Rosewater Wind Generation LLC and its wholly owned subsidiary, Rosewater Wind Farm LLC
Indiana Crossroads Wind
Indiana Crossroads Wind Generation LLC and its wholly owned subsidiary, Indiana Crossroads Wind Farm LLC
Abbreviations and Other
基金類型
在施工期間使用資金的津貼
未實現其他綜合收益
累計其他綜合收益（損失）
會計準則更新
會計準則更新
自動取款機
按市場情況
BTA
建設-轉讓協議
CCR
煤燃燒廢料
CEP
資本支出計劃
《綜合環境回應、補償及責任法案》（CERCLA）
全面環境應急補償和責任法案（也稱爲超級基金）
公司單位
A系列公司單位
COVID-19（"COVID-19大流行"或"大流行"）
2019新冠病毒及其變體，包括 Delta 和 Omicron 變種，以及可能出現的任何其他變體
DPU
公用事業部
DSIC
配電系統改善費
美國環保署（EPA）
美國環境保護局
每股收益
每股收益
股權單位
A輪股權單位
FAC
燃料調整條款
FASB
財務會計準則委員會
聯邦能源監管機構（FERC）
聯邦能源監管委員會
FMCA
Federally Mandated Cost Adjustment
通用會計原則(GAAP)
公認會計原則
GCA
燃料幣成本調整
溫室氣體
溫室氣體
千瓦時
千瓦時
IRA
通貨膨脹削減法案
IRP
基礎設施更換計劃
IURC
Indiana Utility Regulatory Commission
合資公司
合資企業
3
定義條款
倫敦銀行同業拆借利率
倫敦銀行同業拆借利率
後進先出
後進先出
低收入家庭暖氣能源援助計劃
低收入取暖能源援助計劃
馬薩諸塞州業務
所有資產按照資產購買協議出售給以及由Eversource承擔的負債
MGP
制氣廠
MISO
Midcontinent獨立系統運營商
百萬MBTU
百萬dekatherms
兆瓦
兆瓦
兆瓦時
Megawatt hours
nymex
紐約商品交易所
其他離崗福利
Other Postemployment Benefits
PHMSA
管道和危險物質安全管理局
電力購買協議
電力購買協議
PUCO
俄亥俄州公用事業委員會
RNG
可再生天然氣的天氣狀況良好
SAVE
推進弗吉尼亞能源計劃的步驟
Scope 1 溫室氣體排放
我們擁有或控制的源頭直接排放（例如，燃料的燃燒、車輛和工藝排放以及泄漏排放）
Scope 2 溫室氣體排放
我們擁有或控制的源頭間接排放
SEC
證券交易委員會
201年關稅
Tariffs imposed by Executive Order from the President of the U.S. on certain imported solar cells and modules at a rate of 15%, which were recently extended to 2026
SMRP
Safety Modification and Replacement Program
SMS
Safety Management System
SOFR
擔保隔夜融資利率
STRIDE
戰略基礎設施發展增強
TCJA
根據2018財年預算決議的第二章和第五章進行和解的法案（通常稱爲2017年稅收減免和就業法案）
TDSIC
變速器、配電和儲存系統改進費
美國檢察官辦公室
馬薩諸塞區美國檢察官辦公室
VIE
可變利益實體
Note regarding forward-looking statements
This Quarterly Report on Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Investors and prospective investors should understand that many factors govern whether any forward-looking statement contained herein will be or can be realized. Any one of those factors could cause actual results to differ materially from those projected. These forward-looking statements include, but are not limited to, statements concerning our plans, strategies, objectives, expected performance, expenditures, recovery of expenditures through rates, stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements that are other than statements of historical fact. Expressions of future goals and expectations and similar expressions, including "may," "will," "should," "could," "would," "aims," "seeks," "expects," "plans," "anticipates," "intends," "believes," "estimates," "predicts," "potential," "targets," "forecast," and "continue," reflecting something other than historical fact are intended to identify forward-looking statements. All forward-looking statements are based on assumptions that management believes to be reasonable; however, there can be no assurance that actual results will not differ materially.
4
Factors that could cause actual results to differ materially from the projections, forecasts, estimates and expectations discussed in this Quarterly Report on Form 10-Q include, among other things, our ability to execute our business plan or growth strategy, including utility infrastructure investments; potential incidents and other operating risks associated with our business; our ability to adapt to, and manage costs related to, advances in, or failures of, technology; impacts related to our aging infrastructure; our ability to obtain sufficient insurance coverage and whether such coverage will protect us against significant losses; the success of our electric generation strategy; construction risks and natural gas costs and supply risks; fluctuations in demand from residential and commercial customers; fluctuations in the price of energy commodities and related transportation costs or an inability to obtain an adequate, reliable and cost-effective fuel supply to meet customer demands; the attraction and retention of a qualified, diverse workforce and ability to maintain good labor relations; our ability to manage new initiatives and organizational changes; the actions of activist stockholders; the performance of third-party suppliers and service providers; potential cybersecurity attacks; increased requirements and costs related to cybersecurity; any damage to our reputation; any remaining liabilities or impact related to the sale of the Massachusetts Business; the impacts of natural disasters, potential terrorist attacks or other catastrophic events; the physical impacts of climate change and the transition to a lower carbon future; our ability to manage the financial and operational risks related to achieving our carbon emission reduction goals, including our Net-Zero Goal (as defined below); our debt obligations; any changes to our credit rating or the credit rating of certain of our subsidiaries; any adverse effects related to our equity units; adverse economic and capital market conditions or increases in interest rates; inflation; recessions; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; continuing and potential future impacts from the COVID-19 pandemic; economic conditions in certain industries; the reliability of customers and suppliers to fulfill their payment and contractual obligations; the ability of our subsidiaries to generate cash; pension funding obligations; potential impairments of goodwill; the outcome of legal and regulatory proceedings, investigations, incidents, claims and litigation; potential remaining liabilities related to the Greater Lawrence Incident; compliance with applicable laws, regulations and tariffs; compliance with environmental laws and the costs of associated liabilities; changes in taxation; other matters in the "Risk Factors" section of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, many of which risks are beyond our control. In addition, the relative contributions to profitability by each business segment, and the assumptions underlying the forward-looking statements relating thereto, may change over time.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. We undertake no obligation to, and expressly disclaim any such obligation to, update or revise any forward-looking statements to reflect changed assumptions, the occurrence of anticipated or unanticipated events or changes to the future results over time or otherwise, except as required by law.
Condensed Statements of Consolidated Comprehensive Income (unaudited)
Three Months Ended March 31,
(in millions, net of taxes)
2023
2022
Net Income
$
337.8
$
431.3
Other comprehensive income:
Net unrealized gain (loss) on available-for-sale debt securities(1)
2.0
(5.7)
Reclassification adjustment for cash flow hedges(2)
0.1
47.0
Unrecognized pension and OPEB benefit(3)
0.3
0.1
Total other comprehensive income
2.4
41.4
Comprehensive Income
$
340.2
$
472.7
(1)Net unrealized gain (loss) on available-for-sale securities, net of $0.5 million tax expense and $1.5 million tax benefit in the first quarter of 2023 and 2022, respectively.
(2)Reclassification adjustment for cash flow hedges, net of $0.1 million tax benefit and $21.3 million tax expense in the first quarter of 2023 and 2022, respectively.
(3)Unrecognized pension and OPEB benefit, net of $0.1 million and zero tax expense in the first quarter of 2023 and 2022, respectively.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
Available-for-sale debt securities (amortized cost of $162.8 and $166.7, allowance for credit losses of $0.8 and $0.9, respectively)
150.4
151.6
Other investments
74.3
71.0
Total Investments and Other Assets
226.9
224.2
Current Assets
Cash and cash equivalents
106.4
40.8
Restricted cash
41.9
34.6
Accounts receivable
954.2
1,065.8
Allowance for credit losses
(31.4)
(23.9)
Accounts receivable, net
922.8
1,041.9
Gas inventory
138.8
531.7
Materials and supplies, at average cost
172.6
151.4
Electric production fuel, at average cost
64.9
68.8
Exchange gas receivable
92.1
128.1
Regulatory assets
237.6
233.2
Deposits to renewable generation asset developer
281.2
143.8
Prepayments and other
278.2
210.0
Total Current Assets(1)
2,336.5
2,584.3
Other Assets
Regulatory assets
2,319.2
2,347.6
Goodwill
1,485.9
1,485.9
Deferred charges and other
257.6
252.0
Total Other Assets
4,062.7
4,085.5
Total Assets
$
26,853.7
$
26,736.6
(1)Includes $972.7 million and $978.5 million at March 31, 2023 and December 31, 2022, respectively, of net property, plant and equipment assets and $33.8 million and $25.7 million at March 31, 2023 and December 31, 2022, respectively, of current assets of consolidated VIEs that may be used only to settle obligations of the consolidated VIEs. Refer to Note 12, "Variable Interest Entities," for additional information.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
Common stock - $0.01 par value, 600,000,000 shares authorized; 412,982,639 and 412,142,602 shares outstanding, respectively
$
4.2
$
4.2
Preferred stock - $0.01 par value, 20,000,000 shares authorized; 1,302,500 and 1,302,500 shares outstanding, respectively
1,546.5
1,546.5
Treasury stock
(99.9)
(99.9)
Additional paid-in capital
7,372.9
7,375.3
Retained deficit
(1,114.8)
(1,213.6)
Accumulated other comprehensive loss
(34.7)
(37.1)
Total NiSource Stockholders’ Equity
7,674.2
7,575.4
Noncontrolling interest in consolidated subsidiaries
329.5
326.4
Total Equity
8,003.7
7,901.8
Long-term debt, excluding amounts due within one year
10,264.7
9,523.6
Total Capitalization
18,268.4
17,425.4
Current Liabilities
Current portion of long-term debt
30.3
30.0
Short-term borrowings
1,281.6
1,761.9
Accounts payable
642.2
899.5
Dividends payable - common stock
103.4
—
Dividends payable - preferred stock
19.4
—
Customer deposits and credits
225.5
324.7
Taxes accrued
268.7
246.2
Interest accrued
139.2
138.4
Exchange gas payable
19.6
147.6
Regulatory liabilities
359.1
236.8
Asset retirement obligations
48.1
35.5
Accrued compensation and employee benefits
124.5
167.5
Obligations to renewable generation asset developer
347.2
347.2
Other accruals
298.1
325.2
Total Current Liabilities(1)
3,906.9
4,660.5
Other Liabilities
Deferred income taxes
1,950.1
1,854.5
Accrued liability for postretirement and postemployment benefits
239.6
245.5
Regulatory liabilities
1,725.5
1,775.8
Asset retirement obligations
464.7
478.1
Other noncurrent liabilities and deferred credits
298.5
296.8
Total Other Liabilities(1)
4,678.4
4,650.7
Commitments and Contingencies (Refer to Note 15, "Other Commitments and Contingencies")
Total Capitalization and Liabilities
$
26,853.7
$
26,736.6
(1)Includes $135.4 million and $128.2 million at March 31, 2023 and December 31, 2022, respectively, of current liabilities and $30.7 million and $30.6 million at March 31, 2023 and December 31, 2022, respectively, of other liabilities of consolidated VIEs that creditors do not have recourse to our general credit. Refer to Note 12, "Variable Interest Entities," for additional information.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
Condensed Statements of Consolidated Equity (unaudited)
(in millions)
Common Stock
Preferred Stock(1)
Treasury Stock
Additional Paid-In Capital
Retained Deficit
Accumulated Other Comprehensive Loss
Noncontrolling Interest in Consolidated Subsidiaries
Total
Balance as of January 1, 2023
$
4.2
$
1,546.5
$
(99.9)
$
7,375.3
$
(1,213.6)
$
(37.1)
$
326.4
$
7,901.8
Comprehensive Income:
Net income
—
—
—
—
333.0
—
4.8
337.8
Other comprehensive income, net of tax
—
—
—
—
—
2.4
—
2.4
Dividends:
Common stock ($0.50 per share)
—
—
—
—
(206.7)
—
—
(206.7)
Preferred stock (See Note 5)
—
—
—
—
(27.5)
—
—
(27.5)
Contributions from noncontrolling interest
—
—
—
—
—
—
3.6
3.6
Distributions to noncontrolling interests
—
—
—
—
—
—
(5.3)
(5.3)
Stock issuances:
Employee stock purchase plan
—
—
—
1.3
—
—
—
1.3
Long-term incentive plan
—
—
—
(6.3)
—
—
—
(6.3)
401(k) and profit sharing
—
—
—
2.6
—
—
—
2.6
Balance as of March 31, 2023
$
4.2
$
1,546.5
$
(99.9)
$
7,372.9
$
(1,114.8)
$
(34.7)
$
329.5
$
8,003.7
(1)Series A, Series B, and Series C shares have an aggregate liquidation preference of $400M, $500M, and $863M, respectively. See Note 5, "Equity," for additional information.
(in millions)
Common Stock
Preferred Stock(1)
Treasury Stock
Additional Paid-In Capital
Retained Deficit
Accumulated Other Comprehensive Loss
Noncontrolling Interest in Consolidated Subsidiaries
Total
Balance as of January 1, 2022
$
4.1
$
1,546.5
$
(99.9)
$
7,204.3
$
(1,580.9)
$
(126.8)
$
325.6
$
7,272.9
Comprehensive Income:
Net income
—
—
—
—
426.8
—
4.5
431.3
Other comprehensive income, net of tax
—
—
—
—
—
41.4
—
41.4
Dividends:
Common stock ($0.47 per share)
—
—
—
—
(190.7)
—
—
(190.7)
Preferred stock (See Note 5)
—
—
—
—
(27.5)
—
—
(27.5)
Distributions to noncontrolling interest
—
—
—
—
—
—
(0.6)
(0.6)
Stock issuances:
Employee stock purchase plan
—
—
—
1.2
—
—
—
1.2
Long-term incentive plan
—
—
—
0.9
—
—
—
0.9
401(k) and profit sharing
—
—
—
2.5
—
—
—
2.5
Balance as of March 31, 2022
$
4.1
$
1,546.5
$
(99.9)
$
7,208.9
$
(1,372.3)
$
(85.4)
$
329.5
$
7,531.4
(1)Series A, Series B and Series C shares have an aggregate liquidation preference of $400M, $500M, and $863M, respectively. See Note 5, "Equity," for additional information.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
1. Basis of Accounting Presentation
Our accompanying Condensed Consolidated Financial Statements (unaudited) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP in the United States of America. The accompanying financial statements include the accounts of us, our majority-owned subsidiaries, and VIEs of which we are the primary beneficiary after the elimination of all intercompany accounts and transactions.
The accompanying financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors.
The Condensed Consolidated Financial Statements (unaudited) have been prepared pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made in this Quarterly Report on Form 10-Q are adequate to make the information herein not misleading.
2. Recent Accounting Pronouncements
Recently Adopted Accounting Pronouncements
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and in January 2021, the FASB issuedASU 2021-01, Reference Rate Reform (Topic 848): Scope. These pronouncements provide temporary optional expedients and exceptions for applying GAAP principles to contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. These pronouncements were effective upon issuance on March 12, 2020 through December 31, 2022. In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, to extend the temporary accounting rules under Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. During 2022, the company applied a practical expedient under Topic 848 which allowed for the continuation of cash flow hedge accounting for interest rate derivative contracts upon the transition from LIBOR to alternative reference rates. The application of this expedient had no impact on the Condensed Consolidated Financial Statements (unaudited).
3. Revenue Recognition
Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment, as well as by customer class. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, and Indiana. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The tables below reconcile revenue disaggregation by customer class to segment revenue, as well as to revenues reflected on the Condensed Statements of Consolidated Income (unaudited):
Three Months Ended March 31, 2023
(in millions)
Gas Distribution Operations(2)
Electric Operations
Corporate and Other
Total
Customer Revenues(1)
Residential
$
987.0
$
150.4
$
—
$
1,137.4
Commercial
360.6
150.9
—
511.5
Industrial
71.9
134.2
—
206.1
Off-system
17.2
—
—
17.2
Miscellaneous
18.4
5.5
—
23.9
Total Customer Revenues
$
1,455.1
$
441.0
$
—
$
1,896.1
Other Revenues
46.2
23.5
0.2
69.9
Total Operating Revenues
$
1,501.3
$
464.5
$
0.2
$
1,966.0
(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues.
(2)Amounts included in Gas Distributions Operations Other revenues primarily relate to weather normalization adjustments driven by warmer weather in 2023 compared to 2022.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Three Months Ended March 31, 2022
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other(2)
Total
Customer Revenues(1)
Residential
$
976.9
$
138.5
$
—
$
1,115.4
Commercial
356.5
134.5
—
491.0
Industrial
67.8
129.8
—
197.6
Off-system
18.7
—
—
18.7
Miscellaneous
14.0
3.6
—
17.6
Total Customer Revenues
$
1,433.9
$
406.4
$
—
$
1,840.3
Other Revenues
2.8
23.7
6.5
33.0
Total Operating Revenues
$
1,436.7
$
430.1
$
6.5
$
1,873.3
(1)Customer revenue amounts exclude intersegment revenues. See Note 18, "Business Segment Information," for discussion of intersegment revenues.
(2)Amounts associated with Corporate and Other revenues primarily relate to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.
Customer Accounts Receivable. Accounts receivable on our Condensed Consolidated Balance Sheets (unaudited) includes both billed and unbilled amounts, as well as certain amounts that are not related to customer revenues. Unbilled amounts of accounts receivable relate to a portion of a customer’s consumption of gas or electricity from the date of the last cycle billing through the last day of the month (balance sheet date). Factors taken into consideration when estimating unbilled revenue include historical usage, customer rates, and weather. A significant portion of our operations are subject to seasonal fluctuations in sales. During the heating season, primarily from November through March, revenues and receivables from gas sales are more significant than in other months. The opening and closing balances of customer receivables for the three months ended March 31, 2023 are presented in the table below. We had no significant contract assets or liabilities during the period. Additionally, we have not incurred any significant costs to obtain or fulfill contracts.
Utility revenues are billed to customers monthly on a cycle basis. We expect that substantially all customer accounts receivable will be collected following customer billing, as this revenue consists primarily of periodic, tariff-based billings for service and usage. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. Our regulated operations also utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility. It is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations.
Allowance for Credit Losses. To evaluate for expected credit losses, customer account receivables are pooled based on similar risk characteristics, such as customer type, geography, payment terms, and related macro-economic risks. Expected credit losses are established using a model that considers historical collections experience, current information, and reasonable and supportable forecasts. Internal and external inputs are used in our credit model including, but not limited to, energy consumption trends, revenue projections, actual charge-offs data, recoveries data, shut-offs, customer delinquencies, final bill data, and inflation. We continuously evaluate available information relevant to assessing collectability of current and future receivables. We evaluate creditworthiness of specific customers periodically or following changes in facts and circumstances. When we become aware of a specific commercial or industrial customer's inability to pay, an allowance for expected credit losses is recorded for the relevant amount. We also monitor other circumstances that could affect our overall expected credit losses including, but not limited to, creditworthiness of overall population in service territories, adverse conditions impacting an industry sector, and current economic conditions.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
At each reporting period, we record expected credit losses to an allowance for credit losses account. When deemed to be uncollectible, customer accounts are written-off. A rollforward of our allowance for credit losses as of March 31, 2023 and December 31, 2022 are presented in the table below:
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other
Total
Balance as of January 1, 2023
$
17.2
$
5.9
$
0.8
$
23.9
Current period provisions
10.4
2.0
—
12.4
Write-offs charged against allowance
(12.1)
(1.5)
—
(13.6)
Recoveries of amounts previously written off
8.5
0.2
—
8.7
Balance as of March 31, 2023
$
24.0
$
6.6
$
0.8
$
31.4
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other
Total
Balance as of January 1, 2022
$
18.9
$
3.8
$
0.8
$
23.5
Current period provisions
29.1
6.9
—
36.0
Write-offs charged against allowance
(52.1)
(5.3)
—
(57.4)
Recoveries of amounts previously written off
21.3
0.5
—
21.8
Balance as of December 31, 2022
$
17.2
$
5.9
$
0.8
$
23.9
4. Earnings Per Share
The calculations of basic and diluted EPS are based on the weighted average number of shares of common stock and potential common stock outstanding during the period. For the purposes of determining diluted EPS, the shares underlying the purchase contracts included within the Equity Units were included in the calculation of potential common stock outstanding for the three months ended March 31, 2023 and 2022 using the if-converted method under US GAAP. For the purchase contracts, the number of shares of our common stock that would be issuable at the end of each reporting period will be reflected in the denominator of our diluted EPS calculation. If the stock price falls below the initial reference price of $24.51, subject to anti-dilution adjustments, the number of shares of our common stock used in calculating diluted EPS will be the maximum number of shares per the contract as described in Note 5, "Equity." Conversely, if the stock price is above the initial reference price of $24.51, subject to anti-dilution adjustments, a variable number of shares of our common stock will be used in calculating diluted EPS. A numerator adjustment is reflected in the calculation of diluted EPS for interest expense incurred for the three months ended March 31, 2023 and 2022 net of tax, related to the purchase contracts.
We adopted ASU 2020-06 on January 1, 2022, which resulted in additional dilution from our Equity Units by requiring us to assume share settlement of the remaining purchase contract payment balance based on the average share price during the period.
The shares underlying the Series C Mandatory Convertible Preferred Stock included within the Equity Units are contingently convertible as the conversion is contingent on a successful remarketing as described in Note 5, "Equity." Contingently convertible shares where conversion is not tied to a market price trigger are excluded from the calculation of diluted EPS until such time as the contingency has been resolved under the if-converted method. As of March 31, 2023 and 2022, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the three months ended March 31, 2023 and 2022.
Diluted EPS also includes the incremental effects of the various long-term incentive compensation plans and the open ATM forward agreements during the period under the treasury stock method when the impact would be dilutive.
We began using the two-class method of computing earnings per share in 2023 because we have participating securities in the form of non-vested restricted stock units with a non-forfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
During 2022, we had no outstanding securities other than common and preferred stock, which required holders’ participation in dividends and earnings; therefore, we were not required to calculate EPS under the two-class method. Basic net income per share is computed by dividing net income available to common shareholders by the weighted-average number of shares of common stock outstanding during the period. Diluted net income per share is computed by giving effect to all potential shares of common stock, to the extent they are dilutive.
The following table presents the calculation of our basic and diluted EPS:
Three Months Ended March 31,
(in millions, except per share amounts)
2023
2022
Numerator:
Net Income Available to Common Shareholders
$
319.2
$
413.0
Less: Income allocated to participating securities
0.2
—
Net Income Available to Common Shareholders - Basic
319.0
413.0
Add: Dilutive effect of Equity Units
0.4
0.5
Net Income Available to Common Shareholders - Diluted
$
319.4
$
413.5
Denominator:
Average common shares outstanding - Basic
412.8
406.0
Dilutive potential common shares:
Equity Units purchase contracts
31.2
29.1
Equity Units purchase contract payment balance
1.8
4.0
Shares contingently issuable under employee stock plans
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
5. Equity
ATM Program. On February 22, 2021, we entered into six separate equity distribution agreements pursuant to which we are able to sell up to an aggregate of $750.0 million of our common stock. As of March 31, 2023, the ATM program had approximately $300.0 million of equity available for issuance. The program expires on December 31, 2023. There are no outstanding forward agreements as of March 31, 2023.
Preferred Stock. As of March 31, 2023, we had 20,000,000 shares of preferred stock authorized for issuance, of which 1,302,500 shares of preferred stock in the aggregate for all series were outstanding. The following table displays preferred dividends declared for the period by outstanding series of shares:
Three Months Ended March 31,
March 31,
December 31,
2023
2022
2023
2022
(in millions except shares and per share amounts)
Liquidation Preference Per Share
Shares
Dividends Declared Per Share
Outstanding
5.650% Series A
$
1,000.00
400,000
28.25
28.25
$
393.9
$
393.9
6.500% Series B
$
25,000.00
20,000
812.50
812.50
$
486.1
$
486.1
Series C(1)
$
1,000.00
862,500
—
—
$
666.5
$
666.5
(1)The Series C Mandatory Convertible Preferred Stock initially will not bear any dividends. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock.
In addition, 20,000 shares of Series B–1 Preferred Stock, par value $0.01 per share, were outstanding as of March 31, 2023. Holders of Series B–1 Preferred Stock are not entitled to receive dividend payments and have no conversion rights. The Series B–1 Preferred Stock is paired with the Series B Preferred Stock and may not be transferred, redeemed or repurchased except in connection with the simultaneous transfer, redemption, or repurchase of the underlying Series B Preferred Stock.
As of March 31, 2023 and 2022, Series A Preferred Stock had $6.7 million of cumulative preferred dividends in arrears, or $16.63 per share, and Series B Preferred Stock had $1.4 million of cumulative preferred dividends in arrears, or $72.23 per share.
Equity Units. On April 19, 2021, we completed the sale of 8.625 million Equity Units, initially consisting of Corporate Units, each with a stated amount of $100. The offering generated net proceeds of $835.5 million, after underwriting and issuance expenses. Each Corporate Unit consists of a forward contract to purchase shares of our common stock in the future and a 1/10th, or 10%, undivided beneficial ownership interest in one share of Series C Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share.
Selected information about the Equity Units at the issuance date is presented below:
(in millions except contract rate)
Issuance Date
Units Issued
Total Net Proceeds(1)
Purchase Contract Annual Rate
Purchase Contract Liability
Equity Units
April 19, 2021
8.625
$
835.5
7.75
%
$
168.8
(1)Issuance costs of $27.0 million were recorded on a relative fair value basis as a reduction to preferred stock of $22.5 million and a reduction to the purchase contract liability of $4.5 million.
The purchase contract obligates holders to purchase shares of our common stock on December 1, 2023, subject to early settlement in certain situations. The purchase price paid under the purchase contract is $100 and the number of shares to be purchased will be determined under a settlement rate formula based on the volume-weighted average share price of our common stock near the settlement date, subject to a maximum settlement rate. The Series C Mandatory Convertible Preferred Stock will initially be pledged upon issuance as collateral to secure the purchase of common stock under the related purchase contracts.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The Series C Mandatory Convertible Preferred Stock is expected to be remarketed prior to December 1, 2023, and each share, unless previously converted, will automatically convert to common stock based on a conversion rate on the mandatory conversion date, which is expected to be on or about March 1, 2024. The conversion rate will be determined based on the volume-weighted average share price of our common stock near the conversion date, subject to a minimum and maximum conversion rate. Prior to December 1, 2023, the Series C Mandatory Convertible Preferred Stock will not bear any dividends and the liquidation preference will not accrete. Following a successful remarketing, dividends may become payable on the Series C Mandatory Convertible Preferred Stock and/or the minimum conversion rate of the Series C Mandatory Convertible Preferred Stock may be increased. If no successful remarketing of the Series C Mandatory Convertible Preferred Stock has previously occurred, effective as of December 1, 2023, the conversion rate will be zero, no shares of our common stock will be delivered upon automatic conversion and each share of Series C Mandatory Convertible Preferred Stock will be automatically transferred to us on the mandatory conversion date without any payment of cash or shares of our common stock thereon. In the event of such a remarketing failure, any shares of Series C Mandatory Convertible Preferred Stock held as part of Corporate Units will be automatically delivered to us on December 1, 2023 in full satisfaction of the relevant holder's obligation under the related purchase contracts.
We will pay quarterly contract adjustment payments at the rate of 7.75% per year on the stated amount of $100 per Equity Unit. The contract adjustment payments are payable in cash, shares of our common stock or a combination thereof, at our election. The payment of contract adjustment payments may also be deferred until the purchase contract settlement date, December 1, 2023, at our election. If we exercise our option to defer the payment of contract adjustment payments, then until the deferred contract adjustment payments have been paid, we will not declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any shares of our capital stock; make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of our debt securities that rank on parity with, or junior to, the contract adjustment payments; or make any guarantee payments under any guarantee by us of securities of any of our subsidiaries if our guarantee ranks on parity with, or junior to, the contract adjustment payments. As of March 31, 2023, no contract adjustment payments have been deferred with quarterly cash payments being remitted to the holders. As of March 31, 2023 and December 31, 2022 the purchase contract liability, net of issuance costs, was $48.8 million and $65.0 million, respectively. Purchase contract payments are recorded against this liability. Accretion of the purchase contract liability is recorded as interest expense. Cash payments of $16.7 million were made during the three months ended March 31, 2023 and 2022.
The Series C Mandatory Convertible Preferred Stock and forward purchase contracts are legally detachable and separately exercisable, however, due to the economic linkage between the forward purchase contract and the Series C Mandatory Convertible Preferred Stock, we have concluded that the ability to separate the Corporate Units is non-substantive. Accordingly, we are accounting for the Corporate Units as a single unit of account. We recorded the initial present value of the purchase contract payments as a liability with a corresponding reduction to preferred stock. This liability is included in "Other accruals" on theCondensed Consolidated Balance Sheets (unaudited).
Refer to Note 4, "Earnings Per Share," for additional information regarding our treatment of the Equity Units for diluted EPS. Under the terms of the Equity Units, assuming no anti-dilution or other adjustments such as a fundamental change, the maximum number of shares of common stock we will issue under the purchase contracts is 35.2 million and maximum number of shares of common stock we will issue under the Series C Mandatory Convertible Preferred Stock is 35.2 million. Had we settled the remaining purchase contract payment balance in shares at March 31, 2023, we would have issued approximately 1.8 million shares.
6. Gas in Storage
We use both the LIFO inventory methodology and the weighted-average cost methodology to value natural gas in storage. Natural gas storage injections are priced at the average of the costs of natural gas supply purchased during the year. For interim periods, the difference in the cost of replacing the current portion of stored gas inventory compared to the amount stated on a LIFO basis is recorded within the Condensed Consolidated Balance Sheets (unaudited). Due to seasonality requirements, we expect interim variances in LIFO layers to be replenished by year end. The LIFO basis exceeded the cost of replacing the current portion of stored gas by $22.3 million and zero as of March 31, 2023 and December 31, 2022, respectively, for certain gas distribution companies recorded within "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
7. Regulatory Matters
NIPSCO change in accounting estimate
As part of the NIPSCO Gas Settlement and Stipulation Agreement filed on March 2, 2022, NIPSCO Gas agreed to change the depreciation methodology for its calculation of depreciation rates, which reduces depreciation expense and subsequent revenues and cash flows. An order was received on July 27, 2022 approving the rate case and rates were effective as of September 1, 2022. NIPSCO has proposed a similar change in depreciation methodology in its pending electric base rate case, and this proposed change is included in the settlement that has been filed for approval. An order is expected in the electric rate case in August of 2023.
Columbia of Ohio regulatory filing update
Columbia of Ohio's base rate case was filed on June 21, 2021, requesting a net rate increase of approximately 21.3% or $221.4 million increase in revenue per year. The case was filed in conjunction with applications for an alternative rate plan, approval of certain deferral authority, and updates to certain riders. On October 31, 2022, Columbia of Ohio filed a joint stipulation and recommendation with certain parties to settle the base rate case. On January 26, 2023, the PUCO modified and approved the joint stipulation and recommendation, and Columbia of Ohio placed rates into effect on March 1, 2023. Applications for Rehearing were filed by the three parties who opposed certain rate design and energy efficiency assistance components of the joint stipulation and recommendation, which was granted for further consideration by the PUCO on March 22, 2023.
Regulatory deferral related to renewable energy investments
In accordance with the accounting principles of ASC 980, we recognize a regulatory liability or asset for 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. The amounts recorded in income will ultimately reflect the amount allowed in regulated rates to recover our investments over the useful life of the projects. The offset to the regulatory liability or asset associated with our renewable investments included in regulated rates is recorded in "Depreciation expense" on the Condensed Statements of Consolidated Income (unaudited). NiSource recorded a decrease to depreciation expense of $4.4 million and $2.9 million for the three months ended March 31, 2023 and 2022, respectively. Refer to Note 12, "Variable Interest Entities," for additional information.
8. Risk Management Activities
We are exposed to certain risks relating to our ongoing business operations; namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below:
March 31, 2023
December 31, 2022
(in millions)
Assets
Liabilities
Assets
Liabilities
Current(1)
Derivatives designated as hedging instruments
$
—
$
—
$
—
$
—
Derivatives not designated as hedging instruments
5.0
5.4
18.8
1.1
Total
$
5.0
$
5.4
$
18.8
$
1.1
Noncurrent(2)
Derivatives designated as hedging instruments
$
—
$
—
$
—
$
—
Derivatives not designated as hedging instruments
46.5
1.1
66.0
1.9
Total
$
46.5
$
1.1
$
66.0
$
1.9
(1)Currentassets and liabilities are presented in "Prepayments and other" and "Other accruals", respectively, on the Condensed Consolidated Balance Sheets (unaudited).
(2)Noncurrentassets and liabilities are presented in "Deferred charges and other" and "Other noncurrent liabilities and deferred credits", respectively, on the Condensed Consolidated Balance Sheets (unaudited).
Our derivative instruments aresubject to enforceable master netting arrangements or similar agreements. No collateral was either received or posted related to our outstanding derivative positions at March 31, 2023. If the above gross asset and liability positions were presented net of amounts owed or receivable from counterparties, we would report a net asset position of $45.0 million and $81.8 million at March 31, 2023 and December 31, 2022, respectively.
All gains and losses on derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism.
Derivatives Not Designated as Hedging Instruments
Commodity price risk management. We, along with our utility customers, are exposed to variability in cash flows associated with natural gas purchases and volatility in natural gas prices. We purchase natural gas for sale and delivery to our retail, commercial and industrial customers, and for most customers the variability in the market price of gas is passed through in their rates. Some of our utility subsidiaries offer programs whereby variability in the market price of gas is assumed by the respective utility. The objective of our commodity price risk programs is to mitigate the gas cost variability, for us or on behalf of our customers, associated with natural gas purchases or sales by economically hedging the various gas cost components using a combination of futures, options, forwards or other derivative contracts. At March 31, 2023 and December 31, 2022, we had 92.8 MMDth and 99.0 MMDth, respectively, of net energy derivative volumes outstanding related to our natural gas hedges.
NIPSCO has received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments and is limited to 20% of NIPSCO's average annual GCA purchase volume. As of March 31, 2023, the remaining terms of these instruments range from one to four years.
The following table summarizes the gains and losses associated with the commodity price risk programs:
(in millions)
March 31, 2023
December 31, 2022
Regulatory Assets
Losses on commodity price risk programs
$
21.7
$
10.0
Regulatory Liabilities
Gains on commodity price risk programs
52.3
90.0
Our derivative instruments measured at fair value as of March 31, 2023 and December 31, 2022 do not contain any credit-risk-related contingent features.
Derivatives Designated as Hedging Instruments
Interest rate risk management. As of March 31, 2023, we have no active interest rate swap positions.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The net gain related to multiple of our settled interest rate swaps, is recorded in AOCI. We amortize the net gain over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial for the three months ended March 31, 2023 and 2022 and are recorded in "Interest expense, net" on the Condensed Statements of Consolidated Income (unaudited). Amounts expected to be reclassified to earnings during the next twelve months are immaterial. Amortization will continue for 350 months. See Note 16, "Accumulated Other Comprehensive Loss," for additional information.
9. Fair Value
A. Fair Value Measurements
Recurring Fair Value Measurements
The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of March 31, 2023 and December 31, 2022:
Recurring Fair Value Measurements March 31, 2023 (in millions)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Balance as of
March 31, 2023
Assets
Risk management assets
$
—
$
51.5
$
—
$
51.5
Available-for-sale debt securities
—
150.4
—
150.4
Total
$
—
$
201.9
$
—
$
201.9
Liabilities
Risk management liabilities
$
—
$
6.5
$
—
$
6.5
Total
$
—
$
6.5
$
—
$
6.5
Recurring Fair Value Measurements December 31, 2022 (in millions)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Balance as of
December 31, 2022
Assets
Risk management assets
$
—
$
84.8
$
—
$
84.8
Available-for-sale debt securities
—
151.6
—
151.6
Total
$
—
$
236.4
$
—
$
236.4
Liabilities
Risk management liabilities
$
—
$
3.0
$
—
$
3.0
Total
$
—
$
3.0
$
—
$
3.0
Risk Management Assets and Liabilities. Risk management assets and liabilities include exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts.
Level 1- When utilized, exchange-traded derivative contracts are based on unadjusted quoted prices in active markets and are classified within Level 1. These financial assets and liabilities are secured with cash on deposit with the exchange; therefore, nonperformance risk has not been incorporated into these valuations. These financial assets and liabilities are deemed to be cleared and settled daily by NYMEX as the related cash collateral is posted with the exchange. As a result of this exchange rule, NYMEX derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and are subject to future commodity price fluctuations until they are settled in accordance with their contractual terms.
Level 2- Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. We use a similar model
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs, (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized within Level 2.
Level 3- Certain derivatives trade in less active markets with a lower availability of pricing information and models may be utilized in the valuation. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized within Level 3.
Credit risk is considered in the fair value calculation of derivative instruments that are not exchange-traded. Credit exposures are adjusted to reflect collateral agreements that reduce exposures. As of March 31, 2023 and December 31, 2022, there were no material transfers between fair value hierarchies. Additionally, there were no changes in the method or significant assumptions used to estimate the fair value of our financial instruments.
NIPSCO has entered into long-term forward natural gas purchase instruments to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 8, "Risk Management Activities."
Available-for-Sale Debt Securities. Available-for-sale debt securities are investments pledged as collateral for trust accounts related to our wholly owned insurance company. We value U.S. Treasury, corporate debt and mortgage-backed securities using a matrix pricing model that incorporates market-based information. These securities trade less frequently and are classified within Level 2.
Our available-for-sale debt securities impairments are recognized periodically using an allowance approach. At each reporting date, we utilize a quantitative and qualitative review process to assess the impairment of available-for-sale debt securities at the individual security level. For securities in a loss position, we evaluate our intent to sell or whether it is more-likely-than-not that we will be required to sell the security prior to the recovery of its amortized cost. If either criteria is met, the loss is recognized in earnings immediately, with the offsetting entry to the carrying value of the security. If both criteria are not met, we perform an analysis to determine whether the unrealized loss is related to credit factors. The analysis focuses on a variety of factors that include, but are not limited to, downgrade on ratings of the security, defaults in the current reporting period or projected defaults in the future, the security's yield spread over treasuries, and other relevant market data. If the unrealized loss is not related to credit factors, it is included in other comprehensive income. If the unrealized loss is related to credit factors, the loss is recognized as credit loss expense in earnings during the period, with an offsetting entry to the allowance for credit losses. The amount of the credit loss recorded to the allowance account is limited by the amount at which the security's fair value is less than its amortized cost basis. If certain amounts recorded in the allowance for credit losses are deemed uncollectible, the allowance on the uncollectible portion will be charged off, with an offsetting entry to the carrying value of the security. Subsequent improvements to the estimated credit losses of available-for-sale debt securities will be recognized immediately in earnings. As of March 31, 2023 and December 31, 2022, we have $0.8 million and $0.9 million, respectively, recorded as an allowance for credit losses on available-for-sale debt securities as a result of the analysis described above. Continuous credit monitoring and portfolio credit balancing mitigates our risk of credit losses on our available-for-sale debt securities.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The amortized cost, gross unrealized gains and losses, allowance for credit losses, and fair value of available-for-sale securities at March 31, 2023 and December 31, 2022 were:
March 31, 2023 (in millions)
Amortized Cost
Gross Unrealized Gains
Gross Unrealized Losses(1)
Allowance for Credit Losses
Fair Value
Available-for-sale debt securities
U.S. Treasury debt securities
$
67.0
$
0.1
$
(3.3)
$
—
$
63.8
Corporate/Other debt securities
95.8
—
(8.4)
(0.8)
86.6
Total
$
162.8
$
0.1
$
(11.7)
$
(0.8)
$
150.4
December 31, 2022 (in millions)
Amortized Cost
Gross Unrealized Gains
Gross Unrealized Losses(2)
Allowance for Credit Losses
Fair Value
Available-for-sale debt securities
U.S. Treasury debt securities
$
67.7
$
—
$
(4.5)
$
—
$
63.2
Corporate/Other debt securities
99.0
—
(9.7)
(0.9)
88.4
Total
$
166.7
$
—
$
(14.2)
$
(0.9)
$
151.6
(1)Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $56.2 million and $82.5 million, respectively, at March 31, 2023.
(2)Fair value of U.S. Treasury debt securities and Corporate/Other debt securities in an unrealized loss position without an allowance for credit losses is $61.0 million and $85.5 million, respectively, at December 31, 2022.
The cost of maturities sold is based upon specific identification. Realized gains and losses on available-for-sale securities were immaterial for the three months ended March 31, 2023 and 2022.
At March 31, 2023, approximately $6.3 million of U.S. Treasury debt securities and approximately $4.1 million of Corporate/Other debt securities have maturities of less than a year.
Non-recurring Fair Value Measurements
We measure the fair value of certain assets, including goodwill, on a non-recurring basis, typically when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable.
Purchase Contract Liability. At April 19, 2021, we recorded the purchase contract liability at fair value using a discounted cash flow method and observable, market-corroborated inputs. This estimate was made at April 19, 2021, and will not be remeasured at each subsequent balance sheet date. It has been categorized within Level 2 of the fair value hierarchy. Refer to Note 5, "Equity," for additional information.
B. Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, notes receivable, customer deposits and short-term borrowings is a reasonable estimate of fair value due to their liquid or short-term nature. Our long-term borrowings are recorded at historical amounts.
The following method and assumptions were used to estimate the fair value of each class of financial instruments.
Long-term Debt. The fair value of outstanding long-term debt is estimated based on the quoted market prices for the same or similar securities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. These fair value measurements are classified within Level 2 of the fair value hierarchy. As of March 31, 2023, there was no change in the method or significant assumptions used to estimate the fair value of long-term debt.
The carrying amount and estimated fair values of these financial instruments were as follows:
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
10. Income Taxes
Our interim effective tax rates reflect the estimated annual effective tax rates for 2023 and 2022, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended March 31, 2023 and 2022 were 20.3% and 18.2%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% primarily due to increased amortization of excess deferred federal income tax liabilities, as specified in the TCJA, tax credits, state flow through, and other permanent book-to-tax differences. These adjustments have a relative impact on the effective tax rate proportionally to pretax income or loss.
The increase in the three month effective tax rate of 2.1% in 2023 compared to 2022 is primarily attributed to renewable partnership income, partially offset by increased amortization of excess deferred federal income tax liabilities, the Pennsylvania rate differential, and restricted stock unit excess benefit.
There were no material changes recorded in 2023 to our uncertain tax positions recorded as of December 31, 2022.
11. Pension and Other Postemployment Benefits
We provide defined contribution plans and noncontributory defined benefit retirement plans that cover certain of our employees. Benefits under the defined benefit retirement plans reflect the employees' compensation, years of service and age at retirement. Additionally, we provide health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for us. The expected cost of such benefits is accrued during the employees' years of service. We determined that, for certain rate-regulated subsidiaries, the future recovery of postretirement benefit costs is probable, and we record regulatory assets and liabilities for amounts that would otherwise have been recorded to expense or accumulated other comprehensive loss. Current rates of rate-regulated companies include postretirement benefit costs, including amortization of the regulatory assets and liabilities that arose prior to inclusion of these costs in rates. For most plans, cash contributions are remitted to grantor trusts.
For the three months ended March 31, 2023, we contributed $1.2 million to our pension plans and $5.6 million to our OPEB plans.
The following table provides the components of the plans' actuarially determined net periodic benefit cost for the three months ended March 31, 2023 and 2022:
Pension Benefits
OPEB
Three Months Ended March 31, (in millions)
2023
2022
2023
2022
Components of Net Periodic Benefit (Income) Cost(1)
Service cost
$
5.1
$
7.1
$
1.3
$
1.6
Interest cost
17.1
9.4
5.4
3.0
Expected return on assets
(23.6)
(22.9)
(3.8)
(4.0)
Amortization of prior service credit
—
—
(0.5)
(0.6)
Recognized actuarial loss
8.4
4.5
0.8
0.7
Total Net Periodic Benefit (Income) Cost
$
7.0
$
(1.9)
$
3.2
$
0.7
(1)The service cost component and all non-service cost components of net periodic benefit (income) cost are presented in "Operation and maintenance" and "Other, net," respectively, on the Condensed Statements of Consolidated Income (unaudited).
12. Variable Interest Entities
A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. NIPSCO owns and operates two wind facilities, Rosewater and Indiana Crossroads Wind, which have 102 MW and 302 MW of nameplate capacity, respectively. NIPSCO also owns one solar facility, Indiana Crossroads Solar, which is expected to go into service in 2023 with 200 MW of nameplate capacity. We control decisions that are significant to these entities' ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary and have consolidated all three entities.
Members of the respective JVs are NIPSCO (who is the managing member) and tax equity partners. Earnings, tax attributes and cash flows are allocated to both NIPSCO and the tax equity partner in varying percentages by category and over the life of the partnership. NIPSCO and each tax equity partner contributed cash, and NIPSCO also assumed an obligation to the developers
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
of the wind facilities representing the remaining economic interest. The developers of the wind facilities are not a partner in the JV for federal income tax purposes and do not receive any share of earnings, tax attributes, or cash flows of each JV. Once the tax equity partner has earned their negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partner the remaining interest in the respective JV. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by our in-service JVs.
We did not provide any financial or other support during the quarter that was not previously contractually required, nor do we expect to provide such support in the future.
Our Condensed Consolidated Balance Sheets (unaudited) included the following assets and liabilities associated with VIEs.
(in millions)
March 31, 2023
December 31, 2022
Net Property, Plant and Equipment
$
972.7
$
978.5
Current assets
33.8
25.7
Total assets(1)
1,006.5
1,004.2
Current liabilities
135.4
128.2
Asset retirement obligations
30.7
30.6
Total liabilities
$
166.1
$
158.8
(1)The assets of each VIE represent assets of a consolidated VIE that can be used only to settle obligations of the respective consolidated VIE. The creditors of the liabilities of the VIEs do not have recourse to the general credit of the primary beneficiary.
13. Long-Term Debt
On March 24, 2023, we completed the issuance and sale of $750.0 million of 5.25% senior unsecured notes maturing in 2028, which resulted in approximately $742.2 million of net proceeds after discount and debt issuance costs.
14. Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, accounts receivable transfer programs, and term credit agreement. Each of these borrowing sources is described further below.
Revolving Credit Facility. We maintain a revolving credit facility to fund ongoing working capital requirements, including the provision of liquidity support for our commercial paper program, provide for issuance of letters of credit and also for general corporate purposes. Our revolving credit facility has a program limit of $1.85 billion and is comprised of a syndicate of banks.We had no outstanding borrowings under this facility as of March 31, 2023 and December 31, 2022.
Commercial Paper Program. Our commercial paper program has a program limit of up to $1.5 billion. We had zero and $415.0 million of commercial paper outstanding with weighted-average interest rates of zero and 4.60% as of March 31, 2023 and December 31, 2022, respectively.
Accounts Receivable Transfer Programs. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third-party financial institutions through wholly owned and consolidated special purpose entities. The three agreements expire between August 2023 and May 2024 and may be further extended if mutually agreed to by the parties thereto.
All receivables transferred to third parties are valued at face value, which approximates fair value due to their short-term nature. The amount of the undivided percentage ownership interest in the accounts receivables transferred is determined in part by required loss reserves under the agreements.
Transfers of accounts receivable are accounted for as secured borrowings resulting in the recognition of short-term borrowings on the Condensed Consolidated Balance Sheets (unaudited). As of March 31, 2023, the maximum amount of debt that could be borrowed related to our accounts receivable programs is $635.5 million.
We had $281.8 million and $347.2 million of short-term borrowings related to the securitization transactions as of March 31, 2023 and December 31, 2022, respectively.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
For the three months ended March 31, 2023 $65.4 million was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. For the three months ended March 31, 2022 $355.0 million was recorded as cash flows from financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.9 million and $0.3 million for the three months ended March 31, 2023 and 2022, respectively. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.
Term Credit Agreement. On December 20, 2022, we entered into a $1.0 billion term credit agreement with a syndicate of banks. The agreement matures on December 19, 2023 and interest charged on the borrowings depends on the variable rate structure elected at the time of each borrowing. The available variable rate structures from which we can choose are defined in the agreement. Under the agreement, we borrowed $1.0 billion on December 20, 2022 with an interest rate of SOFR plus 105 basis points. We had $1.0 billion outstanding with interest rates of 5.81% and 5.37% as of March 31, 2023 and December 31, 2022, respectively.
Items listed above, excluding the term credit agreement, are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.
15. Other Commitments and Contingencies
A. Guarantees and Indemnities. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. As of March 31, 2023 and December 31, 2022, we had issued stand-by letters of credit of $10.2 million for the benefit of third parties.
We provide guarantees related to our future performance under BTAs for our renewable generation projects. At March 31, 2023 and December 31, 2022, our guarantees for multiple BTAs totaled $841.6 million. As of April 2023, the amount of the guarantees increased to $938.9 million in accordance with the Fairbanks BTA. The amount of each guaranty will fluctuate upon the completion of the various steps outlined in each BTA. See ''- D. Other Matters - Generation Transition,'' below for more information.
B. Legal Proceedings.
Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim, proceeding or investigation would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more matters were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods that we would be required to pay such liability.
Private Actions. On September 13, 2018, a series of fires and explosions occurred in Lawrence, Andover, and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the "Greater Lawrence Incident"). There continue to be asserted wrongful death and bodily injury claims as it relates to the Greater Lawrence Incident. We continue to discuss potential settlements with remaining claimants. The outcomes and impacts of such private actions are uncertain at this time.
FERC Investigation. In April 2022, NIPSCO was notified that the FERC Office of Enforcement (“OE”) is conducting an investigation of an industrial customer for allegedly manipulating the MISO Demand Response (“DR”) market. The customer and NIPSCO are cooperating with the investigation. If the OE ultimately were to seek to require the customer to repay any portion of the DR revenue received from MISO, it is reasonably possible that the OE would also seek to require NIPSCO to disgorge administrative fees and foregone margin charges that NIPSCO collected pursuant to its own IURC-approved tariff. NIPSCO currently estimates the maximum amount of its disgorgement exposure to be $9.7 million, and the investigation is still ongoing. NIPSCO intends to seek indemnification under its agreements with the customer for any liability NIPSCO incurs related to this matter.
Other Legal Proceedings.We are also party to other claims, regulatory and legal proceedings arising in the ordinary course of business in each state in which we have operations, none of which we believe to be individually material at this time.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
C. Environmental Matters. Our operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and solid waste. We believe that we are in substantial compliance with the environmental regulations currently applicable to our operations.
It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred. Management expects a majority of environmental assessment and remediation costs and asset retirement costs, further described below, to be recoverable through rates.
As of March 31, 2023 and December 31, 2022, we had recorded a liability of $84.3 million and $86.5 million, respectively, to cover environmental remediation at various sites. This liability is included in "Other accruals" and "Other noncurrent liabilities" in the Condensed Consolidated Balance Sheets (unaudited). We recognize costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated. The original estimates for remediation activities may differ materially from the amount ultimately expended. The actual future expenditures depend on many factors, including laws and regulations, the nature and extent of impact and the method of remediation. These expenditures are not currently estimable at some sites. We periodically adjust our liability as information is collected and estimates become more refined.
CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under CERCLA and similar state laws. Under CERCLA, each potentially responsible party can be held jointly, severally and strictly liable for the remediation costs as the EPA, or state, can allow the parties to pay for remedial action or perform remedial action themselves and request reimbursement from the potentially responsible parties. Our affiliates have retained CERCLA environmental liabilities, including remediation liabilities, associated with certain current and former operations. At this time, we cannot estimate the full cost of remediating properties that have not yet been investigated, but it is possible that the future costs could be material to the Condensed Consolidated Financial Statements (unaudited).
MGP. We maintain a program to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 53 such sites where liability is probable. Remedial actions at many of these sites are being overseen by state or federal environmental agencies through consent agreements or voluntary remediation agreements.
We utilize a probabilistic model to estimate our future remediation costs related to MGP sites. The model was prepared with the assistance of a third party and incorporates our experience and general industry experience with remediating MGP sites. We complete an annual refresh of the model in the second quarter of each fiscal year. No material changes to the estimated future remediation costs were noted as a result of the refresh completed as of June 30, 2022. Our total estimated liability related to the facilities subject to remediation was $79.3 million and $81.0 million at March 31, 2023 and December 31, 2022, respectively. The liability represents our best estimate of the probable cost to remediate the MGP sites. Our model indicates that it is reasonably possible that remediation costs could vary by as much as $17 million in addition to the costs noted above. Remediation costs are estimated based on the best available information, applicable remediation standards at the balance sheet date and experience with similar facilities.
CCRs. NIPSCO continues to meet the compliance requirements established in the EPA's final rule for the regulation of CCRs. The CCR rule also resulted in revisions to previously recorded legal obligations associated with the retirement of certain NIPSCO facilities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased asset retirement obligation due to the uncertainty about the requirements that will be established by environmental authorities, compliance strategies that will be used and the preliminary nature of available data used to estimate costs. As allowed by the rule, NIPSCO will continue to collect data over time to determine the specific compliance solutions and associated costs and, as a result, the actual costs may vary.
D. Other Matters.
Generation Transition.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. NIPSCO's purchase obligation under each respective BTA is dependent on satisfactory approval of the BTA by the IURC, successful execution by NIPSCO of an agreement with a tax equity partner and timely completion of construction. NIPSCO has received IURC approval for all of its BTAs and PPAs. NIPSCO and the tax equity partner, for each respective BTA, are obligated to make cash contributions to the
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
JV that acquires the project at the date construction is substantially complete. Certain agreements require NIPSCO to make partial payments upon the developer's completion of significant construction milestones. Once the tax equity partner has earned its negotiated rate of return and we have reached the agreed upon contractual date, NIPSCO has the option to purchase at fair market value the remaining interest in the JV from the tax equity partner.
16. Accumulated Other Comprehensive Loss
The following tables display the components of Accumulated Other Comprehensive Loss, net of tax:
(in millions)
Gains and Losses on Securities(1)
Gains and Losses on Cash Flow Hedges(1)
Pension and OPEB Items(1)
Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2023
$
(11.2)
$
(12.6)
$
(13.3)
$
(37.1)
Other comprehensive income before reclassifications
1.7
—
—
1.7
Amounts reclassified from accumulated other comprehensive loss
0.3
0.1
0.3
0.7
Net current-period other comprehensive income
2.0
0.1
0.3
2.4
Balance as of March 31, 2023
$
(9.2)
$
(12.5)
$
(13.0)
$
(34.7)
(1)All amounts are net of tax. Amounts in parentheses indicate debits.
(in millions)
Gains and Losses on Securities(1)
Gains and Losses on Cash Flow Hedges(1)
Pension and OPEB Items(1)
Accumulated Other Comprehensive Loss(1)
Balance as of January 1, 2022
$
2.1
$
(122.5)
$
(6.4)
$
(126.8)
Other comprehensive income (loss) before reclassifications
(5.9)
47.0
—
41.1
Amounts reclassified from accumulated other comprehensive loss
0.2
—
0.1
0.3
Net current-period other comprehensive income (loss)
(5.7)
47.0
0.1
41.4
Balance as of March 31, 2022
$
(3.6)
$
(75.5)
$
(6.3)
$
(85.4)
(1)All amounts are net of tax. Amounts in parentheses indicate debits.
17. Other, Net
The following table displays the components of Other, Net included on the Condensed Statements of Consolidated Income (unaudited):
Three Months Ended March 31,
(in millions)
2023
2022
Interest income
$
1.8
$
0.9
AFUDC equity
4.8
3.0
Pension and other postretirement non-service benefit (cost)
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
18. Business Segment Information
Our operations are divided into two primary reportable segments, the Gas Distribution Operations and the Electric Operations segments. 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" and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities. Refer to Note 3, "Revenue Recognition," for additional information on our segments and their sources of revenues. The following table provides information about our reportable segments. We use operating income as our primary measurement for each of the reported segments and make decisions on finance, dividends, and taxes at the corporate level on a consolidated basis. Segment revenues include intersegment sales to affiliated subsidiaries, which are eliminated in consolidation. Affiliated sales are recognized on the basis of prevailing market, regulated prices or at levels provided for under contractual agreements. Operating income is derived from revenues and expenses directly associated with each segment.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
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" at the beginning of this report for a list of factors that may cause results to differ materially.
Management's Discussion is designed to provide an understanding of our operations and financial performance and should be read in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
We are an energy holding company under the Public Utility Holding Company Act of 2005 whose utility 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 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 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. Serving as a guiding practice for our SMS, NiSource is certified in conformance to the American Petroleum Institute Recommended Practice 1173. 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.
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 March 31, 2023, 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. We continue to make significant progress on our first two solar BTAs and anticipate completion of these projects and tax equity financing by June 2023. We have also taken contractual actions on a number of our other renewable projects to address the timing of these projects as well as consider the broad market issues facing the industry. We remain on track to retire R.M Schahfer's remaining two coal units by the end of 2025. On January 1, 2023, the provisions of the 2022 IRA became effective. 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. We will analyze opportunities to leverage the IRA on a project-by-project basis in consideration of several factors, both quantitative and qualitative, to enable project success and ensure value for the customer and company. 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Transformation: Our Enterprise-wide Transformation Roadmap focuses on operational excellence, safety, operation and maintenance management, and unlocking efficiencies. We have formally launched several initiatives that will enable us to streamline work and improve logistics company-wide. These efforts will include investments in proven technologies backed with standardized processes that will change the way we plan, schedule, and execute work in the field and how we engage and provide service to our customers. Taken together, all the initiatives under the Enterprise-wide Transformation Roadmap will prioritize safety and continue to optimize our long-term growth profile.
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 continue to see 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. Additionally, 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."
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.
There has been volatility in the market price of natural gas costs which influences customer bills. For the first three quarters of 2022, gas prices increased. Prices began to decrease in November of 2022 and have continued to decrease during the first quarter of 2023. Changes in gas prices do not 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 the first quarter of 2023 compared to the first quarter of 2022 associated with short-term borrowings. We continue to evaluate our financing plan to manage interest expense and exposure to rates. For more information on interest rate risk, see "Market Risk Disclosures".
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Summary of Consolidated Financial Results
A summary of our consolidated financial results for the three months ended March 31, 2023 and 2022 are presented below:
Three Months Ended March 31,
(in millions, except per share amounts)
2023
2022
Favorable (Unfavorable)
Operating Revenues
$
1,966.0
$
1,873.3
$
92.7
Operating Expenses
Cost of energy
765.1
706.7
(58.4)
Other Operating Expenses
669.9
566.3
(103.6)
Total Operating Expenses
1,435.0
1,273.0
(162.0)
Operating Income
531.0
600.3
(69.3)
Total Other Deductions, Net
(107.4)
(72.8)
(34.6)
Income Taxes
85.8
96.2
10.4
Net Income
337.8
431.3
(93.5)
Net income attributable to noncontrolling interest
4.8
4.5
(0.3)
Net Income Attributable to NiSource
333.0
426.8
(93.8)
Preferred dividends
(13.8)
(13.8)
—
Net Income Available to Common Shareholders
319.2
413.0
(93.8)
Earnings Per Share
Basic Earnings Per Share
$
0.77
$
1.02
$
(0.25)
Diluted Earnings Per Share
$
0.71
$
0.94
$
(0.23)
The majority of the cost of energy in both segments are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in operating revenues.
The decrease in net income available to common shareholders during the three months ended March 31, 2023 was primarily due to an insurance settlement related to the Greater Lawrence Incident received in 2022, decreased revenue related to weather and increased other deductions, partially offset by higher revenues from outcomes of gas base rate proceedings and regulatory capital programs.
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 for the three months ended March 31, 2023 compared to the same period in 2022 is primarily driven by higher long-term and short-term debt interest in 2023 and higher non-service pension costs. See Note 13, "Long-Term Debt," Note 14, "Short-Term Borrowings," and Note 11, "Pension and Other Postemployment Benefits," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information.
Income Taxes
Refer to Note 10, "Income Taxes," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on income taxes and the change in the effective tax rate.
Changes in tax laws, as well as the potential tax effects of business decisions, could negatively impact our business, results of operations (including our expected project returns from our planned renewable energy projects), financial condition and cash flows. We continue to monitor the implementation of any final and proposed tax legislation and regulations related to the IRA which introduces a new corporation minimum tax, excise tax on stock buy-backs, and an extension of a technology neutral investment tax credit and production tax credit regime beginning in 2023.
On April 14, 2023, the IRS issued Revenue Procedure 2023-15 which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve linear property and non-linear natural gas transmission and distribution property must be capitalized as improvements or are allowable as deductions. We are analyzing the provisions of the safe harbor method of accounting which we expect to adopt.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
RESULTS AND DISCUSSION OF SEGMENT OPERATIONS
Presentation of Segment Information
Our operations are divided into two primary reportable segments, the Gas Distribution Operations and the Electric Operations segments. 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 Condensed Consolidated Financial Statements (unaudited) and primarily are comprised of interest expense on holding company debt, and unallocated corporate costs and activities.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Gas Distribution Operations
Financial and operational data for the Gas Distribution Operations segment for the three months ended March 31, 2023 and 2022 are presented below.
Three Months Ended March 31,
(in millions)
2023
2022
Favorable (Unfavorable)
Operating Revenues
$
1,504.4
$
1,439.8
$
64.6
Operating Expenses
Cost of energy
602.7
589.1
(13.6)
Operation and maintenance
285.7
277.3
(8.4)
Depreciation and amortization
110.1
100.7
(9.4)
Gain on sale of fixed assets and impairments, net
—
(105.0)
(105.0)
Other taxes
59.0
66.9
7.9
Total Operating Expenses
1,057.5
929.0
(128.5)
Operating Income
$
446.9
$
510.8
$
(63.9)
Revenues
Residential
$
1,025.3
$
977.6
$
47.7
Commercial
365.9
357.5
8.4
Industrial
72.0
68.1
3.9
Off-System
17.2
18.7
(1.5)
Other
24.0
17.9
6.1
Total
$
1,504.4
$
1,439.8
$
64.6
Sales and Transportation (MMDth)
Residential
103.6
122.9
(19.3)
Commercial
68.4
79.9
(11.5)
Industrial
132.6
135.1
(2.5)
Off-System
7.4
4.3
3.1
Other
0.2
0.2
—
Total
312.2
342.4
(30.2)
Heating Degree Days
2,339
2,841
(502)
Normal Heating Degree Days
2,824
2,824
—
% Colder (Warmer) than Normal
(17)
%
1
%
% Warmer than prior year
(18)
%
Gas Distribution Customers
Residential
3,003,277
2,980,965
22,312
Commercial
255,384
254,876
508
Industrial
4,934
4,920
14
Other
3
3
—
Total
3,263,598
3,240,764
22,834
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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Gas Distribution Operations
The underlying reasons for changes in our operating revenues for the three months ended March 31, 2023 compared to the same period in 2022 are presented below.
Favorable (Unfavorable)
Changes in Operating Revenues (in millions)
Three Months Ended March 31, 2023 vs 2022
New rates from base rate proceedings and regulatory capital programs
$
82.6
Increased customer usage
3.7
The effects of customer growth
1.2
The effects of weather in 2023 compared to 2022
(33.3)
Reduction in gross receipts tax, offset in operating expenses
(6.3)
Other
5.2
Change in operating revenues (before cost of energy and other tracked items)
$
53.1
Operating revenues offset in operating expense
Higher cost of energy billed to customers
13.6
Lower tracker deferrals within operation and maintenance, depreciation, and tax
(2.1)
Total change in operating revenues
$
64.6
Weather
In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating degree days, net of weather normalization mechanisms. Our composite heating degree days reported do not directly correlate to the weather-related dollar impact on the results of Gas Distribution Operations. Heating degree days experienced during different times of the year or in different operating locations may have more or less impact on volume and dollars depending on when and where they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite heating degree day comparison.
Throughput
The decrease in total volumes for the three months ended March 31, 2023, compared to the same period in 2022, is primarily attributable to the effects of warmer 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 Condensed Consolidated Balance Sheets (unaudited) 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Gas Distribution Operations
The underlying reasons for changes in our operating expenses for the three months ended March 31, 2023 compared to the same period in 2022 are presented below.
Favorable (Unfavorable)
Changes in Operating Expenses (in millions)
Three Months Ended March 31, 2023 vs 2022
Reduction in gross receipts tax, offset in operating revenues
$
6.3
Lower employee and administrative related expenses
4.1
Property insurance settlement related to the Greater Lawrence Incident received in 2022
(105.0)
Higher depreciation and amortization expense
(9.8)
Higher other than income taxes primarily due to property tax
(2.6)
Impacts from Columbia of Ohio's rate case settlement
(2.6)
Higher expenses related to uncollectible customer accounts
(1.8)
Higher outside services expenses
(1.3)
Other
(4.3)
Change in operating expenses (before cost of energy and other tracked items)
$
(117.0)
Operating expenses offset in operating revenue
Higher cost of energy billed to customers
(13.6)
Lower tracker deferrals within operation and maintenance, depreciation, and tax
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
Financial and operational data for the Electric Operations segment for the three months ended March 31, 2023 and 2022 are presented below.
Three Months Ended March 31,
(in millions)
2023
2022
Favorable (Unfavorable)
Operating Revenues
$
464.7
$
430.3
$
34.4
Operating Expenses
Cost of energy
162.4
117.6
(44.8)
Operation and maintenance
125.3
116.6
(8.7)
Depreciation and amortization
85.9
82.9
(3.0)
Other taxes
9.2
14.0
4.8
Total Operating Expenses
382.8
331.1
(51.7)
Operating Income
$
81.9
$
99.2
$
(17.3)
Revenues
Residential
$
150.4
$
138.5
$
11.9
Commercial
150.9
134.5
16.4
Industrial
134.4
130.0
4.4
Wholesale
2.6
2.6
—
Other
26.4
24.7
1.7
Total
$
464.7
$
430.3
$
34.4
Sales (GWh)
Residential
766.1
819.2
(53.1)
Commercial
856.2
885.3
(29.1)
Industrial
1,937.7
2,007.8
(70.1)
Wholesale
—
4.4
(4.4)
Other
22.8
25.1
(2.3)
Total
3,582.8
3,741.8
(159.0)
Electric Customers
Residential
425,090
423,177
1,913
Commercial
58,499
58,092
407
Industrial
2,133
2,135
(2)
Wholesale
708
712
(4)
Other
3
2
1
Total
486,433
484,118
2,315
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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
The underlying reasons for changes in our operating revenues for the three months ended March 31, 2023 compared to the same period in 2022 are presented below.
Favorable (Unfavorable)
Changes in Operating Revenues (in millions)
Three Months Ended March 31, 2023 vs 2022
New rates from regulatory capital and DSM programs
$
4.0
PPA revenue from renewable JV projects, fully offset by JV operating expenses and noncontrolling interest net income (loss)
0.6
Decreased customer usage
(8.3)
Reduction in gross receipts tax, offset in operating expenses
(5.9)
The effects of weather in 2023 compared to 2022
(2.0)
Other
(1.7)
Change in operating revenues (before cost of energy and other tracked items)
$
(13.3)
Operating revenues offset in operating expense
Higher cost of energy billed to customers
44.8
Higher tracker deferrals within operation and maintenance, depreciation and tax
2.9
Total change in operating revenues
$
34.4
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
The decrease in total volumes sold for the three months ended March 31, 2023 compared to the same period in 2022 was primarily attributable to decreased usage by industrial and residential customers.
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 Condensed Consolidated Balance Sheets (unaudited) 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
The underlying reasons for changes in our operating expenses for the three months ended March 31, 2023 compared to the same period in 2022 are presented below.
Favorable (Unfavorable)
Changes in Operating Expenses (in millions)
Three Months Ended March 31, 2023 vs 2022
Higher outside services expenses primarily related to higher generation-related maintenance
$
(7.0)
Renewable JV project expenses, offset by JV operating revenues
(1.2)
Reduction in gross receipts tax, offset in operating revenues
5.9
Lower employee and administrative expenses
3.3
Other
(5.0)
Change in operating expenses (before cost of energy and other tracked items)
$
(4.0)
Operating expenses offset in operating revenue
Higher cost of energy billed to customers
(44.8)
Higher tracker deferrals within operation and maintenance, depreciation and tax
(2.9)
Total change in operating expense
$
(51.7)
Electric Supply and Generation Transition
NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan and 2021 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. NIPSCO is evaluating 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
Project Name
Transaction Type
Technology
Nameplate Capacity (MW)
Storage Capacity (MW)
Dunn's Bridge I(1)
BTA
Solar
265
—
Indiana Crossroads(1)
BTA
Solar
200
—
Dunn's Bridge II(1)
BTA
Solar & Storage
435
75
Cavalry(1)
BTA
Solar & Storage
200
60
Fairbanks(1)
BTA
Solar
250
—
Elliott(1)
BTA
Solar
200
—
Indiana Crossroads II
15 year PPA
Wind
204
—
Brickyard
20 year PPA
Solar
200
—
Greensboro
20 year PPA
Solar & Storage
100
30
Gibson
22 year PPA
Solar
280
—
Green River
20 year PPA
Solar
200
—
(1)Ownership of the facility 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 our other renewable projects as upcoming project milestones related to permitting and obtaining interconnection rights are expected to occur. 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Liquidity and Capital Resources
We continually evaluate the availability of adequate financing to fund our ongoing business operations, working capital and core safety and infrastructure investment programs. Our financing is sourced through cash flow from operations and the issuance of debt and/or equity. External debt financing is provided primarily through the issuance of long-term debt, accounts receivable securitization programs and our $1.5 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 March 24, 2023, we completed the issuance and sale of $750.0 million of 5.25% senior unsecured notes maturing in 2028, which resulted in approximately $742.2 million of net proceeds after discount and debt issuance costs. On November 7, 2022, we announced that we intend to pursue the sale of a minority interest in our NIPSCO business unit. We maintain an ATM equity program that provides an opportunity to issue and sell shares of our common stock up to an aggregate issuance of $750.0 million through December 31, 2023. As of March 31, 2023, 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 5, "Equity," in the Notes to the Condensed Consolidated Financial Statements (unaudited) 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.
The following table summarizes our cash flow activities:
Three Months Ended March 31,
(in millions)
2023
2022
Change in 2023 vs 2022
Cash from (used for):
Operating Activities
$
683.4
$
579.8
$
103.6
Investing Activities
(727.8)
(370.4)
(357.4)
Financing Activities
117.3
(173.9)
291.2
Operating Activities
The increase in cash from operating activities was primarily driven by year over year change in accounts receivable collections and decreased cash outflows related to inventory balances due to lower gas costs. This was partially offset by increased purchases from gas suppliers, driven by lower gas costs.
Investing Activities
Our current year investing activities were comprised of increased capital expenditures related to system growth and reliability, payments to renewable generation asset developers related to Dunn's Bridge II and Cavalry Solar milestone payments, as well as the property insurance settlement related to the Greater Lawrence Incident received in the prior year.
As we evaluate adjustments to renewable generation project timing, we remain on track to make capital investments totaling $3.3 billion to $3.6 billion during the 2023 period. We also expect to invest approximately $15.0 billion during the 2023-2027 period, including capital investments to support our generation transition strategy. These forecasted capital investments and those included in our Annual Report on Form 10-K for the year ended December 31, 2022, are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates. For additional information, see "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory Capital Programs. We replace pipe and modernize our gas infrastructure to enhance safety and reliability by reducing leaks. An ancillary benefit of these programs is the reduction of GHG emissions. In 2023, we continue 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.
The following table describes the most recent vintage of our regulatory programs to recover infrastructure replacement as well as other federally mandated compliance investments currently in rates or pending commission approval:
(in millions)
Company
Program
Incremental Revenue
Incremental Capital Investment
Investment Period
Costs Covered(1)
Rates Effective
Columbia of Ohio
IRP - 2023
$
38.4
$
316.3
1/22-12/22
Replacement of (1) hazardous service lines, (2) cast iron, wrought iron, uncoated steel, and bare steel pipe.
May 2023
Columbia of Ohio
CEP - 2023
$
31.0
$
265.6
1/22-12/22
Assets not included in the IRP.
September 2023
NIPSCO - Gas(2)
TDSIC 4
$
3.1
$
77.5
7/21-12/21
New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.
July 2022
NIPSCO - Gas
TDSIC 6
$
(2.5)
$
149.8
1/22-2/23
New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.
September 2023
NIPSCO - Gas(2)(3)
FMCA 1
$
1.5
$
14.1
10/21-3/22
Project costs to comply with federal mandates.
October 2022
NIPSCO - Gas(2)(3)
FMCA 2
$
4.2
$
38.2
4/22-9/22
Project costs to comply with federal mandates.
April 2023
Columbia of Virginia(4)
SAVE - 2023
$
4.5
$
45.9
1/23-12/23
Replacement projects that (1) enhance system safety or reliability, or (2) reduce, or potentially reduce, greenhouse gas emissions.
January 2023
Columbia of Kentucky
SMRP - 2023
$
1.6
$
41.6
1/23-12/23
Replacement of mains and inclusion of system safety investments.
January 2023
Columbia of Maryland
STRIDE - 2023
$
1.3
$
18.0
1/23-12/23
Pipeline upgrades designed to improve public safety or infrastructure reliability.
January 2023
NIPSCO - Electric
TDSIC - 1
$
10.4
$
148.5
6/21-1/22
New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.
August 2022
NIPSCO - Electric
TDSIC - 2
$
6.6
$
143.5
2/22-7/22
New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.
February 2023
NIPSCO - Electric(5)
TDSIC - 3
$
45.6
$
130.2
8/22-1/23
New or replacement projects undertaken for the purpose of safety, reliability, system modernization or economic development.
August 2023
(1)Programs do not include any costs already included in base rates.
(2)On March 1, 2023, incremental tracker revenue was updated as certain investments are now being recovered through base rates.
(3)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.
(4)Columbia of Virginia received a final order on November 1, 2022 modifying the SAVE filing incremental revenue and investments.
(5)NIPSCO Electric TDSIC-3 is for a 14-month billing period in anticipation of a rate case order in August 2023 and a subsequent 9 month hold-out period.
On March 30, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of Michigan City Generating Station's CCR ash ponds. The project includes a total estimated $40.0 million of federally mandated retirement costs. On November 2, 2022, NIPSCO Electric filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for closure of R.M. Schahfer Generation Station's multi-cell unit. The project includes a total estimated $53.0 million of federally mandated retirement costs. Due to the Settlement filed on March 10, 2023, both FMCA cases have been stayed pending the outcome of NIPSCO’s electric base rate case, which proposes these pond closure costs be recovered through base rates, rather than the FMCA Tracker. Refer to Note 15, "Other Commitments and Contingencies - C. Environmental Matters," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for further discussion of the CCRs.
Columbia of Ohio filed an application on February 28, 2023, to establish a new PHMSA IRP Rider in order to recover costs incurred to comply with the PHMSA regulations. As proposed, the rider would provide for cost deferrals and carrying costs during the investment period, with rates effective in May 2024. It is anticipated that the PUCO will rule on this application in 2023.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Financing Activities
Common Stock, Preferred Stock and Equity Units. Refer to Note 5, "Equity," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on common and preferred stock and equity units activity.
Long-Term Debt. Refer to Note 13, "Long-Term Debt," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on long-term debt activity.
Short-Term Debt. Refer to Note 14, "Short-Term Borrowings," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on short-term debt activity.
Noncontrolling Interest. Refer to Note 12, "Variable Interest Entities," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on contributions from noncontrolling interest activity.
Sources of Liquidity
The following table displays our liquidity position as of March 31, 2023 and December 31, 2022:
(in millions)
March 31, 2023
December 31, 2022
Current Liquidity
Revolving Credit Facility
$
1,850.0
$
1,850.0
Accounts Receivable Programs(1)
635.5
447.2
Less:
Commercial Paper
—
415.0
Accounts Receivable Programs Utilized
281.8
347.2
Letters of Credit Outstanding Under Credit Facility
10.2
10.2
Add:
Cash and Cash Equivalents
106.4
40.8
Net Available Liquidity
$
2,299.9
$
1,565.6
(1)Represents the lesser of the seasonal limit or maximum borrowings supportable by the underlying receivables.
Debt Covenants. We are subject to financial covenants under our revolving credit facility, which require us to maintain a debt to capitalization ratio that does not exceed 70.0%. As of March 31, 2023, the ratio was 59.1%.
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 March 31, 2023. There were no changes to the below 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.
S&P
Moody's
Fitch
Rating
Outlook
Rating
Outlook
Rating
Outlook
NiSource
BBB+
Stable
Baa2
Stable
BBB
Stable
NIPSCO
BBB+
Stable
Baa1
Stable
BBB
Stable
Commercial Paper
A-2
Stable
P-2
Stable
F2
Stable
Certain of our subsidiaries have agreements that contain ''ratings triggers'' that require increased collateral if our credit rating 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 March 31, 2023, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $80.8 million. 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
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 March 31, 2023, 412,982,639 shares of common stock and 1,302,500 shares of preferred stock were outstanding.
Contractual Obligations. A summary of contractual obligations is included in the Company's Annual Report on Form 10-K for the year ended December 31, 2022. Except for our March 2023 debt issuance, there were no additional material changes from year-end during the three months ended March 31, 2023. Refer to Note 13, "Long-Term Debt,"in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information regarding the debt issuance.
Guarantees, Indemnities and Other Off Balance Sheet Arrangements. We and certain of our subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries as a part of normal business. Such agreements include guarantees and stand-by letters of credit. Refer to Note 15, "Other Commitments and Contingencies," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information about such arrangements.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
Cost Recovery and Trackers
Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are subject to approved regulatory tracker mechanisms generally lead to increased regulatory assets, which ultimately result in a corresponding increase in operating revenues and, therefore, have essentially no impact on total operating income results. Certain approved regulatory tracker mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to quickly implement revised rates and recover associated costs.
A portion of the Gas Distribution Operations revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to confirm the recovery of prudently incurred energy commodity costs supplied to customers.
We recognize that energy efficiency reduces emissions, conserves natural resources and saves our customers money. Our gas distribution companies offer programs such as energy efficiency upgrades, home checkups and weatherization services. The increased efficiency of natural gas appliances and improvements in home building codes and standards contributes to a long-term trend of declining average use per customer. While we are looking to expand offerings so the energy efficiency programs can benefit as many customers as possible, our Gas Distribution Operations have pursued changes in rate design to more effectively match recoveries with costs incurred. Columbia of Ohio has adopted a straight fixed variable rate design that closely links the recovery of fixed costs with fixed charges. Columbia of Maryland and Columbia of Virginia have regulatory approval for weather and revenue normalization adjustments for certain customer classes, which adjust monthly revenues that exceed or fall short of approved levels. Columbia of Pennsylvania continues to operate its pilot residential weather normalization adjustment and also has a fixed customer charge. This weather normalization adjustment only adjusts revenues when actual weather compared to normal varies by more than 3%. Columbia of Kentucky incorporates a weather normalization adjustment for certain customer classes and also has a fixed customer charge. In a prior gas base rate proceeding, NIPSCO implemented a higher fixed customer charge for residential and small customer classes moving toward recovering more of its fixed costs through a fixed recovery charge, but has no weather or usage protection mechanism.
A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, which is updated quarterly to reflect actual costs incurred to supply electricity to customers.
While increased efficiency of electric appliances and improvements in home building codes and standards has similarly impacted the average use per electric customer in recent years, NIPSCO expects future growth in per customer usage as a result of increasing electric applications. Further growth is anticipated as electric vehicles become more prevalent. These ongoing changes in use of electricity will likely lead to development of innovative rate designs, and NIPSCO will continue efforts to design rates that increase the certainty of recovery of fixed costs.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
Rate Case Actions
The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:
(in millions)
Company
Proposed ROE
Approved ROE
Requested Incremental Revenue
Approved Incremental Revenue
Filed
Status
Rates Effective
Currently Approved in Current or Future Rates
Columbia of Pennsylvania(1)
10.95
%
None specified
$
82.2
$
44.5
March 18, 2022
Approved December 8, 2022
December 2022
Columbia of Maryland
10.85
%
9.65
%
$
5.8
$
3.5
May 13, 2022
Approved November 17, 2022
December 2022
Columbia of Kentucky(2)
10.30
%
9.35
%
$
26.7
$
18.3
May 28, 2021
Approved December 28, 2021
January 2022
Columbia of Virginia(3)
10.95
%
None specified
$
14.2
$
1.3
August 28, 2018
Approved June 12, 2019
February 2019
Columbia of Ohio
10.95
%
9.60
%
$
221.4
$
68.3
June 30, 2021
Approved January 26, 2023
March 2023
NIPSCO - Gas(4)
10.50
%
9.85
%
$
109.7
$
71.8
September 29, 2021
Approved July 27, 2022
September 2022
NIPSCO - Electric
10.80
%
9.75
%
$
21.4
$
(53.5)
October 31, 2018
Approved December 4, 2019
January 2020
Active Rate Cases
Columbia of Virginia(5)
10.75
%
In process
$
40.6
In process
April 29, 2022
Order Expected Q2 2023
Interim Rates October 2022
NIPSCO - Electric(6)
10.40
%
In process
$
291.8
In process
September 19, 2022
Order Expected Q3 2023
September 2023
(1)No approved ROE is identified for this matter since the approved revenue increase is the result of a black box settlement under which parties agree upon the amount of increase.
(2)The approved ROE for natural gas capital riders (e.g.,SMRP) is 9.275%.
(3)Columbia of Virginia's rate case resulted in a black box settlement, representing a settlement to a specific revenue increase but not a specified ROE. The settlement provides use of a 9.70% ROE for future SAVE filings.
(4)New rates are implemented in 2 steps, with implementation of Step 1 rates in September 2022. The Step 2 rates were filed on February 21, 2023, with rates effective March 2023.
(5)Beginning October 2022, interim rates are being billed subject to refund, pending a final commission order. On December 9, 2022, a Stipulation and Proposed Recommendation was filed with the Virginia State Corporation Commission recommending approval of $25.8 million of incremental revenue.
(6) If the pending settlement is approved, new rates will be implemented in 2 steps, with implementation of Step 1 rates to be effective in September 2023 and Step 2 rates to be effective in March 2024. In addition to the requested incremental revenue of $291.8 million, an additional request was made for $103.2 million for costs associated with a new Variable Cost Tracker (VCT) bringing the total requested incremental revenue to $395.0 million. A settlement agreement was filed on March 10, 2023, with supporting testimony filed on March 17, 2023, reflecting incremental revenue of $261.9 million plus an additional $29.9 million for recovery of costs associated with a new Environmental Cost Tracker (replacing the VCT). The evidentiary hearing occurred in April 2023 with an anticipated final order August 2023.
PHMSA Regulations
On December 27, 2020, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020 was signed into law, reauthorizing funding for federal pipeline safety programs through September 30, 2023. Among other things, the PIPES Act requires that PHMSA revise the pipeline safety regulations to require operators to update, as needed, their existing distribution integrity management plans, emergency response plans, and operation and maintenance plans. The PIPES Act also requires PHMSA to adopt new requirements for managing records and updating, as necessary, existing district regulator stations to eliminate common modes of failure that can lead to overpressurization. PHMSA must also require that operators implement and utilize advanced leak detection and repair technologies that enable the location and categorization of all leaks that are hazardous, or potentially hazardous, to human safety or the environment. Natural gas companies, including NiSource and our subsidiaries, may see increased costs depending on how PHMSA implements the new mandates resulting from the PIPES Act.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
Climate Change Issues
Physical Climate Risks. Increased frequency of severe and extreme weather events associated with climate change could materially impact our facilities, energy sales, and results of operations. We are unable to predict these events. However, we perform ongoing assessments of physical risk, including physical climate risk, to our business. More extreme and volatile temperatures, increased storm intensity and flooding, and more volatile precipitation leading to changes in lake and river levels are among the weather events that are most likely to impact our business. Efforts to mitigate these physical risks continue to be implemented on an ongoing basis.
Transition Climate Risks. Future legislative and regulatory programs, at both the federal and state levels, could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Revised or additional future GHG legislation and/or regulation related to the generation of electricity or the extraction, production, distribution, transmission, storage and end use of natural gas could materially impact our gas supply, financial position, financial results and cash flows.
Regarding federal policies, we continue to monitor the implementation of any final and proposed climate change-related legislation and regulations, including the Infrastructure Investment and Jobs Act, signed into law in November 2021; the IRA, signed into law in August 2022; and the EPA's proposed methane regulations for the oil and natural gas industry, but we cannot predict their impact on our business at this time. We have identified potential opportunities associated with the Infrastructure Investment and Jobs Act and the IRA and are evaluating how they may align with our strategy going forward. The energy-related provisions of the Infrastructure Investment and Jobs Act include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional LIHEAP funding over the next five years. The IRA contains climate and energy provisions, including funding to decarbonize the electric sector.
In February 2021, the United States rejoined the Paris Agreement, an international treaty through which parties set nationally determined contributions to reduce GHG emissions, build resilience, and adapt to the impacts of climate change. Subsequently, the Biden Administration released a target for the United States to achieve a 50%-52% GHG reduction from 2005 levels by 2030, which supports the President's goals to create a carbon-free power sector by 2035 and net zero emissions economy no later than 2050. There are many pathways to reach these goals.
On June 30, 2022, the Supreme Court of the United States ruled for the petitioners in West Virginia v. EPA, which examined the authority of the EPA to regulate GHG emissions from the power sector. We will continue to evaluate this matter, but we remain committed to our previously stated carbon reduction goals.
We also continue to monitor the implementation of any final and proposed state policy. The Virginia Clean Economy Act was signed into law in 2020. While the Act does not establish any new mandates on Columbia of Virginia, certain natural gas customers may, over the long-term, reduce their use of natural gas to meet the 100% renewable electricity requirement. Columbia of Virginia will continue to monitor this matter, but we cannot predict its final impact on our business at this time. Separately, the Virginia Energy Innovation Act, enacted into law in April 2022, and effective July 1, 2022, allows natural gas utilities to supply alternative forms of gas that meet certain standards and reduce emissions intensity. The Act also provides that the costs of enhanced leak detection and repair may be added to a utility’s plan to identify proposed eligible infrastructure replacement projects and related cost recovery mechanisms, known as the SAVE Plan. Furthermore, under the Act, utilities can recover eligible biogas supply infrastructure costs on an ongoing basis. The provisions of these laws may provide opportunities for Columbia of Virginia as it participates in the transition to a lower carbon future.
The Climate Solutions Now Act of 2022 requires Maryland to reduce GHG emissions by 60% by 2031 (from 2006 levels), and it requires the state to reach net zero emissions by 2045. The Maryland Department of the Environment is required to adopt a plan to achieve the 2031 goal by December 2023, and it is required to adopt a plan for the net zero goal by 2030. The Act also enacts a state policy to move to broader electrification of both existing buildings and new construction, and requires the Public Service Commission to complete a study assessing the capacity of gas and electric distribution systems to successfully serve customers under a transition to a highly electrified building sector. Columbia of Maryland will continue to monitor this matter, but we cannot predict its final impact on our business at this time.
NIPSCO, Columbia of Maryland, Columbia of Pennsylvania, Columbia of Virginia and Columbia of Kentucky each filed petitions to implement the Green Path Rider, which will be a voluntary rider that allows customers to opt in and offset either 50% or 100% of their natural gas related emissions. To reduce the emissions, the utilities will purchase RNG attributes and carbon offsets to match the usage for customers opting into the program. The program was approved by the IURC at NIPSCO in November 2022 with a January 2023 start date. After reaching settlement with other parties in September 2022, NIPSCO
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
agreed to add a third tier to offset 25% of customer usage. Columbia of Maryland’s filing was denied by the PUC in January 2023. The filings for Columbia of Pennsylvania, Columbia of Virginia and Columbia of Kentucky are still being evaluated. Additionally, NIPSCO has a voluntary Green Power Rider program in place that allows customers to designate a portion or all their monthly electric usage to come from power generated by renewable energy sources.
Net-Zero Goal. In response to these transition risks and opportunities, on November 7, 2022, we announced a goal of net-zero greenhouse gas emissions by 2040 covering both Scope 1 and Scope 2 emissions ("Net-Zero Goal"). Our Net-Zero Goal builds on greenhouse gas emission reductions achieved to-date and demonstrates that continued execution of our long-term business plan will drive further greenhouse gas emission reductions. We remain on track to achieve previously announced interim greenhouse gas emission reduction targets by reducing fugitive methane emissions from main and service lines by 50 percent from 2005 levels by 2025 and reducing Scope 1 greenhouse gas emissions from company-wide operations by 90 percent from 2005 levels by 2030. We plan to achieve our Net-Zero Goal primarily through continuation and enhancement of existing programs, such as retiring and replacing coal-fired electric generation with low- or zero-emission electric generation, ongoing pipe replacement and modernization programs, and deployment of advanced leak-detection technologies. In addition, we plan to advance other low- or zero-emission energy resources and technologies, such as hydrogen, renewable natural gas, and/or deployment of carbon capture and utilization technologies, if and when these become technologically and economically feasible. Carbon offsets and renewable energy credits may also be used to support achievement of our Net-Zero Goal. As of the end of 2022, we had reduced Scope 1 GHG emissions by approximately 67% from 2005 levels.
Our greenhouse gas emissions projections, including achieving a Net-Zero Goal, are subject to various assumptions that involve risks and uncertainties. Achievement of our Net-Zero Goal by 2040 will require supportive regulatory and legislative policies, favorable stakeholder environments and advancement of technologies that are not currently economical to deploy. Should such regulatory and legislative policies, stakeholder environments or technologies fail to materialize, our actual results or ability to achieve our Net-Zero Goal, including by 2040, may differ materially.
As discussed above in this Management's Discussion within "Results and Discussion of Segment Operations - Electric Operations," NIPSCO continues to execute on an electric generation transition consistent with the preferred pathways identified in its 2018 and 2021 Integrated Resource Plans. Additionally, as discussed above in this Management's Discussion within "Liquidity and Capital Resources - Regulatory Capital Programs," our natural gas distribution companies are lowering methane emissions by replacing aging infrastructure, which also increases safety and reliability for customers and communities.
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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Our subsidiaries are required to make cash margin deposits with their brokers to cover actual and potential losses in the value of outstanding exchange traded derivative contracts. The amount of these deposits, some of which are reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.
Refer to Note 8, "Risk Management Activities," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for further information on our commodity price risk assets and liabilities as of March 31, 2023 and December 31, 2022.
Interest Rate Risk
We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our revolving credit agreement, commercial paper program, term credit 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 $4.5 million and $1.5 million for the three months ended March 31, 2023 and 2022, respectively. We are also exposed to interest rate risk as a result of changes in benchmark rates that can influence the interest rates of future long-term 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 8, "Risk Management Activities," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for further information on our interest rate risk assets and liabilities as of March 31, 2023 and December 31, 2022.
Credit Risk
Due to the nature of the industry, credit risk is embedded in many of our business activities. Our extension of credit is governed by a Corporate Credit Risk Policy. In addition, Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by the risk management function, which is independent of commercial operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. For derivative-related contracts, credit risk arises when counterparties are obligated to deliver or purchase defined commodity units of gas or power to us at a future date per execution of contractual terms and conditions. Exposure to credit risk is measured in terms of both current obligations and the market value of forward positions net of any posted collateral such as cash and letters of credit.
We evaluate the financial status of our banking partners through the use of market-based metrics such as credit default swap pricing levels, and also through traditional credit ratings provided by major credit rating agencies.
Other Information
Critical Accounting Estimates
A summary of our critical accounting estimates is included in the Company's Annual Report on Form 10-K for the year ended December 31, 2022. There were no material changes made as of March 31, 2023.
Recently Issued Accounting Pronouncements
Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information about recently issued and adopted accounting pronouncements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Quantitative and qualitative disclosures about market risk are reported in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures."
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our chief executive officer and our chief financial officer are responsible for evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our chief executive officer and chief financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that financial information was processed, recorded and reported accurately.
Changes in Internal Controls
There have been no changes in our internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
For a description of our legal proceedings, see Note 15, "Other Commitments and Contingencies - B. Legal Proceedings," in the Notes to the Condensed Consolidated Financial Statements (unaudited).
ITEM 1A. RISK FACTORS
Please refer to the risk factors set forth in Part I, Item 1A of the Annual Report on Form 10-K for the year ended December 31, 2022. There have been no material changes to such risk factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.