Attached files
| file | filename |
|---|---|
| EX-31.2 - EXHIBIT 31.2 - NISOURCE INC. | ni-ex312_2018930.htm |
| EX-32.2 - EXHIBIT 32.2 - NISOURCE INC. | ni-ex322_2018930.htm |
| EX-32.1 - EXHIBIT 32.1 - NISOURCE INC. | ni-ex321_2018930.htm |
| EX-31.1 - EXHIBIT 31.1 - NISOURCE INC. | ni-ex311_2018930.htm |
| EX-10.3 - EXHIBIT 10.3 - NISOURCE INC. | ni-ex103_2018930.htm |
| EX-10.2 - EXHIBIT 10.2 - NISOURCE INC. | ni-ex102_2018930.htm |
| EX-10.1 - EXHIBIT 10.1 - NISOURCE INC. | ni-ex101_2018930.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
or
¨ 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)
Delaware | 35-2108964 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
801 East 86th Avenue Merrillville, Indiana | 46410 | |
(Address of principal executive offices) | (Zip Code) | |
(877) 647-5990
(Registrant’s telephone number, including area code)
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.
Yes þ 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.)
Yes þ 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. (Check one):
Large accelerated filer þ 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 þ
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: 363,286,952 shares outstanding at October 23, 2018.
NISOURCE INC.
FORM 10-Q QUARTERLY REPORT
FOR THE QUARTER ENDED SEPTEMBER 30, 2018
Table of Contents
Page | |||
PART I | FINANCIAL INFORMATION | ||
Item 1. | Financial Statements - unaudited | ||
Item 2. | |||
Item 3. | |||
Item 4. | |||
PART II | OTHER INFORMATION | ||
Item 1. | |||
Item 1A. | |||
Item 2. | |||
Item 3. | |||
Item 4. | |||
Item 5. | |||
Item 6. | |||
2
DEFINED TERMS | |
The following is a list of frequently used abbreviations or acronyms that are found in this report: | |
NiSource Subsidiaries, Affiliates and Former Subsidiaries | |
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. |
Abbreviations and Other | |
ACE | Affordable Clean Energy |
AFUDC | Allowance for funds used during construction |
AMRP | Accelerated Main Replacement Program |
AOCI | Accumulated Other Comprehensive Income (Loss) |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
ATM | At-the-market |
CAA | Clean Air Act |
CCRs | Coal Combustion Residuals |
CEP | Capital Expenditure Program |
CERCLA | Comprehensive Environmental Response Compensation and Liability Act (also known as Superfund) |
CO2 | Carbon Dioxide |
CPP | Clean Power Plan |
DPU | Department of Public Utilities |
EGUs | Electric Utility Generating Units |
ELG | Effluent limitations guidelines |
EPA | United States Environmental Protection Agency |
EPS | Earnings per share |
FAC | Fuel adjustment clause |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | Generally Accepted Accounting Principles |
GCA | Gas cost adjustment |
GCR | Gas cost recovery |
GHG | Greenhouse gases |
GSEP | Gas System Enhancement Program |
gwh | Gigawatt hours |
IRP | Infrastructure Replacement Program |
IRS | Internal Revenue Service |
IURC | Indiana Utility Regulatory Commission |
LDCs | Local distribution companies |
LIBOR | London InterBank Offered Rate |
3
DEFINED TERMS | |
LIFO | Last In, First Out |
MGP | Manufactured Gas Plant |
MISO | Midcontinent Independent System Operator |
MMDth | Million dekatherms |
NOL | Net operating loss |
NTSB | National Transportation Safety Board |
NYMEX | New York Mercantile Exchange |
OPEB | Other Postretirement Benefits |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
PSC | Public Service Commission |
PUC | Public Utility Commission |
PUCO | Public Utilities Commission of Ohio |
Pure Air | Pure Air on the Lake LP |
RCRA | Resource Conservation and Recovery Act |
SEC | Securities and Exchange Commission |
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 |
VIE | Variable Interest Entities |
VSCC | Virginia State Corporation Commission |
WCE | Whiting Clean Energy |
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 NiSource’s 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. 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 debt obligations; any changes in our credit rating; our ability to execute our growth strategy; changes in general economic, capital and commodity market conditions; pension funding obligations; economic regulation and the impact of regulatory rate reviews; our ability to obtain expected financial or regulatory outcomes; advances in technology; any damage to our reputation; compliance with environmental laws and the costs of associated liabilities; fluctuations in demand from residential and commercial customers; economic conditions of certain industries; the success of NIPSCO's electric generation strategy; the price of energy commodities and related transportation costs; the reliability of customers and suppliers to fulfill their payment and contractual obligations; potential impairments of goodwill or definite-lived intangible assets; changes in taxation and accounting principles; potential incidents and other operating risks associated with our business; impacts from the Greater Lawrence Incident (as defined in this report) (including any changes in management's estimates or assumptions regarding financial impact, the timing and amount of insurance recoveries, the outcomes of governmental investigations, changes to state and federal legislation or regulation impacting our operating practices, and our ability to recover our costs through rates or offset them through operational or other cost savings); the impact of an aging infrastructure; the impact of climate change; potential cyber-attacks; construction risks and natural gas costs and supply risks; extreme weather conditions; the attraction and retention of a qualified workforce; the ability of our subsidiaries to generate cash; tax liabilities associated with the separation of Columbia Pipeline Group, Inc. on July 1, 2015; our ability to manage new initiatives and organizational changes; the performance of certain third-party suppliers upon which we rely; our ability to obtain sufficient insurance coverage; and other matters set forth in the “Risk Factors” section of this report and our Annual Report on Form 10-K for the fiscal year ended December
4
31, 2017, 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.
5
Index | Page |
6
PART I
ITEM 1. FINANCIAL STATEMENTS
NiSource Inc.
Condensed Statements of Consolidated Income (Loss) (unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions, except per share amounts) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Operating Revenues | |||||||||||||||
Customer revenues | $ | 855.8 | $ | 883.4 | $ | 3,555.1 | $ | 3,386.0 | |||||||
Other revenues | 39.2 | 33.6 | 97.7 | 120.3 | |||||||||||
Total Operating Revenues | 895.0 | 917.0 | 3,652.8 | 3,506.3 | |||||||||||
Operating Expenses | |||||||||||||||
Cost of sales (excluding depreciation and amortization) | 222.0 | 233.6 | 1,259.7 | 1,062.7 | |||||||||||
Operation and maintenance | 780.8 | 371.7 | 1,548.5 | 1,174.9 | |||||||||||
Depreciation and amortization | 148.5 | 143.0 | 437.8 | 428.5 | |||||||||||
Loss (Gain) on sale of assets and impairments, net | 0.7 | — | 0.4 | (0.1 | ) | ||||||||||
Other taxes | 58.9 | 57.5 | 203.3 | 189.7 | |||||||||||
Total Operating Expenses | 1,210.9 | 805.8 | 3,449.7 | 2,855.7 | |||||||||||
Operating Income (Loss) | (315.9 | ) | 111.2 | 203.1 | 650.6 | ||||||||||
Other Income (Deductions) | |||||||||||||||
Interest expense, net | (83.4 | ) | (87.9 | ) | (265.2 | ) | (260.8 | ) | |||||||
Other, net | (1.7 | ) | (6.8 | ) | 42.4 | (0.3 | ) | ||||||||
Loss on early extinguishment of long-term debt | (33.0 | ) | — | (45.5 | ) | (111.5 | ) | ||||||||
Total Other Deductions, Net | (118.1 | ) | (94.7 | ) | (268.3 | ) | (372.6 | ) | |||||||
Income (Loss) before Income Taxes | (434.0 | ) | 16.5 | (65.2 | ) | 278.0 | |||||||||
Income Taxes | (94.5 | ) | 2.5 | (26.3 | ) | 97.1 | |||||||||
Net Income (Loss) | (339.5 | ) | 14.0 | (38.9 | ) | 180.9 | |||||||||
Preferred dividends | (5.6 | ) | — | (6.9 | ) | — | |||||||||
Net Income (Loss) Available to Common Shareholders | (345.1 | ) | 14.0 | (45.8 | ) | 180.9 | |||||||||
Earnings (Loss) Per Share | |||||||||||||||
Basic Earnings (Loss) Per Share | $ | (0.95 | ) | $ | 0.04 | $ | (0.13 | ) | $ | 0.55 | |||||
Diluted Earnings (Loss) Per Share | $ | (0.95 | ) | $ | 0.04 | $ | (0.13 | ) | $ | 0.55 | |||||
Dividends Declared Per Common Share | $ | 0.195 | $ | 0.175 | $ | 0.780 | $ | 0.700 | |||||||
Basic Average Common Shares Outstanding | 363.9 | 331.1 | 352.1 | 326.7 | |||||||||||
Diluted Average Common Shares | 363.9 | 332.4 | 352.1 | 328.0 | |||||||||||
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
7
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Condensed Statements of Consolidated Comprehensive Income (Loss) (unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions, net of taxes) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Net Income (Loss) | $ | (339.5 | ) | $ | 14.0 | $ | (38.9 | ) | $ | 180.9 | |||||
Other comprehensive income (loss): | |||||||||||||||
Net unrealized gain (loss) on available-for-sale securities(1) | 0.1 | 0.1 | (2.3 | ) | 1.1 | ||||||||||
Net unrealized gain (loss) on cash flow hedges(2) | 22.5 | (9.3 | ) | 56.5 | (21.2 | ) | |||||||||
Unrecognized pension and OPEB benefit(3) | 0.8 | 1.1 | 1.2 | 1.5 | |||||||||||
Total other comprehensive income (loss) | 23.4 | (8.1 | ) | 55.4 | (18.6 | ) | |||||||||
Comprehensive Income (Loss) | $ | (316.1 | ) | $ | 5.9 | $ | 16.5 | $ | 162.3 | ||||||
(1) Net unrealized gain (loss) on available-for-sale securities, net of zero tax expense in the third quarter of 2018 and 2017, and $0.6 million tax benefit and $0.6 million tax expense for the nine months ended 2018 and 2017, respectively.
(2) Net unrealized gain (loss) on cash flow hedges, net of $7.5 million tax expense and $5.8 million tax benefit in the third quarter of 2018 and 2017, respectively, and $18.7 million tax expense and $13.1 million tax benefit for the nine months ended 2018 and 2017, respectively. See Note 8, "Risk Management Activities," for additional information.
(3) Unrecognized pension and OPEB benefit, net of zero and $0.5 million tax expense in the third quarter of 2018 and 2017, respectively, and $0.2 million and $0.8 million tax expense for the nine months ended 2018 and 2017, respectively.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
8
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc. Condensed Consolidated Balance Sheets (unaudited) | |||||||
(in millions) | September 30, 2018 | December 31, 2017 | |||||
ASSETS | |||||||
Property, Plant and Equipment | |||||||
Utility plant | $ | 22,328.2 | $ | 21,026.6 | |||
Accumulated depreciation and amortization | (7,171.0 | ) | (6,953.6 | ) | |||
Net utility plant | 15,157.2 | 14,073.0 | |||||
Other property, at cost, less accumulated depreciation | 17.2 | 286.5 | |||||
Net Property, Plant and Equipment | 15,174.4 | 14,359.5 | |||||
Investments and Other Assets | |||||||
Unconsolidated affiliates | 2.6 | 5.5 | |||||
Other investments | 214.5 | 204.1 | |||||
Total Investments and Other Assets | 217.1 | 209.6 | |||||
Current Assets | |||||||
Cash and cash equivalents | 41.8 | 29.0 | |||||
Restricted cash | 12.0 | 9.4 | |||||
Accounts receivable (less reserve of $13.0 and $18.3, respectively) | 500.4 | 898.9 | |||||
Gas inventory | 320.2 | 285.1 | |||||
Materials and supplies, at average cost | 97.7 | 105.9 | |||||
Electric production fuel, at average cost | 49.0 | 80.1 | |||||
Exchange gas receivable | 37.3 | 45.8 | |||||
Regulatory assets | 221.0 | 176.3 | |||||
Prepayments and other | 89.7 | 132.8 | |||||
Total Current Assets | 1,369.1 | 1,763.3 | |||||
Other Assets | |||||||
Regulatory assets | 1,907.4 | 1,624.9 | |||||
Goodwill | 1,690.7 | 1,690.7 | |||||
Intangible assets, net | 223.5 | 231.7 | |||||
Deferred charges and other | 117.2 | 82.0 | |||||
Total Other Assets | 3,938.8 | 3,629.3 | |||||
Total Assets | $ | 20,699.4 | $ | 19,961.7 | |||
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
9
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc. Condensed Consolidated Balance Sheets (unaudited) (continued) | |||||||
(in millions, except share amounts) | September 30, 2018 | December 31, 2017 | |||||
CAPITALIZATION AND LIABILITIES | |||||||
Capitalization | |||||||
Stockholders’ Equity | |||||||
Common stock - $0.01 par value, 400,000,000 shares authorized; 363,167,067 and 337,015,806 shares outstanding, respectively | $ | 3.7 | $ | 3.4 | |||
Preferred stock - $1,000 par value, 20,000,000 shares authorized; 400,000 shares outstanding | 393.9 | — | |||||
Treasury stock | (99.9 | ) | (95.9 | ) | |||
Additional paid-in capital | 6,161.0 | 5,529.1 | |||||
Retained deficit | (1,387.5 | ) | (1,073.1 | ) | |||
Accumulated other comprehensive income (loss) | 2.5 | (43.4 | ) | ||||
Total Stockholders’ Equity | 5,073.7 | 4,320.1 | |||||
Long-term debt, excluding amounts due within one year | 7,094.5 | 7,512.2 | |||||
Total Capitalization | 12,168.2 | 11,832.3 | |||||
Current Liabilities | |||||||
Current portion of long-term debt | 48.6 | 284.3 | |||||
Short-term borrowings | 1,611.0 | 1,205.7 | |||||
Accounts payable | 433.7 | 625.6 | |||||
Dividends payable - common stock | 70.8 | — | |||||
Dividends payable - preferred stock | 11.6 | — | |||||
Customer deposits and credits | 238.4 | 262.6 | |||||
Taxes accrued | 150.0 | 208.1 | |||||
Interest accrued | 108.0 | 112.3 | |||||
Risk management liabilities | 4.8 | 43.2 | |||||
Exchange gas payable | 58.2 | 59.6 | |||||
Regulatory liabilities | 81.9 | 58.7 | |||||
Legal and environmental | 20.4 | 32.1 | |||||
Accrued compensation and employee benefits | 153.4 | 195.4 | |||||
Claims accrued | 365.9 | 12.5 | |||||
Other accruals | 54.5 | 78.3 | |||||
Total Current Liabilities | 3,411.2 | 3,178.4 | |||||
Other Liabilities | |||||||
Risk management liabilities | 45.2 | 28.5 | |||||
Deferred income taxes | 1,291.7 | 1,292.9 | |||||
Deferred investment tax credits | 11.7 | 12.4 | |||||
Accrued insurance liabilities | 81.8 | 80.1 | |||||
Accrued liability for postretirement and postemployment benefits | 300.9 | 337.1 | |||||
Regulatory liabilities | 2,826.8 | 2,736.9 | |||||
Asset retirement obligations | 346.9 | 268.7 | |||||
Other noncurrent liabilities | 215.0 | 194.4 | |||||
Total Other Liabilities | 5,120.0 | 4,951.0 | |||||
Commitments and Contingencies (Refer to Note 16, "Other Commitments and Contingencies") | — | — | |||||
Total Capitalization and Liabilities | $ | 20,699.4 | $ | 19,961.7 | |||
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
10
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc. Condensed Statements of Consolidated Cash Flows (unaudited) | |||||||
Nine Months Ended September 30, (in millions) | 2018 | 2017 | |||||
Operating Activities | |||||||
Net Income (Loss) | $ | (38.9 | ) | $ | 180.9 | ||
Adjustments to Reconcile Net Income to Net Cash from Operating Activities: | |||||||
Loss on early extinguishment of debt | 45.5 | 111.5 | |||||
Depreciation and amortization | 437.8 | 428.5 | |||||
Deferred income taxes and investment tax credits | (26.4 | ) | 96.3 | ||||
Other adjustments | 15.6 | 28.5 | |||||
Changes in Assets and Liabilities: | |||||||
Components of working capital | 442.9 | 32.6 | |||||
Regulatory assets/liabilities | 61.3 | (12.9 | ) | ||||
Postretirement and postemployment benefits | (41.4 | ) | (314.5 | ) | |||
Deferred charges and other noncurrent assets | 0.8 | (3.7 | ) | ||||
Other noncurrent liabilities | 30.0 | (17.6 | ) | ||||
Net Cash Flows from Operating Activities | 927.2 | 529.6 | |||||
Investing Activities | |||||||
Capital expenditures | (1,296.6 | ) | (1,216.4 | ) | |||
Cost of removal | (72.6 | ) | (78.9 | ) | |||
Purchases of available-for-sale securities | (71.4 | ) | (139.4 | ) | |||
Sales of available-for-sale securities | 58.5 | 129.4 | |||||
Other investing activities | 5.6 | (1.4 | ) | ||||
Net Cash Flows used for Investing Activities | (1,376.5 | ) | (1,306.7 | ) | |||
Financing Activities | |||||||
Issuance of long-term debt | 350.0 | 2,750.0 | |||||
Repayments of long-term debt and capital lease obligations | (1,044.0 | ) | (1,352.4 | ) | |||
Premiums and other debt related costs | (46.1 | ) | (139.8 | ) | |||
Issuance of short-term debt (maturity > 90 days) | 600.0 | — | |||||
Change in short-term borrowings, net (maturity ≤ 90 days) | (194.6 | ) | (644.9 | ) | |||
Issuance of common stock | 611.6 | 332.6 | |||||
Issuance of preferred stock | 394.3 | — | |||||
Acquisition of treasury stock | (4.0 | ) | (5.9 | ) | |||
Dividends paid - common stock | (202.5 | ) | (170.2 | ) | |||
Net Cash Flows from Financing Activities | 464.7 | 769.4 | |||||
Change in cash, cash equivalents and restricted cash | 15.4 | (7.7 | ) | ||||
Cash, cash equivalents and restricted cash at beginning of period | 38.4 | 36.0 | |||||
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 53.8 | $ | 28.3 | |||
Supplemental Disclosures of Cash Flow Information
Nine Months Ended September 30, (in millions) | 2018 | 2017 | |||||
Non-cash transactions: | |||||||
Capital expenditures included in current liabilities | $ | 167.5 | $ | 219.1 | |||
Dividends declared but not paid | 82.4 | 58.9 | |||||
Reclassification of other property to regulatory assets(1) | 245.3 | — | |||||
Change in estimated costs of asset retirement obligations(2) | $ | 70.7 | $ | — | |||
(1)See Note 16-D "Other Matters" for additional information.
(2)See Note 6 "Asset Retirement Obligations" for additional information.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
11
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Condensed Statements of Consolidated Equity (unaudited)
(in millions) | Common Stock | Preferred Stock | Treasury Stock | Additional Paid-In Capital | Retained Deficit | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||
Balance as of January 1, 2018 | $ | 3.4 | $ | — | $ | (95.9 | ) | $ | 5,529.1 | $ | (1,073.1 | ) | $ | (43.4 | ) | $ | 4,320.1 | ||||||||||
Comprehensive Income: | |||||||||||||||||||||||||||
Net Loss | — | — | — | — | (38.9 | ) | — | (38.9 | ) | ||||||||||||||||||
Other comprehensive income, net of tax | — | — | — | — | — | 55.4 | 55.4 | ||||||||||||||||||||
Common stock dividends ($0.78 per share) | — | — | — | — | (273.4 | ) | — | (273.4 | ) | ||||||||||||||||||
Preferred stock dividends ($28.88 per share) | — | — | — | — | (11.6 | ) | — | (11.6 | ) | ||||||||||||||||||
Treasury stock acquired | — | — | (4.0 | ) | — | — | — | (4.0 | ) | ||||||||||||||||||
Cumulative effect of change in accounting principle(1) | — | — | — | — | 9.5 | (9.5 | ) | — | |||||||||||||||||||
Stock issuances: | |||||||||||||||||||||||||||
Common stock - private placement(2) | 0.3 | — | — | 599.3 | — | — | 599.6 | ||||||||||||||||||||
Preferred stock(2) | — | 393.9 | — | — | — | — | 393.9 | ||||||||||||||||||||
Employee stock purchase plan | — | — | — | 4.2 | — | — | 4.2 | ||||||||||||||||||||
Long-term incentive plan | — | — | — | 11.5 | — | — | 11.5 | ||||||||||||||||||||
401(k) and profit sharing | — | — | — | 16.9 | — | — | 16.9 | ||||||||||||||||||||
Balance as of September 30, 2018 | $ | 3.7 | $ | 393.9 | $ | (99.9 | ) | $ | 6,161.0 | $ | (1,387.5 | ) | $ | 2.5 | $ | 5,073.7 | |||||||||||
(1) See Note 2, "Recent Accounting Pronouncements," for additional information.
(2) See Note 5, "Equity," for additional information.
Preferred | Common | ||||||||||
(in thousands) | Shares | Shares | Treasury | Outstanding | |||||||
Balance as of January 1, 2018 | — | 340,813 | (3,797 | ) | 337,016 | ||||||
Treasury Stock acquired | — | — | (166 | ) | (166 | ) | |||||
Issued: | |||||||||||
Common stock - private placement(1) | — | 24,964 | — | 24,964 | |||||||
Preferred stock(1) | 400 | — | — | — | |||||||
Employee stock purchase plan | — | 166 | — | 166 | |||||||
Long-term incentive plan | — | 499 | — | 499 | |||||||
401(k) and profit sharing | — | 688 | — | 688 | |||||||
Balance as of September 30, 2018 | 400 | 367,130 | (3,963 | ) | 363,167 | ||||||
(1) See Note 5, "Equity," for additional information.
The accompanying Notes to Condensed Consolidated Financial Statements (unaudited) are an integral part of these statements.
12
Table of Contents
ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited)
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 contain our accounts and that of our majority-owned or controlled subsidiaries.
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, 2017. 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:
Standard | Description | Effective Date | Effect on the financial statements or other significant matters |
ASU 2018-14, Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans | The pronouncement modifies the disclosure requirements for defined benefit pension or other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. | Annual periods ending after December 15, 2020. Early adoption is permitted. | We are currently evaluating the effects of this pronouncement on our Notes to Condensed Consolidated Financial Statements (unaudited), including potential early adoption in the fourth quarter of 2018. |
ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) | The pronouncement changes the impairment model for most financial assets, replacing the current "incurred loss" model. ASU 2016-13 will require the use of an "expected loss" model for instruments measured at amortized cost. It will also require entities to record allowances for available-for-sale debt securities rather than impair the carrying amount of the securities. Subsequent improvements to the estimated credit losses of available-for-sale securities will be recognized immediately in earnings instead of over time as they are under historic guidance. | Annual periods beginning after December 15, 2019, including interim periods therein. Early adoption is permitted for annual or interim periods beginning after December 15, 2018. | We maintain investments in U.S. Treasury, corporate and mortgage-backed debt securities, which are pledged as collateral for trust accounts related to our wholly-owned insurance company. These debt securities are classified as available for sale. We are currently evaluating the impact of adoption, if any, on our Condensed Consolidated Financial Statements (unaudited) and Notes to Condensed Consolidated Financial Statements (unaudited). |
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Standard | Description | Effective Date | Effect on the financial statements or other significant matters |
ASU 2018-11, Leases (Topic 842): Targeted Improvements | The pronouncement allows entities the option to initially apply ASC 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. | Annual periods beginning after December 15, 2018, including interim periods therein. Early adoption is permitted. | We are the lessee for substantially all of our current leasing activity. Upon adopting ASC 842 we will begin recognizing right-of-use assets and liabilities associated with operating leases (other than short term operating leases) on our Condensed Consolidated Balance Sheets (unaudited). The impact of this change on the balance sheet is not reasonably estimable at this time. We do not anticipate the adoption of ASC 842 will have a material impact to our results of operations or cash flows. We have undertaken efforts to outline mock footnote disclosures intended to satisfy ASC 842’s disclosure requirements, which will enhance our disclosures on lease accounting policies and elections. We are implementing a new lease accounting system, which we will utilize to capture, track, and account for lease data. The new system will also aid in automating the compilation of disclosure information. We expect to conclude final system tests in the fourth quarter of 2018, with full system implementation prior to the effective date of these standards. ASC 842 provides lessees the option of electing an accounting policy, by class of underlying asset, in which the lessee may choose not to separate nonlease components from lease components. We currently anticipate adopting this practical expedient for certain classes of leases. Further, we will elect the "practical expedient package" described in ASC 842-10-65-1. We maintain a substantial number of easements and will also elect the provisions of ASU 2018-01 to ease the process of implementing ASC 842. Lastly, we anticipate electing the transition method provided in ASU 2018-11 when we adopt these standards effective January 1, 2019. |
ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 | The pronouncement offers a practical expedient for accounting for land easements under ASU 2016-02. This practical expedient allows an entity the option of not evaluating existing land easements under ASC 842. New or modified land easements will still require evaluation under ASC 842 on a prospective basis beginning on the date of adoption. | ||
ASU 2016-02, Leases (Topic 842) | The pronouncement introduces a lessee model that brings most leases on the balance sheet. The standard requires that lessees recognize the following for all leases (with the exception of short-term leases, as that term is defined in the standard) at the lease commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. | ||
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Recently Adopted Accounting Pronouncements
Standard | Adoption |
ASU 2018-15, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract | In August 2018, the FASB issued this ASU, which amends current guidance to align the accounting for costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs associated with developing or obtaining internal-use software. We elected to early adopt the ASU on a prospective basis, effective October 1, 2018. As a result of adopting this ASU, we will defer onto the balance sheet those up-front implementation costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution. |
ASU 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income | We adopted this ASU effective March 31, 2018. Upon adoption, $9.5 million of tax effects that were stranded in accumulated other comprehensive income (loss) as a result of the implementation of the TCJA were reclassified to retained deficit. This change is reflected on our Condensed Statements of Consolidated Equity (unaudited). |
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) | We adopted this ASU effective January 1, 2018. The adoption of this standard did not have a material impact on our Condensed Consolidated Financial Statements (unaudited) or Notes to Condensed Consolidated Financial Statements (unaudited). |
ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients | See Note 3, "Revenue Recognition," for our discussion of the effects of implementing these standards. |
ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations | |
ASU 2014-09, Revenue from Contracts with Customers (Topic 606) | |
We also adopted ASU 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, effective January 1, 2018. We continue to present the service cost component of net periodic benefit cost within "Operation and maintenance;" however, other components of the net periodic benefit cost (including regulatory deferrals and settlement charges) are now presented separately within "Other, net" on our Condensed Statements of Consolidated Income (Loss) (unaudited).
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Changes in income statement presentation were implemented on a retrospective basis. The impact of this ASU on previously issued annual financial statements is summarized in the tables below:
Year Ended December 31, 2016 (in millions) | As Previously Reported | Effect of Change(1) | As Adjusted | |||||||||
Operation and maintenance | $ | 1,453.7 | $ | (7.9 | ) | $ | 1,445.8 | |||||
Total Operating Expenses | 3,634.3 | (7.9 | ) | 3,626.4 | ||||||||
Operating Income | 858.2 | 7.9 | 866.1 | |||||||||
Other Income (Deductions) | ||||||||||||
Other, net | 1.5 | (7.9 | ) | (6.4 | ) | |||||||
Total Other Deductions | (348.0 | ) | (7.9 | ) | (355.9 | ) | ||||||
Income before Income Taxes | $ | 510.2 | $ | — | $ | 510.2 | ||||||
(1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $4.3 million, $(9.8) million, and $(2.4) million, respectively.
Year Ended December 31, 2017 (in millions) | As Previously Reported | Effect of Change(1) | As Adjusted | |||||||||
Operation and maintenance | $ | 1,612.3 | $ | (10.6 | ) | $ | 1,601.7 | |||||
Total Operating Expenses | 3,964.0 | (10.6 | ) | 3,953.4 | ||||||||
Operating Income | 910.6 | 10.6 | 921.2 | |||||||||
Other Income (Deductions) | ||||||||||||
Other, net | (2.8 | ) | (10.6 | ) | (13.4 | ) | ||||||
Total Other Deductions | (467.5 | ) | (10.6 | ) | (478.1 | ) | ||||||
Income before Income Taxes | $ | 443.1 | $ | — | $ | 443.1 | ||||||
(1) The effect of this change is attributable to our business segments: Gas Distribution Operations, Electric Operations, and Corporate and Other in the amounts of $(4.4) million, $(2.6) million, and $(3.6) million, respectively.
3. Revenue Recognition
ASC 606 Adoption. In 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASC 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (ASC 606): Principal versus Agent Considerations, and ASU 2016-12, Revenue from Contracts with Customers (ASC 606): Narrow-Scope Improvements and Practical Expedients. We adopted the provisions of ASC 606 beginning on January 1, 2018 using a modified retrospective method, which was applied to all contracts. No material adjustments were made to January 1, 2018 opening balances as a result of the adoption. As required under the modified retrospective method of adoption, results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC 605.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The table below provides results for the three and nine months ended September 30, 2018 as if they had been prepared under historic accounting guidance. We included operating revenue information for the three and nine months ended September 30, 2017 for comparability.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Operating Revenues | |||||||||||||||
Gas Distribution | $ | 232.3 | $ | 239.4 | $ | 1,600.3 | $ | 1,403.0 | |||||||
Gas Transportation | 186.0 | 191.6 | 745.2 | 735.1 | |||||||||||
Electric | 476.2 | 485.8 | 1,304.4 | 1,365.5 | |||||||||||
Other | 0.5 | 0.2 | 2.9 | 2.7 | |||||||||||
Total Operating Revenues | $ | 895.0 | $ | 917.0 | $ | 3,652.8 | $ | 3,506.3 | |||||||
Beginning in 2018 with the adoption of ASC 606, the Condensed Statements of Consolidated Income (Loss) (unaudited) disaggregates “Customer revenues” (i.e. ASC 606 Revenues) from “Other revenues,” both of which are discussed in more detail below.
Customer Revenues. Substantially all of our revenues are tariff-based, which we have concluded is within the scope of ASC 606. Under ASC 606, the recipients of our utility service meet the definition of a customer, while the operating company tariffs represent an agreement that meets the definition of a contract. ASC 606 defines a contract as an agreement between two or more parties, in this case us and the customer, which creates enforceable rights and obligations. In order to be considered a contract, we have determined that it is probable that substantially all of the consideration to which we are entitled from customers will be collected upon satisfaction of performance obligations. We maintain common utility credit risk mitigation practices, including requiring deposits and actively pursuing collection of past due amounts. In addition, our regulated operations utilize certain regulatory mechanisms that facilitate recovery of bad debt costs within tariff-based rates, which provides further evidence of collectibility.
We have identified our performance obligations created under tariff-based sales as 1) the commodity (natural gas or electricity, which includes generation and capacity) and 2) delivery. These commodities are sold and / or delivered to and generally consumed by customers simultaneously, leading to satisfaction of our performance obligations over time as gas or electricity is delivered to customers. Due to the at-will nature of utility customers, performance obligations are limited to the services requested and received to date. Once complete, we generally maintain no additional performance obligations.
Transaction prices for each performance obligation are generally prescribed by each operating company’s respective tariff. Rates include provisions to adjust billings for fluctuations in fuel and purchased power costs and cost of natural gas. Revenues are adjusted for differences between actual costs subject to reconciliation and the amounts billed in current rates. Under or over recovered revenues related to these cost recovery mechanisms are included in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets (unaudited) and are recovered from or returned to customers through adjustments to tariff rates. As we provide and deliver service to customers, revenue is recognized based on the transaction price allocated to each performance obligation. In general, revenue recognized from tariff-based sales is equivalent to the value of natural gas or electricity supplied and billed each period, in addition to an estimate for deliveries completed during the period but not yet billed to the customer.
In addition to tariff-based sales, our Gas Distribution Operations segment enters into balancing and exchange arrangements of natural gas as part of our operations and off-system sales programs. We have concluded that these sales are within the scope of ASC 606. Performance obligations for these types of sales include transportation and storage of natural gas and can be satisfied at a point in time or over a period of time, depending on the specific transaction. For those transactions that span a period of time, we record a receivable or payable for any cumulative gas imbalances, as well as for any gas inventory borrowed or lent under a Gas Distributions Operations exchange agreement.
Revenue Disaggregation and Reconciliation. We disaggregate revenue from contracts with customers based upon reportable segment as well as by customer class. As our revenues are primarily earned over a period of time, and we do not earn a material amount of revenues at a point in time, revenues are not disaggregated as such below. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia,
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The table below reconciles revenue disaggregation by customer class to segment revenue as well as to revenues reflected on the Condensed Statements of Consolidated Income (Loss) (unaudited):
Three Months Ended September 30, 2018 (in millions) | Gas Distribution Operations | Electric Operations | Corporate and Other | Total | |||||||||||
Customer Revenues(1) | |||||||||||||||
Residential | $ | 257.0 | $ | 154.7 | $ | — | $ | 411.7 | |||||||
Commercial | 80.9 | 140.7 | — | 221.6 | |||||||||||
Industrial | 39.0 | 153.6 | — | 192.6 | |||||||||||
Off-system | 20.4 | — | — | 20.4 | |||||||||||
Miscellaneous | 9.2 | 0.1 | 0.2 | 9.5 | |||||||||||
Total Customer Revenues | $ | 406.5 | $ | 449.1 | $ | 0.2 | $ | 855.8 | |||||||
Other Revenues | 12.1 | 27.1 | — | 39.2 | |||||||||||
Total Operating Revenues | $ | 418.6 | $ | 476.2 | $ | 0.2 | $ | 895.0 | |||||||
(1) Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.
Nine Months Ended September 30, 2018 (in millions) | Gas Distribution Operations | Electric Operations | Corporate and Other | Total | |||||||||||
Customer Revenues(1) | |||||||||||||||
Residential | $ | 1,540.3 | $ | 382.3 | $ | — | $ | 1,922.6 | |||||||
Commercial | 516.2 | 374.2 | — | 890.4 | |||||||||||
Industrial | 161.3 | 468.1 | — | 629.4 | |||||||||||
Off-system | 63.6 | — | — | 63.6 | |||||||||||
Miscellaneous | 36.2 | 12.3 | 0.6 | 49.1 | |||||||||||
Total Customer Revenues | $ | 2,317.6 | $ | 1,236.9 | $ | 0.6 | $ | 3,555.1 | |||||||
Other Revenues | 30.2 | 67.5 | — | 97.7 | |||||||||||
Total Operating Revenues | $ | 2,347.8 | $ | 1,304.4 | $ | 0.6 | $ | 3,652.8 | |||||||
(1) Customer revenue amounts exclude intersegment revenues. See Note 19, "Business Segment Information," for discussion of intersegment revenues.
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. The opening and closing balances of customer receivables for the nine months ended September 30, 2018 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.
(in millions) | Customer Accounts Receivable, Billed (less reserve)(1) | Customer Accounts Receivable, Unbilled (less reserve)(2) | |||||
Balance as of December 31, 2017 | $ | 477.0 | $ | 356.0 | |||
Balance as of September 30, 2018 | 297.2 | 154.8 | |||||
Increase (Decrease) | $ | (179.8 | ) | $ | (201.2 | ) | |
(1) Customer billed receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.
(2) Customer unbilled receivables decreased over the period due to the expected seasonal decrease in customer usage in September when compared to December.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Utility revenues are billed to customers monthly on a cycle basis. We generally expect that substantially all customer accounts receivable will be collected within the month following customer billing, as this revenue consists primarily of monthly, tariff-based billings for service and usage.
Other Revenues. As permitted by accounting principles generally accepted in the United States, regulated utilities have the ability to earn certain types of revenue that are outside the scope of ASC 606. These revenues primarily represent revenue earned under Alternative Revenue Programs. Alternative Revenue Programs represent regulator-approved programs that allow for the adjustment of billings and revenue for certain broad, external factors, or for additional billings if the entity achieves certain objectives, such as a specified reduction of costs. We maintain a variety of these programs, including demand side management initiatives that recover costs associated with the implementation of energy efficiency programs, as well as normalization programs that adjust revenues for the effects of weather or other external factors. Additionally, we maintain certain programs with future test periods that operate similarly to FERC formula rate programs and allow for recovery of costs incurred to replace aging infrastructure. When the criteria to recognize Alternative Revenue have been met, we establish a regulatory asset and present revenue from Alternative Revenue Programs on the Condensed Statements of Consolidated Income (Loss) (unaudited) as “Other revenues.” When amounts previously recognized under Alternative Revenue accounting guidance are billed, we reduce the regulatory asset and record a customer account receivable.
4. Earnings Per Share
Basic EPS is computed by dividing net income available to common shareholders by the weighted-average number of shares of common stock outstanding for the period. The weighted-average shares outstanding for diluted EPS includes the incremental effects of the various long-term incentive compensation plans. The computation of diluted average common shares for the three and nine months ended September 30, 2018 is not presented since we had a net loss on the Condensed Statements of Consolidated Income (Loss) (unaudited) during the periods, and any incremental shares would have had an anti-dilutive impact on EPS. The computation of diluted average common shares is as follows:
Three Months Ended | Nine Months Ended | |||||
September 30, | September 30, | |||||
(in thousands) | 2017 | 2017 | ||||
Denominator | ||||||
Basic average common shares outstanding | 331,139 | 326,662 | ||||
Dilutive potential common shares: | ||||||
Shares contingently issuable under employee stock plans | 604 | 503 | ||||
Shares restricted under employee stock plans | 653 | 866 | ||||
Diluted Average Common Shares | 332,396 | 328,031 | ||||
5. Equity
ATM Program and Forward Sale Agreement. On May 3, 2017, we entered into four separate equity distribution agreements, pursuant to which we may sell, from time to time, up to an aggregate of $500.0 million of our common stock. As of September 30, 2018, the ATM program (including impacts of forward sales agreements discussed below) had $10.0 million of equity available for issuance. The program expires on December 31, 2018. The following table summarizes our activity under the ATM Program:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Number of shares issued | — | 10,612,915 | — | 11,931,376 | |||||||||||
Average price per share | $ | — | $ | 26.67 | $ | — | $ | 26.58 | |||||||
Proceeds, net of fees (in millions) | $ | — | $ | 281.0 | $ | — | $ | 314.7 | |||||||
On November 13, 2017, under the ATM program, we executed a forward agreement, which allows us to issue a fixed number of shares at a price to be settled in the future. From November 13, 2017 to December 8, 2017, 6,345,860 shares were borrowed from third parties and sold by the dealer at a weighted average price of $27.24 per share. We may settle this agreement in shares, cash, or net shares by November 12, 2018. Had we settled all 6,345,860 shares under the forward agreement at September 30, 2018, we
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
would have received approximately $168.7 million, based on a net price of $26.59 per share.
Private Placement of Common Stock. On May 4, 2018, we completed the sale of 24,964,163 shares of $0.01 par value common stock at a price of $24.28 per share in a private placement to selected institutional and accredited investors. The private placement resulted in $606.0 million of gross proceeds or $599.6 million of net proceeds, after deducting commissions and sale expenses. The common stock issued in connection with the private placement was registered on Form S-1, filed with the SEC on May 11, 2018.
Private Placement of Preferred Stock. On June 11, 2018, we completed the sale of 400,000 shares of 5.650% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "Series A Preferred Stock") at a price of $1,000 per share. The transaction resulted in $400.0 million of gross proceeds or $393.9 million of net proceeds, after deducting commissions and sales expenses. The Series A Preferred Stock was issued in a private placement pursuant to SEC Rule 144A. We agreed pursuant to a registration rights agreement to file with the SEC a registration statement enabling holders to exchange their unregistered shares of Series A Preferred Stock for publicly registered shares with substantially identical terms.
Proceeds from the issuance of the Series A Preferred Stock were used to pay a portion of the notes tendered in June 2018 and the redemption of the remaining notes in July 2018. See Note 14, “Long-term Debt” for additional information regarding the tender offer and redemption.
Dividends on the Series A Preferred Stock accrue and are cumulative from the date the shares of Series A Preferred Stock were originally issued to, but not including, June 15, 2023 at a rate of 5.650% per annum of the $1,000 liquidation preference per share. On and after June 15, 2023, dividends on the Series A Preferred Stock will accumulate for each five year period at a percentage of the $1,000 liquidation preference equal to the five-year U.S. Treasury Rate plus (i) in respect of each five year period commencing on or after June 15, 2023 but before June 15, 2043, a spread of 2.843% (the “Initial Margin”), and (ii) in respect of each five year period commencing on or after June 15, 2043, the Initial Margin plus 1.000%. The Series A Preferred Stock may be redeemed by us at our option on June 15, 2023, or on each date falling on the fifth anniversary thereafter, or in connection with a ratings event (as defined in the Certificate of Designation of the Series A Preferred Stock).
Holders of Series A Preferred Stock generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to our certificate of incorporation that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series A Preferred Stock, (ii) the creation or issuance of any security ranking on a parity with the Series A Preferred Stock if the cumulative dividends payable on then outstanding Series A Preferred Stock are in arrears, or (iii) the creation or issuance of any security ranking senior to the Series A Preferred Stock. The Series A Preferred Stock does not have a stated maturity and is not subject to mandatory redemption or any sinking fund. The Series A Preferred Stock will remain outstanding indefinitely unless repurchased or redeemed by us. Any such redemption would be effected only out of funds legally available for such purposes and will be subject to compliance with the provisions of our outstanding indebtedness.
6. Asset Retirement Obligations
During 2018, we made revisions to the estimated costs associated with refining the CCR compliance plan. The CCR rule requires the continued collection of data over time to determine the specific compliance solution. The change in estimated costs resulted in an increase to the asset retirement obligation liability of $70.7 million that was recorded in 2018. See Note 16-C, "Environmental Matters," for additional information on CCRs.
7. Regulatory Matters
Gas Distribution Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Gas Distribution Operations 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 the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.
Certain operating costs of our distribution companies are significant, recurring in nature and generally outside the control of the distribution companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the distribution companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders and bad debt recovery mechanisms.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
A portion of the distribution companies' 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 permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.
Certain of our distribution companies have completed rate proceedings involving infrastructure replacement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each LDC's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.
Columbia of Ohio. On January 10, 2018, the PUCO issued an entry to investigate the impacts of the TCJA including an invitation to utilities and other interested stakeholders to file public comments including: (1) those components of utility rates that the PUCO will need to reconcile with the TCJA; and (2) the process and mechanics for how the PUCO should do so. The PUCO also directed utilities to record a regulatory liability for the estimated reduction in federal income tax resulting from the TCJA. On February 15, 2018, Columbia of Ohio filed comments proposing to: (1) reflect the impact of the TCJA on its application to adjust rates associated with its IRP rider, subsequently filed on February 27, 2018; and (2) file a reduction in other base rates reflecting the impact of the TCJA. The PUCO issued a procedural schedule on May 24, 2018 and a hearing was held on July 10, 2018. As discussed in further detail below, on October 25, 2018, Columbia of Ohio filed a joint stipulation and recommendation with the PUCO related to its CEP. Included in that stipulation were terms that would serve to resolve all remaining TCJA-related considerations for Columbia of Ohio.
On January 31, 2018, the PUCO approved Columbia of Ohio’s application to extend its IRP for an additional five years (2018-2022), allowing Columbia of Ohio to continue to invest and recover on its accelerated main replacements. The Office of the Ohio Consumers’ Counsel filed an application for rehearing asserting certain issues with Columbia of Ohio's application. On May 9, 2018, the PUCO issued an order denying the application for rehearing.
As referred to above, Columbia of Ohio filed its most recent application to adjust rates associated with its IRP rider on February 27, 2018, which requested authority to increase annual billings by approximately $2.3 million (net of the impact of the TCJA) reflecting recovery of and return on approximately $207 million of incremental IRP capital additions in 2017. A stipulation was filed with the PUCO on March 28, 2018. On April 25, 2018, the PUCO approved Columbia of Ohio’s annual IRP tracker adjustment with rates effective May 1, 2018.
On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. A hearing on the stipulation is expected to occur on November 6, 2018.
NIPSCO Gas. On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case (discussed immediately below) resolved all issues in Phase 2.
On September 27, 2017, NIPSCO filed a base rate case with the IURC, seeking an annual revenue increase of $143.5 million (inclusive of amounts being recovered through various tracker programs). As part of this filing and among other items, NIPSCO proposed to update base rates for ongoing infrastructure improvements, revised depreciation rates and ongoing level of expenses to reflect the current costs of providing natural gas service. NIPSCO submitted a rebuttal on March 28, 2018 updating its request, including the impact of the TCJA, seeking a revised annual revenue increase of $138.1 million. On April 20, 2018, a settlement agreement was filed with the IURC seeking, among other items, an annual revenue increase of $107.3 million. An order approving
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
the settlement agreement, as filed, was issued by the IURC on September 19, 2018. Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018, reflecting an annual revenue increase of $84.3 million. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also approved NIPSCO’s dismissal from phase 2 of the IURC’s TCJA investigation.
On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the aforementioned settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and ratemaking relief, including establishment of a periodic rate adjustment mechanism. NIPSCO anticipates filing the first tracker proceeding in this case on or around December 1, 2018.
On April 30, 2013, the Governor of Indiana signed Senate Enrolled Act 560, the TDSIC statute, into law. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next general rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenues. On April 2, 2018, NIPSCO filed a new seven-year gas TDSIC plan with the IURC beginning in 2019 seeking approval of a total capital expenditure level of approximately $1.25 billion. On September 4, 2018, the IURC dismissed the filing without prejudice. The initial seven-year gas TDSIC plan, approving a total capital expenditure level of approximately $767 million remains in effect as approved by the IURC in April 2014. A new seven-year gas TDSIC plan may be filed with IURC once the considerations in the pending TDSIC tracker appeal discussed below are resolved.
On February 27, 2018, NIPSCO filed TDSIC-8 requesting to recover an incremental increase to revenue of $0.8 million (net of the impacts of TCJA) associated with incremental capital investment of $77.9 million made in the second half of 2017. On June 20, 2018, the Indiana Supreme Court issued an order reversing the IURC and the Court of Appeals in NIPSCO’s gas TDSIC-4 proceeding. The Indiana Supreme Court order stated that periodic rate increases are available only for specific projects designated in the threshold proceeding and multiple-unit-projects not identified with particularity are not recoverable through the tracker. In the second quarter of 2018, NIPSCO recorded a liability of $2.5 million associated with the TDSIC-4 through TDSIC-8 filings for a related passback of revenue previously billed to customers. A revised TDSIC-8 was filed on July 18, 2018 and reduced the previous February 27, 2018 request by $0.2 million associated with incremental capital investment of approximately $54 million. On August 22, 2018, the IURC issued an order approving the requested rates, subject to refund. On August 28, 2018, NIPSCO filed TDSIC-9 requesting an incremental decrease to revenue of $0.5 million associated with incremental capital investment of $72.9 million through June 30, 2018. The filing included the pass back of the revenue associated with multiple-unit-projects from prior TDSIC filings and the pass back of TCJA revenues of $7.1 million for associated tax expense collected from January 1, 2018 through April 30, 2018. On September 26, 2018, NIPSCO filed a revised TDSIC-9 decreasing the requested revenue amount by an additional $7.6 million to reflect assets being included in the base rate amounts for the step 1 rate implementation discussed above. An IURC order is expected in the fourth quarter of 2018.
Columbia of Massachusetts. On February 2, 2018, the Massachusetts DPU opened an investigation into the effect of the reduction in federal income tax rates on the rates charged by utility companies. Columbia of Massachusetts was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred income taxes as regulatory liabilities effective January 1, 2018. Companies were ordered to submit a proposal to revise rates by May 1, 2018. The order indicates that if a company files a base rate case prior to the conclusion of the investigation, it must address the TCJA issues as part of the case. Since CMA filed a base rate case on April 13, 2018, the changes in base rates and the regulatory liability disposition related to the TCJA are reflected in the case. On June 29, 2018, the Massachusetts DPU required companies in a rate case to reduce rates as of July 1, 2018 or, in the alternative, defer this rate reduction to coincide with the effective date of new rates in a rate case, provided that tax savings from July 1, 2018 through the effective date of new rates accrue interest at prime rate. On July 2, 2018, Columbia of Massachusetts filed tariffs reflecting revised rates incorporating the lower federal corporate income tax rate for effect July 1, 2018. In the filing, Columbia of Massachusetts noted the Massachusetts DPU stated it would address the refund of any tax savings accrued from January 1, 2018, through June 30, 2018, in a separate phase of its investigation. On July
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
10, 2018, the Massachusetts DPU approved the tariffs effective July 1, 2018, finding the adjustment is in the public interest, as it provides an immediate benefit to ratepayers.
As noted above, on April 13, 2018, Columbia of Massachusetts filed a rate case with the Massachusetts DPU, seeking approval for an annual revenue increase of approximately $43.8 million which is offset by revenue decreases in other rate factors of $19.7 million, representing a net increase in operating revenues of $24.1 million. Included in the filing was a proposal to adjust rates and address the regulatory liability disposition related to the TCJA. As a result of the incident that occurred on September 13, 2018, involving a series of fires and explosions that occurred in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by Columbia of Massachusetts (the “Greater Lawrence Incident”), Columbia of Massachusetts filed a motion with the Massachusetts DPU on September 19, 2018, seeking to withdraw its petition for a base rate revenue increase in the interest of focusing its efforts on the on-going service restoration and customer assistance in the area. Refer to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information regarding the Greater Lawrence Incident. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes with an effective date of rates to be determined by the Massachusetts DPU.
On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, An Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file gas infrastructure replacement plans with the Massachusetts DPU to address the replacement of aging natural gas pipeline infrastructure. In addition, the Act provides that the Massachusetts DPU may, after review of the plans, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. On October 31, 2017, Columbia of Massachusetts filed its GSEP for the 2018 construction year which proposed to recover incremental revenue of $9.7 million associated with incremental capital investment of $83.9 million to be made during calendar year 2018. The filing included a request for approval of a waiver to allow collection of the $3.1 million revenue requirement that exceeds the GSEP cap provision. On January 29, 2018, Columbia of Massachusetts filed a revision to its GSEP tracker for the 2018 construction season reducing the proposed revenue requirement by $2.4 million to reflect the impact of the TCJA. On June 21, 2018, the Massachusetts DPU issued an order granting the waiver on the revenue cap allowing an incremental revenue requirement of $6.5 million with new rates effective July 1, 2018. On October 31, 2018, Columbia of Massachusetts filed its GSEP for the 2019 construction year, proposing to recover an incremental revenue requirement of $10.7 million associated with incremental capital of $64.0 million. The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision. An order is expected from the Massachusetts DPU in the second quarter of 2019, with new rates effective May 1, 2019.
Columbia of Pennsylvania. On February 12, 2018, the Pennsylvania PUC established a docket to investigate the impact of the TCJA on customer rates. The Pennsylvania PUC directed Pennsylvania utilities to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On May 17, 2018, the Pennsylvania PUC issued an order directing utilities that do not have a pending rate case to implement a negative surcharge in their billings to reflect the annual reduction in federal tax expense and associated revenue requirement for each utility, effective July 1, 2018.
On March 16, 2018, Columbia of Pennsylvania filed a rate case with the Pennsylvania PUC, incorporating the impacts of the TCJA and seeking approval for an annual revenue increase of $46.9 million. On March 21, 2018, Columbia of Pennsylvania filed a supplement to the rate case, under which it proposed to hold the overcollection of taxes during 2018 until the effective date of new base rates as credit to rate base for a period beginning January 2019 not to exceed three years. On August 31, 2018 a partial settlement was filed with the Pennsylvania PUC which included a revenue increase of $26.0 million and provided for the TCJA federal tax expense reduction of $22.5 million to be returned to customers over an 18 month period beginning December 16, 2018. On September 18, 2018 the administrative law judge issued a recommended decision approving the partial settlement without modification. A final order is expected in the fourth quarter of 2018 with new rates anticipated to be implemented in December 2018.
Columbia of Virginia. On January 8, 2018, the VSCC issued an order regarding the TCJA requiring Columbia of Virginia and other Virginia utilities subject to the TCJA to accrue regulatory liabilities reflecting the impacts of the reduced corporate income tax rate effective January 1, 2018. On August 28, 2018 Columbia of Virginia filed a request with the VSCC requesting a $22.2 million increase in base rates. The filing seeks to recover costs associated with ongoing infrastructure investment programs and incorporates the impacts of the TCJA. Columbia of Virginia proposed that the TCJA regulatory liability associated with lower federal income tax expense accrued prior to the implementation of new rates be considered in future VSCC reviews that assess earnings for the associated time period. Rates will be implemented on an interim basis, subject to refund, effective February 1, 2019, with a final order expected from the VSCC in the second half of 2019.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Columbia of Kentucky. On January 26, 2018, in accordance with the Kentucky PSC investigation related to the TCJA, Columbia of Kentucky filed testimony and proposed a reduction to base rates effective May 1, 2018, to reflect the tax expense reduction as a result of the TCJA. Columbia of Kentucky was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. Columbia of Kentucky proposed to include the impact of the excess deferred taxes in rates effective October 2018 and to return the revenue related to the regulatory liability subsequent to this date. On April 30, 2018 Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates that are subject to future adjustment effective May 1, 2018. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018, through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On September 27, 2018, Columbia of Kentucky received a PSC order suspending the filing for five months. No procedural time line beyond the five month suspension period has been set.
On October 15, 2018, Columbia of Kentucky filed an application to adjust rates associated with its AMRP, requesting authority to increase annual revenues by $3.6 million associated with incremental capital investment of $30.1 million to be made during calendar year 2019. An order is anticipated from the Kentucky PSC in December 2018, with new rates effective January 2019.
Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018.
On April 13, 2018, Columbia of Maryland filed a request with the Maryland PSC to increase base rates by $6.1 million, inclusive of the impacts of the TCJA. On July 31, 2018, Columbia of Maryland filed a settlement with the Maryland PSC. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. On October 2, 2018, the assigned judge issued a proposed order which recommended that the settlement be approved. A final order from the Maryland PSC is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018.
On April 6, 2018, Columbia of Maryland filed an application requesting authority to extend its STRIDE plan for an additional five years (2019-2023). The proposed order issued on August 28, 2018 was not appealed or modified and therefore it became final on September 28, 2018.
Electric Operations Regulatory Matters
Cost Recovery and Trackers. Comparability of Electric Operations 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 the subject of trackers result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.
Certain operating costs of the Electric Operations are significant, recurring in nature, and generally outside the control of NIPSCO. The IURC allows for recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for NIPSCO to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.
A portion of NIPSCO's 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, a quarterly regulatory proceeding in Indiana.
As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection and stated that all other phase 2 issues will be addressed in the to-be-filed base rate case, as discussed below.
On October 31, 2018 NIPSCO filed a request for an increase in base rates with the IURC for a proposed $21.4 million increase in revenues in part, to address anticipated revenue loss resulting from the WCE filing discussed below, as well as to address phase 2 issues of the TCJA. The filing also addresses the appropriate depreciation rates for the accelerated retirement of NIPSCO’s aging coal fleet, as discussed in the 2018 Integrated Resource Plan below. An order is expected from the IURC in the third quarter of 2019 with rates anticipated to be effective September 2019.
Also on October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.
On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. NIPSCO is currently in discussions with BP.
On January 30, 2018, NIPSCO made a TDSIC-3 rate adjustment mechanism filing requesting a revenue decrease of $1.8 million to be billed over six months, associated with $75.0 million of incremental capital expenditures made from May 1, 2017 to November 30, 2017. The decrease was due to the impact of the TCJA as well as a shorter billing period compared to TDSIC-2. TDSIC-3 was approved on May 30, 2018 and became effective for the first billing cycle of June. Additionally, the TDSIC-2 rates revised for tax reform approved as a part of NIPSCO’s Phase 1 filing described above were made effective on May 1, 2018, until TDSIC-3 rates went into effect. The impact of TCJA on TDSIC-2 was an approximate decrease in revenue of $1.2 million for the period from January through May 2018. NIPSCO made a TDSIC-4 rate adjustment mechanism filing on July 31, 2018, which was modified on October 25, 2018, seeking an incremental semi-annual revenue decrease of $11.2 million due primarily to the pass back of a $14.1 million TCJA electric base rate customer refund for the period January through May 2018. The TCJA refund offsets a $2.8 million increase associated with $72.2 million of incremental capital expenditures from December 2017 through May 2018. An order approving the request is expected in the fourth quarter of 2018.
On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA provisions into 2018 transmission formula rates as soon as possible. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will lower revenue by approximately $8.5 million in 2018 associated with NIPSCO's multi-value projects.
Material Updates to Regulatory Assets and Liabilities Since December 31, 2017
TCJA-Related Regulatory Liabilities. As referenced above, during the nine months ended September 30, 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million to reflect 2018 collections from customers which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.
As discussed in Note 12, "Income Taxes," in 2018 we began amortizing regulatory liabilities associated with excess deferred taxes, which resulted in a $6.8 million and $24.6 million income tax benefit for the three and nine months ended September 30, 2018, respectively. Related to this activity, we recorded an offsetting reserve of $3.6 million and $15.9 million (net of tax) in "Customer revenues" to reflect the probable future passback of this earnings benefit to customers for the three and nine months ended September 30, 2018, respectively. In certain jurisdictions, we received additional regulatory guidance on the treatment and passback period of excess deferred income taxes, indicating that such a reserve was not required as of September 30, 2018.
Bailly Generating Station. On February 1, 2018, as previously approved by the MISO, NIPSCO commenced a four-month outage of Bailly Generating Station Unit 8 in order to begin work on converting the unit to a synchronous condenser (a piece of equipment designed to maintain voltage to ensure continued reliability on the transmission system). Approximately $15 million of net book value of Unit 8 remained in “Net Utility Plant” as it is expected to remain used and useful upon completion of the synchronous condenser, while the remaining net book value of approximately $142 million was reclassified to “Regulatory assets (noncurrent)”
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
on the Condensed Consolidated Balance Sheets (unaudited). On May 31, 2018, Units 7 and 8 were retired from service. As a result, the remaining net book value of Unit 7 of approximately $103 million was reclassified to “Regulatory assets (noncurrent)” on the Condensed Consolidated Balance Sheets (unaudited).These amounts continue to be amortized at a rate consistent with their inclusion in customer rates.
8. Risk Management Activities
We are exposed to certain risks relating to our ongoing business operations, namely commodity price risk and interest rate risk. We recognize that the prudent and selective use of derivatives may help to lower our cost of debt capital, manage our interest rate exposure and limit volatility in the price of natural gas.
Risk management assets and liabilities on our derivatives are presented on the Condensed Consolidated Balance Sheets (unaudited) as shown below:
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Risk Management Assets - Current(1) | |||||||
Interest rate risk programs | $ | 21.4 | $ | 14.0 | |||
Commodity price risk programs | 1.0 | 0.5 | |||||
Total | $ | 22.4 | $ | 14.5 | |||
Risk Management Assets - Noncurrent(2) | |||||||
Interest rate risk programs | $ | 32.6 | $ | 5.6 | |||
Commodity price risk programs | 2.6 | 1.0 | |||||
Total | $ | 35.2 | $ | 6.6 | |||
Risk Management Liabilities - Current | |||||||
Interest rate risk programs | $ | — | $ | 38.6 | |||
Commodity price risk programs | 4.8 | 4.6 | |||||
Total | $ | 4.8 | $ | 43.2 | |||
Risk Management Liabilities - Noncurrent | |||||||
Interest rate risk programs | $ | — | $ | — | |||
Commodity price risk programs | 45.2 | 28.5 | |||||
Total | $ | 45.2 | $ | 28.5 | |||
(1)Presented in "Prepayments and other" on the Condensed Consolidated Balance Sheets (unaudited).
(2)Presented in "Deferred charges and other" on the Condensed Consolidated Balance Sheets (unaudited).
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.
NIPSCO received IURC approval to lock in a fixed price for its natural gas customers using long-term forward purchase instruments. The term of these instruments may range from five to ten years and is limited to twenty percent of NIPSCO’s average annual GCA purchase volume. 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.
Interest Rate Risk Management
As of September 30, 2018, we have forward-starting interest rate swaps with an aggregate notional value totaling $750.0 million to hedge the variability in cash flows attributable to changes in the benchmark interest rate during the periods from the effective dates of the swaps to the anticipated dates of forecasted debt issuances, which are expected to take place by the end of 2019. These interest rate swaps are designated as cash flow hedges. The effective portions of the gains and losses related to these swaps are
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
recorded to AOCI and are recognized in "Interest expense, net" concurrently with the recognition of interest expense on the associated debt, once issued. 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 April 2018, we settled forward-starting interest rate swaps with a notional value of $250.0 million. These derivative contracts were accounted for as cash flow hedges. As part of the transaction, the associated net unrealized gain of $21.2 million was recognized immediately in "Other, net" on the Condensed Statements of Consolidated Income (Loss) (unaudited) due to the probability associated with the forecasted borrowing transaction no longer occurring.
There were no amounts excluded from effectiveness testing for derivatives in cash flow hedging relationships at September 30, 2018 and December 31, 2017.
Our derivative instruments measured at fair value as of September 30, 2018 and December 31, 2017 do not contain any credit-risk-related contingent features.
9. Fair Value
A. Fair Value Measurements
Recurring Fair Value Measurements. The following tables present financial assets and liabilities measured and recorded at fair value on our Condensed Consolidated Balance Sheets (unaudited) on a recurring basis and their level within the fair value hierarchy as of September 30, 2018 and December 31, 2017:
Recurring Fair Value Measurements September 30, 2018 (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, 2018 | |||||||||||
Assets | |||||||||||||||
Risk management assets | $ | — | $ | 57.6 | $ | — | $ | 57.6 | |||||||
Available-for-sale securities | — | 143.8 | — | 143.8 | |||||||||||
Total | $ | — | $ | 201.4 | $ | — | $ | 201.4 | |||||||
Liabilities | |||||||||||||||
Risk management liabilities | $ | — | $ | 50.0 | $ | — | $ | 50.0 | |||||||
Total | $ | — | $ | 50.0 | $ | — | $ | 50.0 | |||||||
Recurring Fair Value Measurements December 31, 2017 (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, 2017 | |||||||||||
Assets | |||||||||||||||
Risk management assets | $ | — | $ | 21.1 | $ | — | $ | 21.1 | |||||||
Available-for-sale securities | — | 133.9 | — | 133.9 | |||||||||||
Total | $ | — | $ | 155.0 | $ | — | $ | 155.0 | |||||||
Liabilities | |||||||||||||||
Risk management liabilities | $ | — | $ | 71.4 | $ | 0.3 | $ | 71.7 | |||||||
Total | $ | — | $ | 71.4 | $ | 0.3 | $ | 71.7 | |||||||
Risk management assets and liabilities include interest rate swaps, exchange-traded NYMEX futures and NYMEX options and non-exchange-based forward purchase contracts. 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. Certain non-exchange-traded derivatives are valued using broker or over-the-counter, on-line exchanges. In such cases, these non-exchange-traded
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
derivatives are classified within Level 2. Non-exchange-based derivative instruments include swaps, forwards, options and treasury lock agreements. 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. 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 which reduce exposures. As of September 30, 2018 and December 31, 2017, 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.
We have entered into forward-starting interest rate swaps to hedge the interest rate risk on coupon payments of forecasted issuances of long-term debt. These derivatives are designated as cash flow hedges. Credit risk is considered in the fair value calculation of each agreement. 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. For additional information, see Note 8, "Risk Management Activities."
NIPSCO has entered into long-term forward natural gas purchase instruments that range from five to ten years to lock in a fixed price for its natural gas customers. We value these contracts using a pricing model that incorporates market-based information when available, as these instruments trade less frequently and are classified within Level 2 of the fair value hierarchy. For additional information, see Note 8, “Risk Management Activities.”
Available-for-sale securities are investments pledged as collateral for trust accounts related to our wholly-owned insurance company. Available-for-sale securities are included within “Other investments” in the Condensed Consolidated Balance Sheets (unaudited). 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. Total unrealized gains and losses from available-for-sale securities are included in other comprehensive income. The amortized cost, gross unrealized gains and losses and fair value of available-for-sale securities at September 30, 2018 and December 31, 2017 were:
September 30, 2018 (in millions) | Amortized Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | |||||||||||
Available-for-sale securities | |||||||||||||||
U.S. Treasury debt securities | $ | 29.7 | $ | — | $ | (0.2 | ) | $ | 29.5 | ||||||
Corporate/Other debt securities | 116.8 | 0.4 | (2.9 | ) | 114.3 | ||||||||||
Total | $ | 146.5 | $ | 0.4 | $ | (3.1 | ) | $ | 143.8 | ||||||
December 31, 2017 (in millions) | Amortized Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | |||||||||||
Available-for-sale securities | |||||||||||||||
U.S. Treasury debt securities | $ | 26.9 | $ | — | $ | (0.1 | ) | $ | 26.8 | ||||||
Corporate/Other debt securities | 106.8 | 0.9 | (0.6 | ) | 107.1 | ||||||||||
Total | $ | 133.7 | $ | 0.9 | $ | (0.7 | ) | $ | 133.9 | ||||||
Realized gains and losses on available-for-sale securities were immaterial for the three and nine months ended September 30, 2018 and 2017.
The cost of maturities sold is based upon specific identification. At September 30, 2018, approximately $14.9 million of U.S. Treasury debt securities and approximately $3.0 million of Corporate/Other debt securities have maturities of less than a year.
There are no material items in the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2018 and 2017.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Non-recurring Fair Value Measurements. There were no significant non-recurring fair value measurements recorded during the three and nine months ended September 30, 2018.
B. Other Fair Value Disclosures for Financial Instruments. The carrying amount of cash and cash equivalents, restricted cash, 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. For the nine months ended September 30, 2018, 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:
(in millions) | Carrying Amount as of September 30, 2018 | Estimated Fair Value as of September 30, 2018 | Carrying Amount as of Dec. 31, 2017 | Estimated Fair Value as of Dec. 31, 2017 | |||||||||||
Long-term debt (including current portion) | $ | 7,143.1 | $ | 7,280.1 | $ | 7,796.5 | $ | 8,603.4 | |||||||
10. Transfers of Financial Assets
Columbia of Ohio, NIPSCO and Columbia of Pennsylvania each maintain a receivables agreement whereby they transfer their customer accounts receivables to third party financial institutions through wholly-owned and consolidated special purpose entities. The three agreements expire between March 2019 and October 2019 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, 2018, the maximum amount of debt that could be recognized related to our accounts receivable programs is $265.0 million.
The following table reflects the gross receivables balance and net receivables transferred as well as short-term borrowings related to the securitization transactions as of September 30, 2018 and December 31, 2017:
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Gross Receivables | $ | 410.9 | $ | 635.3 | |||
Less: Receivables not transferred | 145.9 | 298.6 | |||||
Net receivables transferred | $ | 265.0 | $ | 336.7 | |||
Short-term debt due to asset securitization | $ | 265.0 | $ | 336.7 | |||
For the nine months ended September 30, 2018 and 2017, $71.7 million and $47.8 million, respectively, was recorded as cash flows used for financing activities related to the change in short-term borrowings due to securitization transactions. Fees associated with the securitization transactions were $0.4 million and $0.6 million for the three months ended September 30, 2018 and 2017, respectively, and $1.9 million for the nine months ended September 30, 2018 and 2017, respectively. We remain responsible for collecting on the receivables securitized, and the receivables cannot be transferred to another party.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
11. Goodwill
The following presents our goodwill balance allocated by segment as of September 30, 2018:
(in millions) | Gas Distribution Operations | Electric Operations | Corporate and Other | Total | ||||||||||||
Goodwill | $ | 1,690.7 | $ | — | $ | — | $ | 1,690.7 | ||||||||
We applied the qualitative "step 0" analysis to our reporting units for the annual impairment test performed as of May 1, 2018. For this test, we assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting units as compared to their base line May 1, 2016 "step 1" fair value measurement. The results of this assessment indicated that it was not more likely than not that our reporting unit fair values were less than the reporting unit carrying values, accordingly, no "step 1" analysis was required.
In the third quarter of 2018, we determined the Greater Lawrence Incident (see FN 16, "Other Commitments and Contingencies") represents a triggering event that requires an impairment analysis of goodwill. This incident specifically impacts our Columbia of Massachusetts reporting unit in which the associated goodwill totaled $204.8 million immediately prior to the incident. We performed a quantitative impairment analysis as of September 30, 2018 and determined that the fair value of the Columbia of Massachusetts reporting unit continues to exceed its carrying value. Therefore, no goodwill impairment charges were recorded in the third quarter of 2018. This interim analysis was performed using updated cash flow projections reflecting the estimated ongoing impacts of the Greater Lawrence Incident on Columbia of Massachusetts' operations. We also updated other significant inputs to the fair value calculation (e.g. discount rate, market multiples) to reflect current market conditions and the increased risk and uncertainty resulting from the incident. We will continue to monitor the impacts of the Greater Lawrence Incident for events that could trigger a new impairment analysis including, but not limited to, unfavorable regulatory outcomes, extended customer impacts, and NTSB investigation results.
12. Income Taxes
Our interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017, adjusted for tax expense associated with certain discrete items. The effective tax rates for the three months ended September 30, 2018 and 2017 were 21.8% and 15.2%, respectively. The effective tax rates for the nine months ended September 30, 2018 and 2017 were 40.3% and 34.9%, respectively. These effective tax rates differ from the federal statutory tax rate of 21% in 2018 and 35% in 2017, primarily due to the effects of tax credits, state income taxes, utility ratemaking and other permanent book-to-tax differences.
The increase in the three month effective tax rate of 6.6% in 2018 compared to 2017 is due to state tax apportionment benefits recorded in the third quarter of 2017 that were not recorded in the current year period along with the impact of the Greater Lawrence Incident on consolidated state income taxes. These increases were partially offset by the change in the federal statutory rate due to the enactment of the TCJA.
The increase in the nine month effective tax rate of 5.4% in 2018 versus the same period in 2017 is primarily due to the impact of the Greater Lawrence Incident on consolidated state income taxes, partially offset by the change in the federal statutory rate due to the enactment of the TCJA.
In 2018 we began amortizing a portion of our regulatory liability associated with excess deferred taxes which resulted in a current year income tax benefit of $6.8 million and $24.6 million for the three and nine months ended September 30, 2018, respectively. Additionally, we continue to work with the public utility commissions in each of our seven states on the appropriate treatment and resolution of TCJA impacts. Final regulatory orders from our public utility commissions in ongoing proceedings may decrease our TCJA-related regulatory liabilities by up to approximately $150 million. Such decreases would be recorded in the period the respective orders are received. Refer to Note 7, "Regulatory Matters," for additional information.
There were no material changes recorded in 2018 to our uncertain tax positions as of December 31, 2017.
13. Pension and Other Postretirement 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
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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. For most plans, cash contributions are remitted to grantor trusts.
For the nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 million to our other postretirement benefit plans.
The following table provides the components of the plans’ actuarially determined net periodic benefit cost for the three and nine months ended September 30, 2018 and 2017:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
Three Months Ended September 30, (in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Components of Net Periodic Benefit Cost(1) | |||||||||||||||
Service cost | $ | 7.8 | $ | 7.4 | $ | 1.3 | $ | 1.2 | |||||||
Interest cost | 16.8 | 17.1 | 4.4 | 4.4 | |||||||||||
Expected return on assets | (35.4 | ) | (30.8 | ) | (3.7 | ) | (3.9 | ) | |||||||
Amortization of prior service credit | (0.1 | ) | (0.1 | ) | (1.0 | ) | (1.1 | ) | |||||||
Recognized actuarial loss | 10.2 | 13.2 | 0.9 | 0.7 | |||||||||||
Settlement loss | 8.3 | 10.6 | — | — | |||||||||||
Total Net Periodic Benefit Cost | $ | 7.6 | $ | 17.4 | $ | 1.9 | $ | 1.3 | |||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
Nine Months Ended September 30, (in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Components of Net Periodic Benefit Cost(1) | |||||||||||||||
Service cost | $ | 23.6 | $ | 22.4 | $ | 3.9 | $ | 3.6 | |||||||
Interest cost | 50.0 | 51.5 | 13.2 | 13.4 | |||||||||||
Expected return on assets | (107.9 | ) | (91.3 | ) | (11.1 | ) | (11.9 | ) | |||||||
Amortization of prior service credit | (0.3 | ) | (0.5 | ) | (3.0 | ) | (3.3 | ) | |||||||
Recognized actuarial loss | 30.6 | 40.0 | 2.7 | 2.2 | |||||||||||
Settlement loss | 11.8 | 10.6 | — | — | |||||||||||
Total Net Periodic Benefit Cost | $ | 7.8 | $ | 32.7 | $ | 5.7 | $ | 4.0 | |||||||
(1)The service cost component, and all non-service cost components, of net periodic benefit cost are presented in "Operation and maintenance" and "Other, net", respectively, on the Condensed Statements of Consolidated Income (Loss) (unaudited).
As of May 31, 2018, two of our qualified pension plans paid lump sums in excess of the respective plan's 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $3.5 million was recorded during the second quarter of 2018. As a result of these settlements, the two pension plans were remeasured. The remeasurements led to an increase to the pension benefit obligation, net of plan assets, of $1.1 million, a net decrease to regulatory assets of $2.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.1 million. Net periodic pension benefit cost for 2018 increased by $1.1 million as a result of the second quarter remeasurement.
As of August 31, 2018, an additional qualified pension plan paid lump sums in excess of its 2018 service cost plus interest cost, thereby meeting the requirement for settlement accounting. A settlement charge of $8.3 million was recorded during the third quarter of 2018. As a result of this settlement, the plan was remeasured, leading to a decrease to the net pension asset of $2.5 million, a net decrease to regulatory assets of $5.3 million, and a net credit to accumulated other comprehensive income (loss) of $0.5 million. Net periodic pension benefit cost for 2018 increased by $1.9 million as a result of the third quarter remeasurement.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
The following table provides the key assumptions that were used to calculate the pension benefit obligation and the net periodic benefit cost for the plans that triggered settlement accounting at the measurement dates of August 31, 2018, May 31, 2018 and December 31, 2017:
August 31, 2018 | May 31, 2018 | December 31, 2017 | ||||||
Weighted-average Assumption to Determine Benefit Obligation: | ||||||||
Discount rate | 4.08 | % | 4.03 | % | 3.58 | % | ||
Weighted-average Assumptions to Determine Net Periodic Benefit Costs for the period ended: | ||||||||
Discount rate - service cost | 3.79 | % | 3.79 | % | 4.40 | % | ||
Discount rate - interest cost | 3.15 | % | 3.15 | % | 3.31 | % | ||
Expected return on assets | 6.30 | % | 6.30 | % | 7.25 | % | ||
14. Long-Term Debt
On March 15, 2018, we redeemed $275.1 million of 6.40% senior unsecured notes at maturity.
In June 2018, we executed a tender offer for $209.0 million of outstanding notes consisting of a combination of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. In conjunction with the debt retired, we recorded a $12.5 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
On June 11, 2018, we closed our private placement of $350.0 million of 3.65% senior unsecured notes maturing in 2023 which resulted in approximately $346.6 million of net proceeds after deducting commissions and expenses. We used the net proceeds from this private placement to pay a portion of the redemption price for the notes subject to the tender offer described above.
In July 2018, we redeemed $551.1 million of outstanding notes representing the remainder of our 6.80% notes due 2019, 5.45% notes due 2020 and 6.125% notes due 2022. During the third quarter of 2018, we recorded a $33.0 million loss on early extinguishment of long-term debt, primarily attributable to early redemption premiums.
15. Short-Term Borrowings
We generate short-term borrowings from our revolving credit facility, commercial paper program, letter of credit issuances, accounts receivable transfer programs and term loan borrowings. Each of these borrowing sources is described further below.
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 led by Barclays. At September 30, 2018 and December 31, 2017, we had no outstanding borrowings under this facility.
Our commercial paper program has a program limit of up to $1.5 billion with a dealer group comprised of Barclays, Citigroup, Credit Suisse and Wells Fargo. We had $746.0 million and $869.0 million of commercial paper outstanding as of September 30, 2018 and December 31, 2017, respectively.
As of September 30, 2018 and December 31, 2017, we had $10.2 million and $11.1 million of stand-by letters of credit, respectively. All stand-by letters of credit were under the revolving credit facility.
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). We had $265.0 million in transfers as of September 30, 2018 and $336.7 million as of December 31, 2017. Refer to Note 10, "Transfers of Financial Assets," for additional information.
On April 18, 2018, we entered into a multiple-draw $600.0 million term loan agreement with a syndicate of banks led by MUFG Bank, Ltd. The term loan matures April 17, 2019, at which point any and all outstanding borrowings under the agreement are due. Interest charged on borrowings depends on the variable rate structure we elected at the time of each borrowing. Under the agreement, we borrowed an initial tranche of $150.0 million on April 18, 2018 with an interest rate of LIBOR plus 50 basis points and a second tranche of $450.0 million on May 31, 2018 with an interest rate of LIBOR plus 55 basis points.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
Short-term borrowings were as follows:
(in millions) | September 30, 2018 | December 31, 2017 | |||||
Commercial paper weighted-average interest rate of 2.57% and 1.97% at September 30, 2018 and December 31, 2017, respectively | $ | 746.0 | $ | 869.0 | |||
Accounts receivable securitization facility borrowings | 265.0 | 336.7 | |||||
Term loan weighted-average interest rate of 2.79% at September 30, 2018 | 600.0 | — | |||||
Total Short-Term Borrowings | $ | 1,611.0 | $ | 1,205.7 | |||
Other than for the term loan, cash flows related to the borrowings and repayments of the items listed above are presented net in the Condensed Statements of Consolidated Cash Flows (unaudited) as their maturities are less than 90 days.
16. 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, 2018 and December 31, 2017, we had issued stand-by letters of credit of $10.2 million and $11.1 million, respectively.
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 (referred to herein as the “Greater Lawrence Incident”). The Greater Lawrence Incident resulted in one fatality and a number of injuries, damaged multiple homes and businesses, and caused the temporary evacuation of significant portions of each municipality. The Massachusetts Governor’s office declared a state of emergency, authorizing the Massachusetts DPU to order another utility company to coordinate the restoration of utility services in Lawrence, Andover and North Andover. The incident resulted in the interruption of gas and other utility service for approximately 8,500 gas meters, of which approximately 700 serve businesses. Columbia of Massachusetts is currently in the process of replacing the cast iron and bare steel gas pipeline system to restore service to these meters. See “ - D. Other Matters - Greater Lawrence Pipeline Replacement” below for more information.
The NTSB is investigating the Greater Lawrence Incident. The parties to the investigation include the PHMSA, the Massachusetts DPU, Columbia of Massachusetts, and police and fire first responders. The Company and Columbia of Massachusetts are cooperating with the NTSB and have provided information to assist in its ongoing investigation into relevant facts related to the event, the probable cause, and its development of safety recommendations. According to the preliminary public report that the NTSB issued on October 11, 2018, an over pressurization of a low pressure gas distribution system occurred which appears to have been related to work being done on behalf of Columbia of Massachusetts on a pipeline replacement project in Lawrence. In addition, according to the report, sensing lines detected a drop in pressure in a portion of mainline that was being abandoned, causing a regulator to open up and increase pressure in the system to a level that exceeded the maximum allowable operating pressure of the distribution system. While the NTSB investigation is pending, the Company and Columbia of Massachusetts are prohibited from disclosing information related to the investigation without approval from the NTSB.
The Massachusetts DPU has announced its intent to hire an independent evaluator to conduct a statewide examination of the safety of the natural gas distribution systems within the Commonwealth of Massachusetts. Through authority granted by the Massachusetts Governor under the state of emergency, the Chair of the Massachusetts DPU will direct all natural gas distribution companies operating in the Commonwealth to fund the statewide examination. The examination is expected to complement, but not duplicate, the NTSB’s investigation. Following the release of the NTSB's preliminary report, the Massachusetts DPU placed a moratorium on Columbia of Massachusetts, which prohibits the company from performing any work in the state through at least December 1, 2018. The ban does not apply to compliance and emergency work, including the restoration of service in Lawrence, Andover and North Andover.
Under Massachusetts law, the DPU is authorized to investigate potential violations of pipeline safety regulations and to assess a civil penalty of up to $209,000 for a violation of federal pipeline safety regulations. A separate violation occurs for each day of violation up to $2.1 million for a related series of violations. The Massachusetts DPU also is authorized to investigate potential violations of the Columbia of Massachusetts emergency response plan and to assess penalties of up to $250,000 per violation, or
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
up to $20 million per related series of violations. Further, as a result of the declaration of emergency by the Governor, the DPU is authorized to investigate potential violations of the DPU's operational directives during the restoration efforts and assess penalties of up to $1 million per violation. The timing and outcome of any such investigations are uncertain at this time.
Various lawsuits, including several purported class action lawsuits, have been 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. The class action lawsuits allege varying causes of action, including those for strict liability for ultra-hazardous activity, negligence, private nuisance, public nuisance, premises liability, trespass, breach of implied warranty of merchantability, breach of contract and gross negligence, and seek punitive damages. Many residents and business owners have submitted individual damage claims to Columbia of Massachusetts. We also have received notice from two parties indicating an intent to assert wrongful death claims. In addition, the Commonwealth of Massachusetts and the municipalities of Lawrence, Andover and North Andover are seeking reimbursement from Columbia of Massachusetts for their respective expenses incurred in connection with the Greater Lawrence Incident.
The Company and Columbia of Massachusetts are subject to a criminal investigation being conducted under the supervision of the U.S. Attorney's Office for the District of Massachusetts. The initial grand jury subpoenas were served on the Company and Columbia of Massachusetts on September 24, 2018. The Company and Columbia of Massachusetts are cooperating with the investigation.
During the quarter ended September 30, 2018, Columbia of Massachusetts expensed approximately $415 million for estimated third-party claims related to the Greater Lawrence Incident, including personal injury and property damage claims, damage to infrastructure, and other damage claims, which include mutual aid payments to other utilities assisting with the restoration effort, gas-fueled appliance replacement and related services for impacted customers, temporary lodging for displaced customers, and claims-related legal fees. We estimate that total costs related to third-party claims resulting from the incident will range from $415 million to $450 million, depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We also expect to incur losses for third party business interruption claims, the costs for which are not included in the amounts disclosed above due to insufficient information to reasonably estimate the damages from such claims. The amounts set forth above do not include non-claims related expenses resulting from the incident or the estimated capital cost of the pipeline replacement, which are set forth in " - D. Other Matters - Greater Lawrence Incident Restoration" and " - Greater Lawrence Pipeline Replacement," respectively, below.
The process for estimating costs associated with third-party claims relating to the Greater Lawrence Incident requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change.
Further, it is not possible at this time to reasonably estimate the amount of any fines, penalties or settlements with governmental authorities, including the Massachusetts DPU and other regulators, that the Company or Columbia of Massachusetts may incur in connection with the Greater Lawrence Incident. Therefore, the foregoing amounts do not include estimates for any such fines, penalties or settlements.
The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). The expenses above are presented within “Operation and maintenance” in our Condensed Statement of Consolidated Income (unaudited).
The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims related to the Greater Lawrence Incident will be substantially covered by this insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.
In addition, we are party to certain other claims and legal proceedings arising in the ordinary course of business, none of which are deemed 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 or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. If one or more of such 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
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
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 significant portion of environmental assessment and remediation costs to be recoverable through rates for certain of our companies.
As of September 30, 2018 and December 31, 2017, we had recorded a liability of approximately $107.1 million and $111.4 million, respectively, to cover environmental remediation at various sites. The current portion of this liability is included in "Legal and environmental" in the Condensed Consolidated Balance Sheets (unaudited). The noncurrent portion is included in "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 currently enacted 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.
Electric Operations' compliance estimates disclosed below are reflective of NIPSCO's Integrated Resource Plan submitted to the IURC on October 31, 2018. See section D, "Other Matters," below for additional information.
Air
The actions listed below could require further reductions in emissions from various emission sources. We will continue to closely monitor developments in these matters.
Future legislative and regulatory programs could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Additionally, rules that increase methane leak detection, require emission reductions or impose additional requirements for natural gas facilities could restrict GHG emissions and impose additional costs. We carefully monitor all GHG reduction proposals and regulations.
CPP and ACE Rules. On October 23, 2015, the EPA issued the CPP to regulate CO2 emissions from existing fossil-fuel EGUs under section 111(d) of the CAA. The U.S. Supreme Court has stayed implementation of the CPP until litigation is decided on its merits, and the EPA has proposed to repeal the CPP. On August 31, 2018, the EPA published a proposal to replace the CPP with the ACE rule, which establishes guidelines for states to use when developing plans to reduce CO2 emissions from existing coal-fired EGUs. The proposal would provide states three years after a final rule is issued to develop state-specific plans, and the EPA would have twelve months to act on a complete state plan submittal. Within two years after a finding of failure to submit a complete plan, or disapproval of a state plan, the EPA would issue a federal plan. NIPSCO will continue to monitor this matter and cannot estimate its impact at this time.
Waste
CERCLA. Our subsidiaries are potentially responsible parties at waste disposal sites under the CERCLA (commonly known as Superfund) 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. These liabilities are not material to the Condensed Consolidated Financial Statements (unaudited).
MGP. A program has been instituted to identify and investigate former MGP sites where Gas Distribution Operations subsidiaries or predecessors may have liability. The program has identified 64 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 future remediation costs related to our 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
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
remediation costs were noted as a result of the refresh completed as of June 30, 2018. Our total estimated liability related to the facilities subject to remediation was $103.3 million and $106.9 million at September 30, 2018 and December 31, 2017, respectively. The liability represents our best estimate of the probable cost to remediate the facilities. We believe that it is reasonably possible that remediation costs could vary by as much as $25 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. On April 17, 2015, the EPA issued a final rule for regulation of CCRs. The rule regulates CCRs under the RCRA Subtitle D, which determines them to be nonhazardous. The rule is implemented in phases and requires increased groundwater monitoring, reporting, recordkeeping and posting of related information to the Internet. The rule also establishes requirements related to CCR management and disposal. The rule will allow NIPSCO to continue its byproduct beneficial use program.
The publication of the CCR rule 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 compliance strategies that will be used and the preliminary nature of available data used to estimate costs. In addition, to comply with the rule, NIPSCO is incurring capital expenditures to modify its infrastructure and manage CCRs. Capital compliance costs are currently expected to total approximately $193 million. As allowed by the EPA, 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.
NIPSCO filed a petition on November 1, 2016 with the IURC seeking approval of the projects and recovery of the costs associated with CCR compliance. On June 9, 2017, NIPSCO filed with the IURC a settlement reached with certain parties regarding the CCR projects and treatment of associated costs. The IURC approved the settlement in an order on December 13, 2017.
Water
ELG. On November 3, 2015, the EPA issued a final rule to amend the ELG and standards for the Steam Electric Power Generating category. The final rule became effective January 4, 2016. The rule imposes new water treatment and discharge requirements on NIPSCO's electric generating facilities to be applied between 2018 and 2023. On April 25, 2017, the EPA published notice in the Federal Register that the EPA is reconsidering the ELG in response to several petitions for reconsideration. On September 18, 2017, the EPA postponed the earliest compliance dates for flue gas desulfurization wastewater and bottom ash transport water requirements from 2018 to 2020 to potentially consider revisions to technology and numeric limits achievable. NIPSCO is unable to estimate the financial impact of the EPA reconsideration at this time. Based upon a preliminary study of the November 3, 2015 final rule, capital compliance costs were expected to be approximately $170 million. However, NIPSCO does not anticipate material ELG compliance costs based on the most viable option for customers announced as part of NIPSCO's 2018 Integrated Resource Plan (discussed below).
D. Other Matters.
NIPSCO 2018 Integrated Resource Plan. Multiple factors, but primarily economic ones, including low natural gas prices, advancing cost effective renewable technology and increasing capital and operating costs associated with existing coal plants, have led NIPSCO to conclude in its Integrated Resource Plan submission that NIPSCO’s current fleet of coal generation facilities will be retired earlier than previous Integrated Resource Plan’s had indicated.
On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The preferred option within the Integrated Resource Plan retires R.M. Schahfer Generating Station (Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar, and battery storage.
NIPSCO Pure Air. NIPSCO had a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and First Air Partners LP, under which Pure Air provided scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at the Bailly Generating Station. Services under this contract commenced on July 1, 1992 and expired on June 30, 2012. The agreement was renewed effective July 1, 2012 for ten years, requiring NIPSCO to pay for the services under a combination of fixed and variable charges. We made an exhaustive effort to obtain information needed from Pure Air to determine the status of Pure Air as a VIE. However, NIPSCO was not able to obtain this information and, as a result, it was not determined whether Pure Air was a VIE and whether NIPSCO was the primary beneficiary. Payments under this agreement were $8.3 million and $16.5 million for the nine months ended September 30, 2018 and 2017, respectively. In accordance with GAAP, the renewed agreement was evaluated to determine whether the arrangement qualified as a lease. Based on the terms of the agreement, the arrangement
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
qualified for capital lease accounting. As the effective date of the new agreement was July 1, 2012, we capitalized this lease beginning in the third quarter of 2012.
NIPSCO retired the generation station units serviced by Pure Air on May 31, 2018. In December 2016, as allowed by the provisions of the service agreement, NIPSCO provided Pure Air formal notice of intent to terminate the service agreement, effective May 31, 2018. Providing this notice to Pure Air triggered a contract termination liability of $16 million, which was recorded in fourth quarter of 2016. In connection with the closure of Bailly Units 7 and 8, NIPSCO paid the termination payment to Pure Air during the second quarter of 2018. Cash flows associated with this payment are presented within operating activities on the Condensed Statements of Consolidated Cash Flows (unaudited).
Greater Lawrence Incident Restoration. During the quarter ended September 30, 2018, Columbia of Massachusetts recorded a loss of approximately $460 million in connection with the Greater Lawrence Incident. This amount includes approximately $415 million for estimated third-party claims associated with the incident as described above in " - B. Legal Proceedings." The additional $45 million included in the loss recorded includes certain consulting costs, administration costs, charitable contributions, and other labor and related expenses in connection with the incident. We expect to incur a total of $180 million to $210 million in such incident-related costs, depending on the incurrence of future restoration work, substantially all of which we expect to incur by the end of 2018. The amounts set forth above do not include the estimated capital cost of the pipeline replacement, which is set forth below.
The Company maintains liability insurance for damages in the approximate amount of $800 million. The Company and Columbia of Massachusetts believe that third-party claims and other expenses related to the Greater Lawrence Incident will be substantially covered by insurance, other than any fines, penalties or settlements with governmental authorities that the Company or Columbia of Massachusetts may incur. However, no amounts for insurance recoveries have been recorded as of September 30, 2018. The Company and Columbia of Massachusetts are currently unable to predict the amount and timing of insurance recoveries.
The current and noncurrent portions of the remaining liability as of September 30, 2018 are presented within “Claims accrued” and “Other noncurrent liabilities,” respectively, in the Company’s Condensed Consolidated Balance Sheets (unaudited). Costs associated with charitable contributions are presented within “Other, Net” in our Condensed Statement of Consolidated Income (unaudited). All other losses incurred are presented within “Operation and maintenance.”
Greater Lawrence Pipeline Replacement. In connection with the Greater Lawrence Incident, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to approximately 8,500 gas meters, of which approximately 700 serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. At the request of the Massachusetts DPU, which was instructed by the Massachusetts Governor through his executive authority under a state of emergency, Columbia of Massachusetts has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million. The recovery of this capital investment will be addressed in a future regulatory proceeding.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
17. Accumulated Other Comprehensive Income (Loss)
The following tables display the components of Accumulated Other Comprehensive Income (Loss):
Three Months Ended September 30, 2018 (in millions) | Gains and Losses on Securities(1) | Gains and Losses on Cash Flow Hedges(1) | Pension and OPEB Items(1) | Accumulated Other Comprehensive Income (Loss)(1) | |||||||||||
Balance as of July 1, 2018 | $ | (2.2 | ) | $ | (1.7 | ) | $ | (17.0 | ) | $ | (20.9 | ) | |||
Other comprehensive income before reclassifications | — | 21.6 | 1.0 | 22.6 | |||||||||||
Amounts reclassified from accumulated other comprehensive loss | 0.1 | 0.9 | (0.2 | ) | 0.8 | ||||||||||
Net current-period other comprehensive income | 0.1 | 22.5 | 0.8 | 23.4 | |||||||||||
Balance as of September 30, 2018 | $ | (2.1 | ) | $ | 20.8 | $ | (16.2 | ) | $ | 2.5 | |||||
Nine Months Ended September 30, 2018 (in millions) | Gains and Losses on Securities(1) | Gains and Losses on Cash Flow Hedges(1) | Pension and OPEB Items(1) | Accumulated Other Comprehensive Income (Loss)(1) | |||||||||||
Balance as of January 1, 2018 | $ | 0.2 | $ | (29.4 | ) | $ | (14.2 | ) | $ | (43.4 | ) | ||||
Other comprehensive income (loss) before reclassifications | (2.5 | ) | 70.8 | 1.0 | 69.3 | ||||||||||
Amounts reclassified from accumulated other comprehensive loss(2) | 0.2 | (14.3 | ) | 0.2 | (13.9 | ) | |||||||||
Net current-period other comprehensive income (loss) | (2.3 | ) | 56.5 | 1.2 | 55.4 | ||||||||||
Reclassification due to adoption of ASU 2018-02 (Refer to Note 2) | — | (6.3 | ) | (3.2 | ) | (9.5 | ) | ||||||||
Balance as of September 30, 2018 | $ | (2.1 | ) | $ | 20.8 | $ | (16.2 | ) | $ | 2.5 | |||||
Three Months Ended September 30, 2017 (in millions) | Gains and Losses on Securities(1) | Gains and Losses on Cash Flow Hedges(1) | Pension and OPEB Items(1) | Accumulated Other Comprehensive (Loss)(1) | |||||||||||
Balance as of July 1, 2017 | $ | 0.4 | $ | (18.8 | ) | $ | (17.2 | ) | $ | (35.6 | ) | ||||
Other comprehensive income (loss) before reclassifications | 0.1 | (9.7 | ) | — | (9.6 | ) | |||||||||
Amounts reclassified from accumulated other comprehensive loss | — | 0.4 | 1.1 | 1.5 | |||||||||||
Net current-period other comprehensive income (loss) | 0.1 | (9.3 | ) | 1.1 | (8.1 | ) | |||||||||
Balance as of September 30, 2017 | $ | 0.5 | $ | (28.1 | ) | $ | (16.1 | ) | $ | (43.7 | ) | ||||
Nine Months Ended September 30, 2017 (in millions) | Gains and Losses on Securities(1) | Gains and Losses on Cash Flow Hedges(1) | Pension and OPEB Items(1) | Accumulated Other Comprehensive (Loss)(1) | |||||||||||
Balance as of January 1, 2017 | $ | (0.6 | ) | $ | (6.9 | ) | $ | (17.6 | ) | $ | (25.1 | ) | |||
Other comprehensive income (loss) before reclassifications | 1.1 | (23.3 | ) | 0.2 | (22.0 | ) | |||||||||
Amounts reclassified from accumulated other comprehensive loss | — | 2.1 | 1.3 | 3.4 | |||||||||||
Net current-period other comprehensive income (loss) | 1.1 | (21.2 | ) | 1.5 | (18.6 | ) | |||||||||
Balance as of September 30, 2017 | $ | 0.5 | $ | (28.1 | ) | $ | (16.1 | ) | $ | (43.7 | ) | ||||
(1)All amounts are net of tax. Amounts in parentheses indicate debits.
(2) Reclassification from accumulated other comprehensive loss for cash flow hedges relates primarily to the interest rate swap settlement gain. Refer to Note 8 "Risk Management Activities" for additional information.
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ITEM 1. FINANCIAL STATEMENTS (continued)
NiSource Inc.
Notes to Condensed Consolidated Financial Statements (unaudited) (continued)
18. Other, Net
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Interest Income | $ | 1.4 | $ | 1.4 | $ | 4.2 | $ | 3.2 | |||||||
AFUDC Equity | 5.0 | 4.3 | 12.6 | 10.5 | |||||||||||
Charitable Contributions | (11.1 | ) | (0.8 | ) | (13.9 | ) | (3.5 | ) | |||||||
Pension and other postretirement non-service cost | 2.4 | (11.8 | ) | 14.7 | (10.1 | ) | |||||||||
Interest rate swap settlement gain(1) | — | — | 21.2 | — | |||||||||||
Miscellaneous | 0.6 | 0.1 | 3.6 | (0.4 | ) | ||||||||||
Total Other, net | $ | (1.7 | ) | $ | (6.8 | ) | $ | 42.4 | $ | (0.3 | ) | ||||
(1)See Note 8, "Risk Management Activities," for additional information.
19. Business Segment Information
Our operations are divided into two primary reportable segments. The Gas Distribution Operations segment provides natural gas service and transportation for residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, Maryland, Indiana and Massachusetts. The Electric Operations segment provides electric service in 20 counties in the northern part of Indiana.
The following table provides information about our business 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.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
(in millions) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Operating Revenues | |||||||||||||||
Gas Distribution Operations | |||||||||||||||
Unaffiliated | $ | 418.6 | $ | 431.1 | $ | 2,347.8 | $ | 2,139.9 | |||||||
Intersegment | 3.3 | 3.5 | 9.8 | 10.6 | |||||||||||
Total | 421.9 | 434.6 | 2,357.6 | 2,150.5 | |||||||||||
Electric Operations | |||||||||||||||
Unaffiliated | 476.2 | 485.8 | 1,304.4 | 1,365.5 | |||||||||||
Intersegment | 0.2 | 0.2 | 0.6 | 0.6 | |||||||||||
Total | 476.4 | 486.0 | 1,305.0 | 1,366.1 | |||||||||||
Corporate and Other | |||||||||||||||
Unaffiliated | 0.2 | 0.1 | 0.6 | 0.9 | |||||||||||
Intersegment | 116.4 | 126.4 | 346.6 | 367.7 | |||||||||||
Total | 116.6 | 126.5 | 347.2 | 368.6 | |||||||||||
Eliminations | (119.9 | ) | (130.1 | ) | (357.0 | ) | (378.9 | ) | |||||||
Consolidated Operating Revenues | $ | 895.0 | $ | 917.0 | $ | 3,652.8 | $ | 3,506.3 | |||||||
Operating Income (Loss) | |||||||||||||||
Gas Distribution Operations | $ | (455.2 | ) | $ | (15.4 | ) | $ | (94.4 | ) | $ | 367.1 | ||||
Electric Operations | 134.9 | 125.1 | 300.4 | 288.3 | |||||||||||
Corporate and Other | 4.4 | 1.5 | (2.9 | ) | (4.8 | ) | |||||||||
Consolidated Operating Income | $ | (315.9 | ) | $ | 111.2 | $ | 203.1 | $ | 650.6 | ||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NiSource Inc.
Index | Page |
Executive Summary | |
Summary of Consolidated Financial Results | |
Results and Discussion of Segment Operations | |
Gas Distribution Operations | |
Electric Operations | |
Off Balance Sheet Arrangements | |
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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) analyzes our financial condition, results of operations and cash flows and those of our subsidiaries. It also 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, 2017.
We are an energy holding company under the Public Utility Holding Company Act of 2005 whose subsidiaries are fully regulated natural gas and electric utility companies serving customers in seven 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, 2017 for further discussion of our regulated utility business segments.
Our goal is to develop strategies that benefit all stakeholders as we address changing customer conservation patterns, develop more contemporary pricing structures and embark on long-term investment programs. These strategies are intended to improve reliability and safety, enhance customer service and reduce emissions while generating sustainable returns. Additionally, we continue to pursue regulatory and legislative initiatives that will allow residential customers not currently on our system to obtain gas service in a cost effective manner.
Greater Lawrence Incident: 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”). During the quarter ended September 30, 2018, we recorded a loss of approximately $415 million for third-party claims and approximately $45 million for other incident-related expenses in connection with the Greater Lawrence Incident.
We estimate that total costs related to third-party claims will range from $415 million to $450 million, depending on the final outcome of open investigations and the number, nature, and value of third-party claims. We expect to incur a total of $180 million to $210 million in such other incident-related costs, substantially all of which would be incurred by the end of 2018.
We also expect to incur expenses for which we cannot estimate the amounts of or the timing at this time, including expenses associated with business interruption claims and fines, penalties or settlements with governmental authorities in connection with the Greater Lawrence Incident. We expect these expenses and other expenses related to various lawsuits, including class action suits, to extend beyond 2018.
Columbia of Massachusetts expects to record recoveries from third party insurance, resulting in increases to operating income in future periods as such amounts are recorded. The timing and amount of such recoveries is uncertain.
As discussed in Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), Columbia of Massachusetts withdrew its petition for a base rate revenue increase, resulting in delayed increases in forecasted revenues and cash flows beginning the first quarter of 2019. Columbia of Massachusetts expects to invest between $135 - $165 million for replacement of the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to those impacted in the Greater Lawrence Incident. The recovery of this capital investment will be addressed in a future regulatory proceeding. If at any point Columbia of Massachusetts concludes it is probable that any portion of this capital investment is not recoverable through customer rates, that portion of the capital investment, if estimable, would be immediately charged to earnings.
Additionally, as discussed in Note 11, "Goodwill," we concluded the Greater Lawrence Incident was a triggering event requiring a quantitative analysis of goodwill for the Columbia of Massachusetts reporting unit. Future unfavorable events that transpire at Columbia of Massachusetts could trigger the need for another quantitative analysis and a goodwill impairment loss would be required if it's determined Columbia of Massachusetts fair value is less than its book value.
Refer to Note 16-B and D, "Legal Proceedings" and "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), "Summary of Consolidated Financial Results," "Results and Discussion of Segment Operation - Gas Distribution
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NiSource Inc.
Operations," and "Liquidity and Capital Resources" in this Management's Discussion, and Part II. Item 1A. "Risk Factors" for additional information related to the Greater Lawrence Incident.
Summary of Consolidated Financial Results
Our operations are affected by the cost of sales. Cost of sales for the Gas Distribution Operations segment is principally comprised of the cost of natural gas used while providing transportation and distribution services to customers. Cost of sales for the Electric Operations segment is comprised of the cost of coal, related handling costs, natural gas purchased for the internal generation of electricity at NIPSCO and the cost of power purchased from third-party generators of electricity.
The majority of the cost of sales are tracked costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in operating revenues. As a result, we believe net revenues, a non-GAAP financial measure defined as operating revenues less cost of sales (excluding depreciation and amortization), provides management and investors a useful measure to analyze profitability. The presentation of net revenues herein is intended to provide supplemental information for investors regarding operating performance. Net revenues do not intend to represent operating income, the most comparable GAAP measure, as an indicator of operating performance and are not necessarily comparable to similarly titled measures reported by other companies.
For the three and nine months ended September 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Operating Income (Loss) | $ | (315.9 | ) | $ | 111.2 | $ | (427.1 | ) | $ | 203.1 | $ | 650.6 | $ | (447.5 | ) | ||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions, except per share amounts) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Operating Revenues | $ | 895.0 | $ | 917.0 | $ | (22.0 | ) | $ | 3,652.8 | $ | 3,506.3 | $ | 146.5 | ||||||||||
Cost of Sales (excluding depreciation and amortization) | 222.0 | 233.6 | (11.6 | ) | 1,259.7 | 1,062.7 | 197.0 | ||||||||||||||||
Total Net Revenues | 673.0 | 683.4 | (10.4 | ) | $ | 2,393.1 | $ | 2,443.6 | $ | (50.5 | ) | ||||||||||||
Other Operating Expenses | 988.9 | 572.2 | 416.7 | 2,190.0 | 1,793.0 | 397.0 | |||||||||||||||||
Operating Income (Loss) | (315.9 | ) | 111.2 | (427.1 | ) | 203.1 | 650.6 | (447.5 | ) | ||||||||||||||
Total Other Deductions, net | (118.1 | ) | (94.7 | ) | (23.4 | ) | (268.3 | ) | (372.6 | ) | 104.3 | ||||||||||||
Income Taxes | (94.5 | ) | 2.5 | (97.0 | ) | (26.3 | ) | 97.1 | (123.4 | ) | |||||||||||||
Net Income (Loss) | (339.5 | ) | 14.0 | (353.5 | ) | (38.9 | ) | 180.9 | (219.8 | ) | |||||||||||||
Preferred dividends | (5.6 | ) | — | (5.6 | ) | (6.9 | ) | — | (6.9 | ) | |||||||||||||
Net Income (Loss) Available to Common Shareholders | (345.1 | ) | 14.0 | (359.1 | ) | (45.8 | ) | 180.9 | (226.7 | ) | |||||||||||||
Basic Earnings (Loss) Per Share | $ | (0.95 | ) | $ | 0.04 | $ | (0.99 | ) | $ | (0.13 | ) | $ | 0.55 | $ | (0.68 | ) | |||||||
Basic Average Common Shares Outstanding | 363.9 | 331.1 | 32.8 | 352.1 | 326.7 | 25.4 | |||||||||||||||||
On a consolidated basis, we reported a net loss available to common shareholders of $345.1 million, or $0.95 per basic share for the three months ended September 30, 2018, compared to net income available to common shareholders of $14.0 million, or $0.04 per basic share for the same period in 2017. The decrease in income available to common shareholders during 2018 was primarily due to expenses related to the Greater Lawrence Incident restoration, losses on early extinguishment of long-term debt in 2018, other changes in operating income, as discussed below, and dilution resulting from preferred stock dividend commitments.
For the three months ended September 30, 2018, we reported an operating loss of $315.9 million compared to operating income of $111.2 million for the same period in 2017. The decreased operating income was primarily due to increased operation and maintenance expenses related to the Greater Lawrence Incident restoration, increased depreciation expense due to capital expenditures placed in service and decreased net revenues resulting from TCJA impacts on revenue. These increases were partially offset by decreased employee and administrative expenses and outside service costs, higher rates from investments in infrastructure replacement programs and net favorable effects of year-over-year weather variations, which increased revenue in 2018.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
On a consolidated basis, we reported a net loss available to common shareholders of $45.8 million, or $0.13 per basic share for the nine months ended September 30, 2018, compared to net income available to common shareholders of $180.9 million, or $0.55 per basic share for the same period in 2017. The decrease in net income available to common shareholders during 2018 was due primarily to expenses related to the Greater Lawrence Incident restoration, dilution resulting from preferred stock dividend commitments and other changes in operating income, as described below, partially offset by higher losses on early extinguishment of long-term debt expenses in 2017.
For the nine months ended September 30, 2018, we reported operating income of $203.1 million compared to $650.6 million for the same period in 2017. The lower operating income was primarily due to operation and maintenance expenses related to the Greater Lawrence Incident restoration, decreased net revenues attributable to TCJA impacts on revenue as well as higher depreciation expense. These decreases were offset by increased net revenues due to weather variability between the nine months ended September 30, 2018 compared to the same period in 2017 and decreased outside service costs and employee and administrative expenses. Additionally, net revenues increased in 2018 due to new rates from infrastructure replacement programs and base rate proceedings.
Other Deductions, net
Other deductions, net reduced income by $118.1 million in the third quarter of 2018 compared to a reduction in income of $94.7 million in the prior year. This change is primarily due to a loss on early extinguishment of long-term debt of $33.0 million during the third quarter of 2018 and charitable contributions of $10.3 million related to the Greater Lawrence Incident. These reductions were partially offset by higher actuarial investment returns resulting from pension contributions made in the third quarter of 2017.
Other deductions, net reduced income by $268.3 million in the nine months ended September 30, 2018 compared to a reduction in income of $372.6 million in the prior year. This change is primarily due to lower losses on early extinguishment of long-term debt in 2018 of $66.0 million, as well as higher actuarial investment returns resulting from pension contributions made in the third quarter of 2017 and an interest rate swap settlement gain recognized in the first quarter of 2018 of $21.2 million. These favorable variances were partially offset by charitable contributions of $10.3 million made in the third quarter of 2018 related to the Greater Lawrence Incident.
Income Taxes
On December 22, 2017, the President signed into law the TCJA, which, among other things, enacted significant changes to the Internal Revenue Code of 1986, as amended, including a reduction in the maximum U.S. federal corporate income tax rate from 35% to 21%, and certain other provisions related specifically to the public utility industry, including the continuation of certain interest expense deductibility and excluding 100% expensing of capital investments. These changes were effective January 1, 2018.
The decrease in income tax expense from 2017 to 2018 is primarily attributable to the decrease in the federal corporate income tax rate, the effect of amortizing the regulatory liability associated with excess deferred income taxes and lower pre-tax income resulting from expenses incurred for the Greater Lawrence Incident.
Refer to “Liquidity and Capital Resources” below and Note 12, "Income Taxes," in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on income taxes and the change in the effective tax rate.
Capital Investment
For the nine months ended September 30, 2018, we invested $1,296.6 million in capital expenditures across our gas and electric utilities. These expenditures were primarily aimed at furthering the safety and reliability of our gas distribution system, construction of new electric transmission assets and maintaining our existing electric generation fleet.
In connection with the Greater Lawrence Incident described above, Columbia of Massachusetts, in cooperation with the Massachusetts Governor’s office, replaced the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to approximately 8,500 gas meters, of which approximately 700 serve businesses impacted in the Greater Lawrence Incident. This system was replaced with plastic distribution mains and service lines, as well as enhanced safety features such as pressure regulation and excess flow valves at each premise. Columbia of Massachusetts is aiming to restore gas service to all homes and workplaces by December 16, 2018. At the request of the Massachusetts DPU, which was instructed by the Massachusetts Governor through his executive authority under a state of emergency, Columbia of Massachusetts has hired an outside contractor to serve as the Chief Recovery Officer for the Greater Lawrence Incident, responsible for command, control and communications. The estimated capital cost of the pipeline replacement is between $135 - $165 million. The recovery of this capital investment will be addressed in a future regulatory proceeding.
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We continue to execute on an estimated $30 billion in total projected long-term regulated utility infrastructure investments and expect to invest a total of approximately $1.7 to $1.8 billion in capital during 2018 to continue to modernize and improve our system across all seven states.
Liquidity
As discussed in further detail below in "Liquidity and Capital Resources," the enactment of the TCJA has and will continue to have an unfavorable impact on our liquidity in 2018; however, through income generated from operating activities, amounts available under our short-term revolving credit facility, commercial paper program, accounts receivable securitization facilities, term loan borrowings, long-term debt agreements and our ability to access the capital markets, we believe there is adequate capital available to fund our operating activities, capital expenditures and the effects of the Greater Lawrence Incident in 2018 and beyond. As of September 30, 2018 and December 31, 2017, we had $1,135.6 million and $998.9 million, respectively, of net liquidity available, consisting of cash and available capacity under credit facilities.
These factors and other impacts to the financial results are discussed in more detail within the following discussions of “Results and Discussion of Segment Operations” and “Liquidity and Capital Resources.”
Regulatory Developments
During the quarter ended September 30, 2018, we continued to move forward on core infrastructure and environmental investment programs supported by complementary regulatory and customer initiatives across all seven states of our operating area. The discussion below summarizes significant regulatory developments that transpired during the third quarter of 2018:
Gas Distribution Operations
• | On October 1, 2018, the first step of a three step implementation of new rates went into effect at NIPSCO following IURC approval of a settlement with parties on its gas base rate case. The settlement supports continued investment in system upgrades, technology improvements and other measures to increase pipeline safety and system reliability and will ultimately result in an annual revenue increase of $107.3 million, inclusive of amounts being recovered through various tracker programs and reflecting the impact of the TCJA. |
• | On August 31, 2018, Columbia of Pennsylvania filed a settlement agreement in its base rate case with the Pennsylvania PUC. If approved as filed, the settlement supports an annual revenue increase of $26.0 million to upgrade and replace natural gas distribution pipelines and reflects the impact of the TCJA. An order is expected in the fourth quarter of 2018 with new rates to be implemented in December 2018. |
• | On October 25, 2018, Columbia of Ohio filed a settlement agreement in its CEP application pending before the PUCO. If approved as filed, the initial $74.5 million CEP rider would allow recovery of deferred capital investments made between 2011 and 2017 that are not currently recovered through its IRP modernization tracker. The settlement also benefits customers by reducing base rates by approximately $23 million to reflect the impact of the TCJA. |
• | On August 28, 2018, Columbia of Virginia filed a base rate case with the VSCC to recover costs associated with ongoing infrastructure investment programs and to incorporate changes from the TCJA. If approved as filed, the request would result in an annual revenue increase of $22.2 million. A VSCC order is expected in the second half of 2019 with interim rates to be implemented February 1, 2019. |
• | On September 19, 2018, Columbia of Massachusetts' withdrew its base rate case pending before the Massachusetts DPU to focus on service restoration and assisting customers impacted by the Greater Lawrence Incident. |
• | A settlement of Columbia of Maryland's base rate case remains pending before the Maryland PSC. The settlement supports continued replacement of gas pipelines and pipeline safety upgrades, and reflects the impact of federal tax reform. If approved as filed, the settlement would result in an annual revenue increase of $3.7 million. A Maryland PSC order is expected in the fourth quarter of 2018 with rates anticipated to be effective November 2018. |
Electric Operations
• | On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan to the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. The Integrated Resource Plan proposes to retire R.M. Schahfer Generating Station |
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NiSource Inc.
(Units 14, 15, 17, and 18) by 2023 and Michigan City Generating Station (Unit 12) by 2028. The replacement plan is still being defined, but currently points to renewable sources of energy, including wind, solar and battery storage.
• | Also on October 31, 2018 NIPSCO filed an electric base rate case with the IURC to address anticipated revenue loss resulting from the WCE filing, as well as to address impacts of the TCJA on customer rates. If approved as filed, the request is expected to increase annual revenues by $21.4 million. An IURC order is anticipated in the third quarter of 2019, with rates effective in September 2019. |
• | NIPSCO continues to execute on its seven-year electric infrastructure modernization program, which includes enhancements to its electric transmission and distribution system designed to further improve system safety and reliability. The IURC-approved program represents approximately $1.25 billion of electric infrastructure investments expected to be made through 2022. A settlement was filed on October 25, 2018, in NIPSCO's latest tracker update request which remains pending before the IURC. It seeks a semi-annual incremental rate decrease of $11.2 million, due primarily to the pass-back to customers of a $14.1 million base rate refund for the January through May 2018 period related to the TCJA. An order is expected in the fourth quarter of 2018. |
Refer to Note 7, “Regulatory Matters,” as well as to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) for a complete discussion of key regulatory matters.
RESULTS AND DISCUSSION OF SEGMENT OPERATIONS
Presentation of Segment Information
Our operations are divided into two primary reportable segments: Gas Distribution Operations and Electric Operations.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Gas Distribution Operations
For the three and nine months ended September 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Operating Income (Loss) | $ | (455.2 | ) | $ | (15.4 | ) | $ | (439.8 | ) | $ | (94.4 | ) | $ | 367.1 | $ | (461.5 | ) | ||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Net Revenues | |||||||||||||||||||||||
Operating Revenues | $ | 421.9 | $ | 434.6 | $ | (12.7 | ) | $ | 2,357.6 | $ | 2,150.5 | $ | 207.1 | ||||||||||
Less: Cost of gas sold (excluding depreciation and amortization) | 85.7 | 94.6 | (8.9 | ) | 875.1 | 662.0 | 213.1 | ||||||||||||||||
Net Revenues | 336.2 | 340.0 | (3.8 | ) | 1,482.5 | 1,488.5 | (6.0 | ) | |||||||||||||||
Operating Expenses | |||||||||||||||||||||||
Operation and maintenance | 678.5 | 249.6 | 428.9 | 1,214.2 | 787.3 | 426.9 | |||||||||||||||||
Depreciation and amortization | 72.5 | 67.9 | 4.6 | 215.0 | 199.5 | 15.5 | |||||||||||||||||
Other taxes | 40.4 | 37.9 | 2.5 | 147.7 | 134.6 | 13.1 | |||||||||||||||||
Total Operating Expenses | 791.4 | 355.4 | 436.0 | 1,576.9 | 1,121.4 | 455.5 | |||||||||||||||||
Operating Income (Loss) | $ | (455.2 | ) | $ | (15.4 | ) | $ | (439.8 | ) | $ | (94.4 | ) | $ | 367.1 | $ | (461.5 | ) | ||||||
Revenues | |||||||||||||||||||||||
Residential | $ | 260.2 | $ | 264.2 | $ | (4.0 | ) | $ | 1,540.8 | $ | 1,404.4 | $ | 136.4 | ||||||||||
Commercial | 81.8 | 80.9 | 0.9 | 517.6 | 456.0 | 61.6 | |||||||||||||||||
Industrial | 39.2 | 39.7 | (0.5 | ) | 161.7 | 156.5 | 5.2 | ||||||||||||||||
Off-System | 22.0 | 30.4 | (8.4 | ) | 65.2 | 97.1 | (31.9 | ) | |||||||||||||||
Other | 18.7 | 19.4 | (0.7 | ) | 72.3 | 36.5 | 35.8 | ||||||||||||||||
Total | $ | 421.9 | $ | 434.6 | $ | (12.7 | ) | $ | 2,357.6 | $ | 2,150.5 | $ | 207.1 | ||||||||||
Sales and Transportation (MMDth) | |||||||||||||||||||||||
Residential | 13.8 | 14.5 | (0.7 | ) | 187.9 | 157.2 | 30.7 | ||||||||||||||||
Commercial | 17.5 | 17.3 | 0.2 | 129.7 | 111.3 | 18.4 | |||||||||||||||||
Industrial | 132.1 | 125.9 | 6.2 | 417.7 | 380.3 | 37.4 | |||||||||||||||||
Off-System | 7.5 | 11.1 | (3.6 | ) | 21.9 | 33.8 | (11.9 | ) | |||||||||||||||
Other | — | 0.3 | (0.3 | ) | 0.3 | 0.2 | 0.1 | ||||||||||||||||
Total | 170.9 | 169.1 | 1.8 | 757.5 | 682.8 | 74.7 | |||||||||||||||||
Heating Degree Days | 51 | 75 | (24 | ) | 3,498 | 2,911 | 587 | ||||||||||||||||
Normal Heating Degree Days | 85 | 85 | — | 3,576 | 3,576 | — | |||||||||||||||||
% Warmer than Normal | (40 | )% | (12 | )% | (2 | )% | (19 | )% | |||||||||||||||
Gas Distribution Customers | |||||||||||||||||||||||
Residential | 3,140,942 | 3,114,223 | 26,719 | ||||||||||||||||||||
Commercial | 276,832 | 275,424 | 1,408 | ||||||||||||||||||||
Industrial | 6,174 | 6,163 | 11 | ||||||||||||||||||||
Other | 5 | 3 | 2 | ||||||||||||||||||||
Total | 3,423,953 | 3,395,813 | 28,140 | ||||||||||||||||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Gas Distribution Operations
Comparability of line item operating results may be impacted by regulatory, tax and depreciation trackers (other than those for cost of sales) that allow for the recovery in rates of certain costs. Therefore, increases in these tracked operating expenses are generally offset by increases in net revenues and have essentially no impact on net income.
Three months ended September 30, 2018 vs. September 30, 2017 Operating Income
For the three months ended September 30, 2018, Gas Distribution Operations reported an operating loss of $455.2 million, compared to an operating loss of $15.4 million from the comparable 2017 period.
Net revenues for the three months ended September 30, 2018 were $336.2 million, a decrease of $3.8 million from the same period in 2017. The change in net revenues was primarily driven by:
• | A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $11.8 million. |
• | Decreased rates from implementation of regulatory outcomes related to the TCJA of $7.0 million. |
Partially offset by:
• | New rates from infrastructure replacement programs and base rate proceedings of $13.0 million. |
Operating expenses were $436.0 million higher for the three months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:
• | Expenses related to third-party claims and other costs following the Greater Lawrence Incident of $451.6 million. |
• | Increased depreciation of $4.8 million due to higher capital expenditures placed in service. |
Partially offset by:
•Lower employee and administrative expenses of $13.8 million.
• | Decreased outside services of $8.5 million primarily due to IT service provider transition costs in 2017. |
Nine months ended September 30, 2018 vs. September 30, 2017 Operating Income
For the nine months ended September 30, 2018, Gas Distribution Operations reported an operating loss of $94.4 million, compared to operating income of $367.1 million from the comparable 2017 period.
Net revenues for the nine months ended September 30, 2018 were $1,482.5 million, a decrease of $6.0 million from the same period in 2017. The change in net revenues was primarily driven by:
• | A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $78.2 million. |
• | Decreased rates from implementation of regulatory outcomes related to the TCJA of $13.4 million. |
Partially offset by:
• | Higher revenues from the effects of colder weather in 2018 of $34.8 million. |
• | New rates from infrastructure replacement programs and base rate proceedings of $34.7 million. |
• | Increased customer growth and usage of $13.1 million. |
• | Higher regulatory, tax and depreciation trackers, which are offset in expense, of $3.1 million. |
Operating expenses were $455.5 million higher for the nine months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:
• | Expenses related to third-party claims and other costs following the Greater Lawrence Incident of $451.6 million. |
• | Increased depreciation of $15.1 million due to higher capital expenditures placed in service. |
• | Increased property taxes of $5.1 million. |
Partially offset by:
• | Lower outside services expenses of $12.2 million primarily due to IT service provider transition costs in 2017 and ongoing savings related to the new IT service agreements. |
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Gas Distribution Operations
• | Decreased employee and administrative expenses of $9.5 million. |
Weather
In general, we calculate the weather-related revenue variance based on changing customer demand driven by weather variance from normal heating degree days. 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.
Weather in the Gas Distribution Operations service territories for the third quarter of 2018 was about 40% warmer than normal and about 32% warmer than 2017, leading to decreased net revenues of $0.1 million for the quarter ended September 30, 2018 compared to the same period in 2017. This nominal weather-related impact on net revenues for the period is expected as gas usage by customers is traditionally low in the third quarter cooling season
Weather in the Gas Distribution Operations service territories for the nine months ended September 30, 2018 was about 2% warmer than normal and about 20% colder than in 2017, leading to increased net revenues of $34.8 million for the nine months ended September 30, 2018 compared to the same period in 2017.
Throughput
Total volumes sold and transported for the third quarter of 2018 were 170.9 MMDth, compared to 169.1 MMDth for the same period in 2017.
Total volumes sold and transported for the nine months ended September 30, 2018 were 757.5 MMDth, compared to 682.8 MMDth for the same period in 2017. This 11% increase is primarily attributable to the effects of colder weather and increased industrial usage due to energy production from electric generating customers in 2018.
Economic Conditions
All of our Gas Distribution Operations companies have state-approved recovery mechanisms that provide a means for full recovery of prudently incurred gas costs. Gas costs are treated as pass-through costs and have no impact on the net revenues recorded in the period. The gas costs included in revenues are matched with the gas cost expense recorded in the period and 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.
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. These programs serve to further reduce our exposure to gas prices.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
For the three and nine months ended September 30, 2018 and 2017, operating income and a reconciliation of net revenues to the most directly comparable GAAP measure, operating income, was as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Operating Income | $ | 134.9 | $ | 125.1 | $ | 9.8 | $ | 300.4 | $ | 288.3 | $ | 12.1 | |||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(in millions) | 2018 | 2017 | 2018 vs. 2017 | 2018 | 2017 | 2018 vs. 2017 | |||||||||||||||||
Net Revenues | |||||||||||||||||||||||
Operating revenues | $ | 476.4 | $ | 486.0 | $ | (9.6 | ) | $ | 1,305.0 | $ | 1,366.1 | $ | (61.1 | ) | |||||||||
Less: Cost of sales (excluding depreciation and amortization) | 136.3 | 139.0 | (2.7 | ) | 384.6 | 400.9 | (16.3 | ) | |||||||||||||||
Net Revenues | 340.1 | 347.0 | (6.9 | ) | 920.4 | 965.2 | (44.8 | ) | |||||||||||||||
Operating Expenses | |||||||||||||||||||||||
Operation and maintenance | 123.4 | 136.0 | (12.6 | ) | 377.9 | 420.1 | (42.2 | ) | |||||||||||||||
Depreciation and amortization | 66.3 | 69.8 | (3.5 | ) | 196.3 | 212.0 | (15.7 | ) | |||||||||||||||
Other taxes | 15.5 | 16.1 | (0.6 | ) | 45.8 | 44.8 | 1.0 | ||||||||||||||||
Total Operating Expenses | 205.2 | 221.9 | (16.7 | ) | 620.0 | 676.9 | (56.9 | ) | |||||||||||||||
Operating Income | $ | 134.9 | $ | 125.1 | $ | 9.8 | $ | 300.4 | $ | 288.3 | $ | 12.1 | |||||||||||
Revenues | |||||||||||||||||||||||
Residential | $ | 154.7 | $ | 138.0 | $ | 16.7 | $ | 382.3 | $ | 363.7 | $ | 18.6 | |||||||||||
Commercial | 140.7 | 134.6 | 6.1 | 374.2 | 379.0 | (4.8 | ) | ||||||||||||||||
Industrial | 153.8 | 171.5 | (17.7 | ) | 468.7 | 531.4 | (62.7 | ) | |||||||||||||||
Wholesale | 3.8 | 3.7 | 0.1 | 12.4 | 9.0 | 3.4 | |||||||||||||||||
Other | 23.4 | 38.2 | (14.8 | ) | 67.4 | 83.0 | (15.6 | ) | |||||||||||||||
Total | $ | 476.4 | $ | 486.0 | $ | (9.6 | ) | $ | 1,305.0 | $ | 1,366.1 | $ | (61.1 | ) | |||||||||
Sales (Gigawatt Hours) | |||||||||||||||||||||||
Residential | 1,121.5 | 1,002.3 | 119.2 | 2,754.6 | 2,523.9 | 230.7 | |||||||||||||||||
Commercial | 1,079.6 | 1,042.7 | 36.9 | 2,929.0 | 2,868.1 | 60.9 | |||||||||||||||||
Industrial | 2,223.3 | 2,390.9 | (167.6 | ) | 6,785.8 | 7,192.7 | (406.9 | ) | |||||||||||||||
Wholesale | 2.5 | 6.1 | (3.6 | ) | 94.8 | 28.0 | 66.8 | ||||||||||||||||
Other | 34.7 | 31.2 | 3.5 | 95.2 | 96.3 | (1.1 | ) | ||||||||||||||||
Total | 4,461.6 | 4,473.2 | (11.6 | ) | 12,659.4 | 12,709.0 | (49.6 | ) | |||||||||||||||
Cooling Degree Days | 739 | 540 | 199 | 1,131 | 804 | 327 | |||||||||||||||||
Normal Cooling Degree Days | 570 | 570 | 799 | 799 | |||||||||||||||||||
% Warmer (Colder) than Normal | 30 | % | (5 | )% | 42 | % | 1 | % | |||||||||||||||
Electric Customers | |||||||||||||||||||||||
Residential | 410,848 | 407,998 | 2,850 | ||||||||||||||||||||
Commercial | 56,426 | 55,912 | 514 | ||||||||||||||||||||
Industrial | 2,285 | 2,311 | (26 | ) | |||||||||||||||||||
Wholesale | 736 | 740 | (4 | ) | |||||||||||||||||||
Other | 2 | 2 | — | ||||||||||||||||||||
Total | 470,297 | 466,963 | 3,334 | ||||||||||||||||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Electric Operations
Comparability of line item operating results may be impacted by regulatory and depreciation trackers (other than those for cost of sales) that allow for the recovery in rates of certain costs. Therefore, increases in these tracked operating expenses are offset by increases in net revenues and have essentially no impact on net income.
Three months ended September 30, 2018 vs. September 30, 2017 Operating Income
For the three months ended September 30, 2018, Electric Operations reported operating income of $134.9 million, an increase of $9.8 million from the comparable 2017 period.
Net revenues for the three months ended September 30, 2018 were $340.1 million, a decrease of $6.9 million from the same period in 2017. The change in net revenues was primarily driven by:
• | Decreased rates from implementation of regulatory outcomes related to the TCJA of $14.1 million. |
• | Lower regulatory and depreciation trackers, which are offset in operating expense, of $9.9 million. |
• | Decreased industrial usage of $4.6 million. |
Partially offset by:
• | The effects of warmer weather of $14.7 million. |
• | Increased rates from infrastructure replacement programs of $6.2 million. |
Operating expenses were $16.7 million lower for the three months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:
• | Lower regulatory and depreciation trackers, which are offset in net revenues, of $9.9 million. |
• | Decreased employee and administrative costs of $6.6 million. |
• | Decreased outside service costs of $5.1 million on lower generation-related maintenance activities. |
Partially offset by:
• | Increased depreciation of $2.8 million due to higher capital expenditures placed in service. |
Nine months ended September 30, 2018 vs. September 30, 2017 Operating Income
For the nine months ended September 30, 2018, Electric Operations reported operating income of $300.4 million, an increase of $12.1 million from the comparable 2017 period.
Net revenues for the nine months ended September 30, 2018 were $920.4 million, a decrease of $44.8 million from the same period in 2017. The change in net revenues was primarily driven by:
• | Lower regulatory and depreciation trackers, which are offset in operating expense, of $34.1 million. |
• | Decreased rates from implementation of regulatory outcomes related to the TCJA of $22.7 million. |
• | A revenue reserve in 2018 resulting from the probable future refund of certain collections from customers as a result of the lower income tax rate from the TCJA of $16.3 million. |
• | Decreased industrial usage of $10.1 million. |
• | Increased fuel handling costs of $5.9 million. |
Partially offset by:
• | The effects of warmer weather of $24.2 million. |
• | Increased rates from infrastructure replacement programs of $17.6 million. |
Operating expenses were $56.9 million lower for the nine months ended September 30, 2018 compared to the same period in 2017. This change was primarily driven by:
• | Decreased regulatory and depreciation trackers, which are offset in net revenues, of $34.1 million. |
• | Lower outside service costs of $20.8 million and lower materials and supplies costs of $5.3 million primarily related to lower generation-related maintenance activities. |
• | Decreased employee and administrative costs of $10.1 million. |
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NiSource Inc.
Electric Operations
Partially offset by:
• | Increased depreciation of $8.1 million due to higher capital expenditures placed in service. |
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.
Weather in the Electric Operations’ territories for the third quarter of 2018 was about 30% warmer than normal and about 37% warmer than in 2017, resulting in increased net revenues of $14.7 million for the quarter ended September 30, 2018 compared to the same period in 2017.
Weather in the Electric Operations' territories for the nine months ended September 30, 2018 was about 42% warmer than normal and about 41% warmer than 2017, resulting in increased net revenues of $24.2 million for the nine months ended September 30, 2018 compared to 2017.
Sales
Electric Operations sales for the third quarter of 2018 were 4,461.6 gwh, a decrease of 11.6 gwh compared to the same period in 2017. This decrease was primarily attributable to higher internal generation from large industrial customers during the third quarter of 2018, partially offset by increased volumes for residential and commercial customers resulting from warmer weather.
Electric Operations sales for the nine months ended September 30, 2018 were 12,659.4 gwh, a decrease of 49.6 gwh compared to the same period in 2017. This decrease was primarily attributable to higher internal generation from large industrial customers during 2018, partially offset by increased volumes for residential and commercial customers resulting from warmer weather.
BP Products North America. On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery plans to continue to purchase electric service from NIPSCO at a reduced demand level beginning May 2019. Refer to Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information.
Economic Conditions
NIPSCO has a state-approved recovery mechanism that provides a means for full recovery of prudently incurred fuel costs. Fuel costs are treated as pass-through costs and have no impact on the net revenues recorded in the period. The fuel costs included in revenues are matched with the fuel cost expense recorded in the period and 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.
Electric Supply
NIPSCO 2018 Integrated Resource Plan. On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 16-D, "Other Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information on the NIPSCO Integrated Resource Plan.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Liquidity and Capital Resources
Greater Lawrence Incident: As discussed in "Executive Summary" and Note 16, “Other Commitments and Contingencies,” we have recorded losses associated with the Greater Lawrence Incident and expect to invest capital to replace the entire affected 45-mile cast iron and bare steel pipeline system that delivers gas to the impacted area. As discussed in the Executive Summary and Note 16 referenced earlier in this paragraph, and Part II, Item 1A “Risk Factors,” in this report, we may incur additional expenses and liabilities in excess of our recorded liabilities and estimated additional costs associated with the Greater Lawrence Incident. The timing and amount of future financing needs, if any, will depend on the ultimate timing and amount of payments made to third parties in connection with the Greater Lawrence Incident and the timing and amount of associated insurance recoveries. Through income generated from operating activities, amounts available under our short-term revolving credit facility, commercial paper program, accounts receivable securitization facilities, term loan borrowings, long-term debt agreements and our ability to access the capital markets, we believe there is adequate capital available to fund these expenditures.
Operating Activities
Net cash from operating activities for the nine months ended September 30, 2018 was $927.2 million, an increase of $397.6 million compared to the nine months ended September 30, 2017. This increase was driven by decreased pension plan contributions as discussed below as well as changes in gas prices, which impacted working capital. Additionally, cash from operations increased as a result of higher sales due to colder weather during the 2018 winter heating season compared to 2017 and increased rates from infrastructure replacement programs.
Pension and Other Postretirement Plan Funding. During the nine months ended September 30, 2017, we contributed $281.6 million to our pension plans (including a $277 million discretionary contribution made during the third quarter of 2017) and $21.8 million to our other postretirement benefit plans.
For the nine months ended September 30, 2018, we contributed $2.1 million to our pension plans and $16.8 million to our other postretirement benefit plans.
Income Taxes. Rates for our regulated customers include provisions for the collection of U.S. federal income taxes. The reduction in the U.S. federal corporate income tax rate as a result of the TCJA has, and is expected to continue to lead to a decrease in the amount billed to customers through rates, ultimately resulting in lower cash collections from operating activities. As discussed in further detail in Note 7, "Regulatory Matters," in the Notes to Condensed Consolidated Financial Statements (unaudited), our regulated subsidiaries are engaged with the relevant state utility commissions to address the impacts of the TCJA on future customer rates. Through the first nine months of 2018, billings to customers decreased approximately $36.1 million compared to the same period in 2017 as a result of adjustments to certain rates in our Kentucky, Ohio, Maryland, Massachusetts and Indiana jurisdictions. Additionally, during the first nine months of 2018, we recorded additional TCJA-related regulatory liabilities of $69.9 million related to 2018 collections from customers, which we believe are probable of being refunded back to customers once new customer rates are approved by our regulators.
In addition, we will be required to pass back to customers “excess deferred taxes,” which represent amounts collected from customers in the past to cover deferred tax liabilities that, as a result of the passage of the TCJA, are now expected to be less than the originally billed amounts. Approximately $1.5 billion of excess deferred taxes related to implementation of the TCJA were recorded within "Regulatory liabilities (noncurrent)" on the Condensed Consolidated Balance Sheets (unaudited) as of December 31, 2017. The majority of these balances relate to temporary book-to-tax differences on utility property protected by IRS normalization rules. Once modified rates are approved by our regulators, we expect this portion of the balance will be passed back to customers over the remaining average useful life of the associated property. The pass back period for the remainder of the balance will be determined by our state utility commissions in future proceedings. Our estimate of the amount and pass-back period of excess deferred taxes is subject to change pending final review by the utility commissions of the states in which we operate.
As of September 30, 2018, we had a recorded deferred tax asset of $574.9 million related to a Federal NOL carryforward. As a result of being in an NOL position, we were not required to make any cash payments for Federal income tax purposes during the nine months ended September 30, 2018 or 2017. This NOL carryforward expires in 2030; however, we expect to fully utilize the carryforward benefit prior to its expiration.
Investing Activities
Net cash used for investing activities for the nine months ended September 30, 2018 was $1,376.5 million, an increase of $69.8 million compared to the nine months ended September 30, 2017. This increase was mostly attributable to increased capital expenditures in 2018.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Our capital expenditures for the nine months ended September 30, 2018 were $1,296.6 million compared to $1,216.4 million for the comparable period in 2017. The increase was driven by an increase in planned capital expenditures in the current year and the timing of payments through September 2018 compared to September 2017. We project total 2018 capital expenditures to be approximately $1.7 to $1.8 billion.
Financing Activities
Common Stock and Preferred Stock. Refer to Note 5, “Equity,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on common and preferred stock activity.
Long-term Debt. Refer to Note 14, “Long-Term Debt,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on long-term debt activity.
Short-term Debt. Refer to Note 15, “Short-Term Borrowings,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on short-term debt activity.
Net Available Liquidity. As of September 30, 2018, an aggregate of $1,135.6 million of net liquidity was available, including cash and credit available under the revolving credit facility and accounts receivable securitization programs.
The following table displays our liquidity position as of September 30, 2018 and December 31, 2017:
(in millions) | September 30, 2018 | December 31, 2017 | ||||
Current Liquidity | ||||||
Revolving Credit Facility | $ | 1,850.0 | $ | 1,850.0 | ||
Accounts Receivable Program(1) | 265.0 | 336.7 | ||||
Less: | ||||||
Commercial Paper | 746.0 | 869.0 | ||||
Accounts Receivable Program Utilized | 265.0 | 336.7 | ||||
Letters of Credit Outstanding Under Credit Facility | 10.2 | 11.1 | ||||
Add: | ||||||
Cash and Cash Equivalents | 41.8 | 29.0 | ||||
Net Available Liquidity | $ | 1,135.6 | $ | 998.9 | ||
(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 and term loan agreement, which require us to maintain a debt to capitalization ratio that does not exceed 70%. A similar covenant in a 2005 private placement note purchase agreement requires us to maintain a debt to capitalization ratio that does not exceed 75%. As of September 30, 2018, the ratio was 63.3%.
Sale of Trade Accounts Receivables. Refer to Note 10, “Transfers of Financial Assets,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for information on the sale of trade accounts receivable.
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 certain of our subsidiaries' credit ratings and ratings outlook as of September 30, 2018. In June 2018, Fitch upgraded the NiSource Commercial Paper rating to 'F2' from 'F3'. In September 2018, as a result of potential impacts of the Greater Lawrence Incident, S&P changed our outlook from Stable to Negative. In October 2018, Fitch affirmed both NiSource and NIPSCO ratings of BBB. There were no other changes to the below credit ratings or outlooks since December 31, 2017.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
S&P | Moody's | Fitch | ||||
Rating | Outlook | Rating | Outlook | Rating | Outlook | |
NiSource | BBB+ | Negative | Baa2 | Stable | BBB | Stable |
NIPSCO | BBB+ | Negative | Baa1 | Stable | BBB | Stable |
Columbia of Massachusetts | BBB+ | Negative | Baa2 | Stable | Not rated | Not rated |
Commercial Paper | A-2 | Negative | 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, 2018, the collateral requirement that would be required in the event of a downgrade below the ratings trigger levels would amount to approximately $56.1 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 420,000,000 shares, $0.01 par value, of which 400,000,000 are common stock and 20,000,000 are preferred stock. As of September 30, 2018, 363,167,067 shares of common stock and 400,000 shares of preferred stock were outstanding.
Contractual Obligations. Aside from the previously referenced issuances and repayments of long-term debt and payments associated with the Greater Lawrence Incident, there were no material changes recorded during the nine months ended September 30, 2018 to our contractual obligations as of December 31, 2017.
Off Balance Sheet Arrangements
We, along with certain of our subsidiaries, enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees and stand-by letters of credit.
Refer to Note 16, “Other Commitments and Contingencies,” in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about such arrangements.
Market Risk Disclosures
Risk is an inherent part of our businesses. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to our profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal market risks that are involved in our businesses: commodity price risk, interest rate risk and credit risk. Risk management for us is a multi-faceted process with oversight by the Risk Management Committee that requires constant communication, judgment and knowledge of specialized products and markets. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These may include, but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of the energy business, our risk management process, policies and procedures continue to evolve and are subject to ongoing review and modification.
Commodity Price Risk
We are exposed to commodity price risk as a result of our subsidiaries’ operations involving natural gas and power. To manage this market risk, our subsidiaries use derivatives, including commodity futures contracts, swaps, forwards and options. We do not participate in speculative energy trading activity.
Commodity price risk resulting from derivative activities at our rate-regulated subsidiaries is limited, since regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the ratemaking process, including gains or losses on these derivative instruments. If states should explore additional regulatory reform, these subsidiaries may begin providing services without the benefit of the traditional ratemaking process and may be more exposed to commodity price risk.
Our subsidiaries are required to make cash margin deposits with their brokers to cover actual and potential losses in the value of outstanding exchange traded derivative contracts. The amount of these deposits, some of which is reflected in our restricted cash balance, may fluctuate significantly during periods of high volatility in the energy commodity markets.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
NiSource Inc.
Refer to Note 8, "Risk Management Activities," in the Notes to Condensed Consolidated Financial Statements (unaudited) for further information on our commodity price risk assets and liabilities as of September 30, 2018 or December 31, 2017.
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, accounts receivable programs and term loan, 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 $3.1 million and $9.1 million for the three and nine months ended September 30, 2018, and $3.7 million and $12.6 million for the three and nine months ended September 30, 2017, respectively. We are also exposed to interest rate risk as a result of changes in benchmark rates that can influence the interest rates of future debt issuances.
Refer to Note 8, "Risk Management Activities," in the Notes to Condensed Consolidated Financial Statements (unaudited) for further information on our interest rate risk assets and liabilities as of September 30, 2018 and December 31, 2017.
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
Refer to Note 16, "Other Commitments and Contingencies," in the Notes to Condensed Consolidated Financial Statements (unaudited) and Item 1A, "Risk Factors," for additional information about management judgment used in the development of estimates related to the Greater Lawrence Incident.
Recently Issued Accounting Pronouncements
Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Condensed Consolidated Financial Statements (unaudited) for additional information about recently issued and adopted accounting pronouncements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NiSource Inc.
For a discussion regarding quantitative and qualitative disclosures about market risk see “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 fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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PART II
ITEM 1. LEGAL PROCEEDINGS
NiSource Inc.
For a description of the Company’s legal proceedings, see Note 16-B, "Legal Proceedings," in the Notes to Condensed Consolidated Financial Statements (unaudited).
ITEM 1A. RISK FACTORS
Our operations and financial results are subject to various risks and uncertainties, including those disclosed in our most recent Annual Report on Form 10-K for the year ended December 31, 2017, and as set forth below.
The Greater Lawrence Incident may have a material adverse impact on the Company’s and Columbia of Massachusetts' financial condition, results of operations and cash flows.
In connection with the Greater Lawrence Incident, the Company has incurred and will incur various costs and expenses as set forth in Note 16, "Other Commitments and Contingencies - B. Legal Proceedings," and " - D. Other Matters" in the Notes to Condensed Consolidated Financial Statements (unaudited). As more information becomes known, including information resulting from the NTSB investigation, management’s estimates and assumptions regarding the financial impact of the Greater Lawrence Incident may change. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on the Company’s and Columbia of Massachusetts' financial condition and results of operations during the period in which such change occurred.
In addition, the Company is unable to predict the timing and amount of insurance recoveries. If Columbia of Massachusetts is ultimately unable to recover losses related to the Greater Lawrence Incident from insurance, the Company's and Columbia of Massachusetts' financial condition, results of operations and cash flows could be materially adversely affected.
Columbia of Massachusetts also may incur costs, beyond the amount currently anticipated, in response to NTSB, Massachusetts DPU or other orders or requests as the investigations continue. Further, state or federal legislation may be enacted that would require Columbia of Massachusetts to incur additional costs by mandating various changes, including changes to its operating practice standards for natural gas distribution operations and safety. If Columbia of Massachusetts is unable to recover the capital cost of the gas pipeline replacement in the impacted area or incurs a material amount of other costs that it is unable to recover through rates or offset through operational or other cost savings, the Company’s and Columbia of Massachusetts' financial condition, results of operations, and cash flows would be materially and adversely affected.
Further, if it is determined that Columbia of Massachusetts did not comply with applicable statutes, regulations, rules, tariffs, or orders in connection with the Greater Lawrence Incident or in connection with the operations or maintenance of Columbia of Massachusetts’ natural gas system, and Columbia of Massachusetts is ordered to pay a material amount in customer refunds, penalties, or other amounts, the Company’s and Columbia of Massachusetts' financial condition, results of operations, and cash flows would be materially and adversely affected.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
NiSource Inc.
(10.1) | |
(10.2) | |
(10.3) | |
(31.1) | |
(31.2) | |
(32.1) | |
(32.2) | |
(101.INS) | XBRL Instance Document |
(101.SCH) | XBRL Schema Document |
(101.CAL) | XBRL Calculation Linkbase Document |
(101.LAB) | XBRL Labels Linkbase Document |
(101.PRE) | XBRL Presentation Linkbase Document |
(101.DEF) | XBRL Definition Linkbase Document |
* | Exhibit filed herewith. |
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SIGNATURE
NiSource Inc.
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 1, 2018 | By: | /s/ Joseph W. Mulpas | |
Joseph W. Mulpas | ||||
Vice President and Chief Accounting Officer (Principal Accounting Officer) | ||||
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