☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2022
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 Dakota57702
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.
Large Accelerated Filer
x
Accelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒
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.
The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
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).
ASU
Accounting Standards Update issued by the FASB
ATM
At-the-market equity offering program
Availability
The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC
Black Hills Corporation; the Company
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
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 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
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.
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
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.
Dekatherm. A unit of energy equal to 10 therms or approximately one million British thermal units (MMBtu)
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings Inc.
GAAP
Accounting principles generally accepted in the United States of America
Heating Degree Day
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
IRS
United States Internal Revenue Service
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
MEAN
Municipal Energy Agency of Nebraska
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
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.
NOx
Nitrogen oxide
NPSC
Nebraska Public Service Commission
OCI
Other Comprehensive Income
PPA
Power Purchase Agreement
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 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 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.
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.
RMNG
Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
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).
SSIR
System Safety and Integrity Rider
SPP
Southwest 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.
WPSC
Wyoming Public Service Commission
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).
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. 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 2021 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;
•The effects of changing interest rates;
•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.
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2021 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 GAAP 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 2021 Annual Report on Form 10-K.
Segment Reporting
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products and 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 September 30, 2022, December 31, 2021 and September 30, 2021 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.
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 but do not expect it to have a material impact on our financial position, results of operations and cash flows.
We had the following regulatory assets and liabilities (in thousands):
As of
As of
September 30, 2022
December 31, 2021
Regulatory assets
Winter Storm Uri (a)
$
392,994
$
509,025
Deferred energy and fuel cost adjustments (b)
74,998
59,973
Deferred gas cost adjustments (b)
18,764
9,488
Gas price derivatives (b)
10,776
2,584
Deferred taxes on AFUDC (b)
7,407
7,457
Employee benefit plans and related deferred taxes (c)
86,335
88,923
Environmental (b)
1,346
1,385
Loss on reacquired debt (b)
19,663
21,011
Deferred taxes on flow through accounting (b)
66,039
63,243
Decommissioning costs (b)
4,094
5,961
Other regulatory assets (b)
23,790
27,549
Total regulatory assets
706,206
796,599
Less current regulatory assets
(290,087)
(270,290)
Regulatory assets, non-current
$
416,119
$
526,309
Regulatory liabilities
Deferred energy and gas costs (b)
$
6,283
$
6,113
Employee benefit plan costs and related deferred taxes (c)
31,168
32,241
Cost of removal (b)
174,312
179,976
Excess deferred income taxes (c)
257,282
264,042
Other regulatory liabilities (c)
25,715
20,579
Total regulatory liabilities
494,760
502,951
Less current regulatory liabilities
(24,797)
(17,574)
Regulatory liabilities, non-current
$
469,963
$
485,377
__________
(a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below.
(b) Recovery of costs, but we are not allowed a rate of return.
(c) 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 2021 Annual Report on Form 10-K.
Arkansas Gas
On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. On October 10, 2022, the APSC approved a partial settlement agreement with all intervening parties for a general rate increase and authorized a capital structure of 45% equity and 55% debt and a return on equity of 9.6%. The APSC’s decision shifts approximately $10 million of rider revenue to base rates and is expected to generate $8.8 million of new annual revenue. The APSC also approved a new comprehensive safety and integrity rider which replaces three former riders. New rates were effective on October 21, 2022.
On October 7, 2022, RMNG filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 600-mile natural gas pipeline system. The rate review requests $12.3 million in new annual revenue based on a future test year with a capital structure of 52% equity and 48% debt and a return on equity of 12.3%. The rate review also requests a $7.7 million shift of SSIR revenues to base rates. The request seeks to finalize rates in the third quarter of 2023.
Winter Storm Uri
In February 2021, Winter Storm Uri 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, 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 3.5 years. In these applications, we sought approval to recover carrying costs. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow full recovery of our incremental fuel, purchased power and natural gas costs.
On January 27, 2022, Kansas Gas received approval from the KCC for its Winter Storm Uri 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. On October 20, 2022, Wyoming Gas received approval from the WPSC for its Winter Storm Uri cost recovery application. The WPSC had previously approved interim cost recovery effective in September 2021.
For three and nine months ended September 30, 2022 and 2021, $3.7 million, $18 million, $1.8 million and $1.8 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. The carrying costs accrued during the nine months ended September 30, 2022 included a one-time, $10 million true-up recorded in the second quarter to reflect Commission authorized rates.
For the nine months ended September 30, 2022, our Utilities collected $125 million of Winter Storm Uri incremental costs and carrying costs from customers. As of September 30, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.8 years.
TCJA
As part of Kansas Gas’ 2021 rate review settlement agreement, Kansas Gas will annually deliver $3.0 million of TCJA and state tax reform benefits to customers for three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). For the three and nine months ended September 30, 2022, Kansas Gas delivered TCJA and state tax reform bill credits to customers of $0.6 million and $2.1 million, respectively.
These 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 nine months ended September 30, 2022.
Wyoming Electric
On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1,330-mile electric distribution and 59-mile electric transmission systems. The rate review requests $15 million in new annual revenue with a capital structure of 54% equity and 46% debt and a return on equity of 10.3%. The request seeks to finalize rates in the first quarter of 2023.
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 2021 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. The new agreement 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. The new agreement 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 have appealed the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable.
Power Purchase Agreements
On June 23, 2022, Wyoming Electric entered into a PPA with Roundhouse Renewable Energy II, LLC (Roundhouse Renewable Energy) to purchase up to 106 MW of renewable energy upon construction of a new wind facility, to be owned by Roundhouse Renewable Energy, which is expected to be completed by the end of 2023. The agreement will expire 20 years after construction completion. The wind energy from this PPA will be used to serve our expanding partnerships with industrial customers in Cheyenne, Wyoming.
On March 21, 2022, Wyoming Electric entered 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 an 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. On May 27, 2022, Colorado Electric filed its 2030 Ready Plan with the CPUC. A CPUC decision is expected in March 2023, after which time, Colorado Electric will seek new requests for proposals for renewable energy resources.
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.
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 nine months ended September 30, 2022 and 2021. Sales tax and other similar taxes are excluded from revenues.
We had the following Notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2022
December 31, 2021
Balance Outstanding
Letters of Credit (a)
Balance Outstanding
Letters of Credit (a)
Revolving Credit Facility
$
—
$
20,193
$
—
$
27,209
CP Program
501,350
—
420,180
—
Total Notes payable
$
501,350
$
20,193
$
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
Our net short-term borrowings related to our Revolving Credit Facility and CP Program during the nine months ended September 30, 2022 were $81 million. The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at September 30, 2022 was 3.35%.
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. 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.
We were in compliance with our covenants at September 30, 2022 as shown below:
As of September 30, 2022
Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio
61.7%
Less than
65%
Wyoming Electric
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2022, Wyoming Electric’s debt to capitalization ratio was 49%, which was in compliance with these financial covenants.
Equity
At-the-Market Equity Offering Program
During the three months ended September 30, 2022, we did not issue any shares of common stock under the ATM. During the nine months ended September 30, 2022, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $20 million, net of $0.2 million in issuance costs. During the three months ended September 30, 2021, we issued a total of 0.3 million shares of common stock under the ATM for proceeds of $23 million, net of $0.2 million in issuance costs. During the nine months ended September 30, 2021, we issued a total of 0.9 million shares of common stock under the ATM for proceeds of $63 million, net of $0.6 million in issuance costs.
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,
2022
2021
2022
2021
Net income available for common stock
$
34,973
$
44,112
$
185,914
$
165,589
Weighted average shares - basic
64,876
63,341
64,722
62,950
Dilutive effect of:
Equity compensation
185
95
188
96
Weighted average shares - diluted
65,061
63,436
64,910
63,046
Earnings per share of common stock:
Earnings per share, Basic
$
0.54
$
0.70
$
2.87
$
2.63
Earnings per share, Diluted
$
0.54
$
0.70
$
2.86
$
2.63
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,
2022
2021
2022
2021
Equity compensation
—
9
—
12
Restricted stock
—
—
—
1
Anti-dilutive shares
—
9
—
13
(7) Risk Management and Derivatives
Market and Credit Risk Disclosures
Our activities in the energy industry 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:
•Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and 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 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 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, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants 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 utility commissions, we have entered into commission 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 use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers. Periodically, certain wholesale energy contracts are considered derivative instruments due to not qualifying for the normal purchase 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.
To support our Choice Gas Program customers, 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 risks 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 2022 through December 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, 2022
December 31, 2021
Notional Amounts (MMBtus)
Maximum
Term
(months) (a)
Notional Amounts (MMBtus)
Maximum
Term
(months) (a)
Natural gas futures purchased
1,780,000
6
590,000
3
Natural gas options purchased, net
5,500,000
6
3,100,000
3
Natural gas basis swaps purchased
1,530,000
6
870,000
3
Natural gas over-the-counter swaps, net (b)
6,050,000
27
4,570,000
34
Natural gas physical contracts, net (c)
29,017,775
15
16,416,677
24
__________
(a) Term reflects the maximum forward period hedged.
(b) As of September 30, 2022, 2,292,300 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 September 30, 2022, the Company posted $4.6 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 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:
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 nine months ended September 30, 2022 and 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,
2022
2021
2022
2021
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)
Interest rate swaps
$
712
$
712
Interest expense
$
(712)
$
(712)
Commodity derivatives
2,292
5,536
Fuel, purchased power and cost of natural gas sold
43
331
Total
$
3,004
$
6,248
$
(669)
$
(381)
Nine Months Ended September 30,
Nine Months Ended September 30,
2022
2021
2022
2021
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)
Interest rate swaps
$
2,138
$
2,138
Interest expense
$
(2,138)
$
(2,138)
Commodity derivatives
(2,946)
6,896
Fuel, purchased power and cost of natural gas sold
3,620
356
Total
$
(808)
$
9,034
$
1,482
$
(1,782)
As of September 30, 2022, $4.0 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings 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 nine months ended September 30, 2022 and 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,
2022
2021
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)
Commodity derivatives - Electric
Fuel, purchased power and cost of natural gas sold
$
—
$
2,494
Commodity derivatives - Natural Gas
Fuel, purchased power and cost of natural gas sold
Amount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - Electric
Fuel, purchased power and cost of natural gas sold
$
—
$
(2,628)
Commodity derivatives - Natural Gas
Fuel, purchased power and cost of natural gas sold
2,779
6,186
$
2,779
$
3,558
As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, 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 included in our Regulatory asset accounts related to these financial instruments in our Gas Utilities were $11 million and $2.6 million as of September 30, 2022 and December 31, 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 credit 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 2021 Annual Report on Form 10-K.
The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting of cash collateral and contractual netting rights as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.
As of September 30, 2022
Level 1
Level 2
Level 3
Cash Collateral and Counterparty
Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives — Gas Utilities
$
—
$
11,832
$
—
$
(6,594)
$
5,238
Total
$
—
$
11,832
$
—
$
(6,594)
$
5,238
Liabilities:
Commodity derivatives — Gas Utilities
$
—
$
12,212
$
—
$
(6,619)
$
5,593
Total
$
—
$
12,212
$
—
$
(6,619)
$
5,593
__________
(a) As of September 30, 2022, $6.6 million of our commodity derivative assets and $6.6 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.
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 13 to the Consolidated Financial Statements included in our 2021 Annual Report on Form 10-K.
Other Fair 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 are not traded on an exchange; therefore, they are classified as 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, 2022
December 31, 2021
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-term debt, including current maturities (a)
$
4,131,033
$
3,736,930
$
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 in 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
Amount Reclassified from AOCI
Three Months Ended September 30,
Nine Months Ended September 30,
2022
2021
2022
2021
Gains and (losses) on cash flow hedges:
Interest rate swaps
Interest expense
$
(712)
$
(712)
$
(2,138)
$
(2,138)
Commodity contracts
Fuel, purchased power and cost of natural gas sold
43
331
3,620
356
(669)
(381)
1,482
(1,782)
Income tax
Income tax expense
124
(26)
(332)
308
Total reclassification adjustments related to cash flow hedges, net of tax
$
(545)
$
(407)
$
1,150
$
(1,474)
Amortization of components of defined benefit plans:
Prior service cost
Operations and maintenance
$
24
$
25
$
70
$
74
Actuarial gain (loss)
Operations and maintenance
(188)
(598)
(563)
(1,793)
(164)
(573)
(493)
(1,719)
Income tax
Income tax expense
58
133
157
492
Total reclassification adjustments related to defined benefit plans, net of tax
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 nine months of 2022 and anticipated contributions for 2022 and 2023 are as follows (in thousands):
Contributions Made
Additional Contributions
Contributions
Nine Months Ended September 30, 2022
Anticipated for 2022
Anticipated for 2023
Defined Benefit Pension Plan
$
—
$
—
$
—
Non-pension Defined Benefit Postretirement Healthcare Plan
$
3,828
$
1,276
$
5,062
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
1,617
$
539
$
2,224
Funding Status of Employee Benefit Plans
Based on the fair value of assets and estimated discount rate used to value benefit obligations as of September 30, 2022, we estimate the unfunded status of our employee benefit plans to be approximately $32 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 had a limited impact to our unfunded status and does not require interim re-measurement of our pension plan assets or defined benefit obligations.
(11) Income Taxes
Income Tax Expense (Benefit) and Effective Tax Rates
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021
Income tax expense for the three months ended September 30, 2022 was $2.1 million compared to $5.3 million for the same period in 2021. For the three months ended September 30, 2022 the effective tax rate was 5.2% compared to 9.8% for the same period in 2021. The lower effective tax rate was primarily due to tax benefits from state rate changes.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021
Income tax expense for the nine months ended September 30, 2022 was $16 million compared to $6.3 million for the same period in 2021. For the nine months ended September 30, 2022, the effective tax rate was 7.6% compared to 3.5% for the same period in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which were offset by reduced revenue) partially offset by $3.4 million of tax benefits from state rate changes and $2.0 million of increased tax benefits from federal PTCs associated with increased wind production 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 making decisions and assessing financial performance. Our CODM assesses the performance of our operating segments based on operating income.
For the first nine months of 2021, we had reported four operating segments: Electric Utilities, Gas Utilities, Power Generation and Mining. 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.
Our operating segments are equivalent to our reportable segments.
Net income attributable to non-controlling interest
(2,861)
(4,050)
(8,790)
(11,347)
Net income available for common stock
$
34,973
$
44,112
$
185,914
$
165,589
(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, 2022
December 31, 2021
Billed Accounts Receivable
$
168,757
$
181,027
Unbilled Revenue
82,925
142,738
Less: Allowance for Credit Losses
(1,935)
(2,113)
Accounts Receivable, net
$
249,747
$
321,652
Changes to allowance for credit losses for the nine months ended September 30, 2022 and 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,
2022
$
2,113
$
6,473
$
2,117
$
(8,768)
$
1,935
2021
$
7,003
$
1,111
$
2,420
$
(8,222)
$
2,312
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:
The following amounts by major classification are included in Accrued liabilities on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
September 30, 2022
December 31, 2021
Accrued employee compensation, benefits and withholdings
$
64,855
$
74,387
Accrued property taxes
46,513
50,874
Customer deposits and prepayments
44,254
48,814
Accrued interest
46,408
33,680
Other (none of which is individually significant)
48,805
37,004
Total accrued liabilities
$
250,835
$
244,759
(14) Subsequent Events
Except as described in Note 2, there have been no events subsequent to September 30, 2022, which would require recognition in the condensed consolidated financial statements or disclosures.
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 our 2021 Form 10-K.
Executive Summary
Black Hills Corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”) is a customer-focused energy solutions provider that invests in its communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas 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, Winter Storm Uri 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, we incurred significant incremental fuel, purchased power and natural gas costs.
In 2021, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow full recovery of our incremental fuel, purchased power and natural gas costs. See Note 2 of the Notes to Condensed Consolidated Financial Statements for further information.
Macroeconomic Trends
We are monitoring macroeconomic trends including inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; rising interest rates and a competitive and tight labor market. To date, we have experienced moderate net impacts from these trends.
Higher commodity energy costs continue to have an effect on customer bills. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer, which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. As a result of increased customer billings, we incurred higher bad debt expense.
We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital investment targets. We have contracted a significant majority of the materials needed to complete our 2022 capital program. We have also evaluated each of our forecasted projects and will prioritize depending on future constraints. Project delays may occur if costs rise significantly or if materials are not available.
Inflationary pressures and supply chain constraints have increased our operating expenses, which included higher outside services expenses (i.e. consulting and contractor rates), materials expenses and vehicle expenses driven by higher fuel prices.
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 89% of our debt at September 30, 2022 is fixed rate debt. Rising discount rates and recent capital markets volatility had a limited impact to our 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 lower total employee costs due to workforce attrition partially offset by increased employee and contractor costs related to attraction and retention of talent.
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.
Sustainability Goals Updated
On August 31, 2022, we published our 2021 Sustainability Report highlighting our environmental, social and governance achievements and strategies to further decarbonize our Utilities’ systems. The report highlights our progress toward reducing greenhouse gas emissions intensity by one-third off a 2005 baseline. In addition, we announced a new Net Zero by 2035 target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of RNG and hydrogen and utilizing carbon credit offsets.
Environmental Matters - Good Neighbor Rule
In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the Cross-State Air Pollution Rule (CSAPR) framework and is intended to address ozone transport for the 2015 ozone National Ambient Air Quality Standards (NAAQS). The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states, including Wyoming for the first time. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of Selective Catalytic Reactor controls at certain generating facilities. The EPA accepted comments on the proposal through June 21, 2022. We anticipate that any costs incurred as a result of the proposed rule would be recoverable through our regulatory mechanisms.
Inflation Reduction Act
The “Inflation Reduction Act” (“IRA”), signed into law by President Biden on August 16, 2022, features $370 billion in spending and tax incentives on clean energy provisions. Most notably, the IRA includes provisions such as the extension and expansion of production and investment tax credits for wind and solar; energy storage, renewable natural gas, and carbon capture and sequestration; and the transferability of clean energy tax credits. We are currently evaluating the IRA provisions to determine impacts and opportunities.
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 October 11, 2022, the WPSC approved a CPCN submitted by Wyoming Electric to construct an estimated 260-mile transmission expansion project. The transmission expansion project, known as Ready Wyoming, will provide customers long-term price stability and greater flexibility as power markets develop in the Western States. Construction of the project is expected to take place in multiple phases or segments from 2023 through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.
•On July 21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous summer peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021.
•On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 403 MW, surpassing the previous summer peak of 397 MW set in July 2021.
•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 to a new customer in Cheyenne, Wyoming up to 45 MW with an option to expand service up to 75 MW. Energy will be sourced through the electric energy market and 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 2030 Ready Plan establishes a roadmap and preferred resource portfolio for Colorado Electric to achieve the state of Colorado’s requirement calling upon electric utilities to reduce GHG emissions by a minimum of 80% by 2030. The preferred resource portfolio calls for the addition of 149 MW of wind, 258 MW of solar and 50 MW of battery 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 in March 2023, which would be followed by a request for proposals for renewable energy resources.
•On February 23, 2022, Wyoming Electric set a new winter peak load of 262 MW, surpassing the previous winter peaks of 252 MW set on January 5, 2022 and 247 MW set in December 2019.
•During the first quarter of 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service (“WEIS”) Market. On September 26, 2022, South Dakota Electric and Wyoming Electric also agreed to join the WEIS Market. South Dakota Electric and Wyoming Electric will join Colorado Electric in integrating into the WEIS 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 set a new winter peak load of 327 MW, surpassing the previous winter peak of 326 MW set in February 2021.
Gas Utilities
•See Note 2 of the Notes to Condensed Consolidated Financial Statements for recent rate review activity for Arkansas Gas and RMNG.
•During the third quarter of 2022, Kansas Gas and Nebraska Gas submitted proposals to their respective state utility commissions 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 emissions associated with their own natural gas usage. The offset would be achieved through a combination of carbon offset credits and RNG attributes. Kansas Gas and Nebraska Gas designed their voluntary RNG and carbon offset programs as comprehensive four-year pilot programs starting in 2023 and running through 2026. On October 25, 2022, Kansas Gas received approval from the KCC for its voluntary RNG and carbon offset program. On June 6, 2022, Colorado Gas had submitted a similar proposal to the CPUC. In response to intervenor-filed testimony, Colorado Gas filed a motion to withdraw its application which was granted by an administrative law judge on October 26, 2022.
Corporate and Other
•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. We believe we have meritorious defenses to the verdict and have appealed the verdict. See additional information in Note 3 of the Notes to Condensed Consolidated Financial Statements.
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 nine months ended September 30, 2022 and 2021, and our financial condition as of September 30, 2022 and December 31, 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,
2022
2021
2022
2021
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities
$
69,483
$
72,840
$
165,455
$
159,645
Gas Utilities
10,583
17,257
162,318
139,336
Corporate and Other
(587)
(224)
(2,552)
(3,527)
Operating income
79,479
89,873
325,221
295,454
Interest expense, net
(40,019)
(38,018)
(117,328)
(113,820)
Other income, net
464
1,560
2,731
1,635
Income tax (expense)
(2,090)
(5,253)
(15,920)
(6,333)
Net income
37,834
48,162
194,704
176,936
Net income attributable to non-controlling interest
(2,861)
(4,050)
(8,790)
(11,347)
Net income available for common stock
$
34,973
$
44,112
$
185,914
$
165,589
Total earnings per share of common stock, Diluted
$
0.54
$
0.70
$
2.86
$
2.63
Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021:
The variance to the prior year included the following:
•Electric Utilities’ operating income decreased $3.4 million primarily due to higher operating expenses, prior year mark-to-market gains on wholesale energy contacts and lower pricing on the new Wygen I PPA partially offset by increased rider revenues, increased transmission services revenue and off-system excess energy sales and favorable weather;
•Gas Utilities’ operating income decreased $6.7 million primarily due to higher operating expenses and mark-to-market losses on wholesale commodity contracts partially offset by favorable weather, new rates and rider recovery and carrying costs on our Winter Storm Uri regulatory asset;
•Interest expense increased $2.0 million due to higher interest rates and higher short-term borrowings;
•Other income decreased $1.1 million primarily due to a prior year recognition of death benefits from Company-owned life insurance;
•Income tax expense decreased $3.2 million primarily due to lower pre-tax income; and
•Net income attributable to non-controlling interest decreased $1.2 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours.
Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021:
The variance to the prior year included the following:
•Electric Utilities’ operating income increased $5.8 million primarily due to increased rider revenues, prior year impacts related to Colorado Electric’s TCJA-related bill credits to customers (which were offset by reduced income tax expense), increased transmission services revenue and off-system excess energy sales and prior year mark-to-market losses on wholesale energy contacts partially offset by higher operating expenses and lower pricing on the new Wygen I PPA;
•Gas Utilities’ operating income increased $23 million primarily due to new rates and rider recovery, carrying costs on our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth and increased usage per customer partially offset by higher operating expenses;
•Corporate and Other expenses decreased $1.0 million primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments;
•Interest expense increased $3.5 million due to higher interest rates and higher short-term and long-term debt balances;
•Other income increased $1.1 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by a prior year recognition of death benefits from Company-owned life insurance;
•Income tax expense increased $9.6 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits partially offset by tax benefits from state tax rate changes; and
•Net income attributable to non-controlling interest decreased $2.6 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours and 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, Electric 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. Electric 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.
Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact Electric and Gas Utility margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through to our customers.
Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Operating results for the Electric Utilities were as follows (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2022
2021
Variance
2022
2021
Variance
Revenue:
Electric - regulated
$
245,269
$
210,053
$
35,216
$
635,190
$
614,652
$
20,538
Other - non-regulated
13,401
10,351
3,050
34,396
32,172
2,224
Total revenue
258,669
220,404
38,265
669,586
646,824
22,762
Cost of fuel and purchased power:
Electric - regulated
84,309
50,238
34,071
191,511
194,314
(2,803)
Other - non-regulated
1,644
893
751
3,484
2,679
805
Total cost of fuel and purchased power
85,953
51,131
34,822
194,995
196,993
(1,998)
Electric Utility margin (non-GAAP)
172,716
169,273
3,443
474,591
449,831
24,760
Operations and maintenance
68,896
63,472
5,424
207,565
192,507
15,058
Depreciation and amortization
34,337
32,961
1,376
101,571
97,679
3,892
Total operating expenses
103,233
96,433
6,800
309,136
290,186
18,950
Operating income
$
69,483
$
72,840
$
(3,357)
$
165,455
$
159,645
$
5,810
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021:
Electric Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery
$
3.9
Transmission services and off-system excess energy sales
1.7
Weather
1.0
Commercial and industrial load growth
0.7
Integrated Generation (a)
0.7
Lower pricing on new Wygen I PPA
(2.8)
Prior year mark-to-market on wholesale energy contracts
(2.5)
Other
0.7
Total increase in Electric Utility margin
$
3.4
__________
(a) Primarily driven by favorable market pricing.
Operations and maintenance expense increased primarily due to higher generation-related expenses, higher vehicle expenses due to higher fuel costs, increased royalties on higher mining revenues partially offset by lower employee costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021:
Electric Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery
$
10.5
Prior year TCJA-related bill credits (a)
9.3
Transmission services and off-system excess energy sales
4.4
Prior year mark-to-market on wholesale energy contracts
2.6
Integrated Generation (b)
1.8
Prior year Winter Storm Uri impacts (c)
1.2
Weather
0.8
Lower pricing on new Wygen I PPA
(7.9)
Other
2.1
Total increase in Electric Utility margin
$
24.8
__________
(a) In February 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 an immaterial impact to Net income.
(b) Primarily driven by favorable market pricing.
(c) 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 partially offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.
Operations and maintenance expense increased primarily due to higher cloud computing licensing costs, higher generation-related expenses, higher vehicle expenses due to higher fuel costs, higher outside services expenses and increased property taxes due to expiration of an abatement partially offset by lower employee costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
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,
2022
2021
2022
2021
2022
2021
2022
2021
Residential
$
72,115
$
66,138
$
187,217
$
192,349
421,782
419,001
1,137,139
1,150,150
Commercial
77,314
70,696
210,423
214,512
581,239
576,037
1,581,487
1,570,455
Industrial
47,090
37,323
120,688
115,518
483,223
459,076
1,411,919
1,316,060
Municipal
6,093
5,069
15,660
14,471
46,745
47,515
122,290
123,620
Subtotal Retail Revenue - Electric
202,612
179,226
533,989
536,850
1,532,989
1,501,629
4,252,835
4,160,285
Contract Wholesale
8,378
3,855
18,639
12,787
160,070
129,221
492,922
415,979
Off-system/Power Marketing Wholesale
16,769
13,511
32,590
25,549
131,469
120,224
436,335
329,426
Other (a)
17,509
13,461
49,972
39,466
—
—
—
—
Total Regulated
245,269
210,053
635,190
614,652
1,824,528
1,751,074
5,182,092
4,905,690
Non-Regulated (b)
13,401
10,351
34,396
32,172
59,745
56,583
221,609
197,506
Total Revenue and Quantities Sold
$
258,669
$
220,404
$
669,586
$
646,824
1,884,273
1,807,657
5,403,701
5,103,196
Other Uses, Losses or Generation, net (c)
125,613
139,521
337,222
367,201
Total Energy
2,009,886
1,947,178
5,740,923
5,470,397
__________
(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.
Operating results for the Gas Utilities were as follows (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2022
2021
Variance
2022
2021
Variance
Revenue:
Natural gas - regulated
$
192,104
$
150,075
$
42,029
$
1,046,910
$
700,617
$
346,293
Other - non-regulated
16,184
14,608
1,576
56,938
52,635
4,303
Total revenue
208,288
164,683
43,605
1,103,849
753,252
350,597
Cost of natural gas sold:
Natural gas - regulated
77,590
43,884
33,706
588,007
289,168
298,839
Other - non-regulated
5,187
(750)
5,937
11,242
10,131
1,111
Total cost of natural gas sold
82,778
43,134
39,644
599,249
299,299
299,950
Gas Utility margin (non-GAAP)
125,510
121,549
3,961
504,600
453,953
50,647
Operations and maintenance
85,311
78,161
7,150
255,441
237,624
17,817
Depreciation and amortization
29,616
26,131
3,485
86,841
76,993
9,848
Total operating expenses
114,927
104,292
10,635
342,282
314,617
27,665
Operating income
$
10,583
$
17,257
$
(6,674)
$
162,318
$
139,336
$
22,982
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021:
Gas Utility margin increased as a result of the following:
(in millions)
Weather (a)
$
4.4
New rates and rider recovery
3.5
Carrying costs on Winter Storm Uri regulatory asset (b)
1.9
Mark-to-market on non-utility natural gas commodity contracts
(2.5)
Decreased usage per customer
(0.9)
Other
(2.4)
Total increase in Gas Utility margin
$
4.0
__________
(a) Weather impacts for the three months ended September 30, 2022 compared to the same period in the prior year include $3.8 million of increased irrigation loads to agriculture customers in our Nebraska Gas service territory.
(b) In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. See Note 2 of the Notes to Condensed Consolidated Financial Statements for additional information.
Operations and maintenance expense increased primarily due to increased bad debt expense primarily attributable to higher customer billings, higher outside services and materials expenses, and higher vehicle expenses due to higher fuel costs partially offset by lower employee costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021:
Gas Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery
$
21.0
Carrying costs on Winter Storm Uri regulatory asset (a)
16.5
Prior year Black Hills Energy Services Winter Storm Uri costs (b)
8.2
Customer growth and increased usage per customer
4.8
Weather (c)
3.4
Increased transportation and transmission volumes
1.1
Current and prior year TCJA-related bill credits (d)
0.8
Mark-to-market on non-utility natural gas commodity contracts
(3.4)
Other
(1.8)
Total increase in Gas Utility margin
$
50.6
__________
(a) In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs accrued during the nine months ended September 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 was not recoverable through a regulatory mechanism.
(c) Weather impacts for the nine months ended September 30, 2022 compared to the same period in the prior year include $4.3 million of increased irrigation loads to agriculture customers in our Nebraska Gas service territory.
(d) In June 2021, Nebraska Gas provided $2.9 million TCJA-related bill credits to its customers. For the nine months ended September 30, 2022, Kansas Gas provided $2.1 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 increased bad debt expense primarily attributable to higher customer billings, higher cloud computing licensing costs, higher outside services and materials expenses, higher vehicle expenses due to higher fuel costs and increased property taxes due to a higher asset base partially offset by lower employee costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
(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.
Corporate and Other
Corporate and Other operating results were as follows (in thousands):
Three Months Ended September 30,
Nine Months Ended September 30,
2022
2021
Variance
2022
2021
Variance
Operating (loss)
$
(587)
$
(224)
$
(363)
$
(2,552)
$
(3,527)
$
975
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021:
Operating (loss) was comparable to the same period in the prior year.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021:
The decrease in Operating (loss) was primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments.
Consolidated Interest Expense, Other Income and Income Tax Expense
Three Months Ended September 30,
Nine Months Ended September 30,
2022
2021
Variance
2022
2021
Variance
(in thousands)
Interest expense, net
$
(40,019)
$
(38,018)
$
(2,001)
$
(117,328)
$
(113,820)
$
(3,508)
Other income, net
464
1,560
$
(1,096)
$
2,731
$
1,635
$
1,096
Income tax (expense)
(2,090)
(5,253)
$
3,163
$
(15,920)
$
(6,333)
$
(9,587)
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021:
Interest Expense, net
The increase in Interest expense, net was due to higher interest rates and higher short-term debt balances.
Other Income, net
The decrease in Other income, net was primarily driven by a prior year recognition of death benefits from Company-owned life insurance.
Income Tax (Expense)
Income tax expense decreased primarily due to lower pre-tax income partially offset by lower effective tax rate. For the three months ended September 30, 2022, the effective tax rate was 5.2% compared to 9.8% for the same period in 2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021:
Interest Expense, net
The increase in Interest expense, net was due to higher interest rates and higher short-term and long-term debt balances.
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 and a prior year recognition of death benefits from Company-owned life insurance partially offset by higher non-service pension costs primarily driven by a higher discount rate.
Income Tax (Expense)
Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the nine months ended September 30, 2022, the effective tax rate was 7.6% compared to 3.5% for the same period in 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 2021 Annual Report on Form 10-K except as described below.
Cash Flow Activities
The following table summarizes our cash flows for the nine months ended September 30, (in thousands):
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021
Operating Activities:
Net cash provided by (used in) operating activities was $639 million higher than the same period in 2021. The variance to the prior year was primarily attributable to:
•Cash earnings (net income plus non-cash adjustments) were $28 million higher for the nine months ended September 30, 2022 compared to the same period in the prior year primarily due to increased Electric and Gas Utility margins driven by new rates and increased rider revenues and prior year impacts from Winter Storm Uri.
•Net inflows from changes in certain operating assets and liabilities were $622 million higher, primarily attributable to:
◦Cash inflows increased by $687 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 customers;
◦Cash inflows decreased by $92 million as a result of changes in accounts receivable and other current assets primarily driven by higher pass-through revenues reflecting higher commodity prices; and
◦Cash outflows decreased by $26 million as a result of changes in 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 $10 million for other operating activities primarily due to higher cloud computing licensing costs and preliminary survey charges.
Investing Activities:
Net cash used in investing activities was $18 million lower than the same period in 2021. The variance to the prior year was primarily attributable to:
•Capital expenditures of $466 million for the nine months ended September 30, 2022 compared to $498 million for the same period in the prior year. Lower current year expenditures were driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and
•Cash inflows decreased by $14 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material.
Financing Activities:
Net cash provided by (used in) financing activities was $658 million higher than the same period in 2021. The variance to the prior year was primarily attributable to:
•Cash inflows decreased $609 million due to decreases in short-term and long-term borrowings primarily driven by prior year financing activities related to Winter Storm Uri;
•Cash inflows decreased $43 million due to decreased issuances of common stock;
•Cash outflows increased $8.9 million due to increased dividends paid on common stock; and
•Cash inflows increased by $4.4 million for other financing activities.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit and available capacity:
Current
Short-term borrowings at
Letters of Credit (a) at
Available Capacity at
Credit Facility
Expiration
Capacity
September 30, 2022
September 30, 2022
September 30, 2022
(in millions)
Revolving Credit Facility and CP Program
July 19, 2026
$
750
$
501
$
20
$
229
__________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving 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 at September 30, 2022 was 3.35%. Short-term borrowing activity for the nine months ended September 30, 2022 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)
$
508
Average amount outstanding (based on daily outstanding balances)
$
347
Weighted average interest rates
1.41
%
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of September 30, 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. We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, the issuance of common stock under our ATM program or in an opportunistic block trade, or through a non-controlling investment by a third party in certain operating assets. We plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date.
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, outlook and risk profile of BHC at September 30, 2022:
Rating Agency
Senior Unsecured Rating
Outlook
S&P (a)
BBB+
Stable
Moody’s (b)
Baa2
Stable
Fitch (c)
BBB+
Stable
__________
(a) On August 26, 2022, S&P reported BBB+ rating and maintained a Stable outlook.
(b) On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c) On October 6, 2022, Fitch reported BBB+ rating and maintained a Stable outlook.
The following table represents the credit ratings of South Dakota Electric at September 30, 2022:
Rating Agency
Senior Secured Rating
S&P (a)
A
Fitch (b)
A
__________
(a) On March 31, 2022, S&P reported A rating.
(b) On October 6, 2022, Fitch reported A rating.
Capital Requirements
Capital Expenditures
Actual
Forecasted (c)
Capital Expenditures by Segment
Nine Months Ended September 30, 2022 (a)
2022 (b)
2023
2024
2025
2026
(in millions)
Electric Utilities
$
180
$
255
$
197
$
348
$
226
$
194
Gas Utilities
255
364
386
452
412
393
Corporate and Other
7
8
17
19
20
19
Incremental Projects (d)
—
—
—
—
45
100
$
442
$
627
$
600
$
819
$
703
$
706
__________
(a) Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Condensed Consolidated Statements of Cash Flows in the Condensed Consolidated Financial Statements.
(b) Includes actual capital expenditures for the nine months ended September 30, 2022.
(c) The increase in forecasted capital expenditures is primarily driven by RNG projects at our Gas Utilities. Additionally, we have identified various other projects at our Electric and Gas Utilities that we 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 $116 million for the nine months ended September 30, 2022, or $0.595 per share per quarter. On October 25, 2022, our board of directors declared a quarterly dividend of $0.625 per share payable December 1, 2022, equivalent to an annual dividend of $2.50 per share. The amount of 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 Estimates
There have been no material changes in our critical accounting estimates from those reported in our 2021 Annual Report on Form 10-K. We are closely monitoring the impacts of recent 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 2021 Annual Report on Form 10-K.
New Accounting Pronouncements
Other than the pronouncements reported in our 2021 Annual Report on Form 10-K and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements, 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 September 30, 2022. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 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 September 30, 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 2021 Annual Report on Form 10-K and Note 3 of 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 2021 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 September 30, 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, 2022 - July 31, 2022
2
$
75.59
—
—
August 1, 2022 - August 31, 2022
341
$
74.67
—
—
September 1, 2022 - September 30, 2022
3
$
76.42
—
—
Total
346
$
74.69
—
—
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(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.
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.
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.
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
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.
