8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 3, 2020

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

_______________________________

Texas		1-31447			74-0694415
(State or other jurisdiction		(Commission File Number)			(IRS Employer
of incorporation)					Identification No.)
1111 Louisiana
Houston	Texas		77002
(Address of principal executive offices)			(Zip Code)
Registrant’s telephone number, including area code:			(713)	207-1111

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

☐Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	CNP	The New York Stock Exchange
		Chicago Stock Exchange, Inc.
Depositary Shares for 1/20 of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value	CNP/PB	The New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2).

Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Item 7.01    Regulation FD Disclosure.

Included herein is supplemental financial and operational information for the years ended December 31, 2019 and 2018 related to Southern Indiana Gas & Electric Company (“SIGECO”). SIGECO is a wholly-owned subsidiary of Vectren Utility Holdings, Inc. (“VUHI”). VUHI is a wholly-owned subsidiary of Vectren Corporation, which in turn, is a wholly-owned subsidiary of CenterPoint Energy, Inc. (“CenterPoint Energy”).

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

Item 9.01    Financial Statements and Exhibits.

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

(d)    Exhibits.

EXHIBIT NUMBER	EXHIBIT DESCRIPTION
99.1	Supplemental Financial and Operational Information for SIGECO for the year ended December 31, 2019
99.2	Supplemental Financial and Operational Information for SIGECO for the year ended December 31, 2018
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CENTERPOINT ENERGY, INC.
Date: August 3, 2020	By:	/s/ Kristie L. Colvin
		Kristie L. Colvin
		Interim Executive Vice President and Chief Financial Officer and Chief Accounting Officer

EX-99.1

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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.

1

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.

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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

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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.

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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		%

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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

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EX-99.2

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Exhibit 99.2

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 2018 financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.’s 2018 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 2018, the Company’s earnings were $81.5 million compared to $79.9 million in 2017. Results in 2018 reflect an increase in electric earnings due primarily to favorable weather and increased earnings from the Transmission Distribution and Storage System Improvement Charge (TDSIC), offset by tax reform and power plant maintenance. Additionally, gas earnings increased primarily from the Compliance and System Improvement Adjustment (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.

1

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 Notes 9 and 10 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.

2

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)	2018		2017
Electric utility revenues	$	582,504	$	569,587
Cost of fuel & purchased power	186,203		171,794
Total electric utility margin	$	396,301	$	397,793
Margin attributed to:
Residential & commercial customers	$	251,443	$	254,838
Industrial customers	93,604		96,913
Other	5,689		5,617
Regulatory expense recovery mechanisms	15,666		9,611
Subtotal: Retail	366,402		366,979
Wholesale margin	29,899		30,814
Total electric utility margin	$	396,301	$	397,793
Electric volumes sold in MWh attributed to:
Residential & commercial customers	2,754,307		2,638,783
Industrial customers	2,181,464		2,096,523
Other customers	22,251		22,261
Total retail volumes	4,958,022		4,757,567
Wholesale	856,350		463,252
Total volumes sold	5,814,372		5,220,819

Retail

Electric retail utility margins were $366.4 million for the year ended December 31, 2018 compared to $367.0 million in 2017, a decrease of $0.6 million. Results reflect a decrease in margin of $26.1 million as a result of federal tax reform implemented effective January 1, 2018. The decrease was largely offset by increases in margin of $13.8 million due to favorable weather, of $4.5 million due to large customer usage, and of $5.8 million due to regulatory expense recovery mechanisms. Heating degree days were 101 percent of normal in 2018 compared to 80 percent of normal in 2017, and cooling degree days were 136 percent of normal in 2018 compared to 111 percent of normal in 2017.

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)	2018		2017
MISO transmission system margin	$	23,203	$	25,498
MISO off-system margin	6,696		5,316
Total wholesale margin	$	29,899	$	30,814

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $23.2 million during 2018 compared to $25.5 million in 2017, a decrease of $2.3 million. As

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of December 31, 2018, the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $130.1 million at December 31, 2018. 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 September 2016, the FERC issued an order authorizing the transmission owners to receive a 10.32 percent base ROE, 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, 2018, margin from off-system sales was $6.7 million compared to $5.3 million in 2017, an increase of $1.4 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 favorable in 2018 compared to 2017, reflecting higher market prices due primarily to higher 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)	2018		2017
Gas utility revenues	$	100,044	$	92,396
Cost of gas sold	40,309		33,949
Total gas utility margin	$	59,735	$	58,447
Margin attributed to:
Residential & commercial customers	$	42,898	$	41,964
Industrial customers	10,108		9,956
Other	221		1,004
Regulatory expense recovery mechanisms	6,508		5,523
Total gas utility margin	$	59,735	$	58,447
Sold & transported volumes in MDth attributed to:
Residential & commercial customers	10,794		9,113
Industrial customers	32,825		28,771
Total sold & transported volumes	43,619		37,884

Gas Utility margin was $59.7 million for the year ended December 31, 2018 compared to $58.4 million in 2017, an increase of $1.3 million.The increase in margin was largely due to increased returns on the gas infrastructure replacement program and to the margin impact of regulatory expense recovery mechanisms, offset by the $4.7 million margin impact of federal tax reform. 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 101 percent of normal in 2018 compared to 80 percent of normal in 2017.

Operating Expenses

Other Operating

For the year ended December 31, 2018, Other operating expenses were $203.6 million compared to $187.8 million in 2017, an increase of $15.8 million. Operating expenses primarily reflect an increase of $9.6 million in power plant maintenance expense and variable production costs and an increase of $6.4 million due to operating expenses recovered through margin.

Depreciation & Amortization

Depreciation and amortization expense was $104.7 million in 2018 compared to $100.8 million in 2017, an increase of $3.9 million. The increase resulted from additional utility plant investments placed into service, including $1.2 million of depreciation on infrastructure investments.

4

SELECTED ELECTRIC OPERATING STATISTICS

	For the Year Ended
	December 31,
	2018			2017
OPERATING REVENUES (in thousands):
Residential	$	210,232		$	200,821
Commercial	149,255			154,564
Industrial	162,143			162,586
Other	9,138			9,246
Total Retail	530,768			527,217
Net Wholesale Revenues	51,736			42,370
	$	582,504		$	569,587
MARGIN (In thousands):
Residential	$	151,168		$	148,555
Commercial	100,275			106,283
Industrial	93,604			96,913
Other	5,689			5,617
Regulatory expense recovery mechanisms	15,666			9,611
Total Retail	366,402			366,979
Wholesale power & transmission system	29,899			30,814
	$	396,301		$	397,793
ELECTRIC SALES (In MWh):
Residential	1,486,582			1,362,457
Commercial	1,267,725			1,276,326
Industrial	2,181,464			2,096,523
Other Sales - Street Lighting	22,251			22,261
Total Retail	4,958,022			4,757,567
Wholesale	856,350			463,252
	5,814,372			5,220,819
AVERAGE CUSTOMERS:
Residential	127,439			126,443
Commercial	18,677			18,648
Industrial	115			112
Other	40			40
	146,271			145,243
WEATHER AS A % OF NORMAL:
Cooling Degree Days	136		%	111		%
Heating Degree Days	101		%	80		%

5

SELECTED GAS OPERATING STATISTICS

	For the Year Ended
	December 31,
	2018		2017
OPERATING REVENUES (In thousands):
Residential	$	65,125	$	60,097
Commercial	24,055		21,428
Industrial	10,576		9,820
Other	288		1,051
	$	100,044	$	92,396
MARGIN (In thousands):
Residential	$	33,549	$	32,707
Commercial	9,349		9,257
Industrial	10,108		9,956
Other	221		1,004
Regulatory expense recovery mechanisms	6,508		5,523
	$	59,735	$	58,447
GAS SOLD & TRANSPORTED (In MDth):
Residential	6,992		5,860
Commercial	3,802		3,253
Industrial	32,825		28,771
	43,619		37,884
AVERAGE CUSTOMERS:
Residential	101,475		101,064
Commercial	10,342		10,304
Industrial	112		112
	111,929		111,480

6

XML

Cover Page Cover Page	Aug. 03, 2020
Entity Information [Line Items]
Document Type	8-K
Document Period End Date	Aug. 03, 2020
Entity Registrant Name	CENTERPOINT ENERGY INC
Entity Incorporation, State or Country Code	TX
Entity File Number	1-31447
Entity Tax Identification Number	74-0694415
Entity Address, Address Line One	1111 Louisiana
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	207-1111
Written Communications	false
Soliciting Material	false
Pre-commencement Tender Offer	false
Pre-commencement Issuer Tender Offer	false
Entity Emerging Growth Company	false
Amendment Flag	false
Entity Central Index Key	0001130310
Common Stock | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CNP
Security Exchange Name	NYSE
Common Stock | Chicago Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CNP
Security Exchange Name	CHX
Depositary Shares | New York Stock Exchange
Entity Information [Line Items]
Title of 12(b) Security	Depositary Shares for 1/20 of 7.00% Series B Mandatory Convertible Preferred Stock, $0.01 par value
Trading Symbol	CNP/PB
Security Exchange Name	NYSE