Archive for category: Energy Connections Articles

By Jonah Martin, Manager, MNC Project Management Office

Even by the standards of other major utility construction projects across the nation, the numbers behind Tri-State Generation and Transmission’s recently completed, 230-kilovolt Montrose-Nucla-Cahone (MNC) transmission project are staggering. Throw in a worldwide pandemic during the construction phase and we have a real story to tell.

The basic facts are impressive for a project built in remote areas of the Rocky Mountain West. The project began in May 2013 and required the approval of nearly a dozen local, state and federal agencies, including the U.S. Bureau of Land Management, the U.S. Forest Service, the U.S. Fish and Wildlife Service, the Colorado Public Utilities Commission and Colorado Parks & Wildlife.

MNC traversed more than 80 miles of often challenging terrain, and the associated severe weather, through portions of Dolores, Montrose, Ouray and San Miguel counties in Colorado, at times reaching elevations of more than 11,000 feet above sea level.

Substation expansions
The MNC included a substation expansion in Montrose, completed in May 2017; the new Maverick substation, which Tri-State energized in April 2020; and improvements at the Cahone substation.

The Maverick substation was to initially operate at 115 kV, while accommodating a future need for 69 kV of service. The decision last year to decommission Tri-State’s Nucla Station power plant and the associated Nucla substation earlier than planned required the Maverick substation build to take place earlier as part of the initial construction phase.

Transmission lines and fiber optics
The transmission line project also included more than 300 miles of access improvements and significant vegetation management along nearly 60 miles of federal land. In total, MNC required 435 wood structures and 131 steel structures; 1.37 million feet of conductor; and nearly 475,000 feet of optical ground wire. The optical ground wire is part of the regional fiber optic communications backbone between Grand Junction and Albuquerque. Even these figures do not begin to tell the whole story.

The crowning achievement of this challenging project included the crossing of the historic Dolores Canyon just east of Dove Creek. The Dolores Canyon, characterized by red Wingate Sandstone, old-growth ponderosa trees and the winding Dolores River, begins in the southern San Juan Mountains and meanders toward the Utah border. The Juan Rivera expedition viewed the Dolores Canyon in 1765 while exploring trade routes in Ute country.

Dolores Canyon a significant crossing
For Tri-State, the crossing of Dolores Canyon presented several unparalleled challenges in the U.S. transmission industry, with the exception of the smaller, original (and still existing) 115 kV wood-frame crossing of the canyon completed in 1958. Even if the Gateway Arch in St. Louis were placed in the 1,100-foot canyon, it would not be visible, except to someone standing on the rim of the canyon.

The Tri-State crossing effort required a span of nearly 6,600 feet between two 85-foot-tall lattice towers on the north and south rim of the canyon. When counting distances from the “dead ends,” which hold the weight of each of the five 20,000 pounds of conductor and optical ground wire tensions, the distance was 8,000 feet. The line dropped some 400 feet between the lattice towers into the canyon.

Tri-State made five crossings of the canyon: three with conductor and two with optical ground wire. A helicopter first pulled a 5/16-inch rope from the south to the north end of the canyon, and then winch equipment pulled back a 3/4-inch rope back to the south. At that point, the rope then pulled the conductor and optical ground wire back from the south to the north rim. This work started during the week of September 28 and was completed by October 10.

To put some of this in perspective, the transmission line over the Dolores Canyon spans about 1.25 miles between lattice towers and more than 1.5 miles between the dead ends. Only three other spans worldwide are known to be longer, although on much larger towers: an 8,714-foot span between the Jintang and Cezi islands in China; the crossing of the Norwegian Sognefjord at 15,082 feet; and the Ameralik Span in Greenland at 17,638 feet.

In fact, the Dolores Canyon segment wasn’t the only significant crossing.

Workers previously crossed Glade Canyon, 2.5 miles north of Dolores Canyon, which was a 2,800-foot crossing, or just over half a mile, and would have been a significant effort for any other transmission line project but now the second largest on MNC.

The Montrose-Nucla-Cahone transmission line project benefits
The MNC transmission line was energized in October and was complete — aside from reclamation work — by the end of 2020. The project cost nearly $105 million and required 65,000 labor hours for construction.

Completion of this project brings a number of immediate benefits to Tri-State and the bulk electric system. Greater reliability and lower maintenance needs, greater operational capacity and flexibility, and the ability to accommodate load growth in the area are just a few of the immediate impacts. MNC also paves the way for future benefits, including the ability to support Tri-State’s Responsible Energy Plan and the growing interest in generation interconnection projects throughout western Colorado.

Numerous departments and dozens of employees throughout Tri-State left their marks on this once-in-a-career project. Without the hard work and dedication of the MNC project team, none of the amazing numbers, accomplishments and benefits could have been achieved.

Jonah Martin is the manager of the Montrose-Nucla-Cahone project management office and an employee of Tri-State Generation and Transmission. Tri-State is a wholesale power supply cooperative, operating on a not-for-profit basis, with 45 members, including 42 utility electric distribution cooperatives and public power district members in four states that together deliver reliable, affordable and responsible power to more than a million electricity consumers across nearly 200,000 square miles of the West. For more information about Tri-State, visit tristate.coop.

By Reed Karaim

Holy Cross Energy has an ambitious goal: 100% renewable energy sources by 2030. It’s a tall order, complicated by the central Colorado co-op’s mountainous service territory, which isn’t well-suited to wind or solar power generation.

But just 100 miles or so to the east of the co-op’s Glenwood Springs headquarters, the Front Range and eastern plains offer ample wind resources. And the states to its south are among the nation’s solar power leaders.

It’s the lack of transmission that keeps the region’s renewable power from reaching the Western Slope, says Bryan Hannegan, Holy Cross Energy president and CEO.

“Our transmission access is our biggest worry” for meeting the 100% goal, he says.

Hannegan, who served as associate director at the U.S. Department of Energy’s National Renewable Energy Laboratory before joining Holy Cross, sees a solution in the creation of a “super grid.”

The concept, also known as the macro grid, entails uniting the nation’s regional transmission systems with high-voltage, direct current (DC) interties. In particular, it would bridge the seam that runs along the eastern borders of Montana, Wyoming, Colorado and New Mexico between the western and eastern grids and would also tie ERCOT, the wind-rich Texas grid, into a national system.

While at NREL, Hannegan oversaw a study that found a super grid could help reduce costs for consumers by allowing a “balancing of power supply over much larger regions,” he says, “allowing us to harness the resource diversity we have in this country.”

In particular, it would enable greater use of wind and solar power, says Tracy Warren, director of the Macro Grid Initiative at the American Council on Renewable Energy.

“Much of our vast renewable resources are located in remote regions far away from where the power is needed in population-dense areas,” she says.

Being able to move solar and wind power to those areas could increase the utility of renewable generation. One scenario outlined in a study showed a hypothetical heat wave in August causing air conditioners to drive up demand. As the sun moved across the United States, solar plants in the West sent power eastward, limiting the need for expensive peak-load, fossil fuel generation. As the sun moved west and began to set, midwestern wind farms — today in the eastern grid — sent power westward to relieve pressure on the coast’s coal- and gas-fired generation.

Worth the cost?
The price tag for building the DC transmission necessary to create a coast-to-coast super grid would be eye-popping: The NREL study estimated it could cost at least $80 billion, but it could return economic benefits of twice that amount.

“By every measure, a more interconnected grid delivered better outcomes — lower carbon emissions, lower cost to consumers, better reliability,” says Hannegan, along with job creation and other economic benefits in the parts of the country where more renewable energy generation would be built.

But a super grid would also face significant challenges.

“Any transmission beyond a local, minimal addition to an existing line is going to be met with huge amounts of opposition,” says National Rural Electric Cooperative Association Chief Engineer Paul McCurley. “Not just technical, geographic, economic and environmental challenges but many not-in-my-backyard battles.”

Patti Metro, senior grid operations and reliability director at NRECA, says DC interties and converter stations for the three alternating current (AC) grids, which are not synchronous, would be complicated and expensive but would not require new technology.

Much of the recent focus in the industry has been on reducing, not expanding, the distance power travels, turning to more localized, distributed generation that integrates renewables sources like solar and tends to reduce the need for new transmission facilities, Metro says.

Another issue is the allocation of costs. Basin Electric Power Cooperative, a co-op power supplier based in North Dakota, operates coal, gas and wind generation to serve 140 member systems, including Colorado’s Tri-State Generation and Transmission Association, which serves 17 of the state’s 22 electric co-ops. As the demand for power grows, “new transmission development is probably going to be essential, and if there’s a transition to more renewable energy, that’s only going to add to the demand,” says Tom Christensen, Basin’s senior vice president for transmission.

But, he adds, the construction cost of a super grid raises concerns, even if it eventually saves money.

“Regardless of who funds it — banks, utilities, whoever — the point would be that, ultimately, some set of retail customers will have to pay. It will show up in customer bills,” he says.

Rural, sparsely populated areas like the Great Plains, where wind generation is expanding, should not be asked to bear costs that exceed the benefits to their region if the transmission is largely carrying the power elsewhere, Christensen says.

He notes the super grid would require unprecedented coordination on a national scale to make sure the connections were cost effective, a task that’s generally handled by regional transmission organizations (RTOs).

“In general, when it’s transmission planned by an RTO, you really get a cost-effective solution, and you hopefully get an equitable distribution of cost to consumers,” he says, but a macro grid would cross RTOs, complicating planning.

He could see starting a buildout of regional grid interties on a smaller scale: “a more measured approach, going through the RTOs, trying to be very careful determining what’s economically justified.”

Warren acknowledges the macro grid will require large-scale planning but reiterates that transmission investments will pay dividends. She points to a study that shows increased transmission development at the “seams” between regions could save consumers up to $47 billion annually and return more than $2.50 for every dollar invested.

She sees the macro grid working in concert with more localized generation to help the country reach the ambitious clean energy goals states are setting and the Biden administration has promised at the national level.

To meet goals like those, “it’s all hands on deck,” Warren says. “It’s a large-scale challenge that demands a large-scale solution.”

This article was reprinted with permission from the April issue of the National Rural Electric Cooperative Association’s RE Magazine.

By Sarah Smith

Wildfires ravaged Colorado this summer, wreaking havoc across the state and scorching more than 665,000 acres of land. The 2020 wildfire season marked the worst in the Centennial State’s recent history, and the Colorado Rural Electric Association, representing Colorado’s electric cooperatives, and its member cooperatives are determined to serve as advocates for better wildfire mitigation. The prevention of these devastating fires is not only imperative to restore and maintain the natural beauty of Colorado, but also the functioning of critical infrastructure and, of course, public safety.

Colorado’s electric co-ops work tirelessly to mitigate situations in which their power lines might cause a wildfire. Some approaches include trimming trees on an annual basis to ensure they aren’t coming into contact with electric lines, maintaining the rights-of-way and keeping infrastructure up to code and equipment operating properly.

Holy Cross Energy in Glenwood Springs has taken vegetation management a step further by finding new and innovative ways to utilize technology to pinpoint potential fire risks. Holy Cross recently teamed up with Intel Geospatial, a cloud “geovisual” data management platform, for a proof-of-concept project. The project consisted of performing an overhead system inspection with an unmanned aerial vehicle, and then providing the photos to Intel Geospatial.

“Intel has developed a software platform designed to allow integration of the inspection photos into a set of base maps, which then allows the end user to review the photos more efficiently for system deficiencies and create reports for field crews to repair the issue,” said Cody O’Neil, vice president of the Glenwood Springs district operations group at Holy Cross.

“We look forward to incorporating this software into our system maintenance program, with the end goal of improving our system reliability, which in turn minimizes the chance that the electric system ignites a fire,” O’Neil added.

Sangre de Cristo Electric Association, Inc., in Buena Vista is another cooperative that is thinking outside of the box. The association recently added a $6 per month wildfire mitigation rate rider on SDCEA monthly bills, which began in January 2021. The co-op experienced the depredation of wildfires firsthand with the Decker and Hayden Creek fires. The aftermath of these fires created a major impact on those living near the lasting burn scars, and Sangre de Cristo’s region remains at high risk for an even larger, more severe wildfire in the future.

Despite spending hundreds of thousands of dollars on vegetation management over the past several years, it would take an additional 20 years under the co-op’s current allocated budget to raise enough money to efficiently clear regional electric lines, and the association knew it had to accelerate the process. According to SDCEA, the board approved the $6 per month rate rider for 2021, with an incremental increase of $1 per year until it reaches $10. The rider will be reviewed periodically to guarantee its effectiveness and will be removed from SDCEA bills when it is deemed no longer necessary.

“Over the years, Sangre de Cristo has budgeted and spent millions of dollars cutting back trees in our ROW [rights-of-way] and our easements. We have tried to preserve as many trees as we could. But the recent spate of wildfires in California and Colorado, along with the loss of life and homes, has caused us to re-evaluate our risk and the urgency that it requires. Our highest calling is the protection of life and property,” said Paul Erickson, SDCEA chief executive officer.

The safety and livelihoods of co-op consumer-members are always top-of-mind, which is why CREA, along with its member cooperatives, is pursuing a three-pronged approach to reduce the threat of wildfires throughout the state. The approach will heavily focus on the power line rights-of-way through the state’s vast landscape. The three prongs are:

1. Reviewing the vegetation management strategies in rights-of-way with private landowners and public land managers. Sometimes, co-ops and other utilities experience difficulties accessing the rights-of-way or easements if they can’t gain permission from adjacent landowners to cross their land.

2. Working with policymakers on changes that will allow for better vegetation management in rights-of-way.

3. Joining the National Rural Electric Cooperative Association in addressing concerns regarding access to rights-of-way on federal lands.

A right-of-way is an easement agreement between the landowner and the co-op allowing the co-op to access the power line (or whatever infrastructure is in the right-of-way). It also allows the co-op to maintain the power line and to clear any trees or other vegetation that might cause a threat to the power line. Generally, the co-op pays the landowner a yearly fee for this access, which is negotiated between landowners and co-ops.

In Colorado, these rights-of-way can vary in width depending on the type of power line running through the rights-of-way or according to the agreements with landowners. Land owned by the state or federal government can present its own set of challenges. Each governmental agency has its own criteria and policies regarding rights-of-way. Sometimes, it can take months or even years to get necessary permits to work within existing rights-of-way or easements. This lack of consistency and often drawn-out processes can make maintaining the vegetation to minimize wildfire risks difficult.

Positive news is on the horizon for electric cooperatives across the nation. “The [federal] agencies have recently taken several positive steps to streamline approvals that allow electric co-ops more timely access to power line rights-of-way located on federal land,” said Janelle Lemen, NRECA regulatory issues director. “NRECA is engaging with the agencies to ensure consistent and coordinated implementation of these regulations.”

That work is having an effect. The U.S. Forest Service issued a final rule on November 19, 2020, under the National Environmental Policy Act, which ensures that co-ops will no longer face a waiting period when there is an emergency vegetation management situation or maintenance that cannot be put on hold.

Wildfires are not completely avoidable, especially during the dry summer months in Colorado. CREA and its member cooperatives are committed to providing safe, reliable electricity at an affordable rate. Vegetation management for wildfires is a fundamental aspect of the service electric cooperatives work to provide to their consumer-members, and co-ops will continue to act proactively on wildfire mitigation. By working together, wildfire threats in Colorado can be reduced.

Sarah Smith, a freelance writer in Colorado, has a long history with electric co-ops.