Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

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Contractual Obligations**.** We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt, lease obligations, energy commodity contracts and obligations for various services including pipeline capacity and outsourcing of IT services. The total contractual obligations in existence at December 31, 2019 and their maturities were:

(in millions)	Total				2020				2021				2022				2023				2024				After
Long-term debt (1)	$	7,738.6			$	—			$	63.6			$	530.0			$	600.0			$	—			$	6,545.0
Interest payments on long-term debt	6,214.2				342.0				340.7				337.1				311.1				299.9				4,583.4
Finance leases(2)	325.9				27.2				27.3				26.8				23.1				19.9				201.6
Operating leases(3)	79.1				15.6				9.4				8.2				7.6				6.6				31.7
Energy commodity contracts(4)	95.9				65.5				30.4				—				—				—				—
Service obligations:
Pipeline service obligations	3,450.7				605.0				590.1				546.8				357.2				237.5				1,114.1
IT service obligations	153.2				63.6				49.4				38.0				1.1				1.1				—
Other service obligations(5)	59.8				45.8				14.0				—				—				—				—
Other liabilities	27.3				27.3				—				—				—				—				—
Total contractual obligations	$	18,144.7			$	1,192.0			$	1,124.9			$	1,486.9			$	1,300.1			$	565.0			$	12,475.8

(1) Long-term debt balance excludes unamortized issuance costs and discounts of $70.5 million.

(2) Finance lease payments shown above are inclusive of interest totaling $108.3 million.

(3) Operating lease payments shown above are inclusive of interest totaling $14.3 million. Operating lease balances do not include obligations for possible fleet vehicle lease renewals beyond the initial lease term. While we have the ability to renew these leases beyond the initial term, we are not reasonably certain (as that term is defined in ASC 842) to do so. If we were to continue the fleet vehicle leases outstanding at December 31, 2019, payments would be $34.5 million in 2020, $28.3 million in 2021, $23.4 million in 2022, $19.9 million in 2023, $15.2 million in 2024 and $15.2 million thereafter.

(4)In January 2020, NIPSCO signed new coal contract commitments of $14.4 million for 2020. These contracts are not included above.

(5)In February 2020, NIPSCO signed a new railcar coal transportation contract commitment of $12.0 million for 2020. This contract is not included above.

Our calculated estimated interest payments for long-term debt is based on the stated coupon and payment dates. For 2020, we project that we will be required to make interest payments of approximately $368.2 million, which includes $342.0 million of interest payments related to our long-term debt outstanding as of December 31, 2019. At December 31, 2019, we had $1,773.2 million in short-term borrowings outstanding.

Our expected payments included within “Other liabilities” in the table of contractual commitments above contains employer contributions to pension and other postretirement benefits plans expected to be made in 2020. Plan contributions beyond 2020 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated at this time. In 2020, we expect to make contributions of approximately $3.0 million to our pension plans and approximately $24.0 million to our postretirement medical and life plans. Refer to Note 11, “Pension and Other Postretirement 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 long-term obligations classified as “Total Other Liabilities” on the Consolidated Balance Sheets, other than those described above.

We also have obligations associated with income, property, gross receipts, franchise, payroll, sales and use, and various other taxes and expect to make tax payments of approximately $247.1 million in 2020, which are not included in the table above. In addition, we have uncertain income tax positions that are not included in the table above as we are unable to predict when the matters will be resolved. Refer to Note 10, "Income Taxes," in the Notes to Consolidated Financial Statements for more information.

Refer to Note 19-A, “Contractual Obligations,” in the Notes to Consolidated Financial Statements for further information.

In January 2019, NIPSCO executed two 20 year PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Payments under the PPAs will not begin until the associated generation facilities are constructed by the owner / seller which is currently scheduled to be complete by the end of 2020 for one facility. Payments that will be made under the agreements are not included in the table of contractual commitments above as there are no minimum payment obligations under the agreements. NIPSCO has filed a notice with the IURC of its intention not to move forward with one of its approved PPAs due to the failure to meet a condition precedent in the agreement as a result of local zoning restrictions. See Note 19-E, “Other Matters - NIPSCO 2018 Integrated Resource Plan,” in the Notes to Consolidated Financial Statements for additional information.

In January 2019, NIPSCO executed a BTA with a developer to construct a renewable generation facility with a nameplate capacity of approximately 100 MW; construction of the facility is expected to be completed by the end of 2020. In October 2019, NIPSCO

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

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executed a BTA with a developer to construct an additional renewable generation facility with a nameplate capacity of approximately 300 MW; construction of this facility is expected to be completed by the end of 2021. Payments under these agreements are not included in the table of contractual commitments as NIPSCO's purchase requirement under these BTAs is dependent on satisfactory approval of the BTAs by the IURC, successful execution of agreements with a tax equity partner, and timely completion of construction. See Note 19-E, “Other Matters - NIPSCO 2018 Integrated Resource Plan,” in the Notes to Consolidated Financial Statements for additional information.

Off-Balance Sheet Arrangements

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 about such 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. Risk management for us is 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

We are exposed to commodity price risk as a result of our subsidiaries’ operations involving 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, since regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making process, including gains or losses on these derivative instruments. If states should explore additional regulatory reform, these subsidiaries may begin providing services without the benefit of the traditional rate-making process and may be more exposed to commodity price risk.

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 9, "Risk Management Activities," in the Notes to the Consolidated Financial Statements for further information on our commodity price risk assets and liabilities as of December 31, 2019 and 2018.

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 loan 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 $19.0 million and $13.3 million for 2019 and 2018, 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.

Refer to Note 9, "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, 2019 and 2018.

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

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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 closely monitor the financial status of our banking credit providers. 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 Policies

We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on our operations and 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 $2,239.6 million and $2,512.2 million at December 31, 2019, and $2,237.5 million and $2,660.0 million at December 31, 2018, respectively. For additional information, refer to Note 8, “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 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. Regulatory assets requiring specific regulatory action amounted to $307.2 million at December 31, 2019. If we determine that the amounts included as regulatory assets were not recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.

The passage of the TCJA into law in December 2017 necessitated the remeasurement of our deferred income tax balances to reflect the change in the statutory federal tax rate from 35% to 21%. For our regulated entities, substantially all of the impact of this remeasurement was recorded to a regulatory liability and is being passed backed to customers, as established during the rate making process. For additional information, refer to Note 8, "Regulatory Matters," and Note 10, "Income Taxes," in the Notes to Consolidated Financial Statements.

As discussed in Note 19-E, "Other Matters - Greater Lawrence Pipeline Replacement," since the Greater Lawrence Incident and through December 31, 2019, we have invested approximately $258 million of capital spend for the pipeline replacement in the affected communities; this work was completed in 2019. We maintain property insurance for gas pipelines and other applicable property. Columbia of Massachusetts has filed a proof of loss with its property insurer for the full cost of the pipeline replacement. In January 2020, we filed a lawsuit against the property insurer, seeking payment of our property claim. We are currently unable

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

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to predict the timing or amount of any insurance recovery under the property policy. The recovery of any capital investment not reimbursed through insurance will be addressed in a future regulatory proceeding; a future regulatory proceeding is dependent on the outcome of the sale of the Massachusetts Business. The outcome of such a proceeding (if any) is uncertain. In accordance with ASC 980-360, if it becomes probable that a portion of the pipeline replacement cost will not be recoverable through customer rates and an amount can be reasonably estimated, we will reduce our regulated plant balance for the amount of the probable disallowance and record an associated charge to earnings. This could result in a material adverse effect to our financial condition, results of operations and cash flows. Additionally, if a rate order is received allowing recovery of the investment with no or reduced return on investment, a loss on disallowance may be required.

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 2020 net periodic benefit cost, we selected an expected pre-tax long-term rate of return of 5.70% and 5.67% 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 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.

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

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

	Impact on December 31, 2019 Projected Benefit Obligation Increase/(Decrease)
Change in Assumptions (in millions)	Pension Benefits				Other Postretirement Benefits
+50 basis points change in discount rate	$	(89.9	)		$	(29.0	)
-50 basis points change in discount rate	97.7				31.8
+50 basis points change in health care trend rates					15.0
-50 basis points change in health care trend rates					(13.1		)
	Impact on 2019 Expense Increase/(Decrease)(1)
Change in Assumptions (in millions)	Pension Benefits				Other Postretirement Benefits
+50 basis points change in discount rate	$	(1.8	)		$	0.3
-50 basis points change in discount rate	1.9				0.7
+50 basis points change in expected long-term rate of return on plan assets	(8.9		)		(1.2		)
-50 basis points change in expected long-term rate of return on plan assets	8.9				1.2
+50 basis points change in health care trend rates					0.6
-50 basis points change in health care trend rates					(0.5		)

(1)Before labor capitalization and regulatory deferrals.

In January 2017, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change, compared to the previous method, resulted in a decrease in the actuarially-determined service and interest cost components. Historically, we estimated service and interest cost utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2017 and beyond, we now utilize a full yield curve approach to estimate these components 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 11, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated Financial Statements.

Goodwill and Intangible Assets. We have seven goodwill reporting units, comprised of the seven state operating companies within the Gas Distribution Operations reportable segment. Our goodwill assets at December 31, 2019 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, 2019. A qualitative ("step 0") test was completed on May 1, 2019 for all reporting units other than our Columbia of Massachusetts reporting unit. 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 their baseline May 1, 2016 “step 1” fair value measurement. The results of this assessment indicated that it is not more likely than not that these reporting units fair values are less than their reporting unit carrying values; therefore, no “step 1” analysis was required.

The results of our Columbia of Massachusetts reporting unit were negatively impacted by the Greater Lawrence Incident (see Note 19-C, "Legal Proceedings," in the Notes to Consolidated Financial Statements). As a result, we completed a quantitative "step 1" analysis for the May 1, 2019 goodwill analysis for this reporting unit. Consistent with our historical impairment testing of goodwill, fair value of this reporting unit was determined based on a weighting of income and market approaches. These approaches require significant judgments including appropriate long-term growth rates and discount rates for the income approach and appropriate multiples of earnings for peer companies and control premiums for the market approach. The discount rates were derived using peer company data compiled with the assistance of a third party valuation services firm. The discount rates used are subject to change based on changes in tax rates at both the state and federal level, debt and equity ratios at each reporting unit and general economic conditions. The long-term growth rate was derived by evaluating historic growth rates, new business and investment opportunities beyond the near term horizon. The long-term growth rate is subject to change depending on inflationary impacts to

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

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the U.S. economy and the individual business environments in which each reporting unit operates. The Step 1 analysis performed indicated that the fair value of the Columbia of Massachusetts reporting unit exceeds its carrying value. As a result, no impairment charge was recorded as of the May 1, 2019 test date.

Although our annual impairment test is performed during the second quarter, we continue to monitor changes in circumstances that may indicate that it is more likely than not that the fair value of our reporting units is less than the reporting unit carrying value. During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed matters related to Columbia of Massachusetts. While there was no single determinative event or factor, the consideration in totality of several factors that developed during the fourth quarter of 2019 led us to conclude that it was more likely than not that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. These factors included: (i) increased Massachusetts DPU regulatory enforcement activity related to Columbia of Massachusetts during the fourth quarter, including (a) an order imposing work restrictions on Columbia of Massachusetts, impacting Columbia of Massachusetts' infrastructure replacement program, (b) two orders opening public investigations into Columbia of Massachusetts related to the Greater Lawrence Incident and restoration efforts following the incident, and (c) an order defining the scope of the Massachusetts DPU's investigation into the preparation and response of Columbia of Massachusetts related to the incident; (ii) increased uncertainty as to the ability of Columbia of Massachusetts to execute its growth strategy, including utility infrastructure investments, and to obtain timely regulatory outcomes with reasonable rates of return; (iii) further damage to Columbia of Massachusetts' reputation as a result of concerns related to service lines abandoned during the restoration work following the Greater Lawrence Incident and the gas release event in Lawrence, Massachusetts on September 27, 2019; and (iv) a potential sale of the Massachusetts Business. See Note 19, "Other Commitments and Contingencies - C. Legal Proceedings," in the Notes to Consolidated Financial Statements for more information regarding Massachusetts DPU regulatory enforcement activity and Note 26, "Subsequent Event," in the Notes to Consolidated Financial Statements for more information regarding the potential sale of the Massachusetts Business.

As a result, a new impairment analysis was required for our Columbia of Massachusetts reporting unit. This analysis used a weighted average of income and market approaches for calculating fair value. The income approach calculated discounted cash flows using updated cash flow projections, discount rates and return on equity assumptions. The market approach applied a combination of comparable company multiples and comparable transactions and used updated cash flow projections. While certain assumptions, such as market multiples, remained unchanged in the year-end test, our cash flow projections, return on equity and rate case timing assumptions were all unfavorably updated at year-end compared to the May 1, 2019 test. The effects of these unfavorable developments were greater than the favorable change in weighted average cost of capital between the two tests. The year-end impairment analysis indicated that the fair value of the Columbia of Massachusetts reporting unit was below its carrying value. As a result, we reduced the Columbia of Massachusetts reporting unit goodwill balance to zero and recognized a goodwill impairment charge totaling $204.8 million, which is non-deductible for tax purposes.

Our intangible assets, apart from goodwill, consist of franchise rights. Franchise rights were identified as part of the purchase price allocations associated with the acquisition in February 1999 of Columbia of Massachusetts. We review our definite-lived intangible assets for impairment when events or changes in circumstances indicate its fair value might be below its carrying amount.

During the fourth quarter of 2019, in connection with the preparation of the year-end financial statements, we assessed the changes in circumstances that occurred during the quarter to determine if it was more likely than not that the fair value of the franchise rights was below its carrying amount. These factors were the same fourth quarter circumstances outlined in the goodwill impairment discussion above. As a result, we performed a year-end impairment test in which we compared the book value of Columbia of Massachusetts to its undiscounted future cash flow and estimated fair value. With this analysis, we determined that the fair value of the franchise rights was zero. Therefore, we wrote off the entire franchise rights book value, which resulted in an impairment charge totaling $209.7 million. See Note 6, "Goodwill and Other Intangible Assets," in the Notes to Consolidated Financial Statements for more information.

Revenue Recognition. Revenue is recorded as products and services are delivered. Utility revenues are billed to customers monthly on a cycle basis. Revenues are recorded on the accrual basis and include estimates for electricity and gas delivered but not billed.

We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances and no material changes in the amount or timing of future revenue recognition occurred as a result of the adoption of ASC 606. Refer to Note 3 "Revenue Recognition," in the Notes to Consolidated Financial Statements.

Recently Issued Accounting Pronouncements

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