NWPPA Morning Brief

NWPPA Morning Brief - Friday, May 29, 2026

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NWPPA Morning Brief — Friday, May 29, 2026

In today's brief:

Top Federal Developments

Top Regional / State Developments

Western Federal Power Programs Scan

AI and Large Load Demand Radar

Advocacy and Legal Signal Scan

Pilot notice: AI-generated daily briefing. Verify before acting on it.

Feel free to reach out if you have comments or concerns.

SPEAKER_01

Before we begin, a quick note. The NWPPA morning brief is Generative AI, daily intelligence on the federal and Western developments shaping public power. It isn't human-reviewed before publication, so treat it like any AI tool and verify what you'll act on or cite. Sources are in the show notes. You're listening to the NWPPA morning brief. On today's brief, Oregon regulators approve a landmark large load tariff framework for data centers. NERC issues a rare level three alert on computational load drops. Yakima Nation and Columbia Riverkeeper challenge a FERC hydroelectric license in the Ninth Circuit. Rocky Mountain Power warns Utah customers of summer outages and possible shutoffs. BPA releases its 2026 wildfire mitigation plan and more from across the West. Today's briefing is brought to you by the Northwest Public Power Association. Stronger workforce, greater influence, informed decisions, serving community-owned electric utilities across the West since 1940.

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The Oregon PUC's approval of Portland General Electric's large load tariff is the story with the longest reach today. It's the first concrete implementation of Oregon's 2025 Power Act, and it hands every other Western state a working template for cost allocation on hyperscale loads. The question public power utilities need to answer quickly is whether those terms, customer-funded upgrades, long-duration contracts, minimum demand floors, translate to consumer-owned rate structures without modification.

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And the NURC level 3 alert pairs directly with that story. Planning models that can't distinguish firm load from flexible load at sub-second through multi-year horizons are now an interconnection bottleneck. These two developments together reshape what it means to say yes to a hyperscale customer.

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Let's start with the NURC Alert. Nurk issued a level 3 Essential Actions Alert, its highest engagement notice short of a mandatory standard, after multiple events in which more than 1,000 megawatts of computational load dropped off the bulk power system within seconds, causing major grid stability problems. The paired reliability guideline requires transmission operators, balancing authorities, and planners to build long-term resource adequacy models that distinguish firm load from flexible load, capture behind-the-meter resources, and account for AI training operating windows. For public power utilities being approached by hyperscale customers, interconnection studies are now on the critical path. If a balancing authority can't model these loads across the full time horizon, projects stall before they start.

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The practical pressure here is on planning departments that may not have the modeling tools or contract language to handle sub-second load swings at gigawatt scale. Existing ride-through requirements and interconnection study assumptions were built for a different customer profile. Whether current planning cycles and contract templates are adequate before the next interconnection window is the right question to be asking right now.

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Turning to the Ninth Circuit, the Yakima Nation and Columbia Riverkeeper have each filed petitions challenging FERC's issuance of a hydroelectric project license. Ninth Circuit rulings on license conditions, tribal consultation, and environmental review set the template for what other regional licensees can expect on their own relicenses. The key variable is whether these petitions raise process arguments specific to this project or broader claims about FERC's treatment of tribal trust obligations and downstream effects.

SPEAKER_01

The broader claim scenario is the one to watch. A ruling that expands what FERC must demonstrate on tribal consultation or downstream environmental effects lands on every Columbia Basin relicensing now in queue. Public power utilities with projects moving toward license renewal need to be tracking the scope of these petitions closely, not just the outcome.

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Shifting to Oregon, the Oregon PUC approved Portland General Electric's Schedule 96 on May 7th, taking effect June 10th. Data centers above 20 megawatts must sign longer duration contracts, pay 100% of distribution network upgrades their projects require, and accept minimum demand charges set at 90% of contracted system capacity. It's directly tied to Oregon's emissions and clean energy requirements, so large load interconnection approvals now carry a clean energy linkage.

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This is the most concrete Western model yet for keeping hyperscale load growth from shifting costs onto existing ratepayers. For consumer-owned utilities, the structure may need adaptation. The rate design mechanisms available to a cooperative or PUD aren't identical to a large IOU's, but the policy logic is directly transferable. Any public power utility currently in conversations with a data center customer should have someone reviewing Schedule 96 before those conversations advance.

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Next up, Rocky Mountain Power. The utility is warning Utah customers to expect longer or more frequent outages this summer. Governor Cox has declared a statewide drought emergency. Every Utah County is in severe or extreme drought after snowpack peaked March 9th at a record low 8.4 inches of snow water equivalent. Rocky Mountain Power said it may use enhanced safety settings that cut power within fractions of a second when interference is detected, and in extreme conditions, proactive public safety power shutoffs.

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The customer-facing communication is what matters most for neighboring public power utilities. Rocky Mountain Power is formally resetting restoration time expectations and putting proactive de-energization on the table. That's a script regulators and insurers in high fire risk territory may start asking other Western utilities to match, whether they're ready to or not. Utilities serving fire prone areas should be reviewing their own customer communication and de-energization protocols now, not after the first red flag day.

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Moving to BPA, the Bonneville Power Administration released its 2026 Wildfire Mitigation Plan, outlining vegetation management, equipment hardening, and operational protocols during high-risk periods across the federal transmission system. For preference customers, depending on BPA transmission to wheel federal hydropower, those protocols translate directly into reliability and outage expectations.

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With Utah already in extreme drought and fire season arriving early across the West, the timing is tight. Preference customers should understand what BPA's high-risk operational posture looks like in practice, particularly what automatic protective actions could mean for delivery schedules during peak summer months.

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Over to the Idaho Power and Oregon Trail Electric Story. Idaho Power and Oregon Trail Electric Cooperative have filed with the Oregon PUC to transfer Idaho Power's Oregon distribution system to the cooperative in a deal valued at $154 million. The transaction would consolidate Eastern Oregon Distribution Service under a single cooperative provider.

SPEAKER_01

The valuation methodology and the regulatory path through Oregon PUC review are the reference points worth tracking here. Future territory transfers, IOU to cooperative or IOU to public power utility, will look to this proceeding for how the math gets done and how long the process takes. That's useful intelligence whether or not your utility is actively pursuing a transfer.

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On the clean energy front in Utah, about 300,000 Utah homes and businesses across more than a dozen communities are set to participate in the Utah Renewable Communities Initiative, a community aggregation program that lets local governments offset electricity use with 100% renewable power backed by a $4 monthly bill surcharge. Midvale votes Tuesday ahead of next week's enrollment deadline.

SPEAKER_01

The community aggregation model is worth watching as a mechanism where local governments procure clean energy attributes independently of the host IOU's resource plan. For public power utilities, it's a reminder that communities will find paths to clean energy procurement even when the incumbent utility isn't moving at the pace local governments want.

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Turning to nuclear. Fulcrum Point Holdings and Blue Castle Holdings announced a partnership to revive a nearly two-decade-old nuclear project in Green River, Utah, now envisioning small modular reactors at the site. That adds to Utah's emerging nuclear portfolio, alongside the previously announced Brigham City SMR initiative.

SPEAKER_01

Two SMR announcements in Utah in close succession signals genuine developer interest in the state as a nuclear-friendly jurisdiction. The gap between announcement and operation is still very wide for SMR projects. But for public power utilities thinking about long-term baseload, the Utah pipeline is worth watching as a leading indicator of where Western SMR development is concentrating.

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Shifting to California, the California Senate passed SB 913, which would create a competitive pathway for customer-owned resources, home batteries, electric vehicles, smart thermostats, to bid against peaker plants and other traditional grid resources for reliability services at lowest cost. Senator Becker's statement cites CPUC data showing more than 8,000 customer batteries totaling over 100 megawatts installed each month in California.

SPEAKER_01

If enacted, this is a design reference for bring-your-own device and demand-side aggregation programs anywhere in the West. The policy question for public power utilities is whether their tariff structures and operational systems can actually settle bids from distributed customer resources against traditional capacity. That's not a trivial integration challenge.

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On energy pricing, Front Month Henry Hub Natural Gas Futures were trading at $3.37 per million BTU on May 29th, up from $3.08. NIMEX WTI Front Month Futures traded at $87.32 per barrel, down from $90.85.

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On the capital side, the 10-year Treasury yield was 4.48% on May 27th, down fractionally from 4.50%. COMEX Copper settled at $6.40 per pound on May 28th, flat from the prior reading.

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The PUD has begun construction on its crosswind transmission line to support existing and future system loads and facilitate a new battery storage project. The project reflects the load growth plus storage build pattern becoming standard across Washington PUDs. Transmission capacity sized to integrate utility-scale batteries while relieving existing infrastructure loading simultaneously.

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Building transmission and storage integration in parallel rather than sequentially is the approach utilities with growing load profiles need to be taking. Waiting for load to arrive before scoping transmission is a position utilities are increasingly finding themselves unable to afford.

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More than double the projects announced in all of 2025, as developers raced ahead of federal clean energy tax credit phase-outs. At the same time, nearly 8 gigawatts and over $14 billion in planned investment were canceled, closed, or downsized through March, already more than half of all 2025 generation losses.

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The announced pipeline is surging, but a meaningful share is expected to fall out before commercial operation. For public power utilities scoping power purchase agreements or merchant capacity additions, the distribution of project completion risk is wider than the headline numbers suggest. Counterparty diligence on any new PPA matters more right now than it did a year ago.

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The California EV charging story is brief but operationally relevant. The California Energy Commission announced $55.2 million through the Fast Charge California program, with two upcoming incentive windows offering up to 100% of installation costs, up to $100,000 per port in the October 2026 through January 2027 window, and up to $55,000 per port in the February through May 2027 window for chargers with minimum 150 kilowatt output.

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California distribution utilities planning around fast charger load additions now have a concrete incentive schedule to work with. The load impact of high-density fast charging corridors is the distribution planning variable worth sizing carefully before those installations land.

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Worth knowing before we close. ERCOT established a $25 million one-time program on May 26th to incentivize battery storage and other inverter-based resources to adopt grid-forming technology, controls that allow a resource to actively stabilize grid frequency rather than simply follow it, offering $1,500 per megawatt, adjusted by availability factor, payable 12 months after successful implementation. Western system operators and storage developers are likely to study this as a market mechanism.

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DLA Piper's 2026 Wildfire Trends Report is also out, covering inverse condemnation, the legal theory that holds utilities liable for property damage caused by their infrastructure even without negligence. And negligence theories being tested against utilities, including ongoing James v. Pacific core litigation. With fire season opening, that's required reading for Western utility legal and risk teams.

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And SP Global reports midstream pipeline operators are striking direct gas supply deals with data centers pursuing co-located generation as an alternative to waiting and interconnection queues. That bypass the grid pattern carries load forecasting and tariff implications for distribution utilities that have hyperscale projects in their service planning numbers. One to watch.

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BPA's explainer on how federal hydropower is allocated across more than 130 public utilities and cooperatives in the Northwest. The provider of choice and Tier 1 allocation conversations is front of mind for a reason. The Ninth Circuit challenge to a FERC hydro license, the drought conditions driving Rocky Mountain Powers shutoff warnings, the NURC Alert reshaping interconnection modeling, they all converge on the same underlying question. How much firm hydro will be available? To whom, under what conditions, and at what cost as the West tightens?

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The allocation framework was designed for a different load profile and a different risk environment. With hyperscale load growth, early fire seasons, and relicensing pressure all arriving simultaneously, the utilities that understand the mechanics of Tier 1 allocation and where their exposure sits are the ones that will have real options. The ones that don't will be reacting.

SPEAKER_01

Today's brief has a common thread running through it. The planning assumptions that held five years ago are under pressure from multiple directions at once. Federal hydro availability, large load interconnection, wildfire de-energization, project completion risk. The utilities that come out of this period in strong shape are the ones doing the scenario planning now.

SPEAKER_00

Verify what you'll act on. Sources are in the show notes.

SPEAKER_01

That's your NWPPA morning brief for Friday, May 29th, 2026. Sources for every story are linked in the show notes. Have a great weekend. Keep the lights on.