CenterPoint Energy Q3 2026: EPS up 11% to $0.50 on Houston rate recovery; 2026 guidance raised

Overview

CenterPoint Energy's third-quarter 2026 GAAP net income rose 13% to $331 million, or $0.50 per diluted share, from $293 million ($0.45) a year earlier. (GAAP means standard accounting rules, before any company adjustments.) Revenue rose 10.2% to $2,191 million. Almost all of the gain came from the Houston-centred Electric business, whose net income rose $69 million to $362 million as new rates that recover past grid spending kicked in and a hotter summer lifted home electricity use.

The headline growth rate hides two things pulling in opposite directions. Pre-tax income jumped 44%, but a one-time tax benefit in the third quarter of 2025 made last year's profit look higher than it really was, so net income grew far less. And the company's own adjusted figure (non-GAAP EPS, which strips out items management considers unusual) rose only 6%, to $0.53 from $0.50, because last year's adjusted number also included that tax benefit.

In its October 27 earnings release (Form 8-K, Exhibit 99.1), CenterPoint raised 2026 non-GAAP EPS guidance to $1.90–$1.92, gave a first 2027 range of $2.07–$2.09, and lifted its 10-year capital plan by $4.0 billion to $70.7 billion.

CenterPoint Energy, Inc. files one combined 10-Q with its two main subsidiaries, CenterPoint Energy Houston Electric and CERC (the gas business). All figures below are for CenterPoint Energy, Inc. as a whole unless stated otherwise.

Key metrics

Operating margin is the share of revenue left after running the business (fuel, operations and maintenance, depreciation, and non-income taxes), before interest and income tax. The company has no preferred stock, so all net income belongs to common shareholders.

First nine months: revenues were $7,318M, up 6.8% from $6,852M. Net income was $891M, up 13.1% from $788M, and diluted EPS was $1.34, up from $1.20 (+11.7%). Non-GAAP EPS for the nine months was $1.49.

What drove the quarter

Electric: rate recovery and a hot summer

Electric segment revenue rose $184M to $1,549M. The 10-Q breaks that increase into these pieces:

• Customer rates and rate design: +$54M. New rates recover investment Houston Electric has already made in its grid. The latest distribution rate increase (DCRF, a mechanism that lets the utility recover new distribution spending between full rate cases) took effect on September 1, so only one month of it is in this quarter.
• Transmission revenues: +$37M, partly offset by $22M of higher transmission costs billed by other providers.
• Weather and usage: +$23M. Cooling degree days (a measure of how much air-conditioning the heat demanded) were 112% of normal, against 103% a year earlier. Residential deliveries rose 10%, though total deliveries rose only 1%.
• Customer growth: +$7M, with 2% more metered customers.
• Bond Companies and SIGECO Securitization Subsidiary: +$76M. These are charges on customer bills that repay storm-cost bonds. They are offset by $57M of extra amortization, $17M of extra securitization interest and $2M of O&M, so they add essentially no profit.

So about two-fifths of the Electric revenue increase is money collected and paid straight back out. Electric operating income rose 32% to $586M; after interest expense, which rose $43M to $159M, pre-tax income rose $104M to $453M. Electric's tax rate also rose (Houston Electric's went from 18% to 21%, mainly higher state income taxes), so net income rose 24% rather than 30%.

Two smaller depreciation items helped: amortization of regulatory assets (costs regulators approved for recovery, expensed over time) was $39M lower. Lease costs for TEEEF units (large temporary emergency generators) that can no longer be deferred for later recovery cost only $2M more than a year earlier, after $34M in the first half; the company's non-GAAP figure excludes $19M after tax of TEEEF costs this quarter.

Natural Gas: higher pre-tax profit, lower net income

Natural Gas segment revenue rose $19M to $641M. Higher customer rates added $29M; lower gas prices cut revenue by $20M, but gas costs fell by the same amount, so that is a pass-through. Operation and maintenance fell $9M, mainly lower labor and corporate support costs, while depreciation rose $20M as new pipe went into service.

Pre-tax income nearly tripled, from $17M to $49M. Yet segment net income fell $27M to $44M, because Q3 2025 booked a $54M tax benefit in this segment against $5M of tax expense this year. CERC's effective tax rate was −222% a year ago and 11% now. The 10-Q attributes the difference mainly to "the prior year remeasurement of state deferred taxes in the third quarter of 2025."

Corporate: slightly bigger loss

The Corporate and Other loss widened from $71M to $75M. The 10-Q puts this mainly down to a $6M increase in borrowing costs and an unfavourable net swing on CenterPoint's ZENS notes (exchangeable notes valued against shares of AT&T, Charter and Warner Bros. Discovery it holds). The ZENS-related lines netted to −$3M pre-tax this quarter (a $21M gain on the shares, a $24M loss on the notes) against +$1M a year earlier, and the company excludes them from non-GAAP EPS.

What the headline numbers hide

• The tax comparison is harsh. Company-wide pre-tax income rose 44% ($413M vs $286M), but the effective tax rate went from −2% to 20%. The release says the absence of last year's "one-time tax optimization benefit" cost $0.05 per share this quarter. By our arithmetic, at this year's 20% rate last year's $286M of pre-tax income would have left about $229M of net income, so on a like-for-like tax basis net income grew far faster than the reported 13%.
• Adjusted EPS grew less than GAAP EPS. Non-GAAP EPS of $0.53 adds back ZENS swings (net +$0.00), merger and divestiture costs ($0.00) and TEEEF costs no longer in rates ($0.03). Q3 2025's $0.50 included the tax benefit, which is why the adjusted figure grew only 6%. The company's own bridge: rate recovery and growth +$0.09, weather and usage +$0.03, O&M flat, financing −$0.04, other items (mainly the tax benefit) −$0.05.
• Weather helped. The $0.03 from weather and usage will not repeat in a normal summer. It partly offsets the tax drag above.
• Cash flow is fine, but spending far outruns it. Nine-month operating cash flow was $2,051M against net income of $891M (depreciation of $1,312M is a non-cash charge, which is normal for a utility). Capital expenditure was $4,170M, so the gap is funded with debt, equity and asset sales: long-term debt issued reached $4,841M in nine months, against repayments of $2,988M.
• Share count is rising, not falling. CenterPoint bought back no shares. Diluted shares rose 1.2% to 664M, and 24.9M more shares under forward sale agreements (about $866M) must be settled by February 25, 2027. Dividends paid were $159M in the quarter (our calculation: $461M year-to-date less $302M through June), up from $144M.

On balance the quarter is understated: last year's one-time tax benefit ($0.05 a share) costs more than this year's weather tailwind ($0.03) adds, so the 11% GAAP EPS gain is a fair-to-low read of the underlying growth.

Takeaway: CenterPoint's profit growth is coming from rates that recover money already spent, not from selling much more electricity (deliveries rose 1%). Management just added $4.0B to a capital plan whose spending already outran operating cash flow by $2.1B in the first nine months, while the large-load pipeline that justifies it narrowed from ~14 GW submitted to ~12 GW still in ERCOT's process. The plan works only if regulators keep approving recovery on time and those data-centre customers actually connect.

Large loads and data-centre demand

Under Texas Senate Bill 6, ERCOT's "Batch Zero" process (approved by the PUCT, Texas's utility regulator, on June 18, 2026) decides how much large-load demand, such as data centres, can connect and where. Houston Electric originally submitted about 14 GW. It now estimates that 10 GW of base load and about 2 GW of studied load remain in the process.

In the third quarter, these customers provided about $290M in contributions in aid of construction (money customers pay toward building their own connections) and about $600M in financial security, of which about $135M was returned to customers who left or scaled back. The filing says the amount of load that finally connects, how much power it uses and when "remain uncertain."

Regulatory recovery

• Houston Electric DCRF: $101.4M a year, effective September 1, 2026, after the PUCT required certain resiliency spending to be deferred up front. A second DCRF for $73M more has interim rates from September 30; the judge recommended approval as filed and a settlement for the full amount was filed October 1.
• Transmission (TCOS): $36M approved in April and another $29M approved in September.
• TEEEF: a settlement to remove 15 large and 5 medium emergency generators from rates would cut the revenue requirement by $112M; interim rates took effect August 15, and a revised proposed order was filed October 9. Houston Electric has said it will not charge customers for those units.
• Texas gas GRIP (a gas infrastructure recovery mechanism): $62M, approved in June.
• Indiana: the IURC set testimony for December 4, 2026 and hearings in the first half of 2027 on how Indiana's new multi-year rate plans will work; Indiana Electric must file one in January 2028. The DOE has now ordered the F.B. Culley Unit 2 coal plant to keep running through December 18, 2026.

Capital plan, asset sale and financing

• Ohio gas sale closed October 1, 2026, for $2.62B: $1.42B in cash plus a $1.2B promissory note from NFGC at 6.50%, due September 30, 2027. The gain or loss will be booked in Q4; the company says it cannot yet estimate it. The Ohio business earned $19M pre-tax in Q3 (excluding corporate allocations), so that income leaves the group from Q4.
• Spending: the 10-Q expects $2,305M of capital spending in the rest of 2026, $1,353M of it at Houston Electric. CERC repaid $500M of its $800M term loan on October 6 with sale proceeds.
• Equity: besides the forward sales above, a $1B at-the-market program is in place; the company does not expect to sell shares under it in 2026.

Did last time's read hold up?

Our Q2 report said to watch the September DCRF increase, the Ohio sale closing in Q4, interest costs, and whether the 14 GW of large-load interest would turn into real demand. The DCRF started on schedule on September 1 and the Ohio sale closed on October 1, the first day of Q4. Interest costs eased: company-wide finance charges excluding securitization rose 9% ($259M vs $238M) after 26% in Q2, though financing still cost $0.04 a share. The large-load picture moved the other way: the pool still in ERCOT's process shrank to about 12 GW, and $135M of security was handed back. Guidance moved up, from "at least the midpoint of $1.89–$1.91" to $1.90–$1.92.

Outlook

Management's markers (8-K): 2026 non-GAAP EPS of $1.90–$1.92, nearly 9% growth at the midpoint over 2025's $1.76; 2027 of $2.07–$2.09, about 9% above the raised 2026 midpoint; and non-GAAP EPS growth at the mid-to-high end of 7%–9% a year through 2030, backed by rate base growth of more than 14% a year.

In our view, the 2026 range looks safe: nine-month non-GAAP EPS is already $1.49, so Q4 needs only about $0.41–$0.43, and the September DCRF and the second DCRF's interim rates add to Q4. The questions sit further out. Each $1 of the larger capital plan has to be funded with new debt or shares before it earns anything, so the forward share settlement by February 2027 and continued debt issuance will weigh on per-share growth. Things to watch next quarter: the PUCT's final DCRF and TEEEF orders, the Ohio sale accounting in Q4, and how many of the ~12 GW of large-load requests move into construction rather than out of the queue.