******************************************************************************************* The following discussion and analysis provides additional information regarding Southern Indiana Gas and Electric Company’s (the Company) results of operations that is supplemental to, and should be read in conjunction with, the information provided in the Company’s 2025 consolidated financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2025 Annual Report on Form 10-K as it relates to the Company, which includes risk factors and forward looking statements. The Company generates revenue primarily from the delivery of natural gas and electric service to its customers, and the Company’s primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of natural gas and electric services. Executive Summary of Results of Operations Operating Results In 2025, the Company reported net income of $150 million compared to $147 million in 2024, an increase of $3 million. The favorable variance is primarily due to an increase in margin as further described below. The Regulatory Environment Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters, are regulated by the Indiana Utility Regulatory Commission (IURC). In the Company’s natural gas service territory, normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to residential and commercial customers due to weather and changing consumption patterns. In addition to these mechanisms, the IURC has authorized gas and electric infrastructure replacement programs, which allow for recovery of these investments outside of a base rate case proceeding. Further, rates charged to natural gas customers contain a gas cost adjustment (GCA) and electric rates contain a fuel adjustment clause (FAC). Both of these cost tracker mechanisms allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel. The Company utilizes similar mechanisms for other material operating costs, which allow for changes in revenue outside of a base rate case. Rate Design Strategies Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company’s utilities have implemented conservation programs. In the Company’s natural gas service territory, NTA and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. In the Company's natural gas service territory, the IURC has authorized bare steel and cast iron replacement programs. State laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. The Company has received approval to implement these mechanisms. In 2017, the Company's electric service territory started recovering certain costs of electric distribution and transmission infrastructure replacement investments. The electric service territory also currently recovers certain transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives. Tracked Operating Expenses Gas costs and fuel costs incurred to serve customers are two of the Company’s most significant operating expenses. Rates charged to natural gas customers contain a GCA. The GCA allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on actual experience and subject to caps that are based on historical experience. Electric rates contain a FAC that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an approved variable benchmark based on The New York Mercantile Exchange (NYMEX) natural gas prices, is also timely recovered through the FAC. Exhibit 99.2 1

GCA and FAC procedures involve periodic filings and IURC hearings to establish price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred. The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. In the periods presented, the Company has not been impacted by the earnings test. Midcontinent Independent System Operator (MISO) charges and other reliability costs and revenues incurred to serve retail electric customers are recovered through the Reliability Cost and Revenue Adjustment (RCRA) and MISO Cost and Revenue Adjustment (MCRA). MISO charges include specific charges under the MISO’s Federal Energy Regulatory Commission (FERC) approved tariff for items such as reactive power, scheduling, and transmission network charges that are socialized among various MISO members. Reliability costs and revenues include non-fuel costs of purchased power and costs and credits associated with certain interruptible customers. Gas pipeline integrity management operating costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of typical base rate recovery. In addition, certain operating costs, including depreciation associated with federally mandated investments, gas and electric distribution and transmission infrastructure replacement investments, and regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs. Base Rate Orders On December 5, 2023, the Company filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase was approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase was primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a forecasted 55% equity ratio. The Company reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflected a proposed 9.8% ROE on a forecasted 55% equity ratio. The requested increase was lowered to $80 million, an 11% increase. The Company received a final order on February 3, 2025 approving the settlement with one modification that effectively capped the residential increase to 1.15% of the total increase, allocating the difference to other commercial and industrial customers. The final order approves the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million. The final phase of rates, Phase 2, was implemented with an effective date of March 5, 2026. See Note 10 to the consolidated financial statements for more specific information on the significant regulatory proceedings involving the Company. Operating Trends Margin Throughout this discussion, the terms Natural Gas margin and Electric margin are used. Natural Gas margin is calculated as Natural gas revenues less Utility natural gas. Electric margin is calculated as Electric revenues less Fuel and purchased power. The Company believes Natural Gas and Electric margins, together with net income, provide useful indicators for assessing performance. While revenues reflect overall activity levels, gas prices and fuel and purchased power costs can be volatile and are generally collected from customers on a dollar-for-dollar basis. In addition, the Company separately reflects regulatory expense recovery mechanisms within Natural Gas margin and Electric margin. These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin. 2

Electric Margin (Electric revenues less Fuel and purchased power) Electric margin and volumes sold by customer type follows: Year Ended December 31, (In millions) 2025 2024 Electric revenues (1) $ 782 $ 650 Fuel and purchased power 270 198 Total Electric margin $ 512 $ 452 Margin attributed to: Residential and commercial customers $ 240 $ 230 Industrial customers 142 121 Other 13 13 Regulatory expense recovery mechanisms 71 60 Subtotal: Retail 466 424 Wholesale margin 46 28 Total Electric margin $ 512 $ 452 Electric volumes sold in MWh attributed to: Residential and commercial customers 2,598,456 2,566,545 Industrial customers 2,380,611 2,233,775 Other customers 12,156 17,675 Total retail volumes 4,991,223 4,817,995 Wholesale 1,618 (289) Total volumes sold 4,992,841 4,817,706 (1) Includes revenues of $31 million and $33 million from the Securitization Subsidiary for the years ended December 31, 2025 and 2024, respectively. Retail Electric retail utility margin was $466 million for the year ended December 31, 2025, compared to $424 million in 2024, an increase of $42 million. The increase was primarily driven by new customer rates implemented following the final order in the rate case in February 2025, an increase in customer usage and growth, and an increase related to weather impacts. Heating degree days were 99 percent of normal in 2025 compared to 80 percent of normal in 2024, and cooling degree days were 107 percent of normal in 2025 compared to 112 percent of normal in 2024. Margin from Wholesale Electric Activities The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of the MISO’s regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off- system margin and transmission system margin follows: Year Ended December 31, (In millions) 2025 2024 MISO transmission system margin $ 26 $ 24 MISO off-system margin 20 4 Total wholesale margin $ 46 $ 28 Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $26 million during 2025 compared to $24 million in 2024, an increase of $2 million. For the year ended December 31, 2025, margin from off-system sales was $20 million compared to $4 million in 2024, an increase of $16 million. The base rate changes implemented in February 2025 require wholesale margin from off-system sales to be fully returned to customers under the approved rate case mechanism. 3

Natural Gas Margin (Natural Gas revenues less Utility natural gas) Natural Gas margin and throughput by customer type follows: Year Ended December 31, (In millions) 2025 2024 Natural Gas revenues $ 139 $ 121 Utility natural gas 41 29 Total Natural Gas margin $ 98 $ 92 Margin attributed to: Residential & commercial customers $ 80 $ 76 Industrial customers 16 14 Other — 1 Regulatory expense recovery mechanisms 2 1 Total Natural Gas margin $ 98 $ 92 Sold and transported volumes in MDth attributed to: Residential and commercial customers 10,095 8,955 Industrial customers 39,924 34,105 Total sold and transported volumes 50,019 43,060 For the year ended December 31, 2025, Natural Gas margin was $98 million compared to $92 million in 2024, an increase of $6 million. The increase was primarily due to increased revenues driven by customer rates and the impact of the change in rate design. While weather has relatively no impact on customer margin due to the Company's rate design, heating degree days were 93 percent of normal in 2025 compared to 76 percent of normal in 2024. Operating Expenses Operation and Maintenance For the year ended December 31, 2025, Operation and maintenance expenses were $206 million compared to $179 million in 2024, an increase of $27 million. The increase was primarily driven by higher generating facility costs associated with the new natural gas combustion turbines at the previous site of the A.B. Brown power plant in Posey County, Indiana and Posey Solar, both of which began operations in 2025. Depreciation and Amortization For the year ended December 31, 2025, Depreciation and amortization expense was $163 million compared to $136 million in 2024, an increase of $27 million. The Company had a larger plant in service balance as both the new natural gas combustion turbines at the previous site of the A.B. Brown power plant in Posey County, Indiana and Posey Solar were placed in service during 2025, resulting in higher depreciation expense. 4

SELECTED ELECTRIC OPERATING STATISTICS For the Year Ended December 31, 2025 2024 OPERATING REVENUES (in millions): Residential $ 293 $ 246 Commercial 194 173 Industrial 236 190 Other 13 13 Total retail 736 622 Net wholesale revenues 20 4 Transmission revenues 26 24 $ 782 $ 650 MARGIN (In millions): Residential $ 154 $ 139 Commercial 86 91 Industrial 142 121 Other 13 13 Regulatory expense recovery mechanisms 71 60 Total retail 466 424 Wholesale power and transmission system 46 28 $ 512 $ 452 ELECTRIC SALES (In MWh): Residential 1,446,133 1,421,485 Commercial 1,152,323 1,145,060 Industrial 2,380,611 2,233,775 Other sales - street lighting 12,156 17,675 Total retail 4,991,223 4,817,995 Wholesale 1,618 (289) 4,992,841 4,817,706 CUSTOMER COUNT: Residential 134,695 133,866 Commercial 19,596 19,411 Industrial 111 110 Other 20 20 154,422 153,407 WEATHER AS A % OF NORMAL: Cooling degree days 107 % 112 % Heating degree days 99 % 80 % 5

SELECTED GAS OPERATING STATISTICS For the Year Ended December 31, 2025 2024 OPERATING REVENUES (in millions): Residential $ 91 $ 81 Commercial 34 27 Industrial 13 12 Other 1 1 $ 139 $ 121 MARGIN (In millions): Residential $ 62 $ 59 Commercial 18 17 Industrial 16 14 Other — 1 Regulatory expense recovery mechanisms 2 1 $ 98 $ 92 GAS SOLD and TRANSPORTED (In MDth): Residential 6,420 5,756 Commercial 3,675 3,199 Industrial 39,924 34,105 50,019 43,060 CUSTOMER COUNT Residential 105,497 105,344 Commercial 10,518 10,511 Industrial 148 136 116,163 115,991 6