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.

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.

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.

It contains six of the eight U.S. regional reliability entities, as well as the former Southeast Reliability Corporation (SERC), which includes Duke, Southern Company, and TVA.

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%.

Transmission needed

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.

Assumptions about transmission were based on three scenarios “developed independently by the Eastern Interconnection Planning Collaborative (EPIC),” the ERGIS study reports.

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.

Inter-regional AC and HVDC transmission is now in development across the country “but not on the scale the study envisions,” he said.

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

“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.”

“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 may finally be close to advancing as well. It is a 780 mile, $2 billion, HVDC project that would deliver 4,000 MW of Kansas wind to the MISO market.

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 increasing demand for renewables has also led to new merchant HVDC projects in New England and the West. The 192 mile, 1,090 MW Northern Pass HVDC line will deliver Canadian hydropower to New Hampshire and load centers further south. The 333 mile, 1,000 MW Champlain Hudson Power Express HVDC line will deliver Canadian hydro and Maine wind to New York.

West Coast load centers are waiting for TransWest Express, Zephyr Power, SunZia, Western Spirit, and other merchant projects to deliver remote High Plains wind and desert Southwest solar.

“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.