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Federal agencies will accept input through Aug. 15

May 2, 2025
By Eric Barker

Federal agencies have extended a public comment period on their effort to take a new look at the effect Snake and Columbia River dams have on salmon and steelhead.

The Army Corps of Engineers and the U.S. Bureau of Reclamation will now accept comments through Aug. 15 in advance of their work to update the 2020 environmental impact statement on the dams.

The update, known as a supplemental environmental impact statement, is a product of the agreement between the Biden administration and Native American tribes like the Nez Perce and other plaintiffs in a decades-long lawsuit over the harm dams cause to the fish.

Specifically, the agencies plan to consider new information including a tribal circumstances report released last year that said development of the dams caused substantial and ongoing harm to tribes with treaty fishing rights in the Snake and Columbia river basins and a 2022 National Oceanic and Atmospheric Administration Fisheries report that said wild Snake River salmon can’t be recovered to healthy and harvestable levels without dam breaching.

Public meetings related to the work were to be held this spring but were canceled last month, causing some to speculate that the Trump administration may be mulling its support of the agreement struck by his predecessor. According to a news release announcing the extended deadline for public comments, those meetings will now be held virtually over the summer months. However, dates have yet to be announced.

The agreement led to a pause in the litigation expected to last up to 10 years. In exchange for the tribes shelving their lawsuit, the Biden administration pledged to make significant investments in salmon recovery and to study how to replace the services of the four lower Snake River dams if they are ever breached.

More information on the environmental impact statement process and ways to comment on it are available at www.nwd.usace.army.mil/columbiariver/. 

Lewiston Tribune: Salmon and dams comment period extended

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By Eric Tegethoff, Producer
Tuesday, April 29, 2025

A major player in the Northwest's energy landscape is considering changes in the future, as extreme climate events make power delivery in Oregon more unpredictable.

Like utilities in the region, the Bonneville Power Administration - a nonprofit federal administration - is considering joining a larger energy market to ensure reliable access for customers.

BPA is favoring a market known as Markets+, which it says will be less expensive in the long run but could cost between $79 million and $129 million more for ratepayers in 2026.

However, organizations like Save Our Wild Salmon favor the Day-Ahead Energy Market, or EDAM.

Tanya Riordan, policy and advocacy director with the organization, said BPA needs to consider tribal rights in the region, especially when it comes to salmon.

"We can have a more open governance model," said Riordan, "that gives state officials and consumers an equal role, which would keep salmon recovery priorities at the forefront, which is what the EDAM market would offer."

Riordan said the transition to a larger energy market would reduce pressure on the federal hydropower system, also reducing pressure on the region's rivers and salmon.

A formal document outlining BPA's decision is expected in May.

Ben Otto, an energy consultant with the Northwest Energy Coalition, said he also favors EDAM.

He said the BPA has a unique role in the Northwest, with obligations to its customers, but also to the rest of the region by selling hydropower to keep bills low and running a transmission grid in the Northwest.

"Also by mitigating the impacts to salmon and wildlife and tribal interests," said Otto, "this is really important - and we really think that those obligations need to play a more significant role in Bonneville's decision, and we look forward to that being reflected in their record."

Otto said EDAM would reduce costs and be just as reliable as Markets+, and would make the integration of clean energy easier.

He noted that BPA wouldn't fully join the market, regardless of its choice, until 2028 - and so he's urging the administration to take its time making a decision.

"We believe a market that gives a strong role for public interest and state policy is a better fit for Bonneville's obligations than Markets+," said Otto, "which is really more of like a business league and more commercially focused."

Public News Service: Bonneville Power energy market choice impacts NW environment 

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Experts fear Trump’s tariffs on Canada, harsh words could hurt hydropower, salmon, more

Hugh Keenleyside Dam on Lower Arrow Lake © Peter Marbach

By Henry Brannan, Columbian Murrow News Fellow
Published: March 29, 2025
Updated: April 7, 2025

Flood risk management, hydropower generation and salmon runs will suffer if the United States and Canada don’t renew a key provision of the treaty that guides how they manage the Columbia River.

That key component, part of a stop-gap agreement the two countries reached late last year, expires July 31, 2027.

If a new treaty doesn’t come into force by then or the two sides can’t agree on another set of interim measures, Canada will no longer have to hold back more than 1 trillion gallons of water it stores for the U.S. each spring to prevent flooding in the lower Columbia River and maximize hydropower production year-round.

The two countries have been working on a new Columbia River Treaty since 2018. President Donald Trump paused negotiations earlier this month, a routine step at the beginning of a new administration, experts say. What’s not normal, they say, is the backdrop for the pause — a dramatic trade war and diplomatic clash between the two countries.

“Things that we counted on — that the United States would be a friend and ally to Canada — are now no longer true,” said Adrian Dix, British Columbia’s energy minister.

Mutually profitable?

The 1,243-mile-long river springs from Columbia Lake in southeastern British Columbia and flows into the Pacific Ocean near Astoria, Ore.

Over the course of the 20th century dams transformed the once-wild Columbia into a machine that prevents previously inevitable seasonal flooding while also generating hundreds of millions of dollars in hydropower each year and allowing ships carrying billions of dollars in goods to travel from the ocean as far inland as Idaho.

The U.S. and Canada have fine-tuned that machine since the Columbia River Treaty came into force in 1964. Under the treaty, Canada and the United States share the river’s benefits.

Canada helps regulate the flow of water through a system of dams and reservoirs, and the U.S. sends back payment for half of the extra power that can be generated from that re-timed water. In recent years, the payments ranged from roughly $100 million to $300 million each year, but that amount will decline under the 2024 interim measures.

Without a new agreement, worst-case scenarios could include increased flooding along the lower Columbia River in communities like Vancouver; river and reservoir conditions that threaten salmon runs; and costly disruptions to hydropower production, farm irrigation and commercial navigation.

“Either country alone could build dams and do stuff for flood control and power production and whatever else they want to do, but they could only get so much,” said Richard Paisley, director of the Global Transboundary International Waters Governance Initiative at the University of British Columbia. “But it’s only when they decided to cooperate and run together and synchronize their operations that both sides could do better.”

That, in turn, he said, has generated something more valuable than any other commodity: certainty.

And certainty is the foundation of every dollar the Columbia River drives. That’s true for the $31 billion in goods shipped on the deep water channel each year; for the $3 billion in crops watered with nearly 1 trillion gallons of water in the Columbia Basin Project each year; and for the ever-growing residential, commercial and industrial power fueled by hydropower.

All of those depend on the river to be managed just as it is now. They turn that relative consistency into the foundation of the region’s economy. Tens of thousands of jobs rely on the system. And it all stands to be disrupted to varying degrees.

The State Department, which is leading the negotiations for the U.S., declined to answer questions. The U.S. Army Corps of Engineers and Bureau of Reclamation, which together run the Columbia River federal dam system, also declined to comment, as did the Bonneville Power Administration, which markets the power generated by the federal system. The Columbian spoke with 10 officials and experts from both sides of the border; four declined to be quoted.

Diplomatic dominoes

Although the two countries reached an agreement in principle late last year, Canadian officials fear the Trump administration will depart from it.

“We’ve come to an agreement. The only question is, will that agreement get caught up in the currently erratic politics of the American government?” Dix said.

While Trump has singled out the Columbia River Treaty in talks with Canada, his threats to annex the country and the impact of his trade war policies on both countries’ economies are particularly worrying to Dix.

Experts and officials on both sides of the border also fear negotiations won’t succeed in time. During his first term, Trump was slow to appoint key figures, and that’s shaping up to be the case again. Without those officials in place, negotiations can’t continue.

If the key flood-management provision expires Aug. 1, 2027, the Columbia River would shift to a “called upon” storage regime. Through the treaty, Canada assured the U.S. about 3 trillion gallons of pre-planned flood risk management storage each year from 1973 until 2024.

Without action, Canada would provide none. Instead, the burden of managing flood risk while trying to preserve U.S. hydropower generation capability would be shifted to the U.S.

And while it’s taken for granted, the task of managing the Columbia River’s nearly 65 trillion-gallon yearly flow is not easy. That’s especially true because Canadian runoff accounts for as much as half that amount each year, and most of that comes in May, June and July. Between 15 trillion and 19 trillion gallons barrel down across the border in those months alone. To combat those flows without pre-planned Canadian storage, the U.S. will have to call on Canada to hold back water as it becomes clear it will be necessary.

But that’s complicated because the two countries never agreed on the price the U.S. will pay, how drastically the U.S. will have to first disrupt its river operations and how much flood damage communities like Vancouver will have to be projected to incur before Canada will provide that called upon storage.

To Barbara Cosens, a former law professor at the University of Idaho who has studied the treaty for more than 15 years, all of that leaves the U.S. vulnerable in the unlikely but possible event that these issues end up having to be settled during a year when there’s extremely heavy precipitation and risk of a serious flood.

“Those two things mean that you have to have to have good working relationships when that occurs,” she said, “and even the interim measures themselves really depend on continued good working relationships, and so that is clearly one of the wild cards we have in play now.”

Impacts

The potential loss of the last trillion gallons of pre-planned Canadian storage could have dramatic impacts on U.S. flood risk management, hydropower production, agricultural outputs and salmon runs.

For flood control, the loss of the first 2 trillion gallons of storage earlier this year already increased flood risk along the lower Columbia in communities like Vancouver.

Much of the burden of the loss of the final 1 trillion gallons would likely be shouldered by operations at the massive Grand Coulee Dam and Lake Roosevelt reservoir behind it, officials and experts say.

But that comes with consequences. If Grand Coulee is being operated more conservatively to battle floods, its operations will, by definition, be less tailored to producing power when it’s needed and prices are higher. That lack of flexibility could lower production.

The Corps’ Julie Ammann, acting chief of the Columbia Basin water management division, acknowledged that in a September 2023 talk.

“Changes to flow and storage project operations may have an impact on power generation,” she said.

Lower levels at Lake Roosevelt also mean higher pumping costs for area irrigators during an already difficult period for them.

The potential loss of assured storage in 2027 would also affect salmon, said Joseph Bogaard of Save Our Wild Salmon. The change would increase uncertainty and, in the battle between all the competing interests looking to get their slice of the river, salmon would likely continue to come in last place.

“I think it’s safe to say that salmon will continue to pay a heavy price under that sort of scenario, perhaps even heavier than it’s been under the current scenario,” Bogaard said. “There’s a lot of uncertainty.”

Of course, the whole issue could be resolved if the two countries agree on another set of interim measures or manage to ratify a modernized treaty.

Even barring those rosy outcomes, other factors may minimize the impacts of the potential end of assured Canadian storage in summer 2027.

Hydropower coordination between the two countries is set to continue until 2044 and that lets the U.S. know a bit about how Canada will manage the river. Corps’ models show that will lessen the impact.

Cosens also noted that Canadian hydropower operations happen to sometimes align with U.S. flood control interests.

“There is synergy between using those dams for flood control and using them for hydropower,” she said.

Those factors, combined with the long-standing, close relationships between water managers in the two countries and the fact that former President Joe Biden kept on Trump’s lead State Department negotiator all leave Cosens hopeful.

But she fears logic alone is not enough anymore.

“If you follow the logic, they should find — this Trump administration when they review the treaty — that it’s consistent with their original marching orders,” she said, pausing then adding, “whether logic applies, I don’t know.”

The Columbian: Pause in Columbia River Treaty talks stokes worry for flood control in Vancouver

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March 24, 2025
By Emily Senkosky

Time is running out to save Pacific Northwest wild salmon and steelhead, but studies conducted by tribes and the states of Washington and Oregon are providing data needed to preserve them and the ecosystems and economies that depend on them.

In February 2024, a joint agreement between Pacific Northwest tribes and the Biden administration commenced a new approach to recovering salmon and steelhead in the Columbia River Basin. Parties agreed to consider breaching the four lower Snake River Dams, which have long been contentious for their part in decimating fish populations. To remove the dams, which provide energy, irrigation and transportation routes, data on the feasibility of replacing their infrastructure was needed.

The Washington Department of Ecology and the U.S. Bureau of Reclamation conducted the first study, which showed that the removal of the lower Snake River Dams would not affect the river's capacity to supply water for irrigation or for municipal and industrial purposes.

By providing three options for service replacement, the research was meant to give the public and decision makers baseline data that could inform future actions – with water service replacement estimated to cost between $1.7 and $3.5 billion. According to Kayeloni Scott, executive director of the Columbia and Snake River Campaign, the studies were geared at finding out if dam removal was even possible.

“These pieces of information are critical for moving forward,” said Scott. “The studies were meant to find out what would need to be replaced, what actions would need to be taken, and what it would cost.”

Regarding energy replacement, several studies have indicated that energy needs in the Pacific Northwest are projected to nearly double by 2050. The lower Snake River Dams are “run of the river” dams, meaning they are entirely dependent on snowpack and its rate of runoff. This type of energy generation makes them relatively unreliable compared to some other dams in the federal Columbia River system – especially in recent years with decreasing snowpack.

While the Snake River Dams have a collective generating capacity of 3,033 megawatts, their average yearly output is around a third of that at around 1,075 average megawatts. According to actual generation data from 2010-2015, the average output for the dams was even lower, at 930 megawatts of power per year.

“The lower Snake River dams are outdated structures that will require significant funding to update and maintain. We have an opportunity to invest in the region through options that not only consider the needs of salmon, but also stakeholders,” said Scott.

The second study by the Washington State Department of Transportation is multi-phased and aimed at evaluating the transportation impacts of dam removal. The first phase gathered data on current freight volumes and transportation networks to develop a predictive model for future movement and transport needs. A second phase, that began in 2025, will analyze safety and broader impacts, incorporating input from technical and community advisory committees.

The ongoing research aims to fill critical knowledge gaps left by previous federal reports, ensuring policymakers can address the logistical challenges that could come up without the Snake River Dams in place.

Sustaining salmon

For decades, the return of salmon and steelhead to the Snake River Basin has been shifting away from wild-origin and to a great extent to hatchery-origin fish. According to Jay Hesse, fish biologist for the Nez Perce Tribe, over half of the native populations of spring and summer Chinook salmon are now gone. The 32 native populations remaining are in dire condition and listed as an endangered species. Replenishing these fish to the federal standard established by the Endangered Species Act is a much lower bar than getting the fish back to a “healthy and harvestable” status.

“The (federal) regulations are a floor for fish performance within the hydro system,” said Hesse.

The new NOAA report, in combination with efforts by Columbia Basin tribes and state fish managers, is helping to communicate how well fish populations, or stocks, are doing and what types of changes are needed for their protection. If a salmon or steelhead population has had 50 or fewer wild fish on an annual basis for four consecutive years, they have reached what is known as a Quasi Extinction Threshold, which is an indicator that the stock is headed toward extinction.

“We are in dire straits. Nearly half of the spring and summer Chinook populations are at the (threshold) level,” said Hesse.

Metrics showed that 1.9 million salmon passed through the Bonneville Dam in 2024, as compared to historical estimates of 8-16 million. According to Hesse, achieving healthy and abundant management goals will require discourse that considers fish biology, environmental habitat, and human behavior.

“For Snake Basin stocks, the heart of the resolution is to breach the four lower Snake River dams while taking care of the communities and services that those dams provide,” said Hesse.

Powering progress

The new studies are helping to move toward tangible outcomes, but spending freezes and job removals are directly affecting tribes’ commitments as set forth in the Resilient Columbia Basin Agreement – a manifesto based on the priorities outlined in the joint agreement with the Biden administration.

Despite these challenges, the new studies will help lay the groundwork for a path forward. Resilient Columbia Basin Agreement advocates are taking a grassroots approach by participating in town hall meetings and prioritizing direct engagement with stakeholders to hear the concerns of potentially impacted communities. According to Scott, people have been mostly receptive and positive, with their main concerns being for agriculture and reliable, affordable energy.

All of this work has led to an updated environmental impact statement that incorporates new information and circumstances into the 2020 environmental impact statement of the dams. Public meetings for this supplementary statement are scheduled for the week of April 7th, and a public comment period is open now through May 9th. For tribes of the Columbia River Basin, this progress has been a long time coming and is something that could have profound ripples.

“It’s deeper than salmon going extinct,” said Scott. “For tribal members, the survival of the species is the survival of our way of life.”

ICT: New studies may lead to removal of Snake River dams

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By Pete Danko – Staff Reporter, Portland Business Journal
Mar 7, 2025

Bonneville Power Administration intends to join the new energy market Markets+, the federal agency said Thursday, a decision with potentially significant energy cost and reliability ramifications that has divided utilities and other industry stakeholders in the Pacific Northwest.

The draft decision by the region's biggest power player was in line with a policy direction laid out nearly a year ago. Yet it came amid rising pressure to hold off on a commitment, if not opt for a rival market supported by Oregon's two largest utilities, Portland General Electric and PacifiCorp, and many renewable energy and climate advocates.

Oregon's and Washington's U.S. senators had joined in calls for BPA to delay action.

"This hasty draft decision by the BPA is not good news for electricity consumers in Oregon and the Pacific Northwest,” Oregon Sen. Ron Wyden said Thursday in an emailed statement.

BPA's release of a two-page cover letter and 93-page draft policy paper opened a 30-day comment period ahead of a planned final policy declaration in May.

"This draft policy is consistent with Bonneville's strategic goals, day-ahead market evaluation principles, and the Trump Administration's energy directives," John Hairston, BPA's administration and CEO, said in the letter.

For nearly two years, utilities and other electricity providers throughout the West have been weighing two "day-ahead" energy market proposals: Markets+ from the Southwest Power Pool based in Arksansas, and the Extended Day-Ahead Market, or EDAM, that California's grid operator is developing.

Each has promised efficient and robust energy trading that could help in addressing the challenges of grid congestion, reliability in the face of extreme weather events, rising rates and demand, and decarbonization.

"As the region evolves, this draft policy reflects BPA's best opportunity to remain competitively positioned in the long-term to continue meeting firm power sales obligations and marketing surplus to maintain low rates for customers," Rachel Dibble, BPA Power Services vice president of bulk marketing, said in a written statement.

BPA's direction is key not only because it sells power from 31 federal dams and a nuclear plant, but it owns and manages 75% of the region's high-voltage transmission system.

Its tilt toward the Markets+ has been widely — though not unanimously — supported by consumer-owned utilities, who have first dibs on its relatively inexpensive hydropower. A key factor in their preference has been concern that EDAM's governance structure would give California politicians undue influence, putting BPA's market standing at risk.

The agency has stood by its position through two new rounds of analysis that found that an EDAM with BPA in it would deliver greater economic benefits to BPA and the region, possibly amounting to as much as $4.4 billion over the next decade.

EDAM advocates had called on BPA to hold off on a decision while California lawmakers consider legislation that could solve the governance issue. BPA's precarious staffing situation in the wake of Trump administration actions brought new urgency to their calls.

'Tumult inflicted by Donald Trump and Elon Musk'

"The needless tumult inflicted on BPA by Donald Trump and Elon Musk, along with the uncertain outcome of potential changes to the California Independent System Operator add up to serious questions BPA must answer with transparency before issuing its final market decision," Wyden, the Oregon Democrat, said. "Foremost in that decision come May is the need for an electricity market that serves everyone in the Pacific Northwest and keeps reliability and electricity prices at the forefront."

BPA officials, in a news conference Thursday afternoon, said they had waited years for changes to the California system operator's governance and didn't want to be forced into a corner as other utilities made market choices.

"The longer BPA waits, the more the opportunity to chart our own course closes," Dibble said.

She also emphasized the governance advantages the agency sees in Markets+.

"Those are qualitative elements that we hold as very high priorities," Dibble said. "We do believe in the long run they will result in positive, quantitative benefits ... because we will have a seat at the table and be able to work, to collaborate, with partners on those future design elements."

The Public Power Council, which represents consumer-owned utilities, encouraged utilities to rally around the BPA decision and Markets+.

"With many utilities across the Northwest and Southwest already supporting Markets+, this decision signals even greater momentum toward a broad and well-structured market that delivers reliability and cost benefits," Scott Simms, the group's CEO and executive director, said via email. "We encourage additional utilities to consider joining this effort to further enhance regional coordination and market efficiencies."

Many energy players, though, see EDAM — bringing in the massive California energy market — as the only possibility for achieving the broadest and most beneficial market footprint. They warned that a split decision in the region would introduce new costs and reliability risks by introducing "seams" into transmission operations that would have to be overcome.

PGE, PacifiCorp positions

"Maintaining reliability is already challenging in some circumstances, even as we've operated under the same rules," Larry Bekkedahl, a PGE senior vice president, said via email. "BPA's decision may adversely impact all customers in the PNW, including PGE's."

PGE highlighted that EDAM builds on the California grid operator's long-standing real-time market that brings in almost all of the West, including BPA, while Markets+ is starting from the ground up.

PGE had joined with PacifiCorp and Seattle City Light, a municipally owned utility, in a letter earlier this week making the case for EDAM and urging Bonneville to hold off on a decision.

"This would allow BPA to explore mechanisms to better monetize its participation in (the existing real-time market), while continuing to lead on governance reform as it considers future day-ahead market opportunities," the utilities said. "Additionally, it would delay the creation of an unavoidable, not easily managed or reversible, seam and maintain the coordination in the West that is critical to keep the lights on and costs down."

Two groups that support the clean energy transition in the Pacific Northwest expressed disappointment at BPA's decision.

NW Energy Coalition said it puts "every power customer in the Northwest ... at risk for higher costs on their monthly bills." Renewable Northwest said "we believe it will have negative economic impacts on regional customers that have not been adequately addressed."

Both groups noted the BPA staffing challenges that have been in the headlines in recent weeks.

"While we disagree with this proposed decision, we continue to support BPA's employees' essential work to manage the power and resources entrusted to them by the American people, to protect our fish, wildlife and natural resources, and to keep the lights on," Nancy Hirsh, NW Energy Coalition's executive director, said in a statement.

Portland Business Journal: Bonneville Power Administration advances controversial energy market decision

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March 5, 2025
By Lynda Mapes

Heat domes. Cold snaps. Winter storms — even as far away as Texas: extreme weather events are roiling power markets and spiking power prices for energy providers and their customers.

This increasing volatility — and mandates to decarbonize energy supplies, introducing more variable energy sources, such as wind and solar power — is driving big changes for regional utilities, including how they buy and sell power.

In play right now is a new alignment of Northwest utilities into centralized, organized energy markets.

Two power market operators are contending for their business: the Southwest Power Pool’s Markets+, based in Arkansas, and the California Independent System Operator. Both operators are seeking commitments from Northwest utilities.

This is a complex topic, so let’s step back to see what’s new.

Around the region, utilities buy and sell energy to meet customers’ needs, moving power around a connected power grid. That is not new.

What is changing is creation of these larger, centralized pools of utilities over a bigger geographic footprint, with an operator that optimizes trades not just minute to minute but for a whole day. That is intended to help utilities smooth challenges of variability in both weather and energy sources.

As these new market pools shape up, all eyes are on the Bonneville Power Administration.

A nonprofit federal administration, the BPA is self-funded by revenues from selling power and transmission services across 15,000 miles of high-voltage power lines. The juice comes from 31 federal dams and one nuclear plant, which produce about 32% of the power generated in the Northwest, sold wholesale to 142 retail customers — utilities large and small across 300,000 square miles in eight states.

Some get all their energy from BPA. Others, such as Seattle City Light, supplement their own generation with purchases from BPA. Typically, Seattle City Light gets 40% of its customers’ power from BPA — even more in low-water years, such as last year.

BPA has held multiple briefings, and workshops to help lead the process as the region remakes its energy market. BPA staff in a white paper last year recommended BPA jump in the pool operated by Markets+.

But with the players in the two power pools still shaping up, some powerful policymakers are urging BPA to pump the brakes.

Aligning with energy partners in the Southwest Power Pool’s Markets+ initiative is projected to be, under some scenarios, $79 to $129 million more costly in 2026 for Bonneville — and its ratepayers — compared to business as usual, according to a study commissioned by BPA. U.S. senators for the Northwest wrote in a letter to BPA Dec. 13 that there is no scenario evaluated in the study that demonstrated financial benefits in choosing the Markets+ alternative.

BPA counters that while initial costs in the first few years of Markets+ participation are more costly, those costs level out and BPA contends the long-term picture eventually is financially beneficial for customers.

But why eat extra cost? And why the hurry, the senators asked, and urged BPA to do nothing for now, and wait out changes expected in California law this session, that could put to rest concerns about governance of that market pool.

PacifiCorp, PGE, Seattle City Light and three major electrical worker unions in Portland, Tacoma and Seattle also urged BPA to change nothing for now a letter sent to BPA this week, urging BPA to avoid additional costs for customers already facing rate increases.

Heavy hitter customers that guzzle power, including Amazon, Google, Microsoft and Rivian, also in a public comment sent to BPA’s administrator stated Bonneville has not sufficiently taken into consideration the impact to ratepayers and any decision now is premature. A host of environmental groups and green energy advocates have also urged BPA to give this decision more time to more fully consider both economic and environmental impacts before making its move.

But with some area utilities already declaring their market preferences, BPA must make a decision, or will find itself isolated, with limited options, said Rachel Dibble, vice president for bulk power marketing at BPA. “We have to make a choice,” Dibble said. “Or everything will change around us and our options will be limited. Not to make a choice is a choice.”

Chelan, Grant County and Snohomish County PUDs and Tacoma Power have each already indicated a preference for Markets+. For Tacoma Power, the decision came down to reliability and independent governance, said Chris Robinson, general manager and chief operating officer for the utility.

Being hosted by a market run by a California entity didn’t seem like a good deal, Robinson said, and he didn’t want to wait on legislation in California to sort that out, either. “We have this opportunity right in front of us; we think it is important to move forward,” Robinson said.

But Dawn Lindell, general manager for Seattle City Light, isn’t feeling the Markets+ love. She said she is concerned about reliability and affordability for the utility’s customers.

“I want to know, do I have paths by which I can get the energy and send the energy, and is it what makes economic sense?” said Lindell. “We have 113,000 customers at or below 60% of average income, it matters a lot what we charge … I am looking for the least cost, most effective option.”

Weather events of the last four years compared with the previous 20 have gotten the utility’s attention, Lindell said, offering a graph that shows spikes in power prices on the market as jagged as the extreme temperatures that necessitated the power purchases.

“You can see climate change in the graph, it is very impactful over the last four years and every time we have a high (temperature) day or a low day, we have to go on the market and it is very expensive,” Lindell said.

“These weather events are driving the need for a very good and cost effective way of buying and selling energy.”

The larger storms wrought by climate change also make creation of a larger market into which to sell and from which to buy sensible — to escape weather patterns that spike prices. “Storms are stronger, last longer, and affect a much bigger land mass,” Lindell added.

“We need trading markets where the weather is different … I would love a ginormous footprint that covers a lot of ground, north and south, and we want as non-carbon emitting sources as we can find.”

BPA has announced it will make a preliminary decision on market choice March 6 and a final decision in May.

Seattle Times: Climate, energy upheavals roil Northwest power market

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