XEL · Q3 2025 Earnings

Bullish

Xcel Energy

Reported October 30, 2025

30-second summary

30-second take: Xcel formally refreshed the capital plan to $60B over five years (with $10B+ of additional pipeline behind it), initiated 2026 ongoing EPS guidance at $4.04–$4.16, and reaffirmed 2025 at $3.75–$3.85 — delivering on the supercycle setup management spent last quarter building. Q3 ongoing EPS was $1.24 on revenue of $3.92B (+7.4% YoY), and the Marshall wildfire was settled for ~$640M (covered by ~$500M of insurance). The buried news: the long-term EPS growth objective reverted from "upper half of 6–8%" to a fuller "6–8% plus" range, even as management overlaid an explicit "9% on average through 2030" target — a curious split that frames near-term execution as upside, not commitment.

Headline numbers

EPS

Q3 FY2025

$1.24

Revenue

Q3 FY2025

$3.92B

+7.4% YoY

Operating margin

Q3 FY2025

19.1%

Key financials

Q3 FY2025

Metric	Q3 FY2025	YoY	Q2 FY2025	QoQ
Revenue	$3.92B	+7.4%	$3.29B	+19.1%
EPS	$1.24	—	$0.75	+65.3%
Operating margin	19.1%	—	17.6%	+157bps

Guidance

Xcel Energy reaffirmed 2025 EPS guidance while initiating 2026 guidance at $4.04–$4.16 (5–8% growth), but narrowed long-term growth confidence from 'upper half' to full 6–8% range and withdrew the full-year weather-normalized electric sales growth forecast.

Guidance is issued for the full year only, refreshed each quarter. Prior and new below are the same FY updated this quarter.

New guidance

Metric	Period	Guide	YoY
EPS (FY2026)	FY 2026	$4.04 to $4.16	+5.3% to +8.1%

Changes to prior guidance

Metric	Period	Prior guide	New guide	Δ	Result
Long-term EPS growth	FY 2025	Upper half of 6% to 8% range	6% to 8% plus	Narrowed from 'upper half' guidance to full range	Lowered
Weather-normalized electric sales growth (FY2025)	FY 2025	3% for full year	Withdrawn — no replacement	—	Withdrawn

Reaffirmed unchanged this quarter: EPS (FY2025) ($3.75 to $3.85)

Segment KPIs

Q3 FY2025

Segment	Q3 FY2025	YoY
Electric Revenue	$3.638B	+7.2%
Natural Gas Revenue	$0.264B	+10.5%

Other KPIs

Q3 FY2025

Segment	Q3 FY2025
Weather-Normalized Electric Retail Sales Growth (Q3)	2.2%
Weather-Normalized Firm Natural Gas Sales Growth (Q3)	1.2%
Weather-Normalized Electric Residential Sales Growth (Q3)	3.3%
Weather-Normalized Electric C&I Sales Growth (Q3)	1.9%
Operating Margin (Q3)	19.12%
Net Operating Margin (Q3)	13.38%
2025 Ongoing EPS Guidance	$3.75–$3.85
2026 Ongoing EPS Guidance	$4.04–$4.16

Management tone

Q4 2024 anchor (estimated): Defined $45B plan → Q2 2025: $15B likely incremental → Q3 2025: $60B base + $10B+ pipeline + 9% path → forward: Execution and financing.

The capex framework converted from "likely" to formal, and the pipeline behind it grew. Last quarter management signaled "$15B likely" on top of the $45B base, framing the Q3 print as the disclosure event. They delivered: $60B base — slightly above the $45B + $15B math — with an additional $10B+ pipeline from RFPs and transmission that management explicitly expects to capture half of. The framing of competitive wins ("$10 billion plus sitting in that pipeline") is more aggressive than typical utility positioning.

Data center load shifted from the headline to one input among several. Last quarter the story was 1.1 GW contracted, 2.5 GW by 2030, 7+ GW tier-two pipeline — a data-center-centric narrative. This quarter management explicitly de-emphasized concentration: "having the diversification, it's not all data centers. Only three of that 5% is data centers." Oil and gas electrification at SPS adds 1.5%; residential electrification adds 0.5%. The implication is that load growth is durable even if hyperscaler capex moderates — a hedge management did not need to build last quarter but is building now.

Supply chain positioning escalated from defensive to competitive moat. In Q2 management cited 19 turbine reservation slots as protection against tightness. This quarter the language is sharper: "we have access to inventory and supplies maybe that others don't have...we've taken a very progressive shift in how we work with our vendors...backward integrate them into our capital plan." This is unusual positioning for a regulated utility — supply chain as competitive advantage rather than execution risk.

Long-term growth confidence quietly softened. Q2 reaffirmed "upper half of 6–8%." Q3 reverts to "6–8% plus" while adding a "9% on average through 2030" overlay. The 9% number is the headline, but the institutional floor moved lower. Read alongside the ~200bps gap between 11% rate base growth and 9% EPS growth that DeBrisi flagged in Q&A — driven by financing drag during the build phase — and the message is: execution risk is real, but management is willing to commit to the upper number as a path while preserving the lower number as a floor.

Marshall closed. Q2 had the trial as a live overhang; Q3 closes it for ~$640M ($290M charged this quarter + $50M additional + $360M previously committed) against $500M of insurance, leaving roughly $140M of net exposure absorbed. Tone moved to "AI-enabled tools" and forward risk mitigation rather than litigation defense.

Recurring themes management leaned on this quarter:

Elevated capex growth (11% rate-base growth) with defined visibility and customer valueData center load contracting and scaling as material earnings driver across geographiesTax credit acceleration via near-term renewable procurement to capture 2030 cliffSupply chain advantage via vendor relationships and progressive equipment securingMarshall wildfire settlement closure enabling forward focus on risk mitigation and AI-enabled toolsDiversified sales growth (5%+) beyond data centers: oil/gas electrification, residential, customer growth

Risks management surfaced:

Marshall wildfire settlement at $290M charge plus estimated $50M additional liability on top of $360M committed (vs $500M insurance coverage)Financing costs pressure on near-term earnings due to elevated capex timing before rate base offsetsSupply chain elongation on turbines (4-year lead) and main power transformers creating execution riskTax credit policy risk and cliff expiration in 2030 driving acceleration urgencyData center load timing uncertainty and potential tariff/supply chain disruptions

Q&A highlights

Sophie Karp · KeyBank

Concerns about electrification trends in the Permian Basin given current oil price levels, and clarification on why the company is accelerating renewables with tax credits rather than pursuing more gas generation like peers to firm up the system for data center demand.

Management emphasized that Permian properties remain in-the-money even with oil price fluctuations due to being the lowest cost resource globally. On generation mix, management highlighted geographic advantages for wind and solar, while also noting plans to add 4.5 GW of natural gas and over 5 GW of energy storage over five years to firm the system while maintaining affordability, reliability, and sustainability.

4.5 GW of natural gas capability coming in next five yearsOver 5 GW of energy storage plannedPermian remains lowest cost resource for customers globallyContinuing to invest in wind and solar leveraging tax credits

Stephen DeBrisi · RBC Capital Markets

Questioned the implied significant compression in earned ROEs given 20%+ rate base growth but only 9% EPS growth guidance, and whether management has embedded conservatism in ROE assumptions.

Management clarified that 9% earnings growth versus 11% rate-based growth represents expected ~200 basis point delta typical in high-growth periods due to financing needs. Management stated they do not expect material ROE compression, have conservative ROEs in the plan, and financing is lined up with capex spend. Emphasized that regular rate case proceedings over the next couple years will help catch up rate-based EPS growth.

11% rate-based growth expected9% earnings growth guidance~200 basis point delta between rate-based and earnings growth expected over five-year periodConservative ROEs embedded in plan

Travis Miller Clay · Morningstar

Detailed questions on transmission spend attribution: how much is directly paid by specific customers (e.g., data centers) versus allocated to residential/commercial ratepayers, and what share of transmission demand is driven by customer-specific laterals versus regional builds.

Management explained that data centers pay 100% for new lateral transmission lines required for their interconnection, which are tracked separately and not included in net rate base spend. Regional and super-regional transmission (connecting MISO/SPP, long-range planning, STP buildout) is regionally cost-allocated and not fully attributed to retail rates. Customer-specific lateral demand varies based on system impact studies and is difficult to quantify in general terms.

Data centers pay 100% for lateral transmission lines requiredLateral costs tracked separately, not in net rate base spendRegional transmission cost-allocated, not fully attributed to retail ratesCustomer-specific build requirements determined by system impact studies

Alexia Kania · BTIG

Inquiry on regulatory communications regarding rate trends expectations over the five-year plan period, particularly the balance between revenue requirements, volume growth, and bill affordability.

Management emphasized balancing affordability with reliability, sustainability, resiliency, and safety. Stated they maintain regular dialogue with regulators and legislators to ensure recognition of system investments while keeping bills affordable. Referenced strong stewardship track record over the past decade and commitment to prudent, focused approach to delivering needed system capabilities at affordable prices.

Affordability positioned as core to daily operationsStrong track record as steward of customer money over last decadeEngagement with state regulators and legislators ongoingFocus on balancing multiple policy objectives: reliability, sustainability, resiliency, safety

Answers to last quarter's watch list

Q3 FY2025 five-year capex refresh. Delivered: $60B base plan over five years (slightly above the $45B + $15B math signaled in Q2) plus an explicit $10B+ pipeline of RFP and transmission opportunities management expects to capture roughly half of. The long-term EPS growth bracket did not get pushed up to a higher base — instead, management kept "6–8% plus" as the institutional floor and added "9% on average through 2030" as the path. Status: Resolved positively on the capex dollar amount, Resolved negatively on the long-term growth bracket.

Data center signings. Base plan raised to ~3 GW (vs. 2 GW prior), with management stating the remaining ~0.9 GW of the original 2 GW will be contracted by year-end. On pace with the Q2 "+1 GW by year-end" commitment, though final signings are still pending. Status: Continue monitoring through Q4 close.

Marshall trial outcome. Settled. ~$290M charge this quarter, ~$50M additional estimated liability, $360M previously committed, $500M insurance coverage — net P&L absorption manageable and the litigation overhang is gone. Status: Resolved positively.

Weather-normalized electric sales. Q3 standalone +2.2%, decelerating from Q2's +3.5%. The ~3% FY guide was withdrawn rather than reaffirmed or revised. The deceleration plus the withdrawal is the soft spot in this print. Status: Resolved negatively.

Equity issuance signaling. The press release does not detail an updated equity financing plan; without the transcript, the financing mechanics behind a $60B + $10B+ program are not yet visible. Management's framing of a ~200bps gap between rate base and EPS growth implicitly acknowledges meaningful equity needs. Status: Continue monitoring.

What to watch into next quarter

Whether the long-term growth bracket gets re-tightened back to "upper half of 6–8%." The Q3 revert to "6–8% plus" with a "9% on average" overlay is the kind of split framing that rarely persists — management either commits to the upper number or the floor matters. The Q4 print is the next test.

Year-end data center contracting close. Management committed to contracting the remainder of the original 2 GW base plan by year-end. A clean close validates the pipeline; any slippage or counterparty change reframes the load thesis.

FY2026 weather-normalized electric sales disclosure. The FY2025 ~3% guide was withdrawn after Q3 ran +2.2%. Watch whether management reintroduces a quantitative sales-growth forecast for 2026 or keeps the disclosure withdrawn — the latter would signal lower forward visibility on demand.

Equity financing plan disclosure. $60B + $10B pipeline is not financeable on the current capital structure without meaningful equity. The Q4 call or 2026 outlook deck should detail the issuance cadence; silence on financing is itself a signal.

Pipeline conversion from $10B+ to plan. Management said they expect to win "about half of that plus transmission." Watch for RFP awards and certificate-of-need decisions in H1 FY2026 that move dollars from pipeline into the base plan.

Sources

Xcel Energy Q3 FY2025 earnings release: https://www.sec.gov/Archives/edgar/data/72903/000007290325000254/xcelearningsreleaseq32025.htm
Xcel Energy Q2 FY2025 Tapebrief (prior-quarter context).

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