AddedRisk Factors
they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
10-K 0001109357-26-000018 (2026-02-12) vs 10-K 0001109357-25-000043 (2025-02-12)
| Section | Compared text | Words now | Changed |
|---|---|---|---|
| Risk Factors | Item 1A | 6,332 | 9.2% |
| MD&A | Item 7 | 19,524 | 15.9% |
| Legal Proceedings | Item 3, via Note 16 – Commitments and Contingencies (All Registrants) | 4,593 | 25.6% |
| Accounting Policies | Item 8, Note 1 – Significant Accounting Policies | 4,753 | 14.8% |
The redline: what was cut and what was added
In each section, the paragraph that changed most, marked against last year's 10-K:
cut words struck through, new words highlighted and underlined.
Legal Proceedings 204 words changed in this paragraph; it is 63% similar to last year's version.
Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to the DOEE. In October 2022, the DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. The landside FS was approved by the DOEE on March 15, 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. Following the completion of each FS, the DOEE will issue a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying the remedial actions determined to be necessary for the area in question. On October 3, 2023, the The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.
Source: Item 3, via Note 16 – Commitments and Contingencies (All Registrants), 10-K 0001109357-26-000018 vs Item 3, via Note 18 – Commitments and Contingencies (All Registrants), 10-K 0001109357-25-000043
MD&A 181 words changed in this paragraph; it is 52% similar to last year's version.
On August 4, 2022, Exelon executed an equity distribution agreement (“Equity (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement. In the fourth quarter 2023, Exelon issued approximately 3.6 a total of 23.6 million shares of Common common stock at an average gross price of $39.58 per share. In the third quarter 2024, Exelon issued approximately 4 million shares of Common Stock at an average gross price of $37.60 per share. The with net proceeds from of $979 million under these agreements in the 2023 and 2024 issuances were $140 million and $148 million, which were used for general corporate purposes. As of years ended December 31, 2024, $708 million of Common stock remained available for sale pursuant to the ATM program. 2023 through December 31, 2025.
Source: Item 7, 10-K 0001109357-26-000018 vs Item 7, 10-K 0001109357-25-000043
Risk Factors 125 words changed in this paragraph; it is 56% similar to last year's version.
Exelon does not generate the electricity it delivers. The Utility Registrants purchase, transmit, and distribute electric power obtained from power generation facilities owned by third parties. This power is primarily procured through contracts as directed by the Utility Registrants’ respective state laws and regulatory commission actions from various approved bidders or from purchases on the PJM operated markets. Third-party power generation may be insufficient to meet our customers’ electricity demand in the short- and medium-term because of extreme weather, fuel security, market procurement, regulatory requirements, operational issues, maintenance outages, inflexibility of demand, or financial uncertainty impacting existing or prospective generation facilities. Faster energy demand growth, acceleration of generator retirements, or the limited entry of new generating resources in any of the Utility Registrants’ respective service territories may result in a longer-term power generation capacity shortfall. Exelon has forecast substantial increases in load, driven largely by the increasing use of data processing facilities dedicated to artificial intelligence technologies. If third-party power generation capacity is insufficient to meet any Utility Registrant’s customers’ electricity demand or customers’ electricity demand across PJM over any period, transmission and distribution services may be diminished or interrupted, and results of operations, financial condition, and cash flows could be adversely affected.
Source: Item 1A, 10-K 0001109357-26-000018 vs Item 1A, 10-K 0001109357-25-000043
Accounting Policies 50 words changed in this paragraph; it is 80% similar to last year's version.
For derivatives intended to serve as economic hedges, which are not designated for hedge accounting, changes in fair value each period are recognized in earnings or as a regulatory asset or liability. Amounts recognized in earnings are recorded in Electric operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Changes in fair value are also recorded as a regulatory asset or liability when there is an ability to recover or return the associated costs or benefits in accordance with regulatory requirements. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of the hedged item. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.
Source: Item 8, Note 1 – Significant Accounting Policies, 10-K 0001109357-26-000018 vs Item 8, Note 1 – Significant Accounting Policies, 10-K 0001109357-25-000043
Every change, by type
Sentences and paragraphs of EXC's Risk Factors and MD&A, 10-K 2026-02-12 against 10-K 2025-02-12. Each links to the text at sec.gov.
Quiet changes are sentences kept from last year with one to four words changed, at least one of them a hedge, a modal or a qualifier
(may, could, will, not, significant, material…). A year or date rolling forward is not counted.
The full word list
adverse, adversely, all, although, anticipate, anticipates, any, approximately, believe, believes, can, cannot, certain, could, expect, expects, generally, however, if, intend, intends, largely, likely, many, material, materially, may, might, most, must, never, no, not, possible, primarily, probable, should, significant, significantly, some, substantial, substantially, unlikely, will, would
AddedRisk Factors
implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
AddedRisk Factors
Energy storage systems provide additional resources for enhancing grid reliability and stability by providing rapid response capabilities, allowing the injection and absorption of power during electric supply and demand imbalances. As forecasted load increases, the lack of sufficient energy storage growth may also lead to greater price volatility and challenges in power services for customers.
AddedRisk Factors
amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants).
RemovedRisk Factors
RemovedRisk Factors
RemovedRisk Factors
RemovedRisk Factors
RemovedRisk Factors
RewordedRisk Factors
However, the Registrants’ physical facilities could be at greater risk of damage as changes in the global climate affect temperature and weather patterns, including if such climate changes result in more intense, frequent and extreme weather events, elevated or decreased levels of precipitation, sea level rise, increased temperatures, wildfires and/or other effects.
RewordedRisk Factors
Third-party power generation may be insufficient to meet our customers’ electricity demand in the short- and medium-term because of extreme weather, fuel security, market procurement, regulatory requirements, operational issues, maintenance outages, inflexibility of demand, or financial uncertainty impacting existing or prospective generation facilities.
RewordedRisk Factors
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain, are subject to operational failure and could be impacted by lack of availability of disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs which could result in potential liability (All Registrants).
RewordedRisk Factors
These factors could affect the Registrants’ consolidated financial statements through, among other things, increased Operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation over shortened remaining asset useful lives.
RewordedRisk Factors
If the Utility Registrants were found in non-compliance with the Federal or state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
RewordedRisk Factors
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties or regulatory financial requirements, it would be required to provide significant amounts of collateral that could affect its liquidity and could experience higher borrowing costs (All Registrants).
RewordedRisk Factors
See Note 3 1 — Regulatory Matters Significant Accounting Policies and Note 11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for additional information.
RewordedRisk Factors
As is the case for electric utilities generally, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
RewordedRisk Factors
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by the insufficiency of generation or energy storage resources to meet demand, transmission congestion congestion, and failures of neighboring transmission systems (All Registrants).
RewordedRisk Factors
Exelon has forecast substantial increases in load, driven largely by the increasing use of data processing facilities dedicated to cloud services, artificial intelligence technologies. technologies, and other applications.
RewordedRisk Factors
Additionally, earnings may be impacted due to changes in federal or local/state tax laws, and the inherent difficulty of estimating potential tax effects of ongoing business decisions.
AddedMD&A
On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. In the fourth quarter of 2025, Exelon, ComEd, and BGE elected to decline the previously awarded Middle Mile Grant (MMG) and Exelon and PECO elected to decline the previously awarded Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE) grant. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, PECO, and BGE will continue to evaluate whether to move forward with these projects.
AddedMD&A
On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that are no longer eligible to be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations ineligible to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
AddedMD&A
As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately
AddedMD&A
$49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter of 2025. Additional disbursements from the state of Maryland were received by BGE, Pepco, and DPL on February 3, 2026 for approximately $49 million, $21 million, and $8 million, respectively. These amounts will also be used to reduce residential customer receivables in the first quarter of 2026.
AddedMD&A
In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to Regulatory assets. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs. As of December 31, 2025, the Regulatory asset has a remaining balance of $10 million.
AddedMD&A
In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the Residential Universal Bill Credit (RUBC), which will be funded by the NJBPU. The program provided a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued all bill credits to residential customers in September and October. As of December 31, 2025, there is no Regulatory liability remaining.
AddedMD&A
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
AddedMD&A
The Registrants allowance for credit losses on customer receivables is estimated based on historical experience, current conditions, and forward-looking risk factors. Historical experience considered include
AddedMD&A
2025 2024 (Unfavorable) Favorable Variance Operating revenues $ 7,267 $ 8,219 $ (952) Operating expenses Purchased power 1,782 3,042 1,260 Operating and maintenance 1,710 1,703 (7) Depreciation and amortization 1,560 1,514 (46) Taxes other than income taxes 409 376 (33) Total operating expenses 5,461 6,635 1,174 Gain on sales of assets — 5 (5) Operating income 1,806 1,589 217 Other income and (deductions) Interest expense, net (530) (501) (29) Other, net 132 94 38 Total other income and (deductions) (398) (407) 9 Income before income taxes 1,408 1,182 226 Income taxes 261 116 (145) Net income $ 1,147 $ 1,066 $ 81
AddedMD&A
(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.
AddedMD&A
(b)Reflects the derecognition of regulatory assets for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act, partially offset by the absence of capital write-offs included in 2024. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.
AddedMD&A
2025 2024 Favorable (Unfavorable) Variance Operating revenues $ 1,718 $ 1,628 $ 90 Operating expenses Purchased power 808 698 (110) Operating and maintenance 328 368 40 Depreciation and amortization 248 278 30 Taxes other than income taxes 9 9 — Total operating expenses 1,393 1,353 (40) Gain on sale of assets 2 — 2 Operating income 327 275 52 Other income and (deductions) Interest expense, net (82) (79) (3) Other, net 10 14 (4) Total other income and (deductions) (72) (65) (7) Income before income taxes 255 210 45 Income taxes 67 55 (12) Net income $ 188 $ 155 $ 33
RemovedMD&A
RemovedMD&A
RemovedMD&A
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RemovedMD&A
RemovedMD&A
RemovedMD&A
RemovedMD&A
RemovedMD&A
RemovedMD&A
RemovedMD&A
RemovedMD&A
RewordedMD&A
Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Approved Revenue Requirement Increase Approved ROE Approval Date Rate Effective Date ComEd - Illinois January 17, 2023 Electric $1,487 $1,045 8.905% December 19, 2024 January 1, 2024 April 26, 2024 (amended on September 11, 2024) Electric $624 $623 9.89% October 31, 2024 January 1, 2025 PECO - Pennsylvania March 28, 2024 Electric $464 $354 N/A December 12, 2024 January 1, 2025 Natural Gas $111 $78 BGE - Maryland February 17, 2023 Electric $313 $179 9.50% December 14, 2023 January 1, 2024 Natural Gas $289 $229 9.45% Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $186 $123 9.50% November 26, 2024 January 1, 2025 Pepco - Maryland October 26, 2020 (amended March 31, 2021) Electric $104 $52 9.55% June 28, 2021 June 28, 2021 May 16, 2023 (amended February 23, 2024) Electric $111 $45 9.50% June 10, 2024 April 1, 2024 DPL - Maryland May 19, 2022 Electric $38 $29 9.60% December 14, 2022 January 1, 2023 DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $39 $28 9.60% April 18, 2024 July 15, 2023 September 20, 2024 (amended September 5, 2025) Natural Gas $37 $22 9.60% December 17, 2025 January 1, 2026 ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $92 $45 9.60% November 17, 2023 December 1, 2023 November 21, 2024 Electric $109 $54 9.60% November 21, 2025 December 1, 2025
RewordedMD&A
Distribution Revenue increased for the year ended December 31, 2024 2025 compared to the same period in 2023 2024 primarily due to favorable impacts of the higher Delaware electric distribution DSIC rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024. 2025.
RewordedMD&A
At December 31, 2024 2025 Short-term Financing Authority Remaining Long-term Financing Authority Commission Expiration Date Amount Commission Expiration Date Amount ComEd ComEd(a)(b) FERC December 31, 2025 $ 2,500 ICC January 1, 2027 & 2027, May 1, 2027 $ 2,318 PECO(b) 1,593 PECO(a) FERC December 31, 2025 1,500 PAPUC December 31, 2024 — BGE 2027 1,850 BGE(a) FERC December 31, 2025 700 MDPSC N/A 300 Pepco(a) 1,850 Pepco(a)(c)(d) FERC December 31, 2025 500 MDPSC / DCPSC December 31, 2025 375 DPL(a) 100 DPL(a)(c)(e) FERC December 31, 2025 500 MDPSC / DEPSC December 31, 2025 375 ACE(c) 172 ACE(f) NJBPU December 31, 2025 January 1, 2028 350 NJBPU December 31, 2024 375 2026 625
RewordedMD&A
RewordedMD&A
As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.
RewordedMD&A
On August 4, 2022, May 2, 2025, Exelon executed an additional equity distribution agreement (“Equity ("2025 Equity Distribution Agreement”), Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. $2.5 billion through May 2, 2028.
RewordedMD&A
Electric Retail Deliveries to Customers (in GWhs) 2025 2024 2023 % Change Weather - Normal % Change(b) Residential 14,078 13,963 13,262 5.3% 0.2% 0.8% (1.5)% Small commercial & industrial 7,537 7,683 7,367 4.3% 1.3% (1.9)% (3.0)% Large commercial & industrial 13,683 13,889 13,638 1.8% 0.6% (1.5)% (2.2)% Public authorities & electric railroads 678 613 606 1.2% 1.2% 10.6% 11.0% Total electric retail deliveries(a) 35,976 36,148 34,873 3.7% 0.6% (0.5)% (1.9)%
RewordedMD&A
Net income increased by $35 $11 million primarily due to higher distribution rates and lower contracting costs due to transmission rates, partially offset by the absence of the ACE employee strike, partially offset by Maryland multi-year plans reconciliations, lower AFUDC income, and increases in depreciation interest expense and interest depreciation expense.
RewordedMD&A
Electric Retail Deliveries to Delaware Customers (in GWhs) 2025 2024 2023 % Change Weather - Normal % Change (b) Residential 3,288 3,227 3,065 5.3% 3.1% 1.9% (1.4)% Small commercial & industrial 1,459 1,445 1,399 3.3% 2.2% 1.0% 0.2% Large commercial & industrial 3,049 3,019 3,071 (1.7)% (1.9)% 1.0% 0.6% Public authorities & electric railroads 31 32 33 (3.0)% (2.9)% (3.1)% (3.5)% Total electric retail deliveries(a) 7,827 7,723 7,568 2.0% 0.9% 1.3% (0.3)%
RewordedMD&A
Natural Gas Retail Deliveries to Delaware Customers (in mmcf) 2025 2024 2023 % Change Weather - Normal % Change(b) Residential 9,052 7,810 7,326 6.6% 0.9% 15.9% 7.5% Small commercial & industrial 4,339 3,801 3,660 3.9% (1.9)% 14.2% 5.5% Large commercial & industrial 1,680 1,674 1,588 5.4% 5.4% 0.4% 0.4% Transportation 6,355 6,206 6,004 3.4% 1.6% 2.4% (0.3)% Total natural gas deliveries(a) 21,426 19,491 18,578 4.9% 0.9% 9.9% 4.1%
RewordedMD&A
Qualified Pension Plans Non-Qualified Pension Plans OPEB Exelon $ 275 325 $ 16 19 $ 45 48 ComEd 187 2 21 217 3 22 PECO 9 1 1 4 BGE 26 1 32 2 14 PHI 36 8 48 7 6 Pepco 1 1 — 6 DPL 1 — 1 — ACE 4 14 — 1 —
RewordedMD&A
Quiet changesMD&A
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that is are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
Quiet changesMD&A
Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period, and all of its costs of doing so will be is recovered through a new rider.
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