Document/ExhibitDescriptionPagesSize 1: 10-Q Quarterly Report HTML 1.51M
2: EX-31.1 Certification -- §302 - SOA'02 HTML 23K
3: EX-31.2 Certification -- §302 - SOA'02 HTML 23K
4: EX-32.1 Certification -- §906 - SOA'02 HTML 20K
5: EX-32.2 Certification -- §906 - SOA'02 HTML 20K
11: R1 Cover HTML 69K
12: R2 Unaudited Condensed Consolidated Statements Of HTML 94K
Operations
13: R3 Unaudited Condensed Consolidated Statements of HTML 47K
Comprehensive Income Statement
14: R4 Unaudited Condensed Consolidated Balance Sheets HTML 186K
15: R5 Unaudited Condensed Consolidated Statements Of HTML 125K
Cash Flows
16: R6 Unaudited Condensed Consolidated Statements of HTML 101K
Common Stockholders' Equity ( Deficit) Statement
17: R7 Overview and Summary Of Significant Accounting HTML 92K
Policies
18: R8 Regulatory Matters HTML 28K
19: R9 Fair Value HTML 85K
20: R10 Derivative Instruments and Hedging Activities HTML 56K
(Notes)
21: R11 Debt HTML 62K
22: R12 Income Taxes HTML 23K
23: R13 Benefit Plans HTML 41K
24: R14 Commitments And Contingencies HTML 25K
25: R15 Business Segment Information (Notes) HTML 74K
26: R16 Revenue (Notes) HTML 54K
27: R17 Leases (Notes) HTML 38K
28: R18 Overview and Summary Of Significant Accounting HTML 99K
Policies (Policies)
29: R19 Leases, Codification Topic 842 (Policies) HTML 38K
30: R20 Overview and Summary Of Significant Accounting HTML 88K
Policies (Tables)
31: R21 Fair Value (Tables) HTML 68K
32: R22 Derivative Instruments and Hedging Activities HTML 33K
(Tables)
33: R23 Debt (Tables) HTML 57K
34: R24 Benefit Plans (Tables) HTML 36K
35: R25 Business Segment Information (Tables) HTML 69K
36: R26 Revenue (Tables) HTML 22K
37: R27 Leases (Tables) HTML 25K
38: R28 Overview and Summary of Significant Accounting HTML 248K
Policies (Details)
39: R29 Overview and Summary Of Significant Accounting HTML 28K
Policies Schedule of Changes in Asset Retirement
Obligation (Details)
40: R30 Overview and Summary Of Significant Accounting HTML 28K
Policies Schedule of cash, restricted cash and
cash equivalents (Details)
41: R31 Overview and Summary Of Significant Accounting HTML 42K
Policies Schedule of Accounts and notes receivable
(Details)
42: R32 Regulatory Matters (Details) HTML 40K
43: R33 Fair Value (Narrative) (Details) HTML 98K
44: R34 Fair Value Summary of fair value Assets and HTML 46K
Liabilities Measured on a Recurring Basis
(Details)
45: R35 Fair Value (Schedule Of Face And Fair Value Of HTML 38K
Debt) (Details)
46: R36 Derivative Instruments and Hedging Activities HTML 85K
(Details)
47: R37 Debt (Schedule Long-Term Indebtedness) (Details) HTML 101K
48: R38 Debt (Narrative) (Details) HTML 53K
49: R39 Income Taxes (Narrative) (Details) HTML 26K
50: R40 Benefit Plans (Narrative) (Details) HTML 22K
51: R41 Benefit Plans (Schedule Of Defined Benefit Plans HTML 36K
Disclosures) (Details)
52: R42 Benefit Plans (Schedule Of Net Periodic Benefit HTML 37K
Costs) (Details)
53: R43 Commitments and Contingencies (Details) HTML 20K
54: R44 Business Segment Information (Details) HTML 75K
55: R45 Revenue (Details) HTML 67K
56: R46 Leases (Details) HTML 49K
59: XML IDEA XML File -- Filing Summary XML 107K
57: XML XBRL Instance -- cik0000728391-20230930_htm XML 1.45M
58: EXCEL IDEA Workbook of Financial Report Info XLSX 120K
7: EX-101.CAL XBRL Calculations -- cik0000728391-20230930_cal XML 158K
8: EX-101.DEF XBRL Definitions -- cik0000728391-20230930_def XML 1.02M
9: EX-101.LAB XBRL Labels -- cik0000728391-20230930_lab XML 2.10M
10: EX-101.PRE XBRL Presentations -- cik0000728391-20230930_pre XML 1.33M
6: EX-101.SCH XBRL Schema -- cik0000728391-20230930 XSD 203K
60: JSON XBRL Instance as JSON Data -- MetaLinks 567± 846K
61: ZIP XBRL Zipped Folder -- 0000728391-23-000045-xbrl Zip 642K
(Exact name of registrant as specified in its charter)
iIndiana
i35-1575582
(State
or other jurisdiction of incorporation or organization)
(I.R.S Employer Identification No.)
iOne Monument Circle
iIndianapolis, iIndiana
i46204
(Address
of principal executive offices)
(Zip code)
Registrant's telephone number, including area code:
(i317)-i261-8261
Securities
registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
N/A
N/A
N/A
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days. Yes ☐iNo☒
(The registrant is a voluntary filer. The registrant has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)
Indicate by check mark whether the
registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting
company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
iNon-accelerated
filer
Smaller Reporting company
Emerging growth company
☐
☐
☒
i☐
i☐
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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐
No ☒
At November 2, 2023, i108,907,318 shares of IPALCO Enterprises, Inc. common stock were outstanding, of which i89,685,177
shares were owned by AES U.S. Investments, Inc. and i19,222,141 shares were owned by CDP Infrastructures Fund L.P., a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec.
The following is a list of frequently used terms, abbreviations or acronyms that are found in this Form 10-Q:
2022 Form 10-K
IPALCO’s Annual Report on Form 10-K for the year ended December 31, 2022, as amended
2024 IPALCO Notes
$405 million of 3.70% IPALCO Enterprises, Inc. Senior Secured Notes due September 1, 2024
2030 IPALCO Notes
$475 million
of 4.25% IPALCO Enterprises, Inc. Senior Secured Notes due May 1, 2030
ACE
Affordable Clean Energy
AES
The AES Corporation
AES Indiana
Indianapolis Power & Light Company and its consolidated subsidiaries, which does business as AES Indiana
AES U.S. Investments
AES U.S. Investments, Inc.
AFUDC
Allowance
for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income
AOCL
Accumulated Other Comprehensive Loss
ARO
Asset Retirement Obligation
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
BESS
Battery Energy Storage System
BIL
Bipartisan
Infrastructure Law, also known as the Infrastructure Investment and Jobs Act
CAA
U.S. Clean Air Act
CCGT
Combined Cycle Gas Turbine
CCR
Coal Combustion Residuals
CDPQ
CDP Infrastructures Fund L.P., a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec
CO2
Carbon Dioxide
CPCN
Certificate
of Public Convenience and Necessity
Credit Agreement
$350 million AES Indiana Revolving Credit Facilities Second Amended and Restated Credit Agreement, dated as of December 22, 2022
CSAPR
Cross-State Air Pollution Rule
CWA
U.S. Clean Water Act
DSM
Demand Side Management
EGUs
Electrical Generating Units
ELG
Effluent
Limitation Guidelines
EPA
U.S. Environmental Protection Agency
EV
Electric Vehicle
FAC
Fuel Adjustment Clause
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Financial Statements
Unaudited Condensed Consolidated Financial Statements of IPALCOin
“Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q
FIP
Federal Implementation Plan
FTRs
Financial Transmission Rights
GAAP
Generally Accepted Accounting Principles in the United States
GHG
Greenhouse Gas
HLBV
Hypothetical Liquidation Book Value
IDEM
Indiana
Department of Environmental Management
IPALCO
IPALCO Enterprises, Inc. and its consolidated subsidiaries
IPL
Indianapolis Power & Light Company and its consolidated subsidiaries, which does business as AES Indiana
IRA
Inflation Reduction Act of 2022
IRP
Integrated Resource Plan
ITC
Investment
Tax Credit
4
IURC
Indiana Utility Regulatory Commission
kWh
Kilowatt hours
MATS
Mercury and Air Toxics Standards
MISO
Midcontinent Independent System Operator, Inc.
MW
Megawatts
MWh
Megawatt
hours
NAAQS
National Ambient Air Quality Standards
NOx
Nitrogen Oxide
NPDES
National Pollutant Discharge Elimination System
NSPS
New Source Performance Standards
Pension Plans
Employees’ Retirement Plan of AES Indiana and Supplemental Retirement Plan of AES Indiana
PTC
Production
Tax Credit
RFP
Request for Proposal
SEC
United States Securities and Exchange Commission
Service Company
AES US Services, LLC
SO2
Sulfur Dioxide
TDSIC
Transmission, Distribution, and Storage System Improvement Charge
URT
Utility
Receipts Tax
U.S.
United States of America
USD
United States Dollars
VEBA
Voluntary Employees' Beneficiary Association
WOTUS
Waters of the U.S.
Throughout this document, the terms "IPALCO,"“the
Company,”“we,”“us,” and “our” refer to IPALCO Enterprises, Inc. and its consolidated subsidiaries. The term “IPALCO Enterprises, Inc.” refers only to the parent holding company, IPALCO Enterprises, Inc, excluding its subsidiaries.
We encourage investors, the media, our customers and others interested in the Company
to review the information we post at https://www.aesindiana.com. None of the information on our website is incorporated into, or deemed to be a part of, this Quarterly Report on Form 10-Q or in any other report or document we file with the SEC, and any reference to our website is intended to be an inactive textual reference only.
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes “forward-looking statements”
within the meaning of the Private Securities Litigation Reform Act of 1995 including, in particular, the statements about our plans, strategies and prospects under the heading “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part I – Financial Information of this Form 10-Q. Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenues, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,”“may,”“predict,”“anticipate,”“would,”“believe,”“estimate,”“expect,”“forecast,”“project,”“objective,”“intend,”“continue,”“should,”“plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.
Some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to:
•impacts of weather on retail sales;
•growth in our service territory and changes in retail demand and demographic patterns;
•weather-related damage to our electrical system;
•commodity and other input costs;
•performance
of our suppliers;
5
•transmission, distribution and generation system reliability and capacity, including natural gas pipeline system and supply constraints;
•regulatory actions and outcomes, including, but not limited to, the review and approval of our rates and charges by the IURC;
•federal and state legislation and regulations;
•changes in our credit ratings or the credit ratings of AES;
•fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and
our ability to fund defined benefit pension plans;
•changes in financial or regulatory accounting policies;
•environmental and climate change matters, including costs of compliance with, and liabilities related to, current and future environmental and climate change laws and requirements;
•interest rates and the use of interest rate hedges, inflation rates and other costs of capital;
•the availability of capital;
•the ability of subsidiaries to pay dividends or distributions to IPALCO Enterprises, Inc.;
•level
of creditworthiness of counterparties to contracts and transactions;
•labor strikes or other workforce factors, including the ability to attract and retain key personnel;
•facility or equipment maintenance, repairs and capital expenditures;
•significant delays or unanticipated cost increases associated with construction or other projects;
•the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;
•local economic
conditions;
•costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation, cyber-attacks and information security breaches;
•industry restructuring, deregulation and competition;
•issues related to our participation in MISO, including the cost associated with membership, our continued ability to recover costs incurred, and the risk of default of other MISO participants;
•changes in tax laws and the effects of our tax strategies;
•product
development, technology changes, and changes in prices of products and technologies;
•catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences; and
•the risks and other factors discussed in this report and other IPALCO filings with the SEC.
Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. If we do update one or
more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.
All of the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See “Item 1A. Risk Factors” in IPALCO’s 2022 Annual Report on Form 10-K and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in IPALCO’s 2022 Annual Report on Form 10-K and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, and June 30, 2023 and this Quarterly Report on Form 10-Q for a more detailed discussion of the foregoing and certain other factors that could cause actual results
to differ materially from those reflected in any forward-looking statements. These risks may also be specifically described in our other Quarterly Reports on Form 10-Q in "Part II - Item 1A. Risk Factors", Current Reports on Form 8-K and other documents that we may file from time to time with the SEC.
Our SEC filings are available to the public from the SEC’s website at www.sec.gov.
1)
I (1) All of AES Indiana's preferred stock was redeemed on December 30, 2022.
(2) IPALCO made return of capital payments of $i46.5 million and $i33.3 million
during the nine months ended September 30, 2023 and 2022, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.
See
Notes to Condensed Consolidated Financial Statements.
1.
OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO is owned by AES U.S. Investments (i82.35%) and CDPQ (i17.65%). AES
U.S. Investments is owned by AES U.S. Holdings, LLC (i85%) and CDPQ (i15%). IPALCO owns all of the outstanding common stock of IPL, which does business as AES Indiana. Substantially all of IPALCO’s business consists of generating, transmitting,
distributing and selling of electric energy conducted through its principal subsidiary, AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana has approximately i521,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers. AES Indiana owns and operates ifour
generating stations, all within the state of Indiana. AES Indiana’s largest generating station, Petersburg, is coal-fired, and AES Indiana retired i230 MW Petersburg Unit 1 in May 2021 and i415 MW Petersburg Unit 2 in June 2023, which resulted in i630
MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas by the end of 2025 (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to IPALCO’s 2022 Form 10-K). The second largest station, Harding Street, uses natural gas and fuel oil to power steam and combustion turbines. In addition, AES Indiana operates a i20 MW battery energy storage unit at this location, which provides frequency response.
The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of September 30, 2023, AES Indiana’s net electric generation capacity for winter is i3,070 MW and net summer capacity is i2,925
MW. On December 17, 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). As amended in December 2022 and approved by the IURC in August 2023, the Hardy Hills Solar Project is now expected to be completed in 2024. On August 31, 2023, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 180 MWh energy storage facility (the "Petersburg Energy Center Project"). As amended in October 2022 and approved by the IURC in May 2023, the Petersburg Energy Center Project is now expected to be completed in 2025.
i
Consolidation
The
accompanying Financial Statements include the accounts of IPALCO Enterprises, Inc., AES Indiana and Mid-America Capital Resources, Inc., a non-regulated wholly-owned subsidiary of IPALCO. All significant intercompany amounts have been eliminated in consolidation.
Interim Financial Presentation
The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with GAAP, as contained in the FASB ASC, for interim financial information and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial
position, comprehensive income, changes in equity, and cash flows. The results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of expected results for the year ending December 31, 2023. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2022 audited consolidated financial statements and notes thereto, which are included in IPALCO's 2022 Form 10-K.
i
Use of Management Estimates
The
preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimatesi. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenues; the carrying value of property, plant and equipment;
the
//
12
valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.
Reclassifications
Certain immaterial amounts from prior periods have been reclassified to conform to the current
year presentation.
i
Cash, Cash Equivalents and Restricted Cash
i
The following table provides a summary of cash, cash equivalents and restricted cash amounts reported on the Condensed Consolidated Balance
Sheets that reconcile to the total of such amounts as shown on the Condensed Consolidated Statements of Cash Flows:
The
following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the nine months ended September 30, 2023 and 2022, respectively:
For the Nine Months Ended September 30,
$ in Thousands
2023
2022
Allowance
for credit losses:
Beginning balance
$
i1,117
$
i647
Current
period provision
i5,536
i4,046
Write-offs
charged against allowances
(i6,940)
(i5,049)
Recoveries
collected
i1,351
i1,201
Ending
Balance
$
i1,064
$
i845
/
The
allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future
//
13
economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections
efforts have been exhausted.
AES
Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability for the nine months ended September 30, 2023 and 2022, respectively:
AES
Indiana recorded adjustments to its ARO liabilities of $i0.0 million and $i23.2 million for the nine months ended September 30, 2023 and 2022,
respectively, primarily to reflect revisions to cash flow and timing estimates due to increases to estimated ash pond closure costs and accelerated landfill closure dates. As of September 30, 2023 and December 31, 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability. For further information on AES Indiana’s ARO, see Note 3, "Property, Plant and Equipment - ARO" to IPALCO’s 2022 Form 10-K.
AFUDC
In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period
of construction with a corresponding credit to income. During the three and nine months ended September 30, 2023, AFUDC equity was $i3.1 million and $i7.1
million, respectively, and AFUDC debt was $i3.8 million and $i9.5 million, respectively. During the three and nine months ended
September 30, 2022, AFUDC equity was $i1.4 million and $i4.8 million, respectively, and AFUDC debt was $i2.5
million and $i5.8 million, respectively.
Intangible Assets
Finite-lived intangible assets include capitalized software and project development intangible assets amortized over their useful lives. Capitalized software of $i252.3
million and $i205.9 million and its corresponding accumulated amortization of $i116.7 million and $i107.2
million is recorded as of September 30, 2023 and December 31, 2022,
14
respectively. Amortization expense for capitalized software was $i9.7 million and $i7.6
million for the nine months ended September 30, 2023 and 2022, respectively. These capitalized software intangible assets have a 7 year-weighted average amortization period, and the estimated amortization expense is approximately $i40.7 million over the next 5 years ($i8.5 million
in 2024, $i8.4 million in 2025, $i8.4 million in 2026, $i7.7 million
in 2027 and $i7.7 million in 2028). Project development intangible assets were $i84.1 million and $i39.5
million as of September 30, 2023 and December 31, 2022, respectively. These project development intangible assets have a 28 year-weighted average amortization period, and the estimated amortization expense is approximately $i11.6 million over the next 5 years ($i1.0 million
in 2024, $i1.3 million in 2025, $i3.1 million in 2026, $i3.1 million
in 2027 and $i3.1 million in 2028).
Accumulated Other Comprehensive Income / (Loss)
i
The
amounts reclassified out of AOCI / (AOCL) by component during the three and nine months ended September 30, 2023 and 2022 are as follows (in Thousands):
Details about AOCI / (AOCL) components
Affected line item in the Condensed Consolidated Statements of Operations
Total
reclassifications for the period, net of income taxes
$
i1,358
$
i1,358
$
i4,073
$
i4,073
/
See
Note 4, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCI / (AOCL).
Operating Expenses – Other, Net
Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the nine months ended September 30, 2022, the $i3.2 million
is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition.
Related Party Transactions
In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $i29.8 million to this vendor during the nine months ended September 30,
2023.
New Accounting Pronouncements Adopted in 2023
We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements.
15
New Accounting Pronouncements Issued But Not Yet Effective
The following table provides a brief description of recent accounting pronouncements that could have a material impact on the
Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.
ASU Number and Name
Description
Date of Adoption
Effect on the Financial Statements upon adoption
2023-06
Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative
In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC.
The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users
to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.
The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited.
The Company is currently evaluating the impact of adopting the standard on its Financial Statements.
i
2.
REGULATORY MATTERS
Regulatory Rate Review
AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. The
Company also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. AES Indiana's proposed revenue increase is $134 million annually, or 8.9%. A hearing on this petition is expected to be held in December 2023. We expect to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.
DSM
AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. A hearing was held in September 2023, and we expect the IURC to issue an order on this proceeding during the fourth quarter of 2023.
Replacement
Generation
Hardy Hills Solar Project
In December 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 1, LLC, closed on an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.
16
Petersburg
Energy Center Project
In July 2021, AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 2, LLC, executed an agreement for the acquisition and construction of a 250 MW solar and 180 MWh energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition
of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $i48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"for further information).
Pike County BESS Project
In June 2023,
AES Indiana, through its wholly-owned subsidiary AES Indiana Devco Holdings 3, LLC, executed an agreement for the construction of the 200 MW Pike County BESS project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC review is expected to be completed during the fourth quarter of 2023. Subject to IURC approval, the Pike County BESS project is expected to be completed in 2024.
Hoosier Wind Project
On July 5, 2023, AES Indiana filed a Notice of
Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and a hearing was held in October 2023. IURC review is expected to be completed during the fourth quarter of 2023.
EV Portfolio Program
On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment.
The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $i16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held
in July 2023, and we expect the IURC to issue an order on this request during the fourth quarter of 2023.
Storm Outage Restoration Inquiry
On July 11, 2023, the Indiana Office of Utility Consumer Counselor (“OUCC”) and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.
3.
iFAIR VALUE
The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. For further information on our
valuation techniques and policies, see Note 4, "Fair Value" to IPALCO’s 2022 Form 10-K.
17
Financial Assets and Liabilities
VEBA Assets
IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Condensed Consolidated Balance Sheets and classified as equity
securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the periods covered by this report. Any unrealized gains or losses are recorded in "Other (expense) / income, net" on the accompanying Condensed Consolidated Statements of Operations.
FTRs
In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices
for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenues or costs will be flowed through to customers through the FAC. As such, there is no impact on our Condensed Consolidated Statements of Operations.
Interest Rate Hedges
IPALCO's interest rate hedges have a combined notional amount of $i400.0
million. All changes in the market value of the interest rate hedges are recorded in AOCI / (AOCL). See also Note 4, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.
Recurring Fair Value Measurements
i
The fair value of assets and liabilities at September 30, 2023 and December 31,
2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows (In Thousands):
The
following table presents a reconciliation of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy for the periods ending (In Thousands):
Financial
Instruments not Measured at Fair Value in the Condensed Consolidated Balance Sheets
Debt
The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.
i
The
following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:
For further information on the Company’s derivative and hedge
accounting policies, see Note 1, "Overview and Summary of Significant Accounting Policies - Financial Derivatives" and Note 5, "Derivative Instruments and Hedging Activities" to IPALCO’s 2022 Form 10-K.
i
At September 30, 2023, AES Indiana's outstanding derivative instruments were as follows:
Commodity
Accounting
Treatment (a)
Unit
Notional (in thousands)
Sales (in thousands)
Net Notional (in thousands)
Interest rate hedges
Designated
USD
$
i400,000
$
i—
$
i400,000
FTRs
Not
Designated
MWh
i6,264
i—
i6,264
(a) Refers
to whether the derivative instruments have been designated as a cash flow hedge.
/
Cash Flow Hedges
As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair
19
values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract
expiration.
iThe following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:
Interest
Rate Hedges for the Three Months Ended September 30,
Interest Rate Hedges for the Nine Months Ended September 30,
$ in thousands (net of tax)
2023
2022
2023
2022
Beginning accumulated derivative gain (loss) in AOCI / (AOCL)
$
i24,827
$
i7,799
$
i22,269
$
(i29,407)
Net
gains associated with current period hedging transactions
i7,482
i13,136
i7,325
i47,627
Net
losses reclassified to interest expense, net of tax
i1,358
i1,358
i4,073
i4,073
Ending
accumulated derivative gain in AOCI
$
i33,667
$
i22,293
$
i33,667
$
i22,293
Loss
expected to be reclassified to earnings in the next twelve months
$
(i5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows
related to forecasted transactions (in months)
i12
Derivatives Not Designated as Hedge
AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions
under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Condensed Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting". Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized losses of $i0.0 million
and $i0.2 million for the three and nine months ended September 30, 2023. There were net realized gains of $i0.0 million
and $i1.3 million related to forward power contracts for the three and nine months ended September 30, 2022.
Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts
that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or mark to market accounting and are recognized in the Condensed Consolidated Statements of Operations on an accrual basis.
When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of September 30, 2023 and December 31, 2022, IPALCO did not have any offsetting positions.
The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands):
(1)First
mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.
(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.
/
Line of Credit
As of September 30, 2023 and December 31, 2022, AES Indiana had $i75.0 million
and $i0.0 million in outstanding borrowings under the committed Credit Agreement, respectively.
IPALCO’s Senior Secured Notes
IPALCO has $i405 million of i3.70%
Senior Secured Notes due September 1, 2024 ("2024 IPALCO Notes"). Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.
21
6.
iINCOME TAXES
IPALCO's provision for income taxes is based on the estimated annual effective tax rate, plus discrete items. The effective combined state and federal income tax rates were i9.7% and i12.2%
for the three and nine months ended September 30, 2023, respectively, as compared to i19.5% and i20.5% for the three and nine months ended September 30, 2022,
respectively. The year-to-date rate is different from the combined federal and state statutory rate of i24.9% primarily due to the flowthrough of the net tax benefit related to the reversal of excess deferred taxes of AES Indiana, which was partially offset by the net tax expense related to the amortization of allowance for equity funds used during construction.
IPALCO’s income tax expense for the nine months ended September 30,
2023, was calculated using the estimated annual effective income tax rate for 2023 of i12.2% on ordinary income. Management estimates the annual effective tax rate based on its forecast of annual pre-tax income or loss.
AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision
for income taxes using a separate return method.
7. iBENEFIT PLANS
i
The
following table presents the net periodic benefit cost / (credit) of the Pension Plans combined:
Components of net periodic benefit cost / (credit):
Service cost
$
i1,297
$
i2,238
$
i3,892
$
i6,714
Interest
cost
i7,455
i4,530
i22,365
i13,570
Expected
return on plan assets
(i8,277)
(i8,914)
(i24,830)
(i26,747)
Amortization
of prior service cost
i543
i647
i1,629
i1,942
Amortization
of actuarial loss
i1,536
i603
i4,608
i1,815
Net
periodic benefit cost / (credit)
$
i2,554
$
(i896)
$
i7,664
$
(i2,706)
/
The
components of net periodic benefit cost / (credit) other than service cost are included in "Other (expense) / income, net"in the Condensed Consolidated Statements of Operations.
In addition, AES Indiana provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. These postretirement health care benefits and the related unfunded obligation of $i3.2 million at September 30,
2023 and December 31, 2022, respectively, were not material to the Financial Statements in the periods covered by this report.
22
8. iCOMMITMENTS AND CONTINGENCIES
Contingencies
Legal
Matters
IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. As of September 30, 2023 and December 31, 2022, total legal loss contingencies accrued were $i0.2 million and $i0.1 million,
respectively, which primarily related to personal injury litigation. The legal loss contingencies and settlement related accruals are included in "Accrued and other current liabilities" and "Other Non-Current Liabilities" on the accompanying Condensed Consolidated Balance Sheets. We maintain an amount of insurance protection for such litigation that we believe is adequate. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.
Coal Ash Insurance Litigation
In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint
seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.
Environmental Matters
We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including CCR; the use and discharge of water used
in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits.
23
9.
iBUSINESS SEGMENTS
IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility. with all other nonutility business activities aggregated separately. See Note 1, "Overview
and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balances associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.
i
The following table provides information about IPALCO’s business segments (in thousands):
Revenues are primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenues are recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenues are recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities. Please see Note 13, “Revenues”
to IPALCO’s 2022 Form 10-K for further discussion of our retail, wholesale and miscellaneous revenues.
AES Indiana’s revenues from contracts with customers were $i393.9 million and $i486.3 million
for the three months ended September 30, 2023 and 2022, respectively, and $i1,265.0 million and $i1,285.5 million
for the nine months ended September 30, 2023 and 2022, respectively. The following table presents our revenues from contracts with customers and other revenues (in thousands):
Total
miscellaneous revenues from contracts with customers
i1,221
i6,609
i11,359
i11,557
Other
miscellaneous revenues (2)
i1,070
i467
i2,417
i2,036
Total
Revenues
$
i402,887
$
i494,194
$
i1,290,580
$
i1,307,919
(1)Other
retail revenues from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.
(2)Other miscellaneous revenues includes lease and other miscellaneous revenues not accounted for under ASC 606.
iThe balances of receivables from contracts with customers were $i167.6
million and $i198.3 million as of September 30, 2023 and December 31, 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.
25
11.
iLEASES
Lessor
The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenues on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.
The following table
presents lease revenues from operating leases in which the Company is the lessor for the periods indicated (in thousands):
The
following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):
The
option to extend or terminate a lease is based on customary early termination provisions in the contract. The Company has not recognized any early terminations as of September 30, 2023 or December 31, 2022, respectively.
i
The following table shows the future lease receipts as of September 30, 2023
for the remainder of 2023 through 2027 and thereafter (in thousands):
Operating Leases
2023
$
i136
2024
i544
2025
i553
2026
i554
2027
i554
Thereafter
i1,245
Total
$
i3,586
/
26
ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the Financial Statements and the notes thereto included in “Item 1. Financial Statements” included in Part I – Financial Information of this Form 10-Q.
FORWARD-LOOKING INFORMATION
The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results
of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in IPALCO’s 2022 Form 10-K and subsequent filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are
urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and uncertainties that may affect our business.
OVERVIEW OF OUR BUSINESS
IPALCO is a holding company incorporated under the laws of the state of Indiana. Our principal subsidiary is AES Indiana, a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through AES Indiana. Our business segments are “utility” and “all other.” For additional information regarding our business, see "Item 1. Business”of IPALCO's 2022 Form 10-K.
EXECUTIVE
SUMMARY
Compared with the same periods in the prior year, the results for the three months ended September 30, 2023 reflect higher income before income tax of $8.4 million, or 27.1% and the results for the nine months ended September 30, 2023 reflect lower income before income tax of $18.1 million, or 20.3%, primarily due to factors including, but not limited to:
Three
Months Ended
Nine Months Ended
September 30,
September 30,
$ in millions
2023 vs. 2022
2023 vs. 2022
Decrease in retail margin primarily due to lower volumes driven by weather and lower demand
$
(7.1)
$
(45.7)
Decrease
due to higher defined benefit plan costs driven by increase in interest cost
(4.4)
(13.1)
Decrease due to higher depreciation expense from additional assets placed in service and higher amortization of regulatory assets
(5.2)
(13.2)
Decrease
due to impact of lower NOx allowance pricing on retail margin
(7.6)
(7.3)
Increase due to a charge to power purchased costs recorded in the prior period resulting from settlement of the FAC sub-docket on the Eagle Valley CCGT extended outage
27.8
27.8
Increase in TDSIC rider revenues
6.5
18.9
(Decrease)
/ increase driven by (higher) / lower contracted services expenses primarily due to higher / (lower) generation maintenance and outage costs
(2.7)
6.7
Increase due to lower health insurance and disability expense
0.6
5.5
Other
0.5
2.3
Net
change in income before income tax
$
8.4
$
(18.1)
See "Results of Operations" below for further discussion.
27
RESULTS OF OPERATIONS
The
electric utility business is affected by seasonal weather patterns throughout the year and, therefore, operating revenues and associated expenses are not generated evenly by month during the year.
Statements of Operations Highlights
Three
Months Ended
Nine Months Ended
September 30,
September 30,
$ in Thousands
2023
2022
$ Change
% Change
2023
2022
$
Change
% Change
REVENUES
$
402,887
$
494,194
$
(91,307)
(18.5)
%
$
1,290,580
$
1,307,919
$
(17,339)
(1.3)
%
OPERATING
COSTS AND EXPENSES:
Fuel
96,698
188,437
(91,739)
(48.7)
%
411,864
392,497
19,367
4.9
%
Power
purchased
35,748
57,386
(21,638)
(37.7)
%
122,410
151,891
(29,481)
(19.4)
%
Operation
and maintenance
120,858
116,969
3,889
3.3
%
356,386
367,525
(11,139)
(3.0)
%
Depreciation
and amortization
72,021
66,810
5,211
7.8
%
212,292
199,096
13,196
6.6
%
Taxes
other than income taxes
6,359
5,348
1,011
18.9
%
19,779
27,664
(7,885)
(28.5)
%
Other,
net
—
—
—
—
%
—
(3,201)
3,201
(100.0)
%
Total
operating costs and expenses
331,684
434,950
(103,266)
(23.7)
%
1,122,731
1,135,472
(12,741)
(1.1)
%
OPERATING
INCOME
71,203
59,244
11,959
20.2
%
167,849
172,447
(4,598)
(2.7)
%
OTHER
(EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction
3,134
1,408
1,726
122.6
%
7,089
4,782
2,307
48.2
%
Interest
expense
(34,471)
(32,630)
(1,841)
5.6
%
(104,510)
(96,552)
(7,958)
8.2
%
Other
(expense) / income, net
(633)
2,836
(3,469)
(122.3)
%
787
8,674
(7,887)
(90.9)
%
Total
other expense, net
(31,970)
(28,386)
(3,584)
12.6
%
(96,634)
(83,096)
(13,538)
16.3
%
INCOME
BEFORE INCOME TAX
39,233
30,858
8,375
27.1
%
71,215
89,351
(18,136)
(20.3)
%
Less:
income tax expense
3,802
6,020
(2,218)
(36.8)
%
8,663
18,274
(9,611)
(52.6)
%
NET
INCOME
35,431
24,838
10,593
42.6
%
62,552
71,077
(8,525)
(12.0)
%
Less:
dividends on preferred stock
—
803
(803)
(100.0)
%
—
2,410
(2,410)
(100.0)
%
NET
INCOME APPLICABLE TO COMMON STOCK
$
35,431
$
24,035
$
11,396
47.4
%
$
62,552
$
68,667
$
(6,115)
(8.9)
%
28
Revenues
Revenues
during the three and nine months ended September 30, 2023 decreased $91.3 million and $17.3 million, respectively, compared to the same periods in 2022, which resulted from the following changes (dollars in thousands):
The
following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the three months ended September 30, 2023 as compared to the same period in the prior year:
The following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the nine months ended September 30, 2023 as compared to the same period in the prior year:
30
During
the three months ended September 30, 2023, revenues decreased $91.3 million to $402.9 million compared to $494.2 million in the same period of the prior year, and during the nine months ended September 30, 2023, revenues decreased $17.3 million to $1,290.6 million compared to $1,307.9 million in the same period of the prior year. These changes were primarily the result of changes in the components of revenues shown below:
Net
decrease in the volume of kWh sold primarily due to weather and demand in our service territory versus the comparable period.
$
(11.1)
$
(69.7)
Price:
Net (decrease) / increase in the weighted average price of retail kWh sold primarily due to (lower) / higher fuel revenues, as well as higher TDSIC and Off System Sales Margin rider revenues.
(15.9)
108.8
Other:
0.1
2.6
Net
change in retail revenues
(26.9)
41.7
Wholesale revenues:
Volume:
Net
decrease in the volume of wholesale kWh sold. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability.
(48.8)
(4.8)
Price:
Net decrease in the weighted average price of wholesale kWh sold. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs.
(10.8)
(54.4)
Net
change in wholesale revenues
(59.6)
(59.2)
Miscellaneous revenues
Primarily due to (decrease) / increase in capacity revenues of $(5.0) million and $1.4 million for the three and nine months ended September 30, 2023 compared to the same periods in the
prior year, respectively, due to recent MISO auction results.
(4.8)
0.2
Net change in revenues
$
(91.3)
$
(17.3)
31
Operating
Costs and Expenses
The following table illustrates our changes in Operating costs and expenses during the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022 (in thousands):
The (decrease) / increase in fuel costs of $(91.7) million and $19.4 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to the following changes:
The
changes in the price of fuel are reflective of market prices for coal and natural gas. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances. Additionally, fuel and purchased power costs incurred for wholesale energy sales are considered in the Off System Sales Margin rider.
32
Power Purchased
The decreases in power purchased of $21.6 million and $29.5 million during the three and nine months ended September 30,
2023, respectively, compared to the same periods of the prior year were primarily due to the following changes:
Net
change in the volume of power purchased primarily due to AES Indiana's generation units running (less)/more frequently, as well as the timing and duration of outages, during these respective periods
$
21.8
$
(27.1)
Price:
Market prices
(26.3)
(42.5)
Deferred
purchased power
(23.0)
34.1
Net change in price
(49.3)
(8.4)
Other, net (mostly due to changes in capacity purchases)
5.9
6.0
Net
change in power purchased costs
$
(21.6)
$
(29.5)
The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the relative cost of producing power versus purchasing power in the market. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the supply of and demand for electricity, and
the time of day during which power is purchased.
The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. The IURC initiated a sub-docket in FAC-133 (IURC Cause No. 38703-FAC-133 S1) to examine the impact of the Eagle Valley extended outage, which was settled in October 2022. A $27.8 million charge was recorded in the third quarter of 2022 resulting from the settlement of the FAC sub-docket of the Eagle Valley CCGT unplanned outage.
Operation and Maintenance
The increase / (decrease) in Operation and maintenance of $3.9 million and $(11.1) million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were
primarily due to the following changes:
Increase / (decrease) in contracted services
expenses primarily due to higher / (lower) generation maintenance and outage costs
$
2.7
$
(6.7)
Decrease in DSM program costs (these program costs are recoverable through customer rates and are offset by a decrease in DSM revenues)
(1.5)
(7.9)
Decrease due to lower health insurance and disability expense
(0.6)
(5.5)
Increase
in charges from the Service Company
2.9
8.3
Other, net
0.4
0.7
Net change in operation and maintenance costs
$
3.9
$
(11.1)
33
Depreciation
and Amortization
The increases in Depreciation and amortization expense of $5.2 million and $13.2 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were mostly attributed to the impact of additional assets placed in service and higher amortization of regulatory assets.
Taxes Other Than Income Taxes
The increase / (decrease) in Taxes other than income taxes of $1.0 million and $(7.9) million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to the following changes:
Decrease due to the repeal of the URT (for further discussion, please see Note 2, "Regulatory Matters - House Bill 1002" to the Financial Statements of IPALCO's 2022 Form 10-K
$
—
$
(11.1)
Increase
in property taxes primarily due to increased assessed values
1.1
3.3
Other, net
(0.1)
(0.1)
Net change in taxes other than income taxes
$
1.0
$
(7.9)
Other,
Net
The changes in Other, net of $0.0 million and $3.2 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition.
Other (Expense) / Income, Net
The following table illustrates our changes in Other (expense) / income, net during the three and nine months ended September 30, 2023, respectively, compared to the same periods in 2022 (in thousands):
Allowance for equity funds used during construction
$
3,134
$
1,408
$
1,726
122.6
%
$
7,089
$
4,782
$
2,307
48.2
%
Interest
expense
(34,471)
(32,630)
(1,841)
5.6
%
(104,510)
(96,552)
(7,958)
8.2
%
Other
(expense) / income, net
(633)
2,836
(3,469)
(122.3)
%
787
8,674
(7,887)
(90.9)
%
Total other expense, net
$
(31,970)
$
(28,386)
$
(3,584)
12.6
%
$
(96,634)
$
(83,096)
$
(13,538)
16.3
%
Allowance
for Equity Funds Used During Construction
The increases in Allowance for equity funds used during construction of $1.7 million and $2.3 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to increased construction activity.
Interest Expense
The increases in Interest expense of $1.8 million and $8.0 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to (i) higher interest expense on debt of $3.0 million and $11.6 million, respectively (mostly due to the debt issuance of $350 million AES Indiana first
mortgage bonds in November 2022), partially offset by (ii) increases in the allowance for borrowed funds used during construction of $1.3 million and $3.7 million, respectively.
34
Other (Expense) / Income, Net
The decreases in Other (expense) / income, net of $3.5 million and $7.9 million during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year were primarily due to (i) increases in defined benefit plan costs of $4.4 million and $13.1 million, respectively (mostly as a result of higher interest cost), partially offset by (ii) increases in investment income of $1.1 million and $5.3
million, respectively.
Income Tax Expense
The following table illustrates our changes in Income tax expense during the three and nine months ended September 30, 2023, respectively, compared to the same periods of the prior year (in thousands):
The
decrease in Income tax expense of $2.2 million during the three months ended September 30, 2023, was primarily driven by a lower estimated annual effective tax rate, partially offset by higher pre-tax income as compared to the comparable period of the prior year.
The decrease in Income tax expense of $9.6 million during the nine months ended September 30, 2023, was primarily driven by a lower estimated annual effective tax rate and lower pre-tax income as compared to the comparable period of the prior year.
KEY TRENDS AND UNCERTAINTIES
During the remainder of 2023 and beyond,
we expect that our financial results will be driven primarily by retail demand, weather and maintenance costs. In addition, our financial results will likely be driven by many other factors including, but not limited to:
•regulatory outcomes and impacts;
•the passage of new legislation, implementation of regulations or other changes in regulation; and
•timely recovery of capital expenditures and operation and maintenance costs.
If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this Quarterly Report impact us more significantly than we currently anticipate, then these factors, or other factors unknown to us, may impact
our operating income, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” as described in IPALCO’s 2022 Form 10-K.
Operational
Trade Restrictions and Supply Chain
On March 29, 2022, the U.S. Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand and Vietnam are circumventing antidumping and countervailing duty orders on solar cells and panels
from China. This investigation resulted in disruptions to the import of solar panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any tariffs that result from this investigation for a 24-month period. Since President Biden’s Proclamation, suppliers in Southeast Asia have imported panels again to the U.S.
On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four South Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to many but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels
imported from the four countries if the wafers were manufactured outside of China or if no more than two out of six specifically identified components were produced in China. On August 18,
35
2023, Commerce issued its final determination on the matter and affirmed its preliminary findings in most respects. Additionally, Commerce found that three of the specific companies it investigated were not circumventing.
While we have executed agreements for AES Indiana's solar projects, further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements with respect to these projects on terms that we deem satisfactory. The impact of any adverse Commerce determination, the impact of the UFLPA, future
disruptions to the solar panel supply chain and their effect on AES Indiana's solar project development and construction activities is uncertain. AES Indiana will continue to monitor developments and take prudent steps towards managing our renewables projects.
Capital Projects
Our construction projects have experienced some indications of delays and price increases due to supply chain disruptions; however, they are currently proceeding without material delays. For further discussion of our capital requirements, see "Part I, Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" of this Form 10-Q.
Macroeconomic and Political
Inflation
Reduction Act and U.S. Renewable Energy Tax Credits
The Inflation Reduction Act (the “IRA”) was signed into law in the United States in 2022. The IRA includes provisions that are expected to benefit the Company's planned clean energy projects, including increases, extensions and/or new tax credits for wind, solar, and storage. We expect that the extension of the current solar investment tax credits ("ITCs") for projects that satisfy wage and apprenticeship requirements, as well as the "technology neutral" clean electricity production tax credit ("PTC") and ITC will provide incremental benefits for our renewable projects. We do not anticipate realizing any benefit related to the IRA in 2023.
We account for renewable projects according
to GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity partners at the time of its creation, which for projects utilizing the ITC, is in the quarter the project begins commercial operation. For projects utilizing the PTC, this value is recognized over 10 years as the facility produces energy.
The implementation of the IRA is expected to require substantial guidance from the U.S. Department of Treasury and other government agencies. While that guidance is pending, there will be uncertainty with respect to the implementation of certain provisions of the IRA.
U.S. Income Tax
The macroeconomic and political environments in the U.S. have changed during 2022
and 2023. This could result in significant impacts to tax law. An example of this is the IRA, which expands and extends incentives related to investment in renewable energy. We continue to evaluate the applicability and effect of the new law on AES Indiana.
Inflation
In the markets in which we operate, there have been higher rates of inflation recently. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may also increase the costs of some of our construction projects. AES Indiana may have the ability to recover operations and maintenance costs through the regulatory process; however, timing impacts on recovery may vary. In addition, the cost of fuel, specifically coal and natural gas, continues to be volatile into 2023. Our exposure to fluctuations in the price
of fuel is limited because of our FAC. If we are unable to timely or fully recover our fuel and purchased power costs; however, it could have a material adverse effect on our results of operations, financial condition and cash flows.
Interest Rates
In the U.S. there has been a rise in interest rates recently. From July 1 to September 30, 2023 the yield on 10-year U.S. Treasury Notes rose from 3.84% to 4.57%. Although all of our existing IPALCO and AES Indiana long-term
36
debt is at fixed rates, an increase in interest rates can have several impacts on our business. For our existing short-term debt under floating
rate structures and any future debt refinancings or future new money financings, rising interest rates will increase future financing costs. Our floating rate debt is currently limited to short-term borrowings under our Credit Agreement. For future IPALCO debt financings, IPALCO manages a hedging program to reduce uncertainty and exposure to future interest rates.
Bipartisan Infrastructure Law (Infrastructure Investment and Jobs Act)
In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years across the United States. The BIL’s energy-related provisions include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure
for public chargers and additional Low Income Home Energy Assistance Program funding. AES Indiana is participating as a sub-recipient for a Department of Energy Office of Energy Efficiency and Renewable Energy Topic 2 award and has identified other potential opportunities associated with the BIL and is submitting concept papers and grants for those that align with its strategy going forward.
Regulatory
Regulatory Rate Review
On June 28, 2023, AES Indiana filed a petition with the IURC for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably.AES Indiana's proposed revenue increase
was $134 million annually, or 8.9%. We expect to receive an order from the IURC by the end of the second quarter of 2024.
2022 IRP
AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas by the end of 2025. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. For further discussion, see Note 2, "Regulatory Matters - Replacement Generation" to the Financial Statements of this Form 10-Q and Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements included in IPALCO’s 2022 Form 10-K.
Please
see Note 2, "Regulatory Matters" to the Financial Statements included in this Form 10-Q and Note 2, “Regulatory Matters” to the Financial Statements included in IPALCO’s 2022 Form 10-K for further discussion of these and other regulatory matters.
Environmental
We are subject to numerous environmental and climate change laws and regulations in the jurisdictions in which we operate. We face certain risks and uncertainties related to these environmental and climate change laws and regulations, including existing and potential GHG legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal or beneficial reuse of CCR) and certain air emissions, such as SO2,
NOx, particulate matter and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on our consolidated results of operations. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in “Item 1. Business - Environmental Matters” in IPALCO’s 2022 Form 10-K.
MATS
In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. AES
Indiana management developed and implemented a plan, which was approved by the IURC, to comply with this rule and all four Petersburg units have been and remain in material compliance with the MATS rule since applicable deadlines.
37
In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to the EPA without vacatur. On May 22, 2020, the EPA published a final finding that it is not “appropriate and necessary” to regulate hazardous air pollutant emissions from coal- and oil-fired EGUs (reversing its prior 2016 finding), but that the EPA would not
remove the source category from the CAA Section 112(c) list of source categories and would notchange the MATS requirements. On March 6, 2023, the EPA published a final rule to revoke its May 2020 finding and reaffirm its 2016 finding that it is appropriate and necessary to regulate these emissions. On April 24, 2023, EPA published the proposed MATS Risk and Technology Review (RTR) Rule to lower certain emissions limits and revise certain other aspects of MATS. We are still reviewing the proposal.However, the existing requirements of MATS and the proposed requirements of MATS RTR Rule would not apply to AES Indiana upon conversion of the remaining two coal-fired units at Petersburg to natural gas.
Further rulemakings
and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.
Waste Management and CCR
In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or
processing. Waste materials generated at our electric power and distribution facilities include asbestos, CCR, oil,
scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree-and-land-clearing
wastes and polychlorinated biphenyl contaminated liquids and solids. We endeavor to ensure that all our solid and
liquid
wastes are disposed of in accordance with applicable national, regional, state and local regulations. With the
exception of CCR, we do not usually physically dispose of waste materials on our property. Instead, they are usually shipped off-site for final disposal, treatment or recycling. Some of our CCRs are beneficially used on-site and offsite,
including as a raw material for production of wallboard, and concrete or cement, and some are disposed off-site in
permitted disposal facilities. A small amount of CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at our Petersburg coal-fired power generation plant using an engineered, permitted landfill.
The EPA's final CCR rule became effective in October 2015 (the "CCR Rule"). Generally, the rule regulates CCR as
nonhazardous
solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ash ponds, including location restrictions, design and operating criteria, groundwater monitoring,
corrective action and closure requirements and post-closure care. The 2016 Water Infrastructure Improvements for
the Nation Act ("WIIN Act") includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a federal permit program. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. If this rule is finalized before Indiana establishes a final state-level CCR permit program, AES Indiana
could eventually be required to apply for a federal
CCR permit from the EPA. On December 21, 2022, IDEM
published in the Indiana Register a Second Notice of Comment Period for its proposed CCR rulemaking which would include regulation of CCR through a state permitting program.
The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing.
On August 28, 2020, the EPA published the CCR Part A Rule that, among other amendments, required certain CCR units to cease waste receipt and initiate closure by April 11, 2021. The CCR Part A Rule also allowed for extensions of the April 11, 2021 deadline if EPA determines certain criteria are met. Facilities seeking
such an extension were required to submit a demonstration to EPA by November 30, 2020. On January 11, 2022, EPA released its first in a series of proposed and final determinations regarding CCR Part A Rule demonstrations and compliance-related
letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. On April 8,
2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. While AES Indiana has not received a proposed determination nor a letter, the determinations and letters include interpretations regarding implementation of the CCR Rule. It is too early to determine the impact of these
letters or any determinations that may be made.
On May 18, 2023, EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. We are still reviewing the proposal and it is too early to determine the potential impact.
38
The CCR Rule, current or proposed amendments to the CCR Rule, Indiana CCR regulations, the results of
groundwater monitoring data or the outcome of CCR-related litigation
could have a material impact on our business,
financial condition and results of operations. We would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard. See Note 3, "Property, Plant and Equipment - ARO" and
Note 10, "Commitments and Contingencies - Coal Ash Insurance Litigation" to the Financial Statements of IPALCO’s 2022 Form 10-K for further discussion.
Environmental Wastewater Requirements
In November 2015, the EPA published its final Steam ELG rule to reduce toxic pollutants discharged into waterways by steam-electric power plants through technology applications. In 2020, EPA issued a final rule, known as the 2020 Reconsideration
Rule, revising certain aspects of the 2015 ELG rule. Wastewater treatment technologies already installed and operated at Petersburg met the requirements of these rules. Following the 2019 U.S. Court of Appeals vacature and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, EPA published a proposed rule revising the 2020 Reconsideration Rule. The proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of this proposed rule, litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition and results of operations.
National Pollutant Discharge Elimination System (NPDES)
permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Section 402 of the Federal Water Pollution Control Act. In 2017, IDEM issued to Eagle Valley a NPDES permit regulating water discharges associated with operation of its CCGT. As part of the normal course of business, AES Indiana submitted a timely application for renewal for the Eagle Valley NPDES permit, and on March 31, 2023, IDEM issued the renewed NPDES permit. On April 17, 2023, a third party filed an appeal of Eagle Valley’s renewed NPDES permit. AES Indiana contends that the renewed permit was validly issued, and the permit remains in effect. AES Indiana is unable to predict the outcome of the appeal, but depending on the results, it could have an adverse effect on the Company.
In
2017, IDEM also issued to Harding Street a NPDES permit regulating water discharges associated with operation of its natural gas-fired power plant. As part of the normal course of business, AES Indiana submitted a timely application for renewal for the Harding Street NPDES permit, and on May 25, 2023, IDEM issued a proposed NPDES permit for public comment. The proposed permit includes new requirements that could result in the need for AES Indiana to take additional actions to ensure compliance with the proposed permit. It is too early to determine the potential impact, but the permit could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.
Regulation of Water Discharge
The
concept of WOTUS defines the geographic reach and authority of the U.S. Army Corps of Engineers and EPA (together, the "Agencies") to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the proper standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (Decision) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a clear standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional
interstate navigable water are not considered a WOTUS and therefore are not federally jurisdictional.
On September 8, 2023, the Agencies published final rule amendments in the Federal Register to amend the final “Revised Definition of ‘Waters of the United States’” rule. This final rule conforms the definition of WOTUS to the definition adopted in the Decision. The Agencies have amended key aspects of the regulatory text to conform the rule to the Decision.
It is too early to determine whether any outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS might have a material adverse effect on our results of operations, financial condition and cash flows.
39
Climate
Change Legislation and Regulation
One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. We face certain risks related to existing and potential international, federal, state, regional and local GHG legislation and regulations,
including risks related to increased capital expenditures or other compliance costs, as well as increased climate change disclosure obligations, which could have a material adverse effect on our results of operations, financial condition and cash flows.
The possible impact of any existing or future international, federal, regional or state GHG legislation, regulations or
proposals will depend on various factors, including but not limited to:
•The
geographic scope of legislation and/or regulation (e.g., international, federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;
•The level of reductions of GHGs being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);
•The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG emission limits, etc.);
•In
any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;
•The price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;
•The operation of and emissions from regulated units;
•The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions
in GHG emissions and that those reductions are permanent (i.e., the verification method);
•Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;
•How the price of electricity is determined, including whether the price includes any costs resulting from any new climate change legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;
•Any impact on fuel demand and volatility that may affect the market clearing price for
power;
•The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;
•The availability and cost of carbon control technology;
•Whether any federal legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits or other litigation by third parties;
•Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency;
•The extent of any required GHG emissions disclosure requirements in the forthcoming final version of the SEC's proposed 2022 climate change
disclosure rule, including potential disclosure of Scope 1-3 GHG emissions; and
•Our ability to recover any resulting costs from our customers and the timing of such recovery.
Except as noted in the discussion below, at this time, we cannot estimate the costs of compliance with existing,
proposed or potential international, federal, state or regional GHG emissions reductions legislation or initiatives due
in part to the fact that many of these proposals are in earlier stages of development and any final laws or
regulations, if adopted, could vary drastically from current proposals. Any international, federal, state or regional
legislation adopted in the U.S. that would require the reduction of GHG emissions could
have a material adverse effect on our business and/or results of operations, financial condition and cash flows.
In the past, the U.S. Congress has considered several different draft bills pertaining to GHG legislation, including comprehensive GHG legislation that would impact many industries and more limited legislation focusing only on the
utility and electric generation industry. Although no legislation pertaining to GHG emissions has been passed to date
40
by the U.S. Congress, similar legislation may be considered or passed by the U.S. Congress in the future. In
addition, in the past Midwestern state governors (including the Governor of Indiana) and the
premier of Manitoba,
Canada committed to reduce GHG emissions through the implementation of a cap-and-trade program pursuant to
the Midwestern Greenhouse Gas Reduction Accord. Though the participating states and province are no longer
pursuing this commitment, similar applicable state or regional initiatives may be pursued in the future.
The final NSPS for CO2 emissions from new, modified and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015. Several states and industry groups challenged the NSPS for
CO2 in the D.C. Circuit Court. On December
20, 2018, the EPA published proposed revisions to the final NSPS for
new, modified and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (BSER) for these units is highly efficient generation that would be equivalent to
supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial
carbon capture and sequestration (CCS), which had been the BSER for these units in the 2015 final NSPS. The
EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018
proposal. Challenges to the GHG NSPS remain held in abeyance at this time. On May 23, 2023,
EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023.
On July 8, 2019, the EPA published the final ACE Rule which would have established CO2 emission rules for existing coal-fired power plants under CAA Section 111(d) and would have replaced the EPA's 2015 CPP, which among other things, had called on states to mandate that power companies shift electricity generation to lower or zero carbon fuel sources. However, on January 19, 2021, the D.C. Circuit vacated and remanded to EPA the ACE Rule.Subsequently,
on June 30, 2022, the U.S. Supreme Court reversed the judgment of the D.C. Circuit Court and
remanded for further proceedings consistent with its opinion, holding that the “generation shifting” approach in the CPP exceeded the authority granted to EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 U.S. Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate holding pending challenges to the ACE Rule in abeyance while EPA developed a replacement rule.
On May 23, 2023, EPA published a proposed rule that would vacate the ACE Rule, establish emissions guidelines in the form of CO2
emissions limitations for certain existing EGUs and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operations to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s.
Due to the uncertainty of these regulations, and existing and potential associated litigation, it is too early to
determine the potential impact, but any rule could have a material impact on our business, financial condition and
results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.
On
the international level, on December 12, 2015, 195 nations, including the U.S., finalized the text of an
international climate change accord in Paris, France (the “Paris Agreement”), which agreement was signed and
officially entered into on April 22, 2016. The Paris Agreement calls for countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. A long-term goal of the
Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the
pre-industrial era. The U.S. withdrawal from the Paris Agreement became effective
on November 4, 2020. However,
on January 20, 2021, President Biden signed and submitted an instrument for the U.S. to rejoin the Paris Agreement, which became effective on February 19, 2021. In November 2022, the international community
gathered in Egypt at the 27th Conference to the Parties on the UN Framework Convention on Climate Change
(“COP27”), during which multiple announcements were made, including the establishment of a loss and damage fund to support vulnerable countries dealing with the effects of climate change and certain pledges in the area of
climate finance.
Based on the above, there is some uncertainty with
respect to the impact of GHG rules on AES Indiana. The NSPS
will not require us to comply with an emissions standard until we construct a new electric generating unit. We do not
have any planned major modifications of an existing source or plans to construct a new major source which are expected to be subject to these regulations at this time. Furthermore, the EPA, states and other utilities are still
41
evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows,
and financial condition, but it could be material.
CSAPR
and 2015 Ozone NAAQS FIP
CSAPR, which became effective in January 2015, addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). The CSAPR Update Rule found that NOx ozone season emissions in 22 states (including Indiana) affect the ability of downwind states to attain and maintain the 2008 ozone NAAQS, and accordingly, the EPA issued federal implementation
plans that both generally provide updated CSAPR NOx ozone season emission budgets for electric generating units within these states and that implement these budgets through modifications to the CSAPR NOx ozone season allowance trading program. Implementation began in the 2017 ozone season and affected facilities receive fewer ozone season NOx allowances beginning in 2017. Following legal challenges related to the CSAPR Update Rule, on April 30, 2021, EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected EGUs within certain states (including Indiana) to participate in a new trading program, the CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx
Ozone Season allowances beginning in 2021.
On June 5, 2023, the EPA published a final Federal Implementation Plan ("FIP") to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule establishes a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and is expected to become effective during 2023. The FIP also includes enhancements in the revised Group 3 trading program which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels.
At
this time, we cannot predict the impact of these rule revisions or potential future legal outcomes, but any such impact could include the need to purchase additional allowances or make operational adjustments or could otherwise be material to our business, financial condition or results of operation. For further discussion, see
"Item 1. Business - Environmental Matters - CSAPR and 2015 Ozone NAAQS FIP" of IPALCO’s 2022 Form 10-K.
Cooling Water Intake Regulations
We use water as a coolant at our generating stations. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. In 2014, the EPA's final standards became effective to protect fish and other aquatic organisms drawn into cooling water systems at
large power plants and other facilities. These standards, based on Section 316(b) of the CWA, require affected facilities to choose amongst seven BTA options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers) or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. AES Indiana’s NPDES permits will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. In May 2023, the Indiana Department
of Environmental Management rendered proposed impingement and entrainment BTA determinations for Harding Street which may result in the need to install modified traveling screens and a fish handling and return system and also conduct a 2-year entrainment study. As final BTA determinations have not yet been rendered, it is not yet possible to predict the total impacts of this final rule, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful.
42
CAPITAL
RESOURCES AND LIQUIDITY
Overview
As of September 30, 2023, we had unrestricted cash and cash equivalents of $21.5 million and available borrowing capacity of $275 million under our unsecured revolving Credit Agreement. All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from the FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate
principal amount of long-term debt, of which $390 million remains available under the order as of September 30, 2023. This order also grants authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $400 million remains available under the order as of September 30, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt, AES Indiana has authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of September 30, 2023. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will
be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.
Cash Flows
The following table provides a summary of our cash flows (in thousands):
Deferred income taxes and investment tax credit adjustments - net
32,735
(11,137)
43,872
Other adjustments to net income
(4,200)
(1,884)
(2,316)
Net
income, adjusted for non-cash items
303,379
257,152
46,227
Net change in operating assets and liabilities(1)
43,708
(30,616)
74,324
Net cash provided by operating activities
$
347,087
$
226,536
$
120,551
(1)
Refer to the table below for explanations of the variance in operating assets and liabilities.
43
The net change in operating assets and liabilities for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022 was driven by changes in the following (in thousands):
Increase from short-term and long-term regulatory assets and liabilities
is primarily due to higher FAC collections in the current year
$
92,523
Increase from accounts receivable driven primarily by the timing of the collections
60,092
Decrease from accounts payable due to the timing of vendor payments
(54,288)
Decrease in accrued taxes due to an increase in deferred taxes mainly driven by the gross tax loss created by Petersburg Unit 2 retirement
(21,394)
Other
(2,609)
Net
change in operating assets and liabilities
$
74,324
Investing Activities
Net cash used in investing activities increased $141.1 million for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, which was primarily driven by (in thousands):
Higher cash outflows
for capital expenditures due to higher T&D maintenance related capital expenditures and growth related capital expenditures primarily from TDSIC Plan
$
(85,035)
Higher cash outflows from purchase of intangibles in 2023
(44,650)
Other
(11,376)
Net
change in investing activities
$
(141,061)
Financing Activities
Net cash provided by financing activities decreased $162.7 million for the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022, which was primarily driven by (in thousands):
Decrease due
to proceeds from issuance of AES Indiana Term Loan in June 2022
$
(200,000)
Other
37,349
Net change in financing activities
$
(162,651)
Liquidity
We believe that existing cash balances, cash generated from operating activities, and borrowing
capacity on our committed Credit Agreement will be adequate for the foreseeable future to meet anticipated operating expenses, interest expense on outstanding indebtedness, recurring capital expenditures, and to pay dividends to AES U.S. Investments and CDPQ. Sources for principal payments on outstanding indebtedness and nonrecurring capital expenditures are expected to be obtained from: (i) existing cash balances; (ii) cash generated from operating activities; (iii) borrowing capacity on our committed Credit Agreement; (iv) additional debt financing; and (v) equity capital contributions. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.
Indebtedness
For
further discussion of our significant debt transactions, please see Note 7, "Debt" to IPALCO’s 2022 Form 10-K and Note 5, "Debt" to the Financial Statements of this Form 10-Q.
Line of Credit
We had the following amounts available under the revolving Credit Agreement:
Our capital expenditure program, including development and permitting costs, for the three-year period from 2023 through 2025 (including amounts already expended in the first nine months of 2023) is currently estimated to cost approximately $2.6 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):
2023
2024
2025
For
the three-year period from 2023 through 2025
Transmission and distribution related additions, improvements and extensions
$
168
$
158
$
163
$
489
(1)
TDSIC Plan investments
193
189
212
594
(2)
Power
generation and replacement capacity related projects
514
580
356
1,450
(3)
Other miscellaneous equipment
48
28
23
99
Total
estimated costs of capital expenditure program
$
923
$
955
$
754
$
2,632
(1) Additions, improvements and extensions to AES Indiana's transmission and distribution lines, substations,
power factor and voltage regulating equipment, distribution transformers and street lighting facilities
(2) Includes spending under AES Indiana's TDSIC plan approved by the IURC on March 4, 2020 for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Total TDSIC costs expended from project inception through September 30, 2023 were $631.8 million.
(3) Includes spending for AES Indiana's power generation and renewable energy projects
The amounts described in the capital expenditure program above include spending
under AES Indiana's 2022 IRP filed with the IURC in December 2022 for the three-year period from 2023 through 2025, including updated capital spending for new agreements executed in 2023 and pending regulatory approval. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of IPALCO's 2022 10-K for further discussion. Additionally, estimated capital expenditure spending on environmental compliance costs for the three-year period from 2023 through 2025 includes plans to spend approximately $2.7 million for studies related to cooling water intake requirements in section 316(b) of the CWA. Please see “Item 1. Business - Environmental Matters - Cooling Water Intake Regulations" of IPALCO's 2022 Form 10-K for additional details.
Credit Ratings
Our
ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement (as well as the amount of certain other fees in the Credit Agreement) are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.
The following table presents the debt ratings and credit ratings (issuer/corporate rating) and outlook for IPALCO and AES Indiana.
Debt
ratings
IPALCO
AES Indiana
Outlook
Fitch Ratings
BBB (a)
A (b)
Stable
Moody’s Investors Service
Baa3 (a)
A2
(b)
Stable
S&P Global Ratings
BBB- (a)
A- (b)
Positive
Credit ratings
IPALCO
AES
Indiana
Outlook
Fitch Ratings
BBB-
BBB+
Stable
Moody’s Investors Service
—
Baa1
Stable
S&P Global Ratings
BBB
BBB
Positive
(a)
Ratings relate to IPALCO's Senior Secured Notes.
(b) Ratings relate to AES Indiana's first mortgage bonds.
45
We cannot predict whether our current debt and credit ratings or the debt and credit ratings of AES Indiana will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. Such ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Dividend
Distributions
All of IPALCO’s outstanding common stock is held by AES U.S. Investments and CDPQ. During the first nine months of 2023 and 2022, IPALCO paid $66.9 million and $102.0 million, respectively, in distributions to its shareholders. Future distributions to our shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from AES Indiana. Dividends from AES Indiana are affected by AES Indiana’s actual results of operations, financial condition, cash flows, capital requirements, regulatory considerations, and such other factors as AES Indiana’s Board of Directors deems relevant.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The
condensed consolidated financial statements of IPALCO are prepared in conformity with GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented.
The Company’s significant accounting policies are described in Note 1, "Overview and Summary of Significant Accounting Policies" of IPALCO's 2022 Form 10-K. The Company’s critical accounting estimates are described in "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations"
in IPALCO's 2022 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that these remain as critical accounting policies as of and for the nine months ended September 30,
2023.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
There have been no material changes to our quantitative and qualitative disclosure about market risk as previously disclosed in IPALCO's 2022 Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures — The Company, under the supervision and with the participation
of its management, including the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective as of September 30, 2023, to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed
to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.
Changes in Internal Controls over Financial Reporting — There were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
46
PARTII– OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also, from time to time, involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our Financial Statements for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements,
as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements cannot be reasonably determined, but could be material.
Please see Note 2, "Regulatory Matters" and Note 8, “Commitments and Contingencies” to the Financial Statements included in Part I - Financial Information of this Form 10-Q for a summary of certain legal proceedings involving us.
In addition, our Form 10-K for the fiscal year ended December 31, 2022 and Form 10-Q for the quarters ended March 31, 2023 and June 30, 2023 and the Notes to IPALCO's Consolidated Financial Statements included therein contain descriptions of certain legal proceedings in which we are or were involved. The information in or incorporated by reference into this Item 1 to Part II is limited to certain recent developments concerning our legal proceedings and new legal proceedings, since the filing of such Forms 10-K and 10-Q, and should be read in conjunction with such Forms 10-K and 10-Q.
ITEM 1A.
RISK FACTORS
There have been no material changes to the risk factors disclosed in Item 1A.—Risk Factors of IPALCO's 2022 Form 10-K. Additional risks and uncertainties also may adversely affect our business and operations, including those discussed in Item 2. – Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-Q.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
XBRL
Instance Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.SCH
XBRL Taxonomy Extension Schema Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.LAB
XBRL
Taxonomy Extension Label Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith as provided in Rule 406T of Regulation S-T)
48
SIGNATURES
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 thereunto duly authorized.
