Who really earns Texas’s electricity delivery charge?

A Houston storm-recovery charge can pay interest to a broad bond-index fund. An Austin Energy customer can help support an investor-owned transmission company far outside Austin. And the pension fund that owns part of Oncor can have its own creditors standing between the utility’s dividend and the pension beneficiary.^{26, 14, 37}

These are different claims on the electricity system. Treating them all as “the utility’s profit” obscures who receives the money, what they supplied in exchange, and who carries the risk.

Three joins make this visible. First, an ERCOT transmission billing matrix identifies the network providers paid by local utilities. Second, approved rate-case capital is linked to the equity interests entitled to its earnings opportunity. Third, bond identifiers are matched to SEC fund portfolios, revealing actual holders of customer-backed storm debt and ordinary utility bonds. These are reproducible calculations from disclosed records, not estimates of what particular investors privately own.

1. Where existing explanations stop

The basic story is already well covered. Retail comparison sites explain delivery-charge acronyms and publish historical rates. Oncor’s consumer material separates transmission, distribution and other riders. Corporate reporting and news coverage name major utility parents. Texas A&M’s Private Enterprise Research Center has examined electricity prices, customer classes and transmission allocation. Private Equity Stakeholder Project reporting examines private ownership and the roles of investment managers.^{35, 34}

Those sources answer different questions. A tariff explainer is not a beneficial-owner ledger; a parent-company diagram is not a cash waterfall; a history of delivery cents per kilowatt-hour does not establish delivery’s share of an entire household bill. In the material reviewed, the missing connection was a document-backed path across all three.

The existing material also needs source control. A useful historical-rate article sometimes treats a base distribution rate as if it were the full delivery charge. An indexed Cross Texas proposed order differs from the signed final order. A May 2025 affiliate report describes ownership at year-end 2024, before a March 2025 sale. The date of publication, the date being measured and the date a transaction closes are separate fields.^{35, 36, 13}

The contribution here is the joined ledger and its checks—not a claim that no one previously understood regulated returns or securitization.

2. Texas has more than four delivery utilities

The statewide starting point is the final 2025 EIA-861 service-territory data. Filtering for Texas yields 150 utility reporting IDs: 72 municipal, 68 cooperative, nine investor-owned and one state utility. The nine investor-owned IDs correspond to the eight operating companies below because AEP Texas Central and North remain separate reporting identities. The state entry is Texas A&M’s campus utility. These are reporting entities, not 150 independently verified legal corporations or a parcel-level title registry.¹

The companion census assigns all 150 records an ownership endpoint. For municipal systems that endpoint is the owning city or cities. For cooperatives it is the membership, sometimes through another cooperative layer. Creditors can earn interest in both cases; residual revenues can support investment, reserves, public transfers or member allocations rather than outside common shareholders. Floresville is a useful exception to simplistic name matching: its system belongs jointly to Floresville, Poth and Stockdale.⁴²

Oncor supplies a particularly clear ownership/control distinction. Despite Sempra’s 80.25% economic interest, Oncor’s filings state that regulatory protections mean Sempra does not control the utility. Seven of Oncor’s 13 directors must be disinterested.²

Public-company shareholders are a changing population, and a fund manager is not interchangeable with its investors. Saying “JPMorgan owns El Paso Electric” without separating advice, regulatory affiliation and economic capital assigns more than the documents establish. Likewise, identifying OMERS does not identify every pension beneficiary or prove that utility dividends pass through without deductions.

The additional owners behind ERCOT transmission

Following only the local distribution companies misses five investor-owned transmission providers that receive payments through the shared network.

This is a map of several kinds of capital: listed utility equity, pension capital, sovereign reserves, family-controlled entities, listed infrastructure funds and private funds. Ownership records support that description. They do not, on their own, prove why any particular buyer invested or that the buyer’s presence caused a bill increase.

3. The financial map extends beyond the service territory

ERCOT transmission charges are allocated using distribution providers’ demands at the system’s four coincident summer peaks. Each provider’s load obligation is combined with transmission owners’ approved access rates. Consequently, a local delivery company collects for a network that it owns only in part.¹⁴

I extracted all 105 entity rows from the PUCT’s approved 2025 matrix, identified the 46 positive transmission-provider tariff rows, and joined those recipients to the ownership ledger. The measure is each provider’s access rate divided by the sum of access rates. This is the correct share of gross charges in that matrix; dividing historical cost-of-service amounts would give different weights because the underlying rate denominators differ.

At the March 20, 2025 rate snapshot, the nine investor-owned providers account for 68.90% of gross charges, public providers for 23.62%, and cooperatives for 7.48%. Oncor’s own transmission function accounts for 28.30% of the portfolio; 71.70% goes to other provider functions. CenterPoint’s own share is 11.57%; 88.43% goes elsewhere. Austin Energy’s own share is 1.82%.

Public ownership of the local utility therefore does not insulate a customer from investor-owned transmission returns. The reverse also holds: customers of investor-owned utilities help finance public and cooperative transmission. The network’s financial footprint does not match the boundaries of the local franchise.

The matrix’s total access rate is $68.547300544 per kW-year and its load is 81,042,656.556 kW. Their product is $5.555 billion of annualized gross charges implied by the snapshot. It is not actual 2025 revenue: the signed order expressly warns against using the matrix for annual billing totals because rates and adjustments change. It also includes self-charges between transmission and distribution functions, which must be eliminated when combining retail-delivery and wholesale-transmission revenues. The 2026 replacement matrix was still pending at the research cutoff.¹⁴

For that reason, I do not multiply these historical portfolio weights into a household’s October 2026 transmission rider and claim to have traced current dollars to the cent.

4. Follow a 1,000-kWh household delivery bill

A standardized residential customer using 1,000 kWh in Oncor’s territory faces $72.733 in recurring delivery charges under the October 4, 2026 schedule, before line rounding, retailer supply charges, retailer fees and final taxes. The tariff calculation is $4.06 plus 6.8673 cents per kWh.¹⁵

The tariff labels are not a profit-and-loss statement. Distribution revenue pays employees, contractors, taxes, depreciation, interest and the equity allowance. Transmission recovery supports other providers as well as Oncor’s own network function. Nor are all riders pure reimbursement: the energy-efficiency rider effective March 2026 included a $32.56 million performance bonus, approved in December 2025 for 2024 achievements.²¹

Ordinary utility creditors are identifiable too. The June 30, 2026 SEC portfolio of Vanguard Total Bond Market Index Fund contains 27 distinct Oncor debt securities with $188.7225 million principal. Their disclosed fixed coupons imply approximately $8.94 million of annual interest at the snapshot balances, before maturities, trading, expenses and taxes. This is a concrete creditor layer supported by utility revenues. It is not a charge added specifically for that fund, and it is not a complete Oncor bondholder register.²⁷

Delivery costs have grown; the whole-bill share needs a denominator

Comparing the PUCT’s September 2021 schedule with the October 2026 endpoints shows a substantial nominal increase at fixed usage. The current Oncor amount is verified against its official tariff; the other current endpoints use Cirro’s posted pass-through schedule.¹⁶

All bills standardized to 1,000 kWh. Percentages use unrounded source amounts. These are dated nominal endpoints, not annual averages or inflation-adjusted changes.

For Oncor, $19.744 of the $28.419 increase—69.5%—comes from base distribution plus distribution cost recovery. Transmission contributes $3.259, or 11.5%; the temporary interim surcharge contributes $3.633, or 12.8%. Combining base distribution with its capital rider avoids misreading the transfer of costs from a rider into base rates as a change in underlying cost.

This does not establish how delivery’s share changed for the typical household. At 1,000 kWh, the same $72.733 delivery charge is 47.6% of a hypothetical bill with an 8-cent/kWh energy charge and 37.7% with a 12-cent energy charge, ignoring other fees and taxes. A defensible share series requires matched retail contract prices, usage and delivery tariffs.

There is a useful counterweight to the rising-dollar story. ERCOT’s February 2026 presentation shows real transmission cost per MWh roughly flat to declining over 2015–2024 even as total transmission spending rose. That aggregate measure does not settle residential affordability; it shows why growth in dollars alone cannot establish rising unit costs or excess returns.³⁹

5. What one point of allowed return is worth

The allowed return on equity applies to the equity-financed portion of the approved rate base. It is not a percentage markup on the delivery bill and not a guaranteed dividend. A simplified revenue requirement includes operating expenses, depreciation, taxes and a return on rate base that compensates both debt and equity capital.²²

Latest verified general-rate-case authorizations: Oncor April 17, 2026; CenterPoint March 13, 2025; AEP October 3, 2024; TNMP July 30, 2026. Calculations exclude subsequent incremental rider capital. They measure annual equity-return opportunity before income-tax gross-up, holding other inputs fixed.

For Oncor, the calculation is $26.452 billion × 43.5% × 1% = about $115.1 million annually. Applying the equity chain proportionally assigns approximately $92.34 million to Sempra’s interest, $11.48 million to OMERS-side capital, and $11.25 million to GIC-side capital, before holding-company financing, expenses and taxes. That is a sensitivity to regulatory policy, not a forecast of checks those ultimate investors receive.

The capital quantity matters alongside the percentage. At Oncor’s authorized equity mix and ROE, another $1 billion of approved rate base corresponds to about $42.4 million of annual equity-return opportunity. Growth in recoverable assets and the timing of recovery can therefore be large earnings levers even when the ROE percentage changes little. The math does not establish that any proposed project is unnecessary.

Two denominator checks are material. TNMP’s order calls $3.876 billion “invested capital,” but its approved schedule identifies that number as gross plant; the net rate base is $2.785 billion. Using gross plant would overstate its one-point result by about 39%. Oncor’s final-order consolidated capital exceeds the two located baseline schedules by $89.3 million, about 0.34%; the model explicitly uses the final order and preserves that scope qualification. Neither discrepancy is evidence of improper earnings.

Test the “guaranteed coupon” story against cash

Oncor’s owners contributed $2.504 billion in 2025 and received $792 million in distributions: $1.712 billion of net capital went into the company, before separate tax transfers. Capital expenditures were $6.761 billion. That is incompatible with portraying the dividend alone as net cash extracted from the system.²

There can also be a creditor above the utility. OMERS disclosed a $290 million private placement at its Oncor holding company in March 2026. The announcement describes refinancing activity, not a new direct customer charge. It nevertheless shows why ownership percentages are not a final cash-distribution register.³⁷

Allowed ROE is not even sufficient to predict the direction of a rate-case revenue change. CenterPoint’s 2025 settlement raised its authorized ROE to 9.65% while reducing annual base-rate revenues by approximately $46.6 million. Expenses, capital, credits and allocations changed too.¹⁸

6. Storm recovery creates a different financial asset

Physical storm-restoration bonds are issued by special-purpose entities that buy a statutory right to impose and collect customer charges. The sponsor receives proceeds to recover approved costs. Bond investors then hold a claim on that charge property, with reserves and periodic adjustments intended to meet debt service. They do not receive the utility’s allowed ROE.²⁴

CenterPoint Restoration Bond Company III issued $1.193 billion in February 2026. Its bonds are obligations of the issuing entity, without general recourse to CenterPoint or a Texas taxpayer guarantee. The restoration charge applies to distribution-voltage customers in the defined territory, including future customers. The prospectus describes uncapped required charge adjustments. This is a particularly direct transfer of collection and forecast risk to the future customer base.²³

The protection is a bill-adjustment mechanism. It does not make storms harmless or all utility spending recoverable. Prudence reviews, excluded costs, liabilities and timing can still affect shareholders. CenterPoint’s September 2026 filing, for example, reports a $35 million unfavorable lease-expense change in its nine-month operating-income comparison for temporary generators that no longer qualified for regulatory deferral. It expressly reports no impairment or disallowance of those assets through that date.³⁸

Who actually owns some of the storm claim?

I matched the 2026 issuer’s bond identifier CUSIP 15202GAC2 to SEC N-PORT filings. Five Vanguard funds reported a combined $45 million principal in that A3 tranche at June 30, 2026.

That is 9.05% of the $497.279 million tranche. Its 4.864% coupon implies $2.1888 million of annual interest at those balances, before amortization, subsequent trades and fund expenses. The funds own the securities for their investors; the coupon is not Vanguard corporate profit. The same broad market fund identified above can therefore hold both ordinary Oncor debt and a legally separate Houston customer-charge security.^{23, 27}

Another match is more concentrated. FPA New Income Fund reported $56.954 million of the older Restoration II A1 tranche. Compared with the issuer’s post-June-payment balance of $224.814 million, that is 25.33% of the tranche. The comparable-date ledger documents 22 CenterPoint fund/security positions across 17 funds, totaling $135.194 million of principal. This is a disclosed subset, not an exhaustive ownership register.^{31, 25}

An actual cash waterfall

The Restoration II payment certificate for June 15, 2026 traces $34.565 million of charge remittances and investment income through its general subaccount. A separate $2.008 million sponsor-funded capital subaccount remained intact. The general-subaccount money was allocated as follows.²⁵

First payment interval ending June 15, 2026; not a normal annual allocation or a decomposition of the entire delivery charge. Principal, reserves and service fees are not all profit.

The issuer’s equity contribution is also different from ordinary rate-base equity. Restoration III required a 0.5% capital contribution—about $5.97 million—supporting a much larger bond issue. That does not entitle CenterPoint to its utility ROE on the whole $1.193 billion of bond principal. The offering separately paid underwriting compensation and provides servicing and administration fees.²³

“Uri bonds” are not one customer charge

ERCOT’s Winter Storm Uri market-financing entities recover wholesale-market obligations. Their charges are not automatically the same as a separately itemized local delivery rider. Physical-restoration bonds are another category; transmission restoration can enter statewide transmission costs, while the Houston restoration bonds apply to the local distribution customer base. The distinction determines who pays and which investors receive the resulting cash.

It also changes over time. The Texas Treasury Safekeeping Trust Company bought the original $800 million of Subchapter M bonds in 2021. In August 2025, $379.1 million of new 5.147% bonds refinanced the remaining old balance, with the new issue placed with qualified institutional and eligible offshore investors. An account that still assigns the whole surviving claim to the state treasury is stale; adding the original issue to the refinancing would double count.³²

7. Who decided—and what was decided?

“The state sets the coupon” compresses several decisions. The legislature establishes the regulatory framework and recovery mechanisms. The PUCT’s five commissioners are appointed by the governor and confirmed by the Senate. Rate cases determine allowable costs, capital structure, ROE, allocation and tariffs, with participation by utilities, cities, consumer representatives, staff and other intervenors. Municipal and cooperative retail governance, and federal transmission regulation outside ERCOT, require separate treatment.^{40, 22}

The PUCT sets the equity-return allowance and authorizes recovery mechanisms; bond coupons are priced through the securities offering. Share sales determine who holds the equity claim. They do not generally replace original-cost rate base with the purchase price. The buyer’s investment return also depends on the acquisition valuation, financing, future investment and eventual exit value; it cannot be inferred from an approved 9.75% ROE.^{22, 23}

Policy can change the timing of earnings and collection as well as the allowed percentage. HB 5247’s 2025 capital-recovery mechanism allows qualifying ERCOT utilities assigned Permian Basin transmission projects, with prior-year capital spending above three times depreciation, to seek a combined annual capital update. It permits specified deferrals and temporary rates subject to refund. Economically, faster recovery can reduce financing risk; the law expressly permits the commission to consider the mechanism’s effect on financial risk when determining a future allowed return.²²

Control review is another distinct question. When John Hancock sought to sell a 45.75% Cross Texas interest, the signed March 2023 PUCT order denied the requested declaratory ruling. All parties agreed approval was unnecessary, leaving no controversy; the commission also said the control question was fact-intensive and the record insufficient. The transaction subsequently closed. That is not an affirmative commission ruling that every minority sale is exempt.^{36, 12}

The result is not simply a market versus a state. Public decisions define the amount, timing and security of different revenue claims; private and public investors trade or retain those claims. The price of capital and the allocation of risk are jointly produced by those decisions.

8. What the evidence supports—and what would change it

Scope of the dataset. The census covers all 150 Texas service-territory reporting IDs in the final 2025 EIA file. The detailed equity ledger covers the eight requested investor-owned distribution companies and five additional investor-owned ERCOT transmission providers. The transmission table preserves all 105 matrix entities. Rate calculations cover the four major competitive-market investor-owned delivery companies. The bond inventory is a bounded six-issuer/series collection with individually dated balances; it must not be summed as a complete same-date statewide debt total.

Reproducible joins. Distribution records are keyed by EIA utility ID. Transmission weights are based on access rates, with aggregated member loads checked against the workbook and statewide total. Bond positions are matched by CUSIP and deduplicated by fund series and observation date, not share-class name. Calculations use principal rather than market value for coupons. Every output table records sources and scope, and the workbook exposes formulas.

Important boundaries. Outside-ERCOT utilities include generation and sometimes multiple jurisdictions, so their entire corporate earnings cannot be labeled Texas delivery profit. Cooperative and municipal ownership is grounded in EIA classifications and named exceptions, not individual charter audits. Historical balancing-authority fields are not current grid assignments: Caldwell moved from MISO to ERCOT in March 2026.⁴¹ A lack of public LP disclosure remains a limitation, not a license to assign a manager’s other investors to a particular utility.

Finally, this is a financial investigation, not an explanation of the 2021 system failure. FERC and NERC’s unit-level investigation attributes the overwhelming majority of unplanned generation losses to freezing and fuel issues. The ownership of wires alone cannot explain that event.³³

Primary sources and research trail

Sources below support the report’s grouped findings. The CSV/JSON tables and workbook carry row-level URLs, observation dates and scope notes. SEC portfolio files are XML; the fund series, CUSIP, principal and coupon fields are the relevant evidence.

1. EIA census. EIA-861 detailed data and definitions; 2025 final data ZIP, released October 7, 2026. Service_Territory, Utility_Data, Sales_Ult_Cust, Delivery_Companies and Short_Form files. Counts are original calculations from Texas service-territory records.
2. Oncor equity and cash. 2025 Form 10-K, ownership, Item 12, cash flows and member contributions/distributions; June 2026 Form 10-Q.
3. CenterPoint legal chain. 2025 Form 10-K, subsidiary/holding-company structure.
4. AEP Texas and SWEPCO. AEP joint 2025 Form 10-K.
5. TNMP. TXNM 2025 Form 10-K, Note 1; October 30, 2026 issuer release; issuer’s PR Newswire release.
6. Entergy Texas. Entergy 2025 Form 10-K.
7. SPS. SPS 2025 Form 10-K, common-stock ownership.
8. El Paso Electric. July 29, 2020 closing release; 2023 financing application; May 2025 application. Not every historical intermediate has a freshly published current cap table.
9. ETT. BHE U.S. Transmission; BHE 2025 Form 10-K.
10. Lone Star. Company site; NextEra financial policy and legal ownership.
11. Sharyland. 2024 FERC report filed with PUCT; Sempra 2025 Form 10-K.
12. Cross Texas. January 14, 2025 rate testimony, Fredkin direct pp. 9–10; HICL current asset page, rounded 45.8% and April 2023 acquisition.
13. WETT. Axium March 24, 2025 acquisition announcement; prior-year affiliate report filed May 2025.
14. Transmission matrix. Staff’s March 20, 2025 original workbook; signed June 5 order, especially ordering paragraph 2; October 29, 2026 notice scheduling the pending replacement for November 5. Original calculations are documented in the companion tables.
15. Current Oncor delivery. Official tariff, printed pp. 67–68, 95, 98, 101, 105–108; October 1 and October 4 monthly reports in the same filing.
16. Bill endpoints. PUCT September 1, 2021 summary, archived by BKV; Cirro October 2026 component schedule. Current Oncor cross-checked to source 15.
17. Oncor return. Docket 58306 final order, April 17, 2026, findings 63–72; approved settlement schedules. Consolidated invested-capital denominator is stated explicitly.
18. CenterPoint return. Docket 56211 final order, March 13, 2025; Exhibits H and I approved rate-base schedules. Full distribution and transmission gross plant and working capital were reconciled to the order.
19. AEP return. Docket 56165 final order, October 3, 2024; Exhibit D total rate base.
20. TNMP return. Docket 58964 final order, July 30, 2026; Attachment 3 II-B line 21 total rate base.
21. Energy-efficiency incentive. Docket 58182 final order, December 12, 2025, ordering paragraphs 2(e) and 3: $32,560,930 incentive; March 1, 2026 effective date.
22. Regulatory mechanism. Texas Utilities Code chapter 36, including fair return and original-cost rate base; HB 5247 enrolled text, new §36.216, especially eligibility, deferral, interim-rate refunds and subsection (k) on effects on financial risk.
23. Restoration III. 2026-A final prospectus, cover, security, customer charge, true-up and issuer capital sections.
24. Restoration II mechanism. 2025-A final prospectus.
25. Actual waterfall. Restoration II June 15, 2026 payment certificate. All listed uses sum exactly to $34,564,946.30.
26. Vanguard Total Bond Market II. June 30, 2026 N-PORT, series S000025158, CUSIP 15202GAC2.
27. Vanguard Total Bond Market Index. June 30, 2026 N-PORT, series S000002564, CUSIP 15202GAC2 and 27 records with issuer name “Oncor Electric Delivery Co LLC.” Principal rather than fair value used for coupon calculations.
28. Vanguard Balanced Index. June 30, 2026 N-PORT, series S000002560.
29. Vanguard Variable Insurance Total Bond Market Index Portfolio. June 30, 2026 N-PORT, series S000004395.
30. Vanguard Core-Plus Bond Index ETF. June 30, 2026 N-PORT, series S000097262.
31. FPA New Income. June 30, 2026 N-PORT, series S000080693, CUSIP 15201GAA7.
32. Uri market financing. TEMS Funding M 2025 audited statements, Note 6; ERCOT HB 4492 program; Subchapter N.
33. System-failure boundary. FERC–NERC final report announcement and report, November 2021.
34. Existing economic analysis. Texas A&M PERC, February 2026. Descriptive economic analysis, not treated here as a causal estimate of ownership effects.
35. Existing explainers and research model. Oncor delivery-charge explainer; BKV historical rates; PESP’s El Paso ownership reporting; the user-supplied Texas toll-road ownership study. Historical rate facts are checked to original schedules, not copied uncritically from the aggregation.
36. Cross Texas decision. Signed March 23, 2023 final order, Docket 54042. The earlier indexed proposal is not the final disposition.
37. Holding-company creditor. OMERS March 17, 2026 Oncor financing announcement.
38. Equity risk. CenterPoint September 2026 Form 10-Q, Houston Electric MD&A and Note 6 on TEEEF.
39. Unit-cost counterevidence. ERCOT February 2026 CEO update, transmission-cost slide. Trend interpreted qualitatively; no precise values digitized from the graphic.
40. Decision makers. PUCT structure and process; Utilities Code chapter 12. See also chapters 40 and 41 for municipal/cooperative governance.
41. Historical geography. ERCOT’s March 12, 2026 Caldwell announcement; TPPA municipal utility list.
42. Public-owner exceptions. FELPS owner cities; Texas A&M campus utilities; LCRA TSC; TMPA’s four owning cities.