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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 2022 financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2022 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 2022, the Company’s earnings were $109 million compared to $106 million in 2021, an increase of $3 million. The favorable variance is primarily due to an increase in margin resulting from the Environmental Cost Adjustment (ECA), the Transmission, Distribution and Storage System Improvement Charge (TDSIC), the Compliance and System Improvement Adjustment (CSIA), and wholesale power marketing.

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 commission 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 commission 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.

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.

The Company's electric territory received an order in April 2011, with rates effective May 2011, and its gas territory received an order and implemented rates in October 2021. The orders authorize a return on equity of 10.40% on the electric operations and 9.7% for the gas operations. The authorized returns reflect the impact of rate design strategies that have been authorized by the IURC.

On October 30, 2020, and as subsequently amended, CEI South filed its gas base rate case with the IURC seeking approval for a revenue increase of approximately $29 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of CEI South’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 5.99% on total rate base of approximately $469 million. CEI South has utilized a projected test year, reflecting its 2021 budget as the basis for the revenue increase requested and proposes to implement rates in two phases. On April 23, 2021, a Stipulation and Settlement Agreement was filed resolving all issues in the case. The settlement recommended a revenue increase of $21 million based on a 9.7% ROE and an overall after-tax rate of return of 5.78% on total rate base of approximately $469 million. A settlement hearing was held on June 24, 2021. On October 6, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in October 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, became effective in March 2022.

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

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 thousands)	2022		2021

Electric revenues	$	695,930	$	629,314
Cost of fuel & purchased power	221,693		186,094
Total Electric margin	$	474,237	$	443,220
Margin attributed to:
Residential & commercial customers	$	285,439	$	277,036
Industrial customers	93,010		98,670
Other	9,709		5,685
Regulatory expense recovery mechanisms	44,090		24,275
Subtotal: Retail	432,248		405,666
Wholesale margin	41,989		37,554
Total Electric margin	$	474,237	$	443,220
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,608,208		2,582,437
Industrial customers	1,967,271		2,040,869
Other customers	20,255		20,665
Total retail volumes	4,595,734		4,643,971
Wholesale	882,864		1,457,358
Total volumes sold	5,478,598		6,101,329

Electric retail utility margins were $432.2 million for the year ended December 31, 2022, compared to $405.7 million in 2021, an increase of $26.5 million. Results primarily reflect an increase in margin of $4.5 million as a result of the CECA and ECA, a $6.0 million increase resulting from the TDSIC, and a $20.6 million increase related to pass-through expenses, partially offset by a $3.3 million decrease in margin due to customer usage. Heating degree days were 107 percent of normal in 2022 compared to 101 percent of normal in 2021, and cooling degree days were 103 percent of normal in 2022 compared to 93 percent of normal in 2021.

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:

For the year ended December 31, 2022, margin from off-system sales was $16.5 million compared to $13.4 million in 2021, an increase of $3.1 million. The base rate changes implemented in May 2011 require wholesale margin from off-system sales earned above or below $7.5 million per year to be shared equally with customers.


	Year Ended December 31,
(In thousands)	2022		2021
Natural Gas revenues	$	145,896	$	134,345
Cost of gas sold	57,846		54,728
Total Natural Gas margin	$	88,050	$	79,617
Margin attributed to:
Residential & commercial customers	$	70,468	$	57,941
Industrial customers	13,986		12,788
Other	1,057		889
Regulatory expense recovery mechanisms	2,539		7,999
Total Natural Gas margin	$	88,050	$	79,617
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	10,957		9,955
Industrial customers	31,573		29,115
Total sold & transported volumes	42,530		39,070

Natural Gas margin was $88.1 million for the year ended December 31, 2022 compared to $79.6 million in 2021, an increase of $8.4 million. The increase in margin was largely due to increased returns on the Compliance and System Improvement Adjustment (CSIA) along with a new rate order implemented in October 2021. Weather has relatively no impact on customer margin due to the Company's rate design. The increase in sold and transported volumes was primarily due to weather. Heating degree days were 98 percent of normal in 2022 compared to 88 percent of normal in 2021.

Depreciation and amortization expense was $144.1 million in 2022, compared to $134.8 million in 2021, an increase of $9.3 million. The increase resulted from additional utility plant investments placed into service, including property, plant and equipment assets purchased from CenterPoint Energy at its net carrying value as of the purchase date.


	For the Year Ended December 31,
	2022			2021
OPERATING REVENUES (in millions):
Residential	$	254.1		$	225.2
Commercial	180.1			159.2
Industrial	186.9			165.6
Other	9.3			9.5
Total Retail	630.4			559.5
Net Wholesale Revenues	40.0			45.7
Transmission Revenues	25.5			24.1
	$	695.9		$	629.3
MARGIN (In millions):
Residential	$	172.4		$	167.7
Commercial	113.0			109.3
Industrial	93.0			98.7
Other	9.7			5.7
Regulatory expense recovery mechanisms	44.1			24.3
Total Retail	432.2			405.7
Wholesale power & transmission system	42.0			37.5
	$	474.2		$	443.2

ELECTRIC SALES (In MWh):
Residential	1,398,174			1,416,843
Commercial	1,210,034			1,165,594
Industrial	1,967,271			2,040,869
Other Sales - Street Lighting	20,255			20,665
Total Retail	4,595,734			4,643,971
Wholesale	882,864			1,457,358
	5,478,598			6,101,329

CUSTOMER COUNT:
Residential	132,402			131,125
Commercial	19,135			19,143
Industrial	114			114

	151,651			150,382

WEATHER AS A % OF NORMAL:
Cooling Degree Days	103		%	114		%
Heating Degree Days	107		%	88		%


	For the Year Ended December 31,
	2022				2021
OPERATING REVENUES (in millions):
Residential	$	94.2			$	90.3
Commercial	38.5				30.8
Industrial	12.1				12.5
Other	1.1				0.5
	$	145.9	$	145,900,000	$	134.1

MARGIN (In millions):
Residential	$	54.6			$	45.8
Commercial	15.9				12.1
Industrial	14.0				12.8
Other	1.1				0.9
Regulatory expense recovery mechanisms	2.5				8.0
	$	88.1			$	79.6

GAS SOLD & TRANSPORTED (In MDth):
Residential	6,961				6,380
Commercial	3,996				3,575
Industrial	31,573				29,115
	42,530				39,070

CUSTOMER COUNT
Residential	104,495				104,043
Commercial	10,531				10,517
Industrial	119				111
	115,145				114,671