Exhibit

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Exhibit 99.1

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 2019 financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2019 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.

Executive Summary of Results of Operations

Operating Results

In 2019, the Company’s earnings were $56.5 million compared to $81.5 million in 2018. Results in 2019 reflect merger and severance expenses following CenterPoint Energy’s acquisition of Vectren and unfavorable weather, partially offset by an increase in electric and gas utility margin from increased returns associated with infrastructure investments (TDSIC, ECA, CECA and CSIA).

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 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 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) clause 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. The implementation of these various mechanisms has allowed the Company to avoid regulatory proceedings to increase base rates since 2011 for its electric business and 2007 for its gas business.

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 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.

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 clause 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.

Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

Base Rate Orders

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 August 2007. The orders authorize a return on equity of 10.40% on the electric operations and 10.15% for the gas operations. The authorized returns reflect the impact of rate design strategies that have been authorized by the IURC.

See Note 9 to the financial statements for more specific information on the significant regulatory proceedings involving the Company.

Operating Trends

Margin

Throughout this discussion, the terms Gas utility margin and Electric utility margin are used. Gas utility margin is calculated as Gas utility revenues less the Cost of gas sold. Electric utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. The Company believes Gas utility and Electric utility 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 Gas utility margin and Electric utility 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.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)

Electric utility margin and volumes sold by customer type follows:



	Year Ended December 31,
(In thousands)	2019		2018

Electric utility revenues	$	570,150	$	582,504
Cost of fuel & purchased power	165,900		186,203
Total electric utility margin	$	404,250	$	396,301
Margin attributed to:
Residential & commercial customers	$	255,545	$	251,443
Industrial customers	95,107		93,604
Other	6,194		5,689
Regulatory expense recovery mechanisms	17,456		15,666
Subtotal: Retail	374,302		366,402
Wholesale margin	29,948		29,899
Total electric utility margin	$	404,250	$	396,301
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,608,827		2,754,307
Industrial customers	2,072,912		2,181,464
Other customers	21,113		22,251
Total retail volumes	4,702,852		4,958,022
Wholesale	495,281		856,350
Total volumes sold	5,198,133		5,814,372

Retail

Electric retail utility margins were $374.3 million for the year ended December 31, 2019, compared to $366.4 million in 2018, an increase of $7.9 million. Results primarily reflect an increase in margin of $14.1 million as a result of the Clean Energy Cost Adjustment and Environmental Cost Adjustment (CECA and ECA) and a $5.5 million increase resulting from the Transmission, Distribution and Storage System Improvement Charge (TDSIC). The increase was partially offset by a $8.1 million decrease in margin due to unfavorable weather along with a $3.2 million decrease in margin resulting from a decline in large industrial customer usage. Heating degree days were 95 percent of normal in 2019 compared to 101 percent of normal in 2018, and cooling degree days were 115 percent of normal in 2019 compared to 136 percent of normal in 2018.

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 thousands)	2019		2018
MISO transmission system margin	$	24,957	$	23,203
MISO off-system margin	4,991		6,696
Total wholesale margin	$	29,948	$	29,899

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $25.0 million during 2019 compared to $23.2 million in 2018, an increase of $1.8 million. As of December 31, 2019, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $126.7 million at December 31, 2019. These projects include an interstate 345 kV transmission line that connects the Company’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. These projects earn the FERC approved equity rate of return on the net plant balance and recover operating expenses. In November 2019, the FERC issued an order authorizing the transmission owners to receive a 9.88 percent base ROE compared to the previously authorized 10.32 percent, plus a separately approved 50 basis point adder. The 345 kV project is the largest of these qualifying projects, with an original cost of $106.8 million.

For the year ended December 31, 2019, margin from off-system sales was $5.0 million compared to $6.7 million in 2018, a decrease of $1.7 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. Results, net of sharing for the periods presented, were unfavorable in 2019 compared to 2018, reflecting lower market prices due primarily to lower natural gas prices.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas utility margin and throughput by customer type follows:



	Year Ended December 31,
(In thousands)	2019		2018
Gas utility revenues	$	99,531	$	100,044
Cost of gas sold	33,623		40,309
Total gas utility margin	$	65,908	$	59,735
Margin attributed to:
Residential & commercial customers	$	45,316	$	42,898
Industrial customers	10,781		10,108
Other	852		221
Regulatory expense recovery mechanisms	8,959		6,508
Total gas utility margin	$	65,908	$	59,735
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	10,439		10,794
Industrial customers	30,170		32,825
Total sold & transported volumes	40,609		43,619

Gas Utility margin was $65.9 million for the year ended December 31, 2019 compared to $59.7 million in 2018, an increase of $6.2 million. The increase in margin was largely due to increased returns on the Compliance and System Improvement Adjustment (CSIA). 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 95 percent of normal in 2019 compared to 101 percent of normal in 2018.

Operating Expenses

Other Operating

For the year ended December 31, 2019, Other operating expenses were $241.9 million compared to $203.6 million in 2018, an increase of $38.3 million. Operating expenses primarily reflect an increase of $29.6 million from merger and severance expenses following CenterPoint Energy’s acquisition of Vectren and a $6.2 million increase due to operating expenses recovered through margin. The remaining increase in operating expenses can be primarily attributed to major maintenance outages at two of the Company’s generating units.

Depreciation & Amortization

Depreciation and amortization expense was $114.0 million in 2019, compared to $104.7 million in 2018, an increase of $9.3 million. The increase resulted from additional utility plant investments placed into service, including $6.2 million of depreciation on infrastructure investments.

SELECTED ELECTRIC OPERATING STATISTICS



	For the Year Ended
	December 31,
	2019			2018
OPERATING REVENUES (in thousands):
Residential	$	210,443		$	210,232
Commercial	148,094			149,255
Industrial	159,892			162,143
Other	9,355			9,138
Total Retail	527,784			530,768
Net Wholesale Revenues	42,366			51,736
	$	570,150		$	582,504

MARGIN (In thousands):
Residential	$	153,801		$	151,168
Commercial	101,744			100,275
Industrial	95,107			93,604
Other	6,194			5,689
Regulatory expense recovery mechanisms	17,456			15,666
Total Retail	374,302			366,402
Wholesale power & transmission system	29,948			29,899
	$	404,250		$	396,301

ELECTRIC SALES (In MWh):
Residential	1,409,212			1,486,582
Commercial	1,199,615			1,267,725
Industrial	2,072,912			2,181,464
Other Sales - Street Lighting	21,113			22,251
Total Retail	4,702,852			4,958,022
Wholesale	495,281			856,350
	5,198,133			5,814,372

AVERAGE CUSTOMERS:
Residential	128,344			127,439
Commercial	18,751			18,677
Industrial	116			115
Other	42			40
	147,253			146,271

WEATHER AS A % OF NORMAL:
Cooling Degree Days	115		%	136		%
Heating Degree Days	95		%	101		%

SELECTED GAS OPERATING STATISTICS



	For the Year Ended
	December 31,
	2019		2018
OPERATING REVENUES (In thousands):
Residential	$	64,743	$	65,125
Commercial	22,507		24,055
Industrial	12,039		10,576
Other	242		288
	$	99,531	$	100,044
MARGIN (In thousands):
Residential	$	35,690	$	33,549
Commercial	9,626		9,349
Industrial	10,781		10,108
Other	852		221
Regulatory expense recovery mechanisms	8,959		6,508
	$	65,908	$	59,735
GAS SOLD & TRANSPORTED (In MDth):
Residential	6,713		6,992
Commercial	3,726		3,802
Industrial	30,170		32,825
	40,609		43,619
AVERAGE CUSTOMERS:
Residential	101,906		101,475
Commercial	10,356		10,342
Industrial	112		112
	112,374		111,929