansion and 20% wind and 10% photovoltaic solar,” he said. “Or it can be done with an inter-regional transmission expansion and 20% onshore wind, 5% offshore wind, and 5% PV solar.”
In either scenario, 60% of the solar PV capacity was utility-scale solar and 40% was distributed solar, he added.
This is the first time simulations this sophisticated have shown this level of renewables could be managed on the EI in the five minute intervals energy markets currently use, Bloom said. That is key, because reliable dispatch at that pace alleviates system operators’ concerns about wind and solar variability.
Five minute dispatch allows “instantaneous wind-solar penetrations of 50% or more,” Bloom said. “We are pretty confident most of the country can get to 30% annual penetration levels and intervals with renewables at 55% or 60% would not be show stoppers.”
As wind and solar penetrations rise, a number of changes would likely happen, the study reports.
Existing fossil and hydro generation would have to ramp up and down more rapidly and frequently to balance variability. Under study parameters, coal plants would be used about 20% more often and natural gas plants would be used over 40% more often.
Fossil plants would also run for shorter periods, which could compensate for increased operational wear and tear. Overall fossil generation would drop 30% and CO2 emissions would drop 33% in the highest renewables scenarios studied.
Power flow across the EI would be faster and more frequent, allowing system operators to take advantage of peaking wind or solar generation. Regional power trading would follow wind and solar load patterns.
Wind peaks at night and is growing in the western portion of the EI, and afternoon-peaking solar solar is expanding in the EI southeast, Bloom said. “The increased power flow would come from those regional and time zone peaking differences.”
A 60% renewables penetration was the highest for any five minute period in any modeled year. The highest annual average curtailment of wind and solar was 6.2%.
The needed flexibility that new renewables and new transmission would deliver will only come through regulatory changes and new market designs that are “outside the scope of the ERGIS study,” Bloom said.
ERGIS did not identify specific transmission projects, but described an optimal build-out of both inter-regional high voltage direct current (HVDC) lines, likely built on a merchant basis, and new intra-regional AC line additions to existing systems built by their operators, said American Wind Energy Association (AWEA) Research Director Michael Goggin, who was part of the EIPC process.
The modeled high renewables penetrations would be more easily achieved with new transmission for at least three basic reasons, according to the Eastern Interconnect study.
Integration and balancing of “hundreds of GW of wind and PV generation depends on generator and transmission operators offering their capabilities to the system operator;”
Market participants will require “significant, additional coordination across multiple areas in order to act on resource availability that is multiple regions away,” and;
Increased balancing with fossil generation “assumed a common thermal generating fleet across scenarios, regardless of renewable penetration,” the study reports.
Current transmission expansion
Siting transmission is a notoriously lengthy and contentious process, but Bloom said another problem the fact that “there’s plenty of generation, and that lowers the drive to build new lines,”
“The study does not say new transmission will absolutely be necessary for the 30% scenario,” he said, “but it will probably be necessary for the 50% and 70% and 90% scenarios needed to deal with climate change.”
Two pieces of big news have come recently from independent, or merchant, transmission developers now working on new HVDC lines to market to power producers and load serving entities (LSEs).
First, Pattern Development has decided to bring its 2,000 MW, 500 kV, HVDC Southern Cross project into the market.
“We have always wanted to move the project, but there was no need to stir up regulators until we were ready to file at their commissions and to stir up landowners until we were ready to start talking to them about rights of way,” said Business Development Manager James Dermody.
Southern Cross was first conceived in 2009, when the Competitive Renewable Energy Zone (CREZ) lines in Texas were being developed, Dermody said. “It is basically an eastward continuation of the CREZ lines to move Texas wind to off-takers in the Southeast that don’t have commercial quality winds.”
The line will run from East Texas, across Louisiana to the Mississippi-Alabama border. Pattern estimates it will provide total economic benefits of over $600 million as well as local annual tax benefits.
Pattern’s development arm is now actively identifying a route corridor and will, in the next 30 days to 60 days, file for permits with Louisiana and Mississippi regulators.
“We came out of the foxhole in the spring of this year because work on our routing is gaining momentum and we want local leaders and landowners to participate with us in that process,” Dermody said.
Next steps include permitting, land acquisition, and completing the interconnection. Construction is scheduled for the first part of 2018, with an online target of spring 2021. Given the challenges of federal environmental and other permitting still ahead, it is an ambitious schedule, he acknowledged.
The permitting processes are not expected to be complicated because the project was designed in coordination with state agencies to avoid known environmental constraints, Dermody said. “Everything right now is pointing to meeting our very aggressive timeline.”
The other big news is that the Plains & Eastern (P&E) Clean Line, a $2 billion, 705-mile, 4,000 MW HVDC transmission system being developed by Clean Line Energy Partners (CLEP), is moving toward construction. It aims to deliver Oklahoma wind to the Southeast U.S.
“We have been super active across Oklahoma, Arkansas, and Tennessee since the Department of Energy ruling,” said Spokesperson Sarah Bray. “We are planning to start building in late 2017 and we are in detailed discussions with generators and off-takers, including utilities and LSEs in all three states and farther east.”
CLEP only recently overcame jurisdictional complications that prevented Arkansas regulators from permitting the P&E line. Development was stopped until the DOE granted federal eminent domain authority under its Energy Policy Act of 2005 power, allowing CLEP to move ahead with obtaining ROWs.
Though Pattern hopes to avoid regulatory barriers with Southern Cross, CLEP still faces them with its P&E line, as well as the Grain Belt Express Clean Line and Rock Island Clean Line projects.
CLEP is negotiating rights of way (ROWs) with landowners along the P&E route in return for “fair compensation,” Bray said.
Grain Belt has been permitted in Kansas, Illinois, and Indiana but CLEP must still overcome Missouri regulators’ objection to its 2014 filing. In response to the Missouri Public Service Commission assertion that Grain Belt does not deliver local benefit to the state, CLEP contracted with the Missouri Joint Municipal Electric Utility Commission (MJMEUC) and re-filed for approval.
The line is expected to save customers of the 35 MJMEUC municipal utilities $10 million annually, according to the public power agency’s analysis. A Missouri Department of Economic Development economic impact analysis showed Grain Belt will also support an estimated 1,500 Missouri jobs during each of its three construction years.
“We are hoping for a decision on the new filing in early-to-mid-2017 so construction can start in 2018 and the project can be online in 2021,” Bray said.
The Rock Island Clean Line, however, still faces regulatory complications preventing approval by the Iowa Utilities Board (IUB) and recently suffered a setback when an appellate court reversed its unanimous 2014 approval from the Illinois Commerce Commission (ICC).
It is a $2 billion, 500 mile HVDC project that would deliver 3,500 MW of Iowa wind to the MISO and PJM Interconnection markets.
The appellate court ruled Rock Island does not serve the public use in Illinois. But the Illinois court’s decision ignores the fact that “100% of the project’s low-cost electricity would be delivered into a ComEd substation in Illinois, and would be available to serve Illinois customers, and would reduce energy prices in Illinois by $320 million in the first year of operation,” CLEP argues.
CLEP, ICC attorneys, and other Illinois groups have appealed to the Illinois Supreme Court and will also argue that if the decision stands it will create barriers to competition and lead to higher electricity prices, Bray said.
In Iowa, Rock Island needs authority to exercise eminent domain in obtaining ROWs. But Iowa law requires project developers to complete the potentially costly and time-consuming process of obtaining ROWs before applying for a permit granting that authority.
“The IUB has not denied the permit,” Bray said. “We have asked the IUB to permit Rock Island on the basis of the portion of ROWs we have already obtained or will obtain but we have been unable to get them to move.”
The federal authority CLEP was able to use in Arkansas does not apply in Iowa, she added.
CLEP began planning merchant transmission development in 2009 and knew from the start it would face obstacles “because there aren’t many people trying to do this,” Bray said. “It is hard, but big projects take a long time, and when you pass a milestone like the DOE granting use of its federal authority, it is exciting.”
“The country is moving toward a cleaner energy future regardless of where the politics are,” Bray said. “Polls show people want clean energy and it can now be delivered at a price that is competitive with any other resource. To make that happen we need to build this infrastructure.”
Overlays connect the dots
Beyond merchant transmission projects, another way to expand system flexibility is emerging.
The Clean Lines and Southern Cross are “pipelines to deliver renewables,” ABB’s Rosenqvist said. “Transmission overlays would add uncommitted transmission capacity to give grid operators the flexibility to shift the renewables-generated power those pipelines deliver.”
The merchant lines will deliver some of the EI’s renewables potential but “all the lines currently in planning do not even get close to the 30% target,” he added.
A transmission overlay would provide new capacity within the EI and new merchant lines would deliver renewables from outside the EI, Rosenqvist said. “It would be like the interstate highway system with multiple paths and excess capacity so generation across the U.S. could be re-dispatched to load centers without creating bottlenecks.”
The obstacle to building an overlay is finding a way to allocate the cost, Rosenqvist believes. Reliability areas allocate new project costs across their rate bases but an overlay connecting two systems would require a new rate structure allocating costs to both systems.
System operators have only recently begun to work out cost allocation for new transmission within their footprints and a push at FERC for inter-regional cost allocation “has not gotten very far,” he said.
FERC Order 1000 was a step forward in inter-regional transmission planning and cost allocation but it has fallen short, AWEA’s Goggin agreed. “There is no effective mechanism for paying for lines between systems yet there is a huge amount of congestion and savings for consumers are being lost because of insufficient transmission between regions that would pay for itself.”
Yet “the speed and scale of adequate resource deployment depends critically on the speed of transmission deployment – especially across regions,” AWEA argued in a recent FERC filing.
Wind on the Wire’s Soholt has been working with MISO on early stage overlay planning that would identify and combine “reliability needs and economic opportunities,” according to a recent presentation from the grid operator.
“The transition the generation fleet is going through is one of the big drivers because an overlay would allow MISO flexibility while keeping the grid reliable,” Soholt said.
Allocating costs for new transmission will be challenging, she agreed. “But if MISO can show value over the long term in lowering wholesale prices or meeting public policy needs or allowing the flexibility to bring new resources online, it could build consensus for moving forward.”
Historically, transmission to deliver new generation was built to meet load growth but load growth today is flat, Soholt said. Now transmission will be added to reliably serve load while taking advantage of renewables to meet public policy needs while keeping costs low.
“Wind in the Midwest and solar in the Southwest are cost-effective now but all regions should be looking at adding renewables because wind and solar are soon going to be cost-effective in one way or another everywhere,” she said.
Like AWEA, WOW has argued to FERC that Order 1000 efforts to drive inter-regional transmission growth need to improve, Soholt said.
“We hope SPP and MISO will be able to incorporate an overlay into the 2017 that could produce candidate lines,” she said.
Rooftop solar is without question the poster child of the clean energy revolution, with good reason: it’s visible, increasingly affordable, and growing explosively. Dubbed “power to the people” by leading environmental author and activist Bill McKibben, rooftop solar now symbolizes green commitment for the left and bootstrap self-reliance for the right. It would be hard to blame anyone for concluding that the shiny panels dotting communities everywhere were the principal drivers of America’s transition to clean energy.
Except that they’re not.
The truth is that the vast majority of America’s wind and solar electricity – more than 85 percent – comes from large scale facilities. Virtually all wind power comes from utility-scale installations in places so remote that they’re rarely seen by anyone who is not operating them. More than half of all solar panels in the U.S. are in vast arrays capable of powering tens of thousands of homes. Solar on residential rooftops is growing rapidly, but accounts for just 20 percent of total U.S. solar electric capacity, a proportion that will fall further as large scale installations grow.
Bigger is Cheaper
Economies of scale – the principle that the cost of making a unit of something falls as you produce more of them – applies to renewable energy just as it has to countless other products, from Henry Ford’s Model T’s to flat screen TVs. Large wind turbines produce energy for pennies on the dollar compared to small turbines suitable for commercial or residential settings. Taller towers reach stronger and more consistent winds at higher elevations, and longer blades capture more of the wind’s energy in each sweep. Despite using identical photovoltaic (PV) technology, large scale solar arrays generate electricity at less than half the cost of panels on a typical home (installed costs per watt dc: $1.38 for utility scale vs. $3.55 for residential). Superior resource quality is a big driver of lower costs: utility-scale developers target very windy and sunny places far from where most people live. Large solar arrays save even more money by cutting unit installation costs and by ensuring that each panel sits at the optimal angle to the sun (not an option for most residential rooftops).
Bigger Networks Connect More Renewables – and Improve Their Performance
Moving power hundreds of miles from remote wind and solar facilities to customers is much more efficient than widely believed. In 2013, just 5% of the power generated on the U.S. grid was lost on wires, and most of that “line loss” occurred at the distribution level. Transmission is the smallest part of the average electric bill, only 9% compared with more than 65% for generation. Generation cost savings from large scale wind and solar facilities are so large that they recoup the cost of transmission lines needed to connect them rapidly. Regional transmission investments in Texas, California, the Southwest Power Pool, and the Midcontinent Independent System Operator are delivering enormous amounts of large scale wind at net savings to customers. Benefits to electricity customers typically exceed costs by factors of 3 to 1 or more, and include reduced energy costs, congestion relief, improved reliability, reduced capacity costs, improved market liquidity and competition, and emissions reductions.
Robust regional transmission grids squeeze more kilowatts out of every wind and solar facility by finding demand whenever the wind is blowing or the sun is shining. When the grid is constrained, excess wind and solar generation are “curtailed,” i.e. wasted or dumped to avoid dangerously overloading the grid. Transmission expansions eliminate these losses, making wind and solar generators even more efficient and valuable. Texas wind curtailments plummeted from 17% in 2009 to 0.5% in 2014 – even as total wind generation nearly doubled – thanks primarily to well-planned transmission expansions and upgrades completed in 2013.
Big Solutions for a Huge Challenge
Small may be beautiful, but the global climate challenge is anything but small. The landmark agreement negotiated in Paris last year provided another stark reminder of its staggering magnitude. Avoiding catastrophic climate change impacts means reducing global carbon emissions 80 percent by 2050, with even steeper cuts in the electric sector. Big, cheap, and abundant wind and solar, enabled by expanded and upgraded regional transmission networks, are quietly leading the transition away from aging fossil power plants and toward an affordable, reliable, and universally accessible clean energy future. America has more than enough wind and solar to power everything – including transportation – dozens of times over. The key to capturing this potential is doubling down on the big solutions that are working better, cheaper, and faster than anything else.
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.
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.