UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20212022
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________.
Commission File Number 001-31303
Black Hills Corporation
Incorporated in South Dakota IRS Identification Number 46-0458824
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Large Accelerated Filer | x | | Accelerated Filer | ☐ | |
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| Non-accelerated Filer | ☐ | | Smaller Reporting Company | ☐ | |
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| | | | Emerging Growth Company | ☐ | |
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒
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| Securities registered pursuant to Section 12(b) of the Act: |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered | |
| Common stock of $1.00 par value | | BKH | | New York Stock Exchange | |
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date. | | | | | | | | | | | | | | |
| Class | Outstanding at October 31, 2021July 29, 2022 | |
| Common stock, $1.00 par value | 63,820,27165,079,859 | | shares | |
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| TABLE OF CONTENTS |
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| TABLE OF CONTENTS |
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GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
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| AFUDC | Allowance for Funds Used During Construction |
ALJ | Administrative Law Judge |
| AOCI | Accumulated Other Comprehensive Income (Loss) |
| APSC | Arkansas Public Service Commission |
| Arkansas Gas | Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy). |
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| ASC | Accounting Standards Codification |
| ASU | Accounting Standards Update issued by the FASB |
| ATM | At-the-market equity offering program |
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| Availability | The availability factor of a power plant is the percentage of the time that it is available to provide energy. |
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| BHC | Black Hills Corporation; the Company |
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| Black Hills Colorado IPP | Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation |
| Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities. |
| Black Hills Energy | The name used to conduct the business of our utility companies |
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| Black Hills Energy Services | Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy). |
| Black Hills Non-regulated Holdings | Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation |
Black Hills Power | Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric. |
| Black Hills Utility Holdings | Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) |
| Black Hills Wyoming | Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation |
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| Blockchain Interruptible Service (BCIS) tariff | The BCIS tariff was proposed by Wyoming Electric and approved by the WPSC in 2019. The tariff was developed to attract new large electric loads related to blockchain and other industry growth with high energy demand. |
| Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric. |
| Chief Operating Decision Maker (CODM) | Chief Executive Officer |
| Choice Gas Program | Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service. |
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City of Gillette | Gillette, Wyoming |
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| Colorado Electric | Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy). |
| Colorado Gas | Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy). |
| Common Use System | The Common Use System is a jointly operated transmission system we participate in with Basin Electric Power Cooperative and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming. |
| Consolidated Indebtedness to Capitalization Ratio | Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility. |
| Cooling Degree Day (CDD) | A cooling degree day is equivalent to each degree that the average of the high and low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations. |
Corriedale | The 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric and Wyoming Electric, serving as the dedicated wind energy supply to the Renewable Ready program. |
COVID-19 | The official name for the 2019 novel coronavirus disease announced on February 11, 2020 by the World Health Organization, that is causing a global pandemic. |
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| CPCN | Certificate of Public Convenience and Necessity |
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| CP Program | Commercial Paper Program |
| CPUC | Colorado Public Utilities Commission |
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CVA | Credit Valuation Adjustment |
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| Dth | Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu) |
Economy Energy | Purchased energy that costs less than that produced with the utilities’ owned generation. |
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FASB | Financial Accounting Standards Board |
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| Fitch | Fitch Ratings Inc. |
| GAAP | Accounting principles generally accepted in the United States of America |
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Global Settlement | Settlement with a utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders. |
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| Heating Degree Day (HDD) | A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations. |
| Integrated Generation | |
| Non-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment. |
| Iowa Gas | Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy). |
| IPP | Independent Power Producer |
IRP | Integrated Resource Plan |
| IRS | United States Internal Revenue Service |
IUB | Iowa Utilities Board |
| Kansas Gas | Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy). |
| KCC | Kansas Corporation Commission |
| kV | Kilovolt |
| LIBOR | London Interbank Offered Rate |
MDU | Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc. |
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| MEAN | Municipal Energy Agency of Nebraska |
| MMBtu | Million British thermal units |
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| Moody’s | Moody’s Investors Service, Inc. |
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| MW | Megawatts |
| MWh | Megawatt-hours |
| Nebraska Gas | Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy). |
| Neil Simpson II | A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. |
NOL | Net Operating Loss |
| NPSC | Nebraska Public Service Commission |
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| OCI | Other Comprehensive Income |
OSHA | Occupational Safety & Health Administration |
| PPA | Power Purchase Agreement |
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PSA | Power Sales Agreement |
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| PTC | Production Tax Credit |
| Pueblo Airport Generation | The 420 MW combined cycle gas-fired power generating plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012. |
| Ready Wyoming | A 285-mile,260-mile, multi-phase transmission expansion project in Wyoming. This transmission project will serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region. |
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Renewable Advantage | A 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023. |
| Renewable Ready | Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming. |
| Revolving Credit Facility | Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 19, 2021, and now terminates on July 19, 2026. |
| RNG | Renewable Natural Gas |
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SDPUC | South Dakota Public Utilities Commission |
| SEC | United States Securities and Exchange Commission |
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| Service Guard Comfort Plan | Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers. |
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| S&P | S&P Global Ratings, a division of S&P Global Inc. |
| South Dakota Electric | Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy). |
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SSIRSPP | System Safety and Integrity RiderSouthwest Power Pool |
| TCJA | Tax Cuts and Jobs Act |
| Tech Services | Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts. |
| Utilities | Black Hills’ Electric and Gas Utilities |
| Wind Capacity Factor | Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential. |
| Winter Storm Uri | February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy. |
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| WPSC | Wyoming Public Service Commission |
WRDC | Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (doing business as Black Hills Energy) |
| Wygen I | A mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%. |
| Wygen II | A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex. |
| Wygen III | A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 110 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%. |
| Wyodak Plant | The 362 MW mine-mouth, coal-fired generating facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility. |
| Wyoming Electric | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy). |
| Wyoming Gas | Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy). |
FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 20202021 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time, and the following:
•Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings on periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power, and other operating costs and the timing in which new rates would go into effect;
•Our ability to complete our capital program in a cost-effective and timely manner;
•Our ability to execute on our strategy;
•Our ability to successfully execute our financing plans;
•Our ability to achieve our greenhouse gas emissions intensity reduction goals;
•Board of Directors’ approval of any future quarterly dividends;
•The impact of future governmental regulation;
•Our ability to overcome the impacts of supply chain disruptions on availability and cost of materials;
•The effects of inflation and volatile energy prices; and
•Other factors discussed from time to time in our filings with the SEC.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
| | (unaudited) | (unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, | (unaudited) | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2021 | 2020 | 2021 | 2020 | | 2022 | 2021 | 2022 | 2021 |
| | (in thousands, except per share amounts) | | (in thousands, except per share amounts) |
| | Revenue | Revenue | $ | 380,590 | | $ | 346,590 | | $ | 1,386,594 | | $ | 1,210,554 | | Revenue | $ | 474,195 | | $ | 372,572 | | $ | 1,297,765 | | $ | 1,006,004 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | |
| Fuel, purchased power and cost of natural gas sold | Fuel, purchased power and cost of natural gas sold | 94,057 | | 71,686 | | 495,678 | | 331,194 | | Fuel, purchased power and cost of natural gas sold | 188,171 | | 108,474 | | 625,097 | | 401,621 | |
| Operations and maintenance | Operations and maintenance | 122,277 | | 122,759 | | 375,201 | | 365,533 | | Operations and maintenance | 132,968 | | 123,245 | | 269,100 | | 252,924 | |
| Depreciation, depletion and amortization | Depreciation, depletion and amortization | 59,159 | | 56,348 | | 174,871 | | 169,413 | | Depreciation, depletion and amortization | 64,128 | | 58,443 | | 124,591 | | 115,712 | |
| Taxes - property and production | Taxes - property and production | 15,224 | | 13,563 | | 45,390 | | 42,062 | | Taxes - property and production | 16,539 | | 15,144 | | 33,235 | | 30,166 | |
| Total operating expenses | Total operating expenses | 290,717 | | 264,356 | | 1,091,140 | | 908,202 | | Total operating expenses | 401,806 | | 305,306 | | 1,052,023 | | 800,423 | |
| | Operating income | Operating income | 89,873 | | 82,234 | | 295,454 | | 302,352 | | Operating income | 72,389 | | 67,266 | | 245,742 | | 205,581 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | |
| | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | (38,604) | | (36,521) | | (115,098) | | (108,067) | | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | (39,053) | | (38,669) | | (77,874) | | (76,494) | |
| Interest income | Interest income | 586 | | 480 | | 1,278 | | 1,028 | | Interest income | 289 | | 467 | | 565 | | 692 | |
| Impairment of investment | — | | — | | — | | (6,859) | | |
| Other income (expense), net | Other income (expense), net | 1,560 | | (1,193) | | 1,635 | | (703) | | Other income (expense), net | 1,563 | | (191) | | 2,267 | | 75 | |
| Total other income (expense) | Total other income (expense) | (36,458) | | (37,234) | | (112,185) | | (114,601) | | Total other income (expense) | (37,201) | | (38,393) | | (75,042) | | (75,727) | |
| | Income before income taxes | Income before income taxes | 53,415 | | 45,000 | | 183,269 | | 187,751 | | Income before income taxes | 35,188 | | 28,873 | | 170,700 | | 129,854 | |
| Income tax (expense) | (5,253) | | (4,651) | | (6,333) | | (25,484) | | |
| Income tax benefit (expense) | | Income tax benefit (expense) | 658 | | (586) | | (13,830) | | (1,080) | |
| Net income | Net income | 48,162 | | 40,349 | | 176,936 | | 162,267 | | Net income | 35,846 | | 28,287 | | 156,870 | | 128,774 | |
| Net income attributable to non-controlling interest | Net income attributable to non-controlling interest | (4,050) | | (4,066) | | (11,347) | | (11,844) | | Net income attributable to non-controlling interest | (2,431) | | (3,126) | | (5,929) | | (7,297) | |
| Net income available for common stock | Net income available for common stock | $ | 44,112 | | $ | 36,283 | | $ | 165,589 | | $ | 150,423 | | Net income available for common stock | $ | 33,415 | | $ | 25,161 | | $ | 150,941 | | $ | 121,477 | |
| | Earnings per share of common stock: | Earnings per share of common stock: | | Earnings per share of common stock: | |
| Earnings per share, Basic | Earnings per share, Basic | $ | 0.70 | | $ | 0.58 | | $ | 2.63 | | $ | 2.41 | | Earnings per share, Basic | $ | 0.52 | | $ | 0.40 | | $ | 2.33 | | $ | 1.94 | |
| Earnings per share, Diluted | Earnings per share, Diluted | $ | 0.70 | | $ | 0.58 | | $ | 2.63 | | $ | 2.41 | | Earnings per share, Diluted | $ | 0.52 | | $ | 0.40 | | $ | 2.33 | | $ | 1.93 | |
| | Weighted average common shares outstanding: | Weighted average common shares outstanding: | | Weighted average common shares outstanding: | |
| Basic | Basic | 63,341 | | 62,575 | | 62,950 | | 62,310 | | Basic | 64,721 | | 62,867 | | 64,643 | | 62,751 | |
| Diluted | Diluted | 63,436 | | 62,630 | | 63,046 | | 62,362 | | Diluted | 64,883 | | 62,918 | | 64,822 | | 62,817 | |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | (unaudited) | (unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, | (unaudited) | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2021 | 2020 | 2021 | 2020 | | 2022 | 2021 | 2022 | 2021 |
| | (in thousands) | | (in thousands) |
| Net income | Net income | $ | 48,162 | | $ | 40,349 | | $ | 176,936 | | $ | 162,267 | | Net income | $ | 35,846 | | $ | 28,287 | | $ | 156,870 | | $ | 128,774 | |
| | Other comprehensive income (loss), net of tax: | Other comprehensive income (loss), net of tax: | | Other comprehensive income (loss), net of tax: | |
| Benefit plan liability adjustments - net gain (net of tax of $0, $0, $0 and $(17), respectively) | — | | — | | — | | 55 | | |
| Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $6, $6, $21 and $19, respectively) | (19) | | (18) | | (53) | | (60) | | |
| Reclassification adjustments of benefit plan liability - net loss (net of tax of $(139), $(149), $(513) and $(426), respectively) | 459 | | 448 | | 1,280 | | 1,365 | | |
| | Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $8, $6, $14 and $15, respectively) | | Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $8, $6, $14 and $15, respectively) | (14) | | (18) | | (32) | | (34) | |
| Reclassification adjustments of benefit plan liability - net loss (net of tax of $(68), $(157), $(113) and $(374), respectively) | | Reclassification adjustments of benefit plan liability - net loss (net of tax of $(68), $(157), $(113) and $(374), respectively) | 119 | | 440 | | 262 | | 821 | |
| Derivative instruments designated as cash flow hedges: | Derivative instruments designated as cash flow hedges: | | Derivative instruments designated as cash flow hedges: | |
| Reclassification of net realized losses on settled/amortized interest rate swaps (net of tax of $(55), $(168), $(395) and $(508), respectively) | 657 | | 544 | | 1,743 | | 1,630 | | |
| Net unrealized gains (losses) on commodity derivatives (net of tax of $(1,437), $(112), $(1,776) and $(44), respectively) | 4,430 | | 401 | | 5,476 | | 181 | | |
| Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $81, $(41), $87 and $(172), respectively) | (250) | | 137 | | (269) | | 562 | | |
| Other comprehensive income, net of tax | 5,277 | | 1,512 | | 8,177 | | 3,733 | | |
| Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(238), $(150), $(415) and $(340), respectively) | | Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(238), $(150), $(415) and $(340), respectively) | 475 | | 563 | | 1,011 | | 1,086 | |
| Net unrealized gains (losses) on commodity derivatives (net of tax of $734, $(304), $394 and $(339), respectively) | | Net unrealized gains (losses) on commodity derivatives (net of tax of $734, $(304), $394 and $(339), respectively) | (2,314) | | 939 | | (1,267) | | 1,046 | |
| Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $319, $14, $871 and $6, respectively) | | Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $319, $14, $871 and $6, respectively) | (1,004) | | (42) | | (2,706) | | (19) | |
| Other comprehensive income (loss), net of tax | | Other comprehensive income (loss), net of tax | (2,738) | | 1,882 | | (2,732) | | 2,900 | |
| | Comprehensive income | Comprehensive income | 53,439 | | 41,861 | | 185,113 | | 166,000 | | Comprehensive income | 33,108 | | 30,169 | | 154,138 | | 131,674 | |
| Less: comprehensive income attributable to non-controlling interest | Less: comprehensive income attributable to non-controlling interest | (4,050) | | (4,066) | | (11,347) | | (11,844) | | Less: comprehensive income attributable to non-controlling interest | (2,431) | | (3,126) | | (5,929) | | (7,297) | |
| Comprehensive income available for common stock | Comprehensive income available for common stock | $ | 49,389 | | $ | 37,795 | | $ | 173,766 | | $ | 154,156 | | Comprehensive income available for common stock | $ | 30,677 | | $ | 27,043 | | $ | 148,209 | | $ | 124,377 | |
See Note 9 for additional disclosures.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
| | (unaudited) | (unaudited) | As of | (unaudited) | As of |
| | September 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
| | (in thousands) | | (in thousands) |
| ASSETS | ASSETS | | ASSETS | |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 10,181 | | | $ | 6,356 | | Cash and cash equivalents | $ | 10,216 | | | $ | 8,921 | |
| Restricted cash and equivalents | Restricted cash and equivalents | 4,753 | | | 4,383 | | Restricted cash and equivalents | 5,146 | | | 4,889 | |
| Accounts receivable, net | Accounts receivable, net | 181,956 | | | 265,961 | | Accounts receivable, net | 267,103 | | | 321,652 | |
| Materials, supplies and fuel | Materials, supplies and fuel | 145,743 | | | 117,400 | | Materials, supplies and fuel | 152,864 | | | 150,979 | |
| Derivative assets, current | Derivative assets, current | 12,316 | | | 1,848 | | Derivative assets, current | 716 | | | 4,373 | |
| Income tax receivable, net | Income tax receivable, net | 17,472 | | | 19,446 | | Income tax receivable, net | 17,299 | | | 18,017 | |
| Regulatory assets, current | Regulatory assets, current | 213,031 | | | 51,676 | | Regulatory assets, current | 267,725 | | | 270,290 | |
| Other current assets | Other current assets | 42,274 | | | 26,221 | | Other current assets | 39,358 | | | 29,012 | |
| Total current assets | Total current assets | 627,726 | | | 493,291 | | Total current assets | 760,427 | | | 808,133 | |
| | Property, plant and equipment | Property, plant and equipment | 7,697,880 | | | 7,305,530 | | Property, plant and equipment | 8,086,704 | | | 7,856,573 | |
| Less: accumulated depreciation and depletion | Less: accumulated depreciation and depletion | (1,380,304) | | | (1,285,816) | | Less: accumulated depreciation and depletion | (1,499,552) | | | (1,407,397) | |
| Total property, plant and equipment, net | Total property, plant and equipment, net | 6,317,576 | | | 6,019,714 | | Total property, plant and equipment, net | 6,587,152 | | | 6,449,176 | |
| | Other assets: | Other assets: | | Other assets: | |
| Goodwill | Goodwill | 1,299,454 | | | 1,299,454 | | Goodwill | 1,299,454 | | | 1,299,454 | |
| Intangible assets, net | Intangible assets, net | 11,063 | | | 11,944 | | Intangible assets, net | 10,177 | | | 10,770 | |
| Regulatory assets, non-current | Regulatory assets, non-current | 617,024 | | | 226,582 | | Regulatory assets, non-current | 434,643 | | | 526,309 | |
| Other assets, non-current | Other assets, non-current | 37,547 | | | 37,801 | | Other assets, non-current | 42,709 | | | 38,054 | |
| Total other assets, non-current | Total other assets, non-current | 1,965,088 | | | 1,575,781 | | Total other assets, non-current | 1,786,983 | | | 1,874,587 | |
| | TOTAL ASSETS | TOTAL ASSETS | $ | 8,910,390 | | | $ | 8,088,786 | | TOTAL ASSETS | $ | 9,134,562 | | | $ | 9,131,896 | |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
| | (unaudited) | (unaudited) | As of | (unaudited) | As of |
| | September 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
| | (in thousands, except share amounts) | | (in thousands, except share amounts) |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | | LIABILITIES AND EQUITY | |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 142,130 | | | $ | 183,340 | | Accounts payable | $ | 185,735 | | | $ | 217,761 | |
| Accrued liabilities | Accrued liabilities | 249,835 | | | 243,612 | | Accrued liabilities | 226,320 | | | 244,759 | |
| Derivative liabilities, current | Derivative liabilities, current | 3,471 | | | 2,044 | | Derivative liabilities, current | 4,719 | | | 1,439 | |
| Regulatory liabilities, current | Regulatory liabilities, current | 30,156 | | | 25,061 | | Regulatory liabilities, current | 33,356 | | | 17,574 | |
| Notes payable | Notes payable | 332,525 | | | 234,040 | | Notes payable | 335,050 | | | 420,180 | |
| Current maturities of long-term debt | — | | | 8,436 | | |
| | Total current liabilities | Total current liabilities | 758,117 | | | 696,533 | | Total current liabilities | 785,180 | | | 901,713 | |
| | Long-term debt, net of current maturities | Long-term debt, net of current maturities | 4,125,571 | | | 3,528,100 | | Long-term debt, net of current maturities | 4,129,662 | | | 4,126,923 | |
| | Deferred credits and other liabilities: | Deferred credits and other liabilities: | | Deferred credits and other liabilities: | |
| Deferred income tax liabilities, net | Deferred income tax liabilities, net | 445,036 | | | 408,624 | | Deferred income tax liabilities, net | 490,207 | | | 465,388 | |
| Regulatory liabilities, non-current | Regulatory liabilities, non-current | 496,261 | | | 507,659 | | Regulatory liabilities, non-current | 482,642 | | | 485,377 | |
| Benefit plan liabilities | Benefit plan liabilities | 150,727 | | | 150,556 | | Benefit plan liabilities | 121,338 | | | 123,925 | |
| Other deferred credits and other liabilities | Other deferred credits and other liabilities | 134,776 | | | 134,667 | | Other deferred credits and other liabilities | 142,732 | | | 141,447 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 1,226,800 | | | 1,201,506 | | Total deferred credits and other liabilities | 1,236,919 | | | 1,216,137 | |
| Commitments, contingencies and guarantees (Note 3) | Commitments, contingencies and guarantees (Note 3) | 0 | | 0 | Commitments, contingencies and guarantees (Note 3) | 0 | | 0 |
| | Equity: | Equity: | | Equity: | |
| Stockholders’ equity — | Stockholders’ equity — | | Stockholders’ equity — | |
| Common stock $1 par value; 100,000,000 shares authorized; issued 63,865,151 and 62,827,179 shares, respectively | 63,865 | | | 62,827 | | |
| Common stock $1 par value; 100,000,000 shares authorized; issued 65,105,178 and 64,793,095 shares, respectively | | Common stock $1 par value; 100,000,000 shares authorized; issued 65,105,178 and 64,793,095 shares, respectively | 65,105 | | | 64,793 | |
| Additional paid-in capital | Additional paid-in capital | 1,726,277 | | | 1,657,285 | | Additional paid-in capital | 1,808,437 | | | 1,783,436 | |
| Retained earnings | Retained earnings | 929,369 | | | 870,738 | | Retained earnings | 1,036,263 | | | 962,458 | |
| Treasury stock, at cost – 43,885 and 32,492 shares, respectively | (2,819) | | | (2,119) | | |
| Treasury stock, at cost – 23,691 and 54,078 shares, respectively | | Treasury stock, at cost – 23,691 and 54,078 shares, respectively | (1,542) | | | (3,509) | |
| Accumulated other comprehensive income (loss) | Accumulated other comprehensive income (loss) | (19,169) | | | (27,346) | | Accumulated other comprehensive income (loss) | (22,816) | | | (20,084) | |
| Total stockholders’ equity | Total stockholders’ equity | 2,697,523 | | | 2,561,385 | | Total stockholders’ equity | 2,885,447 | | | 2,787,094 | |
| Non-controlling interest | Non-controlling interest | 102,379 | | | 101,262 | | Non-controlling interest | 97,354 | | | 100,029 | |
| Total equity | Total equity | 2,799,902 | | | 2,662,647 | | Total equity | 2,982,801 | | | 2,887,123 | |
| | TOTAL LIABILITIES AND TOTAL EQUITY | TOTAL LIABILITIES AND TOTAL EQUITY | $ | 8,910,390 | | | $ | 8,088,786 | | TOTAL LIABILITIES AND TOTAL EQUITY | $ | 9,134,562 | | | $ | 9,131,896 | |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| | (unaudited) | (unaudited) | Nine Months Ended September 30, | (unaudited) | Six Months Ended June 30, |
| | 2021 | 2020 | | 2022 | 2021 |
| Operating activities: | Operating activities: | (in thousands) | Operating activities: | (in thousands) |
| Net income | Net income | $ | 176,936 | | $ | 162,267 | | Net income | $ | 156,870 | | $ | 128,774 | |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities: | Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | Adjustments to reconcile net income to net cash provided by (used in) operating activities: | |
| Depreciation, depletion and amortization | Depreciation, depletion and amortization | 174,871 | | 169,413 | | Depreciation, depletion and amortization | 124,591 | | 115,712 | |
| Deferred financing cost amortization | Deferred financing cost amortization | 3,892 | | 5,523 | | Deferred financing cost amortization | 4,953 | | 4,381 | |
| Impairment of investment | — | | 6,859 | | |
| Stock compensation | Stock compensation | 7,245 | | 2,696 | | Stock compensation | 3,834 | | 5,044 | |
| Deferred income taxes | Deferred income taxes | 5,844 | | 28,502 | | Deferred income taxes | 13,860 | | 692 | |
| Employee benefit plans | Employee benefit plans | 6,779 | | 9,294 | | Employee benefit plans | 1,383 | | 4,934 | |
| Other adjustments, net | Other adjustments, net | 2,708 | | 7,910 | | Other adjustments, net | (9,489) | | 10,495 | |
| Changes in certain operating assets and liabilities: | Changes in certain operating assets and liabilities: | | Changes in certain operating assets and liabilities: | |
| Materials, supplies and fuel | Materials, supplies and fuel | (29,948) | | (10,905) | | Materials, supplies and fuel | (6,993) | | 3,974 | |
| Accounts receivable and other current assets | Accounts receivable and other current assets | 97,348 | | 75,960 | | Accounts receivable and other current assets | 55,641 | | 88,513 | |
| Accounts payable and other current liabilities | Accounts payable and other current liabilities | (20,094) | | (11,136) | | Accounts payable and other current liabilities | (24,130) | | (59,640) | |
| Regulatory assets | Regulatory assets | (559,389) | | 1,954 | | Regulatory assets | 128,315 | | (540,709) | |
| Regulatory liabilities | Regulatory liabilities | (9,533) | | (17,686) | | Regulatory liabilities | — | | (9,509) | |
| Contributions to defined benefit pension plans | — | | (12,700) | | |
| | Other operating activities, net | Other operating activities, net | (1,419) | | 1,508 | | Other operating activities, net | (6,805) | | (2,834) | |
| Net cash provided by (used in) operating activities | Net cash provided by (used in) operating activities | (144,760) | | 419,459 | | Net cash provided by (used in) operating activities | 442,030 | | (250,173) | |
| | Investing activities: | Investing activities: | | Investing activities: | |
| Property, plant and equipment additions | Property, plant and equipment additions | (497,849) | | (535,993) | | Property, plant and equipment additions | (293,803) | | (319,476) | |
| Other investing activities | Other investing activities | 13,743 | | 6,269 | | Other investing activities | 2,418 | | 9,739 | |
| Net cash (used in) investing activities | Net cash (used in) investing activities | (484,106) | | (529,724) | | Net cash (used in) investing activities | (291,385) | | (309,737) | |
| | Financing activities: | Financing activities: | | Financing activities: | |
| Dividends paid on common stock | Dividends paid on common stock | (106,957) | | (99,999) | | Dividends paid on common stock | (77,136) | | (71,092) | |
| Common stock issued | Common stock issued | 62,977 | | 99,316 | | Common stock issued | 20,095 | | 40,037 | |
| Term loan - borrowings | Term loan - borrowings | 800,000 | | — | | Term loan - borrowings | — | | 800,000 | |
| Term loan - repayments | Term loan - repayments | (800,000) | | — | | Term loan - repayments | — | | (200,000) | |
| Net borrowings (payments) of Revolving Credit Facility and CP Program | Net borrowings (payments) of Revolving Credit Facility and CP Program | 98,485 | | (265,180) | | Net borrowings (payments) of Revolving Credit Facility and CP Program | (85,130) | | (4,190) | |
| Long-term debt - issuances | 600,000 | | 400,000 | | |
| | Long-term debt - repayments | Long-term debt - repayments | (8,436) | | (7,163) | | Long-term debt - repayments | — | | (1,436) | |
| Distributions to non-controlling interest | Distributions to non-controlling interest | (10,230) | | (12,636) | | Distributions to non-controlling interest | (8,604) | | (8,705) | |
| Other financing activities | Other financing activities | (2,778) | | (6,519) | | Other financing activities | 1,682 | | 291 | |
| Net cash provided by financing activities | 633,061 | | 107,819 | | |
| Net cash provided by (used in) financing activities | | Net cash provided by (used in) financing activities | (149,093) | | 554,905 | |
| | Net change in cash, restricted cash and cash equivalents | Net change in cash, restricted cash and cash equivalents | 4,195 | | (2,446) | | Net change in cash, restricted cash and cash equivalents | 1,552 | | (5,005) | |
| | Cash, restricted cash and cash equivalents at beginning of period | Cash, restricted cash and cash equivalents at beginning of period | 10,739 | | 13,658 | | Cash, restricted cash and cash equivalents at beginning of period | 13,810 | | 10,739 | |
| Cash, restricted cash and cash equivalents at end of period | Cash, restricted cash and cash equivalents at end of period | $ | 14,934 | | $ | 11,212 | | Cash, restricted cash and cash equivalents at end of period | $ | 15,362 | | $ | 5,734 | |
| | Supplemental cash flow information: | Supplemental cash flow information: | | Supplemental cash flow information: | |
| Cash (paid) refunded during the period: | Cash (paid) refunded during the period: | | Cash (paid) refunded during the period: | |
| Interest, net of amounts capitalized | Interest, net of amounts capitalized | $ | (93,325) | | $ | (87,453) | | Interest, net of amounts capitalized | $ | (72,791) | | $ | (71,825) | |
| Income taxes | Income taxes | 1,486 | | 1,256 | | Income taxes | 752 | | 1,486 | |
| Non-cash investing and financing activities: | Non-cash investing and financing activities: | | Non-cash investing and financing activities: | |
| Accrued property, plant and equipment purchases at September 30 | 55,619 | | 86,474 | | |
| Accrued property, plant and equipment purchases at June 30 | | Accrued property, plant and equipment purchases at June 30 | 49,229 | | 54,448 | |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
| | (unaudited) | (unaudited) | Common Stock | Treasury Stock | | (unaudited) | Common Stock | Treasury Stock | |
| (in thousands except share amounts) | (in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non-controlling Interest | Total | (in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non-controlling Interest | Total |
| December 31, 2020 | 62,827,179 | | $ | 62,827 | | 32,492 | | $ | (2,119) | | $ | 1,657,285 | | $ | 870,738 | | $ | (27,346) | | $ | 101,262 | | $ | 2,662,647 | | |
| December 31, 2021 | | December 31, 2021 | 64,793,095 | | $ | 64,793 | | 54,078 | | $ | (3,509) | | $ | 1,783,436 | | $ | 962,458 | | $ | (20,084) | | $ | 100,029 | | $ | 2,887,123 | |
| Net income | Net income | — | | — | | — | | — | | — | | 96,316 | | — | | 4,171 | | 100,487 | | Net income | — | | — | | — | | — | | — | | 117,526 | | — | | 3,498 | | 121,024 | |
| Other comprehensive income, net of tax | Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 1,018 | | — | | 1,018 | | Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 6 | | — | | 6 | |
| | Dividends on common stock ($0.565 per share) | — | | — | | — | | — | | — | | (35,514) | | — | | — | | (35,514) | | |
| Dividends on common stock ($0.595 per share) | | Dividends on common stock ($0.595 per share) | — | | — | | — | | — | | — | | (38,533) | | — | | — | | (38,533) | |
| Share-based compensation | Share-based compensation | 82,794 | | 83 | | 7,448 | | (445) | | 1,672 | | — | | — | | — | | 1,310 | | Share-based compensation | 425 | | — | | (34,393) | | 2,222 | | (191) | | — | | — | | — | | 2,031 | |
| | Issuance of common stock | | Issuance of common stock | 55,707 | | 56 | | — | | — | | 3,776 | | — | | — | | — | | 3,832 | |
| Issuance costs | | Issuance costs | — | | — | | — | | — | | (41) | | — | | — | | — | | (41) | |
| | Distributions to non-controlling interest | | Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,420) | | (4,420) | |
| March 31, 2022 | | March 31, 2022 | 64,849,227 | | $ | 64,849 | | 19,685 | | $ | (1,287) | | $ | 1,786,980 | | $ | 1,041,451 | | $ | (20,078) | | $ | 99,107 | | $ | 2,971,022 | |
| Net income | | Net income | — | | — | | — | | — | | — | | 33,415 | | — | | 2,431 | | 35,846 | |
| Other comprehensive (loss), net of tax | | Other comprehensive (loss), net of tax | — | | — | | — | | — | | — | | — | | (2,738) | | — | | (2,738) | |
| Dividends on common stock ($0.595 per share) | | Dividends on common stock ($0.595 per share) | — | | — | | — | | — | | — | | (38,603) | | — | | — | | (38,603) | |
| Share-based compensation | | Share-based compensation | 39,066 | | 39 | | 4,006 | | (255) | | 5,370 | | — | | — | | — | | 5,154 | |
| | Issuance of common stock | | Issuance of common stock | 216,885 | | 217 | | — | | — | | 16,353 | | — | | — | | — | | 16,570 | |
| Issuance costs | | Issuance costs | — | | — | | — | | — | | (266) | | — | | — | | — | | (266) | |
| | Distributions to non-controlling interest | | Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,184) | | (4,184) | |
| June 30, 2022 | | June 30, 2022 | 65,105,178 | | $ | 65,105 | | 23,691 | | $ | (1,542) | | $ | 1,808,437 | | $ | 1,036,263 | | $ | (22,816) | | $ | 97,354 | | $ | 2,982,801 | |
| | Other | — | | — | | — | | — | | — | | (2) | | — | | — | | (2) | | |
| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,644) | | (4,644) | | |
| March 31, 2021 | 62,909,973 | | $ | 62,910 | | 39,940 | | $ | (2,564) | | $ | 1,658,957 | | $ | 931,538 | | $ | (26,328) | | $ | 100,789 | | $ | 2,725,302 | | |
| Net income | — | | — | | — | | — | | — | | 25,161 | | — | | 3,126 | | 28,287 | | |
| Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 1,882 | | — | | 1,882 | | |
| Dividends on common stock ($0.565 per share) | — | | — | | — | | — | | — | | (35,578) | | — | | — | | (35,578) | | |
| Share-based compensation | 20,905 | | 21 | | 6,588 | | (424) | | 3,698 | | — | | — | | — | | 3,295 | | |
| | Issuance of common stock | 596,035 | | 596 | | — | | — | | 39,636 | | — | | — | | — | | 40,232 | | |
| Issuance costs | — | | — | | — | | — | | (466) | | — | | — | | — | | (466) | | |
| | Other | — | | — | | — | | — | | — | | 1 | | — | | — | | 1 | | |
| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,061) | | (4,061) | | |
| June 30, 2021 | 63,526,913 | | $ | 63,527 | | 46,528 | | $ | (2,988) | | $ | 1,701,825 | | $ | 921,122 | | $ | (24,446) | | $ | 99,854 | | $ | 2,758,894 | | |
| Net income | — | | — | | — | | — | | — | | 44,112 | | — | | 4,050 | | 48,162 | | |
| Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 5,277 | | — | | 5,277 | | |
| Dividends on common stock ($0.565 per share) | — | | — | | — | | — | | — | | (35,865) | | — | | — | | (35,865) | | |
| Share-based compensation | 17 | | — | | (2,643) | | 169 | | 1,849 | | — | | — | | — | | 2,018 | | |
| | Issuance of common stock | 338,221 | | 338 | | — | | — | | 22,834 | | — | | — | | — | | 23,172 | | |
| Issuance costs | — | | — | | — | | — | | (231) | | — | | — | | — | | (231) | | |
| | Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (1,525) | | (1,525) | | |
| September 30, 2021 | 63,865,151 | | $ | 63,865 | | 43,885 | | $ | (2,819) | | $ | 1,726,277 | | $ | 929,369 | | $ | (19,169) | | $ | 102,379 | | $ | 2,799,902 | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (unaudited) | Common Stock | Treasury Stock | | | | | |
| (in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non-controlling Interest | Total |
| December 31, 2019 | 61,480,658 | | $ | 61,481 | | 3,956 | | $ | (267) | | $ | 1,552,788 | | $ | 778,776 | | $ | (30,655) | | $ | 101,946 | | $ | 2,464,069 | |
| Net income | — | | — | | — | | — | | — | | 93,174 | | — | | 4,050 | | 97,224 | |
| Other comprehensive income (loss), net of tax | — | | — | | — | | — | | — | | — | | 1,273 | | — | | 1,273 | |
| | | | | | | | | |
| | | | | | | | | |
| Dividends on common stock ($0.535 per share) | — | | — | | — | | — | | — | | (32,902) | | — | | — | | (32,902) | |
| Share-based compensation | 69,378 | | 69 | | 20,700 | | (1,658) | | 2,263 | | — | | — | | — | | 674 | |
| | | | | | | | | |
| Issuance of common stock | 1,222,942 | | 1,223 | | — | | — | | 98,777 | | — | | — | | — | | 100,000 | |
| Issuance costs | — | | — | | — | | — | | (967) | | — | | — | | — | | (967) | |
| | | | | | | | | |
| | | | | | | | | |
| Implementation of ASU 2016-13 Financial Instruments - Credit Losses | — | | — | | — | | — | | — | | (207) | | — | | — | | (207) | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,741) | | (4,741) | |
| March 31, 2020 | 62,772,978 | | $ | 62,773 | | 24,656 | | $ | (1,925) | | $ | 1,652,861 | | $ | 838,841 | | $ | (29,382) | | $ | 101,255 | | $ | 2,624,423 | |
| Net income | — | | — | | — | | — | | — | | 20,966 | | — | | 3,728 | | 24,694 | |
| Other comprehensive income (loss), net of tax | — | | — | | — | | — | | — | | — | | 948 | | — | | 948 | |
| | | | | | | | | |
| | | | | | | | | |
| Dividends on common stock ($0.535 per share) | — | | — | | — | | — | | — | | (33,538) | | — | | — | | (33,538) | |
| Share-based compensation | 18 | | — | | 1,743 | | 46 | | 1,781 | | — | | — | | — | | 1,827 | |
| | | | | | | | | |
| | | | | | | | | |
| Issuance costs | — | | — | | — | | — | | (79) | | — | | — | | — | | (79) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (3,779) | | (3,779) | |
| June 30, 2020 | 62,772,996 | | $ | 62,773 | | 26,399 | | $ | (1,879) | | $ | 1,654,563 | | $ | 826,269 | | $ | (28,434) | | $ | 101,204 | | $ | 2,614,496 | |
| Net income | — | | — | | — | | — | | — | | 36,283 | | — | | 4,066 | | 40,349 | |
| Other comprehensive income (loss), net of tax | — | | — | | — | | — | | — | | — | | 1,512 | | — | | 1,512 | |
| Dividends on common stock ($0.535 per share) | — | | — | | — | | — | | — | | (33,559) | | — | | — | | (33,559) | |
| Share-based compensation | 19 | | — | | (1,502) | | 169 | | 1,468 | | — | | — | | — | | 1,637 | |
| | | | | | | | | |
| | | | | | | | | |
| Issuance costs | — | | — | | — | | — | | (119) | | — | | — | | — | | (119) | |
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| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,116) | | (4,116) | |
| September 30, 2020 | 62,773,015 | | $ | 62,773 | | 24,897 | | $ | (1,710) | | $ | 1,655,912 | | $ | 828,993 | | $ | (26,922) | | $ | 101,154 | | $ | 2,620,200 | |
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| (unaudited) | Common Stock | Treasury Stock | | | | | |
| (in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non-controlling Interest | Total |
| December 31, 2020 | 62,827,179 | | $ | 62,827 | | 32,492 | | $ | (2,119) | | $ | 1,657,285 | | $ | 870,738 | | $ | (27,346) | | $ | 101,262 | | $ | 2,662,647 | |
| Net income | — | | — | | — | | — | | — | | 96,316 | | — | | 4,171 | | 100,487 | |
| Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 1,018 | | — | | 1,018 | |
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| Dividends on common stock ($0.565 per share) | — | | — | | — | | — | | — | | (35,514) | | — | | — | | (35,514) | |
| Share-based compensation | 82,794 | | 83 | | 7,448 | | (445) | | 1,672 | | — | | — | | — | | 1,310 | |
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| Other | — | | — | | — | | — | | — | | (2) | | — | | — | | (2) | |
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| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,644) | | (4,644) | |
| March 31, 2021 | 62,909,973 | | $ | 62,910 | | 39,940 | | $ | (2,564) | | $ | 1,658,957 | | $ | 931,538 | | $ | (26,328) | | $ | 100,789 | | $ | 2,725,302 | |
| Net income | — | | — | | — | | — | | — | | 25,161 | | — | | 3,126 | | 28,287 | |
| Other comprehensive income, net of tax | — | | — | | — | | — | | — | | — | | 1,882 | | — | | 1,882 | |
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| Dividends on common stock ($0.565 per share) | — | | — | | — | | — | | — | | (35,578) | | — | | — | | (35,578) | |
| Share-based compensation | 20,905 | | 21 | | 6,588 | | (424) | | 3,698 | | — | | — | | — | | 3,295 | |
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| Issuance of common stock | 596,035 | | 596 | | — | | — | | 39,636 | | — | | — | | — | | 40,232 | |
| Issuance costs | — | | — | | — | | — | | (466) | | — | | — | | — | | (466) | |
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| Other | — | | — | | — | | — | | — | | 1 | | — | | — | | 1 | |
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| Distributions to non-controlling interest | — | | — | | — | | — | | — | | — | | — | | (4,061) | | (4,061) | |
| June 30, 2021 | 63,526,913 | | $ | 63,527 | | 46,528 | | $ | (2,988) | | $ | 1,701,825 | | $ | 921,122 | | $ | (24,446) | | $ | 99,854 | | $ | 2,758,894 | |
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BLACK HILLS CORPORATION
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 20202021 Annual Report on Form 10-K)
(1) Management’s Statement
The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 20202021 Annual Report on Form 10-K.
Segment Reporting
We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products services and regulation.services. All of our operations and assets are located within the United States. We conduct our operations through the Electric Utilities and Gas Utilities segments. In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change.
For further information regarding our segment reporting, see Note 12.
Use of Estimates and Basis of Presentation
The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the SeptemberJune 30, 2021,2022, December 31, 20202021 and SeptemberJune 30, 20202021 financial information. Certain lines of business in which we operate are highly seasonal, and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.
COVID-19 Pandemic
In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed the electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations.
The Company’s Condensed Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three and nine months ended September 30, 2021, there were no material adverse impacts on the Company’s results of operations.
Recently Issued Accounting Standards
Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating whether we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potentialbut do not expect it to have a material impact on our financial position, results of operations and cash flows.
Recently Adopted Accounting Standards
Simplifying the Accounting for Income Taxes, ASU 2019-12
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. We adopted this standard prospectively on January 1, 2021. Adoption of this standard did not have an impact on our financial position, results of operations or cash flows.
(2) Regulatory Matters
We had the following regulatory assets and liabilities (in thousands):
| | | | | | | | |
| As of | As of |
| September 30, 2021 | December 31, 2020 |
| Regulatory assets | | |
Winter Storm Uri (a) | $ | 532,766 | | $ | — | |
Deferred energy and fuel cost adjustments (b) | 59,741 | | 39,035 | |
Deferred gas cost adjustments (b) | 6,076 | | 3,200 | |
Gas price derivatives (b) | — | | 2,226 | |
Deferred taxes on AFUDC (c) | 7,537 | | 7,491 | |
Employee benefit plans and related deferred taxes (d) | 114,234 | | 116,598 | |
Environmental (b) | 1,395 | | 1,413 | |
| | |
Loss on reacquired debt (b) | 21,460 | | 22,864 | |
| | |
Deferred taxes on flow through accounting (d) | 54,199 | | 47,515 | |
Decommissioning costs (b) | 6,583 | | 8,988 | |
Gas supply contract termination (b) | — | | 2,524 | |
Other regulatory assets (b) | 26,064 | | 26,404 | |
| Total regulatory assets | 830,055 | | 278,258 | |
| Less current regulatory assets | (213,031) | | (51,676) | |
| Regulatory assets, non-current | $ | 617,024 | | $ | 226,582 | |
| | |
| Regulatory liabilities | | |
Deferred energy and gas costs (b) | $ | 9,408 | | $ | 13,253 | |
Gas price derivatives (b) | 13,234 | | — | |
Employee benefit plan costs and related deferred taxes (d) | 39,203 | | 40,256 | |
Cost of removal (b) | 181,180 | | 172,902 | |
| | |
Excess deferred income taxes (d) | 266,477 | | 285,259 | |
| | |
Other regulatory liabilities (d) | 16,915 | | 21,050 | |
| Total regulatory liabilities | 526,417 | | 532,720 | |
| Less current regulatory liabilities | (30,156) | | (25,061) | |
| Regulatory liabilities, non-current | $ | 496,261 | | $ | 507,659 | |
| | | | | | | | |
| As of | As of |
| June 30, 2022 | December 31, 2021 |
| Regulatory assets | | |
Winter Storm Uri (a) | $ | 402,971 | | $ | 509,025 | |
Deferred energy and fuel cost adjustments (b) | 71,701 | | 59,973 | |
Deferred gas cost adjustments (b) | 8,083 | | 9,488 | |
Gas price derivatives (b) | 4,845 | | 2,584 | |
Deferred taxes on AFUDC (b) | 7,426 | | 7,457 | |
Employee benefit plans and related deferred taxes (c) | 87,130 | | 88,923 | |
Environmental (b) | 1,360 | | 1,385 | |
| | |
Loss on reacquired debt (b) | 20,112 | | 21,011 | |
| | |
Deferred taxes on flow through accounting (b) | 69,811 | | 63,243 | |
Decommissioning costs (b) | 4,717 | | 5,961 | |
Other regulatory assets (b) | 24,212 | | 27,549 | |
| Total regulatory assets | 702,368 | | 796,599 | |
| Less current regulatory assets | (267,725) | | (270,290) | |
| Regulatory assets, non-current | $ | 434,643 | | $ | 526,309 | |
| | |
| Regulatory liabilities | | |
Deferred energy and gas costs (b) | $ | 15,899 | | $ | 6,113 | |
| | |
Employee benefit plan costs and related deferred taxes (c) | 31,330 | | 32,241 | |
Cost of removal (b) | 184,111 | | 179,976 | |
| | |
Excess deferred income taxes (c) | 259,674 | | 264,042 | |
Other regulatory liabilities (c) | 24,984 | | 20,579 | |
| Total regulatory liabilities | 515,998 | | 502,951 | |
| Less current regulatory liabilities | (33,356) | | (17,574) | |
| Regulatory liabilities, non-current | $ | 482,642 | | $ | 485,377 | |
__________
(a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs arevary by jurisdiction and Wyoming Gas is still subject to pending applicationsapplication with our utility commissions.the WPSC. See further information below.
(b) Recovery of costs, but we are not allowed a rate of return.
(c) In addition to recovery of costs, we are allowed a rate of return.
(d) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
Regulatory Activity
Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 2 of the Notes to the Consolidated Financial Statements in our 20202021 Annual Report on Form 10-K.
Winter Storm Uri
In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental fuel, purchased power and natural gas costs.
Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.73.5 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we seeksought approval to recover carrying costs. For the ninethree and six months ended SeptemberJune 30, 2022 and three and six months ended June 30, 2021, $1.8$12 million, $15 million, $0.1 million and $0.1 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. We are also seeking recoveryThe carrying costs accrued during the three and six months ended June 30, 2022 included a one-time, $10 million true-up to reflect Commission authorized rates.
On January 27, 2022, Kansas Gas received approval from the KCC for its Winter Storm Uri incremental costs through our existing regulatory mechanisms.cost recovery settlement with final rates implemented in February 2022. In March 2022, Colorado Electric and Colorado Gas received approval from the CPUC for their respective Winter Storm Uri cost recovery settlements with final rates implemented in April 2022. In June 2022, Arkansas Gas received approval from the APSC for its Winter Storm Uri cost recovery application. The APSC had previously approved interim cost recovery effective in June 2021.
To date, Arkansas Gas, Colorado Electric, Colorado Gas, Iowa Gas, Kansas Gas, Nebraska Gas and South Dakota Electric received commission approval of their Winter Storm Uri cost recovery applications. Additionally, Arkansas Gas, Iowa Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periodsperiod at a later date. In October 2021, Wyoming Gas filed a settlement agreement for their application with final rates to be implemented January 1, 2022. The settlement is subject to final approval by the commission.For the ninesix months ended SeptemberJune 30, 2021,2022, our Utilities collected $15$111 million of Winter Storm Uri incremental costs and carrying costs from customers. As of June 30, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 3.0 years.
TCJA
On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021. The settlement agreement further provided for Colorado Electric to deliver annual bill credits to customers, starting in April 2021, until remaining excess deferred income tax regulatory liabilities associated with the TCJA are fully amortized. In April 2021, Colorado Electric delivered $0.9 million of TCJA-related bill credits to customers.
On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in June 2021.
These Colorado Electric and Nebraska Gas bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the three and nine months ended September 30, 2021.
As part of theKansas Gas’s 2021 rate review settlement agreement, discussed further below, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for each of the next three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). For the three and six months ended June 30, 2022, Kansas Gas delivered TCJA and state tax reform bill credits to customers of $0.7 million and $1.5 million, respectively.
ColoradoThese bill credits, which resulted in a reduction of revenue, were offset by a reduction in income tax expense and resulted in an immaterial impact to Net income for the three and six months ended June 30, 2022.
Arkansas Gas
Rate Review
On June 1,December 10, 2021, ColoradoArkansas Gas filed a rate review with the CPUCAPSC seeking recovery of significant infrastructure investments in its 7,000-mile7,200-mile natural gas pipeline system. On October 5, 2021, Colorado Gas reached a settlement agreement with the CPUC Staff and various intervenors for a generalThe rate increase. The settlement agreement is subject to review and approval by an ALJ and the CPUC. If approved, the settlement is expected to generate $6.5requests $22 million ofin new annual revenue with new rates effective January 1, 2022. The new revenue is based ona capital structure of 50.9% equity and 49.1% debt and a return on equity of 9.2% and a capital structure10.2%. The request seeks to finalize rates in the fourth quarter of 50.3% equity and 49.7% debt.2022.
SSIRWyoming Electric
On September 11, 2020, in accordance with the final Order from an earlier rate review filed on February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal that will recover safety and integrity focused system investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt.
Iowa Gas
Rate Review
On June 1, 2021, Iowa Gas2022, Wyoming Electric filed a rate review with the IUBWPSC seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system.1,330-mile electric distribution and 59-mile electric transmission systems. The rate review requests shifting $2.2$15 million of rider revenue to base rates and $8.3 million in additional new annual revenue with a capital structure of 50%54% equity and 50%46% debt and a return on equity of 10.15%10.3%. Iowa statute allows implementation of interim rates 10 days after filing a rate review and Iowa Gas implemented interim rates effective on June 11, 2021. The request seeks to finalize rates in the first quarter of 2022.2023.
Rate Review
On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. On October 8, 2021, Kansas Gas reached a Global Settlement agreement with KCC Staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement agreement is subject to review and approval by the KCC. If approved, the settlement will shift $6.6 million of rider revenue to base rates, which are expected to be effective January 1, 2022, and also allow rider renewal for at least five more years.
Nebraska Gas
Jurisdictional Consolidation and Rate Review
On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021, which replaced interim rates effective September 1, 2020. The approval shifted $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions.
(3) Commitments, Contingencies and Guarantees
There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 20202021 Annual Report on Form 10-K except for those described below.
Agreement under Blockchain Interruptible Service Tariff
On June 21, 2022, Wyoming Electric completed its first agreement for service under its Blockchain Interruptible Service tariff. Under the five-year agreement, Wyoming Electric will deliver up to 45 MW of electric service with an option to expand service up to 75 MW to a new customer in Cheyenne, Wyoming. The crypto mining facility is expected to be operational and purchasing energy in the fourth quarter of 2022.
Power Sales Agreements
On May 3, 2022, South Dakota Electric entered into an agreement with MDU to provide MDU capacity and energy up to a maximum of 50 MW in excess of MDU’s 25% ownership in Wygen III. This agreement, which has similar terms and conditions as South Dakota Electric’s existing agreement with MDU expiring on December 31, 2023, is effective on January 1, 2024 and will expire on December 31, 2028.
During periods of reduced production at Wygen III, in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 23 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. On June 3, 2022, South Dakota Electric entered into an agreement with similar terms and conditions as its existing agreement with MDU expiring on December 31, 2023, is effective on January 1, 2024 and will expire on December 31, 2028.
GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver, Colorado)
On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We believe we have meritorious defenses to the verdict and intend to appeal the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable.
Power Purchase Agreement - ColoradoAgreements
On March 21, 2022, Wyoming Electric Renewable Advantageentered into a PPA with South Cheyenne Solar, LLC (Cheyenne Solar) to purchase up to 150 MW of renewable energy upon construction of a new solar facility, to be owned by Cheyenne Solar, which is expected to be completed by the end of 2023. The agreement will expire 20 years after construction completion. The solar energy from this PPA will be used to serve our expanding partnerships with industrial customers in Cheyenne, Wyoming.
On February 19, 2021, Colorado Electric entered into a PPAan agreement with TC Colorado Solar, LLC (TC Solar) to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided notice of its intent to terminate the PPA. Colorado Solar, LLC,Electric will seek new requests for proposals for renewable resources as part of its Clean Energy Plan filing, the “2030 Ready Plan.” On May 27, 2022, Colorado Electric filed its 2030 Ready Plan with the CPUC. A CPUC decision is expected in April 2023, after which time, Colorado Electric’s request for proposals for renewable energy resources is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan.commence.
Transmission Service Agreements
On January 1, 2022, Colorado Electric entered into a firm point-to-point transmission service agreement that provides Tri-State Generation and Transmission Association Inc. with a maximum of 58 MW of transmission capacity. This agreement expires December 31, 2024.
On January 1, 2022, South Dakota Electric entered into a firm point-to-point transmission service agreement that provides MEAN with a maximum of 20 MW of transmission capacity. This agreement expires December 31, 2023.
(4) Revenue
Our revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020.2021. Sales tax and other similar taxes are excluded from revenues.
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| Three Months Ended June 30, 2022 | Electric Utilities | Gas Utilities | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 169,032 | | $ | 229,074 | | $ | — | | $ | 398,106 | |
| Transportation | — | | 34,667 | | (100) | | 34,567 | |
| Wholesale | 8,428 | | — | | — | | 8,428 | |
| Market - off-system sales | 8,666 | | 178 | | — | | 8,844 | |
| Transmission/Other | 15,183 | | 9,344 | | (4,148) | | 20,379 | |
| Revenue from contracts with customers | $ | 201,309 | | $ | 273,263 | | $ | (4,248) | | $ | 470,324 | |
| Other revenues | 3,070 | | 906 | | (105) | | 3,871 | |
| Total revenues | $ | 204,379 | | $ | 274,169 | | $ | (4,353) | | $ | 474,195 | |
| | | | |
| Timing of revenue recognition: | | | | |
| Services transferred at a point in time | $ | 6,671 | | $ | — | | $ | — | | $ | 6,671 | |
| Services transferred over time | 194,638 | | 273,263 | | (4,248) | | 463,653 | |
| Revenue from contracts with customers | $ | 201,309 | | $ | 273,263 | | $ | (4,248) | | $ | 470,324 | |
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| Three Months Ended June 30, 2021 | Electric Utilities | Gas Utilities | Inter-company Revenues | Total |
| Customer Types: | (in thousands) |
| Retail | $ | 163,971 | | $ | 143,845 | | $ | — | | $ | 307,816 | |
| Transportation | — | | 31,649 | | (109) | | 31,540 | |
| Wholesale | 5,655 | | — | | — | | 5,655 | |
| Market - off-system sales | 7,266 | | 87 | | — | | 7,353 | |
| Transmission/Other | 11,224 | | 9,125 | | (4,291) | | 16,058 | |
| Revenue from contracts with customers | $ | 188,116 | | $ | 184,706 | | $ | (4,400) | | $ | 368,422 | |
| Other revenues | 2,900 | | 1,344 | | (94) | | 4,150 | |
| Total Revenues | $ | 191,016 | | $ | 186,050 | | $ | (4,494) | | $ | 372,572 | |
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| Timing of Revenue Recognition: | | | | |
| Services transferred at a point in time | $ | 6,714 | | $ | — | | $ | — | | $ | 6,714 | |
| Services transferred over time | 181,402 | | 184,706 | | (4,400) | | 361,708 | |
| Revenue from contracts with customers | $ | 188,116 | | $ | 184,706 | | $ | (4,400) | | $ | 368,422 | |
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| | Three Months Ended September 30, 2021 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total | |
| Six Months Ended June 30, 2022 | | Six Months Ended June 30, 2022 | Electric Utilities | Gas Utilities | Inter-company Revenues | Total |
| Customer types: | Customer types: | (in thousands) | Customer types: | (in thousands) |
| Retail | Retail | $ | 179,982 | | $ | 115,908 | | $ | — | | $ | 15,814 | | $ | (8,846) | | $ | 302,858 | | Retail | $ | 341,838 | | $ | 790,087 | | $ | — | | $ | 1,131,925 | |
| Transportation | Transportation | — | | 37,651 | | — | | — | | (110) | | 37,541 | | Transportation | — | | 84,190 | | (199) | | 83,991 | |
| Wholesale | Wholesale | 3,856 | | — | | 26,058 | | — | | (23,725) | | 6,189 | | Wholesale | 18,703 | | — | | — | | 18,703 | |
| Market - off-system sales | Market - off-system sales | 15,149 | | 75 | | — | | — | | (1,638) | | 13,586 | | Market - off-system sales | 15,820 | | 416 | | — | | 16,236 | |
| Transmission/Other | Transmission/Other | 13,913 | | 9,863 | | — | | — | | (5,297) | | 18,479 | | Transmission/Other | 30,616 | | 18,919 | | (8,297) | | 41,238 | |
| Revenue from contracts with customers | Revenue from contracts with customers | $ | 212,900 | | $ | 163,497 | | $ | 26,058 | | $ | 15,814 | | $ | (39,616) | | $ | 378,653 | | Revenue from contracts with customers | $ | 406,977 | | $ | 893,612 | | $ | (8,496) | | $ | 1,292,093 | |
| Other revenues | Other revenues | 203 | | 1,186 | | 462 | | 574 | | (488) | | 1,937 | | Other revenues | 3,940 | | 1,949 | | (217) | | 5,672 | |
| Total revenues | Total revenues | $ | 213,103 | | $ | 164,683 | | $ | 26,520 | | $ | 16,388 | | $ | (40,104) | | $ | 380,590 | | Total revenues | $ | 410,917 | | $ | 895,561 | | $ | (8,713) | | $ | 1,297,765 | |
| | Timing of revenue recognition: | Timing of revenue recognition: | | Timing of revenue recognition: | |
| Services transferred at a point in time | Services transferred at a point in time | $ | — | | $ | — | | $ | — | | $ | 15,814 | | $ | (8,846) | | $ | 6,968 | | Services transferred at a point in time | $ | 13,784 | | $ | — | | $ | — | | $ | 13,784 | |
| Services transferred over time | Services transferred over time | 212,900 | | 163,497 | | 26,058 | | — | | (30,770) | | 371,685 | | Services transferred over time | 393,193 | | 893,612 | | (8,496) | | 1,278,309 | |
| Revenue from contracts with customers | Revenue from contracts with customers | $ | 212,900 | | $ | 163,497 | | $ | 26,058 | | $ | 15,814 | | $ | (39,616) | | $ | 378,653 | | Revenue from contracts with customers | $ | 406,977 | | $ | 893,612 | | $ | (8,496) | | $ | 1,292,093 | |
|
| | Three Months Ended September 30, 2020 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total | |
| Six Months Ended June 30, 2021 | | Six Months Ended June 30, 2021 | Electric Utilities | Gas Utilities | Inter-company Revenues | Total |
| Customer Types: | Customer Types: | (in thousands) | Customer Types: | (in thousands) |
| Retail | Retail | $ | 169,505 | | $ | 94,367 | | $ | — | | $ | 14,668 | | $ | (8,100) | | $ | 270,440 | | Retail | $ | 368,251 | | $ | 485,450 | | $ | — | | $ | 853,701 | |
| Transportation | Transportation | — | | 38,196 | | — | | — | | (139) | | 38,057 | | Transportation | — | | 79,600 | | (219) | | 79,381 | |
| Wholesale | Wholesale | 5,925 | | — | | 26,049 | | — | | (24,521) | | 7,453 | | Wholesale | 17,014 | | — | | — | | 17,014 | |
| Market - off-system sales | Market - off-system sales | 9,535 | | 36 | | — | | — | | (1,904) | | 7,667 | | Market - off-system sales | 12,038 | | 160 | | — | | 12,198 | |
| Transmission/Other | Transmission/Other | 15,653 | | 10,277 | | — | | — | | (5,235) | | 20,695 | | Transmission/Other | 25,411 | | 19,515 | | (8,580) | | 36,346 | |
| Revenue from contracts with customers | Revenue from contracts with customers | $ | 200,618 | | $ | 142,876 | | $ | 26,049 | | $ | 14,668 | | $ | (39,899) | | $ | 344,312 | | Revenue from contracts with customers | $ | 422,714 | | $ | 584,725 | | $ | (8,799) | | $ | 998,640 | |
| Other revenues | Other revenues | 224 | | 1,053 | | 469 | | 568 | | (36) | | 2,278 | | Other revenues | 3,706 | | 3,844 | | (186) | | 7,364 | |
| Total Revenues | Total Revenues | $ | 200,842 | | $ | 143,929 | | $ | 26,518 | | $ | 15,236 | | $ | (39,935) | | $ | 346,590 | | Total Revenues | $ | 426,420 | | $ | 588,569 | | $ | (8,985) | | $ | 1,006,004 | |
| | Timing of Revenue Recognition: | Timing of Revenue Recognition: | | Timing of Revenue Recognition: | |
| Services transferred at a point in time | Services transferred at a point in time | $ | — | | $ | — | | $ | — | | $ | 14,668 | | $ | (8,100) | | $ | 6,568 | | Services transferred at a point in time | $ | 13,690 | | $ | — | | $ | — | | $ | 13,690 | |
| Services transferred over time | Services transferred over time | 200,618 | | 142,876 | | 26,049 | | — | | (31,799) | | 337,744 | | Services transferred over time | 409,024 | | 584,725 | | (8,799) | | 984,950 | |
| Revenue from contracts with customers | Revenue from contracts with customers | $ | 200,618 | | $ | 142,876 | | $ | 26,049 | | $ | 14,668 | | $ | (39,899) | | $ | 344,312 | | Revenue from contracts with customers | $ | 422,714 | | $ | 584,725 | | $ | (8,799) | | $ | 998,640 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 536,952 | | $ | 601,358 | | $ | — | | $ | 43,751 | | $ | (23,093) | | $ | 1,158,968 | |
| Transportation | — | | 117,251 | | — | | — | | (329) | | 116,922 | |
| Wholesale | 12,788 | | — | | 79,662 | | — | | (71,656) | | 20,794 | |
| Market - off-system sales | 31,746 | | 235 | | — | | — | | (6,197) | | 25,784 | |
| Transmission/Other | 41,339 | | 29,378 | | — | | — | | (15,892) | | 54,825 | |
| Revenue from contracts with customers | $ | 622,825 | | $ | 748,222 | | $ | 79,662 | | $ | 43,751 | | $ | (117,167) | | $ | 1,377,293 | |
| Other revenues | 2,619 | | 5,030 | | 1,369 | | 1,738 | | (1,455) | | 9,301 | |
| Total revenues | $ | 625,444 | | $ | 753,252 | | $ | 81,031 | | $ | 45,489 | | $ | (118,622) | | $ | 1,386,594 | |
| | | | | | |
| Timing of revenue recognition: | | | | | | |
| Services transferred at a point in time | $ | — | | $ | — | | $ | — | | $ | 43,751 | | $ | (23,093) | | $ | 20,658 | |
| Services transferred over time | 622,825 | | 748,222 | | 79,662 | | — | | (94,074) | | 1,356,635 | |
| Revenue from contracts with customers | $ | 622,825 | | $ | 748,222 | | $ | 79,662 | | $ | 43,751 | | $ | (117,167) | | $ | 1,377,293 | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2020 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer Types: | (in thousands) |
| Retail | $ | 459,949 | | $ | 513,208 | | $ | — | | $ | 43,917 | | $ | (23,855) | | $ | 993,219 | |
| Transportation | — | | 113,096 | | — | | — | | (416) | | 112,680 | |
| Wholesale | 14,947 | | — | | 77,234 | | — | | (72,609) | | 19,572 | |
| Market - off-system sales | 17,940 | | 197 | | — | | — | | (6,123) | | 12,014 | |
| Transmission/Other | 43,271 | | 32,038 | | — | | — | | (14,080) | | 61,229 | |
| Revenue from contracts with customers | $ | 536,107 | | $ | 658,539 | | $ | 77,234 | | $ | 43,917 | | $ | (117,083) | | $ | 1,198,714 | |
| Other revenues | 2,074 | | 7,273 | | 1,372 | | 1,940 | | (819) | | 11,840 | |
| Total Revenues | $ | 538,181 | | $ | 665,812 | | $ | 78,606 | | $ | 45,857 | | $ | (117,902) | | $ | 1,210,554 | |
| | | | | | |
| Timing of Revenue Recognition: | | | | | | |
| Services transferred at a point in time | $ | — | | $ | — | | $ | — | | $ | 43,917 | | $ | (23,855) | | $ | 20,062 | |
| Services transferred over time | 536,107 | | 658,539 | | 77,234 | | — | | (93,228) | | 1,178,652 | |
| Revenue from contracts with customers | $ | 536,107 | | $ | 658,539 | | $ | 77,234 | | $ | 43,917 | | $ | (117,083) | | $ | 1,198,714 | |
| | | | | | |
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 13.
(5) Financing
Short-term Debt
We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | | | | |
| September 30, 2021 | December 31, 2020 |
| Balance Outstanding | Letters of Credit (a) | Balance Outstanding | Letters of Credit (a) |
| | | | |
| Revolving Credit Facility | — | | 23,255 | | — | | 24,730 | |
| CP Program | 332,525 | | — | | 234,040 | | — | |
| Total Notes payable | $ | 332,525 | | $ | 23,255 | | $ | 234,040 | | $ | 24,730 | |
_______________
| | | | | | | | | | | | | | |
| June 30, 2022 | December 31, 2021 |
| Balance Outstanding | Letters of Credit (a) | Balance Outstanding | Letters of Credit (a) |
| | | | |
| Revolving Credit Facility | — | | 14,239 | | — | | 27,209 | |
| CP Program | 335,050 | | — | | 420,180 | | — | |
| Total Notes payable | $ | 335,050 | | $ | 14,239 | | $ | 420,180 | | $ | 27,209 | |
__________(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.
Revolving Credit Facility and CP Program
On July 19, 2021, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 19, 2026 with 2 one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. Based on our current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit will be 0.125%, 1.125% and 1.125%, respectively, and a 0.175% commitment fee will be charged on unused amounts.
Our net short-term borrowingsrepayments related to our Revolving Credit Facility and CP Program during the ninesix months ended SeptemberJune 30, 20212022 were $98.5$85 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at SeptemberJune 30, 20212022 was 0.19%1.74%.
Term Loan
On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, carried no prepayment penalty and was subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. Proceeds from the August 26, 2021 public debt offering (discussed below) were used to repay the remaining balance on this term loan.
Long-term Debt
On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% three year senior unsecured notes due August 23, 2024. The notes include an optional redemption provision and may be redeemed, in whole or in part, without premium, on or after February 23, 2022. The proceeds from the offering, which were net of $3.7 million of deferred financing costs, were used to repay amounts outstanding under our term loan entered into on February 24, 2021.
Debt Covenants
Revolving Credit Facility
Under our Revolving Credit Facility, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) consolidated indebtedness, which includes letters of credit and certain guarantees issued, by (ii) capital, which includes consolidated indebtedness plus consolidated net worth, which excludes non-controlling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.
Our Revolving Credit Facility and term loans require compliance with the following financial covenant, which weWe were in compliance with our covenants at SeptemberJune 30, 2021:
| | | | | | | | | | | | | | |
| As of September 30, 2021 | | Covenant Requirement |
| Consolidated Indebtedness to Capitalization Ratio | 62.4% | | Less than | 65% |
21 | | | | | | | | | | | | | | |
| As of June 30, 2022 | | Covenant Requirement |
| Consolidated Indebtedness to Capitalization Ratio | 60.8% | | Less than | 65% |
Wyoming Electric
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of Contentsno more than 0.60 to 1.00. As of June 30, 2022, Wyoming Electric’s debt to capitalization ratio was 50%, which was in compliance with these financial covenants.
Equity
At-the-Market Equity Offering Program
During the three months ended SeptemberJune 30, 2021,2022, we issued a total of 0.2 million shares of common stock under the ATM for proceeds of $16 million, net of $0.2 million in issuance costs. During the six months ended June 30, 2022, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $23$20 million, net of $0.2 million in issuance costs. During the ninethree and six months ended SeptemberJune 30, 2021, we issued a total of 0.90.6 million shares of common stock under the ATM for proceeds of $63$40 million, net of $0.6$0.4 million in issuance costs.
(6) Earnings Per Share
A reconciliation of share amounts used to compute earnings per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands, except per share amounts):
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2022 | 2021 | | 2022 | 2021 |
| | Net income available for common stock | Net income available for common stock | $ | 44,112 | | $ | 36,283 | | | $ | 165,589 | | $ | 150,423 | | Net income available for common stock | $ | 33,415 | | $ | 25,161 | | | $ | 150,941 | | $ | 121,477 | |
| | Weighted average shares - basic | Weighted average shares - basic | 63,341 | | 62,575 | | | 62,950 | | 62,310 | | Weighted average shares - basic | 64,721 | | 62,867 | | | 64,643 | | 62,751 | |
| Dilutive effect of: | Dilutive effect of: | | Dilutive effect of: | |
| Equity compensation | Equity compensation | 95 | | 55 | | | 96 | | 52 | | Equity compensation | 162 | | 51 | | | 179 | | 66 | |
| Weighted average shares - diluted | Weighted average shares - diluted | 63,436 | | 62,630 | | | 63,046 | | 62,362 | | Weighted average shares - diluted | 64,883 | | 62,918 | | | 64,822 | | 62,817 | |
| | Earnings per share of common stock: | Earnings per share of common stock: | | Earnings per share of common stock: | |
| Earnings per share, Basic | Earnings per share, Basic | $ | 0.70 | | $ | 0.58 | | | $ | 2.63 | | $ | 2.41 | | Earnings per share, Basic | $ | 0.52 | | $ | 0.40 | | | $ | 2.33 | | $ | 1.94 | |
| Earnings per share, Diluted | Earnings per share, Diluted | $ | 0.70 | | $ | 0.58 | | | $ | 2.63 | | $ | 2.41 | | Earnings per share, Diluted | $ | 0.52 | | $ | 0.40 | | | $ | 2.33 | | $ | 1.93 | |
The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature (in thousands):
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2022 | 2021 | | 2022 | 2021 |
| | Equity compensation | Equity compensation | 9 | | 22 | | | 12 | | 22 | | Equity compensation | — | | 13 | | | — | | 12 | |
| Restricted stock | Restricted stock | — | | 49 | | | 1 | | 40 | | Restricted stock | — | | — | | | 1 | | 1 | |
| | Anti-dilutive shares | Anti-dilutive shares | 9 | | 71 | | | 13 | | 62 | | Anti-dilutive shares | — | | 13 | | | 1 | | 13 | |
(7) Risk Management and Derivatives
Market and Credit Risk Disclosures
Our activities in the regulated and non-regulated energy sectorsindustry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.
Market Risk
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed but not limited to, the following market risks, including, but not limited to:risks:
•Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities as well asand our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather (Winter Storm Uri), geopolitical events, market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and
•Interest rate risk associated with outstanding variable rate debt and future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.
Derivatives and Hedging Activity
Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 8.
The operations of our utilities,Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generating facilitiesgeneration plants or those facilitiesplants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatoryutility commissions, we have entered into commission-approvedcommission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions, are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.
We periodically use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers thatcustomers. Periodically, certain wholesale energy contracts are considered derivative instruments due to not qualifying for the normal purchasespurchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Condensed Consolidated Statements of Income.
We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such riskrisks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from October 2021July 2022 through AugustDecember 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.
The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We had the following net long positions as of:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 | | |
| Units | Notional
Amounts | | Maximum Term (months) (a) | | Notional
Amounts | | Maximum Term (months) (a) | | | | |
| Natural gas futures purchased | MMBtus | 1,700,000 | | | 6 | | 620,000 | | | 3 | | | | |
| Natural gas options purchased, net | MMBtus | 8,420,000 | | | 6 | | 3,160,000 | | | 3 | | | | |
| Natural gas basis swaps purchased | MMBtus | 1,500,000 | | | 6 | | 900,000 | | | 3 | | | | |
Natural gas over-the-counter swaps, net (b) | MMBtus | 5,920,000 | | | 35 | | 3,850,000 | | | 17 | | | | |
Natural gas physical contracts, net (c) | MMBtus | 18,758,835 | | | 7 | | 17,513,061 | | | 22 | | | | |
Electric wholesale contracts (c) | MWh | 65,625 | | | 3 | | 219,000 | | | 12 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 | | |
| Notional
Amounts (MMBtus) | | Maximum Term (months) (a) | | Notional
Amounts (MMBtus) | | Maximum Term (months) (a) | | | | |
| Natural gas futures purchased | 100,000 | | | 9 | | 590,000 | | | 3 | | | | |
| Natural gas options purchased, net | 430,000 | | | 9 | | 3,100,000 | | | 3 | | | | |
| Natural gas basis swaps purchased | — | | | 0 | | 870,000 | | | 3 | | | | |
Natural gas over-the-counter swaps, net (b) | 7,090,000 | | | 30 | | 4,570,000 | | | 34 | | | | |
Natural gas physical contracts, net (c) | 12,166,541 | | | 18 | | 16,416,677 | | | 24 | | | | |
| | | | | | | | | | | |
__________
(a) Term reflects the maximum forward period hedged.
(b) As of SeptemberJune 30, 2021, 2,700,0002022, 2,416,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c) Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.
We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At SeptemberJune 30, 2021,2022, the Company posted $0.9$0.4 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.
Derivatives by Balance Sheet Classification
As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements.agreements that allow us to settle positive and negative positions.
The following table presents the fair value and balance sheet classification of our derivative instruments (in thousands) as of:
| | | | | | | | | | | | | | |
| Balance Sheet Location | | September 30, 2021 | December 31, 2020 |
| Derivatives designated as hedges: | | | | |
| Asset derivative instruments: | | | | |
| Current commodity derivatives | Derivative assets, current | | $ | 6,989 | | $ | 181 | |
| Noncurrent commodity derivatives | Other assets, non-current | | 32 | | 43 | |
| Liability derivative instruments: | | | | |
| Current commodity derivatives | Derivative liabilities, current | | — | | (108) | |
| | | | |
| Total derivatives designated as hedges | | | $ | 7,021 | | $ | 116 | |
| | | | |
| Derivatives not designated as hedges: | | | | |
| Asset derivative instruments: | | | | |
| Current commodity derivatives | Derivative assets, current | | $ | 5,327 | | $ | 1,667 | |
| Noncurrent commodity derivatives | Other assets, non-current | | 1,580 | | 151 | |
| Liability derivative instruments: | | | | |
| Current commodity derivatives | Derivative liabilities, current | | (3,471) | | (1,936) | |
| | | | |
| Total derivatives not designated as hedges | | | $ | 3,436 | | $ | (118) | |
| | | | | | | | | | | |
| Balance Sheet Location | June 30, 2022 | December 31, 2021 |
| Derivatives designated as hedges: | | | |
| Asset derivative instruments: | | | |
| Current commodity derivatives | Derivative assets, current | $ | 2 | | $ | 2,017 | |
| Noncurrent commodity derivatives | Other assets, non-current | 256 | | 18 | |
| Liability derivative instruments: | | | |
| Current commodity derivatives | Derivative liabilities, current | (3,318) | | — | |
| | | |
| Total derivatives designated as hedges | | $ | (3,060) | | $ | 2,035 | |
| | | |
| Derivatives not designated as hedges: | | | |
| Asset derivative instruments: | | | |
| Current commodity derivatives | Derivative assets, current | $ | 714 | | $ | 2,356 | |
| Noncurrent commodity derivatives | Other assets, non-current | 923 | | 804 | |
| Liability derivative instruments: | | | |
| Current commodity derivatives | Derivative liabilities, current | (1,401) | | (1,439) | |
| Noncurrent commodity derivatives | Other deferred credits and other liabilities | — | | (20) | |
| Total derivatives not designated as hedges | | $ | 236 | | $ | 1,701 | |
Derivatives Designated as Hedge Instruments
The impacts of cash flow hedges on our Condensed Consolidated Statements of Comprehensive Income and Condensed Consolidated Statements of Income are presented below for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020.2021. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
| | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended June 30, | | Three Months Ended June 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2022 | 2021 | | 2022 | 2021 |
| Derivatives in Cash Flow Hedging Relationships | Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in OCI | Income Statement Location | Amount of Gain/(Loss) Reclassified from AOCI into Income | Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in OCI | Income Statement Location | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | (in thousands) | | (in thousands) | | (in thousands) | | (in thousands) |
| Interest rate swaps | Interest rate swaps | $ | 712 | | $ | 712 | | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | $ | (712) | | $ | (712) | | Interest rate swaps | $ | 713 | | $ | 713 | | Interest expense | $ | (713) | | $ | (713) | |
| Commodity derivatives | Commodity derivatives | 5,536 | | 691 | | Fuel, purchased power and cost of natural gas sold | 331 | | (178) | | Commodity derivatives | (4,371) | | 1,187 | | Fuel, purchased power and cost of natural gas sold | 1,323 | | 56 | |
| Total | Total | $ | 6,248 | | $ | 1,403 | | | $ | (381) | | $ | (890) | | Total | $ | (3,658) | | $ | 1,900 | | | $ | 610 | | $ | (657) | |
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2022 | 2021 | | 2022 | 2021 |
| Derivatives in Cash Flow Hedging Relationships | Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in OCI | Income Statement Location | Amount of Gain/(Loss) Reclassified from AOCI into Income | Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in OCI | Income Statement Location | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | (in thousands) | | (in thousands) | | (in thousands) | | (in thousands) |
| Interest rate swaps | Interest rate swaps | $ | 2,138 | | $ | 2,138 | | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | $ | (2,138) | | $ | (2,138) | | Interest rate swaps | $ | 1,426 | | $ | 1,426 | | Interest expense | $ | (1,426) | | $ | (1,426) | |
| Commodity derivatives | Commodity derivatives | 6,896 | | 959 | | Fuel, purchased power and cost of natural gas sold | 356 | | (734) | | Commodity derivatives | (5,238) | | 1,360 | | Fuel, purchased power and cost of natural gas sold | 3,577 | | 25 | |
| Total | Total | $ | 9,034 | | $ | 3,097 | | | $ | (1,782) | | $ | (2,872) | | Total | $ | (3,812) | | $ | 2,786 | | | $ | 2,151 | | $ | (1,401) | |
As of SeptemberJune 30, 2021, $4.02022, $6.1 million of net gainslosses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings as gains within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020.2021. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
| | | Three Months Ended September 30, | | Three Months Ended June 30, |
| | 2021 | 2020 | | 2022 | 2021 |
| Derivatives Not Designated as Hedging Instruments | Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | (in thousands) | | (in thousands) |
| Commodity derivatives - Electric | Commodity derivatives - Electric | Fuel, purchased power and cost of natural gas sold | $ | 2,494 | | $ | (1,386) | | Commodity derivatives - Electric | Fuel, purchased power and cost of natural gas sold | $ | — | | $ | (3,598) | |
| Commodity derivatives - Natural Gas | Commodity derivatives - Natural Gas | Fuel, purchased power and cost of natural gas sold | 4,004 | | 1,777 | | Commodity derivatives - Natural Gas | Fuel, purchased power and cost of natural gas sold | (2,332) | | 1,816 | |
| | $ | 6,498 | | $ | 391 | | | $ | (2,332) | | $ | (1,782) | |
| | | Nine Months Ended September 30, | | Six Months Ended June 30, |
| | 2021 | 2020 | | 2022 | 2021 |
| Derivatives Not Designated as Hedging Instruments | Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Derivatives Not Designated as Hedging Instruments | Income Statement Location | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | (in thousands) | | (in thousands) |
| Commodity derivatives - Electric | Commodity derivatives - Electric | Fuel, purchased power and cost of natural gas sold | $ | (2,628) | | $ | (228) | | Commodity derivatives - Electric | Fuel, purchased power and cost of natural gas sold | $ | — | | $ | (5,122) | |
| Commodity derivatives - Natural Gas | Commodity derivatives - Natural Gas | Fuel, purchased power and cost of natural gas sold | 6,186 | | 2,992 | | Commodity derivatives - Natural Gas | Fuel, purchased power and cost of natural gas sold | 1,162 | | 2,182 | |
| | $ | 3,558 | | $ | 2,764 | | | $ | 1,162 | | $ | (2,940) | |
As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. ThereHowever, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized (losses) or gainslosses included in our Regulatory asset or Regulatory liabilityaccounts related to the hedgesthese financial instruments in our Gas Utilities were $13.2$4.8 million and $(2.2)$2.6 million as of SeptemberJune 30, 20212022 and December 31, 2020,2021, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.
(8) Fair Value Measurements
We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:
Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.
Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.
Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Recurring Fair Value Measurements
Derivatives
The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVAcredit valuation adjustment based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 20202021 Annual Report on Form 10-K.
| | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting (a) | Total |
| (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 32,298 | | $ | — | | | $ | (18,370) | | $ | 13,928 | |
| Commodity derivatives — Electric Utilities | $ | — | | $ | — | | $ | — | | | $ | — | | $ | — | |
| Total | $ | — | | $ | 32,298 | | $ | — | | | $ | (18,370) | | $ | 13,928 | |
| | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 1,128 | | $ | — | | | $ | (141) | | $ | 987 | |
| Commodity derivatives — Electric Utilities | $ | — | | $ | 2,484 | | $ | — | | | $ | — | | $ | 2,484 | |
| Total | $ | — | | $ | 3,612 | | $ | — | | | $ | (141) | | $ | 3,471 | |
| | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2022 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting (a) | Total |
| (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 2,700 | | $ | — | | | $ | (806) | | $ | 1,894 | |
| | | | | | |
| Total | $ | — | | $ | 2,700 | | $ | — | | | $ | (806) | | $ | 1,894 | |
| | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 5,524 | | $ | — | | | $ | (805) | | $ | 4,719 | |
| | | | | | |
| Total | $ | — | | $ | 5,524 | | $ | — | | | $ | (805) | | $ | 4,719 | |
__________(a) As of SeptemberJune 30, 2021, $182022, $0.8 million of our commodity derivative assets and $0.1$0.8 million of our commodity liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2021 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting (a) | Total |
| (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 7,569 | | $ | — | | | $ | (2,374) | | $ | 5,195 | |
| | | | | | |
| Total | $ | — | | $ | 7,569 | | $ | — | | | $ | (2,374) | | $ | 5,195 | |
| | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 3,273 | | $ | — | | | $ | (1,814) | | $ | 1,459 | |
| | | | | | |
| Total | $ | — | | $ | 3,273 | | $ | — | | | $ | (1,814) | | $ | 1,459 | |
__________
(a) As of December 31, 2021, $2.4 million of our commodity derivative assets and $1.8 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting (a) | Total |
| (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 2,504 | | $ | — | | | $ | (1,527) | | $ | 977 | |
| Commodity derivatives — Electric Utilities | $ | — | | $ | 1,065 | | $ | — | | | $ | — | | $ | 1,065 | |
| Total | $ | — | | $ | 3,569 | | $ | — | | | $ | (1,527) | | $ | 2,042 | |
| | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Gas Utilities | $ | — | | $ | 2,675 | | $ | — | | | $ | (1,552) | | $ | 1,123 | |
| Commodity derivatives — Electric Utilities | $ | — | | $ | 921 | | $ | — | | | $ | — | | $ | 921 | |
| Total | $ | — | | $ | 3,596 | | $ | — | | | $ | (1,552) | | $ | 2,044 | |
__________
(a) As of December 31, 2020, $1.5 million of our commodity derivative assets and $1.6 million of our commodity derivative liabilities, as well as related collateral amounts, were subject to master netting agreements. Collateral amounts are included in Other current assets on the Condensed Consolidated Balance Sheets.
Pension and Postretirement Plan Assets
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 1513 to the Consolidated Financial Statements included in our 20202021 Annual Report on Form 10-K.
Other fair value measuresFair Value Measures
The carrying amount of cash and cash equivalents, restricted cash and equivalents and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange,exchange; therefore, they are classified inas Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Carrying
Amount | Fair Value | | Carrying
Amount | Fair Value |
Long-term debt, including current maturities (a) | $ | 4,125,571 | | $ | 4,614,244 | | | $ | 3,536,536 | | $ | 4,208,167 | |
| | | | | | | | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Carrying
Amount | Fair Value | | Carrying
Amount | Fair Value |
Long-term debt, including current maturities (a) | $ | 4,129,662 | | $ | 3,917,015 | | | $ | 4,126,923 | | $ | 4,570,619 | |
__________
(a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified asin Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.
(9) Other Comprehensive Income
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.
The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Location on the Condensed Consolidated Statements of Income | Amount Reclassified from AOCI |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
| Gains and (losses) on cash flow hedges: | | | | | | |
| Interest rate swaps | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | $ | (712) | | $ | (712) | | | $ | (2,138) | | $ | (2,138) | |
| Commodity contracts | Fuel, purchased power and cost of natural gas sold | 331 | | (178) | | | 356 | | (734) | |
| | (381) | | (890) | | | (1,782) | | (2,872) | |
| Income tax | Income tax (expense) | (26) | | 209 | | | 308 | | 680 | |
| Total reclassification adjustments related to cash flow hedges, net of tax | | $ | (407) | | $ | (681) | | | $ | (1,474) | | $ | (2,192) | |
| | | | | | |
| Amortization of components of defined benefit plans: | | | | | | |
| Prior service cost | Operations and maintenance | $ | 25 | | $ | 24 | | | $ | 74 | | $ | 79 | |
| Actuarial gain (loss) | Operations and maintenance | (598) | | (597) | | | (1,793) | | (1,791) | |
| | (573) | | (573) | | | (1,719) | | (1,712) | |
| Income tax | Income tax (expense) | 133 | | 143 | | | 492 | | 407 | |
| Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (440) | | $ | (430) | | | $ | (1,227) | | $ | (1,305) | |
| Total reclassifications | | $ | (847) | | $ | (1,111) | | | $ | (2,701) | | $ | (3,497) | |
| | | | | | | | | | | | | | | | | | | | |
| Location on the Condensed Consolidated Statements of Income | Amount Reclassified from AOCI | | Amount Reclassified from AOCI |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | 2021 | | 2022 | 2021 |
| Gains and (losses) on cash flow hedges: | | | | | | |
| Interest rate swaps | Interest expense | $ | (713) | | $ | (713) | | | $ | (1,426) | | $ | (1,426) | |
| Commodity contracts | Fuel, purchased power and cost of natural gas sold | 1,323 | | 56 | | | 3,577 | | 25 | |
| | 610 | | (657) | | | 2,151 | | (1,401) | |
| Income tax | Income tax expense | (81) | | 136 | | | (456) | | 334 | |
| Total reclassification adjustments related to cash flow hedges, net of tax | | $ | 529 | | $ | (521) | | | $ | 1,695 | | $ | (1,067) | |
| | | | | | |
| Amortization of components of defined benefit plans: | | | | | | |
| Prior service cost | Operations and maintenance | $ | 22 | | $ | 24 | | | $ | 46 | | $ | 49 | |
| Actuarial gain (loss) | Operations and maintenance | (187) | | (597) | | | (375) | | (1,195) | |
| | (165) | | (573) | | | (329) | | (1,146) | |
| Income tax | Income tax expense | 60 | | 151 | | | 99 | | 359 | |
| Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (105) | | $ | (422) | | | $ | (230) | | $ | (787) | |
| Total reclassifications | | $ | 424 | | $ | (943) | | | $ | 1,465 | | $ | (1,854) | |
Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
| | | | | | | | | | | | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2020 | $ | (12,558) | | $ | 2 | | $ | (14,790) | | $ | (27,346) | |
| Other comprehensive income (loss) | | | | |
| before reclassifications | — | | 5,476 | | — | | 5,476 | |
| Amounts reclassified from AOCI | 1,743 | | (269) | | 1,227 | | 2,701 | |
| As of September 30, 2021 | $ | (10,815) | | $ | 5,209 | | $ | (13,563) | | $ | (19,169) | |
| | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2019 | $ | (15,122) | | $ | (456) | | $ | (15,077) | | $ | (30,655) | |
| Other comprehensive income (loss) | | | | |
| before reclassifications | — | | 181 | | 55 | | 236 | |
| Amounts reclassified from AOCI | 1,630 | | 562 | | 1,305 | | 3,497 | |
| As of September 30, 2020 | $ | (13,492) | | $ | 287 | | $ | (13,717) | | $ | (26,922) | |
| | | | | | | | | | | | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2021 | $ | (10,384) | | $ | 1,476 | | $ | (11,176) | | $ | (20,084) | |
| Other comprehensive income (loss) | | | | |
| before reclassifications | — | | (1,267) | | — | | (1,267) | |
| Amounts reclassified from AOCI | 1,011 | | (2,706) | | 230 | | (1,465) | |
| As of June 30, 2022 | $ | (9,373) | | $ | (2,497) | | $ | (10,946) | | $ | (22,816) | |
| | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2020 | $ | (12,558) | | $ | 2 | | $ | (14,790) | | $ | (27,346) | |
| Other comprehensive income (loss) | | | | |
| before reclassifications | — | | 1,046 | | — | | 1,046 | |
| Amounts reclassified from AOCI | 1,086 | | (19) | | 787 | | 1,854 | |
| As of June 30, 2021 | $ | (11,472) | | $ | 1,029 | | $ | (14,003) | | $ | (24,446) | |
(10) Employee Benefit Plans
Defined Benefit Pension PlanComponents of Net Periodic Expense
The components of net periodic benefit cost for the Defined Benefit Pension Planexpense were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
| Service cost | $ | 1,260 | | $ | 1,352 | | | $ | 3,779 | | $ | 4,058 | |
| Interest cost | 2,328 | | 3,356 | | | 6,984 | | 10,069 | |
| Expected return on plan assets | (5,219) | | (5,647) | | | (15,657) | | (16,943) | |
| | | | | |
| Net loss | 1,828 | | 2,093 | | | 5,486 | | 6,279 | |
| Net periodic benefit cost | $ | 197 | | $ | 1,154 | | | $ | 592 | | $ | 3,463 | |
| | | | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| Three Months Ended June 30, | 2022 | 2021 | 2022 | 2021 | 2022 | 2021 |
| Net Service cost | $ | 982 | | $ | 1,260 | | $ | (1,355) | | $ | 1,020 | | $ | 492 | | $ | 559 | |
| Interest cost | 2,704 | | 2,328 | | 209 | | 177 | | 321 | | 264 | |
| Expected return on plan assets | (4,630) | | (5,219) | | — | | — | | (31) | | (34) | |
| Net amortization of prior service costs | (17) | | — | | — | | — | | (73) | | (109) | |
| Recognized net actuarial loss | 1,523 | | 1,829 | | 69 | | 438 | | 16 | | 117 | |
| Net periodic expense (benefit) | $ | 562 | | $ | 198 | | $ | (1,077) | | $ | 1,635 | | $ | 725 | | $ | 797 | |
Defined Benefit Postretirement Healthcare Plan
The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
| Service cost | $ | 560 | | $ | 514 | | | $ | 1,678 | | $ | 1,542 | |
| Interest cost | 264 | | 412 | | | 793 | | 1,237 | |
| Expected return on plan assets | (34) | | (46) | | | (102) | | (137) | |
| Prior service cost (benefit) | (108) | | (136) | | | (326) | | (410) | |
| Net loss | 116 | | 5 | | | 350 | | 15 | |
| Net periodic benefit cost | $ | 798 | | $ | 749 | | | $ | 2,393 | | $ | 2,247 | |
| | | | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| Six Months Ended June 30, | 2022 | 2021 | 2022 | 2021 | 2022 | 2021 |
| Net Service cost | $ | 1,964 | | $ | 2,519 | | $ | (1,747) | | $ | 1,713 | | $ | 984 | | $ | 1,118 | |
| Interest cost | 5,409 | | 4,656 | | 417 | | 354 | | 642 | | 529 | |
| Expected return on plan assets | (9,261) | | (10,438) | | — | | — | | (62) | | (68) | |
| Net amortization of prior service costs | (34) | | — | | — | | — | | (145) | | (218) | |
| Recognized net actuarial loss | 3,046 | | 3,658 | | 138 | | 877 | | 32 | | 234 | |
| Net periodic expense (benefit) | $ | 1,124 | | $ | 395 | | $ | (1,192) | | $ | 2,944 | | $ | 1,451 | | $ | 1,595 | |
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
| Service cost | $ | 235 | | $ | 1,035 | | | $ | 1,948 | | $ | 1,482 | |
| Interest cost | 176 | | 274 | | | 530 | | 824 | |
| Prior service cost | — | | 1 | | | — | | 1 | |
| Net loss | 439 | | 425 | | | 1,316 | | 1,277 | |
| Net periodic benefit cost | $ | 850 | | $ | 1,735 | | | $ | 3,794 | | $ | 3,584 | |
Plan Contributions
Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in the first ninesix months of 20212022 and anticipated contributions for 20212022 and 20222023 are as follows (in thousands):
| | | | | | | | | | | | |
| | Contributions Made | Additional Contributions | Contributions |
| | Nine Months Ended September 30, 2021 | Anticipated for 2021 | Anticipated for 2022 |
| Defined Benefit Pension Plan | | $ | — | | $ | — | | $ | 3,900 | |
| Non-pension Defined Benefit Postretirement Healthcare Plan | | $ | 4,145 | | $ | 1,382 | | $ | 5,202 | |
| Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | | $ | 1,445 | | $ | 482 | | $ | 2,149 | |
| | | | | | | | | | | | |
| | Contributions Made | Additional Contributions | Contributions |
| | Six Months Ended June 30, 2022 | Anticipated for 2022 | Anticipated for 2023 |
| Defined Benefit Pension Plan | | $ | — | | $ | — | | $ | — | |
| Non-pension Defined Benefit Postretirement Healthcare Plan | | $ | 2,552 | | $ | 2,552 | | $ | 4,761 | |
| Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | | $ | 1,078 | | $ | 1,078 | | $ | 2,215 | |
Funding Status of Employee Benefit Plans
Based on the fair value of assets and estimated discount rate used to value benefit obligations as of June 30, 2022, we estimate the unfunded status of our employee benefit plans to be approximately $29 million compared to $20 million at December 31, 2021. In 2012, we froze our pension plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility has not materially affected our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.
(11) Income Taxes
Winter Storm Uri
As discussed in Note 2 above, our Utilities submitted cost recovery applications which seek to recover incremental costs from Winter Storm Uri through a regulatory mechanism. We expect to recover these costs from customers over several years. Winter Storm Uri costs, which will be deductible in our 2021 tax return, created a net deferred tax liability of approximately $130 million. The deferred tax liability will reverse with the same timing as the costs are recovered from our customers.
The income tax deduction recognized from Winter Storm Uri will create a NOL in our 2021 federal and state income tax returns. Our federal NOL carryforwards no longer expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2021 to 2041. We do not anticipate material changes to our valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of September 30, 2021.
Income Tax (Expense)Expense (Benefit) and Effective Tax Rates
Three Months Ended SeptemberJune 30, 20212022 Compared to the Three Months Ended SeptemberJune 30, 20202021
Income tax (expense) and the effective tax rate were comparable to the same period in the prior year.
Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020
Income tax (expense)expense (benefit) for the ninethree months ended SeptemberJune 30, 20212022 was $(6.3)$(0.7) million compared to $(25)$0.6 million reported for the same period in 2020.2021. For the ninethree months ended SeptemberJune 30, 2021,2022 the effective tax rate was 3.5%(1.9)% compared to 13.6%2.0% for the same period in 2020.2021. The lower effective tax rate iswas primarily due to $3.8 million of tax benefits from state rate changes, $1.5 million of increased tax benefits from federal PTCs associated with increased wind production and a current year PTC rate increase (inflation adjustment). These current year tax benefits were greater than prior year tax benefits from Nebraska Gas TCJA-related bill credits to customers (which were offset by reduced revenue) and prior year flow-through tax benefits related to repairs and certain indirect costs.
Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021
Income tax expense for the six months ended June 30, 2022 was $14 million compared to $1.1 million reported for the same period in 2021. For the six months ended June 30, 2022, the effective tax rate was 8.1% compared to 0.8% for the same period in 2021. The higher effective tax rate was primarily due to $10 million of increasedprior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which iswere offset by reduced revenue), $3.2 partially offset by $3.8 million of current year tax benefits from state rate changes and $2.4 million of increased tax benefits from federal production tax creditsPTCs associated with newincreased wind assets, $2.2 millionproduction and a current year PTC rate increase (inflation adjustment).
(12) Business Segment Information
Our CODM reviews financial information presented on an operating segment basis for purposes of increased tax benefits from amortizationmaking decisions and assessing financial performance. Our CODM assesses the performance of excess deferred income taxes, $1.9 millionour operating segments based on operating income.
For the first nine months of tax benefits from various statutory rate changes2021, we had reported 4 operating segments: Electric Utilities, Gas Utilities, Power Generation and $1.1 millionMining. In the fourth quarter of increased flow-through tax benefits2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to repairs and certain indirect costs. These current year tax benefits were partially offset by a prior year tax benefit from the reversalallocation of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans.resources. Comparative periods presented reflect this change.
Our operating segments are equivalent to our reportable segments.
Segment information was as follows (in thousands):
| | | | | | | | | | | |
| Total assets (net of intercompany eliminations) as of: | June 30, 2022 | | December 31, 2021 |
| Electric Utilities | $ | 3,834,826 | | | $ | 3,796,662 | |
| Gas Utilities | 5,197,194 | | | 5,246,370 | |
| Corporate and Other | 102,542 | | | 88,864 | |
| Total assets | $ | 9,134,562 | | | $ | 9,131,896 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2022 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 198,380 | | $ | 3,070 | | | $ | 2,929 | | $ | — | | | $ | 204,379 | |
| Gas Utilities | 271,944 | | 801 | | | 1,319 | | 105 | | | 274,169 | |
| Inter-company eliminations | — | | — | | | (4,248) | | (105) | | | (4,353) | |
| Total | $ | 470,324 | | $ | 3,871 | | | $ | — | | $ | — | | | $ | 474,195 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 185,235 | | $ | 2,900 | | | $ | 2,881 | | $ | — | | | $ | 191,016 | |
| Gas Utilities | 183,187 | | 1,250 | | | 1,519 | | 94 | | | 186,050 | |
| Inter-company eliminations | — | | — | | | (4,400) | | (94) | | | (4,494) | |
| Total | $ | 368,422 | | $ | 4,150 | | | $ | — | | $ | — | | | $ | 372,572 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2022 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 401,119 | | $ | 3,940 | | | $ | 5,858 | | $ | — | | | $ | 410,917 | |
| Gas Utilities | 890,974 | | 1,732 | | | 2,638 | | 217 | | | 895,561 | |
| Inter-company eliminations | — | | — | | | (8,496) | | (217) | | | (8,713) | |
| Total | $ | 1,292,093 | | $ | 5,672 | | | $ | — | | $ | — | | | $ | 1,297,765 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 416,954 | | $ | 3,706 | | | $ | 5,760 | | $ | — | | | $ | 426,420 | |
| Gas Utilities | 581,686 | | 3,658 | | | 3,039 | | 186 | | | 588,569 | |
| Inter-company eliminations | — | | — | | | (8,799) | | (186) | | | (8,985) | |
| Total | $ | 998,640 | | $ | 7,364 | | | $ | — | | $ | — | | | $ | 1,006,004 | |
(12) Business Segment Information
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the CODM assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.
Segment information was as follows (in thousands):
| | | | | | | | | | | |
| Total assets (net of intercompany eliminations) as of: | September 30, 2021 | | December 31, 2020 |
| Electric Utilities | $ | 3,267,074 | | | $ | 3,120,928 | |
| Gas Utilities | 5,052,898 | | | 4,376,204 | |
| Power Generation | 398,915 | | | 404,220 | |
| Mining | 76,791 | | | 77,085 | |
| Corporate and Other | 114,712 | | | 110,349 | |
| Total assets | $ | 8,910,390 | | | $ | 8,088,786 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended September 30, 2021 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 207,374 | | $ | 203 | | | $ | 5,526 | | $ | — | | | $ | 213,103 | |
| Gas Utilities | 161,977 | | 1,087 | | | 1,520 | | 99 | | | 164,683 | |
| Power Generation | 2,333 | | 412 | | | 23,725 | | 50 | | | 26,520 | |
| Mining | 6,969 | | 235 | | | 8,845 | | 339 | | | 16,388 | |
| Inter-company eliminations | — | | — | | | (39,616) | | (488) | | | (40,104) | |
| Total | $ | 378,653 | | $ | 1,937 | | | $ | — | | $ | — | | | $ | 380,590 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended September 30, 2020 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 194,941 | | $ | 224 | | | $ | 5,677 | | $ | — | | | $ | 200,842 | |
| Gas Utilities | 141,275 | | 863 | | | 1,601 | | 190 | | | 143,929 | |
| Power Generation | 1,528 | | 414 | | | 24,521 | | 55 | | | 26,518 | |
| Mining | 6,568 | | 777 | | | 8,100 | | (209) | | | 15,236 | |
| Inter-company eliminations | — | | — | | | (39,899) | | (36) | | | (39,935) | |
| Total | $ | 344,312 | | $ | 2,278 | | | $ | — | | $ | — | | | $ | 346,590 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2021 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 604,966 | | $ | 2,619 | | | $ | 17,859 | | $ | — | | | $ | 625,444 | |
| Gas Utilities | 743,663 | | 4,745 | | | 4,559 | | 285 | | | 753,252 | |
| Power Generation | 8,006 | | 1,219 | | | 71,656 | | 150 | | | 81,031 | |
| Mining | 20,658 | | 718 | | | 23,093 | | 1,020 | | | 45,489 | |
| Inter-company eliminations | — | | — | | | (117,167) | | (1,455) | | | (118,622) | |
| Total | $ | 1,377,293 | | $ | 9,301 | | | $ | — | | $ | — | | | $ | 1,386,594 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Nine Months Ended September 30, 2020 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
| Segment: | | | | | | | |
| Electric Utilities | $ | 518,641 | | $ | 2,074 | | | $ | 17,466 | | $ | — | | | $ | 538,181 | |
| Gas Utilities | 655,386 | | 7,083 | | | 3,153 | | 190 | | | 665,812 | |
| Power Generation | 4,625 | | 1,206 | | | 72,609 | | 166 | | | 78,606 | |
| Mining | 20,062 | | 1,477 | | | 23,855 | | 463 | | | 45,857 | |
| Inter-company eliminations | — | | — | | | (117,083) | | (819) | | | (117,902) | |
| Total | $ | 1,198,714 | | $ | 11,840 | | | $ | — | | $ | — | | | $ | 1,210,554 | |
| | | | Three Months Ended June 30, | Six Months Ended June 30, |
| | Three Months Ended September 30, | Nine Months Ended September 30, | | 2022 | 2021 | 2022 | 2021 |
| 2021 | 2020 | 2021 | 2020 | |
| Adjusted operating income: | | |
| Operating income (loss): | | Operating income (loss): | |
| Electric Utilities | Electric Utilities | $ | 57,608 | | $ | 52,083 | | $ | 114,989 | | $ | 121,726 | | Electric Utilities | $ | 45,226 | | $ | 47,462 | | $ | 95,972 | | $ | 86,805 | |
| Gas Utilities | Gas Utilities | 17,257 | | 18,147 | | 139,336 | | 139,253 | | Gas Utilities | 28,195 | | 19,985 | | 151,735 | | 122,079 | |
| Power Generation | 10,323 | | 8,738 | | 32,842 | | 31,489 | | |
| Mining | 4,908 | | 3,505 | | 11,813 | | 9,992 | | |
| Corporate and Other | Corporate and Other | (223) | | (239) | | (3,526) | | (108) | | Corporate and Other | (1,032) | | (181) | | (1,965) | | (3,303) | |
| Operating income | Operating income | 89,873 | | 82,234 | | 295,454 | | 302,352 | | Operating income | 72,389 | | 67,266 | | 245,742 | | 205,581 | |
| | Interest expense, net | Interest expense, net | (38,018) | | (36,041) | | (113,820) | | (107,039) | | Interest expense, net | (38,764) | | (38,202) | | (77,309) | | (75,802) | |
| Impairment of investment | — | | — | | — | | (6,859) | | |
| Other income (expense), net | Other income (expense), net | 1,560 | | (1,193) | | 1,635 | | (703) | | Other income (expense), net | 1,563 | | (191) | | 2,267 | | 75 | |
| Income tax (expense) | (5,253) | | (4,651) | | (6,333) | | (25,484) | | |
| Income tax benefit (expense) | | Income tax benefit (expense) | 658 | | (586) | | (13,830) | | (1,080) | |
| Net income | Net income | 48,162 | | 40,349 | | 176,936 | | 162,267 | | Net income | 35,846 | | 28,287 | | 156,870 | | 128,774 | |
| Net income attributable to non-controlling interest | Net income attributable to non-controlling interest | (4,050) | | (4,066) | | (11,347) | | (11,844) | | Net income attributable to non-controlling interest | (2,431) | | (3,126) | | (5,929) | | (7,297) | |
| Net income available for common stock | Net income available for common stock | $ | 44,112 | | $ | 36,283 | | $ | 165,589 | | $ | 150,423 | | Net income available for common stock | $ | 33,415 | | $ | 25,161 | | $ | 150,941 | | $ | 121,477 | |
(13) Selected Balance Sheet Information
Accounts Receivable and Allowance for Credit Losses
Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Accounts receivable, trade | $ | 120,930 | | | $ | 146,899 | |
| Unbilled revenue | 63,338 | | | 126,065 | |
| Less: Allowance for credit losses | (2,312) | | | (7,003) | |
| Accounts receivable, net | $ | 181,956 | | | $ | 265,961 | |
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Billed Accounts Receivable | $ | 188,649 | | | $ | 181,027 | |
| Unbilled Revenue | 81,647 | | | 142,738 | |
| Less: Allowance for Credit Losses | (3,193) | | | (2,113) | |
| Accounts Receivable, net | $ | 267,103 | | | $ | 321,652 | |
Changes to allowance for credit losses for the ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, respectively, were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance at Beginning of Year | | | | Additions Charged to Costs and Expenses | | Recoveries and Other Additions | | Write-offs and Other Deductions | | Balance at September 30, |
| 2021 | | $ | 7,003 | | | | | $ | 1,111 | | | $ | 2,420 | | | $ | (8,222) | | | $ | 2,312 | |
| 2020 | | $ | 2,444 | | | | | $ | 8,471 | | | $ | 3,720 | | | $ | (6,026) | | | $ | 8,609 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance at Beginning of Year | | | | Additions Charged to Costs and Expenses | | Recoveries and Other Additions | | Write-offs and Other Deductions | | Balance at June 30, |
| 2022 | | $ | 2,113 | | | | | $ | 4,239 | | | $ | 1,266 | | | $ | (4,425) | | | $ | 3,193 | |
| 2021 | | $ | 7,003 | | | | | $ | 1,510 | | | $ | 1,786 | | | $ | (4,270) | | | $ | 6,029 | |
Materials, Supplies and Fuel
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Materials and supplies | $ | 85,612 | | | $ | 85,250 | |
| Fuel - Electric Utilities | 1,240 | | | 1,531 | |
| Natural gas in storage | 58,891 | | | 30,619 | |
| Total materials, supplies and fuel | $ | 145,743 | | | $ | 117,400 | |
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Materials and supplies | $ | 91,736 | | | $ | 86,400 | |
| Fuel - Electric Utilities | 2,169 | | | 1,267 | |
| Natural gas in storage | 58,959 | | | 63,312 | |
| Total materials, supplies and fuel | $ | 152,864 | | | $ | 150,979 | |
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | |
| September 30, 2021 | December 31, 2020 |
| Accrued employee compensation, benefits and withholdings | $ | 72,328 | | $ | 77,806 | |
| Accrued property taxes | 44,231 | | 47,105 | |
| Customer deposits and prepayments | 53,652 | | 52,185 | |
| Accrued interest | 46,532 | | 31,520 | |
| Other (none of which is individually significant) | 33,092 | | 34,996 | |
| Total accrued liabilities | $ | 249,835 | | $ | 243,612 | |
| | | | | | | | | | | |
| June 30, 2022 | | December 31, 2021 |
| Accrued employee compensation, benefits and withholdings | $ | 64,417 | | | $ | 74,387 | |
| Accrued property taxes | 42,944 | | | 50,874 | |
| Customer deposits and prepayments | 43,151 | | | 48,814 | |
| Accrued interest | 33,764 | | | 33,680 | |
| Other (none of which is individually significant) | 42,044 | | | 37,004 | |
| Total accrued liabilities | $ | 226,320 | | | $ | 244,759 | |
(14) Subsequent Events
We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the condensed consolidated financial statements or disclosures, with the exception of Colorado Gas, Kansas Gas and Wyoming Gas regulatory activity disclosed in Note 2.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2020our 2021 Form 10-K.
Executive Summary
We are a customer-focused growth-oriented electricenergy solutions provider that invests in our communities’ safety, sustainability and natural gas utility companygrowth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice.Choice. The Company providesCompany’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas utility service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.
Recent Developments
Winter Storm Uri
In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental natural gas and fuel costs.
On February 24,In 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.
During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, severalwe have received final commission approval for all of our Utilities have receivedWinter Storm Uri cost recovery applications with the exception of Wyoming Gas (which is approved for interim or final Commission Orders and have begun recovering costs from customers.cost recovery). See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information on our regulatory activity.information.
COVID-19 UpdateMacroeconomic Trends
ForWe are monitoring macroeconomic trends including inflationary pressures on the nine months ended September 30, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential forprices of commodities, materials, outside services and employee costs; supply chain disruption that may impact our capitalconstraints; rising interest rates and maintenance project plans, the availability of third-party resources to execute our business plansa competitive and the capital markets to ensuretight labor market. To date, we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.experienced moderate net impacts from these trends.
On September 9, 2021We have seen an increase in commodity energy costs that had an effect on customer bills. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the Biden administration announced a mandatory COVID-19 vaccination plan,customer, which directs OSHAmitigates our exposure. Customer billing rates are adjusted periodically to develop a rule requiring employers with 100 or more employees to ensure their workforce is fully vaccinated or require any workers who remain unvaccinated to produce a negative test result on at least a weekly basis. We are closely monitoring updates from OSHA including the effective datereflect changes in our cost of this rule. If an OSHA vaccine rule is implemented, the extent of the regulatory impact is unclear but it could have an adverse impact on the Company's workforce, labor relations and operations.energy.
As we look forward,We are proactively managing increased costs of materials and supply chain disruptions to achieve our operating results could be affected by COVID-19 as discussed inforecasted capital investment targets. We have already contracted a significant majority of the “Risk Factors” section in Part I, Item 1Amaterials needed for our 2022 capital program. We have also evaluated each of our 2020 Annual Reportforecasted projects and will prioritize depending on Form 10-K.
Business Segment Highlights and Corporate Activity
Electric Utilities
•Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 285-mile, multi-phase transmission expansion project will serve the growing needs of customers by enhancing the resiliency of its overall electric system and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic growth in the Cheyenne region. Wyoming Electric plans to file an application seeking WPSC approval for the project in the first quarter of 2022. If approved, construction is expected to commence in early 2023.
•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.future constraints. Project delays may occur if costs rise significantly or if materials are not available.
Rising interest rates have increased interest expense on our variable rate borrowings, which include our Revolving Credit Facility and CP Program. However, the increased interest expense was limited since 92% of our debt at June 30, 2022 is fixed rate debt. Additionally, rising discount rates and recent capital markets volatility did not materially change the unfunded status of the BHC Pension Plan from the prior year.
We are faced with increased competition for employee and contractor talent in the current labor market. To date, we have seen increased employee and contractor costs related to attraction and retention of talent partially offset by decreases in headcount compared to the prior year.
More detailed discussion of the future uncertainties can be found in “Risk Factors” section in Part I, Item 1A of our 2021 Annual Report on Form 10-K.
Business Segment Recent Developments
Electric Utilities
•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent rate review activity for Wyoming Electric.
•On July 27, 2021,21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set on July 28, 2021.
•On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 397403 MW, exceedingsurpassing the previous summer peak of 378397 MW set in August 2020.July 2021.
•On June 30, 2021, South Dakota Electric and21, 2022, Wyoming Electric submittedcompleted its first agreement for service under its Blockchain Interruptible Service tariff. Under the five-year agreement, Wyoming Electric will deliver to a new customer in Cheyenne, Wyoming up to 45 MW with an IRPoption to expand service up to 75 MW. Energy will be sourced through the SDPUCelectric energy market and WPSC.delivered through our Electric Utilities’ infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs of Wyoming Electric’s existing retail customers. Wyoming Electric expects to begin delivering energy to this customer in the fourth quarter of 2022.
•On May 27, 2022, Colorado Electric filed its Clean Energy Plan, “2030 Ready Plan”, with the CPUC. The IRP outlines2030 Ready Plan establishes a rangeroadmap and preferred resource portfolio for Colorado Electric to cost-effectively achieve the state of options for the twoColorado’s requirement calling upon electric utilities to meet long-term forecasted energy needs overreduce GHG emissions by a 20-year planning horizon.minimum of 80% by 2030. The analysis focused on the least-costpreferred resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. The IRP’s preferred optionsportfolio calls for the near-term planning period through 2026 propose the addition of 100149 MW of renewable generation, the conversionwind, 258 MW of Neil Simpson II to natural gas in 2025solar and consideration of up to 2050 MW of battery storage.storage to Colorado Electric's system. The final mix of resources would be determined by the results of a competitive solicitation starting in 2023. Colorado legislation provides up to 50% utility ownership of these additions. As proposed, the plan will achieve a 90% reduction in emissions and result in 79% of Colorado Electric’s customers' electricity being generated by carbon-free sources by 2030. A CPUC decision on Phase 1 of the 2030 Ready Plan is expected by April 2023, which would be followed by a request for proposals for renewable energy resources.
•On February 19, 2021, Colorado23, 2022, Wyoming Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction ofset a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed bywinter peak load of 262 MW, surpassing the endprevious winter peak of 2023. This agreement will expire 15 years after construction completion. The utility-scale solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan. With the addition of 200252 MW of solar energyset on its system, more than half of Colorado Electric’s generation is forecasted to be sourced from renewable energy resources by 2023, leading to a 70% reduction in carbon emissions by 2024 compared to the 2005 base year.January 5, 2022.
•On February 11, 2021,15, 2022, Wyoming Electric submitted a request to the WPSC seeking approval for a CPCN to construct an estimated 260-mile transmission expansion project. As proposed, the approximately $260 million transmission expansion project, known as Ready Wyoming, would provide customers long-term price stability and greater flexibility as power markets develop in the Western States. If approved, construction of the project would take place in multiple phases or segments spanning 2023 through 2025 and would interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.
•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market.
•In January 2022, South Dakota Electric placed in service a $19 million, 54-mile, 230 kV electric transmission line from Rapid City to Spearfish, South Dakota. The second leg of this transmission line rebuild project, an 85-mile segment from Spearfish to Gillette, Wyoming, is expected to be in service by the end of 2023.
•On January 5, 2022, South Dakota Electric and Wyoming Electric set anew winter peak loads. Wyoming Electric’s new winter peak load of 326252 MW surpassingsurpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 320326 MW set in February 2019.2021.
Gas Utilities
•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent regulatoryrate review activity for our Gas Utilities in Colorado, Iowa, Kansas and Nebraska.Arkansas Gas.
Power Generation
•In September 2021, Wygen I experienced an unplanned outage which hadOn June 6, 2022, Colorado Gas submitted a $2.3 million negative impactproposal to operating incomethe CPUC seeking approval to offer a voluntary RNG and carbon offset program for residential and business customers. The program would allow participants to offset 100% or more of the threeemissions associated with their own natural gas usage. The offset would be achieved through a combination of carbon offset credits and nine months ended September 30, 2021.RNG attributes. Colorado Gas has designed its voluntary RNG and carbon offset program as a comprehensive four-year pilot program starting in 2023 and running through 2026. On July 15, 2022, Kansas Gas submitted a similar RNG and carbon offset program proposal with the KCC. Nebraska Gas expects to submit a voluntary RNG and carbon offset program proposal to the NPSC later in 2022 with similar filings for Arkansas Gas, Iowa Gas and Wyoming Gas expected by 2023.
Corporate and Other
•On August 26, 2021,April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3-million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. We believe we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds fromhave meritorious defenses to the offering were usedverdict and intend to repay amounts outstanding under our term loan entered into on February 24, 2021.appeal the verdict. See additional information in Note 53 of the Notes to Condensed Consolidated Financial Statements for further information.
•On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 5 of the Notes to Condensed Consolidated Financial Statements for further information.Statements.
Results of Operations
The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.
Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, and our financial condition as of SeptemberJune 30, 20212022 and December 31, 2020,2021, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change. See further segment information in Note 12 of the Notes to Condensed Consolidated Financial Statements.
Segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.
Consolidated Summary and Overview
| | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 | |
| (in thousands, except per share amounts) |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
Adjusted operating income (a): | | | | | | |
| Electric Utilities | $ | 57,608 | | $ | 52,083 | | | $ | 114,989 | | $ | 121,726 | | |
| Gas Utilities | 17,257 | | 18,147 | | | 139,336 | | 139,253 | | |
| Power Generation | 10,323 | | 8,738 | | | 32,842 | | 31,489 | | |
| Mining | 4,908 | | 3,505 | | | 11,813 | | 9,992 | | |
| Corporate and Other | (223) | | (239) | | | (3,526) | | (108) | | |
| Operating income | 89,873 | | 82,234 | | | 295,454 | | 302,352 | | |
| | | | | | |
| Interest expense, net | (38,018) | | (36,041) | | | (113,820) | | (107,039) | | |
| Impairment of investment | — | | — | | | — | | (6,859) | | |
| Other income (expense), net | 1,560 | | (1,193) | | | 1,635 | | (703) | | |
| Income tax (expense) | (5,253) | | (4,651) | | | (6,333) | | (25,484) | | |
| Net income | 48,162 | | 40,349 | | | 176,936 | | 162,267 | | |
| Net income attributable to non-controlling interest | (4,050) | | (4,066) | | | (11,347) | | (11,844) | | |
| Net income available for common stock | $ | 44,112 | | $ | 36,283 | | | 165,589 | | 150,423 | | |
| | | | | | |
| Total earnings per share of common stock, Diluted | $ | 0.70 | | $ | 0.58 | | | $ | 2.63 | | $ | 2.41 | | |
__________
(a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results. | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2022 | 2021 | | 2022 | 2021 | |
| (in thousands, except per share amounts) |
| Operating income (loss): | | | | | | |
| Electric Utilities | $ | 45,226 | | $ | 47,462 | | | $ | 95,972 | | $ | 86,805 | | |
| Gas Utilities | 28,195 | | 19,985 | | | 151,735 | | 122,079 | | |
| Corporate and Other | (1,032) | | (181) | | | (1,965) | | (3,303) | | |
| Operating income | 72,389 | | 67,266 | | | 245,742 | | 205,581 | | |
| | | | | | |
| Interest expense, net | (38,764) | | (38,202) | | | (77,309) | | (75,802) | | |
| Other income (expense), net | 1,563 | | (191) | | | 2,267 | | 75 | | |
| Income tax benefit (expense) | 658 | | (586) | | | (13,830) | | (1,080) | | |
| Net income | 35,846 | | 28,287 | | | 156,870 | | 128,774 | | |
| Net income attributable to non-controlling interest | (2,431) | | (3,126) | | | (5,929) | | (7,297) | | |
| Net income available for common stock | $ | 33,415 | | $ | 25,161 | | | $ | 150,941 | | $ | 121,477 | | |
| | | | | | |
| Total earnings per share of common stock, Diluted | $ | 0.52 | | $ | 0.40 | | | $ | 2.33 | | $ | 1.93 | | |
Three Months Ended SeptemberJune 30, 20212022 Compared to Three Months Ended SeptemberJune 30, 20202021:
The variance to the prior year included the following:
•Electric Utilities’ adjusted operating income increased $5.5 million primarily due to favorable mark-to-market adjustments on wholesale energy contacts, residential customer growth and increased usage, and increased power marketing and wholesale revenues which were partially offset by higher operating expenses;
•Gas Utilities’ adjusted operating income decreased $0.9$2.2 million primarily due to higher operating expenses, lower pricing on the new Wygen I PPA and prior year regulatory actions reducing certain Winter Storm Uri impacts partially offset by increased rider revenues and prior year mark-to-market adjustments on wholesale energy contacts;
•Gas Utilities’ operating income increased $8.2 million primarily due to carrying costs on our Winter Storm Uri regulatory asset and new rates and rider recovery partially offset by higher operating expenses and unfavorable weather which led to decreased irrigation loads and lower heating demand mostly offset by favorable market-to-marketmark-to-market adjustments on wholesale commodity contracts, new rates and prior year COVID-19 impacts;
•Power Generation’s adjusted operating income increased $1.6 million primarily driven by lower operating expenses due to early retirement of certain assets in the prior year partially offset by negative impacts of an unplanned outage at Wygen I;
•Mining’s adjusted operating income increased $1.4 million primarily due to higher prices per ton sold under our cost based supply agreements;
•Interest expense increased $2.0 million due to higher debt balances partially offset by lower rates; andcontracts;
•Other income increased $2.8$1.8 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performanceperformance; and recognition of death
•Income tax benefit increased $1.2 million driven by a lower effective tax rate due to tax benefits from Company-owned life insurance.state tax rate changes partially offset by higher pre-tax income.
NineSix Months Ended SeptemberJune 30, 20212022 Compared to NineSix Months Ended SeptemberJune 30, 20202021:
The variance to the prior year included the following:
•Electric Utilities’ adjusted operating income decreased $6.7increased $9.2 million primarily due to prior year impacts related to Colorado Electric’s TCJA-related bill credits to customers impacts from Winter Storm Uri and unfavorable(which were offset by reduced income tax expense), increased rider revenues, prior year mark-to-market adjustments on wholesale energy contractscontacts and increased transmission and off-system energy sales partially offset by increased rider revenues, increased power marketinghigher operating expenses and wholesale revenues, residential customer growth and increased usage, and prior year COVID-19 impacts;lower pricing on the new Wygen I PPA;
•Gas Utilities’ adjusted operating income increased $0.1$30 million primarily due to new rates higher heating demand from colder weather and favorable market-to-market adjustmentsrider recovery, carrying costs on wholesale commodity contracts mostly offset byour Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, incurredcustomer growth and increased usage per customer partially offset by Black Hills Energy Services, Nebraska Gas TCJA-related bill credits to customers, and higher operating expenses;
•Power Generation’s adjusted operating income increased $1.4 million primarily due to lower operating expenses driven by early retirement of certain assets in the prior year and favorable impacts from Winter Storm Uri partially offset by unfavorable impacts from current year outages;
•Mining’s adjusted operating income increased $1.8 million primarily due to lower operating expenses driven by lower tons sold and overburden removed;
•Corporate and Other expenses increased $3.4decreased $1.3 million primarily due to an allocation of a prior year favorable2020 employee cost true-up of employee costs allocated to our subsidiaries in the current year,first quarter of 2021, which iswas offset in our business segments;
•Interest expense increased $6.8$1.5 million due to higher interest rates and higher debt balances partially offsetprimarily driven by lower rates;
•A prior year $6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;Winter Storm Uri;
•Other income increased $2.3$2.2 million primarily due to lower non-service pension costs for our non-qualified benefit plans which were driven by a lower discount rate and recognition of death benefits from Company-owned life insurance; andmarket performance;
•Income tax expense decreased $19.2increased $13 million due to lowerdriven by higher pre-tax income and a lowerhigher effective tax rate driven primarily bydue to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits.credits partially offset by tax benefits from state tax rate changes; and
•Net income attributable to non-controlling interest decreased $1.4 million due to lower net income from Black Hills Colorado IPP primarily driven by a planned outage.
Segment Operating Results
A discussion of operating results from our business segments follows.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, grossElectric and Gas Utility margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. GrossElectric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
GrossElectric Utility margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. GrossGas Utility margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our grossElectric and Gas Utility margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact grossElectric and Gas Utility margin as a percentage of revenue, they only impact total grossElectric and Gas Utility margin if the costs cannot be passed through to our customers.
Our grossElectric and Gas Utility margin measure may not be comparable to other companies’ grossElectric and Gas Utility margin measure.measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Electric Utilities
Operating results for the Electric Utilities were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | Variance | 2021 | 2020 | Variance |
| |
| Revenue | $ | 213,103 | | $ | 200,842 | | $ | 12,261 | | $ | 625,444 | | $ | 538,181 | | $ | 87,263 | |
| | | | | | |
| Total fuel and purchased power | 82,794 | | 77,885 | | 4,909 | | 290,101 | | 201,398 | | 88,703 | |
| | | | | | |
| Gross margin (non-GAAP) | 130,309 | | 122,957 | | 7,352 | | 335,343 | | 336,783 | | (1,440) | |
| | | | | | |
| Operations and maintenance | 47,293 | | 47,426 | | (133) | | 144,832 | | 144,956 | | (124) | |
| Depreciation and amortization | 25,408 | | 23,448 | | 1,960 | | 75,522 | | 70,101 | | 5,421 | |
| Total operating expenses | 72,701 | | 70,874 | | 1,827 | | 220,354 | | 215,057 | | 5,297 | |
| | | | | | |
| Adjusted operating income | $ | 57,608 | | $ | 52,083 | | $ | 5,525 | | $ | 114,989 | | $ | 121,726 | | $ | (6,737) | |
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2022 | 2021 | Variance | 2022 | 2021 | Variance |
| |
| Revenue: | | | | | | |
| Electric - regulated | $ | 194,197 | | $ | 181,503 | | $ | 12,694 | | $ | 389,921 | | $ | 404,599 | | $ | (14,678) | |
| Other - non-regulated | 10,182 | | 9,513 | | 669 | | 20,995 | | 21,821 | | (826) | |
| Total revenue | 204,379 | | 191,016 | | 13,363 | | 410,917 | | 426,420 | | (15,503) | |
| | | | | | |
| Cost of fuel and purchased power: | | | | | | |
| Electric - regulated | 55,723 | | 44,607 | | 11,116 | | 107,202 | | 144,076 | | (36,874) | |
| Other - non-regulated | 909 | | 956 | | (47) | | 1,840 | | 1,786 | | 54 | |
| Total cost of fuel and purchased power | 56,632 | | 45,563 | | 11,069 | | 109,042 | | 145,862 | | (36,820) | |
| | | | | | |
| Electric Utility margin (non-GAAP) | 147,747 | | 145,453 | | 2,294 | | 301,875 | | 280,558 | | 21,317 | |
| | | | | | |
| Operations and maintenance | 69,000 | | 65,301 | | 3,699 | | 138,669 | | 129,035 | | 9,634 | |
| Depreciation and amortization | 33,521 | | 32,690 | | 831 | | 67,234 | | 64,718 | | 2,516 | |
| Total operating expenses | 102,521 | | 97,991 | | 4,530 | | 205,903 | | 193,753 | | 12,150 | |
| | | | | | |
| Operating income | $ | 45,226 | | $ | 47,462 | | $ | (2,236) | | $ | 95,972 | | $ | 86,805 | | $ | 9,167 | |
Three Months Ended SeptemberJune 30, 20212022 Compared to the Three Months Ended SeptemberJune 30, 2020:2021:
GrossElectric Utility margin for the three months ended September 30, 2021 increased as a result of the following:
| | | | | |
| |
| (in millions) |
Mark-to-market on wholesale energy contractsNew rates and rider recovery | $ | 3.9 | |
Residential customer growth and increased usage per customer | 2.5 | |
Increased commercial and industrial demand | 1.2 | |
Power marketing and wholesale | 1.14.2 | |
Prior year COVID-19 impactsmark-to-market on wholesale energy contracts | 0.23.6 | |
Prior year release of TCJA revenue reservesLower pricing on new Wygen I PPA | (1.5)(2.6) | |
WeatherPrior year Winter Storm Uri impacts (a)
| (2.4) | |
| |
| Other | (0.5) | |
Other | 0.5 | |
Total changeincrease in GrossElectric Utility margin (non-GAAP) | $ | 7.42.3 | |
__________(a) In the first quarter 2021, our Electric Utilities accrued $3.2 million of negative impacts to our regulated wholesale power margins due to the higher fuel costs associated with Winter Storm Uri. Through regulatory actions in the second quarter of 2021, our Electric Utilities were able to reduce $2.4 million of that negative impact.
Operations and maintenance expense was comparableincreased primarily due to the same period in the prior year.higher outside services expenses, higher cloud computing licensing costs and increased property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.
NineSix Months Ended SeptemberJune 30, 20212022 Compared to the NineSix Months Ended SeptemberJune 30, 2020:2021:
GrossElectric Utility margin for the nine months ended September 30, 2021 decreasedincreased as a result of the following:
| | | | | |
| |
| (in millions) |
Prior year TCJA-related bill credits (a) | $ | (10.2)9.3 | |
| New rates and rider recovery | 6.3 | |
| Prior year mark-to-market on wholesale energy contracts | 5.1 | |
| Transmission services and off-system energy sales | 2.6 | |
| Customer load growth | 1.8 | |
Prior year Winter Storm Uri impacts (b) | (2.9)1.2 | |
Mark-to-marketLower pricing on wholesale energy contractsnew Wygen I PPA | (2.4) | |
Prior year release of TCJA revenue reserves | (2.2)(5.1) | |
| Weather | (0.1) | |
Power marketing and wholesale | 6.6 | |
Residential customer growth and increased usage per customer | 3.2 | |
Rider recovery | 2.9 | |
Increased commercial and industrial demand | 1.7 | |
Prior year COVID-19 impacts | 1.7 (0.2) | |
| Other | 0.20.3 | |
Total changeincrease in GrossElectric Utility margin (non-GAAP) | $ | (1.5)21.3 | |
__________________________(a) In February and April 2021, Colorado Electric delivered $9.3 million of TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimalan immaterial impact to Net income.
(b) As a result of Winter Storm Uri, our Electric Utilities incurred a $0.8 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms.mechanisms partially offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.
Operations and maintenance expense remained constantincreased primarily due to higher cloud computing licensing costs, higher maintenance expenses driven by planned generation outages, higher fuel costs, relatedhigher outside services expenses and increased property taxes due to planned and unplanned outages at the Gillette, Wyoming energy complex anda higher operating expenses associated with Corriedale which was placed in service November 30, 2020, offset by prior year expenses related to the municipalization efforts in Pueblo, Colorado.asset base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.
Operating Statistics
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | | Quantities Sold (MWh) |
| Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| 2022 | 2021 | 2022 | 2021 | | 2022 | 2021 | 2022 | 2021 |
| | | | | | | | | |
| Residential | $ | 52,853 | | $ | 53,451 | | $ | 115,102 | | $ | 126,211 | | | 323,775 | | 335,063 | | 715,357 | | 731,149 | |
| Commercial | 68,756 | | 66,809 | | 133,109 | | 143,816 | | | 509,830 | | 501,463 | | 1,000,248 | | 994,418 | |
| Industrial | 38,190 | | 35,186 | | 73,598 | | 78,195 | | | 464,928 | | 441,793 | | 928,696 | | 856,984 | |
| Municipal | 4,992 | | 4,382 | | 9,567 | | 9,402 | | | 40,240 | | 39,863 | | 75,545 | | 76,105 | |
| Subtotal Retail Revenue - Electric | 164,791 | | 159,828 | | 331,377 | | 357,624 | | | 1,338,773 | | 1,318,182 | | 2,719,846 | | 2,658,656 | |
| Contract Wholesale | 4,339 | | 3,010 | | 10,262 | | 8,932 | | | 150,645 | | 129,763 | | 332,852 | | 286,758 | |
| Off-system/Power Marketing Wholesale | 8,666 | | 7,266 | | 15,820 | | 12,038 | | | 144,425 | | 148,981 | | 304,866 | | 209,202 | |
Other (a) | 16,400 | | 11,399 | | 32,463 | | 26,005 | | | — | | — | | — | | — | |
| Total Regulated | 194,197 | | 181,503 | | 389,921 | | 404,599 | | | 1,633,843 | | 1,596,926 | | 3,357,564 | | 3,154,616 | |
Non-Regulated (b) | 10,182 | | 9,513 | | 20,995 | | 21,821 | | | 72,770 | | 61,408 | | 161,864 | | 140,923 | |
| Total Revenue and Quantities Sold | $ | 204,379 | | $ | 191,016 | | $ | 410,917 | | $ | 426,420 | | | 1,706,613 | | 1,658,334 | | 3,519,428 | | 3,295,539 | |
Other Uses, Losses or Generation, net (c) | | | | | | 98,323 | | 94,932 | | 211,609 | | 227,680 | |
| Total Energy | | | | | | 1,804,936 | | 1,753,266 | | 3,731,037 | | 3,523,219 | |
| | | | | | | | | |
| | | | | | | | | |
__________
(a) Primarily related to transmission revenues from the Common Use System.
(b) Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.
(c) Includes company uses and line losses.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | | Quantities Sold (MWh) |
| Three Months Ended June 30, | | | | Six Months Ended June 30, | | Three Months Ended June 30, | Six Months Ended June 30, |
| 2022 | 2021 | | | | 2022 | 2021 | | 2022 | 2021 | 2022 | 2021 |
| Colorado Electric | $ | 71,197 | | $ | 64,009 | | | | | $ | 146,642 | | $ | 143,446 | | | 568,890 | | 596,364 | | 1,188,478 | | 1,150,344 | |
| South Dakota Electric | 76,195 | | 72,640 | | | | | 154,792 | | 166,769 | | | 600,172 | | 581,628 | | 1,244,395 | | 1,163,476 | |
| Wyoming Electric | 47,146 | | 45,601 | | | | | 89,235 | | 95,551 | | | 464,781 | | 418,934 | | 924,691 | | 840,796 | |
| Integrated Generation | 9,841 | | 8,766 | | | | | 20,248 | | 20,654 | | | 72,770 | | 61,408 | | 161,864 | | 140,923 | |
| Total Revenue and Quantities Sold | $ | 204,379 | | $ | 191,016 | | | | | $ | 410,917 | | $ | 426,420 | | | 1,706,613 | | 1,658,334 | | 3,519,428 | | 3,295,539 | |
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| | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| Quantities Generated and Purchased by Fuel Type (MWh) | 2022 | 2021 | 2022 | 2021 |
| Generated: | | | | |
| Coal | 589,438 | | 623,822 | | 1,252,876 | | 1,241,956 | |
| Natural Gas and Oil | 262,157 | | 377,155 | | 558,579 | | 750,941 | |
| Wind | 244,456 | | 195,736 | | 498,024 | | 409,583 | |
| Total Generated | 1,096,051 | | 1,196,713 | | 2,309,479 | | 2,402,480 | |
| Purchased: | | | | |
| Coal, Natural Gas, Oil and Other Market Purchases | 608,045 | | 481,346 | | 1,196,205 | | 945,887 | |
| Wind | 100,840 | | 75,207 | | 225,353 | | 174,852 | |
| Total Purchased | 708,885 | | 556,553 | | 1,421,558 | | 1,120,739 | |
| | | | |
| Total Generated and Purchased | 1,804,936 | | 1,753,266 | | 3,731,037 | | 3,523,219 | |
Operating Statistics
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | | Quantities Sold (MWh) |
| Three Months Ended
September 30, | Nine Months Ended
September 30, | | Three Months Ended
September 30, | Nine Months Ended
September 30, |
| 2021 | 2020 | 2021 | 2020 | | 2021 | 2020 | 2021 | 2020 |
| | | | | | | | | |
| Residential | $ | 66,138 | | $ | 62,395 | | $ | 192,349 | | $ | 167,048 | | | 419,001 | | 405,989 | | 1,150,150 | | 1,113,821 | |
| Commercial | 70,696 | | 64,756 | | 214,512 | | 178,979 | | | 576,037 | | 538,299 | | 1,570,455 | | 1,492,239 | |
| Industrial | 37,323 | | 35,660 | | 115,518 | | 99,725 | | | 459,076 | | 462,545 | | 1,316,060 | | 1,382,710 | |
| Municipal | 5,069 | | 4,834 | | 14,471 | | 12,732 | | | 47,515 | | 46,256 | | 123,620 | | 121,027 | |
| Subtotal Retail Revenue - Electric | 179,226 | | 167,645 | | 536,850 | | 458,484 | | | 1,501,629 | | 1,453,089 | | 4,160,285 | | 4,109,797 | |
| Contract Wholesale | 7,939 | | 5,924 | | 22,155 | | 14,947 | | | 129,221 | | 129,960 | | 415,979 | | 348,991 | |
| Off-system/Power Marketing Wholesale | 11,065 | | 9,535 | | 22,378 | | 17,939 | | | 151,250 | | 167,494 | | 467,440 | | 469,590 | |
| Other | 14,873 | | 17,738 | | 44,061 | | 46,811 | | | — | | — | | — | | — | |
| Total Revenue and Energy Sold | 213,103 | | 200,842 | | 625,444 | | 538,181 | | | 1,782,100 | | 1,750,543 | | 5,043,704 | | 4,928,378 | |
| Other Uses, Losses or Generation, net | — | | — | | — | | — | | | 139,093 | | 118,410 | | 363,815 | | 294,466 | |
| Total Revenue and Energy | 213,103 | | 200,842 | | 625,444 | | 538,181 | | | 1,921,193 | | 1,868,953 | | 5,407,519 | | 5,222,844 | |
| Less cost of fuel and purchased power | 82,794 | | 77,885 | | 290,101 | | 201,398 | | | | | | |
| Gross Margin (non-GAAP) | $ | 130,309 | | $ | 122,957 | | $ | 335,343 | | $ | 336,783 | | | | | | |
| | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| Quantities Generated and Purchased (MWh) | 2022 | 2021 | 2022 | 2021 |
| Generated: | | | | |
| Colorado Electric | 112,117 | | 110,821 | | 197,548 | | 201,077 | |
| South Dakota Electric | 367,936 | | 442,665 | | 823,541 | | 911,481 | |
| Wyoming Electric | 225,720 | | 222,540 | | 430,318 | | 396,530 | |
| Integrated Generation | 390,278 | | 420,687 | | 858,072 | | 893,392 | |
| Total Generated | 1,096,051 | | 1,196,713 | | 2,309,479 | | 2,402,480 | |
| | | | |
| Purchased: | | | | |
| Colorado Electric | 255,969 | | 251,648 | | 556,366 | | 471,893 | |
| South Dakota Electric | 248,625 | | 154,633 | | 445,688 | | 296,635 | |
| Wyoming Electric | 185,932 | | 135,177 | | 376,737 | | 307,602 | |
| Integrated Generation | 18,359 | | 15,095 | | 42,767 | | 44,609 | |
| Total Purchased | 708,885 | | 556,553 | | 1,421,558 | | 1,120,739 | |
| | | | |
| Total Generated and Purchased | 1,804,936 | | 1,753,266 | | 3,731,037 | | 3,523,219 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Three Months Ended September 30, | | Revenue
(in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold (MWh)(a) |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| Colorado Electric | | $ | 83,274 | | $ | 74,742 | | | $ | 45,482 | | $ | 42,236 | | | 720,592 | | 666,916 | |
| South Dakota Electric | | 81,787 | | 78,861 | | | 62,081 | | 58,062 | | | 709,862 | | 699,150 | |
| Wyoming Electric | | 48,042 | | 47,239 | | | 22,746 | | 22,659 | | | 490,739 | | 502,887 | |
| Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold | | $ | 213,103 | | $ | 200,842 | | | $ | 130,309 | | $ | 122,957 | | | 1,921,193 | | 1,868,953 | |
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| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2022 | 2021 | | 2022 | 2021 |
| Degree Days | Actual | Variance from
Normal | Actual | Variance from
Normal | | Actual | Variance from
Normal | Actual | Variance from
Normal |
| Heating Degree Days: | | | | | | | | | |
| Colorado Electric | 556 | | (5) | % | 595 | | (6) | % | | 3,271 | | 5 | % | 3,326 | | 2 | % |
| South Dakota Electric | 1,221 | | 13 | % | 1,048 | | 2 | % | | 4,469 | | 3 | % | 4,372 | | 3 | % |
| Wyoming Electric | 1,159 | | (3) | % | 1,221 | | 2 | % | | 4,291 | | 2 | % | 4,482 | | 6 | % |
Combined (a) | 904 | | 3 | % | 875 | | — | % | | 3,885 | | 4 | % | 3,915 | | 3 | % |
| | | | | | | | | |
| Cooling Degree Days: | | | | | | | | | |
| Colorado Electric | 333 | | 24 | % | 300 | | 44 | % | | 333 | | 24 | % | 300 | | 44 | % |
| South Dakota Electric | 107 | | 15 | % | 167 | | 69 | % | | 107 | | 15 | % | 167 | | 69 | % |
| Wyoming Electric | 121 | | 102 | % | 117 | | 134 | % | | 121 | | 102 | % | 117 | | 134 | % |
Combined (a) | 213 | | 28 | % | 218 | | 56 | % | | 213 | | 28 | % | 218 | | 56 | % |
__________
(a) Degree days are calculated based on a weighted average of total customers by state.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, | | Revenue
(in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold (MWh)(a) |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| Colorado Electric | | $ | 227,328 | | $ | 191,197 | | | $ | 103,982 | | $ | 106,961 | | | 1,945,741 | | 1,765,501 | |
| South Dakota Electric | | 250,617 | | 213,059 | | | 163,523 | | 163,659 | | | 1,997,696 | | 1,954,902 | |
| Wyoming Electric | | 147,499 | | 133,925 | | | 67,838 | | 66,163 | | | 1,464,082 | | 1,502,441 | |
| Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold | | $ | 625,444 | | $ | 538,181 | | | $ | 335,343 | | $ | 336,783 | | | 5,407,519 | | 5,222,844 | |
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________________ | | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
Contracted generating facilities Availability by fuel type (a) | 2022 | 2021 | 2022 | 2021 |
Coal (b) (c) | 82.1 | % | 86.1 | % | 86.3 | % | 86.2 | % |
| Natural gas and diesel oil | 95.1 | % | 97.6 | % | 95.2 | % | 93.8 | % |
| Wind | 93.8 | % | 96.8 | % | 94.7 | % | 95.3 | % |
| Total Availability | 91.4 | % | 94.4 | % | 92.7 | % | 92.1 | % |
| | | | |
| Wind Capacity Factor | 39.8 | % | 31.0 | % | 40.9 | % | 34.1 | % |
__________
(a) Includes company uses, line losses,Availability and excess exchange production.Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2022 included planned outages at Neil Simpson II and Wyodak Plant.
(c) 2021 included planned outages at Neil Simpson II, Wygen, Wygen II, and Wygen III and unplanned outages at Neil Simpson II and Wyodak Plant.
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| Quantities Generated and Purchased (MWh) | 2021 | 2020 | 2021 | 2020 |
| | | | |
| Generated: | | | | |
| Coal | 589,194 | | 592,681 | | 1,569,410 | | 1,712,540 | |
| Natural Gas and Oil | 231,433 | | 199,408 | | 535,148 | | 453,950 | |
| Wind | 90,496 | | 54,518 | | 315,654 | | 191,696 | |
| Total Generated | 911,123 | | 846,607 | | 2,420,212 | | 2,358,186 | |
| Purchased | 1,010,070 | | 1,022,346 | | 2,987,307 | | 2,864,658 | |
| Total Generated and Purchased | 1,921,193 | | 1,868,953 | | 5,407,519 | | 5,222,844 | |
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| Quantities Generated and Purchased (MWh) | 2021 | 2020 | 2021 | 2020 |
| Generated: | | | | |
| Colorado Electric | 150,646 | | 97,450 | | 351,723 | | 271,957 | |
| South Dakota Electric | 538,632 | | 518,821 | | 1,450,114 | | 1,434,353 | |
| Wyoming Electric | 221,845 | | 230,336 | | 618,375 | | 651,876 | |
| Total Generated | 911,123 | | 846,607 | | 2,420,212 | | 2,358,186 | |
| | | | |
| Purchased: | | | | |
| Colorado Electric | 569,946 | | 569,466 | | 1,594,018 | | 1,493,544 | |
| South Dakota Electric | 171,229 | | 180,329 | | 547,582 | | 520,549 | |
| Wyoming Electric | 268,895 | | 272,551 | | 845,707 | | 850,565 | |
| Total Purchased | 1,010,070 | | 1,022,346 | | 2,987,307 | | 2,864,658 | |
| | | | |
| Total Generated and Purchased | 1,921,193 | | 1,868,953 | | 5,407,519 | | 5,222,844 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, |
| 2021 | | 2020 |
| Degree Days | Actual | | Variance from
Normal | | Actual | | Variance from
Normal |
| Heating Degree Days: | | | | | | | |
| Colorado Electric | 22 | | | (78) | % | | 99 | | | 1 | % |
| South Dakota Electric | 90 | | | (60) | % | | 202 | | | (10) | % |
| Wyoming Electric | 112 | | | (62) | % | | 208 | | | (29) | % |
Combined (a) | 63 | | | (65) | % | | 156 | | | (14) | % |
| | | | | | | |
| Cooling Degree Days: | | | | | | | |
| Colorado Electric | 942 | | | 38 | % | | 987 | | | 44 | % |
| South Dakota Electric | 649 | | | 22 | % | | 561 | | | 5 | % |
| Wyoming Electric | 487 | | | 63 | % | | 492 | | | 65 | % |
Combined (a) | 751 | | | 35 | % | | 742 | | | 34 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
| Degree Days | Actual | | Variance from
Normal | | Actual | | Variance from
Normal |
| Heating Degree Days | | | | | | | |
| Colorado Electric | 3,348 | | | (1) | % | | 3,073 | | | (9) | % |
| South Dakota Electric | 4,462 | | | — | % | | 4,440 | | | — | % |
| Wyoming Electric | 4,594 | | | 2 | % | | 4,356 | | | (3) | % |
Combined (a) | 3,979 | | | — | % | | 3,799 | | | (4) | % |
| | | | | | | |
| Cooling Degree Days: | | | | | | | |
| Colorado Electric | 1,242 | | | 39 | % | | 1,369 | | | 53 | % |
| South Dakota Electric | 816 | | | 29 | % | | 681 | | | 8 | % |
| Wyoming Electric | 604 | | | 74 | % | | 593 | | | 70 | % |
Combined (a) | 968 | | | 39 | % | | 977 | | | 41 | % |
____________________
(a) Combined actuals are calculated based on the weighted average number of total customers by state.
| | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
Contracted generating facilities Availability by fuel type (a) | 2021 | 2020 | 2021 | 2020 |
Coal (b) | 96.3 | % | 97.4 | % | 88.5 | % | 94.1 | % |
Natural Gas and diesel oil (b) (c) | 96.5 | % | 79.7 | % | 93.8 | % | 80.5 | % |
| Wind | 97.0 | % | 97.7 | % | 95.6 | % | 98.3 | % |
| Total Availability | 96.5 | % | 86.8 | % | 92.4 | % | 86.3 | % |
| | | | |
| Wind capacity factor | 34.1 | % | 33.2 | % | 38.0 | % | 39.3 | % |
____________________
(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2021 included planned outages at Neil Simpson II, Wygen II, Wygen III and Pueblo Airport Generation and unplanned outages at Neil Simpson II and Wyodak Plant.
(c) 2020 included an unplanned outage at Pueblo Airport Generation.
Gas Utilities
Operating results for the Gas Utilities were as follows (in thousands):
| | | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2021 | 2020 | Variance | 2021 | 2020 | Variance | | 2022 | 2021 | Variance | 2022 | 2021 | Variance |
| Revenue: | Revenue: | | Revenue: | |
| Natural gas - regulated | Natural gas - regulated | $ | 150,075 | | $ | 128,468 | | $ | 21,607 | | $ | 700,617 | | $ | 612,797 | | $ | 87,820 | | Natural gas - regulated | $ | 258,349 | | $ | 172,465 | | $ | 85,884 | | $ | 854,807 | | $ | 550,542 | | $ | 304,265 | |
| Other - non-regulated services | 14,608 | | 15,461 | | (853) | | 52,635 | | 53,015 | | (380) | | |
| Other - non-regulated | | Other - non-regulated | 15,821 | | 13,585 | | 2,236 | | 40,755 | | 38,027 | | 2,728 | |
| Total revenue | Total revenue | 164,683 | | 143,929 | | 20,754 | | 753,252 | | 665,812 | | 87,440 | | Total revenue | 274,169 | | 186,050 | | 88,119 | | 895,561 | | 588,569 | | 306,992 | |
| | Cost of sales: | | |
| Cost of natural gas sold: | | Cost of natural gas sold: | |
| Natural gas - regulated | Natural gas - regulated | 43,883 | | 25,235 | | 18,648 | | 289,167 | | 222,144 | | 67,023 | | Natural gas - regulated | 126,704 | | 62,317 | | 64,387 | | 510,416 | | 245,284 | | 265,132 | |
| Other - non-regulated services | (749) | | 1,800 | | (2,549) | | 10,132 | | 4,874 | | 5,258 | | |
| Total cost of sales | 43,134 | | 27,035 | | 16,099 | | 299,299 | | 227,018 | | 72,281 | | |
| Other - non-regulated | | Other - non-regulated | 5,040 | | 798 | | 4,242 | | 6,055 | | 10,881 | | (4,826) | |
| Total cost of natural gas sold | | Total cost of natural gas sold | 131,744 | | 63,115 | | 68,629 | | 516,471 | | 256,165 | | 260,306 | |
| | Gross margin (non-GAAP) | 121,549 | | 116,894 | | 4,655 | | 453,953 | | 438,794 | | 15,159 | | |
| Gas Utility margin (non-GAAP) | | Gas Utility margin (non-GAAP) | 142,425 | | 122,935 | | 19,490 | | 379,090 | | 332,404 | | 46,686 | |
| | Operations and maintenance | Operations and maintenance | 78,161 | | 73,642 | | 4,519 | | 237,624 | | 223,351 | | 14,273 | | Operations and maintenance | 83,689 | | 77,263 | | 6,426 | | 170,130 | | 159,463 | | 10,667 | |
| Depreciation and amortization | Depreciation and amortization | 26,131 | | 25,105 | | 1,026 | | 76,993 | | 76,190 | | 803 | | Depreciation and amortization | 30,541 | | 25,687 | | 4,854 | | 57,225 | | 50,862 | | 6,363 | |
| Total operating expenses | Total operating expenses | 104,292 | | 98,747 | | 5,545 | | 314,617 | | 299,541 | | 15,076 | | Total operating expenses | 114,230 | | 102,950 | | 11,280 | | 227,355 | | 210,325 | | 17,030 | |
| | Adjusted operating income | $ | 17,257 | | $ | 18,147 | | $ | (890) | | $ | 139,336 | | $ | 139,253 | | $ | 83 | | |
| Operating income | | Operating income | $ | 28,195 | | $ | 19,985 | | $ | 8,210 | | $ | 151,735 | | $ | 122,079 | | $ | 29,656 | |
Three Months Ended SeptemberJune 30, 20212022 Compared to the Three Months Ended SeptemberJune 30, 2020:2021:
GrossGas Utility margin for the three months ended September 30, 2021 increased as a result of:of the following:
| | | | | |
| |
| (in millions) |
Carrying costs on Winter Storm Uri regulatory asset (a) | $ | 12.3 | |
| New rates and rider recovery | 4.6 | |
Current and prior year TCJA-related bill credits (b) | 2.2 | |
| Increased transportation and transmission volumes | 1.9 | |
| Residential customer growth and increased usage per customer | 1.5 | |
| Mark-to-market on non-utility natural gas commodity contracts | $ | 2.3 (4.3) | |
New ratesWeather | 2.0 | |
Winter Storm Uri carrying costs (a)
| 1.7 | |
Prior year COVID-19 impacts | 0.8 | |
Weather (b)
| (3.4)(0.2) | |
| Other | 1.31.5 | |
Total increase in GrossGas Utility margin (non-GAAP) | $ | 4.719.5 | |
__________
(a) In certain jurisdictions, we have accruedCommission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs and began recovering from customers.accrued during the three months ended June 30, 2022 included a one-time, $10.3 million true-up to reflect Commission authorized rates. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information. (b) Weather impacts forIn June 2021, Nebraska Gas provided $2.9 million TCJA-related bill credits to its customers. For the three months ended SeptemberJune 30, 2021 compared2022, Kansas Gas provided $0.7 million of TCJA and state tax reform bill credits to the same periodcustomers. These bill credits were offset by a reduction in the prior year include decreased irrigation loadsincome tax expense and resulted in an immateriall impact to agriculture customers and decreased heating demand due to warmer temperatures.Net income.
Operations and maintenance expense increased primarily due to $3.4 million of higher employee costs, $1.2 million of higher outside services relatedand materials expenses, $1.1 million of increased property taxes due to a higher asset base and $0.7 million of prior year COVID-19 savings due to lower travel and training expenses partially offset by $2.2 million of decreased bad debt expense associated with lower expected credit losses.primarily attributable to higher billings, higher cloud computing licensing costs and higher vehicle expenses due to higher fuel costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures mostly offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.expenditures.
Nine
Six Months Ended SeptemberJune 30, 20212022 Compared to the NineSix Months Ended SeptemberJune 30, 2020:2021:
GrossGas Utility margin for the nine months ended September 30, 2021 increased as a result of the following:
| | | | | |
| |
| (in millions) |
| New rates and rider recovery | $ | 16.717.4 | |
Carrying costs on Winter Storm Uri regulatory asset (a) | 14.6 | |
Prior year Black Hills Energy Services Winter Storm Uri costs (b) | 8.2 | |
| Residential customer growth and increased usage per customer | 4.5 | |
| Increased transportation and transmission volumes | 1.5 | |
Current and prior year TCJA-related bill credits (c) | 1.4 | |
| Weather | 4.2 (1.0) | |
| Mark-to-market on non-utility natural gas commodity contracts | 3.5 | |
Winter Storm Uri carrying costs (a)
| 1.7 | |
Prior year COVID-19 impacts | 1.7 | |
Black Hills Energy Services Winter Storm Uri costs (b)
| (8.2) | |
TCJA-related bill credits (c)
| (2.9) | |
Non-utility - Service Guard Comfort Plan and Gas Supply Services | (2.9)(0.9) | |
| Other | 1.41.0 | |
Total increase in GrossGas Utility margin (non-GAAP) | $ | 15.246.7 | |
__________(a) In certain jurisdictions, we have accruedCommission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs and began recovering from customers.accrued during the six months ended June 30, 2022 included a one-time, $10.3 million true-up to reflect Commission authorized rates. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information. (b) Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri iswas not recoverable through a regulatory mechanism.
(c) In June 2021, Nebraska Gas deliveredprovided $2.9 million TCJA-related bill credits to its customers. For the three months ended June 30, 2022, Kansas Gas provided $1.5 million of TCJA and state tax reform bill credits to customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.
Operations and maintenance expense increased primarily due to $10.3 million of higher employeecloud computing licensing costs, $4.0 million of higher outside services relatedand materials expenses, $3.4 million ofincreased bad debt expense primarily attributable to higher facilitiesbillings, higher vehicle expenses due to higher fuel costs and office related expenses driven by prior year COVID-19 savings, and $2.7 million of increased property taxes due to a higher asset base partially offset by $5.6 million of decreased bad debt expense associated with lower expected credit losses.base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures mostly offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.expenditures.
Operating Statistics | | | Revenue (in thousands) | | | Gross Margin (non-GAAP) (in thousands) | | | Gas Utilities Quantities Sold & Transported (Dth) | | | Revenue (in thousands) | | Quantities Sold and Transported (Dth) |
| | | Three Months Ended
September 30, | | | Three Months Ended
September 30, | | | Three Months Ended
September 30, | | | Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | 2021 | 2020 | | | 2021 | 2020 | | | 2021 | 2020 | | | 2022 | 2021 | 2022 | 2021 | | 2022 | 2021 | 2022 | 2021 |
| | Residential | Residential | | $ | 68,646 | | $ | 61,515 | | | | $ | 49,349 | | $ | 48,165 | | | | 3,564,722 | | 4,058,040 | | | Residential | $ | 143,127 | | $ | 98,370 | | $ | 519,171 | | $ | 332,767 | | | 8,523,755 | | 8,575,051 | | 40,338,005 | | 39,143,789 | |
| Commercial | Commercial | | 27,038 | | 19,940 | | | | 13,999 | | 12,821 | | | | 2,426,019 | | 2,354,719 | | | Commercial | 61,182 | | 36,888 | | 219,824 | | 127,977 | | | 4,499,245 | | 4,493,931 | | 19,130,948 | | 18,306,252 | |
| Industrial | Industrial | | 13,863 | | 7,280 | | | | 2,316 | | 2,514 | | | | 2,873,540 | | 2,674,127 | | | Industrial | 16,875 | | 5,811 | | 26,113 | | 10,713 | | | 2,150,532 | | 1,337,672 | | 3,315,115 | | 2,235,961 | |
| Other | Other | | 2,706 | | 1,271 | | | | 2,706 | | 1,271 | | | | — | | — | | | Other | 2,300 | | (418) | | 5,072 | | (890) | | | — | | — | | — | | — | |
| Total Distribution | Total Distribution | | 112,253 | | 90,006 | | | | 68,370 | | 64,771 | | | | 8,864,281 | | 9,086,886 | | | Total Distribution | 223,483 | | 140,651 | | 770,179 | | 470,567 | | | 15,173,532 | | 14,406,654 | | 62,784,068 | | 59,686,002 | |
| | Transportation and Transmission | Transportation and Transmission | | 37,822 | | 38,462 | | | | 37,822 | | 38,462 | | | | 34,735,601 | | 33,668,174 | | | Transportation and Transmission | 34,865 | | 31,814 | | 84,627 | | 79,975 | | | 37,623,610 | | 34,074,214 | | 82,668,813 | | 79,388,652 | |
| | Total Regulated | Total Regulated | | 150,075 | | 128,468 | | | | 106,192 | | 103,233 | | | | 43,599,882 | | 42,755,060 | | | Total Regulated | 258,349 | | 172,465 | | 854,807 | | 550,542 | | | 52,797,142 | | 48,480,868 | | 145,452,881 | | 139,074,654 | |
| | Non-regulated Services | Non-regulated Services | | 14,608 | | 15,461 | | | | 15,357 | | 13,661 | | | | | Non-regulated Services | 15,821 | | 13,585 | | 40,755 | | 38,027 | | | — | | — | | — | | — | |
| | Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 164,683 | | $ | 143,929 | | | | $ | 121,549 | | $ | 116,894 | | | | | |
| Total Revenue and Quantities Sold | | Total Revenue and Quantities Sold | $ | 274,169 | | $ | 186,050 | | $ | 895,561 | | $ | 588,569 | | | 52,797,142 | | 48,480,868 | | 145,452,881 | | 139,074,654 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth) |
| | Nine Months Ended
September 30, | | Nine Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| | | | | | | | | |
| Residential | | $ | 401,413 | | $ | 351,986 | | | $ | 219,885 | | $ | 207,654 | | | 42,708,511 | | 40,790,670 | |
| Commercial | | 155,015 | | 127,617 | | | 66,447 | | 61,676 | | | 20,732,271 | | 19,155,051 | |
| Industrial | | 24,576 | | 18,539 | | | 5,505 | | 6,697 | | | 5,109,501 | | 5,771,732 | |
| Other | | 1,816 | | 856 | | | 1,816 | | 856 | | | — | | — | |
| Total Distribution | | 582,820 | | 498,998 | | | 293,653 | | 276,883 | | | 68,550,283 | | 65,717,453 | |
| | | | | | | | | |
| Transportation and Transmission | | 117,797 | | 113,799 | | | 117,797 | | 113,770 | | | 114,124,253 | | 108,967,182 | |
| | | | | | | | | |
| Total Regulated | | 700,617 | | 612,797 | | | 411,450 | | 390,653 | | | 182,674,536 | | 174,684,635 | |
| | | | | | | | | |
| Non-regulated Services | | 52,635 | | 53,015 | | | 42,503 | | 48,141 | | | | |
| | | | | | | | | |
| Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 753,252 | | $ | 665,812 | | | $ | 453,953 | | $ | 438,794 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | | | Gas Utilities Quantities Sold & Transported (Dth) | | |
| | Three Months Ended
September 30, | | | Three Months Ended
September 30, | | | Three Months Ended
September 30, | |
| | 2021 | 2020 | | | | 2021 | 2020 | | | | 2021 | 2020 | | |
| | | | | | | | | | | | | | | |
| Arkansas Gas | | $ | 25,188 | | $ | 21,043 | | | | | $ | 18,468 | | $ | 17,400 | | | | | 4,319,944 | | 3,925,893 | | | |
| Colorado Gas | | 22,452 | | 22,724 | | | | | 17,097 | | 16,972 | | | | | 3,798,587 | | 3,702,666 | | | |
| Iowa Gas | | 22,015 | | 18,155 | | | | | 14,442 | | 14,672 | | | | | 5,810,932 | | 5,628,110 | | | |
| Kansas Gas | | 25,972 | | 18,591 | | | | | 13,600 | | 13,099 | | | | | 9,075,960 | | 8,564,408 | | | |
| Nebraska Gas | | 51,538 | | 46,315 | | | | | 42,896 | | 39,755 | | | | | 16,174,821 | | 16,525,547 | | | |
| Wyoming Gas | | 17,518 | | 17,101 | | | | | 15,046 | | 14,996 | | | | | 4,419,638 | | 4,408,436 | | | |
| Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 164,683 | | $ | 143,929 | | | | | $ | 121,549 | | $ | 116,894 | | | | | 43,599,882 | | 42,755,060 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth) |
| | Nine Months Ended
September 30, | | Nine Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| | | | | | | | | |
| Arkansas Gas | | $ | 145,176 | | $ | 124,621 | | | $ | 93,319 | | $ | 88,161 | | | 23,345,095 | | 19,795,077 | |
| Colorado Gas | | 135,764 | | 123,943 | | | 75,919 | | 73,785 | | | 23,121,887 | | 21,845,915 | |
| Iowa Gas | | 108,600 | | 94,386 | | | 53,082 | | 50,355 | | | 27,141,518 | | 25,429,502 | |
| Kansas Gas | | 87,198 | | 70,571 | | | 45,110 | | 44,162 | | | 26,694,184 | | 25,202,180 | |
| Nebraska Gas | | 187,673 | | 170,447 | | | 124,923 | | 122,140 | | | 59,281,802 | | 56,857,061 | |
| Wyoming Gas | | 88,841 | | 81,844 | | | 61,600 | | 60,191 | | | 23,090,050 | | 25,554,900 | |
| Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 753,252 | | $ | 665,812 | | | $ | 453,953 | | $ | 438,794 | | | 182,674,536 | | 174,684,635 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended September 30, |
| 2021 | | 2020 |
| Heating Degree Days | Actual | | Variance
from Normal | | Actual | | Variance
from Normal |
Arkansas Gas (a) | 11 | | (74)% | | 24 | | (44)% |
| Colorado Gas | 92 | | (51)% | | 159 | | (26)% |
| Iowa Gas | 42 | | (70)% | | 140 | | 1% |
Kansas Gas (a) | 10 | | (82)% | | 70 | | 27% |
| Nebraska Gas | 33 | | (70)% | | 109 | | (1)% |
| Wyoming Gas | 153 | | (50)% | | 245 | | (20)% |
Combined Gas (b) | 53 | | (61)% | | 125 | | (13)% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | | Quantities Sold & Transported (Dth) |
| Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| 2022 | 2021 | 2022 | 2021 | | 2022 | 2021 | 2022 | 2021 |
| | | | | | | | | |
| Arkansas Gas | $ | 51,815 | | $ | 32,994 | | $ | 179,624 | | $ | 119,988 | | | 5,445,450 | | 5,718,417 | | 18,373,186 | | 19,025,151 | |
| Colorado Gas | 50,328 | | 34,190 | | 170,381 | | 113,312 | | | 6,365,777 | | 5,957,285 | | 19,784,461 | | 19,323,300 | |
| Iowa Gas | 42,050 | | 29,831 | | 162,629 | | 86,585 | | | 8,178,613 | | 7,016,613 | | 23,554,795 | | 21,330,586 | |
| Kansas Gas | 35,482 | | 21,163 | | 94,333 | | 61,226 | | | 8,762,807 | | 7,155,427 | | 19,751,874 | | 17,618,224 | |
| Nebraska Gas | 62,337 | | 43,037 | | 196,571 | | 136,135 | | | 16,714,480 | | 15,822,880 | | 44,050,254 | | 43,106,981 | |
| Wyoming Gas | 32,157 | | 24,835 | | 92,023 | | 71,323 | | | 7,330,015 | | 6,810,246 | | 19,938,311 | | 18,670,412 | |
| Total Revenue and Quantities Sold | $ | 274,169 | | $ | 186,050 | | $ | 895,561 | | $ | 588,569 | | | 52,797,142 | | 48,480,868 | | 145,452,881 | | 139,074,654 | |
| | | | | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | Nine Months Ended September 30, | | 2022 | 2021 | | 2022 | 2021 |
| 2021 | | | 2020 | |
| Heating Degree Days: | Actual | | Variance
from Normal | | | Actual | | Variance
from Normal | |
| Heating Degree Days | | Heating Degree Days | Actual | Variance
from Normal | Actual | Variance
from Normal | | Actual | Variance
from Normal | Actual | Variance
from Normal |
Arkansas Gas (a) | Arkansas Gas (a) | 2,515 | | 1% | | | 2,036 | | (18)% | Arkansas Gas (a) | 271 | (18)% | 383 | 16% | | 2,370 | (3)% | 2,504 | 3% |
| Colorado Gas | Colorado Gas | 3,922 | | (4)% | | | 3,797 | | (7)% | Colorado Gas | 817 | (14)% | 865 | (9)% | | 3,763 | (3)% | 3,830 | (1)% |
| Iowa Gas | Iowa Gas | 4,155 | | (1)% | | | 4,104 | | (2)% | Iowa Gas | 803 | 17% | 691 | 1% | | 4,382 | 8% | 4,113 | 1% |
Kansas Gas (a) | Kansas Gas (a) | 3,079 | | 4% | | | 2,851 | | (4)% | Kansas Gas (a) | 436 | (2)% | 493 | 10% | | 3,020 | 4% | 3,069 | 5% |
| Nebraska Gas | Nebraska Gas | 3,754 | | (1)% | | | 3,636 | | (4)% | Nebraska Gas | 679 | 7% | 624 | (1)% | | 3,720 | 1% | 3,721 | 1% |
| Wyoming Gas | Wyoming Gas | 4,778 | | 1% | | | 4,678 | | (1)% | Wyoming Gas | 1,326 | 9% | 1,200 | (1)% | | 4,598 | 4% | 4,625 | 5% |
Combined Gas (b) | 3,978 | | —% | | | 3,731 | | (4)% | |
Combined (b) | | Combined (b) | 768 | 2% | 739 | 1% | | 3,933 | 2% | 3,925 | 2% |
__________
(a) Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.
Regulatory Matters
For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 2 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 2020 Annual Report on Form 10-K.
Power Generation
Our Power Generation segment operating results were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | Variance | 2021 | 2020 | Variance |
| |
| Revenue | $ | 26,520 | | $ | 26,518 | | $ | 2 | | $ | 81,031 | | $ | 78,606 | | $ | 2,425 | |
| | | | | | |
| Fuel expense | 2,547 | | 2,320 | | 227 | | 7,839 | | 6,692 | | 1,147 | |
| Operations and maintenance | 8,233 | | 10,539 | | (2,306) | | 24,913 | | 24,886 | | 27 | |
| Depreciation and amortization | 5,417 | | 4,921 | | 496 | | 15,437 | | 15,539 | | (102) | |
| Total operating expense | 16,197 | | 17,780 | | (1,583) | | 48,189 | | 47,117 | | 1,072 | |
| | | | | | |
| Adjusted operating income | $ | 10,323 | | $ | 8,738 | | $ | 1,585 | | $ | 32,842 | | $ | 31,489 | | $ | 1,353 | |
Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:
The increase in current year adjusted operating income was primarily driven by a prior year $3.1 million expense related to the early retirement of certain assets partially offset by $2.3 million of negative impacts from a current year unplanned outage at Wygen I.
Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:
Adjusted operating income increased compared to the same period in the prior year primarily due to a prior year $3.1 million expense related to the early retirement of certain assets and $1.7 million of favorable Winter Storm Uri impacts realized under Black Hills Wyoming’s Economy Energy PSA partially offset by negative impacts of current year planned and unplanned outages.
Operating Statistics
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | Quantities Sold (MWh) (a) | Revenue (in thousands) | Quantities Sold (MWh) (a) |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 |
| Black Hills Colorado IPP | $ | 14,627 | | $ | 14,527 | | 275,237 | | 301,934 | | $ | 42,862 | | $ | 42,917 | | 718,496 | | 830,860 | |
Black Hills Wyoming (b) | 10,634 | | 10,757 | | 146,525 | | 157,855 | | 34,208 | | 31,403 | | 453,291 | | 471,073 | |
| Black Hills Electric Generation | 1,259 | | 1,234 | | 72,493 | | 65,697 | | 3,961 | | 4,286 | | 257,511 | | 255,605 | |
| Total Power Generation Revenue and Quantities Sold | $ | 26,520 | | $ | 26,518 | | 494,255 | | 525,486 | | $ | 81,031 | | $ | 78,606 | | 1,429,298 | | 1,557,538 | |
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Quantities Generated and Purchased (MWh) (a) | Fuel Type | 2021 | 2020 | | 2021 | 2020 |
| Generated | | | | | | |
| Black Hills Colorado IPP | Natural Gas | 275,237 | | 301,934 | | | 718,496 | | 830,860 | |
Black Hills Wyoming (b) | Coal | 123,705 | | 139,313 | | | 388,059 | | 408,545 | |
| Black Hills Electric Generation | Wind | 72,493 | | 65,697 | | | 257,511 | | 255,605 | |
| Total Generated | | 471,435 | | 506,944 | | | 1,364,066 | | 1,495,010 | |
| | | | | | |
| Purchased | | | | | | |
Black Hills Wyoming (b) | Various | 23,575 | | 18,004 | | | 68,184 | | 62,097 | |
| Total Purchased | | 23,575 | | 18,004 | | | 68,184 | | 62,097 | |
____________
(a) Company uses and losses are not included in the quantities sold, generated, and purchased.
(b) Under the 20-year Economy Energy PSA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement that Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Contracted generating facilities Availability by fuel type (a) | 2021 | 2020 | | 2021 | 2020 |
| | | | | |
Coal (b) | 84.9 | % | 96.1 | % | | 90.4 | % | 94.5 | % |
Natural gas (b) | 99.7 | % | 99.8 | % | | 95.3 | % | 99.6 | % |
| Wind | 96.2 | % | 90.6 | % | | 95.9 | % | 92.8 | % |
| Total Availability | 96.0 | % | 95.8 | % | | 94.7 | % | 96.3 | % |
| | | | | |
| Wind capacity factor | 21.5 | % | 19.4 | % | | 25.6 | % | 25.7 | % |
____________________
(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2021 included planned and unplanned outages at Wygen I and planned outages at Pueblo Airport Generation.
Mining
Our Mining segment operating results were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | Variance | 2021 | 2020 | Variance |
| |
| Revenue | $ | 16,388 | | $ | 15,236 | | $ | 1,152 | | $ | 45,489 | | $ | 45,857 | | $ | (368) | |
| | | | | | |
| Operations and maintenance | 9,344 | | 8,923 | | 421 | | 26,956 | | 28,481 | | (1,525) | |
| Depreciation, depletion and amortization | 2,136 | | 2,808 | | (672) | | 6,720 | | 7,384 | | (664) | |
| Total operating expenses | 11,480 | | 11,731 | | (251) | | 33,676 | | 35,865 | | (2,189) | |
| | | | | | |
| Adjusted operating income | $ | 4,908 | | $ | 3,505 | | $ | 1,403 | | $ | 11,813 | | $ | 9,992 | | $ | 1,821 | |
Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020:
Revenue increased reflecting a 6% increase in price per ton sold driven by contract price adjustments based on actual mining costs.
Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:
Current year revenue was comparable due to fewer tons sold driven primarily by planned and unplanned outages at the Gillette, Wyoming energy complex mostly offset by a 4% increase in price per ton sold driven by contract price adjustments based on actual mining costs. Operating expenses decreased primarily due to lower overburden and processing costs.
Operating Statistics
The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | 2020 | | 2021 | 2020 |
| Tons of coal sold | 960 | | 940 | | | 2,691 | | 2,808 | |
| Cubic yards of overburden moved | 1,757 | | 1,595 | | | 5,188 | | 6,073 | |
| | | | | |
| Revenue per ton | $ | 16.47 | | $ | 15.60 | | | $ | 16.26 | | $ | 15.64 | |
Corporate and Other
Corporate and Other operating results were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | Variance | 2021 | 2020 | Variance |
| |
| Adjusted operating income (loss) | $ | (223) | | $ | (239) | | $ | 16 | | $ | (3,526) | | $ | (108) | | $ | (3,418) | |
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2022 | 2021 | Variance | 2022 | 2021 | Variance |
| |
| Operating (loss) | $ | (1,032) | | $ | (181) | | $ | (851) | | $ | (1,965) | | $ | (3,303) | | $ | 1,338 | |
Three Months Ended SeptemberJune 30, 20212022 Compared to the Three Months Ended SeptemberJune 30, 2020:2021:
Adjusted operating incomeOperating (loss) was comparable to the same period in the prior year.
Nine
Six Months Ended SeptemberJune 30, 20212022 Compared to the NineSix Months Ended SeptemberJune 30, 2020:2021:
The variancedecrease in Adjusted operating incomeOperating (loss) was primarily due to an allocation of a prior year favorable2020 employee cost true-up of employee costs which was allocated to our subsidiaries in the current year. This allocationfirst quarter of 2021, which was offset in our business segments and had no impact to consolidated results.segments.
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax (Expense)
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2021 | 2020 | Variance | 2021 | 2020 | Variance |
| (in thousands) |
| Interest expense, net | $ | (38,018) | | $ | (36,041) | | $ | (1,977) | | $ | (113,820) | | $ | (107,039) | | $ | (6,781) | |
| Impairment of investment | — | | — | | $ | — | | $ | — | | $ | (6,859) | | $ | 6,859 | |
| Other income (expense), net | 1,560 | | (1,193) | | $ | 2,753 | | $ | 1,635 | | $ | (703) | | $ | 2,338 | |
| Income tax (expense) | (5,253) | | (4,651) | | $ | (602) | | $ | (6,333) | | $ | (25,484) | | $ | 19,151 | |
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
| 2022 | 2021 | Variance | 2022 | 2021 | Variance |
| (in thousands) |
| Interest expense, net | $ | (38,764) | | $ | (38,202) | | $ | (562) | | $ | (77,309) | | $ | (75,802) | | $ | (1,507) | |
| Other income, net | 1,563 | | (191) | | $ | 1,754 | | $ | 2,267 | | $ | 75 | | $ | 2,192 | |
| Income tax benefit (expense) | 658 | | (586) | | $ | 1,244 | | $ | (13,830) | | $ | (1,080) | | $ | (12,750) | |
Three Months Ended SeptemberJune 30, 20212022 Compared to the Three Months Ended SeptemberJune 30, 2020:2021:
Interest Expense, net
Interest expense, net was comparable to the same period in the prior year.
Other Income, net
The increase in Other income, net was due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by higher non-service pension costs primarily driven by a higher discount rate.
Income Tax Benefit (Expense)
Income tax benefit increased due to a lower effective tax rate partially offset by higher pre-tax income. For the three months ended June 30, 2022, the effective tax rate was (1.9)% compared to 2.0% for the same period in 2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.
Six Months Ended June 30, 2022 Compared to the Six Months Ended June 30, 2021:
Interest Expense, net
The increase in Interest expense, net was due to higher interest rates and higher debt balances primarily driven by the August 2021 senior unsecured notes and February 2021 term loan partially offset by lower interest rates.Winter Storm Uri.
Other Income, (Expense)net
The increase in Other income, net was primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.
Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020:
Interest Expense
The increase in Interest expense, net was due to higher debt balances driven by the August 2021 senior unsecured notes, February 2021 term loan and the June 2020 senior unsecured notes partially offset by lower interest rates.
Impairment of Investment
In the prior year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company.
Other Income (Expense)
The increase in Other income was primarily due to lowerhigher non-service pension costs primarily driven by a lowerhigher discount rate and recognition of death benefits from Company-owned life insurance.rate.
Income Tax Benefit (Expense)
Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the ninesix months ended SeptemberJune 30, 2021,2022, the effective tax rate was 3.5%8.1% compared to 13.6%0.8% for the same period in 2020.2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.
Liquidity and Capital Resources
There have been no material changes in Liquidity and Capital Resources from those reported in Item 7 of our 20202021 Annual Report on Form 10-K except as described below.
In response to the February 2021 Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments above and in further detail in Note 5 of the Notes to Condensed Consolidated Financial Statements.
Cash Flow Activities
The following table summarizes our cash flows for the ninesix months ended SeptemberJune 30, (in thousands):
| | Cash provided by (used in): | Cash provided by (used in): | 2021 | 2020 | Variance | Cash provided by (used in): | 2022 | 2021 | Variance |
| Operating activities | Operating activities | $ | (144,760) | | $ | 419,459 | | $ | (564,219) | | Operating activities | $ | 442,030 | | $ | (250,173) | | $ | 692,203 | |
| Investing activities | Investing activities | $ | (484,106) | | $ | (529,724) | | $ | 45,618 | | Investing activities | $ | (291,385) | | $ | (309,737) | | $ | 18,352 | |
| Financing activities | Financing activities | $ | 633,061 | | $ | 107,819 | | $ | 525,242 | | Financing activities | $ | (149,093) | | $ | 554,905 | | $ | (703,998) | |
Six Months Ended SeptemberJune 30, 20212022 Compared to the NineSix Months Ended SeptemberJune 30, 20202021
Operating Activities:
Net cash provided by (used in) operating activities was $564$692 million lowerhigher than the same period in 2020.2021. The variance to the prior year was primarily attributable to:
•Cash earnings (net income plus non-cash adjustments) were $14$26 million lowerhigher for the ninesix months ended SeptemberJune 30, 20212022 compared to the same period in the prior year primarily due to increased Electric and Gas Utility margins driven by higher operating expensesnew rates and higher interest expenses;increased rider revenues and prior year impacts from Winter Storm Uri.
•Net inflows from changes in certain operating assets and liabilities were $560$670 million lower,higher, primarily attributable to:
◦Cash outflowsinflows increased by $553$679 million as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from Winter Storm Uri;
◦Cash outflows increased by $9.0 million as a result of decreases in accounts payable and accrued liabilities primarily driven by payment timing related to payroll taxes;customers;
◦Cash inflows decreased by $2.3$44 million as a result of changes in accounts receivable and other current assets primarily driven by increased collections of accounts receivable mostly offset by increased purchases of natural gas in storage;higher pass-through revenues reflecting higher commodity prices; and
•◦Cash outflows decreased by $13$36 million due to pension contributions madeas a result of changes in the prior year;accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.
•Cash outflows increased by $2.9$4.0 million for other operating activities.activities which was primarily driven by changes in contractor retainage balances.
Investing Activities:
Net cash used in investing activities was $46$18 million lower than the same period in 2020.2021. The variance to the prior year was primarily attributable to:
•Capital expenditures of $498$294 million for the ninesix months ended SeptemberJune 30, 20212022 compared to $536$319 million for the same period in the prior year. Lower current year expenditures arewere driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities segmentsand the prior year Corriedale wind project at our Electric Utilities segment;Utilities; and
•Cash inflows increaseddecreased by $7.5$7.3 million for other investing activities which was primarily driven by theprior year sales of transmission assets and facilities, none of which were individually significant.material.
Financing Activities:
Net cash provided byused in financing activities was $525$704 million higher than the same period in 2020.2021. The variance to the prior year was primarily attributable to:
•Cash inflows increased $562decreased $680 million due to short-term and long-term borrowingsrepayments in excess of repayments;borrowings which was primarily driven by prior year term loan borrowings related to Winter Storm Uri;
•Cash inflows decreased $36$20 million due to lowerdecreased issuances of common stock;
•Cash outflows increased $7.0$6.0 million due to increased dividends paid on common stock;
•Cash outflows decreased $2.4 million due to decreased distributions to non-controlling interests; and
•Cash outflows decreasedinflows increased by $3.7$1.4 million for other financing activities.
Capital SourcesResources
Short-term Debt
Revolving Credit Facility and CP Program
On July 19, 2021, we amended and restated our corporate Revolving Credit Facility under similar terms and conditions, See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit and available capacity (in millions):
| | | | | | | | | | | | | | | | | |
| | Current | Short-term borrowings at | Letters of Credit (a) at | Available Capacity at |
| Credit Facility | Expiration | Capacity | September 30, 2021 | September 30, 2021 | September 30, 2021 |
| Revolving Credit Facility and CP Program | July 19, 2026 | $ | 750 | | $ | 333 | | $ | 23 | | $ | 394 | |
| | | | | | | | | | | | | | | | | |
| | Current | Short-term borrowings at | Letters of Credit (a) at | Available Capacity at |
| Credit Facility | Expiration | Capacity | June 30, 2022 | June 30, 2022 | June 30, 2022 |
| Revolving Credit Facility and CP Program | July 19, 2026 | $ | 750 | | $ | 335 | | $ | 14 | | $ | 401 | |
__________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit.Credit Facility. For more information on these letters of credit, see Note 5 of the Notes to Condensed Consolidated Financial Statements.
The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at SeptemberJune 30, 20212022 was 0.19%1.74%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the ninesix months ended SeptemberJune 30, 20212022 was:
| | | | | |
| (dollars in millions) |
| Maximum amount outstanding (based on daily outstanding balances) | $ | 333429 | |
| Average amount outstanding (based on daily outstanding balances) | $ | 224326 | |
| Weighted average interest rates | 0.210.82 | % |
Term Loan
See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to our term loan.
Long-term Debt
See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to our long-term debt.
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of SeptemberJune 30, 2021.2022. See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.
Equity
See Note 5 of the Notes to Condensed Consolidated Financial Statements for information related to common stock issuances under the ATM.
Future Financing Plans
We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. In the fourth quarter of 2021, weWe plan to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program and issuing an additional $40 million to $60 million of common stock under the ATM.
Credit Ratings
After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.
The following table represents the credit ratings, and outlook and risk profile of BHC at SeptemberJune 30, 2021:2022:
| | | | | | | | |
| Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
__________
(a) On April 10, 2020,October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b) On December 21, 2020,20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c) On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.
The following table represents the credit ratings of South Dakota Electric at SeptemberJune 30, 2021:2022:
| | | | | |
| Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’sFitch (b)
| A1 |
Fitch (c)
| A |
__________
(a) On April 16, 2020,March 31, 2022, S&P reported A rating.
(b) On December 21, 2020, Moody’s reported A1 rating.
(c) On September 17, 2021, Fitch reported A rating.
Capital Requirements
Capital Expenditures
| | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | Forecasted (c) |
| Capital Expenditures by Segment | Nine Months Ended September 30, 2021 (a) | | 2021 (b) | 2022 | 2023 | 2024 | 2025 |
| (in millions) | | | | | | | |
| Electric Utilities | $ | 172 | | | $ | 251 | | $ | 227 | | $ | 192 | | $ | 271 | | $ | 216 | |
| Gas Utilities | 294 | | | 393 | | 363 | | 383 | | 386 | | 349 | |
| Power Generation | 11 | | | 14 | | 7 | | 6 | | 4 | | 7 | |
| Mining | 6 | | | 9 | | 5 | | 6 | | 10 | | 8 | |
| Corporate and Other | 3 | | | 11 | | 9 | | 13 | | 13 | | 13 | |
Incremental Projects (d) | — | | | — | | — | | — | | — | | 60 | |
| $ | 486 | | | $ | 678 | | $ | 611 | | $ | 600 | | $ | 684 | | $ | 653 | |
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| Actual | | Forecasted |
| Capital Expenditures by Segment | Six Months Ended June 30, 2022 (a) | | 2022 (b) | 2023 | 2024 | 2025 | 2026 |
| (in millions) | | | | | | | |
| Electric Utilities | $ | 120 | | | $ | 239 | | $ | 205 | | $ | 285 | | $ | 231 | | $ | 155 | |
| Gas Utilities | 150 | | | 363 | | 383 | | 386 | | 349 | | 346 | |
| Corporate and Other | 4 | | | 9 | | 12 | | 13 | | 13 | | 13 | |
Incremental Projects (c) | — | | | — | | — | | — | | 60 | | 140 | |
| $ | 274 | | | $ | 611 | | $ | 600 | | $ | 684 | | $ | 653 | | $ | 654 | |
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(b) Includes actual capital expenditures for the ninesix months ended SeptemberJune 30, 2021.2022.
(c) The increase in forecasted capital expenditures is primarily driven by the Ready Wyoming transmission project at our Electric Utilities. Additionally, we have identified various other projects at our Electric and Gas Utilities that were previously disclosed as Incremental.
(d) These represent projects that are being evaluated by our segments for timing, cost and other factors.
Dividends
Dividends paid on our common stock totaled $107$77 million for the ninesix months ended SeptemberJune 30, 2021,2022, or $0.565$0.595 per share per quarter. On October 26, 2021,July 25, 2022, our board of directors declared a quarterly dividend of $0.595 per share payable DecemberSeptember 1, 2021,2022, equivalent to an annual dividend of $2.38 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.
Unconditional Purchase Obligations
See Note 3 of the Notes to Condensed Consolidated Financial Statements for recent updates to our purchase obligations.
Critical Accounting Policies Involving Significant Estimates
There have been no material changes in our critical accounting estimates from those reported in our 20202021 Annual Report on Form 10-K. We continue toare closely monitormonitoring the impacts of COVID-19recent macroeconomic trends and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, cost recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 20202021 Annual Report on Form 10-K.
New Accounting Pronouncements
Other than the pronouncements reported in our 20202021 Annual Report on Form 10-K and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements, in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations or cash flows.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes to our quantitative and qualitative disclosures about market risk previously disclosed in Item 7A of our Annual Report on Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of SeptemberJune 30, 2021.2022. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at SeptemberJune 30, 2021.2022.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended SeptemberJune 30, 2021,2022, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 3 in Item 8 of our 20202021 Annual Report on Form 10-K and Note 3 in Item 1 of Part I of this Quarterly Report on Form 10-Q.the Notes to Condensed Consolidated Financial Statements.
ITEM 1A.RISK FACTORS
There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 20202021 Annual Report on Form 10-K.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table contains monthly information about our acquisitions of equity securities for the three months ended SeptemberJune 30, 2021:2022:
| | | | | | | | | | | | | | |
| Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
| | | | |
| | | | |
| | | | |
| July 1, 2021 - July 31, 2021 | 2 | $ | 66.21 | | — | | — | |
| August 1, 2021 - August 31, 2021 | 260 | $ | 70.24 | | — | | — | |
| September 1, 2021 - September 30, 2021 | 1 | $ | 71.52 | | — | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Total | 263 | | $ | 70.21 | | — | | — | |
_____________ | | | | | | | | | | | | | | |
| Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
| | | | |
| | | | |
| | | | |
| April 1, 2022 - April 30, 2022 | 2 | $ | 78.44 | | — | | — | |
| May 1, 2022 - May 31, 2022 | 741 | $ | 75.60 | | — | | — | |
| June 1, 2022 - June 30, 2022 | 3 | $ | 76.38 | | — | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Total | 746 | | $ | 75.61 | | — | | — | |
__________
(a) Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Quarterly Report on Form 10-Q..
ITEM 6. EXHIBITS
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.
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4.1 | |
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| 10.1 | FourthBlack Hills Corporation Amended and Restated Credit Agreement dated as of July 19, 2021 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent2015 Omnibus Incentive Plan (filed as Exhibit 10.1Appendix A to the Registrant’s Form 8-Kdefinitive proxy statement for the 2022 Annual Meeting of Shareholders filed on July 19, 2021)March 17, 2022). |
| 31.1* | |
| 31.2* | |
| 32.1* | |
| 32.2* | |
| 95* | |
| 101.INS* | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
| 101.SCH* | XBRL Taxonomy Extension Schema Document |
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document |
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase Document |
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document |
| 104* | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BLACK HILLS CORPORATION
| | | | | | | | |
| | /s/ Linden R. Evans |
| | Linden R. Evans, President and |
| | Chief Executive Officer |
| | |
| | /s/ Richard W. Kinzley |
| | Richard W. Kinzley, Senior Vice President and |
| | Chief Financial Officer |
| | |
| Dated: | November 3, 2021August 4, 2022 | |