ITEM 1.FINANCIAL STATEMENTS
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Revenues
|
|
|
|
|
|
|
|
Electric
|
$
|
287,473
|
|
|
$
|
244,155
|
|
|
$
|
798,984
|
|
|
$
|
706,718
|
|
Gas
|
38,482
|
|
|
36,455
|
|
|
225,991
|
|
|
178,507
|
|
Total Revenues
|
325,955
|
|
|
280,610
|
|
|
1,024,975
|
|
|
885,225
|
|
Operating expenses
|
|
|
|
|
|
|
|
Cost of sales
|
98,659
|
|
|
68,038
|
|
|
311,137
|
|
|
220,353
|
|
Operating, general and administrative
|
80,948
|
|
|
73,322
|
|
|
238,913
|
|
|
224,042
|
|
Property and other taxes
|
43,572
|
|
|
45,306
|
|
|
138,337
|
|
|
136,786
|
|
Depreciation and depletion
|
47,112
|
|
|
44,289
|
|
|
140,896
|
|
|
134,336
|
|
Total Operating Expenses
|
270,291
|
|
|
230,955
|
|
|
829,283
|
|
|
715,517
|
|
Operating income
|
55,664
|
|
|
49,655
|
|
|
195,692
|
|
|
169,708
|
|
Interest expense, net
|
(23,283)
|
|
|
(23,677)
|
|
|
(70,266)
|
|
|
(72,298)
|
|
Other income (expense), net
|
5,326
|
|
|
785
|
|
|
13,932
|
|
|
(973)
|
|
Income before income taxes
|
37,707
|
|
|
26,763
|
|
|
139,358
|
|
|
96,437
|
|
Income tax (expense) benefit
|
(2,511)
|
|
|
2,703
|
|
|
(3,854)
|
|
|
5,227
|
|
Net Income
|
$
|
35,196
|
|
|
$
|
29,466
|
|
|
$
|
135,504
|
|
|
$
|
101,664
|
|
|
|
|
|
|
|
|
|
Average Common Shares Outstanding
|
51,892
|
|
|
50,577
|
|
|
51,175
|
|
|
50,551
|
|
Basic Earnings per Average Common Share
|
$
|
0.68
|
|
|
$
|
0.58
|
|
|
$
|
2.65
|
|
|
$
|
2.01
|
|
Diluted Earnings per Average Common Share
|
$
|
0.68
|
|
|
$
|
0.58
|
|
|
$
|
2.64
|
|
|
$
|
2.01
|
|
Dividends Declared per Common Share
|
$
|
0.62
|
|
|
$
|
0.60
|
|
|
$
|
1.86
|
|
|
$
|
1.80
|
|
See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Net Income
|
$
|
35,196
|
|
|
$
|
29,466
|
|
|
$
|
135,504
|
|
|
$
|
101,664
|
|
Other comprehensive income, net of tax:
|
|
|
|
|
|
|
|
Foreign currency translation adjustment
|
(1)
|
|
|
(3)
|
|
|
(56)
|
|
|
90
|
|
Postretirement medical liability adjustment
|
(159)
|
|
|
—
|
|
|
(476)
|
|
|
—
|
|
Reclassification of net losses on derivative instruments
|
113
|
|
|
113
|
|
|
339
|
|
|
339
|
|
Total Other Comprehensive (Loss) Income
|
(47)
|
|
|
110
|
|
|
(193)
|
|
|
429
|
|
Comprehensive Income
|
$
|
35,149
|
|
|
$
|
29,576
|
|
|
$
|
135,311
|
|
|
$
|
102,093
|
|
See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
2021
|
|
December 31,
2020
|
ASSETS
|
|
|
|
Current Assets:
|
|
|
|
Cash and cash equivalents
|
$
|
8,577
|
|
|
$
|
5,811
|
|
Restricted cash
|
15,642
|
|
|
11,285
|
|
Accounts receivable, net
|
139,328
|
|
|
168,229
|
|
Inventories
|
84,410
|
|
|
61,010
|
|
Regulatory assets
|
113,507
|
|
|
44,973
|
|
Prepaid expenses and other
|
25,814
|
|
|
17,372
|
|
Total current assets
|
387,278
|
|
|
308,680
|
|
Property, plant, and equipment, net
|
5,152,455
|
|
|
4,952,935
|
|
Goodwill
|
357,586
|
|
|
357,586
|
|
Regulatory assets
|
726,015
|
|
|
701,444
|
|
Other noncurrent assets
|
43,296
|
|
|
68,804
|
|
Total Assets
|
$
|
6,666,630
|
|
|
$
|
6,389,449
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
Current Liabilities:
|
|
|
|
Current maturities of finance leases
|
$
|
2,821
|
|
|
$
|
2,668
|
|
Short-term borrowings
|
—
|
|
|
100,000
|
|
Accounts payable
|
89,737
|
|
|
100,388
|
|
Accrued expenses
|
292,535
|
|
|
207,514
|
|
Regulatory liabilities
|
22,912
|
|
|
55,853
|
|
Total current liabilities
|
408,005
|
|
|
466,423
|
|
Long-term finance leases
|
12,642
|
|
|
14,771
|
|
Long-term debt
|
2,463,088
|
|
|
2,315,261
|
|
Deferred income taxes
|
484,161
|
|
|
471,777
|
|
Noncurrent regulatory liabilities
|
635,923
|
|
|
631,419
|
|
Other noncurrent liabilities
|
416,278
|
|
|
410,703
|
|
Total Liabilities
|
4,420,097
|
|
|
4,310,354
|
|
Commitments and Contingencies (Note 10)
|
|
|
|
Shareholders' Equity:
|
|
|
|
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 56,157,660 and 52,605,730 shares, respectively; Preferred stock, par value 0.01; authorized 50,000,000 shares; none issued
|
562
|
|
|
541
|
|
Treasury stock at cost
|
(98,424)
|
|
|
(98,075)
|
|
Paid-in capital
|
1,641,390
|
|
|
1,513,787
|
|
Retained earnings
|
710,467
|
|
|
670,111
|
|
Accumulated other comprehensive loss
|
(7,462)
|
|
|
(7,269)
|
|
Total Shareholders' Equity
|
2,246,533
|
|
|
2,079,095
|
|
Total Liabilities and Shareholders' Equity
|
$
|
6,666,630
|
|
|
$
|
6,389,449
|
|
See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
OPERATING ACTIVITIES:
|
|
|
|
Net income
|
$
|
135,504
|
|
|
$
|
101,664
|
|
Items not affecting cash:
|
|
|
|
Depreciation and depletion
|
140,896
|
|
|
134,336
|
|
Amortization of debt issuance costs, discount and deferred hedge gain
|
3,951
|
|
|
3,604
|
|
Stock-based compensation costs
|
5,850
|
|
|
5,347
|
|
Equity portion of allowance for funds used during construction
|
(7,829)
|
|
|
(4,503)
|
|
Loss (gain) on disposition of assets
|
6,536
|
|
|
(26)
|
|
Deferred income taxes
|
(681)
|
|
|
(3,759)
|
|
Changes in current assets and liabilities:
|
|
|
|
|
|
|
|
Accounts receivable
|
28,901
|
|
|
34,290
|
|
Inventories
|
(23,400)
|
|
|
(15,130)
|
|
Other current assets
|
(8,442)
|
|
|
(4,194)
|
|
Accounts payable
|
(12,472)
|
|
|
(4,181)
|
|
Accrued expenses
|
85,015
|
|
|
67,553
|
|
Regulatory assets
|
(67,672)
|
|
|
7,372
|
|
Regulatory liabilities
|
(32,941)
|
|
|
13,433
|
|
Other noncurrent assets
|
610
|
|
|
(1,825)
|
|
Other noncurrent liabilities
|
(32,216)
|
|
|
(11,466)
|
|
Cash Provided by Operating Activities
|
221,610
|
|
|
322,515
|
|
INVESTING ACTIVITIES:
|
|
|
|
Property, plant, and equipment additions
|
(311,160)
|
|
|
(282,987)
|
|
|
|
|
|
Investment in equity securities
|
(655)
|
|
|
(42)
|
|
Cash Used in Investing Activities
|
(311,815)
|
|
|
(283,029)
|
|
FINANCING ACTIVITIES:
|
|
|
|
Treasury stock activity
|
359
|
|
|
(1,723)
|
|
Proceeds from issuance of common stock, net
|
121,066
|
|
|
—
|
|
Dividends on common stock
|
(95,148)
|
|
|
(90,260)
|
|
Issuance of long-term debt, net
|
99,915
|
|
|
150,000
|
|
Repayments on long-term debt
|
(955)
|
|
|
—
|
|
Line of credit borrowings (repayments), net
|
73,000
|
|
|
(193,000)
|
|
|
|
|
|
(Repayments) issuance of short-term borrowings
|
(100,000)
|
|
|
100,000
|
|
Financing costs
|
(909)
|
|
|
(2,564)
|
|
Cash Provided by (Used in) Financing Activities
|
97,328
|
|
|
(37,547)
|
|
Increase in Cash, Cash Equivalents, and Restricted Cash
|
7,123
|
|
|
1,939
|
|
Cash, Cash Equivalents, and Restricted Cash, beginning of period
|
17,096
|
|
|
12,070
|
|
Cash, Cash Equivalents, and Restricted Cash, end of period
|
$
|
24,219
|
|
|
$
|
14,009
|
|
Supplemental Cash Flow Information:
|
|
|
|
Cash paid during the period for:
|
|
|
|
Income taxes
|
$
|
3,630
|
|
|
$
|
100
|
|
Interest
|
57,473
|
|
|
55,220
|
|
Significant non-cash transactions:
|
|
|
|
Capital expenditures included in accounts payable
|
23,500
|
|
|
15,986
|
|
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
NORTHWESTERN CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Unaudited)
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
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 June 30, 2020
|
54,145
|
|
|
3,571
|
|
|
$
|
541
|
|
|
$
|
(98,438)
|
|
|
$
|
1,513,510
|
|
|
$
|
647,272
|
|
|
$
|
(9,329)
|
|
|
$
|
2,053,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,466
|
|
|
—
|
|
|
29,466
|
|
Foreign currency translation adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
|
(3)
|
|
Reclassification of net losses on derivative instruments from OCI to net income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
113
|
|
|
113
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,140
|
|
|
—
|
|
|
—
|
|
|
1,140
|
|
Issuance of shares
|
—
|
|
|
(7)
|
|
|
—
|
|
|
196
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
366
|
|
Dividends on common stock ($0.600 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(30,088)
|
|
|
—
|
|
|
(30,088)
|
|
Balance at September 30, 2020
|
54,145
|
|
3,564
|
|
$
|
541
|
|
|
$
|
(98,242)
|
|
|
$
|
1,514,820
|
|
|
$
|
646,650
|
|
|
$
|
(9,219)
|
|
|
$
|
2,054,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2021
|
55,118
|
|
3,558
|
|
$
|
551
|
|
|
$
|
(98,578)
|
|
|
$
|
1,575,159
|
|
|
$
|
707,598
|
|
|
$
|
(7,415)
|
|
|
$
|
2,177,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
35,196
|
|
|
—
|
|
|
35,196
|
|
Foreign currency translation adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
(1)
|
|
Reclassification of net losses on derivative instruments from OCI to net income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
113
|
|
|
113
|
|
Postretirement medical liability adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(159)
|
|
|
(159)
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,301
|
|
|
—
|
|
|
|
|
1,301
|
|
Issuance of shares
|
1,039
|
|
|
(6)
|
|
|
11
|
|
|
154
|
|
|
64,930
|
|
|
—
|
|
|
|
|
65,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on common stock ($0.620 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(32,327)
|
|
|
—
|
|
|
(32,327)
|
|
Balance at September 30, 2021
|
56,157
|
|
3,552
|
|
$
|
562
|
|
|
$
|
(98,424)
|
|
|
$
|
1,641,390
|
|
|
$
|
710,467
|
|
|
$
|
(7,462)
|
|
|
$
|
2,246,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
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, 2019
|
53,999
|
|
|
3,547
|
|
|
$
|
541
|
|
|
$
|
(96,015)
|
|
|
$
|
1,508,970
|
|
|
$
|
635,246
|
|
|
$
|
(9,648)
|
|
|
$
|
2,039,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
101,664
|
|
|
—
|
|
|
101,664
|
|
Foreign currency translation adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90
|
|
|
90
|
|
Reclassification of net losses on derivative instruments from OCI to net income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
339
|
|
|
339
|
|
Stock-based compensation
|
146
|
|
|
35
|
|
|
—
|
|
|
(2,740)
|
|
|
5,310
|
|
|
—
|
|
|
—
|
|
|
2,570
|
|
Issuance of shares
|
—
|
|
|
(18)
|
|
|
—
|
|
|
513
|
|
|
540
|
|
|
—
|
|
|
—
|
|
|
1,053
|
|
Dividends on common stock ($1.800 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90,260)
|
|
|
—
|
|
|
(90,260)
|
|
Balance at September 30, 2020
|
54,145
|
|
3,564
|
|
$
|
541
|
|
|
$
|
(98,242)
|
|
|
$
|
1,514,820
|
|
|
$
|
646,650
|
|
|
$
|
(9,219)
|
|
|
$
|
2,054,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2020
|
54,145
|
|
3,558
|
|
$
|
541
|
|
|
$
|
(98,075)
|
|
|
$
|
1,513,787
|
|
|
$
|
670,111
|
|
|
$
|
(7,269)
|
|
|
$
|
2,079,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
135,504
|
|
|
—
|
|
|
135,504
|
|
Foreign currency translation adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(56)
|
|
|
(56)
|
|
Reclassification of net losses on derivative instruments from OCI to net income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
339
|
|
|
339
|
|
Postretirement medical liability adjustment, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(476)
|
|
|
(476)
|
|
Stock-based compensation
|
93
|
|
|
17
|
|
|
1
|
|
|
(970)
|
|
|
5,811
|
|
|
—
|
|
|
—
|
|
|
4,842
|
|
Issuance of shares
|
1,919
|
|
|
(23)
|
|
|
20
|
|
|
621
|
|
|
121,792
|
|
|
—
|
|
|
—
|
|
|
122,433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on common stock ($1.860 per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(95,148)
|
|
|
—
|
|
|
(95,148)
|
|
Balance at September 30, 2021
|
56,157
|
|
3,552
|
|
$
|
562
|
|
|
$
|
(98,424)
|
|
|
$
|
1,641,390
|
|
|
$
|
710,467
|
|
|
$
|
(7,462)
|
|
|
$
|
2,246,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
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 743,000 customers in Montana, South Dakota, Nebraska and Yellowstone National Park.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management 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 the opinion of management, 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 September 30, 2021 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, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends 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, 2020.
Reclassification
In the fourth quarter of 2020, we changed our classification of excess deferred income taxes in the Consolidated Balance Sheets from a regulatory asset to a regulatory liability, such that the excess deferred income tax regulatory liabilities are reflected on a gross basis, rather than net within our income tax regulatory asset based on our right to offset. The impact to our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 is a gross up of non-cash activity within the Other noncurrent assets and Other noncurrent liabilities captions, both within the operating activities section, that offset one another with no impact to cash provided by operating activities. The impact to the total assets reported as of September 30, 2020 in the segment information table within Note 6 - Segment Information was an increase of $168.4 million. This reclassification had no effect on previously reported Net income in our Condensed Consolidated Statements of Income, Condensed Consolidated Statements of Comprehensive Income, and Condensed Consolidated Statements of Shareholders' Equity.
Variable Interest Entities
A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance.
Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain qualifying co-generation facilities and qualifying small power production facilities (QF). We identified one QF contract that may constitute a VIE. We entered into a 40-year power purchase contract in 1984 with this 35 megawatt (MW) coal-fired QF to purchase substantially all of the facility’s capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility’s variability through annual changes to the price we pay per megawatt hour (MWH). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, as of September 30, 2021 our estimated remaining gross contractual payments aggregate approximately $74.1 million through 2024.
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
December 31,
|
September 30,
|
December 31,
|
|
2021
|
2020
|
2020
|
2019
|
Cash and cash equivalents
|
$
|
8,577
|
|
$
|
5,811
|
|
$
|
3,512
|
|
$
|
5,145
|
|
Restricted cash
|
15,642
|
|
11,285
|
|
10,497
|
|
6,925
|
|
Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows
|
$
|
24,219
|
|
$
|
17,096
|
|
$
|
14,009
|
|
$
|
12,070
|
|
Goodwill
We completed our annual goodwill impairment test as of April 1, 2021 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.
(2) Regulatory Matters
Power Costs and Credits Adjustment Mechanism (PCCAM) - Montana
We track electric supply costs for our Montana electric utility, such as purchased power and fuel, against a forecast of costs approved by the Montana Public Service Commission (MPSC). This forecast is referred to as the power costs and credits adjustment mechanism base (PCCAM Base). Our QF power purchase costs are separate from the PCCAM Base and 100% of QF power purchase costs are recoverable through rates. If our actual costs exceed the approved PCCAM Base on an annual basis, we can recover 90% of the excess costs, with the non-recoverable 10% impacting net income. During the three and nine months ended September 30, 2021, we recognized $2.7 million and $4.1 million of non-recoverable excess PCCAM supply costs, respectively, compared to $0.6 million and $0.5 million of non-recoverable excess PCCAM supply costs for the three and nine months ended September 30, 2020, respectively.
The current PCCAM Base, approved in 2019, no longer reflects an accurate current forecast of our fuel and power costs. In April 2021, we filed an application with the MPSC for approval to increase the PCCAM Base by approximately $17.0 million. On June 29, 2021, the MPSC approved interim rates reflecting our request, subject to refund. As of September 30, 2021, we have collected and deferred approximately $3.8 million associated with the interim rates. On August 2, 2021, the Montana Consumer Counsel (MCC) filed a motion asking the MPSC to dismiss the application arguing that the MPSC issued a Final Order in 2018 prohibiting NorthWestern from requesting an update to the PCCAM Base, except in a general rate case. NorthWestern argued that the tariff, which the MPSC approved as implementing the Final Order, allows us to file an application outside of a general rate case. On October 5, 2021, the MPSC voted to grant the MCC’s motion to dismiss, and we await the final written order.
If we continue to experience higher power and fuel costs relative to the approved PCCAM Base, the sharing mechanism will result in delayed recovery for 90% of the excess supply costs and higher losses for the remaining non-recoverable 10% of the excess costs.
FERC Filing - Montana Transmission Service Rates
In May 2019, we submitted a filing with the Federal Energy Regulatory Commission (FERC) for our Montana transmission assets. In June 2019, the FERC issued an order accepting our filing, and granting interim rates (subject to refund) effective July 1, 2019. In November 2020, we filed a settlement and implemented settlement rates on December 1, 2020. In January 2021, the FERC approved our settlement and during the first quarter of 2021 we refunded approximately $20.5 million to our FERC regulated customers.
Revenues from FERC regulated customers associated with our Montana FERC assets are reflected in our MPSC jurisdictional rates as a credit to retail customers. In March 2021, we submitted a compliance filing with the MPSC adjusting the revenue credit in our Montana retail rates to reflect the FERC approved settlement rates and a refund to retail customers of the difference between the FERC interim rates and the FERC approved settlement rates that were collected during the period from July 1, 2019 through March 31, 2021. On May 19, 2021, the MPSC approved the proposed tariffs and rates on a final basis. During the second quarter of 2021, we recognized a $4.7 million favorable adjustment related to excess deferred revenues based on the final MPSC approval. As of September 30, 2021, we had cumulative deferred revenue remaining of approximately $3.9 million recorded as a regulatory liability on the Condensed Consolidated Balance Sheets.
Montana Community Renewable Energy Projects (CREPs)
We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we have made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we have been unable to acquire the remaining MWs required for various reasons, including the fact that proposed projects fail to qualify as CREPs or do not meet the statutory cost cap. The MPSC granted us waivers for 2012 through 2016. The validity of the MPSC’s action as it related to waivers granted for 2015 and 2016 has been challenged legally and has been fully briefed before the Montana Supreme Court.
On May 14, 2021, the Montana Governor signed a bill that repealed the CREP requirement. We notified the Montana Supreme Court of the repeal. We also dismissed our pending application filed with the MPSC for a waiver from full compliance for years 2017 through 2020.
On September 7, 2021, the Montana Supreme Court remanded the case to the District Court to determine whether the repeal of the CREP requirement made the petition challenging the waivers granted for 2015 and 2016 moot. The District Court has established a briefing schedule and we do not expect a decision from the District Court until at least the first quarter of 2022.
If the Montana Courts and/or MPSC determine that the repeal should not be applied retroactively and find that waivers should not be granted, we could be liable for penalties. However, we do not believe any such penalties would be material.
FERC Financial Audit
We are subject to FERC’s jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things. The Division of Audits and Accounting in the Office of Enforcement of FERC has initiated a routine audit of NorthWestern Corporation for the period of January 1, 2018 to the present to evaluate our compliance with FERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received from FERC, but is expected within the next six months. Management is unable to predict the outcome or timing of the final resolution of the audit.
(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 September 30,
|
|
2021
|
|
2020
|
Income before income taxes
|
$
|
37,707
|
|
|
|
|
$
|
26,763
|
|
|
|
|
|
|
|
|
|
|
|
Income tax calculated at federal statutory rate
|
7,918
|
|
|
21.0
|
%
|
|
5,621
|
|
|
21.0
|
%
|
|
|
|
|
|
|
|
|
Permanent or flow-through adjustments:
|
|
|
|
|
|
|
|
State income tax, net of federal provisions
|
397
|
|
|
1.1
|
|
|
46
|
|
|
0.2
|
|
Flow-through repairs deductions
|
(3,473)
|
|
|
(9.2)
|
|
|
(4,213)
|
|
|
(15.7)
|
|
Production tax credits
|
(1,877)
|
|
|
(5.0)
|
|
|
(2,205)
|
|
|
(8.2)
|
|
Plant and depreciation of flow-through items
|
(288)
|
|
|
(0.8)
|
|
|
103
|
|
|
0.4
|
|
Amortization of excess deferred income tax
|
(126)
|
|
|
(0.3)
|
|
|
(222)
|
|
|
(0.8)
|
|
Share-based compensation
|
(62)
|
|
|
(0.2)
|
|
|
—
|
|
|
—
|
|
Income tax return to accrual adjustment
|
389
|
|
|
1.0
|
|
|
(1,728)
|
|
|
(6.5)
|
|
Other, net
|
(367)
|
|
|
(1.0)
|
|
|
(105)
|
|
|
(0.5)
|
|
|
(5,407)
|
|
|
(14.4)
|
|
|
(8,324)
|
|
|
(31.1)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
$
|
2,511
|
|
|
6.6
|
%
|
|
$
|
(2,703)
|
|
|
(10.1)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
Income before income taxes
|
$
|
139,358
|
|
|
|
|
$
|
96,437
|
|
|
|
|
|
|
|
|
|
|
|
Income tax calculated at federal statutory rate
|
29,265
|
|
|
21.0
|
%
|
|
20,252
|
|
|
21.0
|
%
|
|
|
|
|
|
|
|
|
Permanent or flow through adjustments:
|
|
|
|
|
|
|
|
State income, net of federal provisions
|
674
|
|
|
0.5
|
|
|
73
|
|
|
0.1
|
|
Flow-through repairs deductions
|
(15,553)
|
|
|
(11.2)
|
|
|
(14,859)
|
|
|
(15.4)
|
|
Production tax credits
|
(8,446)
|
|
|
(6.1)
|
|
|
(7,553)
|
|
|
(7.8)
|
|
Plant and depreciation of flow through items
|
(812)
|
|
|
(0.6)
|
|
|
299
|
|
|
0.3
|
|
Amortization of excess deferred income tax
|
(534)
|
|
|
(0.4)
|
|
|
(731)
|
|
|
(0.8)
|
|
Share-based compensation
|
(323)
|
|
|
(0.2)
|
|
|
(609)
|
|
|
(0.6)
|
|
Income tax return to accrual adjustment
|
389
|
|
|
0.3
|
|
|
(1,728)
|
|
|
(1.8)
|
|
|
|
|
|
|
|
|
|
Other, net
|
(806)
|
|
|
(0.5)
|
|
|
(371)
|
|
|
(0.4)
|
|
|
(25,411)
|
|
|
(18.2)
|
|
|
(25,479)
|
|
|
(26.4)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
$
|
3,854
|
|
|
2.8
|
%
|
|
$
|
(5,227)
|
|
|
(5.4)
|
%
|
|
|
|
|
|
|
|
|
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 $32.5 million as of September 30, 2021, including approximately $28.1 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 related to uncertain tax positions in income tax expense. As of September 30, 2021, we have $0.3 million accrued for the payment of interest and penalties.
Tax years 2017 and forward remain subject to examination by the Internal Revenue Service (IRS) and state taxing authorities. In addition, the available federal net operating loss carryforward may be reduced by the IRS for losses originating in certain tax years from 2003 forward.
(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
|
|
September 30, 2021
|
|
September 30, 2020
|
|
Before-Tax Amount
|
|
Tax Expense
|
|
Net-of-Tax Amount
|
|
Before-Tax Amount
|
|
Tax Expense
|
|
Net-of-Tax Amount
|
Foreign currency translation adjustment
|
$
|
(1)
|
|
|
$
|
—
|
|
|
$
|
(1)
|
|
|
$
|
(3)
|
|
|
$
|
—
|
|
|
$
|
(3)
|
|
Reclassification of net income on derivative instruments
|
153
|
|
|
(40)
|
|
|
113
|
|
|
153
|
|
|
(40)
|
|
|
113
|
|
Postretirement medical liability adjustment
|
(212)
|
|
|
53
|
|
|
(159)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other comprehensive (loss) income
|
$
|
(60)
|
|
|
$
|
13
|
|
|
$
|
(47)
|
|
|
$
|
150
|
|
|
$
|
(40)
|
|
|
$
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
September 30, 2021
|
|
September 30, 2020
|
|
Before-Tax Amount
|
|
Tax Expense
|
|
Net-of-Tax Amount
|
|
Before-Tax Amount
|
|
Tax Expense
|
|
Net-of-Tax Amount
|
Foreign currency translation adjustment
|
$
|
(56)
|
|
|
$
|
—
|
|
|
$
|
(56)
|
|
|
$
|
90
|
|
|
$
|
—
|
|
|
$
|
90
|
|
Reclassification of net income on derivative instruments
|
459
|
|
|
(120)
|
|
|
339
|
|
|
459
|
|
|
(120)
|
|
|
339
|
|
Postretirement medical liability adjustment
|
(636)
|
|
|
160
|
|
|
(476)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other comprehensive (loss) income
|
$
|
(233)
|
|
|
$
|
40
|
|
|
$
|
(193)
|
|
|
$
|
549
|
|
|
$
|
(120)
|
|
|
$
|
429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2021
|
|
December 31, 2020
|
|
Foreign currency translation
|
$
|
1,444
|
|
|
$
|
1,500
|
|
|
Derivative instruments designated as cash flow hedges
|
(10,390)
|
|
|
(10,729)
|
|
|
Postretirement medical plans
|
1,484
|
|
|
1,960
|
|
|
Accumulated other comprehensive loss
|
$
|
(7,462)
|
|
|
$
|
(7,269)
|
|
|
The following tables display the changes in AOCL by component, net of tax (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
September 30, 2021
|
|
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
|
|
|
$
|
(10,503)
|
|
|
$
|
1,643
|
|
|
$
|
1,445
|
|
|
$
|
(7,415)
|
|
Other comprehensive income before reclassifications
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
(1)
|
|
Amounts reclassified from AOCL
|
Interest Expense
|
|
113
|
|
|
—
|
|
|
—
|
|
|
113
|
|
Amounts reclassified from AOCL
|
|
|
—
|
|
|
(159)
|
|
|
—
|
|
|
(159)
|
|
Net current-period other comprehensive income (loss)
|
|
|
113
|
|
|
(159)
|
|
|
(1)
|
|
|
(47)
|
|
Ending balance
|
|
|
$
|
(10,390)
|
|
|
$
|
1,484
|
|
|
$
|
1,444
|
|
|
$
|
(7,462)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
September 30, 2020
|
|
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
|
|
|
$
|
(10,955)
|
|
|
$
|
120
|
|
|
$
|
1,506
|
|
|
$
|
(9,329)
|
|
Other comprehensive loss before reclassifications
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
|
(3)
|
|
Amounts reclassified from AOCL
|
Interest Expense
|
|
113
|
|
|
—
|
|
|
—
|
|
|
113
|
|
Net current-period other comprehensive income (loss)
|
|
|
113
|
|
|
—
|
|
|
(3)
|
|
|
110
|
|
Ending balance
|
|
|
$
|
(10,842)
|
|
|
$
|
120
|
|
|
$
|
1,503
|
|
|
$
|
(9,219)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30, 2021
|
|
Affected Line Item in the Condensed Consolidated Statements of Income
|
|
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
|
|
Pension and Postretirement Medical Plans
|
|
Foreign Currency Translation
|
|
Total
|
Beginning balance
|
|
|
$
|
(10,729)
|
|
|
$
|
1,960
|
|
|
$
|
1,500
|
|
|
$
|
(7,269)
|
|
Other comprehensive loss before reclassifications
|
|
|
—
|
|
|
—
|
|
|
(56)
|
|
|
(56)
|
|
Amounts reclassified from AOCL
|
Interest Expense
|
|
339
|
|
|
—
|
|
|
—
|
|
|
339
|
|
Amounts reclassified from AOCL
|
|
|
—
|
|
|
(476)
|
|
|
—
|
|
|
(476)
|
|
Net current-period other comprehensive income (loss)
|
|
|
339
|
|
|
(476)
|
|
|
(56)
|
|
|
(193)
|
|
Ending balance
|
|
|
$
|
(10,390)
|
|
|
$
|
1,484
|
|
|
$
|
1,444
|
|
|
$
|
(7,462)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30, 2020
|
|
Affected Line Item in the Condensed Consolidated Statements of Income
|
|
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
|
|
Pension and Postretirement Medical Plans
|
|
Foreign Currency Translation
|
|
Total
|
Beginning balance
|
|
|
$
|
(11,181)
|
|
|
$
|
120
|
|
|
$
|
1,413
|
|
|
$
|
(9,648)
|
|
Other comprehensive income before reclassifications
|
|
|
—
|
|
|
—
|
|
|
90
|
|
|
90
|
|
Amounts reclassified from AOCL
|
Interest Expense
|
|
339
|
|
|
—
|
|
|
—
|
|
|
339
|
|
Net current-period other comprehensive income
|
|
|
339
|
|
|
—
|
|
|
90
|
|
|
429
|
|
Ending balance
|
|
|
$
|
(10,842)
|
|
|
$
|
120
|
|
|
$
|
1,503
|
|
|
$
|
(9,219)
|
|
|
|
|
|
|
|
|
|
|
|
(5) Financing Activities
In March 2021, we issued and sold $100.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00% maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100.0 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming.
In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. During the three months ended September 30, 2021, we issued 1,040,085 shares of our common stock under the ATM program at an average price of $63.13, for net proceeds of $64.8 million, which is net of sales commissions and other fees paid of approximately $0.9 million. During the nine months ended September 30, 2021, we issued 1,919,394 shares of our common stock under the ATM program at an average price of $63.94, for net proceeds of $121.1 million, which is net of sales commissions and other fees paid of approximately $1.7 million.
In July 2021, our two loans totaling $27.0 million associated with the New Market Tax Credit (NMTC) financing agreement were extinguished. These loans were satisfied with our $18.2 million investment in the VIE, investor forgiveness of $7.9 million for substantially all of the benefits derived from the tax credits, and cash payment of $0.9 million. In accordance with our last rate case filing in the state of Montana, the portion of the loan forgiven was recorded as a reduction to the cost of the office building associated with the NMTC financing agreement. This cash payment is reflected within the financing activities section of our Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2021; however, the remaining reduction to Long-term debt, Other noncurrent assets, and Property, plant and equipment are non-cash financing activities that are not reflected within our Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2021.
(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 gross 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 management for internal reporting purposes and involves estimates and assumptions.
Financial data for the business segments are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
September 30, 2021
|
Electric
|
|
Gas
|
|
Other
|
|
Eliminations
|
|
Total
|
Operating revenues
|
$
|
287,473
|
|
|
$
|
38,482
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
325,955
|
|
Cost of sales
|
89,375
|
|
|
9,284
|
|
|
—
|
|
|
—
|
|
|
98,659
|
|
Gross margin
|
198,098
|
|
|
29,198
|
|
|
—
|
|
|
—
|
|
|
227,296
|
|
Operating, general and administrative
|
60,621
|
|
|
20,429
|
|
|
(102)
|
|
|
—
|
|
|
80,948
|
|
Property and other taxes
|
34,066
|
|
|
9,504
|
|
|
2
|
|
|
—
|
|
|
43,572
|
|
Depreciation and depletion
|
38,634
|
|
|
8,478
|
|
|
—
|
|
|
—
|
|
|
47,112
|
|
Operating income (loss)
|
64,777
|
|
|
(9,213)
|
|
|
100
|
|
|
—
|
|
|
55,664
|
|
Interest expense, net
|
(20,429)
|
|
|
(1,640)
|
|
|
(1,214)
|
|
|
—
|
|
|
(23,283)
|
|
Other income (expense), net
|
3,348
|
|
|
2,016
|
|
|
(38)
|
|
|
—
|
|
|
5,326
|
|
Income tax (expense) benefit
|
(1,680)
|
|
|
725
|
|
|
(1,556)
|
|
|
—
|
|
|
(2,511)
|
|
Net income (loss)
|
$
|
46,016
|
|
|
$
|
(8,112)
|
|
|
$
|
(2,708)
|
|
|
$
|
—
|
|
|
$
|
35,196
|
|
Total assets
|
$
|
5,370,432
|
|
|
$
|
1,291,144
|
|
|
$
|
5,054
|
|
|
$
|
—
|
|
|
$
|
6,666,630
|
|
Capital expenditures
|
$
|
102,188
|
|
|
$
|
26,778
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
128,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
September 30, 2020
|
Electric
|
|
Gas
|
|
Other
|
|
Eliminations
|
|
Total
|
Operating revenues
|
$
|
244,155
|
|
|
$
|
36,455
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
280,610
|
|
Cost of sales
|
61,155
|
|
|
6,883
|
|
|
—
|
|
|
—
|
|
|
68,038
|
|
Gross margin
|
183,000
|
|
|
29,572
|
|
|
—
|
|
|
—
|
|
|
212,572
|
|
Operating, general and administrative
|
54,367
|
|
|
20,059
|
|
|
(1,104)
|
|
|
—
|
|
|
73,322
|
|
Property and other taxes
|
35,532
|
|
|
9,772
|
|
|
2
|
|
|
—
|
|
|
45,306
|
|
Depreciation and depletion
|
36,670
|
|
|
7,619
|
|
|
—
|
|
|
—
|
|
|
44,289
|
|
Operating income (loss)
|
56,431
|
|
|
(7,878)
|
|
|
1,102
|
|
|
—
|
|
|
49,655
|
|
Interest expense, net
|
(21,286)
|
|
|
(1,574)
|
|
|
(817)
|
|
|
—
|
|
|
(23,677)
|
|
Other income (expense), net
|
1,559
|
|
|
459
|
|
|
(1,233)
|
|
|
—
|
|
|
785
|
|
Income tax benefit
|
1,197
|
|
|
607
|
|
|
899
|
|
|
—
|
|
|
2,703
|
|
Net income (loss)
|
$
|
37,901
|
|
|
$
|
(8,386)
|
|
|
$
|
(49)
|
|
|
$
|
—
|
|
|
$
|
29,466
|
|
Total assets(1)
|
$
|
5,031,741
|
|
|
$
|
1,201,528
|
|
|
$
|
10,754
|
|
|
$
|
—
|
|
|
$
|
6,244,023
|
|
Capital expenditures
|
$
|
87,432
|
|
|
$
|
19,073
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
106,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
|
|
|
|
September 30, 2021
|
Electric
|
|
Gas
|
|
Other
|
|
Eliminations
|
|
Total
|
Operating revenues
|
$
|
798,984
|
|
|
$
|
225,991
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,024,975
|
|
Cost of sales
|
218,802
|
|
|
92,335
|
|
|
—
|
|
|
—
|
|
|
311,137
|
|
Gross margin
|
580,182
|
|
|
133,656
|
|
|
—
|
|
|
—
|
|
|
713,838
|
|
Operating, general and administrative
|
176,411
|
|
|
60,873
|
|
|
1,629
|
|
|
—
|
|
|
238,913
|
|
Property and other taxes
|
108,050
|
|
|
30,281
|
|
|
6
|
|
|
—
|
|
|
138,337
|
|
Depreciation and depletion
|
115,858
|
|
|
25,038
|
|
|
—
|
|
|
—
|
|
|
140,896
|
|
Operating income (loss)
|
179,863
|
|
|
17,464
|
|
|
(1,635)
|
|
|
—
|
|
|
195,692
|
|
Interest expense, net
|
(62,007)
|
|
|
(4,550)
|
|
|
(3,709)
|
|
|
—
|
|
|
(70,266)
|
|
Other income
|
8,392
|
|
|
4,035
|
|
|
1,505
|
|
|
—
|
|
|
13,932
|
|
Income tax (expense) benefit
|
(2,369)
|
|
|
(1,505)
|
|
|
20
|
|
|
—
|
|
|
(3,854)
|
|
Net income (loss)
|
$
|
123,879
|
|
|
$
|
15,444
|
|
|
$
|
(3,819)
|
|
|
$
|
—
|
|
|
$
|
135,504
|
|
Total assets
|
$
|
5,370,432
|
|
|
$
|
1,291,144
|
|
|
$
|
5,054
|
|
|
$
|
—
|
|
|
$
|
6,666,630
|
|
Capital expenditures
|
$
|
253,588
|
|
|
$
|
57,572
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
311,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
|
|
|
|
September 30, 2020
|
Electric
|
|
Gas
|
|
Other
|
|
Eliminations
|
|
Total
|
Operating revenues
|
$
|
706,718
|
|
|
$
|
178,507
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
885,225
|
|
Cost of sales
|
173,294
|
|
|
47,059
|
|
|
—
|
|
|
—
|
|
|
220,353
|
|
Gross margin
|
533,424
|
|
|
131,448
|
|
|
—
|
|
|
—
|
|
|
664,872
|
|
Operating, general and administrative
|
166,854
|
|
|
61,348
|
|
|
(4,160)
|
|
|
—
|
|
|
224,042
|
|
Property and other taxes
|
107,079
|
|
|
29,700
|
|
|
7
|
|
|
—
|
|
|
136,786
|
|
Depreciation and depletion
|
110,692
|
|
|
23,644
|
|
|
—
|
|
|
—
|
|
|
134,336
|
|
Operating income
|
148,799
|
|
|
16,756
|
|
|
4,153
|
|
|
—
|
|
|
169,708
|
|
Interest expense, net
|
(63,585)
|
|
|
(4,824)
|
|
|
(3,889)
|
|
|
—
|
|
|
(72,298)
|
|
Other income (expense)
|
3,131
|
|
|
863
|
|
|
(4,967)
|
|
|
—
|
|
|
(973)
|
|
Income tax benefit (expense)
|
2,609
|
|
|
(467)
|
|
|
3,085
|
|
|
—
|
|
|
5,227
|
|
Net income (loss)
|
$
|
90,954
|
|
|
$
|
12,328
|
|
|
$
|
(1,618)
|
|
|
$
|
—
|
|
|
$
|
101,664
|
|
Total assets(1)
|
$
|
5,031,741
|
|
|
$
|
1,201,528
|
|
|
$
|
10,754
|
|
|
$
|
—
|
|
|
$
|
6,244,023
|
|
Capital expenditures
|
$
|
230,524
|
|
|
$
|
52,463
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
282,987
|
|
|
|
|
|
|
|
|
|
|
|
___________________________
(1) Subsequent to the issuance of our Annual Report on Form 10-K for the year ended December 31, 2020, we determined that Total Assets - Electric and Total Assets - Gas had been incorrectly reported due to an error in the allocation methodology utilized to calculate assets by segment. As a result, the September 30, 2020 Total Assets - Electric and Total Assets - Gas amounts have been corrected from the amounts previously reported to reflect an increase of Total Assets - Electric and a decrease of Total Assets - Gas of $466.9 million. The correction had no impact on net income or the presentation of total assets on the consolidated balance sheets and was determined not to be material.
(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 residential customers include 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
|
|
September 30, 2021
|
|
September 30, 2020
|
|
Electric
|
|
Natural Gas
|
|
Total
|
|
Electric
|
|
Natural Gas
|
|
Total
|
Montana
|
$
|
85.5
|
|
|
$
|
9.9
|
|
|
$
|
95.4
|
|
|
$
|
78.5
|
|
|
$
|
9.9
|
|
|
$
|
88.4
|
|
South Dakota
|
18.8
|
|
|
2.2
|
|
|
21.0
|
|
|
18.9
|
|
|
1.7
|
|
|
20.6
|
|
Nebraska
|
—
|
|
|
2.5
|
|
|
2.5
|
|
|
—
|
|
|
1.7
|
|
|
1.7
|
|
Residential
|
104.3
|
|
|
14.6
|
|
|
118.9
|
|
|
97.4
|
|
|
13.3
|
|
|
110.7
|
|
Montana
|
95.2
|
|
|
6.1
|
|
|
101.3
|
|
|
89.1
|
|
|
5.6
|
|
|
94.7
|
|
South Dakota
|
28.8
|
|
|
1.8
|
|
|
30.6
|
|
|
27.4
|
|
|
1.0
|
|
|
28.4
|
|
Nebraska
|
—
|
|
|
1.5
|
|
|
1.5
|
|
|
—
|
|
|
0.7
|
|
|
0.7
|
|
Commercial
|
124.0
|
|
|
9.4
|
|
|
133.4
|
|
|
116.5
|
|
|
7.3
|
|
|
123.8
|
|
Industrial
|
9.2
|
|
|
—
|
|
|
9.2
|
|
|
9.2
|
|
|
0.1
|
|
|
9.3
|
|
Lighting, governmental, irrigation, and interdepartmental
|
13.1
|
|
|
0.1
|
|
|
13.2
|
|
|
11.9
|
|
|
0.1
|
|
|
12.0
|
|
Total Customer Revenues
|
250.6
|
|
|
24.1
|
|
|
274.7
|
|
|
235.0
|
|
|
20.8
|
|
|
255.8
|
|
Other tariff and contract based revenues
|
26.9
|
|
|
8.7
|
|
|
35.6
|
|
|
14.9
|
|
|
8.3
|
|
|
23.2
|
|
Total Revenue from Contracts with Customers
|
277.5
|
|
|
32.8
|
|
|
310.3
|
|
|
249.9
|
|
|
29.1
|
|
|
279.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory amortization and other
|
10.0
|
|
|
5.7
|
|
|
15.7
|
|
|
(5.7)
|
|
|
7.4
|
|
|
1.7
|
|
Total Revenues
|
$
|
287.5
|
|
|
$
|
38.5
|
|
|
$
|
326.0
|
|
|
$
|
244.2
|
|
|
$
|
36.5
|
|
|
$
|
280.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
September 30, 2021
|
|
September 30, 2020
|
|
Electric
|
|
Natural Gas
|
|
Total
|
|
Electric
|
|
Natural Gas
|
|
Total
|
Montana
|
$
|
251.4
|
|
|
$
|
82.4
|
|
|
$
|
333.8
|
|
|
$
|
237.7
|
|
|
$
|
65.7
|
|
|
$
|
303.4
|
|
South Dakota
|
51.0
|
|
|
18.7
|
|
|
69.7
|
|
|
52.4
|
|
|
16.7
|
|
|
69.1
|
|
Nebraska
|
—
|
|
|
14.6
|
|
|
14.6
|
|
|
—
|
|
|
12.9
|
|
|
12.9
|
|
Residential
|
302.4
|
|
|
115.7
|
|
|
418.1
|
|
|
290.1
|
|
|
95.3
|
|
|
385.4
|
|
Montana
|
266.6
|
|
|
42.9
|
|
|
309.5
|
|
|
252.5
|
|
|
33.0
|
|
|
285.5
|
|
South Dakota
|
77.0
|
|
|
12.6
|
|
|
89.6
|
|
|
77.1
|
|
|
11.2
|
|
|
88.3
|
|
Nebraska
|
—
|
|
|
7.7
|
|
|
7.7
|
|
|
—
|
|
|
6.2
|
|
|
6.2
|
|
Commercial
|
343.6
|
|
|
63.2
|
|
|
406.8
|
|
|
329.6
|
|
|
50.4
|
|
|
380.0
|
|
Industrial
|
28.1
|
|
|
0.7
|
|
|
28.8
|
|
|
27.2
|
|
|
0.5
|
|
|
27.7
|
|
Lighting, governmental, irrigation, and interdepartmental
|
26.8
|
|
|
1.0
|
|
|
27.8
|
|
|
26.4
|
|
|
0.7
|
|
|
27.1
|
|
Total Customer Revenues
|
700.9
|
|
|
180.6
|
|
|
881.5
|
|
|
673.3
|
|
|
146.9
|
|
|
820.2
|
|
Other tariff and contract based revenues
|
69.2
|
|
|
27.5
|
|
|
96.7
|
|
|
44.1
|
|
|
26.5
|
|
|
70.6
|
|
Total Revenue from Contracts with Customers
|
770.1
|
|
|
208.1
|
|
|
978.2
|
|
|
717.4
|
|
|
173.4
|
|
|
890.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory amortization and other
|
28.9
|
|
|
17.9
|
|
|
46.8
|
|
|
(10.7)
|
|
|
5.1
|
|
|
(5.6)
|
|
Total Revenues
|
$
|
799.0
|
|
|
$
|
226.0
|
|
|
$
|
1,025.0
|
|
|
$
|
706.7
|
|
|
$
|
178.5
|
|
|
$
|
885.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. Average shares used in computing the basic and diluted earnings per share are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
September 30, 2021
|
|
September 30, 2020
|
Basic computation
|
51,891,557
|
|
|
50,576,564
|
|
Dilutive effect of:
|
|
|
|
Performance share awards(1)
|
136,865
|
|
|
97,529
|
|
|
|
|
|
Diluted computation
|
52,028,422
|
|
|
50,674,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
September 30, 2021
|
|
September 30, 2020
|
Basic computation
|
51,175,345
|
|
|
50,551,121
|
|
Dilutive effect of:
|
|
|
|
Performance share awards(1)
|
136,995
|
|
|
105,395
|
|
|
|
|
|
Diluted computation
|
51,312,340
|
|
|
50,656,516
|
|
|
|
|
|
_______________________
(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.
As of September 30, 2021, there were 23,722 shares from performance and restricted share awards which were antidilutive
and excluded from the earnings per share calculations.
(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 September 30,
|
|
Three Months Ended September 30,
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
Components of Net Periodic Benefit Cost (Credit)
|
|
|
|
|
|
|
|
Service cost
|
$
|
3,275
|
|
|
$
|
2,779
|
|
|
$
|
103
|
|
|
$
|
93
|
|
Interest cost
|
4,704
|
|
|
5,710
|
|
|
79
|
|
|
123
|
|
Expected return on plan assets
|
(6,841)
|
|
|
(6,541)
|
|
|
(230)
|
|
|
(246)
|
|
Amortization of prior service credit
|
—
|
|
|
—
|
|
|
(459)
|
|
|
(471)
|
|
Recognized actuarial loss (gain)
|
1,744
|
|
|
1,257
|
|
|
(8)
|
|
|
(15)
|
|
Net periodic benefit cost (credit)
|
$
|
2,882
|
|
|
$
|
3,205
|
|
|
$
|
(515)
|
|
|
$
|
(516)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
Components of Net Periodic Benefit Cost (Credit)
|
|
|
|
|
|
|
|
|
|
Service cost
|
$
|
9,824
|
|
|
$
|
8,337
|
|
|
$
|
306
|
|
|
$
|
278
|
|
|
|
Interest cost
|
14,114
|
|
|
17,130
|
|
|
238
|
|
|
369
|
|
|
|
Expected return on plan assets
|
(20,525)
|
|
|
(19,622)
|
|
|
(689)
|
|
|
(738)
|
|
|
|
Amortization of prior service credit
|
—
|
|
|
—
|
|
|
(1,377)
|
|
|
(1,412)
|
|
|
|
Recognized actuarial loss (gain)
|
5,233
|
|
|
3,771
|
|
|
(23)
|
|
|
(45)
|
|
|
|
Net periodic benefit cost (credit)
|
$
|
8,646
|
|
|
$
|
9,616
|
|
|
$
|
(1,545)
|
|
|
$
|
(1,548)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We contributed $10.2 million to our pension plans during the nine months ended September 30, 2021. We expect to contribute an additional $1.0 million to our pension plans during the remainder of 2021.
(10) Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $24.7 million to $30.4 million. As of September 30, 2021, we had a reserve of approximately $27.1 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.
Manufactured Gas Plants - Approximately $20.9 million of our environmental reserve accrual is related to the following manufactured gas plants.
South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of September 30, 2021, the reserve for remediation costs at this site was approximately $7.8 million, and we estimate that approximately $2.8 million of this amount will be incurred through 2025.
Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.
Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site.
In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and we expect work at the Helena site to continue into 2022.
MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has submitted a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.
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). These actions include legislative proposals, Executive 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. In 2019, the EPA finalized the Affordable Clean Energy Rule (ACE), which repealed the 2015 Clean Power Plan (CPP) in regulating GHG emissions from coal-fired plants. The U.S. Court of Appeals for the District of Columbia Circuit issued an opinion on January 19, 2021, vacating the ACE and remanding it to EPA for further action. It is widely expected that the Biden Administration will develop an alternative plan for reducing GHG emissions from coal-fired plants, and in a memorandum dated February 12, 2021, EPA stated its belief that the January 19, 2021 opinion left neither the ACE nor the CPP rules in place.
We cannot predict whether or how GHG emission regulations will be applied to our plants, including any actions taken by the relevant state authorities. In addition, it is unclear how pending or future litigation relating to GHG matters will impact us. 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 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, 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.
Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act (CAA) that could require the installation of emission control equipment at the generation plants in which we have joint ownership. Air emissions at our thermal generating plants are managed by the use of emissions and combustion controls and monitoring, and sulfur dioxide allowances. These measures are anticipated to be sufficient to permit the facilities to continue to meet current air emissions compliance requirements.
Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. In March 2017, we filed a Petition for Review of these amendments with the D.C. Circuit, which was consolidated with other petitions challenging the final rule. The D.C. Circuit has granted the EPA's request to hold the case in abeyance while the EPA considers further administrative action to revisit the rule.
The states of Montana, North Dakota and South Dakota are expected to develop and submit to EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, we still expect each state to submit its SIP in 2021. While no draft is available publicly, the Montana SIP could impact our interest in Colstrip Unit 4, by requiring additional controls. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are submitted and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities.
Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are or may become subject to the various regulations discussed above that have been or may be issued or proposed.
Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
•We may not know all sites for which we are alleged or will be found to be responsible for remediation; and
•Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
Pacific Northwest Solar Litigation
Pacific Northwest Solar, LLC (PNWS) is a solar QF developer seeking to construct small solar facilities in Montana. We began negotiating with PNWS in early 2016 to purchase the output from 21 of its proposed facilities pursuant to our standard QF-1 Tariff, which is applicable to projects no larger than 3 MWs.
On June 16, 2016, however, the MPSC suspended the availability of the QF-1 Tariff standard rates for that category of solar projects, which included the projects proposed by PNWS. The MPSC exempted from the suspension any projects for which a QF had both submitted a signed power purchase agreement and had executed an interconnection agreement with us by June 16, 2016. Although we had signed four power purchase agreements with PNWS as of that date, we had not entered into interconnection agreements with PNWS for any of those projects. As a result, none of the PNWS projects in Montana qualified for the exemption.
In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and a judicial declaration that some or all of the 21 proposed power purchase agreements it had proposed to us were in effect despite the MPSC's Order. We removed the state lawsuit to the United States District Court for the District of Montana (Court).
PNWS also requested the MPSC to exempt its projects from the tariff suspension and allow those projects to receive the QF-1 tariff rate that had been in effect prior to the suspension. We joined in PNWS’s request for relief with respect to four of the projects, but the MPSC did not grant any of the relief requested by PNWS or us.
In August 2017, we entered into a non-monetary, partial settlement with PNWS in which PNWS amended its original complaint to limit its claims for enforcement and/or damages to only four of the 21 power purchase agreements. As a result, the damages sought by the plaintiff was reduced to approximately $8.0 million for the alleged breach of the four power purchase agreements. We participated in an unsuccessful mediation on January 24, 2019 and subsequent settlement efforts also have been unsuccessful.
After reviewing briefs submitted by the parties addressing key liability issues in the case, on August 31, 2021, the Court ruled that the four agreements are valid and enforceable contracts and that NorthWestern breached the agreements on June 16, 2016 by refusing to go forward with the projects in view of the MPSC's Orders. The Court has scheduled a jury trial to determine damages to begin on December 13, 2021.
Although damages could be as high as approximately $8.0 million, we believe the damages are significantly less than that amount due to the very early stage of development when NorthWestern advised PNWS that it could not go forward with the four projects. We may appeal the trial court's liability determinations to the U.S. Court of Appeals for the Ninth Circuit after the jury trial on damages has been concluded.
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 2012, the United States Supreme Court issued a decision holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach “at least from the head of the first waterfall to the foot of the last” was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State’s Complaint was filed with the State District Court. 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). The State filed a motion to remand. Following briefing and argument, on October 10, 2017, the Federal District Court entered an order denying the State’s motion.
Because the State’s Complaint included a claim that the State owned the riverbeds in the Great Falls Reach, on October 16, 2017, we and Talen renewed our earlier-filed motions seeking to dismiss the portion of the State’s Complaint concerning the Great Falls Reach in light of the United States Supreme Court’s decision. On August 1, 2018, the Federal District Court granted the motions to dismiss the State’s Complaint as it pertains to approximately 8.2 miles of riverbed from “the head of the Black Eagle Falls to the foot of the Great Falls.” In particular, the dismissal pertained to the Black Eagle Dam, Rainbow Dam and reservoir, Cochrane Dam and reservoir, and Ryan Dam and reservoir. While the dismissal of these four facilities may be subject to appeal, that appeal would not likely occur until after judgment in the case. On February 12, 2019, the Federal District Court granted our motion to join the United States as a defendant to the litigation. As a result, on October 31, 2019, the State filed and served an Amended Complaint including the United States as a defendant and removing claims of ownership for the hydroelectric facilities on the Great Falls Reach, except for the Morony and the Black Eagle Developments. We and Talen filed answers to the Amended Complaint on December 13, 2019, and the United States answered on February 5, 2020. The Federal District Court reset the trial date on the issue of navigability to January 4, 2022. The parties have filed various motions, including motions in limine and for partial summary judgment. Those motions are currently in the process of being briefed. Damages were bifurcated by agreement and will be tried separately, should the Federal District Court find any segments navigable.
We dispute the State’s claims and intend 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 and Litigation
As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down those units no later than July 2022. In January 2020, the owners of Units 1 and 2 closed those two units. We do not have ownership in Units 1 and 2, and decisions regarding those units, including their shut down, were made by their respective owners. The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of an operating agreement among them, the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we have incurred additional operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines. We expect to incorporate any reduction in revenue in our next general electric rate filing, resulting in lower revenue credits to certain customers.
The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio. As a result of the Washington legislation, four of the six joint owners of Units 3 and 4 requested the operator prepare a 2021 budget reflecting closure of Units 3 and 4 by 2025, and alternately a closure of Unit 3 by 2025 and a closure of Unit 4 by 2027. Differing viewpoints on closure dates delayed approval of the 2021 budget, until it was approved on March 22, 2021. We anticipate the annual budgeting process for Units 3 and 4 may raise similar efforts to tie budgeting to a closure date, resulting in future budgets that may not be sufficient to maintain the reliability of Units 3 and 4.
While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure.
The Arbitration has given rise to three lawsuits concerning the number of arbitrators, the venue and the applicable arbitration laws. The four joint owners from the Pacific Northwest assert the Arbitration must be conducted under the O&O Agreement, with one arbitrator, in Spokane County, Washington, and pursuant to the Washington Arbitration Act. The fifth joint owner asserts the Arbitration must be conducted per the terms of Montana Senate Bill 265 (SB 265), which requires the Arbitration be conducted, with three arbitrators, in Montana and pursuant to the Montana Uniform Arbitration Act. The three initiated lawsuits do not make direct financial demands, and instead, are intended to address issues related to process for the Arbitration.
Since the Arbitration was initiated, and despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration.
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 the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.
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, Gross 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 Gross Margin as Operating Revenues less Cost of Sales as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Depreciation and depletion expenses, which are presented separate from Cost of Sales in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Gross Margin to Operating Revenues, the most directly comparable GAAP measure.
Management believes that Gross 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, Gross 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 Gross Margin measure may not be comparable to that of other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 743,000 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, 2020.
We are working to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We seek to deliver value to our customers by providing high reliability and customer service, and an environmentally sustainable generation mix at an affordable price. 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 distribution and substations that enables the use of changing technology.
•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.
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.
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 and nine months ended September 30, 2021 and 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2020 RESULTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, 2021 vs. 2020
|
|
|
Income Before Income Taxes
|
|
Income Tax (Expense) Benefit
|
|
Net Income
|
|
|
|
|
(in millions)
|
|
|
Third Quarter 2020
|
|
$
|
26.8
|
|
|
$
|
2.7
|
|
|
$
|
29.5
|
|
Items increasing (decreasing) net income:
|
|
|
|
|
|
|
Higher Montana electric transmission revenue
|
|
10.1
|
|
|
(2.6)
|
|
|
7.5
|
|
Higher electric retail volumes
|
|
8.4
|
|
|
(2.1)
|
|
|
6.3
|
|
Higher income tax expense
|
|
—
|
|
|
(2.1)
|
|
|
(2.1)
|
|
Higher operating, general, and administrative expenses impacting net income
|
|
(5.0)
|
|
|
1.3
|
|
|
(3.7)
|
|
|
|
|
|
|
|
|
Higher depreciation and depletion
|
|
(2.8)
|
|
|
0.7
|
|
|
(2.1)
|
|
Lower Montana electric supply cost recovery
|
|
(2.1)
|
|
|
0.5
|
|
|
(1.6)
|
|
Electric QF liability adjustment
|
|
(1.3)
|
|
|
0.3
|
|
|
(1.0)
|
|
Lower Montana natural gas volumes
|
|
(0.6)
|
|
|
0.2
|
|
|
(0.4)
|
|
Other
|
|
4.2
|
|
|
(1.4)
|
|
|
2.8
|
|
Third Quarter 2021
|
|
$
|
37.7
|
|
|
$
|
(2.5)
|
|
|
$
|
35.2
|
|
Change in Net Income
|
|
|
|
|
|
$
|
5.7
|
|
|
|
|
|
|
|
|
Consolidated net income for the three months ended September 30, 2021 was $35.2 million as compared with $29.5 million for the same period in 2020. This increase was primarily driven by higher Montana transmission loads and rates and warmer summer weather, partly offset by higher operating costs, lower supply cost recovery, an unfavorable QF liability adjustment compared with the prior period, and higher income tax expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SIGNIFICANT TRENDS AND REGULATION
|
Electric Resource Planning - Montana
We are currently 630 MW short of our peak needs and we cover the shortfall through market purchases. Absent resource additions, we forecast that our portfolio will be 725 MW short by 2025, considering expiring contracts and a modest increase in customer demand. We issued an all-source competitive solicitation request in January 2020 for up to 280 MWs of peaking and flexible capacity to be available for commercial operation in late 2023 or early 2024 (the January 2020 request for proposal (RFP)). Further, we expect to issue additional all-source competitive solicitation requests during 2022.
Initial bids for the January 2020 RFP were received in July 2020. A third-party RFP Administrator evaluated the bids
with the following portfolio of projects selected:
•Laurel Generating Station - the construction of a 175 MW natural gas-fired generation plant near Laurel, Montana, at a cost of approximately $275 million, including Allowance for Funds Used During Construction (AFUDC), which we will own;
•Beartooth Battery - A 20-year agreement to purchase capacity and ancillary services produced from a 50 MW battery energy storage facility that will be constructed in Yellowstone County, Montana; and
•Powerex Transaction - a 5-year power purchase agreement for 100 MWs of capacity and energy products originating predominately from hydroelectric resources.
On May 19, 2021, we filed an application with the MPSC for advanced approval to acquire the Laurel Generating Station and Beartooth Battery agreement as new capacity resources. These resources, together with the Powerex Transaction, will help address our identified capacity shortage. The Powerex Transaction, was not included in the application for advanced approval filed with the MPSC. Recent upheaval in the construction market and, specifically, timely availability of critical components and escalating labor and construction costs, has necessitated the flexibility to expend capital and make commercial decisions in
advance of the timeline established by the MPSC advanced approval docket. Accordingly, we withdrew our application on September 23, 2021 and intend to seek approval from the MPSC to place the Laurel Generating Station in rate base through a future filing. We currently intend to file a separate application for advanced approval of the Beartooth Battery agreement.
On October 21, 2021 the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality (MTDEQ) and us, alleging the environmental review of our Laurel Generating Station project was unlawful. This lawsuit could delay the Laurel project if the Court were to require a full Environmental Impact Study regarding the project, set aside the air quality permit granted for the Laurel Generating Station, or determine that the underlying environmental statute violates the Montana Constitutional guarantee of a “clean and healthful environment.”
Electric Resource Supply - South Dakota
Our energy resource plans identify portfolio requirements including potential investments resulting from a completed competitive solicitation process in South Dakota. Our estimated capital expenditures discussed in our Annual Report on Form 10-K for the year ended December 31, 2020 within the Management's Discussion and Analysis of Financial Condition and Results of Operations section includes approximately $60 million for a 30-40 MW flexible natural gas plant near Aberdeen, South Dakota, which was expected to be in service in early 2024. During the third quarter of 2021, we decided to discontinue our plans to build this project as a result of significant increases in estimated construction cost as a result of global supply chain challenges. As a result of the project discontinuance, we recorded a $1.2 million pre-tax charge in the three months ended September 30, 2021, for the write-off of preliminary construction costs.
Construction continues for a 60 MW reciprocating internal combustion engine project in Huron, South Dakota. The project is expect to be online in early 2022 with total construction costs of approximately $80 million (approximately $40 million invested in 2020).
Regulatory Update
We will not make a general rate case filing in any of our regulatory jurisdictions during 2021. We have recently filed several other regulatory filings, primarily in our Montana jurisdiction, including:
•An April 15, 2021 filing of a motion requesting to delay the implementation of our fixed cost recovery mechanism pilot in our Montana jurisdiction for another year until July 2022 or beyond, due to the continued uncertainties created by the COVID-19 pandemic. On June 29, 2021, the MPSC granted our motion and issued a final order denying reconsideration on September 15, 2021; and
•An April 21, 2021 filing requesting approval to increase the PCCAM Base forecasted costs used to develop rates for the recovery of electric power costs through our PCCAM by approximately $17 million, or potentially a greater increase to reflect current market prices and new capacity contracts. On June 29, 2021, the MPSC approved implementing our request for interim rates reflecting the $17 million increase, subject to refund. The MCC filed a motion arguing that the PCCAM Base cannot be updated except in a general rate case and asked the MPSC to dismiss the application. On October 5, 2021, the MPSC voted to grant the MCC’s motion to dismiss, and we await the final written order.
We are subject to FERC’s jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things. The Division of Audits and Accounting in the Office of Enforcement of FERC has initiated a routine audit of NorthWestern Corporation for the period of January 1, 2018 to the present to evaluate our compliance with FERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received from FERC, but is expected within the next six months. Management is unable to predict the outcome or timing of the final resolution of the audit.
February Cold Weather Event
The February 2021 prolonged cold spell resulted in record winter peak demand for electricity and natural gas. The broad reach of this event across the United States and other market factors resulted in an extreme price excursion for purchased power and natural gas. In our South Dakota and Nebraska service territories, natural gas costs for the month of February 2021 exceeded the total cost for all of 2020. Fuel and purchased power costs in these jurisdictions are recovered through fuel adjustment clauses. We’ve incorporated the liquidity impacts into our overall 2021 financing plans.
The Nebraska Public Service Commission (NPSC) opened a docket on March 2, 2021 to investigate the effect of this cold weather event on natural gas supply. In this docket, we proposed recovery of our costs for February 13, 2021 to February 18,
2021 over a two-year period, which was subsequently approved by the NPSC on May 11, 2021, and a regulatory asset of approximately $26.0 million was recorded for these costs, with a remaining balance of $25.2 million as of September 30, 2021.
The South Dakota Public Utilities Commission issued an order allowing recovery of natural gas costs for the same time period over a one-year period, effective March 2, 2021. A regulatory asset of approximately $22.0 million was recorded for these costs, with a remaining balance of $17.7 million as of September 30, 2021.
COVID-19 Pandemic and Global Economic Recovery
The COVID-19 pandemic has had widespread impacts on people, economies, businesses and financial markets. Beginning in March 2020, the pandemic and resulting economic conditions began impacting our business operations and financial results. Our 2020 financial results were impacted by lower sales volumes, an increase in reserves for uncollectible accounts and an increase in interest expense, partly offset by lower operating, general and administrative expenses. We have experienced improving conditions in our service territories during 2021, that have positively impacted our business as compared to 2020. The ultimate impact of the pandemic on our financial results for 2021 and beyond depends on the evolving landscape of the pandemic and the public health responses to contain it, as well as the substance and pace of the macroeconomic recovery. If health conditions deteriorate or the economic recovery stalls, it could have the result of lower demand for electricity and natural gas, as well as reduced ability of various customers, contractors, suppliers and other business partners to fulfill their obligations or provide the services we seek to support our business operations. These impacts could have a material adverse effect on our results of operations, financial condition and prospects. In addition, the Biden administration is seeking to require large companies like us to have all of our employees vaccinated or undergo weekly COVID testing. Complying with either a vaccine mandate or weekly testing requirements (if there are even enough testing kits available) could be difficult and costly and it is possible that some employees may choose to leave employment over a vaccine or testing requirement.
We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases. Should these economic conditions and issues continue, we could have difficulty completing the operations activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations.
Financing Activities
We anticipate financing our ongoing maintenance and capital programs with a combination of cash flows from operations,
first mortgage bonds and equity issuances.
In March 2021, we issued and sold $100.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 1.00% maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100.0 million one-year term loan that was due April 2, 2021.
In April 2021, we entered into an Equity Distribution Agreement pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an ATM program, including an equity forward sales component. During the three months ended September 30, 2021, we issued 1,040,085 shares of our common stock at an average price of $63.13, for net proceeds of $64.8 million. During the nine months ended September 30, 2021, we issued 1,919,394 shares of our common stock at an average price of $63.94, for net proceeds of $121.1 million. We expect a total of approximately $200.0 million of equity proceeds during 2021 to support our current capital program and maintain and protect our credit ratings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
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 gross margin by segment.
Factors Affecting Results of Operations
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. 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.
OVERALL CONSOLIDATED RESULTS
Three Months Ended September 30, 2021 Compared with the Three Months Ended September 30, 2020
Consolidated net income for the three months ended September 30, 2021 was $35.2 million as compared with $29.5 million for the same period in 2020. This increase was primarily driven by higher Montana transmission loads and rates and warmer summer weather, partly offset by higher operating costs, higher Montana electric supply costs, an unfavorable QF liability adjustment compared with the prior period, and higher income tax expense.
Consolidated operating revenues for the three months ended September 30, 2021 were $326.0 million as compared with $280.7 million for the same period in 2020. Consolidated gross margin for the three months ended September 30, 2021 was $227.3 million as compared with $212.6 million for the same period in 2020, an increase of $14.7 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
Natural Gas
|
|
Total
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(dollars in millions)
|
Reconciliation of operating revenue to gross margin:
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
$
|
287.5
|
|
|
$
|
244.2
|
|
|
$
|
38.5
|
|
|
$
|
36.5
|
|
|
$
|
326.0
|
|
|
$
|
280.7
|
|
Cost of Sales
|
89.4
|
|
|
61.2
|
|
|
9.3
|
|
|
6.9
|
|
|
98.7
|
|
|
68.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
198.1
|
|
|
$
|
183.0
|
|
|
$
|
29.2
|
|
|
$
|
29.6
|
|
|
$
|
227.3
|
|
|
$
|
212.6
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
2021
|
|
2020
|
|
Change
|
|
% Change
|
|
(dollars in millions)
|
Gross Margin
|
|
|
|
|
|
|
|
Electric
|
$
|
198.1
|
|
|
$
|
183.0
|
|
|
$
|
15.1
|
|
|
8.3
|
%
|
Natural Gas
|
29.2
|
|
|
29.6
|
|
|
(0.4)
|
|
|
(1.4)
|
|
|
|
|
|
|
|
|
|
Total Gross Margin(1)
|
$
|
227.3
|
|
|
$
|
212.6
|
|
|
$
|
14.7
|
|
|
6.9
|
%
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Primary components of the change in gross margin include the following (in millions):
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
Gross Margin Items Impacting Net Income
|
|
Montana electric transmission revenue
|
$
|
10.1
|
|
Electric retail volumes
|
8.4
|
|
Montana electric supply cost recovery
|
(2.1)
|
|
Electric QF liability adjustment
|
(1.3)
|
|
Natural gas retail volumes
|
(0.6)
|
|
|
|
Other
|
0.4
|
|
Change in Gross Margin Impacting Net Income
|
14.9
|
|
Gross Margin Items Offset Within Net Income
|
|
Property taxes recovered in revenue, offset in property tax expense
|
(1.3)
|
|
Gas production taxes recovered in revenue, offset in property and other taxes
|
0.2
|
|
Operating expenses recovered in revenue, offset in operating expense
|
0.3
|
|
Production tax credits reducing revenue, offset in income tax expense
|
0.6
|
|
Change in Gross Margin Items Offset Within Net Income
|
(0.2)
|
|
Increase in Consolidated Gross Margin(1)
|
$
|
14.7
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated gross margin increased $14.7 million, including a $14.9 million increase from items impacting net income and a $0.2 million decrease from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•Higher Montana transmission rates and higher demand to transmit energy across our transmission lines due to market conditions and pricing;
•An increase in electric retail revenue due to warmer summer weather, overall customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns;
•Higher Montana electric supply costs as compared with the prior period;
•An unfavorable adjustment to our electric QF liability (unrecoverable costs associated with Public Utility Regulatory Policies Act of 1978 (PURPA) contracts as part of a 2002 stipulation with the MPSC and other parties) associated with a one-time clarification in contract term; and
•A decrease in gas volumes due to warmer summer weather, partly offset by customer growth.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
2021
|
|
2020
|
|
Change
|
|
% Change
|
|
(dollars in millions)
|
Operating Expenses (excluding cost of sales)
|
|
|
|
|
|
|
|
Operating, general and administrative
|
$
|
80.9
|
|
|
$
|
73.3
|
|
|
$
|
7.6
|
|
|
10.4
|
%
|
Property and other taxes
|
43.6
|
|
|
45.3
|
|
|
(1.7)
|
|
|
(3.8)
|
|
Depreciation and depletion
|
47.1
|
|
|
44.3
|
|
|
2.8
|
|
|
6.3
|
|
|
$
|
171.6
|
|
|
$
|
162.9
|
|
|
$
|
8.7
|
|
|
5.3
|
%
|
Consolidated operating, general and administrative expenses were $80.9 million for the three months ended September 30, 2021, as compared with $73.3 million for the three months ended September 30, 2020. Primary components of the change include the following (in millions):
|
|
|
|
|
|
|
Operating, General & Administrative Expenses
|
|
2021 vs. 2020
|
Operating, General & Administrative Expenses Impacting Net Income
|
|
Employee benefits
|
$
|
3.3
|
|
Technology implementation and maintenance
|
1.8
|
|
Generation maintenance
|
1.3
|
|
Write-off of preliminary construction costs
|
1.2
|
|
Travel and training
|
0.4
|
|
Uncollectible accounts
|
(2.7)
|
|
Other
|
(0.3)
|
|
Change in Items Impacting Net Income
|
5.0
|
|
|
|
Operating, General & Administrative Expenses Offset Within Net Income
|
|
Pension and other postretirement benefits, offset in other income
|
1.2
|
|
Non-employee directors deferred compensation, offset in other income
|
1.1
|
|
Operating expenses recovered in trackers, offset in revenue
|
0.3
|
|
Change in Operating, General & Administrative Expense Items Offset Within Net Income
|
2.6
|
|
Increase in Operating, General & Administrative Expenses
|
$
|
7.6
|
|
Consolidated operating, general and administrative expenses increased $7.6 million, including a $5.0 million increase from items impacting net income and a $2.6 million increase from items offset within net income.
The change in consolidated operating, general and administrative expenses for items impacting net income includes the following:
•Higher employee benefit costs primarily due to higher compensation and medical costs;
•Higher technology implementation and maintenance costs;
•Higher maintenance costs at our electric generation facilities;
•Higher costs due to the write-off of preliminary construction costs associated with the 30-40MW flexible natural gas plant near Aberdeen, South Dakota;
•Higher travel and training costs; and
•Decreased uncollectible accounts due to collections of previously written off amounts in the current period. In the second quarter of 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic. We subsequently resumed standard disconnection processes in all of our operating jurisdictions in the third quarter of 2020.
Property and other taxes were $43.6 million for the three months ended September 30, 2021, as compared with $45.3 million in the same period of 2020. This decrease was due primarily to a decrease in estimated Montana state and local taxes. 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 in the actual level of state and local taxes and fees and adjust our rates to recover the increase between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Depreciation and depletion expense was $47.1 million for the three months ended September 30, 2021, as compared with $44.3 million in the same period of 2020. This increase was primarily due to plant additions.
Consolidated operating income for the three months ended September 30, 2021 was $55.7 million as compared with $49.7 million in the same period of 2020. This increase was primarily driven by higher Montana transmission loads and rates and
warmer summer weather, partly offset by higher operating costs, higher Montana electric supply costs, and an unfavorable QF liability adjustment compared with the prior period.
Consolidated interest expense was $23.3 million for the three months ended September 30, 2021 as compared with $23.7 million for the same period of 2020. This decrease was primarily due to higher capitalization of AFUDC, partly offset by higher borrowings.
Consolidated other income was $5.3 million for the three months ended September 30, 2021 as compared to $0.8 million during the same period of 2020. This increase includes approximately $2.3 million related to items offset in operating, general and administrative expense with no impact to net income, and higher capitalization of AFUDC. Items offset in operating, general and administrative expense includes an approximately $1.1 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation and a decrease in other pension expense of $1.2 million.
Consolidated income tax expense for the three months ended September 30, 2021 was $2.5 million as compared to an income tax benefit of $2.7 million in the same period of 2020. Our effective tax rate for the three months ended September 30, 2021 was 6.6% as compared with (10.1)% for the same period in 2020. We expect our effective tax rate to range between (2.5)% to 2.5% in 2021.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
2021
|
|
2020
|
Income Before Income Taxes
|
$
|
37.7
|
|
|
|
|
$
|
26.8
|
|
|
|
|
|
|
|
|
|
|
|
Income tax calculated at federal statutory rate
|
7.9
|
|
|
21.0
|
%
|
|
5.6
|
|
|
21.0
|
%
|
|
|
|
|
|
|
|
|
Permanent or flow-through adjustments:
|
|
|
|
|
|
|
|
State income tax, net of federal provisions
|
0.4
|
|
|
1.1
|
|
|
0.0
|
|
|
0.2
|
|
Flow-through repairs deductions
|
(3.5)
|
|
|
(9.2)
|
|
|
(4.2)
|
|
|
(15.7)
|
|
Production tax credits
|
(1.9)
|
|
|
(5.0)
|
|
|
(2.2)
|
|
|
(8.2)
|
|
Plant and depreciation of flow-through items
|
(0.3)
|
|
|
(0.8)
|
|
|
0.1
|
|
|
0.4
|
|
Amortization of excess deferred income tax
|
(0.1)
|
|
|
(0.3)
|
|
|
(0.2)
|
|
|
(0.8)
|
|
Share-based compensation
|
(0.1)
|
|
|
(0.2)
|
|
|
—
|
|
|
—
|
|
Income tax return to accrual adjustment
|
0.4
|
|
|
1.0
|
|
|
(1.7)
|
|
|
(6.5)
|
|
Other, net
|
(0.3)
|
|
|
(1.0)
|
|
|
(0.1)
|
|
|
(0.5)
|
|
|
(5.4)
|
|
|
(14.4)
|
|
|
(8.3)
|
|
|
(31.1)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
$
|
2.5
|
|
|
6.6
|
%
|
|
$
|
(2.7)
|
|
|
(10.1)
|
%
|
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.
Nine Months Ended September 30, 2021 Compared with the Nine Months Ended September 30, 2020
Consolidated net income for the nine months ended September 30, 2021 was $135.5 million as compared with $101.7 million for the same period in 2020. This increase was primarily driven by higher Montana transmission loads and rates, a favorable electric QF liability adjustment as compared with the prior period, favorable weather, and higher commercial demand as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by higher Montana electric supply costs, higher operating costs, depreciation expense, and income tax expense.
Consolidated operating revenues for the nine months ended September 30, 2021 were $1,025.0 million as compared with $885.2 million for the same period in 2020. Consolidated gross margin for the nine months ended September 30, 2021 was $713.8 million as compared with $664.8 million for the same period in 2020, an increase of $49.0 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
Natural Gas
|
|
Total
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(dollars in millions)
|
Reconciliation of operating revenue to gross margin:
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
$
|
799.0
|
|
|
$
|
706.7
|
|
|
$
|
226.0
|
|
|
$
|
178.5
|
|
|
$
|
1,025.0
|
|
|
$
|
885.2
|
|
Cost of Sales
|
218.8
|
|
|
173.3
|
|
|
92.4
|
|
|
47.1
|
|
|
311.2
|
|
|
220.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
580.2
|
|
|
$
|
533.4
|
|
|
$
|
133.6
|
|
|
$
|
131.4
|
|
|
$
|
713.8
|
|
|
$
|
664.8
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
Change
|
|
% Change
|
|
(dollars in millions)
|
Gross Margin
|
|
|
|
|
|
|
|
Electric
|
$
|
580.2
|
|
|
$
|
533.4
|
|
|
$
|
46.8
|
|
|
8.8
|
%
|
Natural Gas
|
133.6
|
|
|
131.4
|
|
|
2.2
|
|
|
1.7
|
|
|
|
|
|
|
|
|
|
Total Gross Margin(1)
|
$
|
713.8
|
|
|
$
|
664.8
|
|
|
$
|
49.0
|
|
|
7.4
|
%
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Primary components of the change in gross margin include the following (in millions):
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
Gross Margin Items Impacting Net Income
|
|
Montana electric transmission revenue
|
$
|
21.3
|
|
Electric retail volumes
|
18.1
|
|
Electric QF liability adjustment
|
4.8
|
|
Natural gas retail volumes
|
1.7
|
|
Montana electric supply cost recovery
|
(4.3)
|
|
Montana natural gas production rates
|
(0.8)
|
|
Other
|
4.3
|
|
Change in Gross Margin Impacting Net Income
|
45.1
|
|
Gross Margin Items Offset Within Net Income
|
|
Production tax credits reducing revenue, offset in income tax expense
|
2.2
|
|
Property taxes recovered in revenue, offset in property tax expense
|
1.0
|
|
Gas production taxes recovered in revenue, offset in property and other taxes
|
0.4
|
|
Operating expenses recovered in revenue, offset in operating expense
|
0.3
|
|
Change in Gross Margin Items Offset Within Net Income
|
3.9
|
|
Increase in Consolidated Gross Margin(1)
|
$
|
49.0
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Consolidated gross margin increased $49.0 million, including a $45.1 million increase from items impacting net income and a $3.9 million increase from items offset within net income.
The change in consolidated gross margin for items impacting net income includes the following:
•Higher Montana transmission rates, the recognition of approximately $4.7 million of deferred interim revenues, and higher demand to transmit energy across our transmission lines due to market conditions and pricing;
•An increase in electric retail revenue driven by colder winter weather in Montana, warmer summer weather in both Montana and South Dakota, customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer winter weather in South Dakota;
•A more favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflecting a $7.9 million gain in 2021, as compared with a $3.1 million gain for the same period in 2020, due to the combination of:
•A $2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $0.9 million favorable reduction in costs in the prior period;
•A negative adjustment, increasing the QF liability by $2.1 million, reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of $2.2 million in the prior year due to lower actual price escalation; and
•A favorable adjustment of approximately $7.4 million decreasing the QF liability associated with a one-time clarification in contract term.
•An increase in natural gas volumes due to colder winter weather in our Montana and Nebraska jurisdictions and customer growth, partly offset by warmer winter weather in our South Dakota jurisdiction and warmer summer weather in all jurisdictions;
•Higher Montana electric supply costs as compared with the prior period; and
•A reduction of rates from the step down of our Montana gas production assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
|
Change
|
|
% Change
|
|
(dollars in millions)
|
Operating Expenses (excluding cost of sales)
|
|
|
|
|
|
|
|
Operating, general and administrative
|
$
|
238.9
|
|
|
$
|
224.0
|
|
|
$
|
14.9
|
|
|
6.7
|
%
|
Property and other taxes
|
138.3
|
|
|
136.8
|
|
|
1.5
|
|
|
1.1
|
|
Depreciation and depletion
|
140.9
|
|
|
134.3
|
|
|
6.6
|
|
|
4.9
|
|
|
$
|
518.1
|
|
|
$
|
495.1
|
|
|
$
|
23.0
|
|
|
4.6
|
%
|
Consolidated operating, general and administrative expenses were $238.9 million for the nine months ended September 30, 2021, as compared with $224.0 million for the nine months ended September 30, 2020. Primary components of the change include the following (in millions):
|
|
|
|
|
|
|
Operating, General & Administrative Expenses
|
|
2021 vs. 2020
|
Operating, General & Administrative Expenses Impacting Net Income
|
|
Employee benefits
|
$
|
4.7
|
|
Generation maintenance
|
3.0
|
|
Technology implementation and maintenance
|
2.4
|
|
Write-off of preliminary construction costs
|
1.2
|
|
Uncollectible accounts
|
(7.1)
|
|
Other
|
0.4
|
|
Change in Items Impacting Net Income
|
4.6
|
|
|
|
Operating, General & Administrative Expenses Offset Within Net Income
|
|
Non-employee directors deferred compensation, offset in other income
|
6.4
|
|
Pension and other postretirement benefits, offset in other income
|
3.6
|
|
Operating expenses recovered in trackers, offset in revenue
|
0.3
|
|
Change in Operating, General & Administrative Expense Items Offset Within Net Income
|
10.3
|
|
Increase in Operating, General & Administrative Expenses
|
$
|
14.9
|
|
Consolidated operating, general and administrative expenses increased $14.9 million, including a $4.6 million increase from items impacting net income and a $10.3 million increase from items offset within net income.
The change in consolidated operating, general and administrative expenses for items impacting net income includes the following:
•Higher employee benefit costs primarily due to higher compensation and medical costs;
•Higher maintenance costs at our electric generation facilities;
•Higher technology implementation and maintenance costs;
•Higher costs due to the write-off of preliminary construction costs associated with the 30-40MW flexible natural gas plant near Aberdeen, South Dakota; and
•Decreased uncollectible accounts due to collections of previously written off amounts in the current period. In the second quarter of 2020, we voluntarily suspended service disconnections for non-payment, to help customers who may be financially impacted by the COVID-19 pandemic.
Property and other taxes were $138.3 million for the nine months ended September 30, 2021, as compared with $136.8 million in the same period of 2020. This increase was due primarily to an increase in Montana state and local taxes. 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 in the actual level of state and local taxes and fees and adjust our rates to recover the increase between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.
Depreciation and depletion expense was $140.9 million for the nine months ended September 30, 2021, as compared with $134.3 million in the same period of 2020. This increase was primarily due to plant additions.
Consolidated operating income for the nine months ended September 30, 2021 was $195.7 million as compared with $169.7 million in the same period of 2020. This increase was primarily driven by higher Montana transmission loads and rates, a favorable electric QF liability adjustment as compared with the prior period, favorable weather, and higher commercial demand as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by higher Montana electric supply costs, higher operating costs, and depreciation expense.
Consolidated interest expense was $70.3 million for the nine months ended September 30, 2021 as compared with $72.3 million for the same period of 2020. This decrease was primarily due to higher capitalization of AFUDC, partly offset by higher borrowings.
Consolidated other income was $13.9 million for the nine months ended September 30, 2021 as compared to consolidated other expense of $1.0 million during the same period of 2020. This increase includes approximately $10.0 million related to items offset in operating, general and administrative expense with no impact to net income and higher capitalization of AFUDC. Items offset in operating, general and administrative expense include a $6.4 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation and a decrease in other pension expense of $3.6 million.
Consolidated income tax expense for the nine months ended September 30, 2021 was $3.9 million as compared to an income tax benefit of $5.2 million in the same period of 2020. Our effective tax rate for the nine months ended September 30, 2021 was 2.8% as compared with (5.4)% for the same period in 2020. We expect our effective tax rate to range between (2.5)% to 2.5% in 2021.
The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
Income Before Income Taxes
|
$
|
139.4
|
|
|
|
|
$
|
96.4
|
|
|
|
|
|
|
|
|
|
|
|
Income tax calculated at federal statutory rate
|
29.3
|
|
|
21.0
|
%
|
|
20.3
|
|
|
21.0
|
%
|
|
|
|
|
|
|
|
|
Permanent or flow-through adjustments:
|
|
|
|
|
|
|
|
State income tax, net of federal provisions
|
0.7
|
|
|
0.5
|
|
|
0.1
|
|
|
0.1
|
|
Flow-through repairs deductions
|
(15.6)
|
|
|
(11.2)
|
|
|
(14.9)
|
|
|
(15.4)
|
|
Production tax credits
|
(8.4)
|
|
|
(6.1)
|
|
|
(7.6)
|
|
|
(7.8)
|
|
Plant and depreciation of flow-through items
|
(0.8)
|
|
|
(0.6)
|
|
|
0.3
|
|
|
0.3
|
|
Amortization of excess deferred income tax
|
(0.6)
|
|
|
(0.4)
|
|
|
(0.7)
|
|
|
(0.8)
|
|
Share-based compensation
|
(0.3)
|
|
|
(0.2)
|
|
|
(0.6)
|
|
|
(0.6)
|
|
Income tax return to accrual adjustment
|
0.4
|
|
|
0.3
|
|
|
(1.7)
|
|
|
(1.8)
|
|
Other, net
|
(0.8)
|
|
|
(0.5)
|
|
|
(0.4)
|
|
|
(0.4)
|
|
|
(25.4)
|
|
|
(18.2)
|
|
|
(25.5)
|
|
|
(26.4)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit)
|
$
|
3.9
|
|
|
2.8
|
%
|
|
$
|
(5.2)
|
|
|
(5.4)
|
%
|
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.
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
cost of sales and therefore has minimal impact on gross margin. The amortization of these amounts are offset in retail
revenue.
•Transmission: Reflects transmission revenues regulated by the FERC.
•Wholesale and other are largely gross margin neutral as they are offset by changes in cost of sales.
Three Months Ended September 30, 2021 Compared with the Three Months Ended September 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
Change
|
|
Megawatt Hours (MWH)
|
|
Avg. Customer Counts
|
|
2021
|
|
2020
|
|
$
|
|
%
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(in thousands)
|
|
|
|
|
Montana
|
$
|
85,539
|
|
|
$
|
78,549
|
|
|
$
|
6,990
|
|
|
8.9
|
%
|
|
692
|
|
|
633
|
|
|
312,265
|
|
|
307,892
|
|
South Dakota
|
18,882
|
|
|
18,912
|
|
|
(30)
|
|
|
(0.2)
|
|
|
158
|
|
|
160
|
|
|
50,756
|
|
|
50,584
|
|
Residential
|
104,421
|
|
|
97,461
|
|
|
6,960
|
|
|
7.1
|
|
|
850
|
|
|
793
|
|
|
363,021
|
|
|
358,476
|
|
Montana
|
95,248
|
|
|
89,082
|
|
|
6,166
|
|
|
6.9
|
|
|
847
|
|
|
794
|
|
|
71,766
|
|
|
70,320
|
|
South Dakota
|
28,798
|
|
|
27,373
|
|
|
1,425
|
|
|
5.2
|
|
|
296
|
|
|
284
|
|
|
12,835
|
|
|
12,870
|
|
Commercial
|
124,046
|
|
|
116,455
|
|
|
7,591
|
|
|
6.5
|
|
|
1,143
|
|
|
1,078
|
|
|
84,601
|
|
|
83,190
|
|
Industrial
|
9,147
|
|
|
9,212
|
|
|
(65)
|
|
|
(0.7)
|
|
|
611
|
|
|
621
|
|
|
76
|
|
|
78
|
|
Other
|
13,089
|
|
|
11,910
|
|
|
1,179
|
|
|
9.9
|
|
|
89
|
|
|
86
|
|
|
8,226
|
|
|
8,193
|
|
Total Retail Electric
|
$
|
250,703
|
|
|
$
|
235,038
|
|
|
$
|
15,665
|
|
|
6.7
|
%
|
|
2,693
|
|
|
2,578
|
|
|
455,924
|
|
|
449,937
|
|
Regulatory amortization
|
9,922
|
|
|
(5,526)
|
|
|
15,448
|
|
|
(279.6)
|
|
|
|
|
|
|
|
|
|
Transmission
|
25,172
|
|
|
12,906
|
|
|
12,266
|
|
|
95.0
|
|
|
|
|
|
|
|
|
|
Wholesale and Other
|
1,676
|
|
|
1,737
|
|
|
(61)
|
|
|
(3.5)
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
287,473
|
|
|
$
|
244,155
|
|
|
$
|
43,318
|
|
|
17.7
|
%
|
|
|
|
|
|
|
|
|
Total Cost of Sales
|
89,375
|
|
|
61,154
|
|
|
28,221
|
|
|
46.1
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
198,098
|
|
|
$
|
183,001
|
|
|
$
|
15,097
|
|
|
8.2
|
%
|
|
|
|
|
|
|
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling Degree Days
|
|
2021 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
493
|
|
340
|
|
361
|
|
45% warmer
|
|
37% warmer
|
South Dakota
|
818
|
|
755
|
|
638
|
|
8% warmer
|
|
28% warmer
|
|
Heating Degree Days
|
|
2021 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
251
|
|
255
|
|
278
|
|
2% warmer
|
|
10% warmer
|
South Dakota
|
23
|
|
71
|
|
87
|
|
68% warmer
|
|
74% warmer
|
The following summarizes the components of the changes in electric gross margin for the three months ended September 30, 2021 and 2020 (in millions):
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
Gross Margin Items Impacting Net Income
|
|
Transmission
|
$
|
10.1
|
|
Retail volumes
|
8.4
|
|
Montana electric supply cost recovery
|
(2.1)
|
|
Electric QF liability adjustment
|
(1.3)
|
|
|
|
Change in Gross Margin Impacting Net Income
|
15.1
|
|
|
|
Gross Margin Items Offset Within Net Income
|
|
Production tax credits reducing revenue, offset in income tax expense
|
0.6
|
|
Operating expenses recovered in revenue, offset in operating expense
|
0.4
|
|
Property taxes recovered in revenue, offset in property tax expense
|
(1.0)
|
|
Change in Gross Margin Items Offset Within Net Income
|
0.0
|
|
Increase in Gross Margin(1)
|
$
|
15.1
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Gross margin increased $15.1 million, with items offset within net income offsetting for no impact on gross margin.
The change in gross margin for items impacting net income includes the following:
•Higher Montana transmission rates and higher demand to transmit energy across our transmission lines due to market conditions and pricing;
•An increase in retail revenue due to warmer summer weather, overall customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns;
•Higher Montana electric supply costs as compared with the prior period; and
•An unfavorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) associated with a one-time clarification in contract term.
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 gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
Nine Months Ended September 30, 2021 Compared with the Nine Months Ended September 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
Change
|
|
Megawatt Hours (MWH)
|
|
Avg. Customer Counts
|
|
2021
|
|
2020
|
|
$
|
|
%
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(in thousands)
|
|
|
|
|
Montana
|
$
|
251,443
|
|
|
$
|
237,777
|
|
|
$
|
13,666
|
|
|
5.7
|
%
|
|
2,067
|
|
|
1,944
|
|
|
311,256
|
|
|
306,886
|
|
South Dakota
|
51,031
|
|
|
52,427
|
|
|
(1,396)
|
|
|
(2.7)
|
|
|
453
|
|
|
463
|
|
|
50,765
|
|
|
50,629
|
|
Residential
|
302,474
|
|
|
290,204
|
|
|
12,270
|
|
|
4.2
|
|
|
2,520
|
|
|
2,407
|
|
|
362,021
|
|
|
357,515
|
|
Montana
|
266,644
|
|
|
252,514
|
|
|
14,130
|
|
|
5.6
|
|
|
2,398
|
|
|
2,269
|
|
|
71,437
|
|
|
69,949
|
|
South Dakota
|
76,969
|
|
|
77,057
|
|
|
(88)
|
|
|
(0.1)
|
|
|
826
|
|
|
818
|
|
|
12,787
|
|
|
12,812
|
|
Commercial
|
343,613
|
|
|
329,571
|
|
|
14,042
|
|
|
4.3
|
|
|
3,224
|
|
|
3,087
|
|
|
84,224
|
|
|
82,761
|
|
Industrial
|
28,086
|
|
|
27,162
|
|
|
924
|
|
|
3.4
|
|
|
1,842
|
|
|
2,026
|
|
|
77
|
|
|
78
|
|
Other
|
26,798
|
|
|
26,400
|
|
|
398
|
|
|
1.5
|
|
|
155
|
|
|
157
|
|
|
6,449
|
|
|
6,467
|
|
Total Retail Electric
|
$
|
700,971
|
|
|
$
|
673,337
|
|
|
$
|
27,634
|
|
|
4.1
|
%
|
|
7,741
|
|
|
7,677
|
|
|
452,771
|
|
|
446,821
|
|
Regulatory amortization
|
29,913
|
|
|
(9,274)
|
|
|
39,187
|
|
|
(422.5)
|
|
|
|
|
|
|
|
|
|
Transmission
|
63,762
|
|
|
38,409
|
|
|
25,353
|
|
|
66.0
|
|
|
|
|
|
|
|
|
|
Wholesale and Other
|
4,338
|
|
|
4,246
|
|
|
92
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
798,984
|
|
|
$
|
706,718
|
|
|
$
|
92,266
|
|
|
13.1
|
%
|
|
|
|
|
|
|
|
|
Total Cost of Sales
|
218,802
|
|
|
173,294
|
|
|
45,508
|
|
|
26.3
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
580,182
|
|
|
$
|
533,424
|
|
|
$
|
46,758
|
|
|
8.8
|
%
|
|
|
|
|
|
|
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cooling Degree Days
|
|
2020 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
632
|
|
395
|
|
416
|
|
60% warmer
|
|
52% warmer
|
South Dakota
|
966
|
|
844
|
|
699
|
|
14% warmer
|
|
38% warmer
|
|
Heating Degree Days
|
|
2021 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
4,680
|
|
4,610
|
|
4,725
|
|
2% cooler
|
|
1% warmer
|
South Dakota
|
5,188
|
|
5,564
|
|
5,648
|
|
7% warmer
|
|
8% warmer
|
The following summarizes the components of the changes in electric gross margin for the nine months ended September 30, 2021 and 2020 (in millions):
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
Gross Margin Items Impacting Net Income
|
|
Transmission
|
$
|
21.3
|
|
Retail volumes
|
18.1
|
|
Electric QF liability adjustment
|
4.8
|
|
Montana electric supply cost recovery
|
(4.3)
|
|
Other
|
3.2
|
|
Change in Gross Margin Impacting Net Income
|
43.1
|
|
|
|
Gross Margin Items Offset Within Net Income
|
|
Production tax credits reducing revenue, offset in income tax expense
|
2.2
|
|
Property taxes recovered in revenue, offset in property tax expense
|
0.8
|
|
Operating expenses recovered in revenue, offset in operating expense
|
0.7
|
|
Change in Gross Margin Items Offset Within Net Income
|
3.7
|
|
Increase in Gross Margin(1)
|
$
|
46.8
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Gross margin increased $46.8 million, including a $43.1 million increase from items impacting net income and a $3.7 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•Higher Montana transmission rates, the recognition of approximately $4.7 million of deferred interim revenues, and higher demand to transmit energy across our transmission lines due to market conditions and pricing;
•An increase in retail revenue driven by colder winter weather in Montana, warmer summer weather in both Montana and South Dakota, customer growth, and increased commercial volume as compared to the prior year due to the COVID-19 pandemic related shutdowns, partly offset by warmer winter weather in South Dakota;
•A more favorable adjustment of our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflecting a $7.9 million gain in 2021, as compared with a $3.1 million gain for the same period in 2020, due to the combination of:
•A $2.6 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $0.9 million favorable reduction in costs in the prior period;
•A negative adjustment, increasing the QF liability by $2.1 million, reflecting annual actual contract price escalation, which was more than previously estimated, compared to a favorable adjustment of $2.2 million in the prior year due to lower actual price escalation; and
•A favorable adjustment of approximately $7.4 million decreasing the QF liability associated with a one-time clarification in contract term.
•Higher Montana electric supply costs as compared with the prior period.
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 gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
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 cost of sales and therefore has minimal impact on gross margin. The amortization of these amounts are
offset in retail revenue.
•Wholesale: Primarily represents transportation and storage for others.
Three Months Ended September 30, 2021 Compared with the Three Months Ended September 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
Change
|
|
Dekatherms (Dkt)
|
|
Avg. Customer Counts
|
|
2021
|
|
2020
|
|
$
|
|
%
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(in thousands)
|
|
|
|
|
Montana
|
$
|
9,910
|
|
|
$
|
9,896
|
|
|
14
|
|
|
0.1
|
%
|
|
845
|
|
|
956
|
|
|
179,571
|
|
|
177,410
|
|
South Dakota
|
2,179
|
|
|
1,702
|
|
|
477
|
|
|
28.0
|
|
|
106
|
|
|
114
|
|
|
40,826
|
|
|
40,437
|
|
Nebraska
|
2,443
|
|
|
1,698
|
|
|
745
|
|
|
43.9
|
|
|
144
|
|
|
156
|
|
|
37,406
|
|
|
37,467
|
|
Residential
|
14,532
|
|
|
13,296
|
|
|
1,236
|
|
|
9.3
|
|
|
1,095
|
|
|
1,226
|
|
|
257,803
|
|
|
255,314
|
|
Montana
|
6,110
|
|
|
5,598
|
|
|
512
|
|
|
9.1
|
|
|
603
|
|
|
611
|
|
|
24,872
|
|
|
24,412
|
|
South Dakota
|
1,781
|
|
|
1,030
|
|
|
751
|
|
|
72.9
|
|
|
179
|
|
|
170
|
|
|
6,846
|
|
|
6,864
|
|
Nebraska
|
1,461
|
|
|
684
|
|
|
777
|
|
|
113.6
|
|
|
144
|
|
|
143
|
|
|
4,920
|
|
|
4,945
|
|
Commercial
|
9,352
|
|
|
7,312
|
|
|
2,040
|
|
|
27.9
|
|
|
926
|
|
|
924
|
|
|
36,638
|
|
|
36,221
|
|
Industrial
|
76
|
|
|
51
|
|
|
25
|
|
|
49.0
|
|
|
8
|
|
|
6
|
|
|
227
|
|
|
231
|
|
Other
|
163
|
|
|
92
|
|
|
71
|
|
|
77.2
|
|
|
18
|
|
|
12
|
|
|
168
|
|
|
153
|
|
Total Retail Gas
|
$
|
24,123
|
|
|
$
|
20,751
|
|
|
$
|
3,372
|
|
|
16.2
|
%
|
|
2,047
|
|
|
2,168
|
|
|
294,836
|
|
|
291,919
|
|
Regulatory amortization
|
5,415
|
|
|
7,265
|
|
|
(1,850)
|
|
|
(25.5)
|
|
|
|
|
|
|
|
|
|
Wholesale and other
|
8,944
|
|
|
8,439
|
|
|
505
|
|
|
6.0
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
38,482
|
|
|
$
|
36,455
|
|
|
$
|
2,027
|
|
|
5.6
|
%
|
|
|
|
|
|
|
|
|
Total Cost of Sales
|
9,284
|
|
|
6,882
|
|
|
2,402
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
29,198
|
|
|
$
|
29,573
|
|
|
$
|
(375)
|
|
|
(1.3)
|
%
|
|
|
|
|
|
|
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating Degree Days
|
|
2021 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
300
|
|
306
|
|
319
|
|
2% warmer
|
|
6% warmer
|
South Dakota
|
23
|
|
71
|
|
87
|
|
68% warmer
|
|
74% warmer
|
Nebraska
|
9
|
|
40
|
|
47
|
|
78% warmer
|
|
81% warmer
|
The following summarizes the components of the changes in natural gas gross margin for the three months ended September 30, 2021 and 2020:
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
|
(in millions)
|
Gross Margin Items Impacting Net Income
|
|
Retail volumes
|
$
|
(0.6)
|
|
|
|
Other
|
0.4
|
|
Change in Gross Margin Impacting Net Income
|
(0.2)
|
|
|
|
Gross Margin Items Offset Within Net Income
|
|
Property tax revenue, offset in property tax expense
|
(0.3)
|
|
Operating expenses recovered in trackers
|
(0.1)
|
|
Gas production taxes recovered in revenue, offset in property and other taxes
|
0.2
|
|
Change in Gross Margin Items Offset Within Net Income
|
(0.2)
|
|
Decrease in Gross Margin(1)
|
$
|
(0.4)
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Gross margin decreased $0.4 million, including a $0.2 million decrease for items impacting net income and a $0.2 million decrease from items offset within net income.
The change in gross margin for items impacting net income includes a decrease in gas volumes due to warmer summer weather, partly offset by customer growth.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
Nine Months Ended September 30, 2021 Compared with the Nine Months Ended September 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
Change
|
|
Dekatherms (Dkt)
|
|
Avg. Customer Counts
|
|
2021
|
|
2020
|
|
$
|
|
%
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
(in thousands)
|
|
|
|
|
Montana
|
$
|
82,424
|
|
|
$
|
65,674
|
|
|
16,750
|
|
|
25.5
|
%
|
|
9,119
|
|
|
8,937
|
|
|
179,340
|
|
|
177,036
|
|
South Dakota
|
18,654
|
|
|
16,697
|
|
|
1,957
|
|
|
11.7
|
|
|
2,248
|
|
|
2,310
|
|
|
40,975
|
|
|
40,509
|
|
Nebraska
|
14,599
|
|
|
12,908
|
|
|
1,691
|
|
|
13.1
|
|
|
1,987
|
|
|
1,984
|
|
|
37,560
|
|
|
37,542
|
|
Residential
|
115,677
|
|
|
95,279
|
|
|
20,398
|
|
|
21.4
|
|
|
13,354
|
|
|
13,231
|
|
|
257,875
|
|
|
255,087
|
|
Montana
|
42,890
|
|
|
32,988
|
|
|
9,902
|
|
|
30.0
|
|
|
4,977
|
|
|
4,674
|
|
|
24,876
|
|
|
24,455
|
|
South Dakota
|
12,562
|
|
|
11,213
|
|
|
1,349
|
|
|
12.0
|
|
|
2,060
|
|
|
2,360
|
|
|
6,873
|
|
|
6,889
|
|
Nebraska
|
7,740
|
|
|
6,284
|
|
|
1,456
|
|
|
23.2
|
|
|
1,397
|
|
|
1,394
|
|
|
4,953
|
|
|
4,973
|
|
Commercial
|
63,192
|
|
|
50,485
|
|
|
12,707
|
|
|
25.2
|
|
|
8,434
|
|
|
8,428
|
|
|
36,702
|
|
|
36,317
|
|
Industrial
|
726
|
|
|
503
|
|
|
223
|
|
|
44.3
|
|
|
88
|
|
|
75
|
|
|
229
|
|
|
231
|
|
Other
|
1,007
|
|
|
612
|
|
|
395
|
|
|
64.5
|
|
|
136
|
|
|
104
|
|
|
164
|
|
|
152
|
|
Total Retail Gas
|
$
|
180,602
|
|
|
$
|
146,879
|
|
|
$
|
33,723
|
|
|
23.0
|
%
|
|
22,012
|
|
|
21,838
|
|
|
294,970
|
|
|
291,787
|
|
Regulatory amortization
|
17,951
|
|
|
4,966
|
|
|
12,985
|
|
|
261.5
|
|
|
|
|
|
|
|
|
|
Wholesale and other
|
27,438
|
|
|
26,662
|
|
|
776
|
|
|
2.9
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
$
|
225,991
|
|
|
$
|
178,507
|
|
|
$
|
47,484
|
|
|
26.6
|
%
|
|
|
|
|
|
|
|
|
Total Cost of Sales
|
92,335
|
|
|
47,058
|
|
|
45,277
|
|
|
96.2
|
|
|
|
|
|
|
|
|
|
Gross Margin(1)
|
$
|
133,656
|
|
|
$
|
131,449
|
|
|
$
|
2,207
|
|
|
1.7
|
%
|
|
|
|
|
|
|
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating Degree Days
|
|
2021 as compared with:
|
|
2021
|
|
2020
|
|
Historic Average
|
|
2020
|
|
Historic Average
|
Montana
|
4,767
|
|
4,707
|
|
4,857
|
|
1% cooler
|
|
2% warmer
|
South Dakota
|
5,188
|
|
5,564
|
|
5,648
|
|
7% warmer
|
|
8% warmer
|
Nebraska
|
4,432
|
|
4,250
|
|
4,646
|
|
4% cooler
|
|
5% warmer
|
The following summarizes the components of the changes in natural gas gross margin for the nine months ended September 30, 2021 and 2020:
|
|
|
|
|
|
|
Gross Margin 2021 vs. 2020
|
|
(in millions)
|
Gross Margin Items Impacting Net Income
|
|
Retail volumes
|
$
|
1.7
|
|
Montana gas production rates
|
(0.8)
|
|
Other
|
1.1
|
|
Change in Gross Margin Impacting Net Income
|
2.0
|
|
|
|
Gross Margin Items Offset Within Net Income
|
|
Gas production taxes recovered in revenue, offset in property and other taxes
|
0.4
|
|
Property tax revenue, offset in property tax expense
|
0.2
|
|
Operating expenses recovered in trackers
|
(0.4)
|
|
Change in Gross Margin Items Offset Within Net Income
|
0.2
|
|
Increase in Gross Margin(1)
|
$
|
2.2
|
|
(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.
Gross margin increased $2.2 million, including a $2.0 million increase for items impacting net income and a $0.2 million increase from items offset within net income.
The change in gross margin for items impacting net income includes the following:
•An increase in gas volumes due to colder winter weather in our Montana and Nebraska jurisdictions and customer growth, partly offset by warmer winter weather in our South Dakota jurisdiction and warmer summer weather in all jurisdictions; and
•A reduction of rates from the step down of our Montana gas production assets.
Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIQUIDITY AND CAPITAL RESOURCES
|
Sources and Uses of Funds
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, borrowing capacity under existing credit facilities, and issuance of debt or equity securities are sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures (excluding strategic growth opportunities). The amount of capital expenditures and dividends are subject to certain factors including the use of existing cash, cash equivalents, the receipt of cash from operations, and available financing. A material change in operations, unfavorable credit metrics, or available financing could impact our current liquidity and ability to fund capital resource requirements, and we may defer a portion of our planned capital expenditures as necessary.
Our liquidity is supported by the use of our credit facilities which includes a $425 million Credit Facility and a $25 million revolving credit facility to provide swingline borrowing capability. The $425 million 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 $425 million Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. A total of ten banks participate in the facility, with no one bank providing more than 16 percent of the total availability. The $25 million revolving credit facility bears interest at the lower of prime plus a credit spread of 0.13 percent, or available rates tied to the Eurodollar rate plus a credit spread of 0.80 percent.
We utilize availability under our credit facilities to manage our cash flows due to the seasonality of our business, and utilize any cash on hand in excess of current operating requirements to invest in our business and reduce borrowings. As of September 30, 2021, our total net liquidity was approximately $163.6 million, including $8.6 million of cash and $155.0 million of revolving credit facility availability. As of September 30, 2021, there were no letters of credit outstanding and $295.0 million in outstanding borrowings under our credit facilities. Availability under our credit facilities was $186.0 million as of October 22, 2021.
We issue debt securities to refinance retiring maturities, fund construction programs and for other general corporate purposes. To fund our strategic growth opportunities, we utilize available cash flow, debt capacity and equity issuances that allow us to maintain investment grade ratings. We target a 50 - 55 percent debt to total capital ratio excluding finance leases, and a long-term dividend payout ratio target of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to maintain our ratios within these target ranges.
In March 2021, we issued and sold $100 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00% maturing in March 26, 2024. The net proceeds were used to repay in full our outstanding $100 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time
to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the
bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding,
the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming.
In April 2021, we entered into an Equity Distribution Agreement pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an ATM program, including an equity forward sales component. During the three months ended September 30, 2021, we issued 1,040,085 shares of our common stock at an average price of $63.13, for net proceeds of $64.8 million, which is net of sales commissions and other fees paid of approximately $0.9 million. During the nine months ended September 30, 2021, we issued 1,919,394 shares of our common stock at an average price of $63.94, for net proceeds of $121.1 million, which is net of sales commissions and other fees paid of approximately $1.7 million. We expect a total of approximately $200.0 million of equity proceeds during 2021 to support our current capital program and maintain and protect our credit ratings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
Factors Impacting our Liquidity
Energy Supply Costs - Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas and electric sales typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolver, are used to purchase natural gas to place in storage, perform maintenance, and make capital improvements. In addition, due to the lag between our purchases of electric and natural gas commodities and revenue receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above; therefore, we typically under collect in the fall and winter and over collect in the spring. Fluctuations in recoveries under our cost tracking mechanisms can have a significant effect on cash flows from operations and make year-to-year comparisons difficult.
We recover the cost of our electric and natural gas supply through tracking mechanisms. The natural gas supply tracking mechanism in each of our jurisdictions, and electric supply tracking mechanism in South Dakota are designed to provide stable recovery of supply costs, with a monthly purchased natural gas rate tracker adjustment and a quarterly electric fuel cost rate tracker adjustment to correct for any under or over collection. The Montana electric supply tracking mechanism implemented in 2018, the PCCAM, is designed for us to absorb risk through a sharing mechanism, with 90% of the variance above or below the established base revenues and actual costs collected from or refunded to customers. Our electric supply rates were adjusted monthly under the prior tracker, and under the PCCAM design are adjusted annually. In periods of significant fluctuation of loads and / or market prices, this design impacts our cash flows as application of the PCCAM requires that we absorb certain power cost increases before we are allowed to recover increases from customers.
As of September 30, 2021, we have under collected our costs recovered through tracking mechanisms by approximately $84.5 million. We under collected our costs by approximately $5.7 million as of December 31, 2020 and under collected our costs by approximately $20.5 million as of September 30, 2020.
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 October 22, 2021, our current ratings with these agencies are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Secured Rating
|
|
Senior Unsecured Rating
|
|
Commercial Paper
|
|
Outlook
|
Fitch
|
A
|
|
A-
|
|
F2
|
|
Stable
|
Moody’s(1)
|
A3
|
|
Baa2
|
|
Prime-2
|
|
Negative
|
S&P
|
A-
|
|
BBB
|
|
A-2
|
|
Stable
|
_________________________
(1) On March 12, 2021, Moody’s affirmed our ratings, but revised our outlook from stable to negative citing rising debt to help fund higher capital expenditures and no substantive revenue increase over the next two to three years.
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.
Cash Flows
The following table summarizes our consolidated cash flows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2021
|
|
2020
|
Operating Activities
|
|
|
|
Net income
|
$
|
135.5
|
|
|
$
|
101.7
|
|
Non-cash adjustments to net income
|
148.7
|
|
|
135.0
|
|
Changes in working capital
|
(31.0)
|
|
|
99.1
|
|
Other noncurrent assets and liabilities
|
(31.6)
|
|
|
(13.3)
|
|
Cash Provided by Operating Activities
|
221.6
|
|
|
322.5
|
|
|
|
|
|
Investing Activities
|
|
|
|
Property, plant and equipment additions
|
(311.2)
|
|
|
(283.0)
|
|
|
|
|
|
|
|
|
|
Investment in equity securities
|
(0.6)
|
|
|
—
|
|
Cash Used in Investing Activities
|
(311.8)
|
|
|
(283.0)
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock, net
|
121.1
|
|
|
—
|
|
Issuance of long-term debt, net
|
99.9
|
|
|
150.0
|
|
(Repayments) issuance of short-term borrowings
|
(100.0)
|
|
|
100.0
|
|
Repayments of long-term debt
|
(1.0)
|
|
|
—
|
|
Line of credit borrowings (repayments), net
|
73.0
|
|
|
(193.0)
|
|
Dividends on common stock
|
(95.1)
|
|
|
(90.3)
|
|
Financing costs
|
(0.9)
|
|
|
(2.6)
|
|
Other
|
0.3
|
|
|
(1.7)
|
|
Cash Provided by (Used in) Financing Activities
|
97.3
|
|
|
(37.6)
|
|
|
|
|
|
Increase in Cash, Cash Equivalents, and Restricted Cash
|
7.1
|
|
|
1.9
|
|
Cash, Cash Equivalents, and Restricted Cash, beginning of period
|
17.1
|
|
|
12.1
|
|
Cash, Cash Equivalents, and Restricted Cash, end of period
|
$
|
24.2
|
|
|
$
|
14.0
|
|
Cash Provided by Operating Activities
As of September 30, 2021, cash, cash equivalents, and restricted cash were $24.2 million as compared with $17.1 million as of December 31, 2020 and $14.0 million as of September 30, 2020. Cash provided by operating activities totaled $221.6 million for the nine months ended September 30, 2021 as compared with $322.5 million during the nine months ended September 30, 2020. This decrease in operating cash flows is primarily due to a $106.7 million ($65.1 million from electric operations and $41.6 million from natural gas operations) net increase in under collection of energy supply costs from customers in the current period, and a refund of approximately $20.5 million to our FERC regulated customers. These reductions were offset in part by an improvement in net income.
Cash Used in Investing Activities
Cash used in investing activities increased by approximately $28.8 million as compared with the first nine months of 2020. Plant additions during the first nine months of 2021 include maintenance additions of approximately $230.7 million and capacity related capital expenditures of $80.5 million. Plant additions during the first nine months of 2020 included maintenance additions of approximately $192.4 million and capacity related capital expenditures of approximately $90.6 million.
Cash Provided by (Used in) Financing Activities
Cash provided by financing activities totaled $97.3 million during the nine months ended September 30, 2021 as compared with cash used in financing activities of $37.6 million during the nine months ended September 30, 2020. During the nine
months ended September 30, 2021, cash provided by financing activities reflects proceeds received from the issuance of common stock pursuant to our ATM program of $121.1 million, net proceeds from the issuance of debt of $99.9 million, and net issuances under our revolving lines of credit of $73.0 million, offset in part by repayments of our short-term borrowings of $100.0 million and payment of dividends of $95.1 million. During the nine months ended September 30, 2020, net cash used in financing activities reflects net repayments under our revolving lines of credit of $193.0 million and dividends of $90.3 million, offset in part by proceeds from the issuance of debt of $150.0 million and short-term borrowings of $100.0 million.
Capital Requirements
Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt and equity issuances. Our estimated capital expenditures are discussed in our Annual Report on Form 10-K for the year ended December 31, 2020 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section.
As of September 30, 2021, there have been two significant revisions made to our estimated capital expenditures discussed in our Annual Report on Form 10-K for the year ended December 31, 2020. We have decided not to proceed with the construction of an approximately $60 million 30-40 MW flexible natural gas plant near Aberdeen, South Dakota that was previously included in our estimated Electric segment capital expenditures with an expected in service date in early 2024. Additionally, we are moving forward with construction of the 175 MW Laurel Generating Station natural gas plant, which is estimated to cost approximately $275 million, including capitalized AFUDC, which was not included in our estimated electric segment capital expenditures. This project is expected to be in service by January 2024.
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 September 30, 2021. See our Annual Report on Form 10-K for the year ended December 31, 2020 for additional discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
Thereafter
|
|
(in thousands)
|
Long-term debt (1)
|
$
|
2,474,660
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
439,660
|
|
|
$
|
100,000
|
|
|
$
|
300,000
|
|
|
$
|
1,635,000
|
|
Finance leases
|
15,463
|
|
|
692
|
|
|
2,875
|
|
|
3,097
|
|
|
3,338
|
|
|
3,596
|
|
|
1,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated pension and other postretirement obligations (2)
|
52,221
|
|
|
1,428
|
|
|
12,905
|
|
|
12,905
|
|
|
12,492
|
|
|
12,491
|
|
|
N/A
|
Qualifying facilities liability (3)
|
485,786
|
|
|
19,527
|
|
|
80,355
|
|
|
82,452
|
|
|
74,806
|
|
|
60,054
|
|
|
168,592
|
|
Supply and capacity contracts (4)
|
2,639,374
|
|
|
80,300
|
|
|
241,819
|
|
|
264,729
|
|
|
221,282
|
|
|
216,071
|
|
|
1,615,173
|
|
Contractual interest payments on debt (5)
|
1,501,841
|
|
|
21,838
|
|
|
87,352
|
|
|
85,386
|
|
|
79,760
|
|
|
70,791
|
|
|
1,156,714
|
|
Total Commitments (6)
|
$
|
7,169,345
|
|
|
$
|
123,785
|
|
|
$
|
425,306
|
|
|
$
|
888,229
|
|
|
$
|
491,678
|
|
|
$
|
663,003
|
|
|
$
|
4,577,344
|
|
_________________________
(1)Represents cash payments for long-term debt and excludes $11.6 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 $48 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $485.8 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $403.4 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 and exclude contract payments associated with the Beartooth Battery agreement, which is subject to approval 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 1.36% on the outstanding balance through maturity of the facilities.
(6)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 $19.9 million as of September 30, 2021 on behalf of the operator 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
|
Management’s 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, 2020. As of September 30, 2021, there have been no material changes in these policies.