Xcel Energy Q2 2026 EPS rose 24% to $0.93 on infrastructure recovery, a depreciation catch-up and an unrealized investment gain, while revenue fell 5.1% as cheaper fuel was passed through; 2026 guidance of $4.04-$4.16 reaffirmed.
Revenue
$3.1B
-5.1% YoY
Net income
$586M
+32.0% YoY
Diluted EPS
$0.93
+24.0% YoY
Operating margin
22.6%
How XEL compares with Utilities peers
Figure
XEL
Peer median
Rank
Revenue growth (YoY)
-5.1%
+4.3%
24th of 26
Operating margin
22.6%
21.0%
10th of 26
EPS growth (YoY)
+24.0%
+19.7%
6th of 25
Rank 1 = fastest revenue growth, highest operating margin, fastest EPS growth. Peers are the other Utilities companies with a 2026 report on this site, each at its latest period we've analyzed; fiscal calendars differ, so periods are not always the same months.
Xcel Energy's second-quarter 2026 diluted EPS rose 24% to $0.93 from $0.75, and net income rose 32% to $586 million, even though revenue fell 5.1% to $3.12 billion. Both moves have the same main cause. The revenue drop mostly reflects cheaper fuel and purchased power, which Xcel passes straight through to customers. The earnings gain came from customers paying for the grid and generation Xcel has built (the filing calls this "increased recovery of electric infrastructure investments"), helped by a lower depreciation charge, more capitalized financing income and a mark-to-market gain on venture-style investments. Higher interest costs and a larger share count took back part of the gain. Management reaffirmed its 2026 ongoing EPS guidance of $4.04 to $4.16.
At a glance
$5.97 billion of capital spending in the first half, up 35%. Xcel is building faster than ever, and every dollar of approved spending becomes part of the asset base it is allowed to earn a return on. This is the main thing that drives the stock's value.
$1.84 of ongoing EPS in the first half, about 45% of the $4.10 guidance midpoint. The company is on track, but the first half included about $0.10 of weather drag, mostly from a mild winter that cut natural gas demand.
Total debt of $39.5 billion, up from $33.9 billion in December. Borrowing is paying for the build-out. Interest charges rose $94 million in the quarter, and 69.7 million shares (about 11% of the current count) are already contracted for future sale.
Results
Metric
Q2 2026
Q2 2025
YoY Change
Total operating revenues
$3,119M
$3,287M
-5.1%
Electric fuel & purchased power (pass-through cost)
$678M
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Net property, plant & equipment (period end vs. Dec. 31)
$69,497M
$65,639M
+5.9% in 6 months
Weather-normalized retail electric sales growth (quarter)
+1.5%
n/a
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Xcel runs four regulated utilities: PSCo in Colorado, NSP-Minnesota (which also serves North and South Dakota), SPS in Texas and New Mexico, and NSP-Wisconsin (which also serves Michigan). All four earned more per share than a year earlier. Combined, the regulated business rose to $0.95 from $0.81. PSCo added $0.06, NSP-Minnesota $0.05, SPS $0.02 and NSP-Wisconsin $0.01. The holding-company drag shrank to $(0.02) from $(0.06).
Why revenue fell while profit rose
A regulated utility passes its fuel and purchased-power costs through to customers without earning a profit on them. When natural gas and power prices fall, revenue falls by roughly the same amount and earnings barely change. That is most of this quarter's story. Electric fuel and purchased power fell $240 million, "primarily due to lower commodity prices, largely in SPS." Electric revenue fell $138 million. That net figure includes $202 million less in fuel-cost recovery and $41 million more in wind and solar production tax credits passed back to customers.
Pulling in the other direction:
Non-fuel riders added $114 million of electric revenue. A rider is a surcharge regulators approve between full rate cases so the utility can start earning on specific projects, such as transmission or renewables, soon after building them. This is the rate-base growth appearing in the income statement.
Sales and demand added $25 million and wholesale transmission added $29 million.
Rate case outcomes reduced revenue by $36 million. This was mainly because Xcel recorded refunds of interim rates in the Minnesota electric case, since the final award was below the interim level. Per the filing, this revenue loss was "more than offset by corresponding reductions in depreciation expense due to nuclear life extensions approved in the case."
Xcel's EPS bridge shows the net effect for the quarter: lower fuel and purchased power +$0.30, lower electric revenue −$0.18, higher interest charges −$0.12, the larger share count −$0.06, and lower natural gas revenue −$0.04. On the positive side were higher AFUDC +$0.08, lower depreciation +$0.08 and "other, net" +$0.12.
What the headline numbers hide
Some of the gain is timing and accounting, not operations. Four items stand out:
A depreciation catch-up. Depreciation and amortization fell $60 million year over year in the quarter. The filing says this reflects "the recognition of 2025 and 2026 depreciation reductions (nuclear life extensions) in the second quarter of 2026." Regulators agreed Xcel's Minnesota nuclear plants can run longer, which spreads their cost over more years. Xcel booked 18 months of that benefit in a single quarter. It is largely matched by the interim-rate refunds that reduced revenue, so the net effect is smaller than $60 million. Still, Q2's lower depreciation is not a run-rate: for the six months, D&A was only $20 million lower, and full-year guidance still calls for D&A to rise $140 to $150 million.
An unrealized investment gain. Earnings from equity method investments swung to +$76 million from −$8 million. The filing attributes this "primarily" to "unrealized gains on investment funds' interests in energy technology companies." That is a mark-to-market gain on paper, not cash from customers. Before tax, the $84 million swing works out to roughly $0.13 per share, which is most of the "other, net" line and most of why the holding-company drag shrank. Xcel counts it in ongoing EPS, so the guidance range does not exclude it. These gains can reverse.
AFUDC is non-cash income. AFUDC (allowance for funds used during construction) is an accounting credit that lets a utility book a return on money tied up in projects still under construction. Regulators allow Xcel to collect it later. Equity AFUDC rose to $105 million from $69 million, and the debt portion to $45 million from $27 million. It is legitimate, regulator-sanctioned income. It is also earnings with no cash attached today, and it grows as the construction backlog grows. Construction work in progress reached $9.8 billion, up from $8.1 billion in December.
Tax did not help. The effective tax rate was −11.4%, compared with −15.6% a year earlier. Because it was less negative, tax was a small headwind to EPS, not a tailwind. Xcel's negative tax rate comes from wind and solar production tax credits, which are passed through to customers in lower revenue.
Buybacks played no part, and share count worked against EPS. Diluted shares rose 6.6% to 627 million because Xcel is issuing equity to fund its capital plan. Net income grew 32% while EPS grew 24%. The difference is dilution.
Weather was roughly neutral in the quarter but a drag over six months. Q2 weather was about $0.012 per share better than Q2 2025. For the six months it was $0.097 worse, almost all from firm natural gas (−$0.089), after a mild winter cut PSCo's gas sales 21.8%. Minnesota's sales true-up and gas decoupling mechanisms offset much of the weather swing in that state.
Cash conversion looks strong, but for a one-off reason. Operating cash flow for the six months was $2,797 million against net income of $1,142 million. The filing says the $688 million increase was "largely due to insurance reimbursements for the Marshall Wildfire and Smokehouse Creek Fire Complex settlement activity." Capital spending of $5,970 million was more than twice operating cash flow, so the gap was funded with debt: $4.69 billion of new long-term debt and $960 million of net short-term borrowing. Debt reached 62% of total capitalization, up from 59% in December.
GAAP and ongoing EPS were identical this quarter. For the half-year, ongoing EPS of $1.84 excludes two items. One is a $38 million charge for refunds of Prairie Island nuclear outage replacement-power costs (+$0.04 added back). The other is a $19 million credit from higher expected insurance recovery on the Marshall Fire (−$0.02 removed).
Wildfire exposure remains open. Xcel has recorded $503 million of estimated losses and legal costs for the 2024 Smokehouse Creek Fire Complex in Texas. About $80 million of its $525 million insurance cover remains. The filing warns that resolution "could exceed our insurance coverage." At the holding company, Moody's rating (Baa1) is on negative outlook. PSCo is on negative outlook at both Moody's and S&P.
Takeaway: Xcel's 24% EPS gain is real but partly flattered. Most of the underlying growth comes from customers paying for new infrastructure through riders and rate cases. A one-quarter depreciation catch-up and an unrealized gain of about $0.13 per share (pre-tax) on energy-tech fund stakes padded the rest. The more durable signal is the 35% jump in capital spending. That spending drives future earnings, but it is funded by debt that rose $5.6 billion in six months and by equity that will enlarge the share count by about 11%.
The regulatory backdrop: rate base is the engine
A regulated utility's profit is set mainly by its rate base (the value of the assets regulators let it earn a return on), its allowed return on equity (ROE), and how quickly regulators approve new rates. Xcel had several major cases active in the quarter:
Case
Requested
Status / terms
Minnesota electric (NSP-MN)
$365M (rebuttal)
MPUC verbal decision June 2026: ~$211M over two years, ROE 9.60% (from 9.25%), 52.5% equity ratio
Non-unanimous settlement: $38M; MPUC decision expected November 2026
South Dakota electric (NSP-MN)
$44M
Settled at $26M, effective July 1, 2026
Settled amounts range from about 54% to 65% of each original request (58% in Minnesota electric), with allowed ROEs between 9.2% and 9.6%. That is normal for utility regulation, and the settlements reduce uncertainty. Several are opposed by some parties (in Colorado electric, the AARP, the City of Boulder and the state consumer advocate), so final orders can still differ.
Data centers and load growth
The filing adds more detail on large new loads:
Google in Minnesota. In Q1 2026, NSP-Minnesota signed an electric service agreement to power a new Google data center. Under the agreement, Google "will pay all costs for its new service for the duration of the contract," and Xcel estimates about $1.1 billion of benefits to other customers. The request for approval includes a Clean Energy Accelerator Charge covering 1,900 MW of clean resources. An MPUC decision is expected in early 2027.
Large-load tariffs. Minnesota approved a tariff in June 2026 that is mandatory for new loads over 100 MW, with a minimum 15-year term, minimum bills and exit fees. Colorado (loads over 50 MW) and Wisconsin have filed similar tariffs, and New Mexico and Texas filings are expected by the end of 2026. These tariffs aim to make data centers pay their own way, so existing customers do not carry the cost if a project is cancelled.
Resource needs. Colorado regulators approved a load forecast of 3% compound annual sales growth through 2031, with about 5,400 MW of new generation need. SPS's latest preferred portfolio adds 3,928 MW of nameplate capacity (2,623 MW company-owned). NSP's joint RFP seeks up to 3,500 MW.
Actual sales are growing, but more slowly than that pipeline suggests. Weather-normalized retail electric sales rose 1.5% in Q2 and 2.1% over six months, against a full-year guidance assumption of about 3%. Most of the growth came from SPS's commercial and industrial customers (+6.2% year to date, citing "increased activity in the energy sector"). Much of the data-center demand is still contracts and regulatory filings, not metered sales.
Outlook
Management reaffirmed 2026 ongoing EPS guidance of $4.04 to $4.16. The guidance assumes constructive rate case outcomes, normal weather, capital rider revenue up $480 to $490 million, and net interest expense up $240 to $250 million. The long-term objective is 6% to 8%+ annual EPS growth from a $3.80 base, plus 4% to 6% annual dividend increases. The quarterly dividend is $0.5925, up from $0.57.
Our read: the first half puts Xcel in range. Reaching the midpoint needs about $2.26 of EPS in the second half, compared with the $1.84 it booked in the first half. Q3 is typically Xcel's strongest quarter because of summer air-conditioning load, and final Colorado electric rates are expected in Q3. So the target looks achievable, provided the Colorado and New Mexico settlements are approved broadly as filed.
Over the longer term, the constraint is financing, not demand. Capital spending is running more than twice operating cash flow. Debt has risen to 62% of capitalization, and 69.7 million shares (at least $5.2 billion of expected proceeds) are already sold forward. EPS growth now depends on three things: approved ROEs of about 9.2% to 9.6% staying above Xcel's rising cost of borrowing, new equity not diluting faster than rate base grows, and wildfire liabilities staying within reach of insurance. Watch these in Q3:
the CPUC's final Colorado electric order
whether weather-normalized sales growth moves toward the ~3% assumption
any further change in Smokehouse Creek loss estimates