Document

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 2023 consolidated financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2023 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 gas and electric services.

In 2023, the Company’s earnings were $80 million compared to $109 million in 2022, a decrease of $29 million. The unfavorable variance is primarily due to an decrease in margin due to customer rate credits associated with the securitization of the A.B. Brown power plants.

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.

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.

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.

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.

MISO charges and other reliability costs and revenues incurred to serve retail electric customers are recovered through the RCRA and MCRA. MISO charges include specific charges under the MISO’s 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.

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 is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is primarily driven by the continuing investment that is being made to ensure the safety and reliability of the system and normal increases in operating expenses. The rate case reflects a proposed 10.4% ROE on a 55% equity ratio. A hearing is scheduled for late-April through mid-May 2024. A final order is expected in the fourth quarter of 2024.

Throughout this discussion, the terms Natural Gas margin and Electric margin are used. Natural Gas margin is calculated as Natural Gas revenues less the Cost of gas sold. Electric margin is calculated as Electric revenues less Cost of fuel & 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.


	Year Ended December 31,
(In millions)	2023		2022

Electric revenues (1)	$	612	$	696
Cost of fuel & purchased power	175		222
Total Electric margin	$	437	$	474
Margin attributed to:
Residential & commercial customers	$	283	$	285
Industrial customers	80		93
Other	10		10
Regulatory expense recovery mechanisms	34		44
Subtotal: Retail	407		432
Wholesale margin	30		42
Total Electric margin	$	437	$	474
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,452,146		2,608,208
Industrial customers	1,921,852		1,967,271
Other customers	19,694		20,255
Total retail volumes	4,393,692		4,595,734
Wholesale	510,300		882,864
Total volumes sold	4,903,992		5,478,598

Electric retail utility margins were $407 million for the year ended December 31, 2023, compared to $432 million in 2022, a decrease of $25 million. Changes to margin primarily reflect a $28 million decrease due customer rate credits associated with the securitization of the A.B. Brown power plants, a $11 million decrease due to milder weather, a $2 million decrease due to customer usage and growth, partially offset by an increase of $1 million as a result of the CECA and ECA, a $8 million increase resulting from the TDSIC, and a $3 million increase in miscellaneous revenue. Heating degree days were 82 percent of normal in 2023 compared to 107 percent of normal in 2022, and cooling degree days were 94 percent of normal in 2023 compared to 103 percent of normal in 2022.

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:

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $23 million during 2023 compared to $26 million in 2022, a decrease of $3 million.

For the year ended December 31, 2023, margin from off-system sales was $7 million compared to $16 million in 2022, a decrease of $9 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.


	Year Ended December 31,
(In millions)	2023		2022
Natural Gas revenues	$	128	$	146
Cost of gas sold	30		58
Total Natural Gas margin	$	98	$	88
Margin attributed to:
Residential & commercial customers	$	72	$	70
Industrial customers	14		14
Other	1		1
Regulatory expense recovery mechanisms	11		3
Total Natural Gas margin	$	98	$	88
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	8,208		10,957
Industrial customers	30,288		31,573
Total sold & transported volumes	38,496		42,530

Natural Gas margin was $98 million for the year ended December 31, 2023 compared to $88 million in 2022, an increase of $10 million. The increase in margin was primarily due to recovery of previously deferred O&M cost through our Compliance and System Improvement Adjustment (CSIA) rider. Weather has relatively no impact on customer margin due to the Company's rate design. The decrease in sold and transported volumes was primarily due to weather. Heating degree days were 77 percent of normal in 2023 compared to 98 percent of normal in 2022.

For the year ended December 31, 2023, Operation and maintenance expenses were $251 million compared to $247 million in 2022, an increase of $4 million. The increase in operations and maintenance costs are primarily due to increased pass through costs related to Compliance and System Improvement Adjustment (CSIA) that were partially offset by lower generating facility costs at the end of 2023.

Depreciation and amortization expense was $146 million in 2023, compared to $144 million in 2022, an increase of $2 million. The increase resulted from additional utility plant investments placed into service, including property, plant, and equipment assets purchased from CenterPoint Energy at it's net carrying value as of the purchase date.


	For the Year Ended December 31,
	2023			2022
OPERATING REVENUES (in millions):
Residential	$	240		$	254
Commercial	162			180
Industrial	155			187
Other	12			9
Total Retail	569			630
Net Wholesale Revenues	20			40
Transmission Revenues	23			26
	$	612		$	696
MARGIN (In millions):
Residential	$	170		$	172
Commercial	113			113
Industrial	80			93
Other	10			10
Regulatory expense recovery mechanisms	34			44
Total Retail	407			432
Wholesale power & transmission system	30			42
	$	437		$	474

ELECTRIC SALES (In MWh):
Residential	1,335,767			1,398,174
Commercial	1,116,379			1,210,034
Industrial	1,921,852			1,967,271
Other Sales - Street Lighting	19,694			20,255
Total Retail	4,393,692			4,595,734
Wholesale	510,300			882,864
	4,903,992			5,478,598

CUSTOMER COUNT:
Residential	133,201			132,402
Commercial	19,178			19,135
Industrial	114			114

	152,493			151,651

WEATHER AS A % OF NORMAL:
Cooling Degree Days	94		%	103		%
Heating Degree Days	82		%	107		%


	For the Year Ended December 31,
	2023		2022
OPERATING REVENUES (in millions):
Residential	$	84	$	94
Commercial	29		39
Industrial	13		12
Other	1		1
	$	127	$	146

MARGIN (In millions):
Residential	$	56	$	55
Commercial	16		16
Industrial	14		14
Other	1		1
Regulatory expense recovery mechanisms	11		2
	$	98	$	88

GAS SOLD & TRANSPORTED (In MDth):
Residential	5,343		6,961
Commercial	3,210		3,996
Industrial	30,861		31,573
	39,414		42,530

CUSTOMER COUNT
Residential	104,725		104,495
Commercial	10,473		10,531
Industrial	133		119
	115,331		115,145