Oregon’s two largest electric utilities are increasingly unlikely to meet ambitious greenhouse gas emission reduction targets established by the state Legislature in 2021, and their slow progress could cost ratepayers dearly.

Portland General Electric and PacifiCorp have achieved limited progress toward the emission caps to date. Passed after Republican walkouts in 2019 and 2020 killed an alternative policy to regulate emissions across industries, the more targeted 2021 law established some of the most aggressive utility decarbonization mandates in the country.

The law requires the utilities to slash 80% of their output of greenhouse gases by 2030 and eliminate them altogether by 2040, making power plants fueled by coal and natural gas a thing of the past.

Utilities, who were effectively being granted a license to build new power plants and pay for them through rates, were on board. And advocates celebrated the win.

“I’m so proud that we have taken steps forward to address climate change and build a more sustainable Oregon. All the while, growing our economy and creating green jobs,” declared then-Oregon Gov. Kate Brown, who later touted the law as one of her signature achievements in office.

That was then. The energy world of 2026, however, is a vastly different place, one facing a host of new obstacles as utilities try to decarbonize the grid while maintaining affordability and reliability.

To be sure, Portland General Electric and PacifiCorp have plans to meet the targets. They’re technically feasible, observers say, detailed in thousands of pages of charts, graphs, resource modeling and narrative explanation filed with state regulators and pored over by a host of stakeholders.

Both utilities say they’re committed to meeting the emission requirements, or making continual progress toward them.

But halfway to the 2030 targets, they’ve made slow progress, and their plans are heavily backloaded, reliant on a massive tranche of new generation and transmission assets projected to come online in 2029 and 2030. The pace and scale of the buildout needed to hit the deadline would be unprecedented.

As it stands, “the current trend lines aren’t steep enough to get to 80% by 2030,” said Bob Jenks, executive director of the Citizens’ Utility Board, a ratepayer advocacy group.

The 2040 targets, meanwhile, are even more implausible, dependent on blue-sky solutions — modular nuclear, hydrogen, long-life batteries, carbon capture, offshore wind — that aren’t economically, technically or politically viable today.

Utility planning, in the interim, has been scrambled by surging energy demand from data centers, all of which needs to be served with green energy to make progress against the emission goals. Inflation and tariffs have spiked the cost of wind, solar and battery resources. Planning and permitting of the transmission capacity needed to move that energy to demand centers has been stymied by public opposition to new lines and disruptions at the Bonneville Power Administration, the federal agency that controls three quarters of the region’s electric grid.

The Trump administration, meanwhile, has declared war on efforts to decarbonize the grid, canceling tax credits, grants and permitting for new projects nationwide and upending massive Biden-era subsidies that would have supported a more cost-effective transition.

“We had some tailwinds we were riding from D.C.,” Meredith Connolly, director of policy and strategy for the Seattle-based advocacy group Climate Solutions, said at a recent policy forum. “All of those have now turned into hurricane force headwinds.”

In contrast to market-based policies like California and Washington’s cap-and-trade programs, which have later deadlines and provide flexibility for polluters to trade allowances and establish a market price for greenhouse emissions, Oregon’s House Bill 2021 established hard caps on utility pollution. As yet, it’s unclear what regulators will do if the utilities can’t meet the mandates, or if doing so will drive already surging rates into the stratosphere.

“It’s ridiculous,” said Randy Hardy, an energy consultant and former administrator of the Bonneville Power Administration who believes lawmakers and advocates ignored the costs and typical planning horizon for bringing major generation and transmission projects online. “When the Legislature passed these laws, they didn’t have a clue about what the consequences were. The utilities, the (Public Utility Commission) and the Legislature are going to have to confront this.”

Big talk, less action

House Bill 2021 established an aggressive timeline to comply with the emission targets and required utilities to demonstrate continual progress toward them. But experts say both Portland General Electric and PacifiCorp have slow-walked those compliance efforts.

PGE’s emissions have declined 27% from the base level set by lawmakers — its average emissions between 2010 and 2012. But a chunk of that decline came from the 2020 retirement of its coal-fired plant in Boardman, previously the workhorse of its generation fleet.

Given the need to make progress against the goals while meeting rising energy demand, PGE fast-tracked a request for proposals in 2023 seeking 750 average megawatts – the average rate of energy generation over a year – from new renewables projects. But it ultimately agreed to procure about 10% of that amount — a shortfall critics decried as a wholesale departure from its earlier plans, and a wait-and-see approach that would jeopardize its ability to comply.

PGE issued a new request for proposals last July. Drew Hanson, a spokesperson for the company, said it will announce a short list of projects from that solicitation next month that will demonstrate more momentum toward the goals.

PacifiCorp’s progress has been even slower: an 19% reduction in emissions over the same period. Facing billions of dollars in liabilities from Oregon’s 2020 wildfires, credit rating downgrades and a potential cash crunch, the utility in 2024 backed off an earlier plan to bring on significant chunk of new renewable and storage resources and submitted an updated resource plan to regulators showing it wouldn’t meet the 2030 emissions target.

The Oregon Public Utility Commission subsequently found the utility had not demonstrated continual progress toward the goal, threatened it with financial penaltiesand contemplated issuing an edict forcing the company to procure more clean resources faster. It backed off when PacifiCorp agreed to issue a new solicitation for renewables.

“PacifiCorp is committed to complying with the energy and emission requirements of House Bill 2021” Omar Granados, a spokesperson, said in an email. He added that its current plan forecasts emissions falling 85 % by 2030.

The utilities still have five years until the 80% deadline, but that’s a blink of an eye in utility time. As it stands, both utilities’ plans call for massive amounts of new resources to come online just before the 2030 deadline.

PGE, for example, plans to add nearly 2,800 megawatts of new wind and solar resources, with nearly 90% of it slated to come online in 2029. To put that in perspective, the utility’s current fleet of power plants, built over decades, had a total generating capacity of 3,570 megawatts at the end of 2024.

The utility also plans to add more than 2,500 megawatts of battery storage capacity, which it can tap to meet summer and winter peaks in demand and when its wind and solar farms aren’t producing.

PacifiCorp’s resource plans show the addition of more than 2,500 megawatts of wind and solar and another 900 of storage capacity, almost 90 percent of which would come online in 2030. And it imposed a requirement in its own modeling that all those resources be sited in Oregon.

Alex Houston, an attorney at the Lewis & Clark College’s Green Policy Institute said that requirement is puzzling, as the utility operates in six western states and could be using that scale to more cost effectively meet Oregon’s emission requirements. Overall, he says the utility’s plan might be technically possible but isn’t credible in the real world.

“Waiting ‘til the eleventh hour and relying on basically an unprecedented level of procurement in a single year is risky for everyone,” he said. “We’re certainly not optimistic.”

PacifiCorp did not respond to a question about locating its projects in Oregon, but Granados said it is actively evaluating feedback on its plans from state regulators and other stakeholders.

Jenks also notes that PacifiCorp has been converting coal plants to burn natural gas, with the electricity and emissions still connected to Oregon’s system.

“I don’t have a clue what PacifiCorp’s emissions are going to look like in 2030 if you can’t tell me how the gas plants are going to be allocated among the states” it operates in, he said. “They’ve kicked that question down the road.”

Costs are going up

Buying the resources needed to comply with the mandates will be significantly more difficult and expensive today than when the law passed.

Renewables remain the cheapest source of energy available, but data from Seattle-based LevelTen Energy, which tracks the price of utility and other power purchase agreements, shows that the blended cost of wind and solar power has more than doubled since the passage of HB 2021.

That includes a 14% year-over-year hike in the cost of wind energy in 2025 and a 4% increase in solar prices as the Trump administration’s tariffs on metals, minerals and essential project components have been layered on top of general inflation, the company said in a recent report.

In addition to other West Coast utilities seeking to meet their own emission reduction mandates, Oregon’s electric utilities are directly competing with data centers looking to reduce the carbon footprint from their energy-hungry facilities. Those companies are not subject to same extended bidding processes that regulators require of utilities and can afford to pay whatever the market demands.

“You don’t want them just gobbling up all the resources that would have gone towards reducing (utilities’) existing emissions,” said Cole Souder, an attorney with the Green Policy Institute, which submitted comments on both PGE and PacifiCorp’s plans.

On top of higher costs comes uncertainty among developers, said Arne Olson, a principal at the energy consulting firm E3.

“The bids we are seeing now tend to contain many caveats and outs on the pricing component,” Olson said, “just because none of the developers has a good line of sight on the cost of their raw materials.”

On top of that, the federal government plans to terminate tax credits that typically cover 30% of the cost of clean energy projects. Under new law, projects need to be up and running by the end of 2027 or under construction by July 4, 2026, to qualify. Utilities are now scrambling to find eligible projects before they reach the tax credit cliff, but analysts say the supply of projects with permits and transmission rights in place is finite, and competition is stiff.

“When those tax credit cliffs actually happen, there will be a lot of announcements … about projects getting canceled, companies merging, getting acquired,” said Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, which represents energy developers. “There’s going to be a lot of corporate restructuring just because people’s balance sheets weren’t constructed assuming the credits would suddenly go away.”

As it stands, most of PGE and PacifiCorp’s new resources are slated to come online between 2028 and 2030, after the tax credit window closes. It’s unclear how many of those might meet the “under construction” deadline.

“Every day and every year that they delay further, they’re more at the whims of uncertain future supply chains and uncertain government support,” Houston said. “And the closer it gets to 2030, the more competition. So, there’s going to be more potential price increase.”

In addition to repealing the tax credits, the administration has canceled grants for renewable and transmission projects, withdrawn and delayed land use approvals for others and gone so far as temporarily halting offshore wind projects that are already 80% complete.

“Everything that they’ve done, like every single thing, has been to make it more difficult to develop clean energy projects,” Olson said.

Renewable energy projects are capital intensive, meaning they involve huge upfront investments but have lower operating costs than coal or natural gas due to the lack of ongoing fuel expenses. PGE and PacifiCorp’s plans will involve billions of dollars in such up-front investments, money they need to raise from investors and Wall Street.

Letha Tawney, chair of the Oregon Public Utility Commission, said ratepayers are effectively borrowing money from the utilities to build the projects, and paying them back in rates over the following 30 to 40 years. But their ability to raise all that money is compromised not only by generally higher interest rates, but wildfire liabilities that drive borrowing costs higher.

PacifiCorp has recently seen its credit downgraded because of its mounting liabilities related to the Labor Day 2020 fires and related concerns about its cash position.

Tawney noted at a recent energy forum that Oregon is one of only two states that don’t have some form of cost cap for utilities on wildfire liabilities.

“If we don’t solve the wildfire risk,” she said, “we won’t solve any of this.”

Transmission woes

Utilities not only have to build or acquire enough clean resources to decarbonize and ensure reliability but obtain the transmission capacity to move the energy to customers. Clean power projects are mostly east of the Cascades, while customers are concentrated on the other side of the mountain range.

As it stands, the region’s transmission system is essentially gridlocked. There is little new capacity currently under construction in Oregon. And the biggest provider, the Bonneville Power Administration, has been in organizational turmoil, raising questions in the energy community about whether the federal behemoth is still a reliable partner.

The agency, which controls three quarters of the region’s high-voltage grid, was swamped by requests for about 68 gigawatts of transmission service in its most recent planning study. The volume was so massive that Bonneville temporarily stopped taking new requests as it established stricter criteria.

The same month it announced the suspension, the agency got “kneecapped” by the Department of Government Efficiency, according to Steve Wright, a former Bonneville chief executive.

Bonneville is funded by ratepayers, not the federal government. But it lost roughly 400 employees through buyouts, the firing of probationary employees and rescinded job offers, causing widespread panic among utilities and developers who were counting on the new transmission lines.

The agency has since restored about half those numbers by rescinding terminations or new hiring. But its headcount is still roughly 10% below its 3,525 authorized number of employees. Kevin Wingert, a spokesperson for the agency, said a plan has been submitted to the Office of Personnel Management to hire an additional 950 employees in the coming year, with 389 being transmission specific. But even if the plan is approved, it won’t be easy.

Transmission planners and engineers are in high demand across the country, and BPA is competing for them with investor-owned utilities who are building their own lines and can afford to pay far higher salaries.

“There was always lower pay at Bonneville, but the differentials were never as great as they are now, not even close,” said Wright, one of three former BPA administrators who endorsed a proposal in Congress to raise pay at Bonneville.

“They are running basically a three-legged race right now,” he added.

Wingert said BPA is being hit by the same forces as utilities in the region and has revamped its transmission and interconnection planning to meet the challenge. It plans to add more than 6,000 megawatts of transmission capacity by 2035, a $5 billion portfolio of 23 projects. In the meantime, it has plans to double its transmission spending in 2028 and has identified 7.5 gigawatts of transmission requests from projects it can connect to the grid by 2030.

“BPA has been, is, and will continue to be a cornerstone in collaborating with the region to meet our mission and the needs of our customers,” he said.

Hardy, the other former Bonneville administrator, says the agency may be able to connect that volume of projects by 2030, but he’s still skeptical it will have the capacity to move all that power to customers.

“That’s a 2032 to 2035 timeline,” he said. “That’s not Bonneville’s fault. That’s how long it takes.”

Meanwhile, Oregon utilities face their own challenges adding capacity.

In May, the Portland City Council shot down a plan by PGE to rewire a 1970s transmission line and add a second line in the utility’s existing right-of-way in Forest Park.

In October, the U.S. Department of Energy said it was canceling a $250 million grant awarded to the Confederated Tribes of Warm Springs and PGE to upgrade an existing transmission line and enable the development of more renewable energy. Neither has received an official notification of the grant cancellation.

PGE also has several planned upgrades and new lines planned to deliver power to data centers in Hillsboro and strengthen its grid around the metro area. But Hardy suspects they’ll face significant opposition from the public and come in later than planned, compromising the utilities’ ability to meet the 2030 target.

This summer, after 20 years of planning, permitting and lawsuits, PacifiCorp and Idaho Power launched construction on a new electrical line running 300 miles from Idaho and across five Oregon counties, an upgrade the utilities had previously said would allow it to deliver more renewable energy from resource rich areas into Oregon and help meet the state’s decarbonization goals.

Last spring, however, the company announced that it had been unable to secure transmission from Bonneville to send the power further west to retail customers. Instead, it said it would sell the power to an industrial customer — likely a data center.

Possible off-ramps

The PUC’s Tawney says there are two potential off-ramps if PGE and PacifiCorp can’t meet the 2030 targets. Utilities can be temporarily exempted from the targets if compliance would violate an established 6% cost cap in the law, or if it would compromise the reliability of the electric grid.

“I would think of both of those as addressing the question of pacing,” she said. “It doesn’t remove the obligation for HB 2021’s goals, but it changes the pacing for when you would reach them.”

She said the commission is looking at the cost question now and has a lot to understand about how much the landscape changed under the Trump administration and how it has impacted the price of the transition.

That interlocking challenge of affordability and reliability will drive Oregon’s debate going forward, and some experts think the region may rely on natural gas as a bridge fuel far longer than anticipated by lawmakers and advocates in 2021.

PacifiCorp’s Granados acknowledged in an email that there will be cost pressures as the utility transitions to renewables from existing, lower-cost coal and gas-fired plants that are available when other resources are not.

Kristen Sheeran, vice president of policy and resource planning at PGE, insists that the utility has made strong progress against the goals in a short period of time, and sees the urgency of trying to move fast while tax credits are still available. The federal policy environment, and the expiration of those credits, she says, are “a game changer,” and transmission constraints pose more challenges.

“An absolute emission target may have made sense back in 2021 when the region was anticipating minimal (demand) growth,” she said. “And that is just not the reality that we’re experiencing today.

“So all of those headwinds are playing out,” she said, adding that “there’s no silver bullet.”