NORTHWESTERN CORP - Quarter Report: 2023 March (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| (mark one) | |||||||||||
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||||
| For the quarterly period ended | March 31, 2023 | ||||||||||
| 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: 1-10499
NORTHWESTERN CORP
(Exact name of registrant as specified in its charter)
| Delaware | 46-0172280 | |||||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||
| 3010 W. 69th Street | Sioux Falls | South Dakota | 57108 | |||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
Registrant’s telephone number, including area code: 605-978-2900
N/A
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| Common stock | NWE | Nasdaq Stock Market LLC | ||||||
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 x No o
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 x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | ☒ | Accelerated Filer | ☐ | Non-accelerated Filer | ☐ | Smaller Reporting Company | ☐ | Emerging Growth 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Common Stock, Par Value $0.01, 59,794,897 shares outstanding at April 21, 2023
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NORTHWESTERN CORPORATION
FORM 10-Q
INDEX
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to our current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, our examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:
•adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;
•the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;
•acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;
•supply chain constraints, recent high levels of inflation for product, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;
•changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
•unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and
•adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.
We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.
From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.
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We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.
Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.
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| PART 1. FINANCIAL INFORMATION | ||||||||||||||
ITEM 1.FINANCIAL STATEMENTS
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per share amounts)
| Three Months Ended March 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Revenues | |||||||||||
| Electric | $ | 295,308 | $ | 271,727 | |||||||
| Gas | 159,234 | 122,755 | |||||||||
| Total Revenues | 454,542 | 394,482 | |||||||||
| Operating expenses | |||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 165,492 | 135,073 | |||||||||
| Operating and maintenance | 55,861 | 52,794 | |||||||||
| Administrative and general | 34,748 | 31,644 | |||||||||
| Property and other taxes | 49,151 | 46,850 | |||||||||
| Depreciation and depletion | 53,248 | 48,905 | |||||||||
| Total Operating Expenses | 358,500 | 315,266 | |||||||||
| Operating income | 96,042 | 79,216 | |||||||||
| Interest expense, net | (28,008) | (23,716) | |||||||||
| Other income, net | 4,737 | 4,721 | |||||||||
| Income before income taxes | 72,771 | 60,221 | |||||||||
| Income tax expense | (10,241) | (1,111) | |||||||||
| Net Income | $ | 62,530 | $ | 59,110 | |||||||
| Average Common Shares Outstanding | 59,776 | 54,097 | |||||||||
| Basic Earnings per Average Common Share | $ | 1.05 | $ | 1.09 | |||||||
| Diluted Earnings per Average Common Share | $ | 1.05 | $ | 1.08 | |||||||
| Dividends Declared per Common Share | $ | 0.64 | $ | 0.63 | |||||||
See Notes to Condensed Consolidated Financial Statements
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NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(in thousands)
| Three Months Ended March 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Net Income | $ | 62,530 | $ | 59,110 | |||||||
| Other comprehensive income, net of tax: | |||||||||||
| Foreign currency translation adjustment | (2) | (2) | |||||||||
| Postretirement medical liability adjustment | (167) | (158) | |||||||||
| Reclassification of net losses on derivative instruments | 113 | 113 | |||||||||
| Total Other Comprehensive Loss | (56) | (47) | |||||||||
| Comprehensive Income | $ | 62,474 | $ | 59,063 | |||||||
See Notes to Condensed Consolidated Financial Statements
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NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
| March 31, 2023 | December 31, 2022 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 10,730 | $ | 8,489 | |||||||
| Restricted cash | 16,372 | 13,974 | |||||||||
| Accounts receivable, net | 218,744 | 244,952 | |||||||||
| Inventories | 92,545 | 107,359 | |||||||||
| Regulatory assets | 86,618 | 136,009 | |||||||||
| Prepaid expenses and other | 23,327 | 28,041 | |||||||||
| Total current assets | 448,336 | 538,824 | |||||||||
| Property, plant, and equipment, net | 5,702,670 | 5,657,480 | |||||||||
| Goodwill | 357,586 | 357,586 | |||||||||
| Regulatory assets | 724,441 | 716,570 | |||||||||
| Other noncurrent assets | 47,961 | 47,323 | |||||||||
| Total Assets | $ | 7,280,994 | $ | 7,317,783 | |||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Current maturities of finance leases | $ | 3,155 | $ | 3,098 | |||||||
| Current portion of long-term debt | 244,382 | 144,525 | |||||||||
| Accounts payable | 104,757 | 201,498 | |||||||||
| Accrued expenses and other | 308,620 | 250,579 | |||||||||
| Regulatory liabilities | 19,767 | 21,145 | |||||||||
| Total current liabilities | 680,681 | 620,845 | |||||||||
| Long-term finance leases | 7,996 | 8,799 | |||||||||
| Long-term debt | 2,340,588 | 2,474,357 | |||||||||
| Deferred income taxes | 541,321 | 538,983 | |||||||||
| Noncurrent regulatory liabilities | 659,189 | 654,213 | |||||||||
| Other noncurrent liabilities | 358,219 | 355,403 | |||||||||
| Total Liabilities | 4,587,994 | 4,652,600 | |||||||||
| Commitments and Contingencies (Note 10) | |||||||||||
| Shareholders' Equity: | |||||||||||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 63,326,346 and 59,793,691 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | 633 | 633 | |||||||||
| Treasury stock at cost | (98,471) | (98,392) | |||||||||
| Paid-in capital | 2,002,839 | 1,999,376 | |||||||||
| Retained earnings | 795,903 | 771,414 | |||||||||
| Accumulated other comprehensive loss | (7,904) | (7,848) | |||||||||
| Total Shareholders' Equity | 2,693,000 | 2,665,183 | |||||||||
| Total Liabilities and Shareholders' Equity | $ | 7,280,994 | $ | 7,317,783 | |||||||
See Notes to Condensed Consolidated Financial Statements
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NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
| Three Months Ended March 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| OPERATING ACTIVITIES: | |||||||||||
| Net income | $ | 62,530 | $ | 59,110 | |||||||
| Items not affecting cash: | |||||||||||
| Depreciation and depletion | 53,248 | 48,905 | |||||||||
| Amortization of debt issuance costs, discount and deferred hedge gain | 1,349 | 1,270 | |||||||||
| Stock-based compensation costs | 3,308 | 2,757 | |||||||||
| Equity portion of allowance for funds used during construction | (3,715) | (3,116) | |||||||||
| Loss on disposition of assets | (18) | (1) | |||||||||
| Deferred income taxes | (10,420) | (6,558) | |||||||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable | 26,208 | 24,936 | |||||||||
| Inventories | 14,814 | 10,005 | |||||||||
| Other current assets | 4,714 | 1,181 | |||||||||
| Accounts payable | (44,193) | (3,432) | |||||||||
| Accrued expenses and other | 58,236 | 46,119 | |||||||||
| Regulatory assets | 49,391 | 14,961 | |||||||||
| Regulatory liabilities | (1,378) | (1,003) | |||||||||
| Other noncurrent assets | 1,290 | 7,153 | |||||||||
| Other noncurrent liabilities | (1,665) | (6,621) | |||||||||
| Cash Provided by Operating Activities | 213,699 | 195,666 | |||||||||
| INVESTING ACTIVITIES: | |||||||||||
| Property, plant, and equipment additions | (136,604) | (115,502) | |||||||||
| Investment in equity securities | — | (567) | |||||||||
| Cash Used in Investing Activities | (136,604) | (116,069) | |||||||||
| FINANCING ACTIVITIES: | |||||||||||
| Dividends on common stock | (38,041) | (33,901) | |||||||||
| Issuance of long-term debt | 220,000 | — | |||||||||
| Line of credit repayments, net | (253,000) | (33,000) | |||||||||
| Other financing activities, net | (1,415) | (560) | |||||||||
| Cash Used in Financing Activities | (72,456) | (67,461) | |||||||||
| Increase in Cash, Cash Equivalents, and Restricted Cash | 4,639 | 12,136 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, beginning of period | 22,463 | 18,762 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, end of period | $ | 27,102 | $ | 30,898 | |||||||
| Supplemental Cash Flow Information: | |||||||||||
| Cash paid during the period for: | |||||||||||
| Income taxes | $ | 3,204 | $ | — | |||||||
| Interest | 18,196 | 14,152 | |||||||||
| Significant non-cash transactions: | |||||||||||
| Capital expenditures included in accounts payable | 12,209 | 17,156 | |||||||||
See Notes to Condensed Consolidated Financial Statements
8
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Unaudited)
(in thousands, except per share data)
| Three Months Ended March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| Number of Common Shares | Number of Treasury Shares | Common Stock | Treasury Stock | Paid in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Total Shareholders' Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 57,606 | 3,546 | $ | 576 | $ | (98,248) | $ | 1,716,227 | $ | 728,468 | $ | (7,310) | $ | 2,339,713 | |||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 59,110 | — | 59,110 | |||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | — | — | — | — | — | — | (2) | (2) | |||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | — | — | — | — | — | — | 113 | 113 | |||||||||||||||||||||||||||||||||||||||
| Postretirement medical liability adjustment, net of tax | — | — | — | — | — | — | (158) | (158) | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | 87 | 16 | 1 | (911) | 2,746 | — | — | 1,836 | |||||||||||||||||||||||||||||||||||||||
| Issuance of shares | — | (6) | — | 173 | 97 | — | — | 270 | |||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($0.630 per share) | — | — | — | — | — | (33,901) | — | (33,901) | |||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2022 | 57,693 | 3,556 | $ | 577 | $ | (98,986) | $ | 1,719,070 | $ | 753,677 | $ | (7,357) | $ | 2,366,981 | |||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 63,278 | 3,534 | $ | 633 | $ | (98,392) | $ | 1,999,376 | $ | 771,414 | $ | (7,848) | $ | 2,665,183 | |||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 62,530 | — | 62,530 | |||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustment, net of tax | — | — | — | — | — | — | (2) | (2) | |||||||||||||||||||||||||||||||||||||||
| Reclassification of net losses on derivative instruments from OCI to net income, net of tax | — | — | — | — | — | — | 113 | 113 | |||||||||||||||||||||||||||||||||||||||
| Postretirement medical liability adjustment, net of tax | — | — | — | — | — | — | (167) | (167) | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | 48 | — | — | (79) | 3,294 | — | — | 3,215 | |||||||||||||||||||||||||||||||||||||||
| Issuance of shares | — | (1) | — | — | 169 | — | — | 169 | |||||||||||||||||||||||||||||||||||||||
Dividends on common stock ($0.640 per share) | — | — | — | — | — | (38,041) | — | (38,041) | |||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2023 | 63,326 | 3,533 | $ | 633 | $ | (98,471) | $ | 2,002,839 | $ | 795,903 | $ | (7,904) | $ | 2,693,000 | |||||||||||||||||||||||||||||||||
See Notes to Condensed Consolidated Financial Statements
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)
(Unaudited)
(1) Nature of Operations and Basis of Consolidation
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires us to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in our opinion, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to March 31, 2023 have been evaluated as to their potential impact to the Financial Statements through the date of issuance.
The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the condensed disclosures provided are adequate to make the information presented not misleading. We recommend that these Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2022.
Supplemental Cash Flow Information
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):
| March 31, | December 31, | March 31, | December 31, | |||||||||||
| 2023 | 2022 | 2022 | 2021 | |||||||||||
| Cash and cash equivalents | $ | 10,730 | $ | 8,489 | $ | 13,645 | $ | 2,820 | ||||||
| Restricted cash | 16,372 | 13,974 | 17,253 | 15,942 | ||||||||||
| Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows | $ | 27,102 | $ | 22,463 | $ | 30,898 | $ | 18,762 | ||||||
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(2) Regulatory Matters
Except as set forth below, the circumstances set forth in Note 3 - Regulatory Matters to the financial statements included in our Annual Report on the Form 10-K for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our regulatory matters.
Montana Rate Review
On August 8, 2022, we filed a Montana electric and natural gas rate review with the Montana Public Service Commission (MPSC) requesting an annual increase to electric and natural gas utility rates. On September 28, 2022, the MPSC approved the recommendations of the MPSC Staff for interim rates effective October 1, 2022, subject to refund. Subsequently, we modified our request through rebuttal testimony. On April 3, 2023, we filed a settlement with certain parties in our Montana electric and natural gas rate review, which is subject to approval by the MPSC. The details of our request, as so modified, the interim rates granted, and the settlement agreement are set forth below:
| Requested Revenue Increase Through Rebuttal Testimony (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $90.6 | $22.4 | ||||||
PCCAM(1) | $69.7 | n/a | ||||||
Property Tax (tracker true-up)(1) | $14.5 | $4.2 | ||||||
| Total Revenue Increase Requested through Rebuttal Testimony | $174.8 | $26.6 | ||||||
| Interim Revenue Increase Granted (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $29.4 | $1.7 | ||||||
Power Cost & Credit Mechanism (PCCAM)(1) | $61.1 | n/a | ||||||
Property Tax (tracker true-up)(1)(2) | $10.8 | $2.9 | ||||||
| Total Interim Revenue Granted | $101.3 | $4.6 | ||||||
| Requested Revenue Increase Through Settlement Agreement (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $67.4 | $14.1 | ||||||
PCCAM(1) | $69.7 | n/a | ||||||
Property Tax (tracker true-up)(1) | $14.5 | $4.2 | ||||||
| Total Revenue Increase Requested Through Settlement Agreement | $151.6 | $18.3 | ||||||
(1) These items are flow-through costs.
(2) While our requested interim property tax base increases were denied from interim rates, these rates went into effect on January 1, 2023, as part of our 2023 property tax tracker period true-up.
The settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms. The settlement is based on a 48.02 percent equity component of our capital structure and an authorized return on equity of 9.65 percent for electric operations and 9.55 percent for natural gas operations, which are consistent with current authorized return on equity amounts.
The settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.
A hearing commenced on April 11, 2023 and concluded on April 18, 2023. Interim rates will remain in effect on a refundable basis until the MPSC issues a final order.
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Holding Company Filings
As previously reported, on June 1, 2022, we filed a legal corporate restructuring application (Restructuring Plan) with the state commissions in Montana, South Dakota and Nebraska and the Federal Energy Regulatory Commission (FERC). Currently, our utility businesses are held in the same legal entity. Under the proposed Restructuring Plan, we would legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to segregate our organizational structure to be more transparent and in line with the public utility industry.
The Restructuring Plan does not propose and we do not expect any procedural or substantive change in how the state public utility commissions regulate those services. Implementation of the Restructuring Plan is subject to receipt of all regulatory approvals. During 2022, we received approvals from the Nebraska Public Service Commission, South Dakota Public Service Commission, and the FERC. On February 21, 2023, the MPSC approved the Restructuring Plan. We are currently developing implementation timing to effectuate the Restructuring Plan.
(3) Income Taxes
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in thousands):
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| Income before income taxes | $ | 72,771 | $ | 60,221 | |||||||||||||||||||
| Income tax calculated at federal statutory rate | 15,282 | 21.0 | % | 12,646 | 21.0 | % | |||||||||||||||||
| Permanent or flow-through adjustments: | |||||||||||||||||||||||
| State income tax, net of federal provisions | 959 | 1.3 | 400 | 0.7 | |||||||||||||||||||
| Flow-through repairs deductions | (5,845) | (8.0) | (6,801) | (11.3) | |||||||||||||||||||
| Production tax credits | (3,199) | (4.4) | (3,824) | (6.4) | |||||||||||||||||||
| Amortization of excess deferred income tax | (799) | (1.1) | (411) | (0.7) | |||||||||||||||||||
| Reduction to previously claimed alternative minimum tax credit | 3,186 | 4.4 | — | — | |||||||||||||||||||
| Plant and depreciation of flow-through items | 688 | 0.9 | (255) | (0.4) | |||||||||||||||||||
| Share-based compensation | 388 | 0.5 | (253) | (0.4) | |||||||||||||||||||
| Other, net | (419) | (0.5) | (391) | (0.7) | |||||||||||||||||||
| (5,041) | (6.9) | (11,535) | (19.2) | ||||||||||||||||||||
| Income tax expense | $ | 10,241 | 14.1 | % | $ | 1,111 | 1.8 | % | |||||||||||||||
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Uncertain Tax Positions
We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We had unrecognized tax benefits of approximately $29.9 million as of March 31, 2023, including approximately $27.9 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.
Our policy is to recognize interest and penalties in income tax expense. As of March 31, 2023, we have accrued $1.7 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets. As of December 31, 2022, we had accrued $1.4 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets.
Tax years 2019 and forward remain subject to examination by the Internal Revenue Service and state taxing authorities. During the first quarter of 2023 the IRS commenced a limited scope examination of the Company's 2019 amended federal income tax return. This examination concluded in the first quarter of 2023 and resulted in a reduction to our previously claimed alternative minimum tax credit refund.
(4) Comprehensive (Loss) Income
The following tables display the components of Other Comprehensive (Loss) Income, after-tax, and the related tax effects (in thousands):
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| March 31, 2023 | March 31, 2022 | ||||||||||||||||||||||||||||||||||
| Before-Tax Amount | Tax Expense | Net-of-Tax Amount | Before-Tax Amount | Tax Expense | Net-of-Tax Amount | ||||||||||||||||||||||||||||||
| Foreign currency translation adjustment | $ | (2) | $ | — | $ | (2) | $ | (2) | $ | — | $ | (2) | |||||||||||||||||||||||
| Reclassification of net income on derivative instruments | 153 | (40) | 113 | 153 | (40) | 113 | |||||||||||||||||||||||||||||
| Postretirement medical liability adjustment | (212) | 45 | (167) | (212) | 54 | (158) | |||||||||||||||||||||||||||||
| Other comprehensive (loss) income | $ | (61) | $ | 5 | $ | (56) | $ | (61) | $ | 14 | $ | (47) | |||||||||||||||||||||||
Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):
| March 31, 2023 | December 31, 2022 | ||||||||||
| Foreign currency translation | $ | 1,433 | $ | 1,435 | |||||||
| Derivative instruments designated as cash flow hedges | (9,712) | (9,825) | |||||||||
| Postretirement medical plans | 375 | 542 | |||||||||
| Accumulated other comprehensive loss | $ | (7,904) | $ | (7,848) | |||||||
The following tables display the changes in AOCL by component, net of tax (in thousands):
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| Three Months Ended | |||||||||||||||||||||||||||||
| March 31, 2023 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | (9,825) | $ | 542 | $ | 1,435 | $ | (7,848) | |||||||||||||||||||||
| Other comprehensive loss before reclassifications | — | — | (2) | (2) | |||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | 113 | — | — | 113 | ||||||||||||||||||||||||
| Amounts reclassified from AOCL | — | (167) | — | (167) | |||||||||||||||||||||||||
| Net current-period other comprehensive income (loss) | 113 | (167) | (2) | (56) | |||||||||||||||||||||||||
| Ending balance | $ | (9,712) | $ | 375 | $ | 1,433 | $ | (7,904) | |||||||||||||||||||||
| Three Months Ended | |||||||||||||||||||||||||||||
| March 31, 2022 | |||||||||||||||||||||||||||||
| Affected Line Item in the Condensed Consolidated Statements of Income | Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Postretirement Medical Plans | Foreign Currency Translation | Total | |||||||||||||||||||||||||
| Beginning balance | $ | (10,277) | $ | 1,524 | $ | 1,443 | $ | (7,310) | |||||||||||||||||||||
| Other comprehensive loss before reclassifications | — | — | (2) | (2) | |||||||||||||||||||||||||
| Amounts reclassified from AOCL | Interest Expense | 113 | — | — | 113 | ||||||||||||||||||||||||
| Amounts reclassified from AOCL | — | (158) | — | (158) | |||||||||||||||||||||||||
| Net current-period other comprehensive income (loss) | 113 | (158) | (2) | (47) | |||||||||||||||||||||||||
| Ending balance | $ | (10,164) | $ | 1,366 | $ | 1,441 | $ | (7,357) | |||||||||||||||||||||
(5) Financing Activities
On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. We received proceeds totaling $220.0 million on March 30, 2023. We will receive the remaining $50.0 million of proceeds, associated with the Montana First Mortgage Bonds, on May 1, 2023. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.
On March 29, 2023, we priced an additional $30.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent. We expect to complete the issuance and sale of these bonds on May 1, 2023 and they will mature on May 1, 2033.
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(6) Segment Information
Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs and unregulated activity.
We evaluate the performance of these segments based on utility margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by us for internal reporting purposes and involves estimates and assumptions.
Financial data for the business segments are as follows (in thousands):
| Three Months Ended | |||||||||||||||||||||||||||||
| March 31, 2023 | Electric | Gas | Other | Eliminations | Total | ||||||||||||||||||||||||
| Operating revenues | $ | 295,308 | $ | 159,234 | $ | — | $ | — | $ | 454,542 | |||||||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 78,134 | 87,358 | — | — | 165,492 | ||||||||||||||||||||||||
| Utility margin | 217,174 | 71,876 | — | — | 289,050 | ||||||||||||||||||||||||
| Operating and maintenance | 42,413 | 13,448 | — | — | 55,861 | ||||||||||||||||||||||||
| Administrative and general | 24,968 | 9,766 | 14 | — | 34,748 | ||||||||||||||||||||||||
| Property and other taxes | 38,251 | 10,898 | 2 | — | 49,151 | ||||||||||||||||||||||||
| Depreciation and depletion | 43,898 | 9,350 | — | — | 53,248 | ||||||||||||||||||||||||
| Operating income (loss) | 67,644 | 28,414 | (16) | — | 96,042 | ||||||||||||||||||||||||
| Interest expense, net | (18,560) | (3,251) | (6,197) | — | (28,008) | ||||||||||||||||||||||||
| Other income (expense), net | 3,366 | 1,415 | (44) | — | 4,737 | ||||||||||||||||||||||||
| Income tax (expense) benefit | (6,628) | 234 | (3,847) | — | (10,241) | ||||||||||||||||||||||||
| Net income (loss) | $ | 45,822 | $ | 26,812 | $ | (10,104) | $ | — | $ | 62,530 | |||||||||||||||||||
| Total assets | $ | 5,874,061 | $ | 1,399,717 | $ | 7,216 | $ | — | $ | 7,280,994 | |||||||||||||||||||
| Capital expenditures | $ | 120,819 | $ | 15,785 | $ | — | $ | — | $ | 136,604 | |||||||||||||||||||
| Three Months Ended | |||||||||||||||||||||||||||||
| March 31, 2022 | Electric | Gas | Other | Eliminations | Total | ||||||||||||||||||||||||
| Operating revenues | $ | 271,727 | $ | 122,755 | $ | — | $ | — | $ | 394,482 | |||||||||||||||||||
| Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 77,623 | 57,450 | — | — | 135,073 | ||||||||||||||||||||||||
| Utility margin | 194,104 | 65,305 | — | — | 259,409 | ||||||||||||||||||||||||
| Operating and maintenance | 39,501 | 13,293 | — | — | 52,794 | ||||||||||||||||||||||||
| Administrative and general | 22,737 | 8,652 | 255 | — | 31,644 | ||||||||||||||||||||||||
| Property and other taxes | 36,425 | 10,423 | 2 | — | 46,850 | ||||||||||||||||||||||||
| Depreciation and depletion | 40,424 | 8,481 | — | — | 48,905 | ||||||||||||||||||||||||
| Operating income (loss) | 55,017 | 24,456 | (257) | — | 79,216 | ||||||||||||||||||||||||
| Interest expense, net | (18,969) | (3,390) | (1,357) | — | (23,716) | ||||||||||||||||||||||||
| Other income, net | 2,982 | 1,530 | 209 | — | 4,721 | ||||||||||||||||||||||||
| Income tax (expense) benefit | (994) | (1,382) | 1,265 | — | (1,111) | ||||||||||||||||||||||||
| Net income (loss) | $ | 38,036 | $ | 21,214 | $ | (140) | $ | — | $ | 59,110 | |||||||||||||||||||
| Total assets | $ | 5,523,726 | $ | 1,291,946 | $ | 6,363 | $ | — | $ | 6,822,035 | |||||||||||||||||||
| Capital expenditures | $ | 98,609 | $ | 16,893 | $ | — | $ | — | $ | 115,502 | |||||||||||||||||||
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(7) Revenue from Contracts with Customers
Nature of Goods and Services
We provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which includes single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products.
Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to customers in our Montana and South Dakota jurisdictions. We recognize revenue when electricity is delivered to the customer. Payments on our tariff-based sales are generally due 20-30 days after the billing date.
Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to customers in our Montana, South Dakota, and Nebraska jurisdictions. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff-based sales are generally due 20-30 days after the billing date.
Disaggregation of Revenue
The following tables disaggregate our revenue by major source and customer class (in millions):
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| March 31, 2023 | March 31, 2022 | ||||||||||||||||||||||||||||||||||
| Electric | Natural Gas | Total | Electric | Natural Gas | Total | ||||||||||||||||||||||||||||||
| Montana | $ | 125.5 | $ | 66.9 | $ | 192.4 | $ | 97.0 | $ | 52.3 | $ | 149.3 | |||||||||||||||||||||||
| South Dakota | 19.8 | 19.9 | 39.7 | 20.4 | 19.9 | 40.3 | |||||||||||||||||||||||||||||
| Nebraska | — | 20.5 | 20.5 | — | 15.4 | 15.4 | |||||||||||||||||||||||||||||
| Residential | 145.3 | 107.3 | 252.6 | 117.4 | 87.6 | 205.0 | |||||||||||||||||||||||||||||
| Montana | 112.6 | 36.3 | 148.9 | 86.5 | 27.1 | 113.6 | |||||||||||||||||||||||||||||
| South Dakota | 25.1 | 14.3 | 39.4 | 27.6 | 14.5 | 42.1 | |||||||||||||||||||||||||||||
| Nebraska | — | 13.2 | 13.2 | — | 9.2 | 9.2 | |||||||||||||||||||||||||||||
| Commercial | 137.7 | 63.8 | 201.5 | 114.1 | 50.8 | 164.9 | |||||||||||||||||||||||||||||
| Industrial | 11.8 | 0.7 | 12.5 | 9.7 | 0.6 | 10.3 | |||||||||||||||||||||||||||||
| Lighting, governmental, irrigation, and interdepartmental | 5.3 | 0.8 | 6.1 | 4.5 | 0.7 | 5.2 | |||||||||||||||||||||||||||||
| Total Customer Revenues | 300.1 | 172.6 | 472.7 | 245.7 | 139.7 | 385.4 | |||||||||||||||||||||||||||||
| Other tariff and contract based revenues | 21.4 | 12.3 | 33.7 | 20.1 | 10.0 | 30.1 | |||||||||||||||||||||||||||||
| Total Revenue from Contracts with Customers | 321.5 | 184.9 | 506.4 | 265.8 | 149.7 | 415.5 | |||||||||||||||||||||||||||||
| Regulatory amortization and other | (26.2) | (25.7) | (51.9) | 5.9 | (26.9) | (21.0) | |||||||||||||||||||||||||||||
| Total Revenues | $ | 295.3 | $ | 159.2 | $ | 454.5 | $ | 271.7 | $ | 122.8 | $ | 394.5 | |||||||||||||||||||||||
(8) Earnings Per Share
Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards and forward equity sale. Average shares used in computing the basic and diluted earnings per share are as follows:
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| Three Months Ended | |||||||||||
| March 31, 2023 | March 31, 2022 | ||||||||||
| Basic computation | 59,776,195 | 54,096,768 | |||||||||
| Dilutive effect of: | |||||||||||
Performance share awards(1) | 13,009 | 11,244 | |||||||||
Forward equity sale(2) | — | 711,383 | |||||||||
| Diluted computation | 59,789,204 | 54,819,395 | |||||||||
(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.
(2) Forward equity shares are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the forward sale agreement.
As of March 31, 2023, there were 69,853 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations, compared to 100,671 shares as of March 31, 2022.
(9) Employee Benefit Plans
We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (credit) for our pension and other postretirement plans consists of the following (in thousands):
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| Three Months Ended March 31, | Three Months Ended March 31, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Components of Net Periodic Benefit Cost (Credit) | |||||||||||||||||||||||
| Service cost | $ | 1,494 | $ | 2,884 | $ | 87 | $ | 91 | |||||||||||||||
| Interest cost | 6,565 | 4,668 | 176 | 91 | |||||||||||||||||||
| Expected return on plan assets | (6,686) | (6,052) | (275) | (262) | |||||||||||||||||||
| Amortization of prior service credit | — | — | 29 | (473) | |||||||||||||||||||
| Recognized actuarial loss (gain) | 140 | — | 31 | (14) | |||||||||||||||||||
| Net periodic benefit cost (credit) | $ | 1,513 | $ | 1,500 | $ | 48 | $ | (567) | |||||||||||||||
We have not contributed to our pension plans during the three months ended March 31, 2023. We expect to contribute $11.2 million to our pension plans during the remainder of 2023.
(10) Commitments and Contingencies
Except as set forth below and in Note 2 - Regulatory Matters above, the circumstances set forth in Note 18 - Commitments and Contingencies to the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our material commitments and contingent liabilities.
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| ENVIRONMENTAL LIABILITIES AND REGULATION | ||||||||||||||
Environmental Matters
The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.
Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $21.3 million to $32.4 million. As of March 31, 2023, we had a reserve of approximately $26.1 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.
Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.
Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) including, most significantly, carbon dioxide (CO2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and Environmental Protection Agency (EPA) actions at the federal level, state level activity, investor activism and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.
While numerous bills have been introduced that address climate change from different perspectives, Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. However, Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources. EPA has acted on this authority, including in 2015 when it sought to implement the Clean Power Plan that would establish rules to control GHG emissions from existing power plants. However, neither the Clean Power Plan nor any other subsequent attempts by the EPA to regulate emissions from coal-fired plants has become effective due to litigation by various states and stakeholders. One of the key issues in the litigation revolves around whether EPA can use its CAA authority to compel fossil fuel sources to curtail operations and invest in renewable and other low carbon energy sources, in other words, establish a carbon emission cap based on a power generation source shift. The litigation culminated in the United States Supreme Court's June 30, 2022 ruling in West Virginia, et al., v. Environmental Protection Agency, et al, in which the Court held that the EPA does not have the authority to force major changes in the U.S. electric generation mix, as that would expand EPA's regulatory authority. In addition, the U.S. Supreme Court concluded that EPA could not meet its burden under the "major questions doctrine" to point to clear congressional authorization for this authority. The U.S. Supreme Court's ruling, however, declined to decide whether the Section 111(d) phrase "system of emissions reduction" refers exclusively to individual source control at coal-fired plants or broader energy-generating industry-wide approaches.
As expected, subsequent to that ruling, EPA opened a docket to collect public input to guide the EPA’s next effort to reduce GHG emissions from new and existing coal fired plants and natural gas operations. EPA indicated that it intends to use this non-rulemaking docket to gather perspectives from a broad group of stakeholders in advance of an expected proposed rulemaking.
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Therefore, we cannot predict whether or how future GHG emission regulations or litigation will impact our plants, including any actions taken by federal or state authorities, or courts. As GHG regulations are implemented, it could result in additional compliance costs impacting our future results of operations and financial position if such costs are not recovered through regulated rates. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any GHG regulations that, in our view, disproportionately impact customers in our region.
Future additional environmental requirements - federal or state - could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, wind, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities.
| LEGAL PROCEEDINGS | ||
State of Montana - Riverbed Rents
On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State’s Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen Montana, LLC (Talen) as defendants. The State claimed it owns the riverbeds underlying 10 of our, and formerly Talen’s, hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.
The litigation has a long prior history in state and federal court, including before the United States Supreme Court, as detailed in Note 18 - Commitments and Contingencies to the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2022. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). On August 1, 2018, the Federal District Court granted our and Talen’s motions to dismiss the State’s Complaint as it pertains to the navigability of the riverbeds associated with four of our hydroelectric facilities near Great Falls. A bench trial before the Federal District Court commenced January 4, 2022, and concluded on January 18, 2022, which addressed the issue of navigability concerning our other six facilities. Damages were bifurcated by agreement and will be tried separately should the Federal District Court find any segments navigable. While we await the Federal District Court decision on navigability, the damages phase of the case remains stayed.
We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.
Colstrip Arbitration
The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively.
As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration while they explore a potential resolution to their disagreements.
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Colstrip Coal Dust Litigation
On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties.
Since this lawsuit remains in its early stages, we are unable to predict outcomes or estimate a range of reasonably possible losses.
BNSF Demands for Indemnity and Remediation Costs
NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980.
According to U.S. EPA, the smelter and refining operations have contaminated soil, groundwater and surface water resources around the site with lead, arsenic and other metal wastes. ARCO (Atlantic Richfield Company) initiated reclamation and maintenance activities in the 1980s and 1990s. Between 2002 and 2008, the EPA conducted several site investigations. In March 2011, the EPA placed the ACM Smelter and Refinery Site on the Superfund program’s National Priority List. The Superfund Site is 427 acres and contains three operable units: Operable Unit 1 (consisting of five subsections including the Railroad Corridor and four other “areas of interest”), Operable Unit 2 (the former smelter and refinery site), and Operable Unit 3 (the Missouri River that flows along the south sides of Operable Units 1 and 2).
NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. BNSF reports it has incurred in excess of $4.4 million, pending final resolution, of response and oversight costs incurred by government agencies (EPA and Montana DEQ), in investigative and other response costs associated with Operable Unit 1, and that in the future it will incur additional costs to implement the final remedy for Operable Unit 1. In the Record of Decision (ROD) for Operable Unit 1 issued on August 21, 2021, the EPA estimated the costs to implement the selected remedies for the Railroad Corridor will be approximately $4.1 million. In the ROD, the EPA also estimated the costs to implement the selected remedy (including institutional controls) for the four “areas of interest” in Operable Unit 1 would be approximately $1.8 million, with annual operating costs of ten thousand dollars. We are evaluating BNSF’s claim and are unable at this time to predict outcomes or estimate a range of reasonably possible losses.
Yellowstone County Generating Station Air Permit
On October 21, 2021, the Montana Environmental Information Center (MEIC) and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality (MDEQ) and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. The Montana District Court judge held oral argument on June 20, 2022. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases. The Montana District Court remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we are required to stop construction and will not be able to recommence construction until the permit is reissued. On April 14, 2023, following entry of final judgment, we filed our motion to stay the order vacating the air quality permit. On April 17, 2023, we filed a notice of appeal with the Montana Supreme Court. This lawsuit, as well as additional legal challenges related to the Yellowstone County Generating Station, could delay the project timing and increase costs. At this time, we still expect the plant to be operational by the end of 2024.
Other Legal Proceedings
We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.
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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.
We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.
| OVERVIEW | ||||||||||||||
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022.
We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:
•Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.
•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices
•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.
We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.
We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, in 2022 we expanded and outlined our efforts towards a carbon-free future through our goal to achieve net zero carbon emissions by 2050.
As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three months ended March 31, 2023 and 2022.
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| HOW WE PERFORMED AGAINST OUR FIRST QUARTER 2022 RESULTS | ||||||||||||||
| Three Months Ended March 31, 2023 vs. 2022 | ||||||||||||||||||||
| Income Before Income Taxes | Income Tax (Expense) Benefit | Net Income | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| First Quarter 2022 | $ | 60.2 | $ | (1.1) | $ | 59.1 | ||||||||||||||
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income: | ||||||||||||||||||||
| Higher electric retail volumes | 9.8 | (2.5) | 7.3 | |||||||||||||||||
| Montana interim rates (subject to refund) | 8.5 | (2.2) | 6.3 | |||||||||||||||||
| Higher natural gas retail volumes | 3.7 | (0.9) | 2.8 | |||||||||||||||||
| Lower non-recoverable Montana electric supply costs due to higher electric supply revenues, partly offset by higher electric supply costs | 1.3 | (0.3) | 1.0 | |||||||||||||||||
| Higher electric transmission revenue | 1.2 | (0.3) | 0.9 | |||||||||||||||||
Variance in expense items(2) impacting net income: | ||||||||||||||||||||
| Higher operating, maintenance, and administrative expenses | (6.6) | 1.7 | (4.9) | |||||||||||||||||
| Higher interest expense | (4.3) | 1.1 | (3.2) | |||||||||||||||||
| Higher depreciation expense | (4.3) | 1.1 | (3.2) | |||||||||||||||||
| Reduction to previously claimed alternative minimum tax credit | — | (3.2) | (3.2) | |||||||||||||||||
| Other | 3.2 | (3.6) | (0.4) | |||||||||||||||||
| First Quarter 2023 | $ | 72.7 | $ | (10.2) | $ | 62.5 | ||||||||||||||
| Change in Net Income | $ | 3.4 | ||||||||||||||||||
(1) Exclusive of depreciation and depletion shown separately below
(2) Excluding fuel, purchased supply, and direct transmission expense
Consolidated net income for the three months ended March 31, 2023 was $62.5 million as compared with $59.1 million for the same period in 2022. This increase was primarily due to higher electric and natural gas retail volumes, higher Montana interim rates associated with our ongoing rate review, which are subject to refund, lower non-recoverable Montana electric supply costs, and higher transmission revenues, partly offset by higher operating and maintenance costs, higher administrative and general costs, higher depreciation and depletion expense, higher interest expense, and higher income tax expense, including a one-time charge for the reduction of previously claimed alternative minimum tax credits.
| SIGNIFICANT TRENDS AND REGULATION | ||||||||||||||
Refer to our Annual Report on the Form 10-K for the year ended December 31, 2022 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:
Regulatory Update
Rate reviews are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service.
Montana Rate Review Filing – On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates. On September 28, 2022, the MPSC approved the recommendations of the MPSC Staff for interim rates effective October 1, 2022, subject to refund. Subsequently, we modified our request through rebuttal testimony. On April 3, 2023, we filed a settlement agreement with certain parties in our Montana electric and natural gas rate review, which is subject to approval by the MPSC. The details of our request, as so modified, the interim rates granted, and the settlement agreement are set forth below:
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| Montana Rate Review ($ in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Current ROE | 9.65% | 9.55% | ||||||
| Current Equity Ratio | 49.38% | 46.79% | ||||||
| Proposed Settlement ROE | 9.65% | 9.55% | ||||||
| Proposed Settlement Equity Ratio | 48.02% | 48.02% | ||||||
| Rebuttal Filing Forecasted 2022 Rate Base | $2,842 | $582 | ||||||
| Requested Revenue Increase Through Rebuttal Testimony (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $90.6 | $22.4 | ||||||
PCCAM(1) | $69.7 | n/a | ||||||
Property Tax (tracker true-up)(1) | $14.5 | $4.2 | ||||||
| Total Revenue Increase Requested through Rebuttal Testimony | $174.8 | $26.6 | ||||||
| Interim Revenue Increase Granted (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $29.4 | $1.7 | ||||||
Power Cost & Credit Mechanism (PCCAM)(1) | $61.1 | n/a | ||||||
Property Tax (tracker true-up)(1)(2) | $10.8 | $2.9 | ||||||
| Total Interim Revenue Granted | $101.3 | $4.6 | ||||||
| Requested Revenue Increase Through Settlement Agreement (in millions) | ||||||||
| Electric | Natural Gas | |||||||
| Base Rates | $67.4 | $14.1 | ||||||
PCCAM(1) | $69.7 | n/a | ||||||
Property Tax (tracker true-up)(1) | $14.5 | $4.2 | ||||||
| Total Revenue Increase Requested Through Settlement Agreement | $151.6 | $18.3 | ||||||
(1) These items are flow-through costs.
(2) While our requested interim property tax base increases were denied from interim rates, these rates went into effect on January 1, 2023, as part of our 2023 property tax tracker period true-up.
The settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms.
The settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.
A hearing commenced on April 11, 2023 and concluded on April 18, 2023. Interim rates will remain in effect on a refundable basis until the MPSC issues a final order.
South Dakota Rate Review Filing – We anticipate making a South Dakota electric general rate filing (2022 test year) in mid-2023.
Holding Company Filings – As previously reported, on June 1, 2022, we filed a legal corporate restructuring application (Restructuring Plan) with the state commissions in Montana, South Dakota and Nebraska and the Federal Energy Regulatory Commission (FERC). Currently, our utility businesses are held in the same legal entity. Under the proposed Restructuring Plan,
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we would legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to segregate our organizational structure to be more transparent and in line with the public utility industry.
The Restructuring Plan does not propose and we do not expect any procedural or substantive change in how the state public utility commissions regulate those services. Implementation of the Restructuring Plan is subject to receipt of all regulatory approvals. During 2022, we received approvals from the Nebraska Public Service Commission, South Dakota Public Service Commission, and the FERC. On February 21, 2023, the MPSC approved the Restructuring Plan. We are currently developing implementation timing to effectuate the Restructuring Plan.
Montana Power Costs and Credits Adjustment Mechanism - The Montana PCCAM Base of $138.7 million, approved in 2019, no longer reflects an accurate current forecast of our normal fuel and power costs. The MPSC's September 28, 2022 decision approving interim rates, which are subject to refund, in our rate review included an increase to the PCCAM Base of $61.1 million, on an interim basis, effective October 1, 2022. As of March 31, 2023, we have under-collected our total Montana electric supply costs for the current July 2022 through June 2023 PCCAM year by approximately $38.8 million. Absent the interim rate PCCAM Base increase, as of March 31, 2023, our under-collected position would have been approximately $65.8 million. Under-collections are not reflected in customer bills and are not recovered until the subsequent power cost adjustment year, adversely affecting our cash flows and liquidity.
Under the PCCAM, under and over-collection of non-qualifying facility related net costs are allocated 90% to Montana customers and 10% to shareholders. For the three months ended March 31, 2023, we deferred $4.3 million of revenue to be refunded to customers (90% of the revenues above base) and recorded an increase in pre-tax earnings of $0.5 million (10% of the variance). For the three months ended March 31, 2022, we deferred $7.2 million of costs for future collection from customers and recorded a reduction in pre-tax earnings of $0.8 million.
Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs. Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows. See the Electric Resource Planning - Montana section below for how we are working to address this market exposure.
Electric Resource Planning - Montana
Yellowstone County 175 MW plant - As previously reported, in October 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality (MDEQ) and us, alleging that the environmental analysis conducted prior to issuance of the Yellowstone County Generating Station's air quality permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding the MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we are required to stop construction and will not be able to recommence construction until the permit is reissued. On April 14, 2023, following entry of final judgment, we filed our motion to stay the order vacating the air quality permit. On April 17, 2023, we filed a notice of appeal with the Montana Supreme Court. This lawsuit, as well as additional legal challenges related to the Yellowstone County Generating Station, could delay the project timing and increase costs. At this time, we still expect the plant to be operational by the end of 2024. Total costs of approximately $174.7 million have been incurred, with expected total costs of approximately $275.0 million.
Future Integrated Resource Planning - Resource adequacy in the Western third of the U.S. has been declining with the retirement of thermal power plants. Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices. To comply with regulatory resource planning requirements, we expect to submit an integrated resource plan to the MPSC by the end of April 2023.
We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads. The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests will reduce our exposure to market purchases at typically high and volatile energy prices.
| RESULTS OF OPERATIONS | ||||||||||||||
Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.
Factors Affecting Results of Operations
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Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.
Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.
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OVERALL CONSOLIDATED RESULTS
Three Months Ended March 31, 2023 Compared with the Three Months Ended March 31, 2022
Consolidated net income for the three months ended March 31, 2023 was $62.5 million as compared with $59.1 million for the same period in 2022. This increase was primarily due to higher electric and natural gas retail volumes, higher Montana interim rates associated with our ongoing rate review, which are subject to refund, lower non-recoverable Montana electric supply costs, and higher transmission revenues, partly offset by higher operating and maintenance costs, higher administrative and general costs, higher depreciation and depletion expense, higher interest expense, and higher income tax expense, including a one-time charge for the reduction of previously claimed alternative minimum tax credits.
Consolidated gross margin for the three months ended March 31, 2023 was $130.7 million as compared with $110.8 million in 2022, an increase of $19.9 million, or 18.0 percent. This increase was primarily due to higher electric and natural gas retail volumes, higher Montana interim rates associated with our ongoing rate review, which are subject to refund, lower non-recoverable Montana electric supply costs, and higher transmission revenues, partly offset by higher Operating and maintenance expense and depreciation and depletion expense.
| Electric | Natural Gas | Total | |||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Reconciliation of gross margin to utility margin: | |||||||||||||||||||||||||||||||||||
| Operating Revenues | $ | 295.3 | $ | 271.7 | $ | 159.2 | $ | 122.8 | $ | 454.5 | $ | 394.5 | |||||||||||||||||||||||
| Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) | 78.1 | 77.6 | 87.4 | 57.5 | 165.5 | 135.1 | |||||||||||||||||||||||||||||
| Less: Operating and maintenance | 42.4 | 39.5 | 13.5 | 13.3 | 55.9 | 52.8 | |||||||||||||||||||||||||||||
| Less: Property and other taxes | 38.3 | 36.5 | 10.9 | 10.4 | 49.2 | 46.9 | |||||||||||||||||||||||||||||
| Less: Depreciation and depletion | 43.9 | 40.4 | 9.3 | 8.5 | 53.2 | 48.9 | |||||||||||||||||||||||||||||
| Gross Margin | 92.6 | 77.7 | 38.1 | 33.1 | 130.7 | 110.8 | |||||||||||||||||||||||||||||
| Operating and maintenance | 42.4 | 39.5 | 13.5 | 13.3 | 55.9 | 52.8 | |||||||||||||||||||||||||||||
| Property and other taxes | 38.3 | 36.5 | 10.9 | 10.4 | 49.2 | 46.9 | |||||||||||||||||||||||||||||
| Depreciation and depletion | 43.9 | 40.4 | 9.3 | 8.5 | 53.2 | 48.9 | |||||||||||||||||||||||||||||
Utility Margin(1) | $ | 217.2 | $ | 194.1 | $ | 71.8 | $ | 65.3 | $ | 289.0 | $ | 259.4 | |||||||||||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2023 | 2022 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Utility Margin | |||||||||||||||||||||||
| Electric | $ | 217.2 | $ | 194.1 | $ | 23.1 | 11.9 | % | |||||||||||||||
| Natural Gas | 71.8 | 65.3 | 6.5 | 10.0 | |||||||||||||||||||
Total Utility Margin(1) | $ | 289.0 | $ | 259.4 | $ | 29.6 | 11.4 | % | |||||||||||||||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated utility margin for the three months ended March 31, 2023 was $289.0 million as compared with $259.4 million for the same period in 2022, an increase of $29.6 million, or 11.4 percent.
Primary components of the change in utility margin include the following (in millions):
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| Utility Margin 2023 vs. 2022 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Higher electric retail volumes | $ | 9.8 | |||
| Montana interim rates (subject to refund) | 8.5 | ||||
| Higher natural gas retail volumes | 3.7 | ||||
| Lower non-recoverable Montana electric supply costs due to higher electric supply revenues, partly offset by higher electric supply costs | 1.3 | ||||
| Higher transmission revenue due to higher demand due to market conditions, partly offset by lower transmission rates | 1.2 | ||||
| Other | 1.2 | ||||
| Change in Utility Margin Items Impacting Net Income | $ | 25.7 | |||
| Utility Margin Items Offset Within Net Income | |||||
| Higher property taxes recovered in revenue, offset in property tax expense | 2.6 | ||||
| Higher revenue from lower production tax credits, offset in income tax expense | 1.7 | ||||
| Lower operating expenses recovered in revenue, offset in operating and maintenance expense | (0.3) | ||||
| Lower gas production taxes recovered in revenue, offset in property and other taxes | (0.1) | ||||
| Change in Utility Margin Items Offset Within Net Income | 3.9 | ||||
Increase in Consolidated Utility Margin(1) | $ | 29.6 | |||
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Higher electric retail volumes were driven by colder winter weather in all jurisdictions and customer growth. Higher natural gas retail volumes were driven by colder winter weather in all jurisdictions and customer growth. Interim rates in our Montana rate review were effective October 1, 2022, and are subject to refund pending an outcome in the proceeding.
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2023 | 2022 | Change | % Change | ||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | |||||||||||||||||||||||
| Operating and maintenance | $ | 55.9 | $ | 52.8 | $ | 3.1 | 5.9 | % | |||||||||||||||
| Administrative and general | 34.7 | 31.6 | 3.1 | 9.8 | |||||||||||||||||||
| Property and other taxes | 49.2 | 46.9 | 2.3 | 4.9 | |||||||||||||||||||
| Depreciation and depletion | 53.2 | 48.9 | 4.3 | 8.8 | |||||||||||||||||||
| Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 193.0 | $ | 180.2 | $ | 12.8 | 7.1 | % | |||||||||||||||
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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $193.0 million for the three months ended March 31, 2023, as compared with $180.2 million for the three months ended March 31, 2022. Primary components of the change include the following (in millions):
| Operating Expenses | |||||
| 2023 vs. 2022 | |||||
| Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income | |||||
| Higher depreciation expense due to plant additions | $ | 4.3 | |||
| Higher expenses at our electric generation facilities | 3.4 | ||||
Higher labor and benefits(1) | 3.1 | ||||
| Higher insurance expense | 0.6 | ||||
| Increase in uncollectible accounts | 0.3 | ||||
| Lower technology implementation and maintenance expenses | (0.4) | ||||
| Lower property tax expenses | (0.2) | ||||
| Other | (0.4) | ||||
| Change in Items Impacting Net Income | 10.7 | ||||
| Operating Expenses Offset Within Net Income | |||||
| Higher property and other taxes recovered in trackers, offset in revenue | 2.5 | ||||
Higher pension and other postretirement benefits, offset in other income(1) | 0.2 | ||||
| Lower non-employee directors deferred compensation recorded within administrative and general expense, offset in other income | (0.3) | ||||
| Lower operating and maintenance expenses recovered in trackers, offset in revenue | (0.3) | ||||
| Change in Items Offset Within Net Income | 2.1 | ||||
| Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) | $ | 12.8 | |||
(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.
We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Consolidated operating income for the three months ended March 31, 2023 was $96.0 million as compared with $79.2 million in the same period of 2022. This increase was primarily driven by higher Montana interim rates associated with our ongoing rate review, which are subject to refund, higher electric and natural gas retail volumes, lower non-recoverable Montana electric supply costs, and higher transmission revenues, partly offset by higher depreciation and depletion expense, higher operating and maintenance expense, and higher administrative and general expense.
Consolidated interest expense was $28.0 million for the three months ended March 31, 2023 as compared with $23.7 million for the same period of 2022. This increase was primarily due to higher interest rates on borrowings under our revolving credit facilities partly offset by higher capitalization of Allowance for Funds Used During Construction.
Consolidated other income remained unchanged at $4.7 million for the three months ended March 31, 2023 and 2022. A decrease in the value of deferred shares held in trust for non-employee directors deferred compensation was offset by a decrease in the non-service component of pension expense.
Consolidated income tax expense was $10.2 million for the three months ended March 31, 2023 as compared to income tax expense of $1.1 million for the three months ended March 31, 2022. Our effective tax rate for the three months ended March 31, 2023 was 14.1% as compared with 1.8% for the same period in 2022. Income tax expense for the three months ended
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March 31, 2023 includes a one-time $3.2 million charge for the reduction of previously claimed alternative minimum tax credits.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| Income Before Income Taxes | $ | 72.8 | $ | 60.2 | |||||||||||||||||||
| Income tax calculated at federal statutory rate | 15.3 | 21.0 | % | 12.6 | 21.0 | % | |||||||||||||||||
| Permanent or flow-through adjustments: | |||||||||||||||||||||||
| State income tax, net of federal provisions | 1.0 | 1.3 | 0.4 | 0.7 | |||||||||||||||||||
| Flow-through repairs deductions | (5.8) | (8.0) | (6.8) | (11.3) | |||||||||||||||||||
| Production tax credits | (3.2) | (4.4) | (3.8) | (6.4) | |||||||||||||||||||
| Amortization of excess deferred income tax | (0.8) | (1.1) | (0.4) | (0.7) | |||||||||||||||||||
| Reduction to previously claimed alternative minimum tax credit | 3.2 | 4.4 | — | — | |||||||||||||||||||
| Plant and depreciation of flow-through items | 0.7 | 0.9 | (0.3) | (0.4) | |||||||||||||||||||
| Share-based compensation | 0.4 | 0.5 | (0.3) | (0.4) | |||||||||||||||||||
| Other, net | (0.6) | (0.5) | (0.3) | (0.7) | |||||||||||||||||||
| (5.1) | (6.9) | (11.5) | (19.2) | ||||||||||||||||||||
| Income tax expense | $ | 10.2 | 14.1 | % | $ | 1.1 | 1.8 | % | |||||||||||||||
We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.
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ELECTRIC SEGMENT
We have various classifications of electric revenues, defined as follows:
•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory
mechanisms.
•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.
Three Months Ended March 31, 2023 Compared with the Three Months Ended March 31, 2022
| Revenues | Change | Megawatt Hours (MWH) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | $ | % | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 125,462 | $ | 96,952 | $ | 28,510 | 29.4 | % | 871 | 825 | 320,739 | 315,442 | |||||||||||||||||||||||||||||||||||
| South Dakota | 19,771 | 20,430 | (659) | (3.2) | 195 | 189 | 51,276 | 51,003 | |||||||||||||||||||||||||||||||||||||||
| Residential | 145,233 | 117,382 | 27,851 | 23.7 | 1,066 | 1,014 | 372,015 | 366,445 | |||||||||||||||||||||||||||||||||||||||
| Montana | 112,613 | 86,534 | 26,079 | 30.1 | 851 | 809 | 74,262 | 72,619 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 25,128 | 27,634 | (2,506) | (9.1) | 279 | 291 | 12,942 | 12,814 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 137,741 | 114,168 | 23,573 | 20.6 | 1,130 | 1,100 | 87,204 | 85,433 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 11,841 | 9,654 | 2,187 | 22.7 | 626 | 628 | 78 | 76 | |||||||||||||||||||||||||||||||||||||||
| Other | 5,254 | 4,472 | 782 | 17.5 | 15 | 15 | 4,859 | 4,783 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Electric | $ | 300,069 | $ | 245,676 | $ | 54,393 | 22.1 | % | 2,837 | 2,757 | 464,156 | 456,737 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | (25,297) | 6,541 | (31,838) | (486.7) | |||||||||||||||||||||||||||||||||||||||||||
| Transmission | 18,893 | 17,691 | 1,202 | 6.8 | |||||||||||||||||||||||||||||||||||||||||||
| Wholesale and Other | 1,643 | 1,819 | (176) | (9.7) | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 295,308 | $ | 271,727 | $ | 23,581 | 8.7 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(1) | 78,134 | 77,623 | 511 | 0.7 | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(2) | $ | 217,174 | $ | 194,104 | $ | 23,070 | 11.9 | % | |||||||||||||||||||||||||||||||||||||||
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Heating Degree Days | 2023 as compared with: | ||||||||||||||||||||||||||||
| 2023 | 2022 | Historic Average | 2022 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 3,539 | 3,236 | 3,298 | 9% colder | 7% colder | ||||||||||||||||||||||||
| South Dakota | 4,344 | 4,095 | 4,109 | 6% colder | 6% colder | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in electric utility margin for the three months ended March 31, 2023 and 2022 (in millions):
| Utility Margin 2023 vs. 2022 | |||||
| Utility Margin Items Impacting Net Income | |||||
| Higher retail volumes | $ | 9.8 | |||
| Montana interim rates (subject to refund) | 8.4 | ||||
| Lower non-recoverable Montana electric supply costs due to higher electric supply revenues, partly offset by higher electric supply costs | 1.3 | ||||
| Higher transmission revenue due to higher demand due to market conditions, partly offset by lower transmission rates | 1.2 | ||||
| Change in Utility Margin Items Impacting Net Income | 20.7 | ||||
| Utility Margin Items Offset Within Net Income | |||||
| Higher revenue from lower production tax credits, offset in income tax expense | 1.7 | ||||
| Higher property taxes recovered in revenue, offset in property tax expense | 1.0 | ||||
| Lower operating expenses recovered in revenue, offset in operating and maintenance expense | (0.3) | ||||
| Change in Utility Margin Items Offset Within Net Income | 2.4 | ||||
Increase in Utility Margin(1) | $ | 23.1 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher electric retail volumes were driven by colder winter weather in all jurisdictions and customer growth.
The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
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NATURAL GAS SEGMENT
We have various classifications of natural gas revenues, defined as follows:
•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.
•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Three Months Ended March 31, 2023 Compared with the Three Months Ended March 31, 2022
| Revenues | Change | Dekatherms (Dkt) | Avg. Customer Counts | ||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | $ | % | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||||||||
| Montana | $ | 66,882 | $ | 52,299 | $ | 14,583 | 27.9 | % | 6,517 | 6,039 | 183,500 | 181,464 | |||||||||||||||||||||||||||||||||||
| South Dakota | 19,935 | 19,916 | 19 | 0.1 | 1,752 | 1,749 | 42,150 | 41,571 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 20,513 | 15,442 | 5,071 | 32.8 | 1,407 | 1,298 | 37,965 | 37,811 | |||||||||||||||||||||||||||||||||||||||
| Residential | 107,330 | 87,657 | 19,673 | 22.4 | 9,676 | 9,086 | 263,615 | 260,846 | |||||||||||||||||||||||||||||||||||||||
| Montana | 36,339 | 27,050 | 9,289 | 34.3 | 3,687 | 3,259 | 25,666 | 25,263 | |||||||||||||||||||||||||||||||||||||||
| South Dakota | 14,286 | 14,525 | (239) | (1.6) | 1,502 | 1,490 | 7,252 | 7,049 | |||||||||||||||||||||||||||||||||||||||
| Nebraska | 13,163 | 9,227 | 3,936 | 42.7 | 999 | 880 | 5,076 | 5,038 | |||||||||||||||||||||||||||||||||||||||
| Commercial | 63,788 | 50,802 | 12,986 | 25.6 | 6,188 | 5,629 | 37,994 | 37,350 | |||||||||||||||||||||||||||||||||||||||
| Industrial | 729 | 551 | 178 | 32.3 | 75 | 67 | 231 | 230 | |||||||||||||||||||||||||||||||||||||||
| Other | 796 | 690 | 106 | 15.4 | 93 | 94 | 188 | 175 | |||||||||||||||||||||||||||||||||||||||
| Total Retail Gas | $ | 172,643 | $ | 139,700 | $ | 32,943 | 23.6 | % | 16,032 | 14,876 | 302,028 | 298,601 | |||||||||||||||||||||||||||||||||||
| Regulatory amortization | (25,401) | (26,570) | 1,169 | 4.4 | |||||||||||||||||||||||||||||||||||||||||||
| Wholesale and other | 11,992 | 9,625 | 2,367 | 24.6 | |||||||||||||||||||||||||||||||||||||||||||
| Total Revenues | $ | 159,234 | $ | 122,755 | $ | 36,479 | 29.7 | % | |||||||||||||||||||||||||||||||||||||||
Fuel, purchased supply and direct transmission expense(1) | 87,358 | 57,450 | 29,908 | 52.1 | |||||||||||||||||||||||||||||||||||||||||||
Utility Margin(2) | $ | 71,876 | $ | 65,305 | $ | 6,571 | 10.1 | % | |||||||||||||||||||||||||||||||||||||||
(1) Exclusive of depreciation and depletion.
(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
| Heating Degree Days | 2023 as compared with: | ||||||||||||||||||||||||||||
| 2023 | 2022 | Historic Average | 2022 | Historic Average | |||||||||||||||||||||||||
Montana(1) | 3,592 | 3,283 | 3,315 | 9% colder | 8% colder | ||||||||||||||||||||||||
| South Dakota | 4,344 | 4,095 | 4,109 | 6% colder | 6% colder | ||||||||||||||||||||||||
| Nebraska | 3,364 | 3,078 | 3,287 | 9% colder | 2% colder | ||||||||||||||||||||||||
(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.
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The following summarizes the components of the changes in natural gas utility margin for the three months ended March 31, 2023 and 2022:
| Utility Margin 2023 vs. 2022 | |||||
| (in millions) | |||||
| Utility Margin Items Impacting Net Income | |||||
| Higher retail volumes | $ | 3.7 | |||
| Montana interim rates (subject to refund) | 0.1 | ||||
| Other | 1.2 | ||||
| Change in Utility Margin Items Impacting Net Income | 5.0 | ||||
| Utility Margin Items Offset Within Net Income | |||||
| Higher property taxes recovered in revenue, offset in property tax expense | 1.6 | ||||
| Lower gas production taxes recovered in revenue, offset in property and other taxes | (0.1) | ||||
| Change in Utility Margin Items Offset Within Net Income | 1.5 | ||||
Increase in Utility Margin(1) | $ | 6.5 | |||
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.
Higher natural gas retail volumes were driven by colder winter weather in all jurisdictions and customer growth.
Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.
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| LIQUIDITY AND CAPITAL RESOURCES | ||||||||||||||
Liquidity
We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.
As of March 31, 2023, our total net liquidity was approximately $363.7 million, including $10.7 million of cash and $353.0 million of revolving credit facility availability with no letters of credit outstanding.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
| Three Months Ended March 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Operating Activities | |||||||||||
| Net income | $ | 62.5 | $ | 59.1 | |||||||
| Non-cash adjustments to net income | 43.8 | 43.3 | |||||||||
| Changes in working capital | 107.8 | 92.8 | |||||||||
| Other noncurrent assets and liabilities | (0.4) | 0.5 | |||||||||
| Cash Provided by Operating Activities | 213.7 | 195.7 | |||||||||
| Investing Activities | |||||||||||
| Property, plant and equipment additions | (136.6) | (115.5) | |||||||||
| Investment in equity securities | — | (0.6) | |||||||||
| Cash Used in Investing Activities | (136.6) | (116.1) | |||||||||
| Financing Activities | |||||||||||
| Issuance of long-term debt | 220.0 | — | |||||||||
| Line of credit repayments, net | (253.0) | (33.0) | |||||||||
| Dividends on common stock | (38.0) | (33.9) | |||||||||
| Other financing activities, net | (1.5) | (0.6) | |||||||||
| Cash Used in Financing Activities | (72.5) | (67.5) | |||||||||
| Increase in Cash, Cash Equivalents, and Restricted Cash | 4.6 | 12.1 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, beginning of period | 22.5 | 18.8 | |||||||||
| Cash, Cash Equivalents, and Restricted Cash, end of period | $ | 27.1 | $ | 30.9 | |||||||
Operating Activities
As of March 31, 2023, cash, cash equivalents, and restricted cash were $27.1 million as compared with $22.5 million as of December 31, 2022 and $30.9 million as of March 31, 2022. Cash provided by operating activities totaled $213.7 million for the three months ended March 31, 2023 as compared with $195.7 million during the three months ended March 31, 2022. As shown in the table below, this increase in operating cash flows is primarily due to a $25.8 million improvement in net cash inflows for uncollected energy supply costs during the three months ended March 31, 2023, compared to the three months ended March 31, 2022.
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| Under-collected supply costs (in millions) | |||||||||||||||||
| Beginning of period | End of period | Net cash inflows (outflows) | |||||||||||||||
| 2022 | $ | 99.1 | $ | 76.0 | $ | 23.1 | |||||||||||
| 2023 | $ | 115.4 | $ | 66.5 | $ | 48.9 | |||||||||||
| Improvement in net cash inflows | $ | 25.8 | |||||||||||||||
As of March 31, 2023, our uncollected energy supply cost balance includes $26.0 million related to the July 2021 - June 2022 PCCAM period, which has been included in customer rates for recovery beginning October 1, 2022. The balance also includes an additional $38.8 million under-collection related to the PCCAM period that began on July 1, 2022. As part of our Montana rate review we have requested an increase to the PCCAM base to more accurately reflect the current higher overall market energy prices. On September 28, 2022, the MPSC approved our request for interim rates, which are subject to refund, including a $61.1 million increase to the PCCAM Base, which became effective in customer rates on October 1, 2022. Our under-collected position improved $27.0 million due to the interim rate approved PCCAM Base increase.
If the settlement agreement is approved as submitted, we anticipate continued improvements in our cash flows from operations. However, unfavorable results in our Montana rate review, and continued higher overall market prices, which could be further exacerbated by extreme weather events, could create additional costs with deferred recovery that would offset these anticipated cash flow improvements.
Investing Activities
Cash used in investing activities totaled $136.6 million during the three months ended March 31, 2023, as compared with $116.1 million during the three months ended March 31, 2022. Plant additions during the first three months of 2023 include maintenance additions of approximately $83.1 million and capacity related capital expenditures of $53.5 million. Plant additions during the first three months of 2022 included maintenance additions of approximately $53.2 million and capacity related capital expenditures of approximately $62.3 million.
Financing Activities
Cash used in financing activities totaled $72.5 million during the three months ended March 31, 2023 as compared with $67.5 million during the three months ended March 31, 2022. During the three months ended March 31, 2023, cash used in financing activities reflects net repayments under our revolving lines of credit of $253.0 million and payment of dividends of $38.0 million, offset in part by net proceeds from the issuance of debt of $220.0 million. During the three months ended March 31, 2022, cash used in financing activities reflects payment of dividends of $33.9 million and net repayments under our revolving lines of credit of $33.0 million.
Cash Requirements and Capital Resources
We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.
Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in our Annual Report on Form 10-K for the year ended December 31, 2022 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of March 31, 2023, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.
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Credit Facilities
Liquidity is generally provided by internal cash flows and the use of our unsecured revolving credit facilities. This includes the $425 million Credit Facility, the $100 million Additional Credit Facility, and a $25 million Swingline Facility to provide swingline borrowing capability. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.
Our $425 million Credit Facility has a maturity date of May 18, 2027. The Credit Facility includes uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional $75 million with the consent of the lenders. The Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. A total of nine banks participate in the facility, with no one bank providing more than 15 percent of the total availability.
Our $100 million Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points.
Our $25 million Swingline Facility has a maturity date of March 27, 2025. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate plus a margin of 12.5 basis points.
As of March 31, 2023 and 2022 the outstanding balances on our credit facilities were $197.0 million and $340.0 million, respectively. As of April 21, 2023, our availability under our revolving credit facilities was approximately $395.0 million, and there were no letters of credit outstanding.
Long-term Debt and Equity
We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $144.7 million of debt maturing in 2023 and $100.0 million of debt maturing in March 2024, both of which we intend to refinance.
On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. We received proceeds totaling $220.0 million on March 30, 2023. We will receive the remaining $50.0 million of proceeds, associated with the Montana First Mortgage Bonds, on May 1, 2023. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.
On March 29, 2023, we priced an additional $30.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent. We expect to complete the issuance and sale of these bonds on May 1, 2023 and they will mature on May 1, 2033.
We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases. We anticipate issuing $75.0 million of common stock through our At-the-Market program in 2023.
Credit Ratings
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of April 21, 2023, our current ratings with these agencies are as follows:
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| Senior Secured Rating | Senior Unsecured Rating | Outlook | |||||||||||||||
| Fitch | A- | BBB+ | Stable | ||||||||||||||
| Moody’s | A3 | Baa2 | Stable | ||||||||||||||
| S&P | A- | BBB | Stable | ||||||||||||||
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of March 31, 2023.
| Total | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | |||||||||||||||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||||||||||||||||||
Long-term debt(1) | $ | 2,596,660 | $ | 144,660 | $ | 100,000 | $ | 325,000 | $ | 105,000 | $ | 172,000 | $ | 1,750,000 | |||||||||||||||||||||||||||
| Finance leases | 11,151 | 2,352 | 3,338 | 3,596 | 1,865 | — | — | ||||||||||||||||||||||||||||||||||
Estimated pension and other postretirement obligations(2) | 58,157 | 12,389 | 11,667 | 11,367 | 11,367 | 11,367 | N/A | ||||||||||||||||||||||||||||||||||
Qualifying facilities liability(3) | 365,908 | 60,563 | 76,393 | 60,360 | 55,393 | 56,665 | 56,534 | ||||||||||||||||||||||||||||||||||
Supply and capacity contracts(4) | 2,777,447 | 309,883 | 255,774 | 240,223 | 251,451 | 234,751 | 1,485,365 | ||||||||||||||||||||||||||||||||||
Contractual interest payments on debt(5) | 1,484,534 | 79,621 | 103,381 | 94,412 | 88,322 | 79,325 | 1,039,473 | ||||||||||||||||||||||||||||||||||
Commitments for significant capital projects(6) | 184,567 | 100,124 | 74,368 | 10,075 | — | — | — | ||||||||||||||||||||||||||||||||||
Total Commitments(7) | $ | 7,478,424 | $ | 709,592 | $ | 624,921 | $ | 745,033 | $ | 513,398 | $ | 554,108 | $ | 4,331,372 | |||||||||||||||||||||||||||
_________________________
(1)Represents cash payments for long-term debt and excludes $11.7 million of debt discounts and debt issuance costs, net.
(2)We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.
(3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from $64 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $365.9 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $312.5 million.
(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC.
(5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 6.14 percent on the outstanding balance through maturity of the facilities.
(6)Represents significant firm purchase commitments for construction of planned capital projects.
(7)The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 10 - Commitments and Contingencies) and asset retirement obligations as the amount and timing of cash payments may be uncertain.
Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $17.3 million as of March 31, 2023 and December 31, 2022, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced.
| CRITICAL ACCOUNTING POLICIES AND ESTIMATES | ||||||||||||||
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Our discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.
We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans, income taxes and qualifying facilities liability. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022. As of March 31, 2023, there have been no material changes in these policies.
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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and counterparty credit exposure. We have established comprehensive risk management policies and procedures to manage these market risks. There have been no material changes in our market risks as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022.
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ITEM 4.CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS
See Note 10 - Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.
ITEM 1A. RISK FACTORS
Refer to our Annual Report on the Form 10-K for the year ended December 31, 2022 for disclosure of the risk factors that could have a significant impact on our business, financial condition, results of operations or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not changed materially since such disclosure.
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ITEM 6. EXHIBITS -
(a) Exhibits
Exhibit 10.1 — Forty-Second Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499).
Exhibit 10.2 — Seventeenth Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon, as trustee, (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499).
Exhibit 10.3—Form of 2023 Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499).
Exhibit 10.4—Form of 2023 Restricted Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499).
Exhibit 101.INS—Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
Exhibit 101.SCH—Inline XBRL Taxonomy Extension Schema Document
Exhibit 101.CAL—Inline XBRL Taxonomy Extension Calculation Linkbase Document
Exhibit 101.DEF—Inline XBRL Taxonomy Extension Definition Linkbase Document
Exhibit 101.LAB—Inline XBRL Taxonomy Label Linkbase Document
Exhibit 101.PRE—Inline XBRL Taxonomy Extension Presentation Linkbase Document
Exhibit 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
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SIGNATURES
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.
| NorthWestern Corporation | |||||||||||
| Date: | April 28, 2023 | By: | /s/ CRYSTAL LAIL | ||||||||
| Crystal Lail | |||||||||||
| Vice President and Chief Financial Officer | |||||||||||
| Duly Authorized Officer and Principal Financial Officer | |||||||||||
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