☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 001-16189
NiSource Inc.
(Exact name of registrant as specified in its charter)
DE
35-2108964
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
801 East 86th Avenue
Merrillville,
IN
46410
(Address of principal executive offices)
(Zip Code)
(877)647-5990
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share
NI
NYSE
Depositary Shares, each representing a 1/1,000th ownership interest in a share of 6.50% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, liquidation preference $25,000 per share and a 1/1,000th ownership interest in a share of Series B-1 Preferred Stock, par value $0.01 per share, liquidation preference $0.01 per share
NI PR B
NYSE
Series A Corporate Units
NIMC
NYSE
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yesþ No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)
Yesþ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ Accelerated filer ¨Emerging growth company ☐Non-accelerated filer ¨Smaller reporting company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Common Stock, $0.01 Par Value: 406,134,342 shares outstanding at October 31, 2022.
The following is a list of frequently used abbreviations or acronyms that are found in this report:
NiSource Subsidiaries and Affiliates
Columbia of Kentucky
Columbia Gas of Kentucky, Inc.
Columbia of Maryland
Columbia Gas of Maryland, Inc.
Columbia of Massachusetts
Bay State Gas Company
Columbia of Ohio
Columbia Gas of Ohio, Inc.
Columbia of Pennsylvania
Columbia Gas of Pennsylvania, Inc.
Columbia of Virginia
Columbia Gas of Virginia, Inc.
NIPSCO
Northern Indiana Public Service Company LLC
NiSource ("we," "us" or "our")
NiSource Inc.
Rosewater
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
AFUDC
Allowance for funds used during construction
AOCI
Accumulated Other Comprehensive Income (Loss)
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
ATM
At-the-market
BTA
Build-transfer agreement
CCRs
Coal Combustion Residuals
CEP
Capital Expenditure Program
CERCLA
Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund)
Corporate Units
Series A Corporate Units
COVID-19 ("the COVID-19 pandemic" or "the pandemic")
Novel Coronavirus 2019 and its variants, including the Delta and Omicron variants, and any other variant that may emerge
DPU
Department of Public Utilities
DSIC
Distribution System Improvement Charge
EPA
United States Environmental Protection Agency
EPS
Earnings per share
Equity Units
Series A Equity Units
FAC
Fuel adjustment clause
FASB
Financial Accounting Standards Board
FMCA
Federally Mandated Cost Adjustment
GAAP
Generally Accepted Accounting Principles
GCA
Gas cost adjustment
GHG
Greenhouse gases
GWh
Gigawatt hours
IRA
Inflation Reduction Act
IRP
Infrastructure Replacement Program
IURC
Indiana Utility Regulatory Commission
LIBOR
London InterBank Offered Rate
3
DEFINED TERMS
LIHEAP
Low Income Heating Energy Assistance Programs
Massachusetts Business
All of the assets sold to, and liabilities assumed by, Eversource pursuant to the Asset Purchase Agreement
MGP
Manufactured Gas Plant
MISO
Midcontinent Independent System Operator
MMDth
Million dekatherms
MW
Megawatts
MWh
Megawatt hours
NTSB
National Transportation Safety Board
NYMEX
New York Mercantile Exchange
OPEB
Other Postemployment Benefits
PHMSA
Pipeline and Hazardous Materials Safety Administration
PPA
Power Purchase Agreement
PUCO
Public Utilities Commission of Ohio
RNG
Renewable Natural Gas
SAVE
Steps to Advance Virginia's Energy Plan
Scope 1 GHG Emissions
Direct emissions from sources owned or controlled by us (e.g., emissions from our combustion of fuel, vehicles, and process emissions and fugitive emissions)
SEC
Securities and Exchange Commission
Section 201 Tariffs
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
STRIDE
Strategic Infrastructure Development Enhancement
TCJA
An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018 (commonly known as the Tax Cuts and Jobs Act of 2017)
TDSIC
Transmission, Distribution and Storage System Improvement Charge
U.S. Attorney's Office
U.S. Attorney's Office for the District of Massachusetts
VIE
Variable Interest Entity
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.
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 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
4
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; changes in the method for determining LIBOR and the potential replacement of the LIBOR benchmark interest rate; the outcome of legal and regulatory proceedings, investigations, incidents, claims and litigation; potential remaining liabilities related to the Greater Lawrence Incident; compliance with the agreements entered into with the U.S. Attorney's Office to settle the U.S. Attorney's Office's investigation relating 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, 2021, and in our Quarterly Report on Form 10-Q for the quarterly period ended March 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 September 30,
Nine Months Ended September 30,
(in millions, net of taxes)
2022
2021
2022
2021
Net Income
$
63.5
$
62.2
$
550.6
$
415.6
Other comprehensive income:
Net unrealized loss on available-for-sale debt securities(1)
(4.5)
(0.8)
(14.1)
(2.4)
Net unrealized gain on cash flow hedges(2)
16.2
6.6
119.2
41.4
Unrecognized pension and OPEB benefit (costs)(3)
0.6
0.4
(1.8)
0.3
Total other comprehensive income
12.3
6.2
103.3
39.3
Comprehensive Income
$
75.8
$
68.4
$
653.9
$
454.9
(1)Net unrealized loss on available-for-sale debt securities, net of $1.1 million and $0.2 million tax benefit in the third quarter of 2022 and 2021, respectively, and $3.7 million and $0.6 million tax benefit for the nine months ended 2022 and 2021, respectively.
(2)Net unrealized gain on cash flow hedges, net of $5.3 million and $2.2 million tax expense in the third quarter of 2022 and 2021, respectively, and $39.4 million and $13.7 million tax expense for the nine months ended 2022 and 2021, respectively.
(3)Unrecognized pension and OPEB benefit (costs), net of $0.2 million and $0.2 million tax expense in the third quarter of 2022 and 2021, respectively, and $0.6 million tax benefit and $1.3 million tax expense for the nine months ended 2022 and 2021, 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 $174.6 and $169.3, allowance for credit losses of $1.7 and $0.2, respectively)
157.8
171.8
Other investments
68.8
87.1
Total Investments and Other Assets
228.2
259.7
Current Assets
Cash and cash equivalents
35.8
84.2
Restricted cash
42.8
10.7
Accounts receivable
605.9
849.1
Allowance for credit losses
(19.2)
(23.5)
Accounts receivable, net
586.7
825.6
Gas inventory
606.3
327.4
Materials and supplies, at average cost
141.4
139.1
Electric production fuel, at average cost
52.4
32.2
Exchange gas receivable
184.7
99.6
Regulatory assets
245.7
206.2
Prepayments and other
332.8
195.8
Total Current Assets(1)
2,228.6
1,920.8
Other Assets
Regulatory assets
2,240.3
2,286.0
Goodwill
1,485.9
1,485.9
Deferred charges and other
402.4
322.7
Total Other Assets
4,128.6
4,094.6
Total Assets
$
25,576.4
$
24,156.9
(1)Includes $678.8 million and $695.9 million at September 30, 2022 and December 31, 2021, respectively, of net property, plant and equipment assets and $20.4 million and $14.3 million at September 30, 2022 and December 31, 2021, respectively, of current assets of consolidated VIEs that may be used only to settle obligations of the consolidated VIEs. Refer to Note 11, "Variable Interest Entities," for additional information.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
Noncontrolling interest in consolidated subsidiaries
311.8
325.6
Total Equity
7,505.7
7,272.9
Long-term debt, excluding amounts due within one year
9,521.2
9,183.4
Total Capitalization
17,026.9
16,456.3
Current Liabilities
Current portion of long-term debt
28.6
58.1
Short-term borrowings
1,274.2
560.0
Accounts payable
666.5
697.8
Dividends payable - common stock
95.6
—
Dividends payable - preferred stock
19.4
—
Customer deposits and credits
314.5
237.9
Taxes accrued
189.7
277.1
Interest accrued
124.1
105.5
Exchange gas payable
170.9
107.7
Regulatory liabilities
288.9
137.4
Accrued compensation and employee benefits
150.5
182.7
Other accruals
588.2
382.0
Total Current Liabilities(1)
3,911.1
2,746.2
Other Liabilities
Deferred income taxes
1,803.7
1,659.4
Accrued liability for postretirement and postemployment benefits
277.2
292.5
Regulatory liabilities
1,810.3
1,842.6
Asset retirement obligations
458.7
469.7
Other noncurrent liabilities
288.5
690.2
Total Other Liabilities(1)
4,638.4
4,954.4
Commitments and Contingencies (Refer to Note 14, "Other Commitments and Contingencies")
Total Capitalization and Liabilities
$
25,576.4
$
24,156.9
(1)Includes $7.8 million and $10.0 million at September 30, 2022 and December 31, 2021, respectively, of current liabilities and $20.9 million and $20.5 million at September 30, 2022 and December 31, 2021, respectively, of other liabilities of consolidated VIEs that creditors do not have recourse to our general credit. Refer to Note 11, "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 July 1, 2022
$
4.1
$
1,546.5
$
(99.9)
$
7,218.6
$
(1,408.9)
$
(35.8)
$
315.8
$
7,540.4
Comprehensive Income:
Net income (loss)
—
—
—
—
65.8
—
(2.3)
63.5
Other comprehensive income, net of tax
—
—
—
—
—
12.3
—
12.3
Dividends:
Common stock ($0.24 per share)
—
—
—
—
(95.6)
—
—
(95.6)
Preferred stock (See Note 5)
—
—
—
—
(19.4)
—
—
(19.4)
Distributions to noncontrolling interests
—
—
—
—
—
—
(1.7)
(1.7)
Stock issuances:
Employee stock purchase plan
—
—
—
1.3
—
—
—
1.3
Long-term incentive plan
—
—
—
2.6
—
—
—
2.6
401(k) and profit sharing
—
—
—
2.4
—
—
—
2.4
ATM program
—
—
—
(0.1)
—
—
—
(0.1)
Balance as of September 30, 2022
$
4.1
$
1,546.5
$
(99.9)
$
7,224.8
$
(1,458.1)
$
(23.5)
$
311.8
$
7,505.7
(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 (loss)
—
—
—
—
559.6
—
(9.0)
550.6
Other comprehensive income, net of tax
—
—
—
—
—
103.3
—
103.3
Dividends:
Common stock ($0.94 per share)
—
—
—
—
(381.7)
—
—
(381.7)
Preferred stock (See Note 5)
—
—
—
—
(55.1)
—
—
(55.1)
Distributions to noncontrolling interests
—
—
—
—
—
—
(4.8)
(4.8)
Stock issuances:
Employee stock purchase plan
—
—
—
3.8
—
—
—
3.8
Long-term incentive plan
—
—
—
9.5
—
—
—
9.5
401(k) and profit sharing
—
—
—
7.3
—
—
—
7.3
ATM program
—
—
—
(0.1)
—
—
—
(0.1)
Balance as of September 30, 2022
$
4.1
$
1,546.5
$
(99.9)
$
7,224.8
$
(1,458.1)
$
(23.5)
$
311.8
$
7,505.7
(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.
Condensed Statements of Consolidated Equity (unaudited) (continued)
(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 July 1, 2021
$
3.9
$
1,718.8
$
(99.9)
$
6,728.0
$
(1,704.1)
$
(123.6)
$
90.4
$
6,613.5
Comprehensive Income:
Net income (loss)
—
—
—
—
63.2
—
(1.0)
62.2
Other comprehensive income, net of tax
—
—
—
—
—
6.2
—
6.2
Dividends:
Common stock ($0.22 per share)
—
—
—
—
(86.5)
—
—
(86.5)
Preferred stock (See Note 5)
—
—
—
—
(19.4)
—
—
(19.4)
Distribution to noncontrolling interest
—
—
—
—
—
—
(0.2)
(0.2)
Stock issuances:
Equity Units
—
1.0
—
—
—
—
—
1.0
Employee stock purchase plan
—
—
—
1.2
—
—
—
1.2
Long-term incentive plan
—
—
—
4.0
—
—
—
4.0
401(k) and profit sharing
—
—
—
2.5
—
—
—
2.5
ATM program
—
—
—
(0.4)
—
—
—
(0.4)
Balance as of September 30, 2021
$
3.9
$
1,719.8
$
(99.9)
$
6,735.3
$
(1,746.8)
$
(117.4)
$
89.2
$
6,584.1
(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, 2021
$
3.9
$
880.0
$
(99.9)
$
6,890.1
$
(1,765.2)
$
(156.7)
$
85.6
$
5,837.8
Comprehensive Income:
Net income (loss)
—
—
—
—
419.0
—
(3.4)
415.6
Other comprehensive income, net of tax
—
—
—
—
—
39.3
—
39.3
Dividends:
Common stock ($0.88 per share)
—
—
—
—
(345.5)
—
—
(345.5)
Preferred stock (See Note 5)
—
—
—
—
(55.1)
—
—
(55.1)
Contribution from noncontrolling interest, net of distributions
—
—
—
—
—
—
7.0
7.0
Stock issuances:
Equity Units
—
839.8
—
(173.3)
—
—
666.5
Employee stock purchase plan
—
—
—
3.7
—
—
—
3.7
Long-term incentive plan
—
—
—
8.3
—
—
—
8.3
401(k) and profit sharing
—
—
—
7.2
—
—
—
7.2
ATM program
—
—
—
(0.7)
—
—
(0.7)
Balance as of September 30, 2021
$
3.9
$
1,719.8
$
(99.9)
$
6,735.3
$
(1,746.8)
$
(117.4)
$
89.2
$
6,584.1
(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.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
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, 2021. 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 Issued Accounting Pronouncements
We are currently evaluating the impact of certain ASUs on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited), which are described below:
In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance. This pronouncement requires certain annual disclosures for transactions with a government that are accounted for by applying a grant or contribution accounting model by analogy to other accounting guidance. This pronouncement is applicable for financial statements issued for annual periods beginning after December 15, 2021. We do not expect the adoption of this pronouncement to have a material impact on the Notes to the Consolidated Financial Statements.
Recently Adopted Accounting Pronouncements
In August 2020, the FASB issued ASU 2020-06, Debt with Conversion and Other Options (Subtopic 470-20) and Derivative and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity. This pronouncement amends the guidance for entities that issue convertible instruments and/or contracts indexed to and potentially settled in an entity's own equity. The pronouncement eliminates the beneficial conversion and cash conversion accounting models for convertible instruments. Additionally, the pronouncement amends the guidance for the derivatives scope exception for contracts in an entity's own equity. This pronouncement impacts the denominator in the calculation of diluted EPS for our Equity Units as we are required to assume share settlement of the remaining purchase contract payment balance when applying the if-converted method. Moreover, we are required to utilize the average share price for the period instead of the end of period price. We adopted this pronouncement using the modified retrospective method as of January 1, 2022.
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 are effective upon issuance on March 12, 2020, and will apply through December 31, 2022. The company has elected to apply the practical expedient which allows 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 material 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.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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 September 30, 2022
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other
Total
Customer Revenues(1)
Residential
$
330.1
$
178.8
$
—
$
508.9
Commercial
114.6
158.9
—
273.5
Industrial
42.6
151.9
—
194.5
Off-system
72.7
—
—
72.7
Miscellaneous
7.3
1.3
—
8.6
Total Customer Revenues
$
567.3
$
490.9
$
—
$
1,058.2
Other Revenues
5.1
25.4
0.8
31.3
Total Operating Revenues
$
572.4
$
516.3
$
0.8
$
1,089.5
(1)Customer revenue amounts exclude intersegment revenues. See Note 17, "Business Segment Information," for discussion of intersegment revenues.
Three Months Ended September 30, 2021
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other(2)
Total
Customer Revenues(1)
Residential
$
304.3
$
178.7
$
—
$
483.0
Commercial
99.2
151.6
—
250.8
Industrial
41.0
125.7
—
166.7
Off-system
14.5
—
—
14.5
Miscellaneous
4.6
(1.0)
0.2
3.8
Total Customer Revenues
$
463.6
$
455.0
$
0.2
$
918.8
Other Revenues
8.7
23.9
8.0
40.6
Total Operating Revenues
$
472.3
$
478.9
$
8.2
$
959.4
(1)Customer revenue amounts exclude intersegment revenues. See Note 17, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues primarily related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Nine months ended September 30, 2022
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other(2)
Total
Customer Revenues(1)
Residential
$
1,772.0
$
454.3
$
—
$
2,226.3
Commercial
631.7
428.1
—
1,059.8
Industrial
158.5
420.4
—
578.9
Off-system
150.5
—
—
150.5
Miscellaneous
29.9
9.6
—
39.5
Total Customer Revenues
$
2,742.6
$
1,312.4
$
—
$
4,055.0
Other Revenues
7.6
71.1
12.3
91.0
Total Operating Revenues
$
2,750.2
$
1,383.5
$
12.3
$
4,146.0
(1)Customer revenue amounts exclude intersegment revenues. See Note 17, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues related to the Transition Services Agreement entered into in connection with the sale of the Massachusetts Business, which was substantially completed as of June 30, 2022.
Nine months ended September 30, 2021
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other(2)
Total
Customer Revenues(1)
Residential
$
1,456.5
$
439.8
$
—
$
1,896.3
Commercial
496.0
404.4
—
900.4
Industrial
142.9
367.7
—
510.6
Off-system
46.0
—
—
46.0
Miscellaneous
19.2
4.6
0.6
24.4
Total Customer Revenues
$
2,160.6
$
1,216.5
$
0.6
$
3,377.7
Other Revenues
21.8
68.4
23.1
113.3
Total Operating Revenues
$
2,182.4
$
1,284.9
$
23.7
$
3,491.0
(1)Customer revenue amounts exclude intersegment revenues. See Note 17, "Business Segment Information," for discussion of intersegment revenues.
(2)Other revenues related 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 nine months ended September 30, 2022 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.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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.
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 September 30, 2022 and December 31, 2021 are presented in the table below:
(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
24.1
5.5
—
29.6
Write-offs charged against allowance
(40.9)
(3.8)
—
(44.7)
Recoveries of amounts previously written off
10.5
0.3
—
10.8
Balance as of September 30, 2022
$
12.6
$
5.8
$
0.8
$
19.2
(in millions)
Gas Distribution Operations
Electric Operations
Corporate and Other
Total
Balance as of January 1, 2021
$
41.8
$
9.7
$
0.8
$
52.3
Current period provisions
5.8
1.4
—
7.2
Write-offs charged against allowance
(46.7)
(7.7)
—
(54.4)
Recoveries of amounts previously written off
18.0
0.4
—
18.4
Balance as of December 31, 2021
$
18.9
$
3.8
$
0.8
$
23.5
In connection with the COVID-19 pandemic, certain state regulatory commissions instituted regulatory moratoriums that impacted our ability to pursue our standard credit risk mitigation practices during 2021. Following the issuance of these moratoriums, certain of our regulated operations have been authorized to recognize a regulatory asset for bad debt costs above levels currently recovered in rates. At December 31, 2021, in addition to our evaluation of the allowance for credit losses discussed above, we considered benefits available under governmental COVID-19 relief programs, the impact of unemployment benefits initiatives, and flexible payment plans being offered to customers affected by or experiencing hardship as a result of the pandemic, which could help to mitigate the potential for increasing customer account delinquencies. We also considered the on-time bill payment promotion and robust customer marketing strategy for energy assistance programs that we have implemented. Based upon our overall evaluation, we have concluded that the allowance for credit losses as of December 31, 2021 and September 30, 2022 adequately reflected the collection risk and net realizable value for our receivables. As of December 31, 2021, we resumed our common credit mitigation practices in all jurisdictions as all moratoriums had expired.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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 and nine months ended September 30, 2022 and 2021 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 average stock price during the period 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 average stock price during the period 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 and nine months ended September 30, 2022 and 2021 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. Refer to Note 2, "Recent Accounting Pronouncements," for more information on ASU 2020-06.
The shares underlying the Series C Mandatory Convertible Preferred Stock included within the Equity Units are contingently convertible securities 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 September 30, 2022 and 2021, the contingency was not resolved and thus no shares were reflected in the denominator in the calculation of diluted EPS for the three and nine months ended September 30, 2022 and 2021.
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. Refer to Note 5, "Equity," for more information on our ATM forward agreements.
The following table presents the calculation of our basic and diluted EPS:
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions, except per share amounts)
2022
2021
2022
2021
Numerator:
Net Income Available to Common Shareholders - Basic
$
52.0
$
49.4
$
518.2
$
377.6
Dilutive effect of Equity Units
0.5
0.6
1.5
1.0
Net Income Available to Common Shareholders - Diluted
$
52.5
$
50.0
$
519.7
$
378.6
Denominator:
Average common shares outstanding - Basic
406.5
393.2
406.3
392.9
Dilutive potential common shares:
Equity Units purchase contracts
31.3
35.2
29.4
21.3
Equity Units purchase contract payment balance
3.0
—
3.4
—
Shares contingently issuable under employee stock plans
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
5. Equity
ATM Program and Forward Sale Agreement. 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.
On August 9, 2021, under the ATM program, we executed a forward sale agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From August 9, 2021 to September 1, 2021, the forward purchaser under our forward sale agreement borrowed 5,941,598 shares from third parties, which the forward purchaser sold, through its affiliated agent, at a weighted average price of $25.25 per share. The forward sale agreement must be settled by December 15, 2022 in shares, cash, or net shares. Had we settled all the shares under the forward sale agreement at September 30, 2022, we would have received approximately $143.0 million, based on a net price of $24.06 per share.
As of September 30, 2022, the ATM program (including the impacts of the forward sale agreement discussed above) had approximately $300.0 million of equity available for issuance. The program expires on December 31, 2023.
Preferred Stock. As of September 30, 2022, 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 September 30,
Nine Months Ended September 30,
September 30,
December 31,
2022
2021
2022
2021
2022
2021
(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
56.50
56.50
$
393.9
$
393.9
6.500% Series B
$
25,000.00
20,000
406.25
406.25
1,625.00
1,625.00
$
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 September 30, 2022. 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 September 30, 2022 and 2021, 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. 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. We are accounting for the Corporate Units as a single unit of account.
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
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Stock will initially be pledged upon issuance as collateral to secure the purchase of common stock under the related purchase contracts.
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 to holders of the Equity Units 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. As of September 30, 2022, no contract adjustment payments have been deferred with quarterly cash payments being remitted to the holders. As of September 30, 2022 and December 31, 2021 the purchase contract liability was $81.1 million and $129.4 million, respectively. Purchase contract payments are recorded against this liability. Accretion of the purchase contract liability is recorded as interest expense. Cash payments of $50.1 million and $24.5 million were made during the nine months ended September 30, 2022 and 2021, respectively.
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 September 30, 2022, we would have issued approximately 3.0 million shares.
6. 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.
Columbia of Ohio regulatory filing update
On Wednesday, April 6, 2022, the PUCO Staff issued its Staff Report in Columbia of Ohio's base rate case, filed on June 21, 2021, which was filed in conjunction with applications for an alternative rate plan, approval of certain deferral authority, and updates to certain riders. Columbia of Ohio's application requested a net rate increase approximating a 21.3% or $221.4 million increase in revenue per year. The Staff Report recommended a rate increase of 4.0% - 6.3% or $35.2 million to $57.6 million increase in revenue per year. The Staff recommended adjustments include, but are not limited to, plant assets, labor adjustments, COVID-19 deferrals and environmental remediation costs, rider caps, and rate of return. On May 6, 2022 and May 13, 2022, respectively, Columbia of Ohio and the other parties filed written objections to the Staff report as well as written testimony. On October 31, 2022, Columbia of Ohio filed a joint stipulation and recommendation with certain parties to settle the base rate case. The joint stipulation and recommendation includes a rate increase of 7.97%, or $68.2 million and includes adjustments to, plant assets, pension expenses, environmental remediation costs and other operations and maintenance expenses. The joint stipulation and recommendation also proposes to extend both of Columbia of Ohio's capital investment riders, the IRP and CEP, for capital invested through the 2026 calendar year. The joint stipulation and recommendation is subject to final PUCO approval.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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 joint ventures and the amount included in regulated rates to recover our approved investments in consolidated joint ventures. 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). We recorded a decrease to depreciation expense of $2.2 million and an increase to depreciation expense of $4.5 million for the three and nine months ended September 30, 2022, and zero for the three and nine months ended September 30, 2021, respectively, related to the regulatory deferral of income (loss) associated with our joint ventures, which is not included in current rates. Refer to Note 11, "Variable Interest Entities," for additional information.
FAC Adjustment
As ordered by the IURC on June 15, 2022, NIPSCO is required to refund to customers $8.0 million of over-collected fuel costs. The refund is recorded as a regulatory liability on the Condensed Consolidated Balance Sheets (unaudited).
7. 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.
Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below:
September 30, 2022
December 31, 2021
(in millions)
Assets
Liabilities
Assets
Liabilities
Current(1)
Derivatives designated as hedging instruments
$
—
$
—
$
—
$
136.4
Derivatives not designated as hedging instruments
41.8
1.9
10.6
0.4
Total
$
41.8
$
1.9
$
10.6
$
136.8
Noncurrent(2)
Derivatives designated as hedging instruments
$
12.1
$
—
$
—
$
—
Derivatives not designated as hedging instruments
82.3
1.7
13.8
7.4
Total
$
94.4
$
1.7
$
13.8
$
7.4
(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", respectively, on the Condensed Consolidated Balance Sheets (unaudited).
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 September 30, 2022 and December 31, 2021, we had 108.0 MMDth and 124.5 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 September 30, 2022, the remaining terms of these instruments range from one to five years.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
All gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are remitted to or collected from customers through NIPSCO’s quarterly GCA mechanism. These instruments are not designated as accounting hedges.
The following table summarizes the gains and losses associated with the commodity price risk programs:
(in millions)
September 30, 2022
December 31, 2021
Regulatory Assets
Losses on commodity price risk programs
$
6.0
$
9.6
Regulatory Liabilities
Gains on commodity price risk programs
150.7
34.2
Derivatives Designated as Hedging Instruments
Interest rate risk management. As of September 30, 2022, we have one forward-starting interest rate swap with a notional value of $250.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate associated with a forecasted debt issuance. This interest rate swap is designated as a cash flow hedge.
On June 7, 2022, we settled a $250.0 million forward-starting interest rate swap agreement contemporaneously with the issuance of $350.0 million of 5.00% senior unsecured notes maturing in 2052. The derivative contract was accounted for as a cash flow hedge. As part of the transaction, the associated net unrealized gain position of $10.2 million is being amortized from AOCI loss into interest expense over the life of the associated debt. Refer to Note 12, "Long-Term Debt," for additional information.
Cash flow hedges included in "Accumulated other comprehensive loss" on the Condensed Consolidated Balance Sheets (unaudited) were:
(in millions)
AOCI(1)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months(1)
Maximum Term
Interest Rate
$
(3.3)
(0.2)
380 months
(1) All amounts are net of tax.
The actual amounts reclassified from AOCI to Net Income can differ from the estimate above due to market rate changes.
The gains and losses related to these swaps are recorded to AOCI. Upon issuance, we amortize the gains and losses over the life of the debt associated with these swaps as we recognize interest expense. These amounts are immaterial for the three and nine months ended September 30, 2022 and 2021 and are recorded in "Interest expense, net" on the Condensed Statements of Consolidated Income (unaudited).
If it becomes probable that a hedged forecasted transaction will no longer occur, the accumulated gains or losses on the derivative will be recognized currently in "Other, net" in the Condensed Statements of Consolidated Income (unaudited).
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2022 and December 31, 2021.
Our derivative instruments measured at fair value as of September 30, 2022 and December 31, 2021 do not contain any credit-risk-related contingent features. Cash flows for derivative financial instruments are generally classified as operating activities.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
8. 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 September 30, 2022 and December 31, 2021:
Recurring Fair Value Measurements September 30, 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
September 30, 2022
Assets
Risk management assets
$
—
$
136.2
$
—
$
136.2
Available-for-sale debt securities
—
157.8
—
157.8
Total
$
—
$
294.0
$
—
$
294.0
Liabilities
Risk management liabilities
$
—
$
3.6
$
—
$
3.6
Total
$
—
$
3.6
$
—
$
3.6
Recurring Fair Value Measurements December 31, 2021 (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, 2021
Assets
Risk management assets
$
—
$
24.4
$
—
$
24.4
Available-for-sale debt securities
—
171.8
—
171.8
Total
$
—
$
196.2
$
—
$
196.2
Liabilities
Risk management liabilities
$
—
$
144.2
$
—
$
144.2
Total
$
—
$
144.2
$
—
$
144.2
Risk Management Assets and Liabilities. Risk management assets and liabilities include interest rate swaps, 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 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.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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 September 30, 2022 and December 31, 2021, 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.
Credit risk is considered in the fair value calculation of each of our forward-starting interest rate swaps, as described in Note 7, "Risk Management Activities." As they are based on observable data and valuations of similar instruments, the hedges are categorized within Level 2 of the fair value hierarchy. There was no exchange of premium at the initial date of the swaps, and we can settle the contracts at any time.
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 7, "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 September 30, 2022 and December 31, 2021, we recorded $1.7 million and $0.2 million, respectively, 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 September 30, 2022 and December 31, 2021 were:
September 30, 2022 (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
$
69.7
$
—
$
(4.8)
$
—
$
64.9
Corporate/Other debt securities
104.9
—
(10.3)
(1.7)
92.9
Total
$
174.6
$
—
$
(15.1)
$
(1.7)
$
157.8
December 31, 2021 (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
$
52.8
$
0.1
$
(0.4)
$
—
$
52.5
Corporate/Other debt securities
116.5
3.7
(0.7)
(0.2)
119.3
Total
$
169.3
$
3.8
$
(1.1)
$
(0.2)
$
171.8
(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 $62.3 million and $85.1 million, respectively, at September 30, 2022.
(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 $36.2 million and $35.4 million, respectively, at December 31, 2021.
The cost of maturities sold is based upon specific identification. Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2022 and 2021.
At September 30, 2022, approximately $7.0 million of U.S. Treasury debt securities and approximately $9.1 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 September 30, 2022, 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)
9. Income Taxes
Our interim effective tax rates reflect the estimated annual effective tax rates for 2022 and 2021, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2022 and 2021 were 15.6% and 19.2%, respectively. The effective tax rate for both the nine months ended September 30, 2022 and 2021 was 17.9%. 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 income taxes, 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 decrease in the three month effective tax rate of 3.6% in 2022 compared to 2021 is primarily attributed to the Pennsylvania tax rate change and rate differential, and increased amortization of excess deferred federal income tax liabilities.
There were no material changes recorded in 2022 to our uncertain tax positions recorded as of December 31, 2021.
10. 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 nine months ended September 30, 2022, we contributed $2.1 million to our pension plans and $15.9 million to our OPEB plans.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The following table provides the components of the plans' actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2022 and 2021:
Pension Benefits
OPEB
Three Months Ended September 30, (in millions)
2022
2021
2022
2021
Components of Net Periodic Benefit (Income) Cost(1)
Service cost
$
6.8
$
7.5
$
1.6
$
1.5
Interest cost
10.7
7.9
3.0
2.5
Expected return on assets
(22.6)
(25.2)
(4.0)
(3.8)
Amortization of prior service credit
—
—
(0.6)
(0.6)
Recognized actuarial loss
5.6
5.5
0.7
1.2
Settlement loss
3.0
2.9
—
—
Total Net Periodic Benefit (Income) Cost
$
3.5
$
(1.4)
$
0.7
$
0.8
(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).
Pension Benefits
OPEB
Nine Months Ended September 30, (in millions)
2022
2021
2022
2021
Components of Net Periodic Benefit (Income) Cost(1)
Service cost
$
20.9
$
22.6
$
4.8
$
4.5
Interest cost
29.9
23.5
9.0
7.5
Expected return on assets
(68.3)
(76.3)
(12.0)
(11.4)
Amortization of prior service credit
—
—
(1.8)
(1.8)
Recognized actuarial loss
14.9
16.3
2.1
3.6
Settlement loss
9.3
9.5
—
—
Total Net Periodic Benefit (Income) Cost
$
6.7
$
(4.4)
$
2.1
$
2.4
(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).
As of May 31, 2022, one of our qualified pension plans met the requirement for settlement accounting. A settlement charge of $6.3 million was recorded during the second quarter of 2022. As a result of the settlement, the pension plan was remeasured, resulting in a decrease to the net pension asset of $39.8 million, a net increase to regulatory assets of $30.0 million, and a net debit to accumulated other comprehensive loss of $3.5 million. Net periodic pension benefit cost for 2022 increased by $5.7 million as a result of the interim remeasurement.
For the interim remeasurement, the discount rate used to calculate the remeasured plan's pension benefit obligation was updated to 4.13% from 2.60% at December 31, 2021. At the time of the interim remeasurement, we also updated the discount rates and expected return on assets used to calculate net periodic pension benefit costs in 2022. Our discount rates for service and interest costs, respectively, were updated to 4.30% and 3.64% from 2.85% and 1.90% at January 1, 2022. The expected return on assets assumption was updated to 5.70% from 4.80% at January 1, 2022.
During the third quarter of 2022, the requirements for settlement accounting were also met, resulting in a settlement charge of $3.0 million for the three months ended September 30, 2022.
11. Variable Interest Entities
A VIE is an entity in which the controlling interest is determined through means other than a majority voting interest. We control decisions that are significant to Rosewater and Indiana Crossroads Wind's ongoing operations and economic results. Therefore, we have concluded that we are the primary beneficiary and have consolidated both.
Members of the respective joint ventures 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 partners in varying percentages over the life of the partnerships. Once the tax equity partners have earned their negotiated rate of return and we have reached the agreed upon
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
contractual date, NIPSCO has the option to purchase at fair market value from the tax equity partners the remaining interest in the respective joint venture. NIPSCO has an obligation to purchase, through a PPA at established market rates, 100% of the electricity generated by the joint ventures.
Rosewater
Rosewater owns and operates 102 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner have made total contributions of $170.1 million. NIPSCO and the tax equity partner contributed cash, and NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. The obligation to developer is included within "Other accruals" on the Condensed Consolidated Balance Sheets (unaudited). The developer of the facility is not a partner in the joint venture for federal income tax purposes and does not receive any share of earnings, tax attributes, or cash flows of Rosewater.
Indiana Crossroads Wind
Indiana Crossroads Wind owns and operates 302 MW of nameplate capacity wind generation assets. NIPSCO and the tax equity partner have made total contributions of $511.8 million. NIPSCO and the tax equity partner contributed cash, and NIPSCO also assumed an obligation to the developer of the wind generation assets representing the remaining economic interest, which comes due in 2023. The obligation to developer is included within "Other accruals" on the Condensed Consolidated Balance Sheets (unaudited). The developer of the facility is not a partner in the joint venture for federal income tax purposes and does not receive any share of earnings, tax attributes, or cash flows of Indiana Crossroads Wind.
The following table displays the noncontrolling interest in consolidated subsidiaries included in the Condensed Consolidated Balance Sheets (unaudited):
(in millions)
September 30, 2022
December 31, 2021
Rosewater
$
82.4
$
88.2
Indiana Crossroads Wind
229.4
237.4
Total
$
311.8
$
325.6
The following table displays the Net income (loss) attributable to noncontrolling interest included in the Condensed Statements of Consolidated Income (unaudited):
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions)
2022
2021
2022
2021
Rosewater
$
(1.1)
$
(1.0)
$
(4.0)
$
(3.4)
Indiana Crossroads Wind
(1.2)
—
(5.0)
—
Total
$
(2.3)
$
(1.0)
$
(9.0)
$
(3.4)
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.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Our Condensed Consolidated Balance Sheets (unaudited) included the following assets and liabilities associated with VIEs.
(in millions)
September 30, 2022
December 31, 2021
Rosewater
Indiana Crossroads Wind
Rosewater
Indiana Crossroads Wind
Net Property, Plant and Equipment
$
165.9
$
512.9
$
170.1
$
525.8
Current assets
7.7
12.7
6.2
8.1
Total assets(1)
173.6
525.6
176.3
533.9
Current liabilities
4.4
3.4
2.5
7.5
Asset retirement obligations
5.8
15.1
5.7
14.8
Total liabilities
$
10.2
$
18.5
$
8.2
$
22.3
(1)The assets of Rosewater and Indiana Crossroads 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 Rosewater and Indiana Crossroads do not have recourse, to the general credit of the primary beneficiary.
12. Long-Term Debt
On April 1, 2022, we repaid $20.0 million of 7.99% medium term notes at maturity. The remaining $29.0 million of 7.99% medium term notes outstanding September 30, 2022 and December 31, 2021 are expected to be repaid in May 2027 at maturity.
On June 10, 2022, we completed the issuance and sale of $350.0 million of 5.00% senior unsecured notes maturing in 2052, which resulted in approximately $344.6 million of net proceeds after discount and debt issuance costs.
On August 30, 2022, NIPSCO repaid $10.0 million of 7.40% medium term notes at maturity.
13. Short-Term Borrowings
We generate short-term borrowings through several sources, described in further detail 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. On February 18, 2022, we extended the termination date of our revolving credit facility to February 18, 2027. We had no outstanding borrowings under this facility as of September 30, 2022 and December 31, 2021.
Commercial Paper Program. Our commercial paper program has a program limit of up to $1.5 billion. We had $956.0 million and $560.0 million of commercial paper outstanding with weighted-average interest rates of 3.11% and 0.24% as of September 30, 2022 and December 31, 2021, respectively.
Accounts Receivable Transfer Programs. Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they may transfer their customer accounts receivables to third-party financial institutions through wholly owned and consolidated special purpose entities. The three agreements expire between May 2023 and October 2023 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 September 30, 2022, the maximum amount of debt that could be recognized related to our accounts receivable programs is $345.0 million.
We had $318.2 million and zero short-term borrowings related to the securitization transactions as of September 30, 2022 and December 31, 2021, respectively.
For the nine months ended September 30, 2022 and 2021, $318.2 million and zero, respectively, were recorded as cash flows from financing activities related to the change in short-term borrowings due to securitization transactions. For the accounts receivable transfer programs, we pay used facility fees for amounts borrowed, unused commitment fees for amounts not borrowed, and upfront renewal fees. Fees associated with the securitization transactions were $0.7 million and $0.3 million for
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
the three months ended September 30, 2022 and 2021, respectively and $1.7 million and $1.1 million for the nine months ended September 30, 2022 and 2021, 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.
Items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.
14. 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 September 30, 2022 and December 31, 2021, we had issued stand-by letters of credit of $10.2 million and $18.9 million, respectively.
We provide guarantees related to our future performance under BTAs for our renewable generation projects. At September 30, 2022 and December 31, 2021, our guarantees for BTAs totaled $788.0 million and $288.9 million, respectively. 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. 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").
We have been subject to inquiries and investigations by government authorities and regulatory agencies regarding the Greater Lawrence Incident. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney’s Office for the District of Massachusetts to resolve the U.S. Attorney’s Office’s investigation relating to the Greater Lawrence Incident, as described below. The Company and Columbia of Massachusetts entered into an agreement with the Massachusetts Attorney General’s Office (among other parties) to resolve the Massachusetts DPU and the Massachusetts Attorney General’s Office investigations, that was approved by the Massachusetts DPU on October 7, 2020 as part of the sale of the Massachusetts Business to Eversource.
U.S. Department of Justice Investigation. On February 26, 2020, the Company and Columbia of Massachusetts entered into agreements with the U.S. Attorney's Office to resolve the U.S. Attorney's Office's investigation relating to the Greater Lawrence Incident. Columbia of Massachusetts agreed to plead guilty in the United States District Court for the District of Massachusetts (the ''Court'') to violating the Natural Gas Pipeline Safety Act (the ''Plea Agreement''), and the Company entered into a Deferred Prosecution Agreement (the ''DPA'').
On March 9, 2020, Columbia of Massachusetts entered its guilty plea pursuant to the Plea Agreement. The Court sentenced Columbia of Massachusetts on June 23, 2020, in accordance with the terms of the Plea Agreement (as modified). On June 23, 2021, the Court terminated Columbia of Massachusetts' period of probation under the Plea Agreement, which marked the completion of all terms of the Plea Agreement.
Under the DPA, the U.S. Attorney's Office agreed to defer prosecution of the Company in connection with the Greater Lawrence Incident for a three-year period ending on February 26, 2023 (which three-year period may be extended for twelve (12) months upon the U.S. Attorney's Office's determination of a breach of the DPA) subject to certain obligations of the Company, including, but not limited to, the Company's agreement, as to each of the Company's subsidiaries involved in the distribution of gas through pipeline facilities in Massachusetts, Indiana, Ohio, Pennsylvania, Maryland, Kentucky and Virginia to implement and adhere to each of the recommendations from the NTSB stemming from the Greater Lawrence Incident. Pursuant to the DPA, if the Company complies with all of its obligations under the DPA, the U.S. Attorney's Office will not file any criminal charges against the Company related to the Greater Lawrence Incident.
Private Actions. Various lawsuits, including several purported class action lawsuits, were filed by various affected residents or businesses in Massachusetts state courts against the Company and/or Columbia of Massachusetts in connection with the Greater Lawrence Incident.
On March 12, 2020, the Court granted final approval of the settlement of the consolidated class action. With respect to claims not included in the consolidated class action, many of the asserted wrongful death and bodily injury claims have settled, and we
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
continue to discuss potential settlements with remaining claimants. The outcomes and impacts of such private actions are uncertain at this time.
Shareholder Derivative Lawsuit. On April 28, 2020, a shareholder derivative lawsuit was filed by the City of Detroit Police and Fire Retirement System in the United States District Court for the District of Delaware against certain of the Company's current and former directors, alleging state-law claims for breaches of fiduciary duty with respect to the pipeline safety management systems relating to the distribution of natural gas prior to the Greater Lawrence Incident and also including federal-law claims related to our proxy statement disclosures regarding our safety systems. The remedies sought included damages for the alleged breaches of fiduciary duty, corporate governance reforms, and restitution of any unjust enrichment. On March 9, 2021, the district court granted the defendants' motion to dismiss the federal-law claims with prejudice for failure to state a claim on which relief can be granted and declined to exercise jurisdiction over the state-law claims, which were dismissed without prejudice.
Following the dismissal of the federal court action, on April 29, 2021, the same plaintiff filed a shareholder derivative lawsuit in the Delaware Court of Chancery against certain of our current and former directors related to substantially the same matters as those alleged in the dismissed federal derivative complaint and alleged a single count for breach of fiduciary duty. The remedies sought included damages for the alleged breaches of fiduciary duty, corporate governance reforms, and restitution of compensation by the individual defendants. On June 30, 2022, the Court of Chancery issued a Memorandum Opinion granting the defendants' motion to dismiss. The deadline for the plaintiff to appeal the dismissal lapsed on August 12, 2022.
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 Claims and Proceedings. We are also party to certain 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.
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 other 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.
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 September 30, 2022 and December 31, 2021, we had recorded a liability of $93.7 million and $91.1 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.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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, NIPSCO 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 $88.0 million and $85.1 million at September 30, 2022 and December 31, 2021, respectively. The liability represents our best estimate of the probable cost to remediate the MGP sites. We believe 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. We are in compliance with 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 joint venture 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 joint venture from the tax equity partner.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
16. Other, Net
The following table displays the components of Other, Net included on the Condensed Statements of Consolidated Income (unaudited):
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions)
2022
2021
2022
2021
Interest income
$
2.1
$
1.1
$
3.6
$
2.7
AFUDC equity
4.0
3.5
11.0
8.4
Pension and other postretirement non-service benefit
5.3
9.3
17.6
26.4
Miscellaneous
(1.3)
0.4
(2.2)
(0.3)
Total Other, net
$
10.1
$
14.3
$
30.0
$
37.2
17. 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, 2021.
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, 2021 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. The Safety Management System ("SMS") is an established operating model within NiSource. With the continued support and advice from our Quality Review Board (a panel of third parties with safety operations expertise engaged by management to advise on safety matters), we are continuing to mature our SMS processes, capabilities and talent as we collaborate within and across industries to enhance safety and reduce operational risk. Additionally, we continue to pursue regulatory and legislative initiatives that will allow customers not currently on our system to obtain gas and electric 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, as described in our 2018 Integrated Resource Plan ("2018 Plan"), is well underway, and we are continually adjusting to the dynamic renewable energy landscape. As of September 30, 2022, we have executed and received IURC approval for BTAs and PPAs with a combined nameplate capacity of 1,950 MW and 1,380 MW, respectively, under the 2018 Plan. Further, we have placed three wind projects into service and completed the retirement of R.M. Schahfer Generating Station Units 14 and 15. We anticipate delays on our previously announced solar and storage projects due to several factors, including the U.S. Department of Commerce investigation. In connection with these delays, we currently expect to retire R.M. Schahfer's remaining two coal units by the end of 2025. In June 2022, the Biden Administration announced a 24-month tariff relief on solar panels subject to the ongoing U.S. Department of Commerce investigation and authorized the use of the Defense Production Act of 1950, as amended (the "Defense Production Act"), to accelerate domestic production of clean energy technologies, including solar panel parts. In August 2022, the Inflation Reduction Act ("IRA") was signed into law. We see the IRA as generally supportive of our generation transition strategy and as having the potential to drive increased value for our customers. We are still evaluating the impacts of this legislation on our projects. 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 which is expected to occur between 2026 and 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 expected to occur between 2025 and 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.
NiSource Next: Starting in 2021, we optimized our workforce by redefining roles to sharpen our focus on safety and risk mitigation, operational rigor, and adherence to process and procedures, as well as implemented consistent span of control for
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
leadership to increase individual responsibility and clear accountability. Additionally, we began to make advancements across our operations to improve safety, operational efficiencies, and customer satisfaction through continued standardization of work processes, the implementation of new mobile technology to provide real-time access to information while serving our customers and enhanced customer self-service options to better meet customer expectations. These enhancements set the foundation for 2022 and beyond, to continue improving safety and customer experience through analytics and significant technology investments.
Economic Environment: We are monitoring risks related to increasing order and delivery lead times for construction and other materials, increasing risk of unavailability of materials due to global shortages in raw materials, and risk of decreased construction labor productivity in the event of disruptions in the availability of materials. We are also seeing increasing prices associated with certain materials and supplies. To the extent that delays occur or our costs increase, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected. For more information on supply chain impacts to our electric generation strategy, see "Results and Discussion of Segment Operations - Electric Operations," in this Management's Discussion.
Early in 2022, NIPSCO experienced a rail service shortage in deliveries of coal, particularly to its Michigan City Generating Station, and the primary rail carrier for that generating station was unable to provide assurance of adequate future service to maintain coal inventory. A lack of adequate coal deliveries to any of our coal-fired generating facilities for an extended period could deplete our inventories to a level that prevents the generating station from running, and NIPSCO would need to rely on market purchases of replacement power, which could increase the cost of electricity for NIPSCO's customers. NIPSCO believes these shortages have been resolved but continues to monitor deliveries of coal from its rail carriers. We do not expect this to have a material impact on our operations.
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 competitive and attractive appeal for potential recruits. With a focus on workforce planning, we are creating flexible work arrangements where we can, and being anticipatory in evaluating our talent footprint for the future to ensure we have the right people, in the right role, and at the right time. To the extent we are unable to execute on our workforce planning initiatives and experience increased employee and contractor costs, our business operations, results of operations, cash flows, and financial condition could be materially adversely affected.
We have seen an increase in natural gas costs as the spot market for natural gas has substantially increased since the start of 2022. Nationally, levels of gas in storage are lower in 2022 compared to 2021, liquified natural gas exports to Europe continue at a steady pace, and domestic production is seeing a recent decline in demand. These factors drive increased volatility in the marketplace, which we expect to influence customer bills through 2022. For the nine months ended September 30, 2022, we have not seen this increase 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 are experiencing higher interest expense in 2022 compared to 2021 associated with short-term borrowings. We expect additional interest rate increases throughout the remainder of the year that will negatively impact our cash flows and financial condition. 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 and nine months ended September 30, 2022 and 2021 are presented below:
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions, except per share amounts)
2022
2021
Favorable (Unfavorable)
2022
2021
Favorable (Unfavorable)
Operating Revenues
$
1,089.5
$
959.4
$
130.1
$
4,146.0
$
3,491.0
$
655.0
Operating Expenses
Cost of energy
330.8
208.3
(122.5)
1,421.2
913.4
(507.8)
Other Operating Expenses
602.0
604.0
2.0
1,824.5
1,855.1
30.6
Total Operating Expenses
932.8
812.3
(120.5)
3,245.7
2,768.5
(477.2)
Operating Income
156.7
147.1
9.6
900.3
722.5
177.8
Total Other Deductions, Net
(81.5)
(70.1)
(11.4)
(229.8)
(216.3)
(13.5)
Income Taxes
11.7
14.8
3.1
119.9
90.6
(29.3)
Income from Continuing Operations
63.5
62.2
1.3
550.6
415.6
135.0
Net Income
63.5
62.2
1.3
550.6
415.6
135.0
Net loss attributable to noncontrolling interest
(2.3)
(1.0)
1.3
(9.0)
(3.4)
5.6
Net Income Attributable to NiSource
65.8
63.2
2.6
559.6
419.0
140.6
Preferred dividends
(13.8)
(13.8)
—
(41.4)
(41.4)
—
Net Income Available to Common Shareholders
52.0
49.4
2.6
518.2
377.6
140.6
Earnings Per Share
Basic Earnings Per Share
$
0.13
$
0.13
$
—
$
1.28
$
0.96
$
0.32
Diluted Earnings Per Share
$
0.12
$
0.12
$
—
$
1.18
$
0.91
$
0.27
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.
Net income available to common shareholders for the three months ended September 30, 2022 is comparable to the same period in 2021. The increase in net income available to common shareholders during the nine months ended September 30, 2022 was primarily due to higher revenues from outcomes of gas base rate proceedings and regulatory capital programs, as well as an insurance settlement related to the Greater Lawrence Incident, offset by higher income taxes in 2022 compared to the 2021.
For additional information on operating income variance drivers see "Results and Discussion of Segment Operations" for Gas and Electric Operations in this Management's Discussion.
Other Deductions, net
Other deductions, net for the three and nine months ended September 30, 2022 is comparable to the same periods in 2021. See Note 12, "Long-Term Debt," Note 13, "Short-Term Borrowings," and Note 10, "Pension and Other Postemployment Benefits," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information.
Income Taxes
Refer to Note 9, "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.
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 and nine months ended September 30, 2022 and 2021 are presented below.
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions)
2022
2021
Favorable (Unfavorable)
2022
2021
Favorable (Unfavorable)
Operating Revenues
$
575.5
$
475.3
$
100.2
$
2,759.6
$
2,191.5
$
568.1
Operating Expenses
Cost of energy
158.0
89.0
(69.0)
1,000.5
597.0
(403.5)
Operation and maintenance
237.0
232.4
(4.6)
774.1
725.1
(49.0)
Depreciation and amortization
104.3
96.9
(7.4)
307.2
283.4
(23.8)
Loss (gain) on sale of fixed assets and impairments, net
—
(0.1)
(0.1)
(105.0)
8.0
113.0
Other taxes
42.8
46.1
3.3
158.0
158.9
0.9
Total Operating Expenses
542.1
464.3
(77.8)
2,134.8
1,772.4
(362.4)
Operating Income
$
33.4
$
11.0
$
22.4
$
624.8
$
419.1
$
205.7
Revenues
Residential
$
332.3
$
309.8
$
22.5
$
1,772.7
$
1,472.9
$
299.8
Commercial
115.5
101.3
14.2
634.3
501.6
132.7
Industrial
42.9
41.4
1.5
159.3
144.0
15.3
Off-System
72.7
14.6
58.1
150.5
46.0
104.5
Other
12.1
8.2
3.9
42.8
27.0
15.8
Total
$
575.5
$
475.3
$
100.2
$
2,759.6
$
2,191.5
$
568.1
Sales and Transportation (MMDth)
Residential
13.6
12.4
1.2
169.8
161.5
8.3
Commercial
17.7
17.3
0.4
126.1
118.8
7.3
Industrial
115.6
123.3
(7.7)
365.6
384.4
(18.8)
Off-System
10.6
4.1
6.5
23.2
15.7
7.5
Other
—
—
—
0.2
0.2
—
Total
157.5
157.1
0.4
684.9
680.6
4.3
Heating Degree Days
87
44
43
3,493
3,353
140
Normal Heating Degree Days
60
70
(10)
3,428
3,475
(47)
% Colder (Warmer) than Normal
45
%
(37)
%
2
%
(4)
%
% Colder than 2021
98
%
4
%
Gas Distribution Customers
Residential
2,952,458
2,942,031
10,427
Commercial
250,919
250,931
(12)
Industrial
4,860
4,904
(44)
Other
3
3
—
Total
3,208,240
3,197,869
10,371
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 and nine months ended September 30, 2022 compared to the same periods in 2021 are presented below.
Favorable (Unfavorable)
Changes in Operating Revenues (in millions)
Three Months Ended September 30, 2022 vs 2021
Nine Months Ended September 30, 2022 vs 2021
New rates from base rate proceedings and regulatory capital programs
$
24.3
$
109.3
The effects of weather in 2022 compared to 2021
2.5
13.2
Higher revenue related to off system sales
1.8
5.9
Higher revenue due to the effects of resuming common credit mitigation practices
0.6
3.6
The effects of customer growth
—
3.6
Other
0.1
5.4
Change in operating revenues (before cost of energy and other tracked items)
$
29.3
$
141.0
Operating revenues offset in operating expense
Higher cost of energy billed to customers
69.0
403.5
Higher tracker deferrals within operation and maintenance, depreciation, and tax
1.9
23.6
Total change in operating revenues
$
100.2
$
568.1
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
Total volumes for the three months ended September 30, 2022 are comparable to the same period in 2021.
The increase in total volumes for the nine months ended September 30, 2022 compared to the same period in 2021 is primarily attributable to the effects of colder weather.
Commodity Price Impact
Cost of energy for the Gas Distribution Operations segment is principally comprised of the cost of natural gas used while providing transportation and distribution services to customers. All of our Gas Distribution Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. These are tracked costs that are passed through directly to the customer, and the gas costs included in revenues are matched with the gas cost expense recorded in the period. The difference is recorded on the 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 and nine months ended September 30, 2022 compared to the same periods in 2021 are presented below.
Favorable (Unfavorable)
Changes in Operating Expenses (in millions)
Three Months Ended September 30, 2022 vs 2021
Nine Months Ended September 30, 2022 vs 2021
Higher outside services expenses
$
(12.4)
$
(21.0)
Higher depreciation and amortization expense
(7.5)
(23.5)
Higher environmental remediation costs
(0.2)
(3.8)
Lower NiSource Next program expenses
5.1
16.9
Lower other than income taxes primarily related to property tax expense
4.4
10.1
Lower (higher) employee and administrative related expenses
4.0
(17.9)
Lower (higher) materials and supplies expense
3.1
(4.3)
The loss on sale and expenses related to the Massachusetts Business in 2021
2.9
17.1
Property insurance settlement related to the Greater Lawrence Incident
—
105.0
Other
(6.3)
(13.9)
Change in operating expenses (before cost of energy and other tracked items)
$
(6.9)
$
64.7
Operating expenses offset in operating revenue
Higher cost of energy billed to customers
(69.0)
(403.5)
Higher 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 and nine months ended September 30, 2022 and 2021 are presented below.
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions)
2022
2021
Favorable (Unfavorable)
2022
2021
Favorable (Unfavorable)
Operating Revenues
$
516.5
$
479.1
$
37.4
$
1,384.1
$
1,285.5
$
98.6
Operating Expenses
Cost of energy
172.8
119.3
(53.5)
420.8
316.4
(104.4)
Operation and maintenance
126.5
120.5
(6.0)
367.3
366.9
(0.4)
Depreciation and amortization
88.1
83.3
(4.8)
267.0
250.4
(16.6)
Other taxes
5.8
15.6
9.8
33.9
43.9
10.0
Total Operating Expenses
393.2
338.7
(54.5)
1,089.0
977.6
(111.4)
Operating Income
$
123.3
$
140.4
$
(17.1)
$
295.1
$
307.9
$
(12.8)
Revenues
Residential
$
178.7
$
178.7
$
—
$
454.3
$
439.8
$
14.5
Commercial
158.9
151.6
7.3
428.1
404.4
23.7
Industrial
152.1
126.0
26.1
421.0
368.3
52.7
Wholesale
4.1
4.8
(0.7)
10.6
11.3
(0.7)
Other
22.7
18.0
4.7
70.1
61.7
8.4
Total
$
516.5
$
479.1
$
37.4
$
1,384.1
$
1,285.5
$
98.6
Sales (GWh)
Residential
1,080.6
1,159.4
(78.8)
2,745.2
2,785.0
(39.8)
Commercial
1,044.7
1,057.0
(12.3)
2,845.3
2,829.1
16.2
Industrial
2,076.3
2,081.0
(4.7)
6,078.8
6,295.1
(216.3)
Wholesale
4.9
37.2
(32.3)
37.0
81.7
(44.7)
Other
17.9
36.1
(18.2)
67.5
83.7
(16.2)
Total
4,224.4
4,370.7
(146.3)
11,773.8
12,074.6
(300.8)
Cooling Degree Days
592
658
(66)
934
976
(42)
Normal Cooling Degree Days
573
556
17
820
795
25
% Warmer than Normal
3
%
18
%
14
%
23
%
% Colder than 2021
(10)
%
(4)
%
Electric Customers
Residential
423,764
421,074
2,690
Commercial
58,196
57,860
336
Industrial
2,133
2,140
(7)
Wholesale
711
719
(8)
Other
3
2
1
Total
484,807
481,795
3,012
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 and nine months ended September 30, 2022 compared to the same periods in 2021 are presented below.
Favorable (Unfavorable)
Changes in Operating Revenues (in millions)
Three Months Ended September 30, 2022 vs 2021
Nine Months Ended September 30, 2022 vs 2021
PPA revenue from renewable joint venture projects, fully offset by JV operating expenses
$
3.6
$
18.3
Increased fuel handling costs
2.3
4.0
The effects of customer growth
1.3
3.8
New rates from regulatory capital and DSM programs
0.7
2.9
The effects of weather in 2022 compared to 2021
(7.5)
(4.0)
Reduction in gross receipts tax, offset in operating expenses
(6.5)
(5.9)
Decreased customer usage
(5.7)
(10.8)
FAC over earnings reserve
(3.7)
(3.7)
FAC adjustment(1)
—
(8.0)
Other
(3.4)
(2.9)
Change in operating revenues (before cost of energy and other tracked items)
$
(18.9)
$
(6.3)
Operating revenues offset in operating expense
Higher cost of energy billed to customers
53.5
104.4
Higher tracker deferrals within operation and maintenance, depreciation and tax
2.8
0.5
Total change in operating revenues
$
37.4
$
98.6
(1)See Note 6, "Regulatory Matters," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information.
Weather
In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating or cooling degree days. Our composite heating or cooling degree days reported do not directly correlate to the weather-related dollar impact on the results of Electric Operations. Heating or cooling degree days experienced during different times of the year may have more or less impact on volume and dollars depending on when they occur. When the detailed results are combined for reporting, there may be weather-related dollar impacts on operations when there is not an apparent or significant change in our aggregated composite heating or cooling degree day comparison.
Sales
The decrease in total volumes sold for the three and nine months ended September 30, 2022 compared to the same periods in 2021 was primarily attributable to decreased usage by industrial 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 and nine months ended September 30, 2022 compared to the same periods in 2021 are presented below.
Favorable (Unfavorable)
Changes in Operating Expenses (in millions)
Three Months Ended September 30, 2022 vs 2021
Nine Months Ended September 30, 2022 vs 2021
Higher outside services expenses
$
(12.5)
$
(6.1)
Renewable joint venture project expenses, offset by JV operating revenues
(6.6)
(19.6)
Reduction in gross receipts tax, offset in operating revenues
6.5
5.9
Lower employee and administrative expenses
4.3
3.0
Expenses related to the accelerated retirement of the R.M. Schahfer Generating Station's coal Units 14 and 15 in 2021
2.7
11.3
Lower (higher) depreciation and amortization expense driven by the joint venture depreciation adjustment(1)
2.0
(4.9)
Lower NiSource Next program expenses
1.9
6.2
Effects of environmental recoveries in 2021
—
(6.5)
Other
3.5
4.2
Change in operating expenses (before cost of energy and other tracked items)
$
1.8
$
(6.5)
Operating expenses offset in operating revenue
Higher cost of energy billed to customers
(53.5)
(104.4)
Higher tracker deferrals within operation and maintenance, depreciation and tax
(2.8)
(0.5)
Total change in operating expense
$
(54.5)
$
(111.4)
(1)See Note 6, "Regulatory Matters,"in the Notes to the Condensed Consolidated Financial Statements (unaudited) for additional information.
Electric Supply and Generation Transition
NIPSCO continues to execute on an electric generation transition consistent with the 2018 Plan, which outlines plans to retire its remaining coal-fired generation by 2026-2028, to be replaced by lower-cost, reliable and cleaner options. We retired R.M. Schahfer Generating Station Units 14 and 15 on October 1, 2021. The remaining two coal units, at Schahfer are currently expected to be retired by the end of 2025. See "Expected Project Delays" 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 will also continue to work with the EPA and the Indiana Department of Environmental Management to obtain administrative approvals associated with the continued operation of R.M. Schahfer’s remaining two coal units beyond 2023. These agencies are unlikely to deny approvals, but in the event that the approvals are not obtained, future operations could be impacted. We cannot estimate the financial impact on us if these approvals are not obtained.
The current replacement plan primarily includes renewable sources of energy, including wind, solar, and battery storage to be obtained through a combination of NIPSCO ownership and PPAs. NIPSCO has sold, and may in the future sell, renewable energy credits from this generation to third parties to offset customer costs. NIPSCO has executed several PPAs to purchase 100% of the output from renewable generation facilities at a fixed price per MWh. Each facility supplying the energy will have an associated nameplate capacity, and payments under the PPAs will not begin until the associated generation facility is constructed by the owner/seller. NIPSCO has also executed several BTAs with developers to construct renewable generation facilities.
Three wind projects have been placed into service, totaling approximately 804 MW of nameplate capacity. All announced projects below have received IURC approval. During 2022, NIPSCO amended certain of its BTAs and PPAs. NIPSCO is discussing potentially amending other BTAs and PPAs. Any amendments that result in increased project costs may require additional approval by the IURC in order to obtain recovery for increased costs. Our current replacement program will be augmented by the Preferred Energy Resource Plan outlined in our 2021 Integrated Resource Plan. See "Executive Summary - Your Energy, Your Future" in this Management's Discussion for additional information.
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 joint ventures whose members include NIPSCO and an unrelated tax equity partner.
Expected Project Delays. Compared to the previously disclosed targeted construction completion dates in our Annual Report on Form 10-K for the year ended December 31, 2021, we estimate delays for most projects to range from six to 18 months, resulting in the majority of our projects, and investment, being in service between 2023 and 2025. We do not currently anticipate any delays to the 2023 in-service date of our outstanding wind energy project. The expected delays and inflationary cost pressures communicated from the developers of our solar and storage projects 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., (iii) Section 201 Tariffs and (iv) persistent general global supply chain and labor availability issues. We are also monitoring potential delays communicated by the developers of our renewable energy projects related to local permitting processes and obtaining interconnection rights. Preliminary findings from the DOC Investigation, including potential tariff amounts, are expected to be released in November 2022, with a final decision expected between January 2023 and March 2023. We have received and are evaluating several notices of possible force majeure from developers in connection with solar panel availability. The resolution of these issues, including the final conclusion of the DOC Investigation will determine what additional costs or delays our solar projects will be subject to as a result of any tariffs imposed. If any of these impacts result in cost increases for certain projects, such potential impacts are expected to result in the need for us to seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects.
In June 2022, the U.S. Department of Homeland Security published its Uyghur Forced Labor Prevention Act Entity List (the "List"). None of the developers or suppliers of our renewable energy projects were named on the List. Additionally, the Biden Administration announced a 24-month tariff relief on solar panels subject to the ongoing U.S. Department of Commerce investigation and authorized the use of the Defense Production Act, to accelerate domestic production of clean energy technologies, including solar panel parts.
We, along with the developers of these generation projects, are continuously evaluating potential impacts to the targeted completion date of each project. Delays to the completion dates of our projects could also include delays in the financial return of certain investments and impact the overall timing of our electric generation transition.Although we are not currently expecting delays to extend the completion dates of our six solar and storage BTA projects beyond the currently planned sunset of investment tax credits at the end of 2025 under the existing tax laws, if such delays occur, they could impact the economic viability of the projects.
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 February 18, 2022, we amended our revolving credit agreement to, among other things, extend its term to February 18, 2027. The commercial paper program and credit facility provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves our desired capital structure. On June 10, 2022, we completed the issuance and sale of $350.0 million of 5.00% senior unsecured notes maturing in 2052, which resulted in approximately $344.6 million of net proceeds after discount and debt issuance costs. We intend to disburse an amount equal to the net proceeds of the notes to finance, in whole or in part, the acquisition of our 302 MW Indiana Crossroads Wind project and 102 MW Rosewater Wind project from the project developer. We utilize an ATM equity program that allows us to issue and sell shares of our common stock up to an aggregate issuance of $750.0 million through December 31, 2023. As of September 30, 2022, the ATM program (including the impact of the forward sale agreement) 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. On November 7, 2022, we announced that we intend to pursue the sale of a minority interest in our NIPSCO business unit.
We believe these sources provide adequate capital to fund our operating activities and capital expenditures in 2022 and beyond.
Greater Lawrence Incident. As discussed in Note 14, "Other Commitments and Contingencies," in the Notes to the Condensed Consolidated Financial Statements (unaudited), due to the inherent uncertainty of litigation, there can be no assurance that the outcome or resolution of any particular claim related to the Greater Lawrence Incident will not continue to have an adverse impact on our cash flows. Through income generated from operating activities, amounts available under the short-term revolving credit facility, and our ability to access capital markets, we believe we have adequate capital available to settle remaining anticipated claims associated with the Greater Lawrence Incident.
Operating Activities
Net cash from operating activities for the nine months ended September 30, 2022 was $1,036.2 million, an increase of $96.9 million compared to the nine months ended September 30, 2021. This increase was primarily driven by year over year increased cash inflows related to the collection of under-recovered gas and fuel costs from the prior year and increased revenues. We also received a refund in 2022 from a gas supplier that will be passed back to customers through the GCA mechanism in each affected jurisdiction. This was offset by increased cash outflows related to inventory balances year over year due to higher gas costs.
Investing Activities
Net cash used for investing activities for the nine months ended September 30, 2022 was $1,682.7 million, an increase of $288.5 million compared to the nine months ended September 30, 2021. Our current year investing activities were comprised of increased capital expenditures related to system growth and reliability and payments to a renewable generation asset developer related to the Dunn's Bridge I construction milestones, which were offset by insurance recoveries in the current year.
As we evaluate adjustments to renewable generation project timing, we remain on track to make capital investments totaling $2.4 billion to $2.7 billion during the 2022 period. We also expect to invest approximately $15.0 billion during the 2023-2027 period, included in these amounts are 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, 2021, are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates. For example, the timing and ultimate cost associated with solar and battery storage capital expenditures may vary due to the U.S. Department of Commerce's investigation into an Antidumping and Countervailing Duties circumvention claim on solar cells and panels supplied from Malaysia, Vietnam, Thailand and Cambodia. 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 2022, 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(2)
IRP - 2022
$
25.0
$
232.9
1/21-12/21
Replacement of (1) hazardous service lines, (2) cast iron, wrought iron, uncoated steel, and bare steel pipe, (3) natural gas risers prone to failure and (4) installation of AMR devices.
May 2022
Columbia of Ohio(2)
CEP - 2022
$
32.2
$
253.5
1/21-12/21
Assets not included in the IRP.
September 2022
NIPSCO - Gas(3)
TDSIC 4
$
0.5
$
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(4)
FMCA 1
$
1.5
$
14.1
10/21-3/22
Project costs to comply with federal mandates.
October 2022
Columbia of Virginia
SAVE - 2023
$
5.1
$
51.1
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
4.8
$
41.6
1/23-12/23
Replacement of mains and inclusion of system safety investments.
January 2023
Columbia of Maryland
STRIDE - 2022
$
1.3
$
17.5
1/22-12/22
Pipeline upgrades designed to improve public safety or infrastructure reliability.
January 2022
NIPSCO - Electric(5)
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
(1)Programs do not include any costs already included in base rates.
(2)The January through March 2021 investments included in these filings are also included in the pending Columbia of Ohio rate case. The infrastructure filings will be adjusted to reflect the final rate case outcome.
(3)NIPSCO Gas program incremental revenue decreased because of revisions for the Step 1 rate case compliance filing amounts included in base rates.
(4)NIPSCO filed a new certificate of public convenience and necessity on April 1, 2022 for an additional Pipeline Safety III Compliance Plan, including $235.3M in capital and $34.1M in operation and maintenance expense project investments.
(5)NIPSCO filed for a new electric TDSIC plan on June 1, 2021. An order approving NIPSCO's new electric TDSIC plan was received on December 28, 2021. NIPSCO filed its first tracker, TDSIC – 1, on March 30, 2022. An order was received and approved on July 27, 2022.
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. NIPSCO is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment through the FMCA mechanism. Refer to Note 14, "Other Commitments and Contingencies - C. Environmental Matters," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for further discussion of the CCRs.
On April 1, 2022, NIPSCO Gas filed a petition with the IURC seeking approval of NIPSCO's federally mandated costs for a Pipeline Safety III Compliance Plan. The federally mandated costs include a total estimated $228.7 million of capital costs as well as $34.1 million of operation and maintenance programs. NIPSCO Gas is requesting all associated accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism.
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 activity.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Long-Term Debt. Refer to Note 12, "Long-Term Debt," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on long-term debt.
Short-Term Debt and Sale of Trade Accounts Receivables. Refer to Note 13, "Short-Term Borrowings," in the Notes to the Condensed Consolidated Financial Statements (unaudited) for information on short-term debt activity, including sale of trade accounts receivable.
Noncontrolling Interest. Refer to Note 11, "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 September 30, 2022 and December 31, 2021:
(in millions)
September 30, 2022
December 31, 2021
Current Liquidity
Revolving Credit Facility
$
1,850.0
$
1,850.0
Accounts Receivable Programs(1)
318.2
251.2
Less:
Commercial Paper
956.0
560.0
Accounts Receivable Programs Utilized
318.2
—
Letters of Credit Outstanding Under Credit Facility
10.2
18.9
Add:
Cash and Cash Equivalents
35.8
84.2
Net Available Liquidity
$
919.6
$
1,606.5
(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%. As of September 30, 2022, 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 September 30, 2022. 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 September 30, 2022, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $67.9 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.
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 September 30, 2022, 406,049,747 shares of common stock and 1,302,500 shares of preferred stock were outstanding.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
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, 2021. Except for our June debt issuance, there were no additional material changes from year-end during the nine months ended September 30, 2022. Refer to Note 12, "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 14, "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 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 offers 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
$
98.3
$
58.5
March 30, 2021
Approved December 16, 2021
December 2021
Columbia of Maryland
10.85
%
9.65
%
$
4.8
$
2.4
May 14, 2021
Approved December 3, 2021
December 2021
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
11.50
%
10.39
%
$
87.8
$
47.1
March 3, 2008
Approved December 3, 2008
December 2008
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 Ohio(5)
10.95
%
In process
$
221.4
In process
June 30, 2021
Order Expected Q1 2023
Pending
Columbia of Pennsylvania(6)
11.20
%
In process
$
82.2
In process
March 18, 2022
Order Expected Q4 2022
December 2022
Columbia of Virginia(7)
10.75
%
In process
$
40.6
In process
April 29, 2022
Order Expected Q1 2023
Interim Rates October 2022
Columbia Gas of Maryland(8)
10.95
%
In process
$
5.5
In process
May 13, 2022
Order Expected Q4 2022
December 2022
NIPSCO - Electric(9)
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 without specifying ratemaking elements to establish the Company's revenue requirement. Pursuant to the settlement, for purposes of calculating its DSIC, Columbia of Pennsylvania shall use the equity return rate for gas utilities contained in the Pennsylvania Commission’s most recent Quarterly Report on the Earnings of Jurisdictional Utilities, including quarterly updates thereto.
(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 will be implemented in 2 steps, with implementation of step 1 rates effective in September 2022 and step 2 rates to be effective in March 2023.
(5)On October 31, 2022, certain parties to Columbia of Ohio’s rate case filed a Joint Stipulation and Recommendation for Approval of a Settlement Agreement that provides for an annual revenue increase of $68.2 million and an ROE of 9.60%.
(6)The parties to Columbia of Pennsylvania’s rate case filed a Joint Petition for Partial Settlement on September 2, 2022 for an annual revenue increase of $44.5 million. On October 4, 2022, the Administrative Law Judges issued their recommended decision to approve the Partial Settlement without modification.
(7)The revenue request including the SAVE tracker related amount is $58.2 million. Beginning October 2022, interim rates will be billed subject to refund, pending a final commission order.
(8)On September 2, 2022, the parties to Columbia of Maryland’s rate case filed a Joint Motion for Approval of Settlement Agreement that provides for an annual revenue increase of $4.8 million and an ROE of 9.65%. On November 3, 2022, the Maryland Public Service Commission issued the Judge’s Proposed Order, which recommends the acceptance of the settlement without modification. Subject to full Commission review and approval, the Proposed Order will become a final order on November 17, 2022.
(9)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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
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 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.
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.
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. 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.
Federal Policy. 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.
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 ("the 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
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Regulatory, Environmental and Safety Matters
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 and Columbia of Virginia 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. NIPSCO reached settlement with other parties in September 2022 and agreed to add a third tier to offset 25% of customer usage. Columbia of Maryland withdrew the filing from its rate case and refiled it as a separate issue on September 16, 2022.
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 2021, we had reduced Scope 1 GHG emissions by approximately 58% 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.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
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.
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 7, "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 September 30, 2022 and December 31, 2021.
Interest Rate Risk
We are exposed to interest rate risk as a result of changes in interest rates on borrowings under our revolving credit agreement, commercial paper program 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 $2.3 million and $5.0 million for the three and nine months ended September 30, 2022, and $0.4 million and $1.8 million for the three and nine months ended September 30, 2021, respectively. We are also exposed to interest rate risk as a result of changes in benchmark rates that can influence the interest rates of future 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 7, "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 September 30, 2022 and December 31, 2021.
Credit Risk
Due to the nature of the industry, credit risk is embedded in many of our business activities. Our extension of credit is governed by a Corporate Credit Risk Policy. In addition, Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by the risk management function, which is independent of commercial operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. For derivative-related contracts, credit risk arises when counterparties are obligated to deliver or purchase defined commodity units of gas or power to us at a future date per execution of contractual terms and conditions. Exposure to credit risk is measured in terms of both current obligations and the market value of forward positions net of any posted collateral such as cash and letters of credit.
We closely monitor the financial status of our banking credit providers. We evaluate the financial status of our banking partners through the use of market-based metrics such as credit default swap pricing levels, and also through traditional credit ratings provided by major credit rating agencies.
Other Information
Critical Accounting 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, 2021. There were no material changes made as of September 30, 2022.
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 14, "Other Commitments and Contingencies - B. Legal Proceedings," in the Notes to the Condensed Consolidated Financial Statements (unaudited). This information is supplemented by Note 14, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) of the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022.
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, 2021, as supplemented by the risk factor set forth in Part II, Item 1A of the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Bylaws of NiSource Inc., as amended and restated through August 9, 2022 (incorporated by reference to Exhibit 3.1 to the NiSource Inc. Form 8-K filed on August 10, 2022).
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
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(101.CAL)
Inline XBRL Calculation Linkbase Document
(101.LAB)
Inline XBRL Labels Linkbase Document
(101.PRE)
Inline XBRL Presentation Linkbase Document
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Inline XBRL Definition Linkbase Document
(104)
Cover page Interactive Data File (formatted as inline XBRL, and contained in Exhibit 101.)
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.
NiSource Inc.
(Registrant)
Date:
November 7, 2022
By:
/s/ Gunnar J. Gode
Gunnar J. Gode
Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)
