Dominion Energy sells electricity to homes and businesses in Virginia and the Carolinas, supplies natural gas in South Carolina, and operates power plants that sell under contracts. In the third quarter of 2026, higher approved electricity rates and earnings on utility investments lifted profit. But through September, the company generated $4.69 billion of operating cash while spending $8.58 billion on construction and other property additions. Its ability to turn growing electricity demand into a stronger business therefore depends on controlling project costs, collecting approved charges and maintaining access to funding.
Analysis period: quarter and nine months ended September 30, 2026. Research cutoff: November 1, 2026, New York time. The latest company financial update reviewed is dated October 30, 2026.
Source: Dominion Energy third-quarter 2026 Form 10-Q, consolidated income and cash-flow statements, pp. 7 and 13; Note 1, p. 21.
1. Higher approved rates did more for profit than customer growth
The quarter’s earnings improvement came mainly from regulatory decisions and returns on utility investment. Dominion charges customers under rates approved by regulators. Some charges recover fuel or other costs; others also allow the company to earn a return on the power plants and networks it builds. That distinction explains why a large increase in revenue does not translate directly into the same increase in profit.
Quarterly revenue rose 24.1%. Of the $1.09 billion increase, $382 million came from fuel-related revenue, which largely accompanies energy costs. Virginia’s project-specific charges, called riders, added $258 million of revenue, and its latest base-rate review added $184 million. Warmer weather added $122 million of retail electricity revenue. The separately identified contribution from customer growth was $21 million.
The following comparison separates the strong quarter from the weaker cumulative result. Operating profit is what remains after operating costs but before interest and income taxes. Net income below is the portion attributable to Dominion, after deducting earnings belonging to outside owners of subsidiaries.
| Consolidated results; USD million except EPS and margins | Q3 2025 | Q3 2026 | First nine months 2025 | First nine months 2026 |
|---|---|---|---|---|
| Revenue | 4,527 | 5,617 | 12,413 | 15,116 |
| Reported operating profit | 1,339 | 1,842 | 3,658 | 3,563 |
| Operating margin, calculated | 29.6% | 32.8% | 29.5% | 23.6% |
| Interest and related charges | 527 | 623 | 1,513 | 1,739 |
| Net income attributable to Dominion | 1,006 | 1,160 | 2,431 | 2,121 |
| Diluted earnings per common share, USD | 1.16 | 1.30 | 2.81 | 2.37 |
Source: 2026 Form 10-Q, p. 7 and MD&A, pp. 65–66. Margins are calculated from the reported amounts.
Virginia’s reported segment earnings rose $183 million in the quarter. The rate review contributed $137 million after tax and returns on rider-funded investments contributed $112 million. These gains exceeded the segment’s total improvement because costs also rose. Higher costs for securing generating capacity reduced earnings by $48 million, while salaries, benefits and administrative costs reduced them by $33 million. Weather contributed $55 million.
South Carolina’s segment earnings increased $62 million. Its rate changes contributed $46 million after tax, and weather added $36 million, partly offset by costs. The regulator approved a $219 million annual non-fuel base-rate increase effective with July billing, before separate demand-management reductions. This was below the company’s original $331 million base-rate request, illustrating the regulator’s influence over how much investment and operating cost customers must pay.
The next already-approved Virginia base-rate increase is $210 million annually, effective January 2027. That offers a concrete source of additional revenue. The order remains under appeal, and more revenue will also have to cover rising wages, depreciation and financing costs. The practical gain is a better route to recovering investment, rather than an automatic increase of the same amount in profit.
Source: 2026 Form 10-Q, Note 12, pp. 43 and 46; segment earnings explanations, pp. 69–70.
2. Large electricity users create demand, but also require costly commitments
Dominion is selling more electricity, while a larger share of its revenue depends on customers with unusually large power needs. Virginia’s electricity deliveries increased 5.9% through September. Its average number of distribution customer accounts rose only about 0.9%. Existing customers’ consumption, weather and the size of new users therefore matter much more than the account count alone.
| Operating evidence; first nine months | 2025 | 2026 |
|---|---|---|
| Virginia segment electricity delivered, million MWh | 76.1 | 80.6 |
| South Carolina segment electricity delivered, million MWh | 17.2 | 18.0 |
| Virginia high-load customer revenue, USD million | 1,308 | 2,156 |
| Largest customer’s share of Virginia Power revenue | 9% | 12% |
Source: 2026 Form 10-Q, Note 3, p. 23; Note 17, pp. 54–55; operating statistics, pp. 69–70. A megawatt-hour, or MWh, measures electricity delivered. “High load” includes certain data centers and other Virginia customers meeting the filing’s demand and usage thresholds; it is not a data-center-only category. Virginia Power is the subsidiary, while the delivery figures are segment measures.
High-load revenue rose 64.8%, much faster than electricity deliveries across the Virginia segment. This demonstrates greater commercial importance, but does not measure growth in data-center electricity use by itself: rates, customer mix and consumption all affect the revenue figure. Weather also matters. Virginia’s measure of cooling demand rose 13% over the nine months, while South Carolina’s rose 31%.
PJM, the regional grid operator, provides useful evidence beyond Dominion’s plans. Its January 2026 forecast projected average annual summer peak-demand growth of 3.6% over the next decade, compared with 0.3% in its 2021 forecast. Yet PJM lowered near-term demand estimates from its previous forecast after examining large-user commitments more closely. The regional need for investment is substantial, but proposed projects do not all arrive on their original schedules.
Source: PJM’s updated long-term demand forecast, January 14, 2026, “Changes From 2025,” “Summer Peak Load Growth” and “Improving the Forecast.” These are regional planning forecasts, not Dominion sales forecasts.
Dominion must build enough supply and transmission to serve those users without committing too much money before customers arrive. Its planned investment in Valley Link, a transmission venture with AEP and FirstEnergy, is approximately $1.5 billion during 2026–2030. Dominion’s initial ownership is 30%. The arrangement shares the work and financing burden with other utilities, although it still requires substantial cash from Dominion.
Regulators can also narrow the construction program. In October, Virginia approved $388 million of capital investment in Phase IV of Dominion’s distribution-grid plan, compared with $983 million requested. The full $125 million requested for operations and maintenance was approved. Dominion can submit revised proposals in 2027. Separately, the regulator approved only part of an earlier solar-and-storage application. Growing demand supports the need for projects; permission to build and recover their costs remains a separate hurdle.
Source: 2026 Form 10-Q, Note 12, p. 44; MD&A, “Investment in Valley Link,” p. 76.
Securing dependable generation is already affecting profit. Virginia’s capacity costs reduced its nine-month segment earnings by $124 million after tax. Capacity payments reserve generating resources so they will be available when needed. This is different from paying for electricity actually consumed. PJM’s published auction price for the Dominion zone fell from $444.26 to $329.17 per megawatt-day between the 2025/26 and 2026/27 delivery years, even though Dominion’s reported net capacity expense increased. The company’s own mix of obligations, generation and contracts therefore matters more than applying a regional price headline directly to its costs.
Sources: 2026 Form 10-Q, pp. 65–66 and 70; PJM 2026/2027 auction report, executive summary and Table 1, p. 3. Auction delivery years differ from calendar reporting years; the price comparison is market context, not an earnings reconciliation.
3. Offshore wind can add supply, but Dominion bears part of the overrun risk
The offshore wind budget held steady during the quarter, but the project still carries costs that customers will not repay. Coastal Virginia Offshore Wind is designed to add 2.6 gigawatts of generating capacity and help Virginia Power meet renewable-energy requirements. Dominion expects installation of the final turbines by the end of 2027.
The estimated construction cost remained approximately $11.7 billion, excluding financing costs and including about $100 million of contingency. That was unchanged from July. Compared with the January update, roughly $400 million of lower projected connection and network-upgrade costs offset roughly $400 million of higher installation-related costs. Tariff estimates also changed. These are rounded movements, so they should not be treated as an exact budget bridge.
The remaining contingency—the budget reserved for unexpected costs—equals approximately 8% of estimated remaining construction costs. Weather, installation fuel, supplier performance, tariffs and further government work suspensions can still change the outcome. A stable total estimate therefore reflects offsetting developments, rather than the disappearance of construction risk.
Source: 2026 Form 10-Q, Note 10, pp. 38–39; MD&A, pp. 75–76.
The annual report expected most turbines in service by the end of 2026 and the remainder in early 2027. The current target for final installation by the end of 2027 extends the period during which Dominion must manage construction risk.
The regulatory agreement permits recovery of half the unforeseen construction overruns in the $10.3–$11.3 billion band, none in the $11.3–$13.7 billion band, and a future review above that. Applicable federal cost reductions also adjust the bands. Stonepeak’s funding above $11.3 billion is optional; Dominion’s share of additional funding can consequently exceed half.
Source: Dominion Energy 2025 Form 10-K, Note 10, pp. 112–113, and project discussion, pp. 11–12.
The current accounting already recognizes part of this exposure. During the first nine months, the consolidated project recorded a $129 million pretax charge for costs not expected to be collected from customers. Of that, $64 million belonged to Stonepeak’s outside ownership interest. Dominion’s share was $65 million before tax and $48 million after tax. No additional charge was recorded in the third quarter.
Stonepeak owns half the project entity, but Dominion controls and consolidates it. The accounts therefore include the project’s full assets and cash spending, then separately show Stonepeak’s contributions and earnings share. This matters when judging the funding burden: subtracting only half the construction spending from consolidated operating cash would understate the cash actually passing through the group.
Source: 2026 Form 10-Q, Notes 2, 10, 14 and 20, pp. 22, 39, 47–48 and 57.
Other major commitments will continue beyond the wind installation. South Carolina approved the proposed Canadys gas-fired station in June. Dominion’s subsidiary and Santee Cooper would each own half of the approximately $5 billion, 2.2-gigawatt plant, excluding financing costs. The expected service date is 2033; cost refinement, permitting and pending appeals remain relevant. Dominion’s construction needs therefore extend well beyond completing one large project.
Source: 2026 Form 10-Q, Note 12, pp. 46–47.
4. The utility improvement coexists with a large loss on renewable natural gas
The $820 million renewable natural gas write-down shows a substantial loss on earlier investment. Dominion concluded that these nonregulated facilities would probably be sold before the end of their useful lives. Its estimate of recoverable value fell below the amount recorded in the accounts. The resulting second-quarter charge reduced nine-month net income by $640 million after tax.
The facilities were written down to an estimated value of $468 million, after accounting for related investment tax credits. That estimate uses expected future cash receipts, reduced to reflect waiting time and risk, rather than an agreed sale price. It demonstrates that the original recorded investment was not fully supported by the revised outlook. The charge itself did not consume another $820 million of cash in 2026; much of the money had been committed earlier.
The business is producing gas: nine-month output was 1.4 million MMBtu, a measure of heat energy, and new operations added $48 million of revenue from gas and related environmental credits. But projects placed in service in late 2025 also added $81 million of operating and maintenance costs. These two disclosed changes do not form a complete profit calculation. Tax credits are important too: the company recognized a $94 million clean-fuel production tax benefit through September. Across the consolidated business, the effective income-tax rate fell from 15.7% to 13.9%, helping soften the decline in after-tax income from continuing operations.
Source: 2026 Form 10-Q, Notes 4 and 10, pp. 24 and 40; MD&A, pp. 66–67 and 70–71.
Other accounting movements pulled reported earnings in opposite directions. Dominion recognized a $195 million pretax benefit, or $142 million after tax, after revising estimated spent-fuel recoveries associated with closing Millstone Unit 1. This reduced an estimated future obligation; it was not new electricity-sale income. Nuclear decommissioning investments also generated gains, while certain solar assets were written down. Dominion completed the sale of some nonregulated solar facilities to Enel in October under an agreement for $140 million cash, subject to closing adjustments.
Management’s “operating earnings” removes investment and hedge-value changes, merger costs, selected storm effects, asset charges and benefits, and discontinued operations. The table reconciles the total pretax and tax adjustments, including both gains and losses.
| Earnings reconciliation; USD million | Q3 2025 | Q3 2026 | First nine months 2025 | First nine months 2026 |
|---|---|---|---|---|
| Reported net income attributable to Dominion | 1,006 | 1,160 | 2,431 | 2,121 |
| Pretax adjustment to remove selected items | -146 | -37 | -146 | 661 |
| Associated income-tax adjustment | 61 | 16 | 88 | -84 |
| Management’s operating earnings, non-GAAP | 921 | 1,139 | 2,373 | 2,698 |
Sources: October 30, 2026 earnings release, Schedule 1; 2026 Form 10-Q, Notes 2, 10 and 20, pp. 22–23, 39–40 and 57; Corporate and Other analysis, p. 71. The adjustment is on Dominion’s ownership scope, rather than the full amount of every subsidiary charge.
The adjusted measure grew 13.7% over the nine months, while reported net income fell 12.8%. This changes the diagnosis: ongoing utility earnings improved, while selected losses outweighed that improvement in the reported result. It does not make the excluded losses unimportant. Construction overruns and unsuccessful investments still consume capital, and storm costs can recur even when management excludes particular events.
The adjusted measure also retains favorable weather, tax credits and ordinary financing costs. Contracted Energy’s segment earnings declined from $321 million to $284 million despite higher production tax credits. Depreciation, interest and other expenses increased, while investment tax credits fell. Moreover, Dominion reports many exceptional operating-business losses within Corporate and Other, so the segment result alone does not show the renewable natural gas investment loss.
Source: 2026 Form 10-Q, Note 20, p. 57, and MD&A, pp. 69–71. Percentage changes are calculated from the reconciliation above.
5. More operating cash still leaves a construction funding gap
Operations funded about 55% of cash construction and property spending through September. That improved from 47% a year earlier, but left a substantial amount to finance. The decline in spending was primarily payment timing, according to management, rather than evidence that the construction program had ended.
| Cash generation and uses; first nine months, USD million | 2025 | 2026 |
|---|---|---|
| Operating cash inflow | 4,374 | 4,688 |
| Cash construction and other property additions, positive spending amount | 9,255 | 8,576 |
| Operating cash less that spending, calculated | -4,881 | -3,888 |
| Common dividends paid | 1,708 | 1,761 |
| Cash remaining after that spending and common dividends, calculated | -6,589 | -5,649 |
Source: 2026 Form 10-Q, cash-flow statement, p. 13, and MD&A, p. 72. Property spending includes nuclear fuel and the consolidated wind project. Free cash flow here means operating cash less this property spending: negative $3,888 million in 2026 and negative $4,881 million in 2025, before dividends. It excludes separately reported solar-development acquisitions, other investing flows and financing flows, including Stonepeak contributions.
Operating cash increased $314 million. Management identified $733 million of stronger utility cash flow from riders and Virginia’s rate review, plus $371 million less cash tied up in net prepayments and deposits. Higher interest payments absorbed $430 million of that improvement. Changes in other short-term operating balances and lower interest-swap settlements also reduced the benefit.
Customers had not yet paid for all the revenue or fuel costs recorded. Receivable movements used $372 million of operating cash, compared with $63 million a year earlier. Deferred fuel and purchased-gas costs used another $505 million. The company pays suppliers first and collects some of these costs through later bills, leaving it to finance the waiting period.
September’s regulatory order provides a way to shorten that wait. Virginia Power received permission to finance $932 million of previously under-collected fuel costs with bonds lasting no more than approximately seven years. Such financing can replace a delayed stream of customer payments with earlier cash proceeds, while customers repay the bonds over time. The filing reports approval, rather than a completed issuance of these new bonds by September 30.
Source: 2026 Form 10-Q, p. 13; Notes 11–12, pp. 41 and 43–44; cash-flow discussion, p. 72.
The balance sheet shows where the money is going. Net property increased $4.77 billion. Customer receivables and amounts recoverable through future regulated bills also increased. Those assets can support future cash generation, but they cannot all pay today’s construction invoices.
| Consolidated financial position; USD million | December 31, 2025 | September 30, 2026 |
|---|---|---|
| Cash and cash equivalents | 250 | 435 |
| Customer receivables, after allowance | 2,531 | 3,094 |
| Inventories | 1,957 | 2,030 |
| Net property, plant and equipment | 78,967 | 83,735 |
| Regulatory assets, current and noncurrent | 9,656 | 10,566 |
| Nuclear decommissioning trust investments | 9,166 | 10,093 |
| Total assets | 115,857 | 124,784 |
| Total liabilities | 82,440 | 90,369 |
| Total equity, including outside subsidiary owners | 33,417 | 34,415 |
Source: 2026 Form 10-Q, balance sheets, pp. 9–10; Notes 9 and 11, pp. 36–42.
Regulatory assets are costs recorded for collection through future bills. Their $910 million increase included a $722 million increase in current and noncurrent deferred electric-fuel costs. Dominion does not expect to earn a return during collection on $6.1 billion of its regulatory assets. Even eventual repayment therefore leaves a financing burden while the company waits.
The nuclear trusts are set aside for eventual plant closure, so their $10.09 billion balance should not be treated as available construction cash. Other long-term assets rose $1.29 billion. Within that increase, the recorded value of long-term derivative contracts—used to manage price and interest-rate risks—rose $566 million. A new storage-facility lease added a $269 million right to use the asset. These are recorded rights or contract values, rather than cash receipts.
Goodwill, the acquisition premium retained in the accounts, was unchanged at $4.14 billion. Inventory increased only $73 million and was a much smaller use of resources than construction.
Source: 2026 Form 10-Q, p. 9; Notes 8–9, 11 and 13, pp. 33–42 and 47.
6. Borrowing keeps the program moving, at a growing interest cost
Dominion has substantial credit access, but debt is growing faster than equity. Reported financing debt increased from $48.94 billion at year-end to $54.65 billion in September. Equity increased by about $1.00 billion. The group funded its cash deficit largely through debt, supplemented by Stonepeak’s net investment and a much smaller amount of new common equity.
Long-term debt issuance and remarketing brought in $6.725 billion of cash. After $1.713 billion of repayments and $85 million of fuel-securitization repayments, those flows provided $4.927 billion. Short-term borrowing added $851 million. Stonepeak contributed $506 million and received $246 million in distributions, leaving $260 million of net funding, compared with $974 million a year earlier. These cash sources explain how construction continued even though operating cash did not cover it.
At September 30, $2.399 billion of securities were due within one year, in addition to $3.308 billion of short-term debt. Cash was $435 million. Available capacity under the main and supplemental revolving credit facilities was $5.057 billion, already reduced for supported commercial paper and relevant letters of credit. That provides meaningful flexibility, but borrowing capacity is not cash already earned, and drawing it increases future interest requirements.
Source: 2026 Form 10-Q, pp. 10 and 13; Note 15, pp. 48–50. The debt measure adds short-term debt, securities due within one year and reported long-term debt; it includes the finance-lease amounts classified there, but excludes ordinary payables and operating leases.
The $7 billion joint credit facility runs to April 2031; the $1 billion supplemental facility runs to April 2028, before optional extensions. Much of the new bond borrowing matures in 2036 or 2056, spreading repayment beyond the construction period. Nevertheless, the company must keep refinancing near-term obligations while raising money for additional investment.
The last annual maturity schedule showed $1.963 billion due in 2027 and $2.477 billion in 2028. The lending agreements limited debt to 67.5% of defined total capital, versus an actual 53.5% at December 2025. Its contractual exclusions mean an ordinary balance-sheet ratio is not a valid compliance test. The quarterly filing reports no material covenant changes or defaults.
Sources: 2026 Form 10-Q, Note 15, pp. 48–50, and “Financial Covenants,” pp. 73–74; 2025 Form 10-K, pp. 59 and 131. The annual principal schedule is dated December 31, 2025; it is not a newly reported September maturity schedule.
The cost of funding is already visible. Nine-month interest and related charges increased 14.9% to $1.739 billion. Management attributed a $284 million increase to net long-term debt issuance, partly offset by other items, including derivative gains. Cash interest payments increased even more than the reported expense change, as discussed above.
For a concrete contractual example, June’s $1.5 billion of junior subordinated notes—debt that ranks behind senior borrowing—carries initial rates of 6.15% and 6.25%, equivalent to $92.75 million of annual interest at those rates. The rates reset from 2031 and 2036, respectively, with floors at their initial levels. Dominion can defer interest under specified terms, but doing so would generally restrict dividends and certain other payments. These securities extend the funding horizon without removing its cost.
Source: 2026 Form 10-Q, Note 15, p. 50; MD&A, pp. 67 and 72. Annual coupon calculation: $1,000 million × 6.15% plus $500 million × 6.25%. This is a full-year contractual illustration, not the interest recorded during the partial year after issuance.
Leases add further commitments. At December 2025, undiscounted operating and finance lease payments totaled $2.130 billion. In 2026, a new approximately 15-year storage lease added a $270 million September liability. That current addition should not simply be added to the old payment schedule, which has since changed through payments and other lease activity.
Sources: 2025 Form 10-K, Note 15, p. 126; 2026 Form 10-Q, Note 13, p. 47.
Dominion paid $1.761 billion of common dividends while issuing just $40 million of common shares for cash through September. It made no repurchases under its repurchase authorization. Purchases for direct stock plans and shares tendered for employee tax withholding should not be mistaken for a program to shrink the share count. Forward share-sale agreements scheduled for later settlement offer another funding source, but proceeds are not current cash until settlement occurs.
The average diluted share count, which includes potential shares from forward share-sale agreements, increased 3.1% in the quarter, from 855.4 million to 882.1 million. That helps explain why net income grew 15.3%, while diluted earnings per share grew 12.1%. The comparison reflects shares already issued in earlier periods as well as potential dilution; only about one million new shares were issued through the direct programs during the first nine months of 2026. Stock awards increased the common-stock equity account by $27 million. Equity funding helps limit borrowing, while spreading earnings across more shares.
Source: 2026 Form 10-Q, equity statement, p. 12; Notes 5 and 15, pp. 25 and 50–51. Preferred dividends are deducted before calculating common-share EPS.
7. The NextEra merger addresses scale, while approvals and legacy obligations remain
The proposed merger could improve purchasing, construction and financing capacity, but those benefits remain prospective. Management’s stated purpose is to combine the companies’ resources and operating experience so they can build and supply power more efficiently. That rationale directly addresses Dominion’s large funding needs. It does not establish how much Dominion will actually save.
Under the May agreement, Dominion would become a NextEra subsidiary. Shareholders approved the transaction in September, and the companies filed for federal antitrust clearance in October. The expected closing is the second half of 2027, subject to remaining conditions and approvals from federal energy and nuclear regulators and commissions in Virginia and the Carolinas.
The companies proposed $2.25 billion of customer rate credits funded by NextEra. A September alternative Virginia proposal would extend residential credits to four years, partly by removing credits for certain large-load customers and adding shareholder funding. Other proposed customer-assistance and workforce commitments would also require funding. These commitments are part of securing approval and sharing benefits with customers; they should not be counted as operating savings.
Sources: NextEra and Dominion merger announcement, May 18, 2026, strategic rationale; 2026 Form 10-Q, Note 1, pp. 21–22. The filing supplies the more recent terms and approval status.
Until closing, the agreement requires NextEra’s consent for specified actions, including certain debt or equity issuance and quarterly common dividends above $0.6675 per share. Dominion must therefore fund its ongoing program within those agreed limits. Termination provisions also matter: Dominion could owe $2.24 billion in specified circumstances, while NextEra could owe $6.52 billion in comparable circumstances or $4.83 billion for certain regulatory failures. These are conditional contractual amounts, not current liabilities or amounts expected to be paid.
Legacy exposures remain relevant regardless of ownership. Dominion retained Cove Point guarantees after selling its investment: two have combined maximum exposure of $1.9 billion, and another has no stated maximum. No liability was recorded for them. Separately, reserves for former manufactured-gas sites were $53 million, unchanged from December. Some additional sites and property-damage or personal-injury cases have no estimable loss range. The absence of an estimate does not settle their eventual cost.
Coal-ash cleanup also creates a long collection period. Related noncurrent regulatory assets increased from $2.868 billion to $3.132 billion. A second-quarter revision added $203 million to asset-retirement obligations with an equal regulatory asset, recording an expected future obligation and a corresponding amount to recover from customers. Regulatory recovery can reduce the earnings impact, while still leaving Dominion responsible for arranging and financing the work.
Source: 2026 Form 10-Q, Notes 1–2, 11 and 16, pp. 21–23, 40–42 and 52–54. Guarantee amounts are contingent exposures and are not added to reported financing debt.
8. The business is improving where costs can be recovered, but execution decides the payoff
Dominion’s regulated utility improvement is clear; its ability to fund that improvement remains the central constraint. Approved rates and returns on utility investment are producing more earnings and operating cash. Large electricity users create a reason to build, and access to credit has allowed construction to continue.
The strongest contrary evidence is equally concrete: operating cash still falls well short of property spending, interest costs are rising, and the renewable natural gas write-down shows that committed capital can lose value. Wind cost-sharing rules and narrower project approvals also place limits on what customers will repay.
On October 30, management said it expected operating EPS in the top half of its $3.45–$3.69 full-year guidance range. That is a non-GAAP forecast, without a corresponding GAAP forecast. The near-term earnings outlook is supported by approved rates; the longer-term business outcome depends on completing projects within their recoverable costs and turning customer demand into timely cash collections. Successful execution and improved financing terms would strengthen Dominion’s capacity to invest. Further overruns, delayed collections or a heavier funding burden would weaken it even if revenue keeps rising.
Source: October 30, 2026 earnings release, “Guidance” and explanation of operating earnings. The assessment also draws on the cash, project and financing evidence cited above.
Reporting basis:
This analysis uses Dominion Energy, Inc.’s consolidated U.S. GAAP accounts in Form 10-Q, accession 0001193125-26-440697, filed October 30, 2026, for the quarter ended September 30, 2026. Dominion’s CIK is 0000715957. The combined filing also contains separate Virginia Electric and Power Company accounts; those are used only where explicitly identified. Subsidiary figures are not added again to consolidated totals.
Quarterly comparisons cover July–September; cumulative comparisons cover January–September. Financial-position comparisons use September 30, 2026 and December 31, 2025. Dollar figures are U.S. dollars. The filing says comparative reclassifications did not change net income, total assets, liabilities, equity or cash flows. Historical annual footnotes are used only with their dates stated.
The SEC submissions record confirms the filing metadata. The company-facts response retrieved for this review did not yet contain this accession’s financial facts; current-period amounts were therefore checked against the supplied complete filing’s statements and footnotes, with earnings cross-checked against the company’s October 30 release. The historical Assets fact in the U.S. GAAP taxonomy, measured in USD at December 31, 2025, confirms total assets of $115.857 billion. No older XBRL context was substituted for September 2026.
Sources: SEC submissions record; SEC company facts; 2026 Form 10-Q, cover and Note 2. Events disclosed through the October 30 filing and release are included. The latest company developments verified here are those disclosed on October 30.
Calculation notes:
A. Growth, margins and earnings ownership
Growth means the current-period amount divided by the comparable prior-period amount, minus one. Using revenue in USD million, quarterly growth is 5,617 ÷ 4,527 − 1 = 24.1%, and nine-month growth is 15,116 ÷ 12,413 − 1 = 21.8%.
Operating margin is operating profit divided by revenue. Using USD million, the quarterly calculation is 1,842 ÷ 5,617 = 32.8%, versus 1,339 ÷ 4,527 = 29.6%. The improvement is 3.2 percentage points. The nine-month margin fell from 29.5% to 23.6%.
The consolidated group earned $2,388 million over nine months, including $267 million belonging to outside subsidiary owners. Subtracting that share leaves $2,121 million attributable to Dominion. Subtracting $33 million of preferred dividends then leaves $2,088 million for common shareholders. Dividing by 881.4 million average diluted shares gives $2.37 per share. For the prior period, ($2,431 million − $33 million) ÷ 853.6 million shares gives $2.81. The quarter uses ($1,160 million − $11 million) ÷ 882.1 million shares and ($1,006 million − $11 million) ÷ 855.4 million shares.
Source: 2026 Form 10-Q, pp. 7 and 25.
B. Why operating cash exceeds reported profit
This reconciliation starts with the whole consolidated group’s profit, including outside owners, because the cash-flow statement uses that scope. It removes profits that were not cash receipts, adds costs that did not require current cash payments, and incorporates collections and payment timing.
| Nine months ended September 30, 2026; USD million | Amount |
|---|---|
| Net income including outside subsidiary owners | 2,388 |
| Add depreciation and amortization, including nuclear fuel | 2,197 |
| Add impairment and other noncash charges in the cash-flow reconciliation | 873 |
| Remove investment gains | -453 |
| Cash used by receivable movements | -372 |
| Cash used by deferred fuel and purchased-gas costs | -505 |
| Remaining disclosed adjustments and operating-balance movements, net | 560 |
| Operating cash inflow | 4,688 |
The remaining $560 million consists of the following statement entries. Positive amounts increase cash relative to reported profit; negative amounts reduce it.
| Remaining cash-flow adjustments; first nine months 2026, USD million | Amount |
|---|---|
| Deferred income taxes | 367 |
| Deferred investment tax credits | -43 |
| Other adjustments | -60 |
| Inventory movements | -68 |
| Prepayments and deposits | -174 |
| Accounts payable | -7 |
| Accrued interest, payroll and taxes | 104 |
| Derivative settlements and value changes | 460 |
| Pension and other retirement benefits | -174 |
| Other operating assets and liabilities | 155 |
| Net remaining adjustments | 560 |
Deferred taxes and investment credits recognize tax effects at a different time from cash payment. The remaining rows reconcile noncash items and when Dominion pays or collects money. They are not additional earnings.
Cash including restricted balances reconciles as $343 million opening cash + $4,688 million operating inflow − $8,749 million investing outflow + $4,281 million financing inflow = $563 million closing cash. Closing cash consists of $435 million unrestricted cash and equivalents plus $128 million restricted cash. The opening amounts were $250 million and $93 million, respectively.
Source: 2026 Form 10-Q, p. 13 and Note 2, p. 22. Cash capital spending is the statement’s $8,576 million construction/property line, not additions inferred from depreciation. The $1,320 million of accrued capital expenditures in Note 2 is a noncash disclosure and is not added to this cash-spending measure.
C. How the balance sheet and ownership accounts reconcile
At September 30, assets of $124,784 million equal liabilities of $90,369 million plus total equity of $34,415 million. At December 31, the same check is $115,857 million = $82,440 million + $33,417 million. The asset increase of $8,927 million was matched by $7,929 million more liabilities and $998 million more equity.
| Equity movement over the first nine months of 2026; USD million | Opening balance | Net change | Closing balance |
|---|---|---|---|
| Preferred stock | 991 | 0 | 991 |
| Common-stock capital | 25,892 | 67 | 25,959 |
| Retained earnings | 2,318 | 328 | 2,646 |
| Accumulated other comprehensive income or loss | -118 | 76 | -42 |
| Outside ownership interests in subsidiaries | 4,334 | 527 | 4,861 |
| Total equity | 33,417 | 998 | 34,415 |
Common-stock capital increased by $40 million of issuance and $27 million of stock awards. Retained earnings increased by $2,121 million of profit, less $1,761 million of common dividends and $33 million of preferred dividends, plus $1 million of other movements.
The $76 million improvement in the separate account for accumulated gains and losses mainly reflects changes in hedging contracts; it is not profit from electricity sales. Outside ownership increased by $267 million of earnings plus $506 million of contributions, less $246 million of distributions. No separate treasury-stock balance is presented.
Regulatory liabilities rose from $9,614 million to $10,446 million, including higher balances associated with interest-rate hedges and nuclear trusts. They represent amounts owed back through future customer rates or held for specified future costs, rather than ordinary financing debt. Deferred income-tax liabilities rose $584 million; accounts payable fell $72 million. These obligations are kept separate from the calculated debt increase of $5,705 million.
Source: 2026 Form 10-Q, pp. 8–12 and Note 11, pp. 40–42. All calculations use the filing’s rounded amounts, so displayed growth rates and margins are approximate.
This report is for information and business analysis only. It is not investment advice or a recommendation to trade any security.