NISOURCE INC. (NI) FY 2022 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.

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 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) embark 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 conservation patterns. These strategies focus on improving safety and reliability, enhancing customer service, ensuring customer affordability and reducing emissions while generating sustainable returns. The safety of our customers, communities and employees remains our top priority. In 2022, NiSource achieved conformance certification to the American Petroleum Institute Recommended Practice 1173, which serves as the guiding practice for our SMS. This certification marks an important milestone for our SMS and NiSource’s journey towards operational excellence. Additionally, we continue to pursue regulatory and legislative initiatives that will allow residential customers not currently on our system to obtain gas service in a cost effective manner.

2022 Overview: In 2022, we continued to make significant progress towards our strategic and financial goals and objectives. We completed the first full year of operating Indiana Crossroads Wind, and construction is near completion for two of our solar projects. In 2022, we filed four rate cases and resolved three, in Pennsylvania, Maryland, and the gas rate case in Indiana filed in 2021. In addition, the Ohio rate case was resolved in January 2023 and the Virginia rate case is anticipated to be resolved in the first quarter of 2023. These cases represent balanced outcomes supporting all stakeholders. Between our Gas Distribution and Electric Operating Segments, we added 25,000 customers. We also invested $1.6 billion in infrastructure modernization to enhance safe, reliable service, including replacement of 410 miles of distribution main and service lines, 48 miles of underground cable and 1,352 electric poles.

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

Your Energy, Your Future: Our plan to replace our coal generation capacity by the end of 2028 with primarily renewable resources, initiated through our 2018 Integrated Resource Plan ("2018 Plan") is well underway, and we are continually adjusting to the dynamic renewable energy landscape. As of December 31, 2022, we have executed and received IURC approval for BTAs and PPAs with a combined nameplate capacity of 1,950 MW and 1,380 MW, respectively, under the 2018 Plan. During 2022, we made significant progress on our first two solar BTAs and anticipate completion of these projects and tax equity financing in 2023. We have also taken contractual actions on a number of our other renewable projects to address the

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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. In August 2022, the IRA was signed into law. We are evaluating the impact of this legislation to our renewable projects with potential to drive increased value to customers as part of our expansion of renewable projects and generation transition strategy. However, the leveraging of the IRA will be considered on a project-by-project basis and evaluate several factors, both quantitative and qualitative, that results in the best position for project success as well as customer and company considerations. For additional information, see "Results and Discussion of Segment 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 natural gas peaking unit to replace existing vintage gas peaking units at the R.M. Schahfer Generating Station to support system reliability and resiliency, as well as upgrades to the transmission system to enhance our electric generation transition. The planned retirement of the two vintage gas peaking units 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 are continuing to evaluate potential projects under the 2021 Plan given the responses to our Request for Proposal issued in August 2022.

Transformation: The NiNext initiative, which commenced in 2020, focused on optimizing our workforce and advancing our operations. NiNext has been foundational in preparing for incremental, enterprise-wide investments to address inefficiencies in our current technology footprint, which stem primarily from a complex array of legacy systems. We plan to address these inefficiencies through our Enterprise Transformation Roadmap with investments in technology systems and infrastructure. As a result of these investments, we will deliver more modern, dependable, and secure IT systems backed with standardized processes to reduce the operating risks of our business, increase workforce efficiencies, and increase visibility to data which will be leveraged to drive risk-informed decisions. Our Enterprise Transformation Roadmap will position us to accomplish future strategic investments and aspirational goals.

Economic Environment: We are monitoring risks related to increasing order and delivery lead times for construction and other materials, increasing risk of unavailability of materials due to global shortages in raw materials, and risk of decreased construction labor productivity in the event of disruptions in the availability of materials. We are also seeing increasing prices associated with certain materials and supplies. To the extent that delays occur or our costs increase, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected. For more information on supply chain impacts to our electric generation strategy, see "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.

Early in 2022, NIPSCO experienced a rail service shortage in deliveries of coal, particularly to its Michigan City Generating Station, and the primary rail carrier for that generating station was unable to provide assurance of adequate future service to maintain coal inventory. A lack of adequate coal deliveries to any of our coal-fired generating facilities for an extended period could deplete our inventories to a level that prevents the generating station from running, and NIPSCO would need to rely on market purchases of replacement power, which could increase the cost of electricity for NIPSCO's customers. NIPSCO believes these shortages have been resolved but continues to monitor deliveries of coal from its rail carriers. This did not have a material impact on our operations in 2022.

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, 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 anticipating to evaluate our talent footprint for the future by creating flexible work arrangements where we can, to ensure we have the right people, in the right role, and at the right time. To the extent we are unable to execute on our workforce planning initiatives and experience increased employee and contractor costs, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected.

We experienced an increase in natural gas costs as the spot market for natural gas substantially increased throughout much of 2022, followed by a decrease in the price of natural gas since November 2022. Nationally, levels of gas in storage were lower in 2022 compared to 2021, liquified natural gas exports to Europe continued at a steady pace, and domestic production saw a recent decline in demand. These factors drove increased volatility in the marketplace, which influenced customer bills

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throughout 2022. While production was increasing towards the end of 2022, weather changes have limited demand and decreased withdrawals, causing inventory balances to be higher compared to 2021. With this decline in price, we expect to see lower volatility and declining customer bills. For the year ended December 31, 2022, we did not see this volatility have a material impact on our results of operations. For more information on our commodity price impacts, see "Results and Discussion of Segment Operations - Gas Distribution Operations," and "Market Risk Disclosures."

Due to rising interest rates, we experienced higher interest expense in 2022 compared to 2021 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".

For more information on global availability of materials for our renewable projects, see "Results and Discussion of Segment Operations - Electric Operations - Electric Supply and Generation Transition."

Summary of Consolidated Financial Results

A summary of our consolidated financial results for the years ended December 31, 2022, 2021 and 2020, 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 increase in net income available to common shareholders during 2022 was primarily due to higher revenues from outcomes of gas base rate proceedings and regulatory capital programs, as well as an insurance settlement related to the Greater Lawrence Incident, offset by higher income taxes in 2022 compared to 2021.

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

Other Deductions, Net

The change in Other deductions, net in 2022 compared to 2021 is primarily driven by higher long-term and short-term debt interest in 2022 and lower non-service pension benefits partially offset by the interest rate swap settlement gain in 2022 and charitable contributions in 2021. See Note 15, "Long-Term Debt," Note 16, "Short-Term Borrowings," and Note 12, "Pension and Other Postemployment Benefits," in the Notes to Consolidated Financial Statements for additional information.

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Income Taxes

The increase in income tax expense in 2022 compared to the same period in 2021 is primarily attributable to higher pre-tax income, offset by higher state flow through and the reduction of the Pennsylvania corporate income tax rate.

Refer to Note 11, "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, 2022, 2021 and 2020, 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 2022 to 2021 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 Segment Operations - Gas Distribution Operations," of the Company's 2021 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2021 versus 2020.

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 increase in total volumes sold and transported in 2022 compared to 2021 of 26.4 MMDth is primarily attributable to the effects of colder weather.

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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Gas Distribution Operations (continued)

Columbia of Massachusetts Asset Sale

On October 9, 2020, we completed the sale of our Massachusetts Business. In March 2021, we reached an agreement with Eversource regarding the final purchase price, including net working capital adjustments. This resulted in a pre-tax loss for the years ended December 31, 2022 and 2021 of zero and $6.8 million, respectively, based on asset and liability balances as of the close of the transaction on October 9, 2020, transaction costs and the final purchase price. The pre-tax loss is presented as "Loss (gain) on sale of assets, net" on the Statements of Consolidated Income (Loss).

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Electric Operations

Financial and operational data for the Electric Operations segment for the years ended December 31, 2022, 2021 and 2020, 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 2022 to 2021 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 Segment Operations - Electric Operations," of the Company's 2021 Annual Report on Form 10-K for discussion of underlying reasons for changes in our operating revenues and expenses for 2021 versus 2020.

(1)See Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.

Weather

In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating or cooling degree days. Our composite heating or cooling degree days reported do not directly correlate to the weather-related dollar impact on the results of Electric Operations. Heating or 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 heating or 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 47.4% and 48.1% of the total industrial MWh sales for the years ended December 31, 2022 and 2021, 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)

(1)See Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for additional information.

Electric Supply and Generation Transition

NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan, which outlines the path to retire the remaining two coal units at Schahfer by the end of 2025 and the remaining coal-fired generation 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 anticipated barriers to the success of our electric generation transition and additional information on our capital investment spend.

NIPSCO continues to work with the EPA and the Indiana Department of Environmental Management to obtain administrative approvals associated with the operation of R.M. Schahfer’s remaining two coal units beyond 2023. In the event that the approvals are not obtained, future operations could be impacted. We cannot estimate the financial impact on us if these approvals are not obtained.

The current replacement plan primarily includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. NIPSCO has sold, and may in the future sell, renewable energy credits from this 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.

Three wind projects have been placed into service, totaling approximately 804 MW of nameplate capacity. All announced projects below have received IURC approval. During 2022, NIPSCO amended certain of its BTAs and PPAs. NIPSCO is discussing potentially amending other BTAs and PPAs. Any amendments that result in increased project costs may require additional approval by the IURC in order to obtain recovery for increased costs. Our current replacement program will be augmented by the Preferred Energy Resource Plan outlined in our 2021 Integrated Resource Plan. See "Executive Summary - Your Energy, Your Future" in this Management's Discussion for additional information.

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Electric Operations (continued)

(1) Ownership of the facilities will be transferred to JVs whose members are expected to include NIPSCO and an unrelated tax equity partner.

Project Status. Our contract amendments with certain solar agreements will result in the majority of our remaining projects, and investments, being placed in service between 2023 and 2025. These amendments also formally address inflationary cost pressures communicated from the developers of our solar and storage projects that are primarily due to (i) unavailability of solar panels and other uncertainties related to the pending 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 also monitoring the developers of our renewable energy projects related to local permitting processes and obtaining interconnection rights. Preliminary findings from the DOC Investigation were released in December 2022, with a final decision expected in May 2023. The resolution of these issues, including the final conclusion of the DOC Investigation will determine which, if any, of our solar projects will be subject to any tariffs imposed.

In June 2022, the Biden Administration announced a 24-month tariff relief on solar panels subject to the ongoing U.S. Department of Commerce investigation and authorized the use of the Defense Production Act, to accelerate domestic production of clean energy technologies, including solar panel parts.

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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 $1.5 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. On December 20, 2022, we entered into a $1.0 billion term credit agreement that matures on December 19, 2023. On February 18, 2022, we amended our revolving credit agreement to, among other things, extend its term to February 18, 2027. The commercial paper program and credit facility provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves our desired capital structure. On June 10, 2022, we completed the issuance and sale of $350.0 million of 5.00% senior unsecured notes maturing in 2052, which resulted in approximately $344.6 million of net proceeds after discount and debt issuance costs. We intend to disburse an amount equal to the net proceeds of the notes to finance, in whole or in part, the acquisition of our 302 MW Indiana Crossroads Wind project and 102 MW Rosewater Wind project from the project developer. On November 7, 2022, we announced that we intend to pursue the sale of a minority interest in our NIPSCO business unit. We utilize an ATM equity program that allows us to issue and sell shares of our common stock up to an aggregate issuance of $750.0 million through December 31, 2023. As of December 31, 2022, the ATM program had approximately $300.0 million of equity available for issuance. We also expect to remarket the Series C Mandatory Convertible Preferred Stock prior to December 1, 2023, which could result in additional cash proceeds. See Note 13, "Equity," in the Notes to Consolidated Financial Statements for more information on our ATM program and Equity Units.

We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2023 and beyond.

Greater Lawrence Incident. As discussed in Part I, Item 1A, "Risk Factors," and in Note 19, "Other Commitments and Contingencies," in the Notes to Consolidated Financial Statements, due to the inherent uncertainty of litigation, there can be no assurance that the outcome or resolution of any particular claim related to the Greater Lawrence Incident will not continue to have an adverse impact on our cash flows. Through income generated from operating activities, amounts available under the short-term revolving credit facility, and our ability to access capital markets, we believe we have adequate capital available to settle remaining anticipated claims associated with the Greater Lawrence Incident.

Operating Activities

Net cash from operating activities for the year ended December 31, 2022 was $1,409.4 million, an increase of $191.5 million from 2021. This increase was primarily driven by a year over year increase in revenue and collection of under-recovered gas and fuel cost from the prior year. This was offset by increased cash outflows related to inventory purchases year over year due to higher gas costs.

Investing Activities

Net cash used for investing activities for the year ended December 31, 2022 was $2,570.2 million, an increase of $365.3 million from 2021. 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 Dunn's Bridge I and Indiana Crossroads Solar milestone payments. This was offset by the property insurance settlement related to the Greater Lawrence Incident.

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Capital Expenditures. The table below reflects actual capital expenditures and certain other investing activities by segment for 2022.

(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 $323.9 million of capital investments in the form of milestone payments to the renewable generation asset developer.

We expect to make capital investments totaling approximately $15 billion during the 2023-2027 period related to infrastructure modernization, generation transition and renewables and customer growth for the next five years:

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 2022, 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 currently in rates or pending commission approval:

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

(2)The January through March 2021 investments included in these filings are also included in the pending Columbia of Ohio rate case. The infrastructure filings will be adjusted to reflect the final rate case outcome.

(3)NIPSCO Gas program incremental revenue decreased because of revisions for the rate case compliance filings amounts included in 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 Virginia received a final order on November 1, 2022 modifying the SAVE filing incremental revenue and investments.

(6)Columbia of Kentucky received an Order on December 28, 2022, modifying its 2023 SMRP filing by removing recovery of the 2022 investment not recovered as part of the most recently approved rate case. This modification lowered incremental revenue recovered through SMRP to $1.6M, a reduction of $3.2M from the original filing.

(7)NIPSCO filed for a new electric TDSIC plan on June 1, 2021. An order approving NIPSCO's new electric TDSIC plan was received on December 28, 2021.

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. A final order is expected in the first quarter of 2023. 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. NIPSCO is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment through the FMCA mechanism. On February 21, 2023, the Indiana Court of Appeals issued a decision in a case filed by an Indiana utility company interpreting a statute authorizing recovery of federally mandated costs, finding that such costs incurred prior to issuance of an order by the IURC are not recoverable as federally mandated costs. If any of NIPSCO’s CCR costs were determined to be not eligible for recovery under the federal mandate mechanism, NIPSCO would seek recovery through depreciation within base rates. Refer to Note 19, "Other Commitments and Contingencies - E. Environmental Matters," in the Notes to Consolidated Financial Statements for further discussion of the CCRs.

Refer to Note 9, "Regulatory Matters," in the Notes to Consolidated Financial Statements for a further discussion of regulatory developments during 2022.

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Financing Activities

Common Stock, Preferred Stock and Equity Unit Sale. Refer to Note 13, "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 16, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for information on short-term debt.

Long-term Debt. Refer to Note 15, "Long-Term Debt," in the Notes to Consolidated Financial Statements for information on long-term debt.

Non-controlling Interest. Refer to Note 4, "Variable Interest Entities," in the Notes to Consolidated Financial Statements for information on contributions from noncontrolling interest activity.

Sources of Liquidity

The following table displays our liquidity position as of December 31, 2022 and 2021:

(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 and term credit agreement, which requires us to maintain a debt to capitalization ratio that does not exceed 70%. As of December 31, 2022, the ratio was 58.9%.

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, 2022. 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, 2022, a collateral requirement of approximately $85.7 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.

Equity. Our authorized capital stock consists of 620,000,000 shares, $0.01 par value, of which 600,000,000 are common stock and 20,000,000 are preferred stock. As of December 31, 2022, 412,142,602 shares of common stock and 1,302,500 shares of preferred stock were outstanding. For more information regarding our common and preferred stock, see Note 13, "Equity," in the Notes to Consolidated Financial Statements.

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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, 2022, we had $1,761.9 million in short-term borrowings outstanding. Refer to Note 15, "Long-Term Debt," and Note 16, "Short-Term Borrowings," in the Notes to Consolidated Financial Statements for further information on long-term debt and short-term borrowings, respectively.

During 2023 and 2024, we expect to make cash payments of $642.2 million and $556.9 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 2023. Plan contributions beyond 2023 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2023, we expect to make contributions of approximately $2.6 million to our pension plans and approximately $23.7 million to our postretirement medical and life plans. Refer to Note 12, "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 11, "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," - F. "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 signification 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 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 Segment Operations" in this Management's Discussion.

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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 is reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.

Refer to Note 10, "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, 2022 and 2021.

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 agreement 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 $8.7 million and $3.1 million for 2022 and 2021, 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.

Refer to Note 10, "Risk Management Activities," in the Notes to Consolidated Financial Statements for further information on our interest rate risk assets and liabilities as of December 31, 2022 and 2021.

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, our Risk Management Committee has put guidelines 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 charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are 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 $2,580.8 million and $2,012.6 million at December 31, 2022, and $2,492.2 million and $1,980.0 million at December 31, 2021, respectively. For additional information, refer to Note 9, "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 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

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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. VIEs and Allocation of Earnings," in the Notes to Consolidated Financial Statements.

Equity Unit Transaction. We record the Series C Mandatory Convertible Preferred Stock and forward purchase contracts that comprise the Corporate Units as a single unit of account and classify the Corporate Units as equity under the provisions of ASC 480 and ASC 815. Significant judgments regarding the economic linkage between the Series C Mandatory Convertible Preferred Stock and the forward purchase contracts, as well as the substance of the terms and conditions of the Corporate Units, were required by management in making these determinations.

The initial classification of the Corporate Units, whether viewed as a single unit of account or as two freestanding financial instruments, would affect our financial results. If determined to be two units of account, the forward purchase contracts underlying the Corporate Units would be classified as a derivative and result in impacts to net income through the recognition of interest expense and mark-to-market adjustments. If determined to be one unit of account, the equity classification of the Corporate Units would have no material impact on net income. Each classification has differing impacts to the numerator in the computation of EPS.

We consider that there are a small number of similar equity hosted unit structures and that our unit structure is unique. We also consider that the provisions of ASC 480 and ASC 815 that govern the determination of unit of account are highly complex and that alternate conclusions reached under this guidance would result in materially different financial results. See Note 13, "Equity," in the Notes to Consolidated Financial Statements for additional details of the equity unit transaction.

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

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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 2022 net periodic benefit cost, we selected a weighted-average assumption of the expected pre-tax long-term rate of return of 4.80% and 5.72% for our pension and other postretirement benefit plan assets, respectively. 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 6.69% for our pension and other postretirement benefit plan assets, respectively.

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.

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 12, "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, 2022 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, 2022. A qualitative ("step 0") test was completed on May 1, 2022 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.

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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 7, "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, 2022 we recorded $453.0 million of customer 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, 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.

Valuation allowances against deferred tax assets are recorded when we conclude it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. We evaluate each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At December 31, 2022, we had established $7.8 million of valuation allowances related to certain state NOL carryforwards. Refer to Note 11, "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.