SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): March 13, 2023
CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction||(Commission File Number)||(IRS Employer|
|of incorporation)|| Identification No.)|
| 1111 Louisiana|
| (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|
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 financial information related to Southern Indiana Gas & Electric Company (“CEI South”). CEI South is a wholly-owned subsidiary of Vectren Utility Holdings, LLC ("VUH"). VUH is a wholly-owned subsidiary of Vectren, LLC (“Vectren”), which in turn, is an indirect, wholly-owned subsidiary of CenterPoint Energy, Inc. (“CenterPoint Energy”).
Exhibit 99.1 to this Current Report on Form 8-K includes audited financial statements for the years ended December 31, 2022 and 2021 for CEI South. These financial statements are not intended to comply with Regulation S-X or Regulation S-K. Exhibit 99.2 includes certain supplementary financial and operational data of CEI South for the years ended December 31, 2022 and 2021.
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.
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: March 13, 2023||By:||/s/ Kara Gostenhofer Ryan |
|Kara Gostenhofer Ryan|
|Vice President and Chief Accounting Officer|
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
As of and for the years ended December 31, 2022 and 2021
|Audited Financial Statements|
|Independent Auditor's Report||3-4|
|Statements of Income||7|
|Statements of Cash Flows||8|
|Statements of Common Shareholder's Equity||9|
|Notes to the Financial Statements||10-35|
|ACE||Affordable Clean Energy|
|AFSI||Adjusted financial statement income|
|AFUDC||Allowance for funds used during construction|
|AMA||Asset Management Agreement|
|Arevon||Arevon Energy, Inc., which was formed through the combination of Capital Dynamics, Inc.’s U.S. Clean Energy Infrastructure business unit and Arevon Asset Management|
|ARO||Asset Retirement Obligation|
|ARP||Alternative Revenue Program|
|ASC||Accounting Standards Codification|
|BTA||Build Transfer Agreement|
|CCR||Coal Combustion Residuals|
|CECA||Clean Energy Cost Adjustment|
|COVID-19||Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization|
|CODM||Chief Operating Decision Maker|
|CPCN||Certificate of Public Convenience and Necessity|
|CPP||Clean Power Plan|
|CSIA||Compliance and System Improvement Adjustment|
|DOC||U.S. Department of Commerce|
|ECA||Environmental Cost Adjustment|
|EIA||U.S. Energy Information Administration|
|ELG||Effluent Limitation Guidelines|
|EPA||Environmental Protection Agency|
|FASB||Financial Accounting Standards Board|
|February 2021 Winter Storm Event||The extreme and unprecedented winter weather event in February 2021 resulting in electricity generation supply shortages, including in Texas, and natural gas supply shortages and increased wholesale prices of natural gas in the United States, primarily due to prolonged freezing temperatures.|
|FERC||Federal Energy Regulation Commission|
|GAAP||Generally Accepted Accounting Principles|
|IDEM||Indiana Department of Environmental Management|
|IRA||Inflation Reduction Act of 2022|
|IRP||Integrated Resource Plan|
|IRS||Internal Revenue Service|
|ITCs||Investment Tax Credits|
|IURC||Indiana Utility Regulatory Commission|
|LIBOR||London Interbank Offered Rate|
|LIFO||Last In - First Out inventory method|
|LMP||Locational Marginal Pricing|
|Merger||The merger of Merger Sub with and into Vectren on the terms and subject to the conditions set forth in the Merger Agreement, with Vectren continuing as the surviving corporation and as a wholly-owned subsidiary of CenterPoint Energy, Inc., which closed on the Merger Date|
|Merger Agreement||Agreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Vectren and Merger Sub|
|Merger Date||February 1, 2019|
|Merger Sub||Pacer Merger Sub, Inc., an Indiana corporation and wholly-owned subsidiary of CenterPoint Energy|
|MGP||Manufactured gas plant|
|MISO||Midcontinent Independent System Operator|
|NYMEX||New York Mercantile Exchange|
|Origis||Origis Energy USA Inc.|
|OUCC||Indiana Office of Utility Consumer Counselor|
|Posey Solar||Posey Solar, LLC, a Delaware limited liability company|
|PPA||Power purchase agreement|
|PRP||Potentially responsible parties|
|PTCs||Production Tax Credits|
|RCRA||Resource Conservation and Recovery Act of 1976|
|ROU||Right of use|
|Scope 1 emissions||Direct source of emissions from a company’s operations|
|Scope 2 emissions||Indirect source of emissions from a company’s energy usage|
|Scope 3 emissions||Indirect source of emissions from a company’s end-users|
|SERP||Supplemental Executive Retirement Plan|
|SOFR||Secured Overnight Financing Rate|
|TCJA||Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017|
|TDSIC||Transmission, Distribution and Storage System Improvement Charge|
|Vectren||Vectren, LLC, which converted its corporate structure from Vectren Corporation to a limited liability company on June 30, 2022, a wholly-owned subsidiary of CenterPoint Energy, Inc. as of the Merger Date, and, after the Restructuring, is held indirectly by CenterPoint Energy through Vectren Affiliated Utilities, Inc.|
|VRP||Voluntary Remediation Program|
|VUH||Vectren Utility Holdings, LLC, which converted its corporate structure from Vectren Utility Holdings, Inc. to a limited liability company on June 30, 2022, a wholly-owned subsidiary of Vectren LLC|
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors of Southern Indiana Gas and Electric Company:
We have audited the financial statements of Southern Indiana Gas and Electric Company (the “Company”) (a wholly owned subsidiary of Vectren Utility Holdings, LLC), which comprise the balance sheets as of December 31, 2022 and 2021, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended, and the related notes to the financial statements (collectively referred to as the "financial statements").
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Basis for Opinion
We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date that the financial statements are issued.
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.
In performing an audit in accordance with GAAS, we:
•Exercise professional judgment and maintain professional skepticism throughout the audit.
•Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
•Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.
•Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.
•Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
Other Information Included in the Annual Report
Management is responsible for the other information included in the annual report. The other information comprises the information included in the annual report but does not include the financial statements and our auditor’s report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon.
In connection with our audits of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report.
|/s/ DELOITTE & TOUCHE LLP|
|March 13, 2023|
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
|December 31, 2022||December 31, 2021|
|Cash & cash equivalents||$||5 ||$||2 |
|Accounts receivable - less allowance for credit losses of $3 and $3, respectively||62 ||53 |
|Accrued unbilled revenues - less allowance for credit losses of $-0- and $-0-, respectively||40 ||28 |
|Inventories||103 ||72 |
|Regulatory assets||49 ||24 |
|Prepaid expenses and other current assets||23 ||13 |
|Total current assets||282 ||192 |
|Property, Plant and Equipment, net||2,888 ||2,615 |
|Goodwill ||6 ||6 |
|Regulatory assets||191 ||193 |
|Other non-current assets||53 ||52 |
|Total other assets||250 ||251 |
|Total Assets||$||3,420 ||$||3,058 |
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
|December 31, 2022||December 31, 2021|
|LIABILITIES AND SHAREHOLDER'S EQUITY|
|Accounts payable||$||126 ||$||78 |
|Accounts payable - affiliated companies||11 ||19 |
|Accrued liabilities||60 ||62 |
|Notes payable - affiliated companies||36 ||69 |
|Current maturities of long-term debt - third parties||11 ||5 |
|Current maturities of long-term debt - affiliated companies||25 ||— |
|Total current liabilities||269 ||233 |
|Deferred income taxes||296 ||261 |
|Regulatory liabilities||288 ||284 |
|Other non-current liabilities||197 ||192 |
|Total other liabilities||781 ||737 |
|Long-term debt - third parties, net of current maturities||277 ||288 |
|Long-term debt - affiliated companies, net of current maturities||755 ||640 |
|Total long-term debt||1,032 ||928 |
|Commitments and Contingencies (Note 8)|
|Common shareholder's equity:|
|Common stock (no par value)||539 ||433 |
|Retained earnings||799 ||727 |
|Total common shareholder's equity||1,338 ||1,160 |
|Total Liabilities and Shareholder's Equity||$||3,420 ||$||3,058 |
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS OF INCOME
|Year Ended December 31,|
|Electric utility revenues||$||696 ||$||629 |
|Gas utility revenues||146 ||134 |
|Total ||842 ||763 |
|Fuel and purchased power||222 ||186 |
|Utility natural gas||58 ||55 |
|Operation and maintenance||247 ||215 |
|Depreciation and amortization||144 ||135 |
|Taxes other than income taxes||18 ||20 |
|Total operating expenses||689 ||611 |
|Operating Income||153 ||152 |
|Other Income (Expense):|
|Other income, net||16 ||7 |
|Income Before Income Taxes||136 ||127 |
|Income tax expense||27 ||21 |
|Net Income||$||109 ||$||106 |
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
|Year Ended December 31,|
|Cash Flows from Operating Activities:||(in millions)|
|Net income||$||109 ||$||106 |
|Adjustments to reconcile net income to cash from operating activities:|
|Depreciation and amortization||144 ||135 |
|Deferred income taxes and investment tax credits||36 ||19 |
|Expense portion of pension and postretirement benefit cost||(2)||3 |
|Changes in working capital accounts:|
|Accounts receivable & accrued unbilled revenue||(22)||(8)|
|Accounts receivable/payable, affiliates||(8)||(3)|
|Accounts payable||22 ||8 |
|Net regulatory assets and liabilities||(17)||(38)|
|Other current assets and liabilities||(11)||18 |
|Other assets and liabilities||(13)||4 |
|Other operating activities, net||(6)||(1)|
|Net cash provided by operating activities||201 ||267 |
|Cash Flows from Investing Activities:|
|Other investing activities, net||(3)||4 |
|Net cash used in investing activities||(366)||(305)|
|Cash Flows from Financing Activities:|
|Net change in short-term notes payable - affiliated companies||(32)||(3)|
|Proceeds from long-term notes payable - affiliated companies||140 ||125 |
|Payment of long-term debt - affiliated companies||(5)||(55)|
|Contributions from VUH||102 ||— |
|Dividends to VUH||(37)||(30)|
|Net cash provided by financing activities||168 ||37 |
|Net change in cash & cash equivalents||3 ||(1)|
|Cash & cash equivalents at beginning of period||2 ||3 |
|Cash & cash equivalents at end of period||$||5 ||$||2 |
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS & ELECTRIC COMPANY
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
|Common Stock||Retained Earnings||Total|
|Balance at January 1, 2021||$||433 ||$||651 ||$||1,084 |
|Net income||106 ||106 |
|Dividends to VUH||(30)||(30)|
|Balance at December 31, 2021||$||433 ||$||727 ||$||1,160 |
|Net income||109 ||109 |
|Contribution from VUH||102 ||102 |
|Non-cash contribution from VUH||4 ||4 |
|Dividends to VUH||(37)||(37)|
|Balance at December 31, 2022||$||539 ||$||799 ||$||1,338 |
The accompanying notes are an integral part of these financial statements
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
NOTES TO THE FINANCIAL STATEMENTS
(1)Organization and Nature of Operations
Southern Indiana Gas and Electric Company (the Company or CEI South), an Indiana corporation, provides energy delivery services to 151,651 electric customers and 115,145 gas customers located near Evansville in southwestern Indiana. Of these customers, 87,560 receive combined electric and gas distribution services. The Company also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. The Company is a direct, wholly owned subsidiary of VUH (the Company's parent). VUH is a direct, wholly owned subsidiary of Vectren LLC (Vectren). Vectren, an indirect, wholly owned subsidiary of CenterPoint Energy, Inc. (collectively with its subsidiaries, CenterPoint Energy), is an energy holding company headquartered in Evansville, Indiana.
(2)Summary of Significant Accounting Policies
(a) Use of Estimates
In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of property, plant and equipment and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates.
(b) Cash & Cash Equivalents
Highly-liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.
(c) Accounts Receivable and Allowance for Credit Losses
Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company reviews historical write-offs, current available information, and reasonable and supportable forecasts to estimate and establish allowance for credit losses. Account balances are charged off against the allowance when it is probable the receivable will not be recovered. See Note 5 for further information about regulatory deferrals of bad debt expense related to COVID-19.
In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage is recorded using the LIFO method. Inventory is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
Inventories consist of the following:
| December 31,|
|Materials & supplies||$||57 ||$||37 |
|Coal & oil for electric generation - at average cost||27 ||13 |
|Gas in storage – at LIFO cost||19 ||22 |
|Total inventories||$||103 ||$||72 |
Based on the average cost of gas purchased during December 2022 and 2021, the cost of replacing gas in storage carried at LIFO cost is less than the carrying value at December 31, 2022 and 2021 by approximately less than $1 million and $2 million,
respectively. The Company sources most of its coal supply from two third parties and also purchases most of its natural gas from a different single third party. Rates charged to natural gas customers contain a gas cost adjustment clause and electric rates contain a fuel adjustment clause that allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel.
(e) Long-lived Assets and Goodwill
The Company records property, plant and equipment at historical cost and expenses repair and maintenance costs as incurred.
The Company periodically evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. No long-lived asset impairments were recorded in 2022 or 2021.
The Company performs goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The Company recognizes a goodwill impairment by the amount a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill within that reporting unit. The Company includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. Goodwill is reported in the Company's Natural Gas reporting segment.
The Company performed the annual goodwill impairment tests in the third quarter of 2022 and determined that no goodwill impairment charge was required.
(f) Depreciation and Amortization Expense
The Company computes depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets.
The Company’s portion of jointly owned property, plant and equipment, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.
(g) Capitalization of AFUDC
The Company capitalizes AFUDC as a component of projects under construction and amortizes it over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction as the Company applies the guidance for accounting for regulated operations. Although AFUDC increases both property, plant and equipment and earnings, it is realized in cash when the assets are included in rates.
|Year Ended December 31,|
AFUDC – borrowed funds (1)
|$||7 ||$||4 |
AFUDC – equity funds (2)
|8 ||4 |
(1)Included in Other income, net on the Company’s Statements of Income, inclusive of $3 million of debt post in-service carrying costs on property, plant and equipment, primarily in Indiana, deferred into a regulatory asset in each of the years ended December 31, 2022 and 2021.
(2)Included in Other income, net on the Company's Statements of Income.
Retail public utility operations are subject to regulation by the IURC. The Company is subject to FERC regulation as an electric public utility. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by this agency.
(i) Refundable or Recoverable Gas Costs and Cost of Fuel and Purchased Power
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under or over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding regulatory asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.
(j) Regulatory Assets and Liabilities
The Company applies the guidance for accounting for regulated operations within its Electric and Natural Gas reportable segments. The Company's rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.
The Company's rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.
(k) Asset Retirement Obligations
A portion of removal costs related to interim retirements of gas utility pipeline and electric utility poles, and reclamation activities meet the definition of an ARO. The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.
(l) Derivative Instruments
The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company, from time to time, utilizes derivative instruments such as physical forward contracts, to mitigate the impact of changes in commodity prices on operating results and cash flows. Such derivatives are recognized in the Company’s Balance Sheet at their fair value unless the Company elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.
(m) Environmental Costs
The Company expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Company records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
(n) Income Taxes
The Company is included in CenterPoint Energy's consolidated federal income tax return. Vectren and certain subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint Energy. In other state jurisdictions, Vectren and certain subsidiaries continue to file separate state tax returns. The Company calculates the provision for income taxes and income tax liabilities for each jurisdiction using a separate return method.
The Company uses the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. The Company recognizes interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Income.
To the extent certain excess deferred income taxes of the Company’s rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively.
Investment tax credits are deferred and amortized to income over the approximate lives of the related property.
(o) Revenue Policy
Revenue is recognized when obligations under the terms of a contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring goods or providing services. The satisfaction of performance obligation occurs when the transfer of goods and services occur, which may be at a point in time or over time, resulting in revenue being recognized over the course of the underlying contract or at a single point in time based upon the delivery of services to customers.
(p) MISO Transactions
With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at LMP as determined by the MISO market.
MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, meaning net purchases within that interval are recorded on the Company's Statements of Income in Utility natural gas and Fuel and purchased power, and net sales within that interval are recorded on the Company's Statements of Income in Gas utility and Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.
The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.
(q) Utility Receipts Taxes
A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $5 million in 2022 and $9 million in 2021. Expense associated with utility receipts taxes are recorded as a component of Taxes other than income taxes on the Statements of Income. The Indiana utility receipts tax was repealed as of July 1, 2022. The utility receipts tax rate was removed from Indiana rates at the time of the repeal. The Company expects to file its final utility receipts tax return on April 18, 2023.
(r) Fair Value Measurements
Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:
|Level 1||Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access.|
Inputs to the valuation methodology include
· quoted prices for similar assets or liabilities in active markets;
· quoted prices for identical or similar assets or liabilities in inactive markets;
· inputs other than quoted prices that are observable for the asset or liability;
· inputs that are derived principally from or corroborated by observable market
data by correlation or other means
If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
|Level 3||Inputs to the valuation methodology are unobservable and significant to the fair value measurement.|
The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs.
(s) Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 6).
In accordance with ASC 606, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Company expects to be entitled to receive in exchange for these goods or services.
The Company determines that disaggregating revenue into certain categories achieves the disclosure objective to depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. These material revenue generating categories, as disclosed in Note 12, include: Natural Gas and Electric.
The Company provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company bills customers monthly and has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied to date. The performance obligation is satisfied and revenue is recognized upon the delivery of services to customers. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues, derived from estimated unbilled consumption and tariff rates or in a regulatory asset, as applicable. The Company's revenues are also adjusted for the effects of regulation including tracked operating expenses, infrastructure replacement mechanisms, decoupling mechanisms, and lost margin recovery. Decoupling and lost margin recovery mechanisms are considered ARPs, which are excluded from the scope of ASC 606. Revenues from ARPs are not material to any reporting period Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing. These revenues are not subject to significant returns, refunds, or warranty obligations.
In the following table, the Company's revenue is disaggregated by reportable segment and major source.
|Year Ended December 31, 2022|
|Revenue from contracts||$||677 ||$||146 ||$||823 |
|Other (1)||19 ||— ||19 |
|Total Revenues||$||696 ||$||146 ||$||842 |
|Year Ended December 31, 2021|
|Revenue from contracts||$||609 ||$||132 ||$||741 |
|Other (1)||20 ||2 ||22 |
|Total Revenues||$||629 ||$||134 ||$||763 |
(1)Primarily consists of income from ARPs. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Company recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.
Revenues from Contracts with Customers
Contract Balances. The Company does not have any material contract balances (right to consideration for services already provided or obligations to provide services in the future for consideration already received). Substantially all the Company's accounts receivable results from contracts with customers.
The opening and closing balances of the Company's accounts receivable and other accrued unbilled revenue are as follows:
|Accounts Receivable||Other Accrued Unbilled Revenues|
|Opening balance as of December 31, 2021||$||53 ||$||28 |
|Closing balance as of December 31, 2022||62 ||40 |
| Increase ||$||9 ||$||12 |
Allowance for Credit Losses and Bad Debt Expense
The Company segregates financial assets that fall under the scope of Topic 326, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations, and macroeconomic factors, among others. For a discussion of regulatory deferrals related to COVID-19, see Note 5.
The table below summarizes the Company's bad debt expense amounts for 2022 and 2021, net of regulatory deferrals, including those related to COVID-19:
|Year Ended December 31,|
|Bad debt expense||$||3 ||$||2 |
(4)Property, Plant and Equipment
(a) Property, Plant and Equipment
Property, plant and equipment includes the following:
|December 31, 2022||December 31, 2021|
|Weighted Average Useful Lives||Property, Plant and Equipment, Gross||Accumulated Depreciation and Amortization||Property, Plant and Equipment, Net||Property, Plant and Equipment, Gross||Accumulated Depreciation and Amortization||Property, Plant and Equipment, Net|
|(in years)||(in millions)|
|Electric transmission and distribution||34||$||2,063 ||$||1,066 ||$||997 ||$||1,857 ||$||1,018 ||$||839 |
|Electric generation||26||2,120 ||813 ||1,307 ||2,013 ||750 ||1,263 |
|Natural gas distribution||42||773 ||189 ||584 ||689 ||176 ||513 |
|Total||$||4,956 ||$||2,068 ||$||2,888 ||$||4,559 ||$||1,944 ||$||2,615 |
(b) Depreciation and Amortization
The following table presents depreciation and amortization expense:
|Year Ended December 31, |
|Depreciation||$||142 ||$||133 |
|Amortization of regulatory assets||2 ||2 |
|Total||$||144 ||$||135 |
The Company recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley and for treated wood poles for electric distribution, distribution transformers containing PCB, and underground fuel storage tanks. The Company also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.
A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities in the Company’s Balance Sheets is as follows:
|December 31, 2022||December 31, 2021|
|Beginning balance||$||124 ||$||94 |
Accretion expense (1)
|4 ||4 |
Revisions in estimates (2)
|11 ||26 |
|Ending balance||$||139 ||$||124 |
(1)Reflected in non-current Regulatory assets on the Company’s Balance Sheets.
(2)In 2022, the Company reflected an increase in its ARO liability, which is primarily attributable to a revision to the ARO for Culley East ash pond regarding the change in estimated future cash flows. In 2021, the Company reflected an increase in its ARO liability, which is primarily attributable to establishing an ARO for a new solar generation field, which went into service in 2021, and a revision to the ARO for Culley East ash pond for a new closure methodology and estimated cash flows.
(5) Regulatory Assets & Liabilities
The following is a list of regulatory assets and liabilities reflected on the Company’s Balance Sheets as of December 31, 2022 and 2021.
|Future amounts recoverable from ratepayers related to:|
|Asset retirement obligations & other||$||30 ||$||37 |
|Net deferred income taxes||9 ||7 |
|Total future amounts recoverable from ratepayers||39 ||44 |
|Amounts deferred for future recovery related to:|
Extraordinary gas costs (1)
|— ||11 |
|Cost recovery riders||70 ||52 |
Gas recovery costs (1)
|— ||13 |
|Total amounts deferred for future recovery||70 ||76 |
|Amounts currently recovered through customer rates related to:|
|Authorized trackers and cost deferrals||82 ||89 |
Gas recovery costs (1)
|49 ||— |
|Loss on reacquired debt and hedging costs||— ||8 |
|Total amounts recovered in customer rates||131 ||97 |
|Total Regulatory Assets||$||240 ||$||217 |
|Total Current Regulatory Assets||$||49 ||$||24 |
|Total Non-current Regulatory Assets||$||191 ||$||193 |
|Regulatory liabilities related to TCJA||$||182 ||$||182 |
|Estimated removal costs||83 ||81 |
|Other regulatory liabilities||23 ||21 |
|Total Regulatory Liabilities||$||288 ||$||284 |
(1)Included in current regulatory assets on the Company’s Balance Sheets.
Of the $131 million currently being recovered in rates charged to customers, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $38 million, is 16 years. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable.
Regulatory assets for asset retirement obligations are primarily a result of costs incurred for expected retirement activity for the Company's ash ponds beyond what has been recovered in rates. See Notes 4 and 10 for further information. The Company believes the recovery of these assets are probable as the costs are currently being recovered in rates.
The deferred tax related regulatory liability is primarily the revaluation of deferred taxes at the reduced federal corporate tax rate that was enacted on December 22, 2017. These regulatory liabilities are being refunded to customers over time following regulatory commission approval.
For further information about the Company's regulatory matters, see Note 9.
February 2021 Winter Storm Event
In February 2021, the Company experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted its business. The February 2021 Winter Storm Event impacted wholesale prices of the Company’s natural gas purchases and its ability to serve customers in its service territory, including due to the reduction in available natural gas capacity and impacts to the Company’s natural gas supply portfolio activities, and the effects of weather on its systems and its ability to transport natural gas, among other things. The overall natural gas market, including the markets from which the Company sourced a significant portion of its natural gas for its operations, experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the price of natural gas purchased by the Company.
The Company deferred under-recovered natural gas cost as regulatory assets under existing recovery mechanisms. As of December 31, 2022 and 2021, the Company has recorded current regulatory assets of $-0- and $11 million, respectively, associated with the February 2021 Winter Storm Event through the gas cost recovery mechanism. The recovery of natural gas costs attributable to the February 2021 Winter Storm Event is complete.
COVID-19 Regulatory Matters
The Governor, public utility commission and other authorities in Indiana have issued a number of different orders related to the COVID-19 pandemic, including orders addressing customer non-payment and disconnection. Although the disconnect moratoriums have expired in the Company’s service territory, it continues to support those customers who may need payment assistance, arrangements or extensions.
The IURC has either (1) issued orders to record a regulatory asset for incremental bad debt expenses related to COVID-19, including costs associated with the suspension of disconnections and payment plans or (2) provided authority to recover bad debt expense through an existing tracking mechanism. The IURC issued an order in October 2021 for CEI South approving the settlement in its recent base rate case which included recovery of the applicable regulatory asset. The Company has recorded estimated incremental uncollectible receivables to the associated regulatory asset of $1 million, as of both December 31, 2022 and 2021.
The IURC has authorized utilities to employ deferred accounting authority for certain COVID-19 related costs which ensure the safety and health of customers, employees, and contractors, that would not have been incurred in the normal course of business.
(6) Transactions with Other Vectren Companies & Affiliates
Support Services and Purchases
Affiliates of CenterPoint Energy provide corporate and general and administrative services to the Company and allocate certain costs to the Company. These services are billed to the Company at actual cost, either directly or as allocation using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Affiliates of CenterPoint Energy provide other miscellaneous services, including geographic services and other management support. These services are billed at actual cost, and the charges are not necessarily indicative of what would have been incurred had CenterPoint Energy's subsidiaries not been affiliates. Amounts owed for support services and purchases at December 31, 2022 and 2021 are included in Accounts payable - affiliated companies.
Amounts charged for these services are included primarily in Operation and maintenance expenses:
|Year Ended December 31,|
|Corporate service charges||$||38 ||$||53 |
Property, Plant and Equipment
In 2022, the Company purchased certain property, plant and equipment assets from CenterPoint Energy at they net carrying value of $8 million on the date of purchase. In 2021, the Company purchased certain property, plant and equipment assets from VUH at their net carrying value of $61 million on the date of purchase.
Retirement Plans & Other Postretirement Benefits
As of December 31, 2022, Vectren maintains three closed qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement benefit plan includes health care and life insurance benefits which are a combination of self-insured and fully insured programs. Vectren’s current and former employees comprise the vast majority of the participants and retirees covered by these plans. Effective in 2021, certain participants of the Vectren Non-Bargaining Retirement Plan and all liabilities and assets associated with the accrued benefits of such participants were transferred to and became participants of the CenterPoint Energy pension plan.
Vectren satisfies the future funding requirements for its funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding obligation to the plans. The Company did not make a contribution in 2022 and 2021 to the Company's parents' defined benefit and pension plans. The Company's parent contributed less than $1 million to the CenterPoint Energy pension plan in 2022 and 2021 for Vectren participants. The Company contributed $1 million in both 2022 and 2021 to Vectren's SERP and post retirement benefit plans. The combined funded status of Vectren’s benefit pension plans was approximately 94 percent and 100 percent as of December 31, 2022 and 2021, respectively. The combined funded status of CenterPoint Energy's, excluding Vectren, defined pension plans was approximately 79 percent as of December 31, 2022.
Vectren allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to GAAP to its subsidiaries, which is also how the Company recovers retirement plan periodic costs through base rates. Periodic cost is charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. For both the years ended December 31, 2022 and 2021, costs totaling $3 million were charged to the Company from Vectren and CenterPoint Energy.
Any difference between the Company's funding requirements to Vectren and allocated periodic costs is recognized by the Company as an intercompany asset or liability. The allocation methodology to determine the intercompany funding requirements from the subsidiaries to Vectren is consistent with FASB guidance related to "multiemployer" benefit accounting. Neither plan assets nor plan obligations as calculated pursuant to GAAP by Vectren are allocated to individual subsidiaries, except for current portions of other postretirement benefit plan obligations which are allocated to individual subsidiaries.
As of December 31, 2022 and 2021, the Company had $16 million and $22 million, respectively, representing defined benefit pension funding by the Company to Vectren that is yet to be reflected in costs. As of December 31, 2022 and 2021, the Company had $17 million and $18 million, respectively, included in Other non-current liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to Vectren. The Company's labor allocation methodology is used to compute the Company's funding of the defined benefit retirement and other postretirement plans to Vectren, which is consistent with the regulatory ratemaking processes of the Company.
Share-Based Incentive Plans and Deferred Compensation Plans
The Company does not have share-based compensation plans separate from Vectren or CenterPoint Energy. As of December 31, 2021 most active employees of the deferred compensation plans were transferred out of VUH and into other CenterPoint Energy companies. As of December 31, 2022 and 2021, less than $1 million, respectively, is included in Other non-current liabilities and represents deferred compensation obligations that are yet to be funded in CenterPoint Energy's plan.
Cash Management Arrangements
The Company participates in the centralized cash management program with affiliates of Vectren. See Note 7 for further information regarding intercompany borrowing arrangements.
The Company does not file federal or state income tax returns separate from those filed by Vectren or CenterPoint Energy. Vectren is included in CenterPoint Energy's consolidated U.S. federal income tax return. Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from
it being a part of Vectren's consolidated tax group are recorded at the Company's parent level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.
Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company recognizes regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.
Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Other non-current liabilities.
ITCs are deferred and amortized to income over the approximate lives of the related property. Production tax credits PTCs are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.
The Company's gas and electric utilities currently recover corporate income tax expense in approved rates charged to customers. The IURC issued an order which initiated a proceeding to investigate the impact of the TCJA on utility companies and customers within the state. In addition, the IURC ordered the Company to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018. For further information, see Note 5.
The components of income tax expense/(benefit) and amortization of investment tax credits follow:
|Year Ended December 31,|
|State||— ||2 |
|Total current tax expense/(benefit)||(9)||2 |
|State||9 ||5 |
|Total deferred tax expense (benefit)||36 ||(6)|
|Investment tax credit amortization||— ||(1)|
|Investment tax credit deferred||— ||26 |
|Total income tax expense||$||27 ||$||21 |
A reconciliation of the federal statutory rate to the effective income tax rate follows:
|Year Ended December 31,|
|Statutory rate||21 ||%||21 ||%|
|State & local taxes, net of federal benefit||5 ||4 |
|Amortization of investment tax credit||— ||(1)|
|Research & development tax credits||— ||(1)|
|Regulatory liability amortization settled through rates||(3)||(4)|
|All other - net||(3)||(2)|
|Effective tax rate||20 ||%||17 ||%|
Significant components of the net deferred tax liability follow:
| December 31,|
|Non-current deferred tax assets:|
|Net operating loss & other carryforwards||$||36 ||$||26 |
| Regulatory liabilities settled through future rates||45 ||43 |
|Total deferred tax assets||81 ||69 |
|Non-current deferred tax liabilities:|
|Depreciation & cost recovery timing differences||349 ||299 |
|Regulatory assets recoverable through future rates||9 ||7 |
|Employee benefit obligations||1 ||2 |
|Deferred fuel costs||18 ||14 |
|Other – net||— ||8 |
|Total deferred tax liabilities||377 ||330 |
|Net deferred tax liability||$||296 ||$||261 |
As of December 31, 2022, the Company has $27 million investment tax credit carryforward that will expire in 2041. As of both December 31, 2022 and 2021, investment tax credits totaling $28 million are included in Other non-current liabilities, respectively.
Uncertain Tax Positions
Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Balance Sheets for unrecognized tax benefits inclusive of interest and penalties totaled $-0- and less than $1 million as of December 31, 2022 and 2021, respectively.
The Company's parent and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. Vectren's pre-Merger 2014-2019 tax years have been audited and settled with the IRS. The State of Indiana, Vectren's primary state tax jurisdiction, has concluded examinations of Vectren's consolidated state income tax returns for tax years through 2017 with no adjustments. The statutes of limitations for assessment of Indiana income tax have expired with respect to tax years through 2016 except to the extent of refunds claimed on amended tax returns. Tax years through 2018 have been audited and settled with the IRS for CenterPoint Energy. For the 2019-2021 tax years, CenterPoint Energy and its subsidiaries are participants in the IRS’s Compliance Assurance Process.
(7)Borrowing Arrangements & Other Financing Transactions
Long-term senior unsecured obligations and first mortgage bonds outstanding follow:
| December 31,|
|Fixed Rate Senior Unsecured Notes Payable to Affiliated Companies|
|2023, 3.72%||$||25 ||$||25 |
|2025, 1.21%||106 ||106 |
|2028, 3.20%||27 ||27 |
|2030, 1.72%.||75 ||75 |
|2032, 3.26%||75 ||75 |
|2035, 6.10%||25 ||25 |
|2035, 3.90%||17 ||17 |
| 2043, 4.25%||48 ||48 |
| 2045, 4.36%||16 ||16 |
| 2047, 3.93%||30 ||30 |
| 2049, 3.42%||80 ||80 |
|2050, 3.92%||100 ||100 |
| 2055, 4.51%||16 ||16 |
|2028, 4.67%||70 ||— |
|2033, 4.98%||70 ||— |
|Total long-term debt payable - affiliated companies||780 ||640 |
| Total long-term debt payable - affiliated companies, net of current maturities||$||755 ||$||640 |
|First Mortgage Bonds Payable to Third Parties:|
|2022, 2013 Series C, current adjustable rate .83%, tax-exempt||$||— ||$||5 |
|2024, 2013 Series D, current adjustable rate 4.25%, tax-exempt||23 ||23 |
|2025, 2014 Series B, current adjustable rate 4.25%, tax-exempt||41 ||41 |
|2029, 1999 Series, 6.72%||80 ||80 |
|2037, 2013 Series E, current adjustable rate 4.25%, tax-exempt||22 ||22 |
|2038, 2013 Series A, current adjustable rate 4.25%, tax-exempt||22 ||22 |
| 2043, 2013 Series B, current adjustable rate 4.25%, tax-exempt||40 ||40 |
| 2044, 2014 Series A, 4.00%, tax exempt||22 ||22 |
| 2055, 2015 Series Mt. Vernon, .875%, tax-exempt||15 ||15 |
| 2055, 2015 Series Warrick County, .875%, tax-exempt||23 ||23 |
|Total first mortgage bonds payable to third parties||288 ||293 |
Current maturities (1)
|Total long-term debt payable to third parties, net of current maturities||$||277 ||$||288 |
(1)On December 16, 2022, the Company provided notice of redemption and on January 17, 2023, the Company redeemed $11 million aggregate principal amount of its outstanding first mortgage bonds due 2044 at a redemption price equal to 100% of the principal amount of the first mortgage bonds to be redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date.
Credit Facilities. On December 6, 2022, CEI South entered into a new revolving credit facility totaling an additional $250 million in aggregate commitments. The Company had the following revolving credit facility as of December 31, 2022:
|Execution Date||Company||Size of Facility|
Draw Rate of SOFR plus (1)
|Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio|
Debt for Borrowed Money to Capital Ratio as of December 31, 2021 (2)
|December 6, 2022||CEI South||250 ||1.125%||65%||45.2%||December 6, 2027|
(1)Based on credit ratings as of December 31, 2022.
(2)As defined in the revolving credit facility agreement.
There were no borrowings outstanding under the revolving credit facility as of December 31, 2022.
Mandatory Tenders. Certain series of the Company's bonds, aggregating $186 million, are subject to mandatory tenders prior to the bond's final maturities and the Company expects to remarket them in 2023 at then market rates.
Future Long-Term Debt Sinking Fund Requirements and Maturities. As of December 31, 2022, the Company had approximately $288 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of the Company’s real and tangible property is subject to the lien of its mortgage indenture. As of December 31, 2022, the Company was permitted to issue additional bonds under its mortgage indenture up to 60% of then unfunded property additions and approximately $1.4 billion of additional first mortgage bonds could be issued on this basis. The mortgage indenture was amended and restated effective as of January 1, 2023 which, among other things, permits the Company to issue additional bonds up to 70% of currently unfunded property additions.
Maturities. As of December 31, 2022, maturities of long-term debt were as follows:
|Affiliate Debt||Third Party Debt||Total Debt|
|2023||$||25 ||$||11 ||$||36 |
|2024||— ||23 ||23 |
|2025||106 ||41 ||147 |
|2026||— ||— ||— |
|2027||— ||— ||— |
|2028 and thereafter||624 ||213 ||837 |
Covenants. Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2022, the Company was in compliance with all financial debt covenants.
(8)Commitments & Contingencies
(a) Purchase Obligations
Commitments include minimum purchase obligations related to the Company's Natural Gas reportable segment and Electric reportable segment. A purchase obligation is defined as an agreement to purchase goods or services that is enforceable and legally binding on the Company and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in the Company's Balance Sheets as of December 31, 2022 and 2021. These contracts meet an exception as “normal purchases contracts”
or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.
As of December 31, 2022, minimum purchase obligations were approximately:
|Natural Gas and Coal Supply|
|2023||$||120 ||$||71 |
|2024||60 ||90 |
|2025||50 ||678 |
|2026||42 ||43 |
|2027||43 ||43 |
|2028 and beyond||116 ||66 |
(1)Primarily the Company’s undiscounted minimum payment obligations related to PPAs with commitments ranging from 15 to 25 years and its purchase commitment under its BTA in Posey County, Indiana at the original contracted amount, prior to any renegotiation, and its BTA in Pike County, Indiana, are included above.
Excluded from the table above are estimates for cash outlays from other PPAs through CEI South that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.
For further details about the Company's BTAs and PPAs, see Note 9.
The Company entered into a third-party AMA beginning in April 2021 through March 2024 associated with its utility distribution service in Indiana. Pursuant to the provisions of the agreement, the Company either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between the Company and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, the Company agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for the Company and to use the released capacity for other purposes when it is not needed for the Company. The Company may receive compensation from the asset manager through payments made over the life of the AMAs. The Company has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs.
(c) Environmental and Other Matters
MGP Sites. The Company and its predecessors operated MGPs in the past. The costs the Company expects to incur to fulfill its obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While the Company has recorded obligations for all costs which are probable and estimable, including amounts it is presently obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.
Indiana MGPs. The Company has identified its involvement in 5 manufactured gas plant sites in the Company's service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.
Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to the Company's share of the remediation efforts and are therefore net of exposures of other PRPs. The
estimated range of possible remediation costs for the sites for which the Company believes it may have responsibility was based on remediation continuing for the minimum time frame given in the table below.
|December 31, 2022|
|(in millions, except years)|
|Amount accrued for remediation||$||2 |
|Minimum estimated remediation costs||1 |
|Maximum estimated remediation costs||8 |
|Minimum years of remediation||5 |
|Maximum years of remediation||20 |
The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.
The Company does not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows.
CCR Rule. In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by the Company's generating plants will continue to be reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. In August 2019, the EPA proposed additional “Part A” amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. Further “Part B” amendments, which related to alternate liners for CCR surface impoundments and the surface impoundment closure process, were published in March 2020. The Part A amendments were finalized in August 2020 and extended the deadline to cease placement of ash in ponds to April 11, 2021, discussed further below. The Part A amendments do not restrict the Company's current beneficial reuse of its fly ash. The Company evaluated the Part B amendments to determine potential impacts and determined that the Part B amendments did not have an impact on its current plans.
The Company has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the existing CCR Rule, the Company is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. The Company's Warrick generating unit is not included in the scope of the CCR Rule as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Preliminary groundwater monitoring indicates potential groundwater impacts very close to the Company's ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. The Company completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, the Company was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021, unless approved for an extension. The Company filed timely extension requests available under the CCR Rule that would allow the Company to continue to use the ponds through October 15, 2023. The EPA is still reviewing industry extension requests, including the Company's extension request. Companies can continue to operate ponds pending completion of the EPA’s evaluation of the requests for extension. If the EPA denies a full extension request, that denial may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or may adversely impact the Company's future operations. Failure to comply with a cease waste receipt could also result in an enforcement proceeding, resulting in the imposition of fines and penalties. On October 5, 2022, EPA issued a proposed conditional approval of the Part A extension request for the A.B. Brown pond. On April 24, 2019, the Company received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, the Company filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved the Company's ECA proceeding, which included the initiation of recovery of the federally mandated project costs.
In July 2018, the Company filed a Complaint for Damages and Declaratory Relief against its insurers seeking reimbursement of defense, investigation and pond closure costs incurred to comply with the CCR Rule, and has since reached confidential settlement agreements with its insurers. The proceeds of these settlements will offset costs that have been and will be incurred to close the ponds. On November 1, 2022, the Company filed for a CPCN to recover federally mandated costs associated with closure of the Culley East Pond, its third and final ash pond. The Company is also seeking accounting and ratemaking relief for the project. The project costs are estimated to be approximately $50 million, inclusive of overheads. OUCC and intervenor testimony was due
February 10, 2023 and the Company's rebuttal testimony was due on February 24, 2023. A hearing is currently scheduled for March 14, 2023.
As of December 31, 2022, the Company has recorded an approximate $104 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of the Company's generation transition plan; changing environmental regulations; and proceeds received from the settlements in the aforementioned insurance proceeding. In addition to these AROs, the Company also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.
Clean Water Act Permitting of Groundwater Discharges. In April 2020, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. The Company is evaluating the extent to which this decision will affect Clean Water Act permitting requirements and/or liability for its operations.
Other Environmental. From time to time, the Company identifies the presence of environmental contaminants during operations or on property where predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Company has and expects to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Company has received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been, or may be, named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.
The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Company is also defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.
COVID-19 Regulatory Matters
For information about COVID-19 regulatory matters, see Note 5 to the financial statements.
February 2021 Winter Storm Event
For information about February 2021 Winter Storm Event regulatory matters, see Note 5 to the financial statements.
CEI South CPCN
On February 23, 2021, the Company filed a CPCN with the IURC seeking approval to purchase the Posey solar project. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing the Company to purchase the Posey solar project through a BTA to acquire its solar array assets for a fixed purchase price and approved recovery of costs via a levelized rate over the anticipated 35-year life. Due to community feedback and rising project costs caused by inflation and supply chain issues affecting the energy industry, the Company, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey solar project to 191 MW. The Company collaboratively agreed to the scope change, and on February 1, 2023, the Company entered into an amended and restated BTA that is contingent on further IURC review and approval. On February 7, 2023, the Company filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, the Company can now pursue PTCs for solar projects. The Company will request that project costs, net of PTCs, be recovered in rate base rather than a levelized
rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. The Posey solar project is expected to be placed in service in 2025.
On July 5, 2022, the Company entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between the Company and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement granting the Company to purchase and acquire the Pike County solar project through a BTA and approved the estimated cost. The IURC also designated the project as a clean energy project under Ind. Code Ch. 8-1-8.8, approved the proposed levelized rate and associated ratemaking and accounting treatment. The project is expected to be placed in service by the first quarter of 2025.
On January 10, 2023, the Company filed a CPCN with the IURC to acquire a wind energy generating facility through a BTA, consistent with its 2019/2020 IRP that calls for up to 300 MWs of wind generation. The wind project is located in MISO’s Central Region. Commercial operation is expected in 2025. The Company has requested recovery via the CECA mechanism or through base rates in the next general rate case, depending on which provides more timely recovery. As of the date of these financial statements, the Company has not entered into any definitive agreement relating to this wind energy generating facility, and it is not certain that a definitive agreement will be entered into at all.
The Company also sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera and the Company were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, the Company filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA. The amended PPA will be brought before the IURC in a fully docketed proceeding in the second quarter of 2023. The Clenera solar array is expected to be placed in service in the second quarter of 2025.
On August 25, 2021, the Company filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving the Company to enter into both PPAs. In March 2022, when the results of the MISO interconnection study were completed, Origis advised the Company that the costs to construct the solar project in Knox County, Indiana had increased. The increase was largely driven by escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, the Company and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On October 19, 2022, the Company filed with the IURC seeking approval of the amended PPA with Origis and a hearing was held on January 4, 2023. On January 17, 2023, the Company filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. On February 22, 2023, the IURC approved the amended PPA with Origis. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. The amended PPA with Oriden will be brought before the IURC in a fully docketed proceeding in the second quarter of 2023. The Oriden solar array is expected to be placed in service in the second quarter of 2025 and the Origis solar array is expected to be placed in service by the third quarter of 2024.
Natural Gas Combustion Turbines
On June 17, 2021, the Company filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The estimated $334 million turbine facility is planned to be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. The Company received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date the Company's base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5 mile pipeline will be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. A party to the proceeding filed a petition for review of FERC’s order with the United States Court of Appeals for the District of Columbia on February 21, 2023. The Company granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. The facility is targeted to be operational by year end 2025. Recovery of the proposed natural gas combustion turbines and regulatory asset will be requested in the Company's next rate case expected in 2023.
Culley Unit 3 Operations
In June 2022, F.B. Culley Unit 3, the Company's coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine, and it remains out of service. The current estimate of the costs to repair F.B. Culley Unit 3 is approximately $6 million to $7 million, which will largely be capital expenditures. CenterPoint Energy has located a replacement boiler feed pump turbine which is currently being refurbished by the original equipment manufacturer to ensure it is in good working order. Currently, F.B. Culley Unit 3 is expected to return to service in the first half of 2023 depending on the time it takes to refurbish, install and test operation of the replacement turbine and related materials. CenterPoint Energy is evaluating the applicability of insurance coverages. For the duration of the unplanned outage, CenterPoint Energy expects to meet its generation capacity needs from its other generation units and power purchase agreements
Securitization of Planned Generation Retirements
The State of Indiana has enacted legislation, Senate Bill 386, that would enable the Company to request approval from the IURC to securitize the remaining book value and removal costs associated with certain generating facilities not more than twenty-four months before the unit is retired. The Governor of Indiana signed the legislation on April 19, 2021. On May 10, 2022, the Company filed an application with the IURC to securitize qualified costs associated with its planned retirements of coal generation facilities. Total qualified costs are estimated at $359 million, of which $350 million would be financed and $9 million are estimated total ongoing costs. A hearing was held before the IURC on September 7, 2022 and a final order was received on January 4, 2023 authorizing the issuance of up to $350 million in securitization bonds. Per Senate Bill 386, the Company has 90 days after the 30-day appeal period has expired to issue the securitization bonds, subject to an approved extension. As a result of this order, the Company will reclassify property, plant and equipment to be recovered through securitization to a regulatory asset in 2023.
In July 2021, the Company filed a petition with the IURC for the approval of a new financial services agreement and a final order was issued by the IURC on December 28, 2021.
Solar Panel Issues
The Company's current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects are primarily due to (i) unavailability of solar panels and other uncertainties related to the pending DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties; however, the investigation continues with the DOC’s final determination, which is currently scheduled for May 2023. In June 2022, President Biden authorized an executive order which would suspend anti-circumvention tariffs on solar panels for two years; however, the executive order could be subject to legal challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects.
Rate Change Applications
The Company is routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Company is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC, ECA and CECA for Electric). The table below reflects significant applications pending or completed since the Company’s 2021 financial statements were furnished to the SEC on Current Report 8-K dated March 16, 2022.
|Mechanism||Annual Increase (Decrease) (1) (in millions)||Filing Date||Effective Date||Approval Date||Additional Information|
|CSIA||9||October 2022||January 2023||January 2023||Requested an increase of $12 million to rate base, which reflects approximately $1 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of ($1 million) annually. Also included are unrecovered deferred O&M expenses of $9 million. OUCC filed on December 2, 2022 recommending approval of revenue requirement as filed, with additional recommendations on disallowing increases on cost estimates for a specific transmission project (no disallowances of actual costs in this filing). Rebuttal testimony was filed on December 9, 2022 responding to OUCC’s recommendations. A hearing was held on December 20, 2022, and an agreed upon joint proposed order was submitted to the judge on January 9, 2023, which the IURC approved on January 25, 2023.|
|2||February 2023||TBD||TBD||Requested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million).|
|—||February 2023||TBD||TBD||Requested an increase of less than $1 million to rate base, which reflects an annual increase of less than $1 million in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million).|
|3||August 2022||November 2022||November 2022|
Requested an increase of $43 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million).
|ECA||6||May 2022||August 2022||August 2022||Requested an increase of $21 million to rate base, which reflects a $9 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of ($3 million).|
Requested an increase of $42 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million.
Requested a decrease of less than $1 million to rate base, which reflects a $3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021.
(1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.
(10) Environmental and Sustainability Matters
On August 16, 2022, the IRA was signed into law. The new law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax on share repurchases after December 31, 2022, and implements a 15% corporate alternative minimum tax based on the AFSI of those corporations with an average AFSI of $1 billion over the most recent three-year period. The IRA did not have a material impact on the Company’s 2022
financial results and no material impact is expected for 2023 financial results. Further guidance on the tax provisions of the IRA is expected and the Company continues to evaluate the IRA provisions for the effect on its future financial results.
Greenhouse Gas Regulation and Compliance
There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. The EPA has announced it plans on issuing new GHG emissions rules in the future.
The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the U.S.' commitments announced in Glasgow. In September 2021, the Company announced its new net zero emissions goals for both Scope 1 and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. The Company's Scope 2 estimates exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. The Company's Scope 3 estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the EIA Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. The Company's net zero emissions goals are aligned with CEI South's generation transition plan and are expected to position CEI South to comply with anticipated future regulatory requirements related to GHG emissions reductions. The Company’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas. Incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Company’s services. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. These initiatives could have a significant impact on the Company and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. Further, our third party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact the Company’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to the Company. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit the Company. At this time, however, the Company cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Company’s business.
Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. Although the amount of compliance costs remains uncertain, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. While the requirements of a federal or state rule remain uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, the Company does not purchase carbon credits. In connection with its net zero emissions goals, the Company is expected to purchase carbon credits in the future; however, the Company does not currently expect the number of credits, or cost for those credits, to be material.
Climate Change Trends and Uncertainties
As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices,
and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Company's services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Company's systems and services, which may result in, among other things, the Company's generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on the Company's electric generation and natural gas businesses. For example, because the Company's current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in the Company's financing arrangements. Conversely, demand for the Company's services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of the Company's systems and services. Any negative opinions with respect to the Company's environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, legislators or other stakeholders could harm its reputation.
To address these developments,CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and certain Scope 2 emissions by 2035. The Company's 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. The Company continues to execute on its 2019/2020 IRP and has received approvals for 756 MWs of the 700-1,000 MWs identified within its 2019/2020 IRP. The Company believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its net zero emissions goals support global efforts to reduce the impacts of climate change.
To the extent climate changes result in warmer temperatures in the Company’s service territory, financial results from its business could be adversely impacted. For example, the Company could be adversely affected through lower natural gas sales. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. To the extent adverse weather conditions affect the Company’s suppliers, results from their natural gas business may suffer. When the Company cannot deliver natural gas to customers, or customers cannot receive services, the Company’s financial results can be impacted by lost revenues, and it generally must seek approval from regulators to recover restoration costs. To the extent the Company is unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Company’s future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact the Company’s ability to secure cost-efficient insurance.
In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved the Company's ELG compliance plan for its F.B. Culley Generating Station, and the Company is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.
Cooling Water Intake Structures
Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. The Company is currently completing the required ecological studies and anticipates timely compliance in 2023.
(11) Fair Value Measurements
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of
actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:
| December 31,|
|Carrying Amount||Est. Fair Value||Carrying Amount||Est. Fair Value|
|Long-term debt payable to third parties||$||288 ||$||273 ||$||293 ||$||316 |
|Long-term debt payable - affiliated companies||755 ||636 ||640 ||686 |
|Cash & cash equivalents||5 ||5 ||2 ||2 |
Natural gas purchase instrument assets (1)
|2 ||2 ||2 ||2 |
Interest rate swap assets(1)
|1 ||1 ||— ||— |
Interest rate swap liabilities (2)
|— ||— ||14 ||14 |
(1)Presented in Prepaid expenses and other current assets and Other non-current assets on the Balance Sheets.
(2)Presented in Accrued liabilities and Other non-current liabilities on the Balance Sheets.
Certain of the Company's interest rate swaps contain provisions that require the Company to maintain an investment grade credit rating on its long-term unsecured unsubordinated debt from S&P and Moody’s. If the Company's debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment.
|As of December 31,|
|Aggregate fair value of interest rate swaps with credit-risk-related contingent features in a liability position||$||— ||$||14 |
|Fair value of collateral already posted||— ||7 |
Additional collateral required to be posted if credit risk contingent features triggered (1)
|— ||7 |
(1)The maximum collateral required if further escalating collateral is triggered would equal the net liability position.
Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations.
The Company entered into two five-year forward purchase arrangements to hedge the variable price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s gas cost recovery mechanism.
(12) Segment Reporting
The Company’s determination of reportable segments considers the strategic operating units under which its CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company's CODM views net income as the measure of profit or loss for the reportable segments.
As of December 31, 2022, reportable segments are as follows:
•The Natural Gas segment provides natural gas distribution and transportation services to primarily southwestern Indiana.
•The Electric segment provides electric generation, transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations.
Information related to the Company’s business segments is summarized below:
|Revenues from External Customers||Depreciation and Amortization||Net Income |
|For the year ended December 31, 2022:|
|Natural Gas||$||146 ||$||19 ||$||19 |
|Electric||696 ||125 ||90 |
|Total||$||842 ||$||144 ||$||109 |
|For the year ended December 31, 2021:|
|Natural Gas||$||134 ||$||19 ||$||15 |
|Total||$||763 ||$||135 ||$||106 |
| ||Year Ended December 31,|
|Capital Expenditures || || |
| Natural Gas||$||86 ||$||73 |
| Electric ||315 ||254 |
| Non-cash costs & changes in accruals||(38)||(18)|
| Total capital expenditures||$||363 ||$||309 |
| December 31,|
|Natural Gas||$||697 ||$||626 |
|Electric ||2,723 ||2,448 |
| Total assets||$||3,420 ||$||3,074 |
(13) Supplemental Cash Flow Information
|Year Ended December 31,|
|Income tax payments (refunds)||$||17 ||$||(6)|
|Interest||33 ||32 |
|Accounts payable related to capital expenditures||$||39 ||$||14 |
|Non-cash contribution from VUH ||4 ||— |
(14) Impact of Recently Issued Accounting Standards
Management believes that recently adopted standards and recently issued standards that are not yet effective will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption.
An arrangement is determined to be a lease at inception based on whether the Company has the right to control the use of an identified asset. ROU assets represent the Company's right to use the underlying asset for the lease term and lease liabilities represent the Company's obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement dates, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Lease expense and lease income are recognized on a straight-line basis over the lease term for operating leases.
The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices.
The Company's lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Because risk is minimal, the Company does not take any significant actions to manage risk associated with the residual value of their leased assets.
The Company's lease agreements are primarily equipment and real property leases, including land and office facility leases. The Company's lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Company has elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.
The components of lease cost, included in Operation and maintenance on the Company's Statements of Income, were as follows:
|Year Ended December 31,|
|Operating lease cost||$||— ||$||1 |
|Short-term lease cost||1 ||1 |
|Total lease cost||$||1 ||$||2 |
Supplemental balance sheet information related to leases is as follows:
|(In millions, except lease term and discount rate)|
Operating ROU assets (1)
|$||1 ||$||2 |
|Total leased assets||$||1 ||$||2 |
Current operating lease liability (2)
|$||— ||$||1 |
Non-current operating lease liability (3)
|1 ||1 |
|Total lease liabilities||$||1 ||$||2 |
|Weighted-average remaining lease term (in years) - operating leases||17.5||13.0|
|Weighted-average discount rate - operating leases||3.65 ||%||3.60 ||%|
(1)Reported within Other non-current assets in the Balance Sheets.
(2)Reported within Accrued liabilities in the Balance Sheets.
(3)Reported within Other non-current liabilities in the Balance Sheets.
As of December 31, 2022, maturities of operating lease liabilities were as follows:
|2028 and beyond||1 |
| Total lease payments||$||2 |
|Less: Interest||1 |
| Present value of lease liabilities||$||1 |
Other information related to leases is as follows:
|Year Ended December 31, |
|Operating cash flows from operating leases included in the measurement of lease liabilities||$||1 ||$||1 |
(16) Subsequent Events
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. The Company's management has performed a review of subsequent events through March 13, 2023, the date the financial statements were issued.
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.
Executive Summary of Results of Operations
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.
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 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.
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 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 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 $469 million. A settlement hearing was held on June 24, 2021. On October 6, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in October 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, became effective in March 2022.
See Note 9 to the financial statements for more specific information on the significant regulatory proceedings involving the Company.
Throughout this discussion, the terms Natural Gas margin and Electric margin are used. Natural Gas margin is calculated as Natural Gas revenues less the Cost of gas sold. Electric margin is calculated as Electric revenues less Cost of fuel & purchased power. The Company believes Natural Gas and Electric margins are better indicators of relative contribution than revenues since
gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.
In addition, the Company separately reflects regulatory expense recovery mechanisms within Natural Gas margin and Electric margin. These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin.
Electric Margin (Electric revenues less Cost of fuel & purchased power)
Electric margin and volumes sold by customer type follows:
|Year Ended December 31,|
|Electric revenues||$||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 $3.3 million decrease in margin due to customer usage. Heating degree days were 107 percent of normal in 2022 compared to 101 percent of normal in 2021, and cooling degree days were 103 percent of normal in 2022 compared to 93 percent of normal in 2021.
Margin from Wholesale Electric Activities
The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of the MISO’s regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off-system margin and transmission system margin follows:
|Year Ended December 31,|
|MISO transmission system margin||$||25,534 ||$||24,128 |
|MISO off-system margin||16,455 ||13,426 |
|Total wholesale margin||$||41,989 ||$||37,554 |
Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $25.5 million during 2022 compared to $24.1 million in 2021, an increase of $1.4 million.
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 $7.5 million per year to be shared equally with customers.
Natural Gas Margin (Natural Gas revenues less Cost of gas sold)
Natural Gas margin and throughput by customer type follows:
|Year Ended December 31,|
|Natural Gas revenues||$||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.
Operation and Maintenance
For the year ended December 31, 2022, Operation and maintenance expenses were $246.9 million compared to $215.4 million in 2021, an increase of $31.5 million. The increase in operating expenses was primarily due to generation and support services costs.
Depreciation & Amortization
Depreciation and amortization expense was $144.1 million in 2022, compared to $134.8 million in 2021, an increase of $9.3 million. The increase resulted from additional utility plant investments placed into service, including property, plant and equipment assets purchased from CenterPoint Energy at its net carrying value as of the purchase date.
SELECTED ELECTRIC OPERATING STATISTICS
|For the Year Ended December 31,|
|OPERATING REVENUES (in millions):|
|Residential||$||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 ||$||443.2 |
|ELECTRIC SALES (In MWh):|
|Residential||1,398,174 ||1,416,843 |
|Commercial||1,210,034 ||1,165,594 |
|Industrial||1,967,271 ||2,040,869 |
|Other Sales - Street Lighting||20,255 ||20,665 |
|Total Retail||4,595,734 ||4,643,971 |
|Wholesale||882,864 ||1,457,358 |
|5,478,598 ||6,101,329 |
|Residential||132,402 ||131,125 |
|Commercial||19,135 ||19,143 |
|Industrial||114 ||114 |
|151,651 ||150,382 |
|WEATHER AS A % OF NORMAL:|
|Cooling Degree Days||103 ||%||114 ||%|
|Heating Degree Days||107 ||%||88 ||%|
SELECTED GAS OPERATING STATISTICS
|For the Year Ended December 31,|
|OPERATING REVENUES (in millions):|
|Residential||$||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 |
|Residential||104,495 ||104,043 |
|Commercial||10,531 ||10,517 |
|Industrial||119 ||111 |
|115,145 ||114,671 |