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******************************************************************************************* 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 2024 consolidated financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2024 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 2024, the Company’s earnings were $147 million compared to $80 million in 2023, an increase of $67 million. The favorable variance is primarily due to a decrease in operating expenses 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 Exhibit 99.2 1

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. 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 Resource Conservation and Recovery Act of 1976 (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. See Note 9 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 are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers. 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) 2024 2023 Electric revenues (1) $ 650 $ 612 Fuel and purchased power 198 175 Total Electric margin $ 452 $ 437 Margin attributed to: Residential and commercial customers $ 230 $ 283 Industrial customers 121 80 Other 13 10 Regulatory expense recovery mechanisms 60 34 Subtotal: Retail 424 407 Wholesale margin 28 30 Total Electric margin $ 452 $ 437 Electric volumes sold in MWh attributed to: Residential and commercial customers 2,566,545 2,452,146 Industrial customers 2,233,775 1,921,852 Other customers 17,675 19,694 Total retail volumes 4,817,995 4,393,692 Wholesale (289) 510,300 Total volumes sold 4,817,706 4,903,992 (1) Includes revenues of $33 million and $17 million from the Securitization Subsidiary for the years ended December 31, 2024 and 2023, respectively. Retail Electric retail utility margins were $424 million for the year ended December 31, 2024, compared to $407 million in 2023, an increase of $17 million. Changes to margin primarily reflect a $16 million increase in revenue associated with the Securitization Subsidiary, a $11 million increase due to customer usage and growth, a $11 million increase resulting from the TDSIC, a $7 million increase resulting from the CECA and ECA, and a $4 million increase due to milder weather, partially offset by a $23 million decrease due customer rate credits associated with the securitization of the A.B. Brown power plants, and a decrease of $6 million in miscellaneous revenue. Heating degree days were 80 percent of normal in 2024 compared to 82 percent of normal in 2023, and cooling degree days were 112 percent of normal in 2024 compared to 94 percent of normal in 2023. 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) 2024 2023 MISO transmission system margin $ 24 $ 23 MISO off-system margin 4 7 Total wholesale margin $ 28 $ 30 3

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $24 million during 2024 compared to $23 million in 2023, an increase of $1 million. For the year ended December 31, 2024, margin from off-system sales was $4 million compared to $7 million in 2023, a decrease of $3 million. The base rate changes implemented in May 2011 require wholesale margin from off-system sales earned above or below $8 million per year to be shared equally with customers. 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) 2024 2023 Natural Gas revenues $ 121 $ 128 Utility natural gas 29 30 Total Natural Gas margin $ 92 $ 98 Margin attributed to: Residential & commercial customers $ 76 $ 72 Industrial customers 14 14 Other 1 1 Regulatory expense recovery mechanisms 1 11 Total Natural Gas margin $ 92 $ 98 Sold and transported volumes in MDth attributed to: Residential and commercial customers 8,955 8,208 Industrial customers 34,105 30,288 Total sold and transported volumes 43,060 38,496 For the year ended December 31, 2024, Natural Gas margin was $92 million compared to $98 million in 2023, a decrease of $6 million. The decrease was primarily due to Operation and maintenance cost through our Compliance and System Improvement Adjustment collected in 2023. Weather has relatively no impact on customer margin due to the Company's rate design. Heating degree days were 76 percent of normal in 2024 compared to 77 percent of normal in 2023. Operating Expenses Operation and Maintenance For the year ended December 31, 2024, Operation and maintenance expenses were $179 million compared to $251 million in 2023, a decrease of $72 million. The decrease was primarily due to lower generating facility costs associated with the A.B. Brown 1 and 2 as well as Warrick 4 power plants being no longer in operation during 2024 and a decrease in pass through costs related to Nitrogen Oxides (NOX) allowances. Depreciation and Amortization For the year ended December 31, 2024, Depreciation and amortization expense was $136 million compared to $146 million in 2023, a decrease of $10 million. The decrease was primarily due to a full year in 2024 and partial year in 2023 of securitization for the A.B. Brown assets that were no longer operational. In addition, the Company exited joint operations of the Warrick Power Plant on January 1, 2024, resulting in lower depreciation expense. 4

SELECTED ELECTRIC OPERATING STATISTICS For the Year Ended December 31, 2024 2023 OPERATING REVENUES (in millions): Residential $ 246 $ 240 Commercial 173 162 Industrial 190 155 Other 13 12 Total Retail 622 569 Net Wholesale Revenues 4 20 Transmission Revenues 24 23 $ 650 $ 612 MARGIN (In millions): Residential $ 139 $ 170 Commercial 91 113 Industrial 121 80 Other 13 10 Regulatory expense recovery mechanisms 60 34 Total Retail 424 407 Wholesale power and transmission system 28 30 $ 452 $ 437 ELECTRIC SALES (In MWh): Residential 1,421,485 1,335,767 Commercial 1,145,060 1,116,379 Industrial 2,233,775 1,921,852 Other Sales - Street Lighting 17,675 19,694 Total Retail 4,817,995 4,393,692 Wholesale (289) 510,300 4,817,706 4,903,992 CUSTOMER COUNT: Residential 133,866 133,201 Commercial 19,411 19,139 Industrial 110 114 Other 20 39 153,407 152,493 WEATHER AS A % OF NORMAL: Cooling Degree Days 112 % 94 % Heating Degree Days 80 % 82 % 5

SELECTED GAS OPERATING STATISTICS For the Year Ended December 31, 2024 2023 OPERATING REVENUES (in millions): Residential $ 81 $ 84 Commercial 27 29 Industrial 12 13 Other 1 1 $ 121 $ 127 MARGIN (In millions): Residential $ 59 $ 56 Commercial 17 16 Industrial 14 14 Other 1 1 Regulatory expense recovery mechanisms 1 11 $ 92 $ 98 GAS SOLD and TRANSPORTED (In MDth): Residential 5,756 5,343 Commercial 3,199 3,210 Industrial 34,105 30,861 43,060 39,414 CUSTOMER COUNT Residential 105,344 104,725 Commercial 10,511 10,473 Industrial 136 133 115,991 115,331 6