Decarbonizing Colorado

Updated from Allen Best’s initial article on June 23, 2020

Closing most of the coal plants in Colorado during the next decade will be the easy part.  Transportation—already the No. 1 source of greenhouse emissions in the state—will be a much tougher challenge.  But even that won’t be enough to allow

Colorado to hit its targeted reductions in greenhouse gas emissions. There will have to be reductions in emissions caused by buildings, but also farm operations and other sectors of the economy.

The Colorado Climate Action Plan, a law also known as HB 19-1261, specified a target of 26% reduction by 2025, as compared to 2005 levels. Colorado is already at roughly 18% based on improved energy efficiency and planned coal plant retirements.  Far heavier lifting will be required to achieve the 50% reduction by 2030 identified by the law and then the 2050 goal.  Can Colorado hope to hit that 2030 target using the tools available? For their last two meetings, members of the Air Quality Control Commission have been asking that question in different ways.  The commission has been moving forward deliberately, methodically, on vehicle emissions standards and tightening of regulations governing oil and gas extraction and distribution. In May, the commission adopted regulations reducing use of hydrofluorocarbons, a powerful greenhouse gas, in refrigerants.  More being queued up, such as regulations to further reduce methane emissions from oil and gas operations, the fourth largest source of emissions in Colorado.

Coal plant closings continue to be announced, in line with explicit legislative orders to utilities to reduce emissions 80% or more by 2030 and shifts in technology and costs that make those closings easy to justify.  Prior to HB 1261 and SB 096, the commission already had authority, under its requirement to create rules to address regional haze, to make sure the emissions drop rapidly.

But will all this be enough? Should the state be moving even faster? At the commission’s May meeting, and then with more elaboration in June, a significant minority of commission members expressed reservations about the pace of the state’s actions.  Auden Schendler, a commission member, juggled baseball and

football idioms to make his point at the June meeting about “astoundingly hard” rulemaking.  “We keep knocking things out of the park,” he said, “But they only move the ball a little bit down the field.”  Schendler, along with two commission members from Boulder County continued to wonder whether

broader, more muscular topdown regulations will be necessary in Colorado for the state to briskly decarbonize its economy as identified by the law.

CDPHE execs continue to argue that more sweeping changes might require additional legislation or even voter approval of tax reform.

The Commissioners were reinforced by legislators they heard from in May, who emphasized that the AQCC has all the authority it needs, beyond what they had prior to 1261 and 096, to take comprehensive action.  Commissioners also saw the need:

“We need to stop digging a deeper hole,” said Elise Jones, an air commission member who is also a Boulder County commissioner. She pointed to actions taken by DRCOG, or the Denver Regional Council of the public through a process carbon fee and dividend.

“A backstop may or may not be the right thing,” said, Tony Gerber, a commission member who is physician and professor from National Jewish Health.

John Putnam, director of environmental programs for the CDPH&E, said an attempt will be made to address this in the roadmap. But several times in the course of two afternoons speaking with commission members last week he identified a funding gap. California, has $50 million just to administer its

cap-and-trade program, he said.  And his agency, he said, has funding for only 5 or 6 people in its climate change department.

At least one environmental group says the state needs to move more briskly.  “We can’t just check back every two years. We really have to put a lot of thought into what the total regulations will be,” said Stacy Tellinghuisen, senior climate policy analyst for Western Resource Advocates. While the state’s process has involved some stakeholder groups, she said she believes the state – even if short-funded given the enormity of the task – should make more effort to tap the expertise of stakeholder groups. She pointed to the formulation of stakeholder groups by Maine as part of its effort to achieve comparable reductions in emissions to those in Colorado.

The draft roadmap sketched by the two agencies starts with the electric source— mostly, but not completely, on its way toward decarbonization—and also sees steady work in reducing methane emissions from the production of oil and gas. The steps here range from proposed rules governing continuous monitoring for methane to, down the line, electrification of oil and gas operations, something that already has started but which could be expanded. Two tough sectors will be transportation and buildings. Unlike electrical generation, which involves a handful of utilities, most of them already regulated by state

government, transportation involves several million people. It’s already the largest source of emissions in Colorado.

The state has plans to induce electrification of transportation, with a goal of having 42% of vehicles on the road by 2030 electrified. Xcel Energy recently submitted its proposal to spend $102 million to help add charging infrastructure, to encourage more comfort among EV buyers.

And there’s a possibility that Colorado might tag along with California’s upcoming efforts to adopt emissions standards for medium and heavy-duty vehicles.  How much will Coloradans reduce their annual vehicle miles traveled as a result of the stay-at-home procedures now commonplace during the time of covid? The two state agencies and their consultant, Energy + Environmental Economics, tend to think we’ll be driving less. Nobody really knows, of course. “There is a lot of uncertainty,” agreed Amber Mahone, from the consulting company, when pressed by Milford, who called the willingness to take easy reductions from the Covid downturn “speculative” when projected out to the longer term.

Ditto for oil and gas operations. The modeling here suggests a flattening of extraction in Colorado in the next decade, unlike the rambunctious growth of the past two decades, first in the Piceance Basin and then in the Wattenberg Field. But nobody really knows.

Legislators have already tightened building codes, requiring local jurisdictions to adopt one of the last three iterations, each of which successively tamps down energy use in homes and other buildings. Before, there was no requirement.

Will Toor, director of the Colorado Energy Office, discussed expansion of benchmarking from commercial buildings, such as has been adopted by Denver, Boulder, and Fort Collins (and which is being studied by Aspen, perhaps among others). A bill introduced into the Legislature this year—but dropped,

because of Covid constraints, would have required rulemaking around benchmarking.  (For a primer on benchmarking, see Urbanland story.)

Performance standards are designed to incentivize modest improvements over time to allow lower-performing buildings to move up to higher performance.  And a renewable natural gas standard was also dropped, for similar reasons, but could have a role in reducing emissions from buildings.

As for taking action to reduce emission of methane from coal mines, Schendler advised that this should be done—because it’s relatively easy and it has a big impact. As an employee of the Aspen Skiing Co., he was largely responsible for Colorado’s sole success to date in that regard.

FERC accepts Tri-State’s contract termination filing, but what does that mean exactly?

The Federal Energy Regulatory Commission on June 12 accepted Tri-State’s contract termination payment filing and referred it to FERC’s hearing and settlement judge procedures.

What to make of this?

In a statement issued by Tri-State hours later, chief executive Duane Highley called it a “decidedly positive outcome.” He said that the decisions give each of Tri-State’s members a voice and they will be treated equally on wholesale contract and rate matters.

“Importantly, FERC rejected arguments that it did not have jurisdiction on contract termination payments.” Jessica Matlock, general manager of LaPlata Electric, one of two member co-ops weighing whether to seek an exit from Tri-State, said FERC had three choices: 1) reject the contract termination payment tariff; 2) accept and approve it; or 3) accept but suspend the tariff.

“FERC went with the third path, and because the CTP tariff is not approved, our Colorado case moves forward.”

An administrative law judge for the Colorado Public Utilities Commission in May spent about a week hearing from both La Plata and United Power about what constitutes fair and equitable terms of exit. Tri-State also had its days in court. The judge has not issued a decision, but Matlock said she’s hopeful that one will be rendered by late June or early July.

Meanwhile, the legal skirmishing between United Power and Tri-State continues in Adams County District Court. There has been a press release, but nothing really new.

Hope continues for carbon capture in Wyoming, New Mexico —and even Colorado

In New Mexico, the Escalante coal plant will close later this year. In Colorado, the first of the Comanche plants will close in 2023, and one of the Craig units in 2025. But still, hope remains that carbon capture and storage technology will arrive in time.

Jason Begger, executive of the Wyoming Infrastructure Authority (soon to be the Wyoming Energy Authority), drew attention to his state’s ongoing effort to “turn a liability into an asset.” Speaking on a webinar sponsored by the Center for Climate and Energy Solutions, Begger drew attention to the Wyoming Integrated Test Center, which he described as the largest coal combustion research center in the United States.

Located near Gillette, the center is the host site for $20 million in prize money through the NRG COSIA Carbon XPRIZE competition. There are divisions for both coal and natural gas. Within the coal category there were 12 teams creating technologies for use at a coal plant.

The winners—which Begger said he hopes will be announced by early next year—demonstrate technology that can best remove carbon dioxide emissions from coal combustion.

The hope is that the technology can be scaled up and spread across the world.

“This isn’t just about power plants. Oil plants are huge emitters of CO2, too,” he said. “You are going to have to move these emissions from the sources to places where they can be used.”

Wyoming also sees coal as the key to firming up renewables, because of the baseload generation.

He also said that for the United States to not burn coal will not provide the global answer for warming. “It doesn’t matter what an individual state is doing,” he said. He pointed to Asian countries—India, South Korea, and China among them—who have or will surpass the U.S. in carbon emissions.

Wyoming contributed $15 million to the prize money, and Tri-State Generation & Transmission $5 million. Basin Electric, a partner with Tri-State on a coal plant at Wheatland, Wyo., provided the facility.  Hope also continues in New Mexico, where the Public Service Co. plans to stop

operating the 847-megawatt San Juan Generating Station by mid-2022. A company called Enchant Energy Corp. will get the plant near Farmington for $1—yes, one George Washington—and plans to spend $1.3 billion for a carbon-capture system that would reduce emissions by as much as 90%.

Peter Mandelstam, the chief operating officer for Enchant, told Bloomberg earlier this month that a federal tax credit similar to what allowed wind energy to prosper, was crucial to the New Mexico project. “The Enchant project only works if the tax credit is in place.”

Bloomberg explained that Congress more than doubled the tax credit in 2018, providing $50 for every metric ton of CO2 that’s sequestered, or $35 a ton for producing oil worth the captured carbon. Financing, however, was held up by unanswered tax questions. The IRS issued proposed regulations in May.

CCS—the “S” sometimes stands for storage, and in other cases sequestration— has had a checkered history. The federal government has bestowed many billions of dollars in aid for projects, most notably of late at the Southern Co.’s Kemper plant in Mississippi. But Southern pulled the plug in 2017 because of cost overruns. Similar problem caused a project in Illinois to be shelved about a decade ago.

One problem has been that it takes so much power—about a third of electrical generation at a plant—to sequester the carbon. Even so, 13 commercial systems are operating in the United States, and 30 more are in development, according to the Carbon Capture Coalition.  At least one Colorado utility also

remains interested in carbon capture. Jeff Lyng, director of energy and environmental policy for Xcel Energy said in the webinar that “advanced” carbon capture remains one of the options for the utility to achieve its stated goal of achieving zero-emissions energy. Alice Jackson, president of Xcel’s Colorado division, said the same thing in late April at a Denver Museum of Nature and Science event.  Lyng also identified the following as being possible pathways for Xcel to its midcentury goal of zero-emissions:

• advanced, dispatchable renewables

• zero-carbon fuels

• advanced nuclear, modular reactors

• long-duration storage and demand response. By long duration, Lyng specified, he means days, weeks and months – not merely hours.

Solar co-op launched for Grand & Jackson counties

The non-profit Solar United Neighbors has launched a new cooperative for Grand and Jackson counties, which are coterminous with the Middle Park Electric. The primary advantage of the solar cooperative is that members can leverage through their amassed numbers to achieve improved group economics. Solar

cooperatives have previously been established in the Yampa Valley around Steamboat Springs and Craig, the Grand Valley around Grand Junction, and in the Fort Collins area.

Partners in this new co-op, called the Colorado Headwaters Solar Co-op, include Fraser’s municipal government, New Energy Colorado, and Solar CitiSuns, among others. “The cooler mountain air and higher alpine elevations make for an ideal landscape for solar, as panels produce more energy being closer to the sun and in colder temperatures,” said Jacob Schlesinger, chair of the co-op steering committee and partner at Keyes & Fox, LLP.

Time is of the essence, he said, as the 26% federal tax credit will be reduced.  After a competitive bidding process facilitated by SUN, co-op members will select a single solar company to complete the installations. However, joining the co-op does not obligate members to purchase solar.

Coal plant to close but much needed to hit 2030 goal

FORT COLLINS, Colo. — The Platte River Power Authority plans to cease production of electricity from its 280-megawatt Rawhide power plant north of Fort Collins by 2030, 16 years before its original retirement date.  The utility delivers electricity to Fort Collins and also three other owner communities: Loveland, Longmont, and Estes Park. They are also owners. The decision to set the retirement resulted from a confluence of several factors. One of them, a new survey of customers this spring in the four towns and cities, once again affirmed broad support for non-carbon energy resources. The survey found 63% of residential customers viewed the non-carbon resources as somewhat or very important. 

Platte River also has an 18% interest in two coal-burning units at Craig Generating Station. Unit 1 is scheduled to end production in 2025 and Unit 2 no later than 2030.  The stage for today’s announcement was set in December 2018 when Platte River directors adopted a policy calling for 100% non-carbon energy mix by 2030.  The resource diversification policy identified nine advancements that must occur in the “near term” to achieve that 2030 goal. They include active participation by Platte River in an organized regional market; matured battery storage performance and declined costs; and increased investment in transmission and distribution infrastructure.  

Platte River is among most Colorado utilities who will be joining energy imbalance markets in the next two years. There is common agreement, however, that deep decarbonization such as planned by Platte River and other Colorado utilities will require

participation in a robust regional transmission organization, or RTO, such as operate in other parts of the country.  Xcel Energy in December 2018 gained national attention when it announced its intentions to reduce carbon emissions 80% by 2030 as compared to 2005 levels. It operates in eight states and supplies more than 60% of the energy consumed in Colorado. Xcel said it planned to achieve emission-free electricity by 2050, but like Platte River, said technology must continue to evolve for it to achieve that goal.

Holy Cross Energy, the co-operative serving Vail and Aspen, has shown innovation that has attracted national attention, but nonetheless has committed only to a 70% carbon-free goal called Seventy70Thirty. It could, however, achieve that in 2021. Several coal plants in Colorado have

already been retired, and many more large units will be retired in the next decade. Only the plants at Hayden and Brush and Comanche 3 at Pueblo are currently scheduled to remain in operation past 2030. Xcel is the sole or majority owner of the three plants.  Spread of covid-19 interrupted Platte

River’s integrated resource planning process, which had been scheduled to include public meetings. But managers of the utility decided it was best to announce the retirement to support state regulatory timelines. Colorado last year adopted a law that identified a target of 80% emissions reduction from the electrical sector by 2030 and 50% more broadly in the state’s economy.

“Although circumstances associated with the coronavirus prevent us from making this announcement in alignment with our current IRP process, we need to continue moving forward to reach our Resource Diversification Policy’s 100% noncarbon goal,” said Jason Frisbie, chief executive of Platte River.

“Rawhide Unit 1 has served us extremely well for the past 36 years,” said Wade Troxell, Platte River Board chair and Fort Collins mayor, “but the time has come for us to move toward a cleaner future with grid modernization and integration while maintaining our core pillars of providing reliable, financially sustainable and environmentally responsible energy and services.”

Platte River Power projects that 55% of electricity will come from coal this year, supplemented by 19% from hydropower, 17% from wind, 3% from solar. Another 1% comes from natural gas; and 5% comes from purchased power, which could include fossil fuels.

Construction to build Rawhide Unit 1 began in 1979 and commercial operations started in 1984 and have performed with exceptional reliability, capacity, and environmental performance. It had been scheduled to retire in 2046. “Unit 1 has outperformed nearly every other coal plant of its type in the nation and

that is a testament not only to its design but also to the people who run it,” noted Frisbie, who began his career at the Rawhide Energy Station and became its plant manager before being promoted to chief operating officer, then general manager and CEO of Platte River.

In addition to Unit 1, the 4,560-acre Rawhide Energy Station also hosts five natural gas combustion turbines and a 30 MW solar farm, along with another 22 MW of solar power (with battery storage) currently under construction. Energy from the 225 MW Roundhouse wind farm located in southern Wyoming will be delivered to the Rawhide Energy Station and then to the owner communities. 

Frisbie said plans will be developed to smoothly transition 100 workers to new roles at the other generation resources at Rawhide after the coal-plant closure.  Following its retirement, Unit 1 will undergo a lengthy decommissioning process. Coal for Rawhide comes from the Antelope Mine near Gillette, Wyo.