NWPPA Morning Brief

NWPPA Morning Brief - Thursday, May 21, 2026

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NWPPA Morning Brief — Thursday, May 21, 2026

In today's brief:

Top Federal Developments

Top Regional / State Developments

Congressional and Federal Agency Scan

AI and Large Load Demand Radar

Worth Knowing

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, NURC's 2026 Summer Reliability Assessment finds the grid better resourced, but warns that demand forecasting is getting harder. PJM accelerates its backstop reliability auction and presses states on data center cost rules. CAISO's board approves a $6.7 billion transmission plan for 45 gigawatts of new solar. California zeroes out its flagship demand response program. Denver imposes a one-year moratorium on new data center permits, and house appropriators advance the FY 2027 Energy Water Bill with funding levels set for WAPA and the Army Corps Hydropower System. 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.

SPEAKER_00

The story I want to flag immediately is NURC's summer assessment. Not because the reliability picture is alarming, it isn't, but because NURC is now formally saying that data center interconnection delays are degrading the quality of demand forecasts across the bulk power system. That is a system-level admission that the load inputs driving reserve margins and capacity procurement are less reliable than they were. For public power resource planners, that uncertainty doesn't stay abstract for long.

SPEAKER_01

And it compounds what utilities are already navigating on their own service territories. When NURC says this is a recognized reliability concern at the system level, that changes the conversation with your board about planning assumptions.

SPEAKER_00

Let's start with the NURC Summer Outlook in full. Nurk released its 2026 Summer Reliability Assessment on May 19. The headline is genuinely better than last year. More than 58 gigawatts of new summer capacity has been added, including 16 Gigawatts of solar, 15 Gigawatts of storage, and 7 Gigawatts of gas. Nurk narrowed the list of areas at elevated shortfall risk from 6 last year to 4. On paper, summer adequacy looks workable for most of the Western footprint.

SPEAKER_01

But the caveat is real. Nurk flagged that shoulder season risk is rising as conventional generation retirements continue, and that the demand forecast inputs utilities rely on, for reserve margins, capacity purchases, bilateral contracts, are getting noisier because of data center interconnection slippage. That gap between requested load and realized load is now a system level concern. Resource planners should factor that uncertainty into their next IRP cycle, not just into summer ops.

SPEAKER_00

Turning to PJM, the PJM board announced May 19th it will move a backstop reliability auction to September rather than March, citing rising data center demand and near-term reliability concerns. More pointedly, the board sent a letter to member states urging them to immediately establish frameworks that assign auction costs to new data center loads rather than spreading them across residential and existing customers.

SPEAKER_01

PJM is outside our footprint, but the cost allocation question is identical to what Western utilities and state commissions are working through right now on large load tariff design. The PJM letter essentially puts the political responsibility on states. You write the rules, or your existing customers absorb the cost. Whether that template lands at CAISO in bilateral WEC arrangements or in BPA's large load policy is the live question. Watch how Western regulators respond to the PJM precedent when their own dockets heat up.

SPEAKER_00

The political deflection angle is real. Telling states to solve it is easier than the grid operator solving it directly. That dynamic will show up in Western proceedings too.

SPEAKER_01

Moving to the KISO transmission plan. The CAISO Board of Governors approved the 2025 through 2026 transmission plan, clearing 38 projects to accommodate 45 gigawatts of new solar and 10 years of load growth. The estimated cost came in at $6.7 billion, down from a $7 billion projection a month earlier. Roughly half the projects are driven by forecasted load growth.

SPEAKER_00

For Western Public Power, the cost allocation mechanics matter as much as the project list. Which customers and utilities bear which share of those approved project costs will shape interconnection economics, congestion patterns, and E Dam dispatch conditions for any utility buying, selling, or wheeling power across the CAISO footprint. If your transmission service obligations touch the ISO, this plan is worth a close read before those cost assignments land.

SPEAKER_01

Next up, California's Demand Response Program. Governor Newsome's budget revision zeroes out funding for the Demand-Side Grid Support Program in 2027 and proposes shifting enrolled customers to the emergency load reduction program. The demand side grid support program dispatched more than 539 megawatts of average output over two hours during organized test events last July. A coalition of clean energy nonprofits and demand response aggregators called the plan detrimental to state energy reliability.

SPEAKER_00

The attribution on that concern is worth noting. That's the advocacy coalition's position, not a settled reliability finding. The real policy question for Western public power is which model the state ultimately backs: utility-run demand response programs or state aggregated ones? California's restructuring is a live test. If the state program model loses budget support even in California, that shifts the weight of the argument toward utility-built programs for the rest of the West.

SPEAKER_01

Shifting to Denver. The Denver City Council approved a one-year moratorium on permits for new data centers, citing the need to develop regulations addressing electricity usage and grid impacts. Denver follows Cheyenne, which adopted a similar pause earlier this month.

SPEAKER_00

The pattern matters. Municipalities are reaching for zoning tools because utility-side interconnection policy and state tariff frameworks haven't kept pace. For public power utilities serving or adjacent to areas weighing similar moves, the practical implication is that interconnection request timelines now depend on local land use decisions as much as on utility studies. That's a new variable in load forecasting, and it isn't going away.

SPEAKER_01

On the capital markets front, LADWP priced a multi-tranche bond sale at coupon rates between 5% and 5.25% across maturities running from 2037 to 2056. With the 10-year Treasury at 4.67%, that spread gives public power CFOs a recent comparable for sizing long-dated infrastructure financing in the current rate environment.

SPEAKER_00

Useful benchmark. The 10-year was at 4.67% on May 19th, up from 4.61%. Front month Henry Hub Natural Gas Futures were trading at $3.06 per million BTU today, down slightly. NYMEX WTI Front Month Futures traded at $101.89 per barrel today, up from $101.67. COMEX Copper settled at $6.25 per pound on May 20th, down from $6.29.

SPEAKER_01

On the appropriations front, the House full committee advanced the FY 2027 Energy and Water Development Bill on May 20, with funding levels set for WAPA and Army Corps hydropower programs. Because BPA is self-financing through ratepayer revenues, the bill doesn't affect BPA directly. But Army Corps and Bureau of Reclamation appropriations in this bill flow through to the federal dams that BPA markets power from. Funding levels for those agencies matter for hydropower system operations and capital programs.

SPEAKER_00

And the same day, the House Appropriations Committee released the FY 2027 Interior, Environment and Related Agencies Bill, with subcommittee markup scheduled for today. Committee leadership framed it around domestic energy production, critical mineral extraction, and public lands access, all of which touch Western utility operations and supply chains. Worth tracking as it moves through markup.

SPEAKER_01

Worth knowing before we wrap. LS Power Grid California broke ground on a combined $2 billion transmission investment in the Bay Area, the Power Santa Clara Valley and Power the South Bay projects, capable of moving 1,000 megawatts across Alameda and Santa Clara counties. The Power Santa Clara Valley segment uses high voltage direct current technology, which is still rare in U.S. transmission build-out.

SPEAKER_00

One of the larger competitive transmission awards in the KISO footprint, it will shape Bay Area delivery capability for the next decade and is another data point on how private capital is positioning around California load growth. For Western public power utilities with KISO delivery exposure, the congestion and dispatch implications of that new capacity are worth modeling as the projects advance.

SPEAKER_01

For the one to watch, I'd put the PJM data center cost allocation letter at the top. Not because PJM's mechanics translate directly, but because it's the first time a major grid operator has formally told states, you own this problem politically. That framing will travel west. Western state commissions and utility regulators who haven't yet moved on large load cost assignment frameworks just got handed a preview of what the pressure looks like when a reliability event forces the question.

SPEAKER_00

The timing accelerates everything. PJM moved its auction to September, that's a compressed timeline, and the September date creates a concrete public example of what it costs to procure capacity for hyperscaler load on an emergency basis. When that number is public, every Western regulator working on large load tariff design will have a price tag to point to. That changes the political calculus faster than any stakeholder process would on its own.

SPEAKER_01

Today's picture comes down to this. The reliability foundation for summer 2026 is stronger than it was, but the planning assumptions underneath it are less solid. Demand forecasting uncertainty, local permitting constraints, and unresolved cost allocation questions are all converging at the same moment. The utilities that get ahead of those variables now are the ones with cleaner decisions in the next rate cycle.

SPEAKER_00

The federal legislative and capital market signals reinforce that the infrastructure build-out is moving. CAISO's transmission plan, the LS Power groundbreaking, the Army Corps' appropriations. The question is whether the governance frameworks for who pays and who decides keep pace. Based on today's brief, they're still running behind.

SPEAKER_01

That's your NWPPA morning brief for Thursday, May 21st, 2026. Sources for every story are linked in the show notes. We'll be back tomorrow morning. Keep the lights on.