NISOURCE INC. (NI) FY 2023 MD&A

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NISOURCE INC.

EXECUTIVE SUMMARY

This Management's Discussion and Analysis of Financial Condition and Results of Operations ("Management's Discussion") includes management’s analysis of past financial results and certain potential factors that may affect future results, potential future risks and approaches that may be used to manage those risks. See "Note regarding forward-looking statements" and Item 1A, "Risk Factors" at the beginning of this report for a list of factors that may cause results to differ materially.

This Management's Discussion is designed to provide an understanding of our operations and financial performance and should be read in conjunction with our Consolidated Financial Statements and related Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

We are an energy holding company under the Public Utility Holding Company Act of 2005 whose subsidiaries are fully regulated natural gas and electric utility companies serving customers in six states. We generate substantially all of our operating income through these rate-regulated businesses, which are summarized for financial reporting purposes into two primary reportable segments: Gas Distribution Operations and Electric Operations.

Refer to the "Business" section under Item 1 of this Annual Report on Form 10-K and Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements for further discussion of our regulated utility business segments.

Our goal is to develop strategies that benefit all stakeholders as we (i) focus on long-term infrastructure investment and safety programs to better serve our customers, (ii) align our tariff structures with our cost structure, and (iii) address changing customer energy demand. These strategies focus on improving safety and reliability, enhancing customer experience, pursuing regulatory and legislative initiatives to increase accessibility for customers currently not on our gas and electric service, ensuring customer affordability and reducing emissions while generating sustainable returns. The safety of our customers, communities and employees remains our focus. Serving as a guiding practice for our SMS, NiSource is certified in conformance to the American Petroleum Institute Recommended Practice 1173, which is the foundation to our journey towards operational excellence.

2023 Overview: In 2023, we continued to make significant progress towards our strategic and financial goals and objectives by achieving in-service status in June 2023 and substantial completion in August 2023 for our first two solar BTA projects, Indiana Crossroads Solar and Dunns Bridge I. We continue to progress on the remaining portfolio of projects that will enable our electric generation transition. During the year, we received orders for four cases: Columbia of Virginia, Columbia of Ohio, Columbia of Maryland, and NIPSCO Electric. In addition, the NIPSCO Gas rate case filed in 2023 is anticipated to be resolved in the third quarter of 2024. These cases represent balanced outcomes supporting all stakeholders. Between our Gas Distribution and Electric Operating Segments, we added 22,000 customers. We also invested $1.5 billion in infrastructure modernization to enhance safe, reliable service, including replacement of 339 miles of distribution main and service lines, 34 miles of underground cable and 1,942 electric poles.

We also made advancements in key strategic initiatives, described in further detail below.

Your Energy, Your Future: We continue to advance Your Energy, Your Future primarily through the continuation and enhancement of existing programs, such as retiring and replacing remaining coal-fired electric generation by 2028 with a balanced mix of low or zero-emission electric generation, ongoing pipe replacement and modernization programs, and deployment of advanced leak detection and repair. Our electric generation transition, initiated through our 2018 Integrated Resource Plan ("2018 Plan") is well underway, and we are continually adjusting to the dynamic energy landscape. As of

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December 31, 2023, we have executed and received IURC approval for BTAs and PPAs with a combined nameplate capacity of 1,950 MW and 1,400 MW, respectively, under the 2018 Plan. We have also taken contractual actions on a number of our other renewable projects to address the timing of these projects as well as consider the broad market issues facing the industry. We remain on track to retire R.M Schahfer's remaining two coal units by the end of 2025. On January 1, 2023, the provisions of the IRA became effective. On January 17, 2024, the IURC approved full ownership of the Cavalry and Dunns Bridge II projects, allowing NIPSCO to leverage provisions of the IRA to monetize tax credits for the benefit of customers in lieu of utilizing tax equity partnerships. We are evaluating the impact of this legislation on our remaining projects, with potential to drive increased value to customers. For additional information, see "Results and Discussion of Operations - Electric Operations," in this Management's Discussion.

In 2021, we announced and filed with the IURC the Preferred Energy Resource Plan associated with our 2021 Integrated Resource Plan ("2021 Plan"). The 2021 Plan lays out a timeline to retire the Michigan City Generating Station by the end of 2028. The 2021 Plan calls for the replacement of the retiring units with a diverse portfolio of resources including demand side management resources, incremental solar, stand-alone energy storage and upgrades to existing facilities at the Sugar Creek Generating Station, among other steps. Additionally, the 2021 Plan calls for a new natural gas peaking facility to replace existing vintage gas peaking facilities at the R.M. Schahfer Generating Station to support system reliability and resiliency, and upgrades to to the electric transmission system. In September of 2023, we filed a request for issuance of a certificate of public convenience and necessity for an approximately 400 MW natural gas peaking generation facility with the IURC. The planned retirement of the two vintage gas peaking facilities at the R.M. Schahfer Generating Station is also expected to occur by the end of 2028. Final retirement dates for these units, as well as Michigan City, will be subject to MISO approval.

We continue to enhance safety and reduce methane emissions on our gas systems through modernization programs and utilization of advanced leak detection and repair. Advanced mobile methane-detection vehicles are being deployed across our service territory. These vehicles are designed to identify potential natural gas leaks using proven technology that is more sensitive than traditional leak-detection equipment. Resources like these vehicles are advancing the company’s commitment to safety and reaching our goal of net zero greenhouse gas emissions by 2040.

In addition, we plan to advance other low- or zero-emission energy resources and technologies, such as hydrogen and renewable natural gas. In 2023, we launched a multi-phase pilot project at the Columbia Gas of Pennsylvania Training Center’s Safety Town to better understand the impact of blending hydrogen into the natural gas system. We have partnered with outside experts to conduct a series of field trials blending hydrogen with the natural gas system at various percentages. The blending system allows blending from 0% to 20% hydrogen, by volume. The field trials have initially focused on the customer experience and are now moving toward system operations and other procedures. This pilot is designed to help us understand hydrogen blending into the natural gas system, identify best practices, and analyze the operational and safety impact on company infrastructure and customer appliances. Carbon offsets and renewable energy credits may also be used to assist with achieving GHG reductions and our Net Zero Goal.

NIPSCO Minority Interest Transaction: On December 31, 2023, we consummated the closing of the NIPSCO Minority Interest Transaction and issued the 19.9% equity interest in NIPSCO Holdings II to BIP in exchange for a capital contribution of $2.16 billion in cash. Refer to Note 4, "Noncontrolling Interest," in the Notes to the Consolidated Financial Statements for more information on this transaction.

Transformation: Our enterprise-wide transformation roadmap focuses on operational excellence, safety, operation and maintenance management, and unlocking efficiencies. We are committed to identifying and implementing initiatives that will enable us to streamline work and improve logistics company-wide. These efforts include investments in proven technologies backed with standardized processes that will change the way we plan, schedule, and execute work in the field and how we engage and provide service to our customers. Taken together, all of our optimization initiatives will prioritize safety and continue to optimize our long-term growth profile.

Economic Environment: We continue to monitor risks related to order and delivery lead times for construction and other materials, potential unavailability of materials due to global shortages in raw materials, and decreased construction labor productivity in the event of disruptions in the availability of materials. We continue to see increasing prices associated with certain materials and supplies. To the extent that work plan delays occur or our costs increase, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected. Refer to Item 1A. Risk Factors, "Financial, Economic and Market Risks" of this Annual Report on Form 10-K for further detail.

We are faced with increased competition for employee and contractor talent in the current labor market which has resulted in increased costs to attract and retain talent. We are ensuring that we use all internal human capital programs (development,

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leadership enablement programs, succession, performance management) to promote retention of our current employees along with having a competitive and attractive appeal for potential recruits. With a focus on workforce planning, we are evaluating our future talent footprint by creating flexible work arrangements where possible to ensure we have the right people, in the right role, and at the right time. Refer to Item 1A. Risk Factors, "Operational Risks" of this Annual Report on Form 10-K for further detail.

The market price of natural gas has been stable during the last half of 2023 at lower levels than 2022 and with little volatility. Similar to natural gas pricing, electric commodity costs have stayed subdued due to plentiful supplies of natural gas and coal and the growing influence of renewable generation on power market pricing. Changes in commodity prices do not have a material impact on our results of operations, however higher commodity prices can impact our cash flows and liquidity. For more information on our commodity price impacts, see Item 1A. Risk Factors, "Operational Risks" of this Annual Report on Form 10-K, "Results and Discussion of Segment Operations - Gas Distribution Operations," "Results and Discussion of Segment Operations - Electric Operations," and "Market Risk Disclosures."

Due to rising interest rates, we experienced higher interest expense during 2023 compared to 2022 associated with short-term borrowings. We continue to evaluate our financing plan to manage interest expense and exposure to rates. For more information on interest rate risk, see "Market Risk Disclosures" and Item 1A. Risk Factors, "Financial, Economic and Market Risks" of this Annual Report on Form 10-K.

Summary of Consolidated Financial Results

A summary of our consolidated financial results for the years ended December 31, 2023, 2022 and 2021, are presented below:

The majority of the costs of energy in both segments are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in operating revenues.

The decrease in net income available to common shareholders during 2023 was primarily due to lower revenue resulting from the effects of weather, the receipt of the insurance settlement related to the Greater Lawrence Incident in 2022, higher other deductions due to higher interest expense in 2023, partially offset by lower tax expense and favorable impact from net loss attributable to noncontrolling interest. The decrease in preferred dividends during 2023 was due primarily to the redemption of Series A Preferred Stock in the second quarter 2023. See Note 6, "Equity," for additional information.

For additional information on operating income variance drivers see "Results and Discussion of Operations" for Gas and Electric Operations in this Management's Discussion.

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Other Deductions, Net

The change in Other deductions, net in 2023 compared to 2022 is primarily driven by higher long-term and short-term debt interest in 2023 and higher non-service pension costs offset by increases in AFUDC. See Note 7, "Short-Term Borrowings," Note 8, "Long-Term Debt," and Note 16, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements for additional information.

Income Taxes

The decrease in income tax expense in 2023 compared to the same period in 2022 is primarily attributable to lower pre-tax income.

Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information on income taxes and the change in the effective tax rate.

RESULTS AND DISCUSSION OF OPERATIONS

Presentation of Segment Information

Our operations are divided into two primary reportable segments: Gas Distribution Operations and Electric Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as "Corporate and Other" within the Notes to the Consolidated Financial Statements and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities.

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Gas Distribution Operations

Financial and operational data for the Gas Distribution Operations segment for the years ended December 31, 2023, 2022 and 2021, are presented below:

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Gas Distribution Operations (continued)

Comparability of operation and maintenance expenses, depreciation and amortization, and other taxes may be impacted by regulatory, depreciation and tax trackers that allow for the recovery in rates of certain costs.

The underlying reasons for changes in our operating revenues and expenses from 2023 to 2022 are presented in the respective tables below. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Operations - Gas Distribution Operations," of the Company's 2022 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2022 versus 2021.

Weather

In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating degree days, net of weather normalization mechanisms. Our composite heating degree days reported do not directly correlate to the weather-related dollar impact on the results of Gas Distribution Operations. Heating degree days experienced during different times of the year or in different operating locations may have more or less impact on volume and dollars depending on when and where they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite heating degree day comparison.

Throughput

The decrease in total volumes sold and transported in 2023 compared to 2022 of 24.7 MMDth is primarily attributable to the effects of warmer weather offset by increased industrial usage.

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Gas Distribution Operations (continued)

Commodity Price Impact

Cost of energy for the Gas Distribution Operations segment is principally comprised of the cost of natural gas used while providing transportation and distribution services to customers. All of our Gas Distribution Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. These are tracked costs that are passed through directly to the customer, and the gas costs included in revenues are matched with the gas cost expense recorded in the period. The difference is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered gas cost to be included in future customer billings. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income. Certain Gas Distribution Operations companies continue to offer choice opportunities, where customers can choose to purchase gas from a third-party supplier, through regulatory initiatives in their respective jurisdictions.

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Electric Operations

Financial and operational data for the Electric Operations segment for the years ended December 31, 2023, 2022 and 2021, are presented below:

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Electric Operations (continued)

Comparability of operation and maintenance expenses and depreciation and amortization may be impacted by regulatory and depreciation trackers that allow for the recovery in rates of certain costs.

The underlying reasons for changes in our operating revenues and expenses from 2023 to 2022 are presented in the respective tables below. Please refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results and Discussion of Operations - Electric Operations," of the Company's 2022 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2022 versus 2021.

Weather

In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal cooling degree days. Our composite cooling degree days reported do not directly correlate to the weather-related dollar impact on the results of Electric Operations. Cooling degree days experienced during different times of the year may have more or less impact on volume and dollars depending on when they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite cooling degree day comparison.

Sales

NIPSCO's Electric Segment results remains closely linked to the performance of the steel industry. MWh sales to steel-related industries accounted for approximately 49.3% and 47.4% of the total industrial MWh sales for the years ended December 31, 2023 and 2022, respectively.

Commodity Price Impact

Cost of energy for the Electric Operations segment is principally comprised of the cost of coal, natural gas purchased for internal generation of electricity at NIPSCO, and the cost of power purchased from generators of electricity. NIPSCO has a state-approved recovery mechanism that provides a means for full recovery of prudently incurred costs of energy. The majority of these costs of energy are passed through directly to the customer, and the costs of energy included in operating revenues are matched with the cost of energy expense recorded in the period. The difference is recorded on the Consolidated Balance Sheets as under-recovered or over-recovered fuel cost to be included in future customer billings. Therefore, increases in these tracked operating expenses are offset by increases in operating revenues and have essentially no impact on net income.

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Electric Operations (continued)

Electric Supply and Generation Transition

NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan and 2021 Plan, which outline the path to retire the remaining two coal units at R.M. Schahfer by the end of 2025 and the remaining coal-fired generation at Michigan City by the end of 2028, to be replaced by lower-cost, reliable and cleaner options. See "Project Status" discussion, below, and "Liquidity and Capital Resources" in this Management's Discussion for information on anticipated in-service dates related to our electric generation transition and additional information on our capital investment spend.

NIPSCO continues to work with the EPA to obtain an administrative approval associated with the operation of R.M. Schahfer’s remaining two coal units until 2025. In the event that the approval is not obtained, future operations could be impacted. We cannot estimate the financial impact on us if this approval is not obtained. Refer to Item 1A. Risk Factors, "Operational Risks," of this Annual Report on Form 10-K for further detail.

The current replacement plan is aligned with the Preferred Energy Resource Plan outlined in the 2021 Plan and primarily includes renewable sources of energy, including wind, solar, battery storage, and flexible natural gas resources to be obtained through a combination of NIPSCO ownership and PPAs. NIPSCO has sold, and may in the future sell, renewable energy credits from its renewable generation to third parties to offset customer costs. NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities.

Since 2020, two wind PPA projects, two wind BTA projects and two solar BTA projects have been placed into service, totaling 1,465 MW of nameplate capacity. NIPSCO has executed commercial agreements for each of the eight remaining identified projects. Dunns Bridge II, Cavalry, Fairbanks, Gibson, GreenRiver, Appleseed, Carpenter and Templeton have received IURC approval. Additional approvals by the IURC may be required to obtain recovery for increases in projects costs. NIPSCO has filed for a new gas peaking facility to be located at R.M. Schahfer Generating Station. On November 22, 2023 the IURC approved NIPSCO's request to convert the Gibson project from a PPA to a BTA. On January 17, 2024 the IURC approved increases to the project costs as well as the full ownership of Cavalry and Dunns Bridge II, allowing NIPSCO to leverage provisions of the IRA to monetize tax credits for the benefit of customers in lieu of utilizing tax equity partnerships. See "Executive Summary - Your Energy, Your Future" in this Management's Discussion for additional information.

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Electric Operations (continued)

(1) Under the structure approved by the IURC ownership of Fairbanks and Gibson will be transferred to JVs whose members are expected to include NIPSCO and an unrelated tax equity partner. NIPSCO is evaluating leveraging provisions of the IRA to monetize tax credits for the benefit of customers in lieu of utilizing tax equity partnerships. NIPSCO may seek IURC approval for full ownership of the Fairbanks and Gibson projects.

Project Status. We expect the majority of our remaining BTA and PPA projects to be placed in service in 2024 and 2025. Our contract amendments for these projects formally address inflationary cost pressures communicated from the developers of our solar and storage projects that are primarily due to (i) limited supply of solar panels and other uncertainties related to the U.S. Department of Commerce investigation on Antidumping and Countervailing Duties petition filed by a domestic solar manufacturer (the "DOC Investigation"), (ii) the U.S. Department of Homeland Security's June 2021 Withhold Release Order on silica-based products made by Hoshine Silicon Industry Co., Ltd./Uyghur Forced Labor Prevention Act, (iii) Section 201 Tariffs and (iv) persistent general global supply chain and labor availability issues. We are actively monitoring progress towards project milestones for each of our remaining projects.

In June 2022, the Biden Administration announced a 24-month tariff relief on solar panels subject to the DOC Investigation and authorized the use of the Defense Production Act, to accelerate domestic production of clean energy technologies, including solar panel parts. On August 18, 2023, the department of Commerce issued final determinations in the DOC Investigation and affirmed that tariff relief announced by the Biden Administration in June 2022 would remain in effect until June 2024. At this time, we do not anticipate any significant panel tariffs will impact our solar projects.

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NISOURCE INC.

Liquidity and Capital Resources

We continually evaluate the availability of adequate financing to fund our ongoing business operations, working capital and core safety and infrastructure investment programs. Our financing is sourced through cash flow from operations and the issuance of debt and/or equity. External debt financing is provided primarily through the issuance of long-term debt, accounts receivable securitization programs and our $1.85 billion commercial paper program, which is backstopped by our committed revolving credit facility with a total availability from third-party lenders of $1.85 billion. We entered into a $1.0 billion term agreement in the fourth quarter of 2022 and a $650.0 million term credit agreement in the fourth quarter of 2023. On January 3, 2024, we terminated and repaid in full our $1.0 billion term credit agreement and our $650.0 million term credit agreement. On March 24, 2023, we completed the issuance and sale of $750.0 million of 5.25% senior unsecured notes maturing in 2028, which resulted in approximately $742.2 million of net proceeds after discount and debt issuance costs. On June 8, 2023, we completed the issuance and sale of a reopening of $300.0 million of 5.25% senior unsecured notes maturing in 2028 and $450.0 million of 5.40% senior unsecured notes maturing in 2033, which resulted in approximately $742.5 million of net proceeds after discount and debt issuance costs. On June 15, 2023, we redeemed all 400,000 shares of Series A Preferred Stock for a redemption price of $1,000 per share, or $400.0 million in total. As of December 31, 2023, the ATM program and the associated equity distribution agreements expired. On December 31, 2023, we consummated the NIPSCO Minority Interest Transaction in exchange for a capital contribution of $2.16 billion in cash. See Note 4, "Noncontrolling Interest,", Note 6, "Equity," Note 7, "Short-Term Borrowings," and Note 8, "Long-Term Debt," in the Notes to the Consolidated Financial Statements for more information.

We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2024 and beyond.

Operating Activities

Net cash from operating activities for the year ended December 31, 2023 was $1,935.1 million, an increase of $525.7 million from 2022. This increase in cash from operating activities was primarily driven by year over year change in accounts receivable collections driven by the implementation of new rates and the impact of lower gas prices as compared to 2022, partially offset by lower accounts payables also driven by lower gas prices.

Investing Activities

Net cash used for investing activities for the year ended December 31, 2023 was $3,571.6 million, an increase of $1,001.4 million from 2022. Our current year investing activities were comprised of increased capital expenditures related to system growth and reliability as well as payments to renewable generation asset developers related to milestone payments for certain of our BTA projects in 2023, as well as the property insurance settlement related to the Greater Lawrence Incident received in the prior year.

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Capital Expenditures. The table below reflects actual capital expenditures and certain other investing activities by segment for 2023.

(1)Amounts differ from those presented in Note 21, "Business Segment Information," in the Notes to Consolidated Financial Statements due to the allocation of Corporate and Other Maintenance Costs to the Gas Distribution and Electric Operations segments.

(2)Amounts differ from those presented on the Statements of Consolidated Cash Flows primarily due to the capitalized portion of the Corporate Incentive Plan payout, inclusion of capital expenditures included in current liabilities and AFUDC Equity.

In addition to these capital expenditures, we made $871.2 million of capital investments in the form of milestone and final payments to the renewable generation asset developers. Through December 2023, NiSource has added approximately $1 billion in renewable generation projects to its rate base.

We expect to make capital investments totaling approximately $16.0 billion during the 2024-2028 period related to infrastructure modernization, generation transition and customer growth over the next five years. This forecast incorporates an estimated $1.7 billion of additional investment in renewable generation projects.

Regulatory Capital Programs. We replace pipe and modernize our gas infrastructure to enhance safety and reliability and reduce leaks. An ancillary benefit of these programs is the reduction of GHG emissions. In 2023, we continued to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all six states of our operating area.

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The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement and other federally mandated compliance investments:

(1)Programs do not include any costs already included in base rates.

(2)Columbia of Maryland’s STRIDE expired December 31, 2023. On June 23, 2023, CMD filed an application for approval of a new five-year STRIDE. On November 21, 2023, the filing was withdrawn. Effective January 1, 2024, the STRIDE capital investments previously recovered are no longer earning a current return.

(3)Coincident with the implementation of Step-1 base rates in August 2023 in Cause No. 45772, TDSIC-3 cumulative capital investment of $554.7 million moved out of this tracker and into base rates.

(4)NIPSCO received approval for a new certificate of public convenience and necessity on December 28, 2022 for an additional Pipeline Safety III Compliance Plan, including $235.3M in capital and $34.1M in operation and maintenance expense project investments.

(5)Columbia of Kentucky placed these rates into effect, as of January 3, 2024, subject to refund, depending on a Commission order ruling on the Application.

On March 30, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of Michigan City Generating Station's CCR ash ponds. The project includes a total estimated $40.0 million of federally mandated retirement costs. On November 2, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of R.M. Schahfer Generation Station's multi-cell unit. The project includes a total estimated $53.0 million of federally mandated retirement costs. Due to the NIPSCO Electric settlement agreement filed on March 10, 2023, both FMCA cases were stayed pending the outcome of the NIPSCO Electric base rate case, which proposed these pond closure costs be recovered through base rates, rather than the FMCA Tracker. NIPSCO received an order approving its electric base rate case settlement on August 2, 2023. Pursuant to that settlement agreement, NIPSCO filed and the IURC approved motions to dismiss the independent FMCA cases related to CCR ash pond recovery, as that recovery will now occur through NIPSCO’s electric base rates. Refer to Note 19, "Other Commitments and Contingencies - D. Environmental Matters," in the Notes to Consolidated Financial Statements for further discussion of the CCRs.

Refer to Note 12, "Regulatory Matters," in the Notes to Consolidated Financial Statements for a further discussion of regulatory developments during 2023.

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Financing Activities

Common Stock, Preferred Stock and Equity Unit Sale. Refer to Note 6, "Equity," in the Notes to Consolidated Financial Statements for information on common stock, preferred stock and equity units activity.

Short-term Debt. Refer to Note 7, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for information on short-term debt.

Long-term Debt. Refer to Note 8, "Long-Term Debt," in the Notes to Consolidated Financial Statements for information on long-term debt.

Non-controlling Interest. We received $2.16 billion upon closing the NIPSCO Minority Interest Transaction. Proceeds from the closing of the NIPSCO Minority Interest Transaction were used to repay short-term debt, including our credit agreements. Under the terms of the LLC Agreement, Blackstone will provide up to $250 million in additional capital contributions over a three-year period after the Closing, which obligation is backed by an Equity Commitment Letter from an affiliate of Blackstone. Refer to Note 4, "Noncontrolling Interest," and Note 7, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for more information.

Sources of Liquidity

The following table displays our liquidity position as of December 31, 2023 and 2022:

(1)Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables.

Debt Covenants. We are subject to a financial covenant under our revolving credit facility which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2023, the ratio was 58.2%.

Credit Ratings. The credit rating agencies periodically review our ratings, taking into account factors such as our capital structure and earnings profile. The following table includes our and NIPSCO's credit ratings and ratings outlook as of December 31, 2023. There have been no changes to our credit ratings or outlooks since February 2020.

A credit rating is not a recommendation to buy, sell or hold securities, and may be subject to revision or withdrawal at any time by the assigning rating organization.

Certain of our subsidiaries have agreements that contain “ratings triggers” that require increased collateral if our credit ratings or the credit ratings of certain of our subsidiaries are below investment grade. These agreements are primarily for insurance purposes and for the physical purchase or sale of power. As of December 31, 2023, a collateral requirement of approximately $90.1 million would be required in the event of a downgrade below investment grade. In addition to agreements with ratings triggers, there are other agreements that contain “adequate assurance” or “material adverse change” provisions that could necessitate additional credit support such as letters of credit and cash collateral to transact business.

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Equity. Our authorized capital stock consists of 770,000,000 shares, $0.01 par value, of which 750,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, 2023, 447,381,671 shares of common stock and 40,000 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note 6, "Equity," in the Notes to Consolidated Financial Statements.

Contractual Obligations, Cash Requirements and Off-Balance Sheet Arrangements

We have certain contractual obligations requiring payments at specified periods. Our material cash requirements are detailed below. We intend to use funds from the liquidity sources referenced above to meet these cash requirements.

At December 31, 2023, we had $11,079.3 million in long-term debt and $3,048.6 million in short-term borrowings outstanding.

During 2024 and 2025, we expect to make cash payments of $652.0 million and $485.7 million, respectively, related to pipeline service obligations including demand for gas transportation, gas storage and gas purchases.

Our expected payments include employer contributions to pension and other postretirement benefits plans expected to be made in 2024. Plan contributions beyond 2024 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2024, we expect to make contributions of approximately $2.2 million to our pension plans and approximately $23.1 million to our postretirement medical and life plans. Refer to Note 16, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements for more information.

We cannot reasonably estimate the settlement amounts or timing of cash flows related to certain of our long-term obligations classified as "Total Other Liabilities" on the Consolidated Balance Sheets.

We have uncertain income tax positions for which we are unable to predict when the matters will be resolved. Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for more information.

NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities. See Note 19, "Other Commitments and Contingencies - A. Contractual Obligations," and Note 19, "Other Commitments and Contingencies," - E. "Other Matters - Generation Transition," in the Notes to Consolidated Financial Statements for additional information.

In addition, we, along with certain of our subsidiaries, enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit.

Refer to Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements for additional information regarding our contractual obligations over the next 5 years and thereafter and our off-balance sheet arrangements.

Market Risk Disclosures

Risk is an inherent part of our businesses. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in our businesses: commodity price risk, interest rate risk and credit risk. We manage risk through a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These may include, but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, our risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.

Commodity Price Risk

Our Gas and Electric Operations have commodity price risk primarily related to the purchases of natural gas and power. To manage this market risk, our subsidiaries use derivatives, including commodity futures contracts, swaps, forwards and options. We do not participate in speculative energy trading activity.

Commodity price risk resulting from derivative activities at our rate-regulated subsidiaries is limited and does not bear significant exposure to earnings risk, since our current regulatory mechanisms allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making process, including gains or losses on these derivative instruments. These changes are included in the GCA and FAC regulatory rate-recovery mechanisms. If these mechanisms were to be adjusted or

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eliminated, these subsidiaries may begin providing services without the benefit of the traditional rate-making process and may be more exposed to commodity price risk. For additional information, see "Results and Discussion of Operations" in this Management's Discussion.

Certain of our subsidiaries are required to make cash margin deposits with their brokers to cover actual and potential losses in the value of outstanding exchange traded derivative contracts. The amount of these deposits, some of which are reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.

Refer to Note 13, "Risk Management Activities," in the Notes to Consolidated Financial Statements for further information on our commodity price risk assets and liabilities as of December 31, 2023 and 2022.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our revolving credit agreement, commercial paper program, term credit agreements and accounts receivable programs, which have interest rates that are indexed to short-term market interest rates. Based upon average borrowings and debt obligations subject to fluctuations in short-term market interest rates, an increase (or decrease) in short-term interest rates of 100 basis points (1%) would have increased (or decreased) interest expense by $18.9 million and $8.7 million for 2023 and 2022, respectively. We are also exposed to interest rate risk as a result of changes in benchmark rates that can influence the interest rates of future debt issuances. From time to time, we may enter into forward interest rate instruments to lock in long term interest costs and/ or rates.

Credit Risk

Due to the nature of the industry, credit risk is embedded in many of our business activities. Our extension of credit is governed by a Corporate Credit Risk Policy. In addition, Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by the risk management function, which is independent of commercial operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. For derivative-related contracts, credit risk arises when counterparties are obligated to deliver or purchase defined commodity units of gas or power to us at a future date per execution of contractual terms and conditions. Exposure to credit risk is measured in terms of both current obligations and the market value of forward positions net of any posted collateral such as cash and letters of credit.

We evaluate the financial status of our banking partners through the use of market-based metrics such as credit default swap pricing levels, and also through traditional credit ratings provided by major credit rating agencies.

Other Information

Critical Accounting Estimates

We apply certain accounting policies in accordance with GAAP, which require that we make estimates and judgments that have had, and may continue to have, significant impacts on our operations and Consolidated Financial Statements. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. We believe the following represent the more significant items requiring the use of judgment in preparing our Consolidated Financial Statements:

Basis of Accounting for Rate-Regulated Subsidiaries. ASC Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be billed and collected. Accordingly, certain expenses and credits subject to utility regulation or rate determination normally reflected in income may be deferred on the Consolidated Balance Sheets and recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were $2,460.2 million and $1,789.3 million at December 31, 2023, and $2,580.8 million and $2,012.6 million at December 31, 2022, respectively. For additional information, refer to Note 12, "Regulatory Matters," in the Notes to Consolidated Financial Statements.

In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such

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event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If we were unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated subsidiaries will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.

Certain of the regulatory assets reflected on our Consolidated Balance Sheets require specific regulatory action in order to be included in future service rates. Although recovery of these amounts is not guaranteed, we believe that these costs meet the requirements for deferral as regulatory assets. If we determine that the amounts included as regulatory assets are no longer probable of recovery, a charge to income would immediately be required to the extent of the unrecoverable amounts.

One of the more significant items recorded through the application of this accounting guidance is the regulatory overlay for JV accounting. The application of HLBV to consolidated VIEs generally results in the recognition of profit from the related JVs over a time frame that is different from when the regulatory return is earned. In accordance with the principles of ASC 980, we have recognized a regulatory deferral of certain amounts representing the timing difference between the profit earned from the JVs and the amount included in regulated rates to recover our approved investments in consolidated JVs. For additional information, refer to Note 1, "Nature of Operations and Summary of Significant Accounting Policies - S. Noncontrolling Interest," in the Notes to Consolidated Financial Statements.

Pension and Postretirement Benefits. We have defined benefit plans for both pension and other postretirement benefits. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, expected long-term rates of return on plan assets, health care trend rates, and mortality rates, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. Differences between actuarial assumptions and actual plan results are deferred into AOCI or a regulatory balance sheet account, depending on the jurisdiction of our entity. These deferred gains or losses are then amortized into the income statement when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the fair value of plan assets (known in GAAP as the “corridor” method) or when settlement accounting is triggered.

The discount rates, expected long-term rates of return on plan assets, health care cost trend rates and mortality rates are critical assumptions. Methods used to develop these assumptions are described below. While a third party actuarial firm assists with the development of many of these assumptions, we are ultimately responsible for selecting the final assumptions.

The discount rate is utilized principally in calculating the actuarial present value of pension and other postretirement benefit obligations and net periodic pension and other postretirement benefit plan costs. Our discount rates for both pension and other postretirement benefits are determined using spot rates along an AA-rated above median yield curve with cash flows matching the expected duration of benefit payments to be made to plan participants.

The expected long-term rate of return on plan assets is a component utilized in calculating annual pension and other postretirement benefit plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, target asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. For measurement of 2023 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 7.00% and 6.96% for our pension and other postretirement benefit plan assets, respectively. For measurement of 2024 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 7.02% and 7.06 % respectively, for our pension and other postretirement benefit plan assets.

We estimate the assumed health care cost trend rate, which is used in determining our other postretirement benefit net expense, based upon our actual health care cost experience, the effects of recently enacted legislation, third-party actuarial surveys and general economic conditions.

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We utilize a full yield curve approach to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. For further discussion of our pension and other postretirement benefits, see Note 16, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements.

Typically, we use the Society of Actuaries’ most recently published mortality data in developing a best estimate of mortality as part of the calculation of the pension and other postretirement benefit obligations. We adopted Aon's U.S. Endemic Mortality Improvement scale MP-2021, accounting for both the near-term and long-term COVID-19 impacts.

The following tables illustrate the effects of changes in these actuarial assumptions while holding all other assumptions constant:

(1)Before labor capitalization and regulatory deferrals.

Goodwill and Other Intangible Assets. We have six goodwill reporting units, comprised of the six state operating companies within the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, 2023 were $1,486 million, most of which resulted from the acquisition of Columbia on November 1, 2000.

As required by GAAP, we test for impairment of goodwill on an annual basis and on an interim basis when events or circumstances indicate that a potential impairment may exist. Our annual goodwill test takes place in the second quarter of each year and was performed on May 1, 2023. A qualitative ("Step 0") test was completed on May 1, 2023, for all reporting units. In the Step 0 analysis, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the applicable reporting units as compared to the baseline "step 1" fair value measurement performed May 1, 2020. The results of this assessment indicated that it was more likely than not that the estimated fair value of the reporting units substantially exceeded the related carrying values of our reporting units; therefore, no "step 1" analysis was required and no impairment charges were indicated. Since the annual evaluation, there have been no indications that the fair values of the goodwill reporting units have decreased below the carrying values.

As noted above, application of the qualitative goodwill impairment test requires evaluating various events and circumstances to determine whether it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. Although we believe all relevant factors were considered in the qualitative impairment analysis to reach the conclusion that goodwill is not impaired, significant changes in any one of the assumptions could potentially result in the recording of an impairment that could have significant impacts on the Consolidated Financial Statements.

See Note 10, "Goodwill," in the Notes to Consolidated Financial Statements for further information.

Unbilled Revenue. We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon historical usage, customer rates and weather. As of December 31, 2023, we recorded $337.6 million of customer

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accounts receivable for unbilled revenue. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Refer to Note 3, "Revenue Recognition," in the Notes to Consolidated Financial Statements for additional information regarding our significant judgments and estimates related to unbilled revenue recognition.

Income Taxes. The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require use of estimates and significant management judgement. Although we believe that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, including reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

We account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. We evaluate each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements. At December 31, 2023 and 2022, we had $21.7 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

On a quarterly basis, we evaluate our deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. We establish a valuation allowance when we conclude it is more likely than not that all, or a portion, of a deferred tax asset will not be realized in future periods. Significant judgment is required to determine the amount of tax benefits expected to be realized. At December 31, 2023 and 2022, we had established $6.4 million and $7.8 million, respectively, of valuation allowances (net of federal benefit) related to certain state net operating loss carryforwards. Refer to Note 15, "Income Taxes," in the Notes to Consolidated Financial Statements for additional information.

Recently Issued Accounting Pronouncements

Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Consolidated Financial Statements.