Treasury yields and the S&P 500 Utilities selloff

Review period: January 1, 2022–September 24, 2026 Scope: The September 2026 utilities selloff, its reported 52-week low, interest-rate transmission, sector fundamentals, and historical comparisons. Source policy: Prioritize Treasury and EIA data, fund and company disclosures, and original industry research; use independent market reporting for contemporaneous context.

Executive summary

Higher Treasury yields are the strongest evidenced explanation for the broad, recent repricing of utilities, but not a measurable percentage of its cause. From August 24 to September 24, 2026, the 10-year Treasury yield rose 48 basis points, from 4.70% to 5.18%. Over those dates, the Utilities Select Sector SPDR ETF (XLU) reportedly fell from $43.22 to $39.36, approximately 8.9%, with the latter close reported as a new 52-week low. XLU tracks a utilities-sector index drawn from the S&P 500; its quoted low is not, by itself, verification that the separately calculated S&P 500 Utilities Index set an identical low. The latest verified fund close and Treasury observation used here are for September 24, not a completed September 25 trading session. (home.treasury.gov)

The timing, breadth and economics favor a substantial common rate effect: investors can earn more from Treasuries, future utility cash flows face a higher discount rate, and exceptionally large construction programs make new financing more consequential. Yet stronger forecast electricity demand and NextEra Energy’s maintained earnings guidance contradict an explanation based on collapsing sector-wide operating prospects. Regulation, financing needs, fuel exposure, project execution and company-specific guidance determine which utilities suffer most. Co-movement is not a causal decomposition: the available evidence cannot responsibly assign, for example, 70% of the decline to yields and 30% to fundamentals. (ssga.com)

What changed—and how much can be attributed?

Relative-contribution judgment: Rates plausibly explain the direction and much of the common movement over this month: the yield jump was contemporaneous, the income trade-off deteriorated, and other income-sensitive shares were also pressured as bond yields rose. Fundamentals appear more important for the size, persistence and differences among companies than for initiating a synchronized selloff. This is a qualitative ranking, not an estimated return attribution. A defensible numerical split would require matched daily index and constituent returns, yield changes, market controls and company-event data—then would still face the problem that higher rates interact with capex and regulation rather than forming an independent cause. (freemalaysiatoday.com)

Why utilities respond to yields

1. Dividend attractiveness and valuation. Regulated utilities are often purchased for relatively stable distributions. A higher risk-free yield competes directly for income-oriented capital and raises the required return on future dividends. State Street put the portfolio’s September 24 forward P/E at 16.45 and estimated three-to-five-year EPS growth at 9.24%: the holdings have a growth case, but that case must clear a more demanding return hurdle. Neither the earnings yield implied by the P/E nor the difference between dividend and Treasury yields should be mislabeled an equity risk premium. (ssga.com)
2. Debt and refinancing. Existing fixed-rate debt does not reprice immediately. Floating-rate borrowings, maturing debt and new bonds issued to build generation and grids do. Illustratively, refinancing $10 billion at a rate 50 bp higher adds $50 million a year in pretax interest, before any regulatory recovery or hedging. Consequently, near-term reported interest expense need not move in lockstep with a one-month Treasury jump; the greater concern can be future funding and the value of the equity claim. S&P Global’s Regulatory Research Associates (RRA) forecasts $259.1 billion of 2026 investment among the energy utilities it tracks and $1.295 trillion across 2026–2030. Those are industry forecasts, not spending already incurred. (spglobal.com)
3. The regulatory lag. A regulated utility may eventually recover prudent investment and financing costs through approved rates, but the timing, authorized return and amount are not automatic. Affordability limits the room for rate increases: RRA reports $22.06 billion of utility rate increases requested in 2025 and says Florida regulators approved about $1.65 billion of Florida Power & Light’s $2.472 billion multiyear 2026–2027 request. That decision illustrates a persistent constraint; it should not be presented as a new September 2026 selloff catalyst. Constructive recovery mechanisms can conversely cushion higher debt costs. (spglobal.com)

Fundamentals: support, risks and differences across companies

Electricity demand is a counterweight, not an immediate cure. The Energy Information Administration (EIA) forecasts record U.S. electricity sales of 4,135 billion kWh in 2026, nearly 2% above 2025, and further growth in 2027; it expects commercial sales to rise 3.3% in 2026, partly because of data centers. More load can ultimately support rate-base growth and contracted generation earnings. But utilities must fund construction before all revenues arrive, and large-load projections depend on actual connections, contracts and regulatory treatment. EIA notes a Texas pause on new data-center grid connections pending an audit—one illustration of execution risk. (eia.gov)

Fuel and power prices cut both ways. For a conventional regulated utility, purchased-power and fuel costs may be substantially recoverable through tariffs, though timing can affect cash needs and customer bills. A competitive generator instead may benefit from higher wholesale power prices if its output is contracted favorably—or suffer if it must buy costly fuel or replacement power. Rising oil prices alongside Treasury yields in late September added a macro inflation concern, but oil is not a reliable stand-in for every U.S. utility’s natural-gas expense. Indeed, EIA’s September forecast put average Henry Hub gas at $3.43 per million Btu in 2026, below $3.53 in 2025; EIA also forecast residential electricity prices rising from 17.3 to 18.2 cents/kWh, highlighting affordability pressure despite the softer annual gas forecast. None of these aggregates establishes a sector-wide September earnings downgrade. (freemalaysiatoday.com)

Renewables and company guidance are heterogeneous. Wind, solar and storage development can require substantial up-front capital and therefore be particularly sensitive to financing terms, construction costs, tax incentives and project delays. But renewable exposure is not synonymous with weak demand or weak earnings. NextEra Energy reported 3.6 GW of new renewables-and-storage backlog additions in the second quarter of 2026, 9.5% year-over-year growth in adjusted quarterly EPS, and unchanged 2026 adjusted-EPS guidance of $3.92–$4.02. It also projected $12 billion–$13 billion of 2026 investment at Florida Power & Light. Its outlook explicitly assumes, among other things, reasonably priced capital, supportive policy and satisfactory rate-case outcomes. These are management expectations—not guaranteed results—but they argue against claiming a contemporaneous, general collapse in earnings guidance. (investor.nexteraenergy.com)

Nor is every S&P 500 utility a dividend-focused regulated electric company: State Street lists NextEra, Southern, Duke and Constellation among XLU’s largest positions and includes independent power and renewable-electricity producers alongside regulated-utility industries. Company news, merchant-power exposure and concentration can therefore move the index even if interest rates are unchanged. NextEra and Dominion’s proposed combination, still subject to approvals, is one example of material company-specific regulatory and financing considerations during this episode—not evidence that the merger caused the sector’s decline. (ssga.com)

Historical tests of the bond-yield explanation

The 2023 Federal Reserve study also finds that models disagree about how much of that earlier yield surge came from expected policy rates versus term premiums. Thus, even when yields clearly matter, the source of the rate change—and accompanying economic news—matters to the equity interpretation. (federalreserve.gov)

Verdict and limits

Supports “yields are primary”: a pronounced 48-bp monthly rise, almost matched by the rise in real yields; an approximately 8.9% contemporaneous XLU fall; a roughly 213-bp Treasury advantage over XLU’s then-published distribution yield; and record prospective capital needs. Contradicts “yields are the whole story”: forecast record electricity use, maintained guidance at a major holding, materially different regulatory and merchant exposures, and historical periods when utilities rose despite rising rates. The most defensible conclusion is rates as the leading common near-term pressure, with fundamentals and regulatory outcomes governing how much of that pressure becomes lasting earnings damage. The cited price correspondence and examples cannot establish a precise causal share—or independently verify an identical 52-week low for the S&P 500 Utilities index rather than its XLU proxy. (home.treasury.gov)

Sources

• U.S. Treasury: daily nominal and real Treasury yield observations for August–September 2026. (home.treasury.gov)
• State Street Global Advisors: XLU’s September 2026 price, yields, portfolio composition and valuation characteristics. (ssga.com)
• U.S. EIA: September 2026 electricity and natural-gas outlooks. (eia.gov)
• NextEra Energy: July 24, 2026, second-quarter results and management outlook. (investor.nexteraenergy.com)
• S&P Global RRA and Federal Reserve: original utility-capex and rate-case research; analysis of the 2023 Treasury surge. (spglobal.com)
• Market and historical cross-checks: EBC’s reported XLU 52-week low, S&P Global’s historical sector reporting, and Gabelli’s first-quarter 2026 sector review. (ebc.com)