BLACK HILLS CORPORATION 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
We are a customer-focused energy solutions provider that invests in our
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 , a prolonged period of historic cold temperatures across the
central United States , which covered all of our Utilities' service territories,
caused a substantial increase in heating and energy demand and contributed to
unforeseeable and unprecedented market prices for natural gas and electricity.
As a result of Winter Storm Uri, we incurred significant incremental natural gas
and fuel costs.
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. To date, we have received final commission approval for
all of our Winter Storm Uri cost recovery applications with the exception of
Wyoming Gas (which is approved for interim cost recovery). 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.
We have seen an increase in commodity energy costs that had an effect on
customer bills. Our utilities have regulatory mechanisms that allow them to pass
prudently incurred costs of energy through to the customer, which mitigates our
exposure. Customer billing rates are adjusted periodically to reflect changes in
our cost of energy.
We are proactively managing increased costs of materials and supply chain
disruptions to achieve our forecasted capital investment targets. We have
already contracted a significant majority of the materials needed for 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.
32
--------------------------------------------------------------------------------
Table of Contents
Rising interest rates have increased interest expense on our variable rate
borrowings, which include our Revolving Credit Facility and CP Program. However,
the increased interest expense was limited since 92% of our debt at June 30,
2022 is fixed rate debt. Additionally, rising discount rates and recent capital
markets volatility did not materially change the unfunded status of the BHC
Pension Plan from the prior year.
We are faced with increased competition for employee and contractor talent in
the current labor market. To date, we have seen increased employee and
contractor costs related to attraction and retention of talent partially offset
by decreases in headcount compared to the prior year.
More detailed discussion of the future uncertainties can be found in "Risk Factors" section in Part I, Item 1A of our 2021 Annual Report on Form 10-K.
Business Segment Recent Developments
•See Note 2 of the Notes to Condensed Consolidated Financial Statements for
recent rate review activity for
•OnJuly 21, 2022 ,Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set onJuly 18, 2022 , 282 MW set onJune 13, 2022 and 274 MW set onJuly 28, 2021 .
•On
•OnJune 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 inCheyenne, 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 ourElectric Utilities' infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs ofWyoming Electric's existing retail customers.Wyoming Electric expects to begin delivering energy to this customer in the fourth quarter of 2022. •OnMay 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 forColorado Electric to cost-effectively achieve the state ofColorado'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 toColorado 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% ofColorado 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 byApril 2023 , which would be followed by a request for proposals for renewable energy resources.
•On
•OnFebruary 15, 2022 ,Wyoming Electric submitted a request to the WPSC seeking approval for a CPCN to construct an estimated 260-mile transmission expansion project. As proposed, the approximately$260 million transmission expansion project, known as Ready Wyoming, would provide customers long-term price stability and greater flexibility as power markets develop in the Western States. If approved, construction of the project would take place in multiple phases or segments spanning 2023 through 2025 and would interconnectSouth Dakota Electric's andWyoming Electric's transmission systems. •OnJanuary 26, 2022 ,Colorado Electric agreed to join SPP's Western Energy Imbalance Service Market.Colorado Electric will join the market inApril 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. •InJanuary 2022 ,South Dakota Electric placed in service a$19 million , 54-mile, 230 kV electric transmission line fromRapid City toSpearfish, South Dakota . The second leg of this transmission line rebuild project, an 85-mile segment fromSpearfish toGillette, Wyoming , is expected to be in service by the end of 2023. •OnJanuary 5, 2022 ,South Dakota Electric andWyoming Electric set new winter peak loads.Wyoming Electric's new winter peak load of 252 MW surpasses the previous peak of 247 MW set inDecember 2019 .South Dakota Electric's new winter peak of 327 MW surpasses the previous winter peak of 326 MW set inFebruary 2021 . 33 -------------------------------------------------------------------------------- Table of ContentsGas Utilities
•See Note 2 of the Notes to Condensed Consolidated Financial Statements for
recent rate review activity for
•OnJune 6, 2022 ,Colorado Gas submitted a proposal to the CPUC seeking approval to offer a voluntary RNG and carbon offset program for residential and business customers. The program would allow participants to offset 100% or more of the emissions associated with their own natural gas usage. The offset would be achieved through a combination of carbon offset credits and RNG attributes.Colorado Gas has designed its voluntary RNG and carbon offset program as a comprehensive four-year pilot program starting in 2023 and running through 2026. OnJuly 15, 2022 ,Kansas Gas submitted a similar RNG and carbon offset program proposal with the KCC.Nebraska Gas expects to submit a voluntary RNG and carbon offset program proposal to the NPSC later in 2022 with similar filings forArkansas Gas ,Iowa Gas andWyoming Gas expected by 2023.
Corporate and Other
•OnApril 13, 2022 , a jury awarded$41 million for claims made byGT Resources, LLC ("GTR") against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. andBlack 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 inCosta Rica which was acquired by a BHC subsidiary in 2003. We believe we have meritorious defenses to the verdict and intend to appeal the verdict. See additional information in Note 3 of the Notes to Condensed Consolidated Financial Statements. Results of Operations 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 ourElectric Utilities is June through August while the normal peak usage season for ourGas Utilities is November through March. Significant earnings variances can be expected between theGas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months endedJune 30, 2022 and 2021, and our financial condition as ofJune 30, 2022 andDecember 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 theElectric 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.
34
--------------------------------------------------------------------------------
Table of Contents
Consolidated Summary and Overview
Six Months Ended
Three Months Ended June 30, June 30,
2022 2021 2022 2021
(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities $ 45,226 $ 47,462 $ 95,972 $ 86,805
Gas Utilities 28,195 19,985 151,735 122,079
Corporate and Other (1,032) (181) (1,965) (3,303)
Operating income 72,389 67,266 245,742 205,581
Interest expense, net (38,764) (38,202) (77,309) (75,802)
Other income (expense), net 1,563 (191) 2,267 75
Income tax benefit (expense) 658 (586) (13,830) (1,080)
Net income 35,846 28,287 156,870 128,774
Net income attributable to non-controlling
interest (2,431) (3,126) (5,929) (7,297)
Net income available for common stock $ 33,415 $ 25,161 Total earnings per share of common stock, Diluted $ 0.52$ 0.40 $ 2.33 $ 1.93
Three Months Ended
The variance to the prior year included the following:
•Electric Utilities' operating income decreased$2.2 million primarily due to higher operating expenses, lower pricing on the new Wygen I PPA and prior year regulatory actions reducing certain Winter Storm Uri impacts partially offset by increased rider revenues and prior year mark-to-market adjustments on wholesale energy contacts; •Gas Utilities' operating income increased$8.2 million primarily due to carrying costs on our Winter Storm Uri regulatory asset and new rates and rider recovery partially offset by higher operating expenses and unfavorable mark-to-market adjustments on wholesale commodity contracts; •Other income increased$1.8 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance; and •Income tax benefit increased$1.2 million driven by a lower effective tax rate due to tax benefits from state tax rate changes partially offset by higher pre-tax income.
Six Months Ended
The variance to the prior year included the following:
•Electric Utilities' operating income increased$9.2 million primarily due to prior year impacts related toColorado Electric's TCJA-related bill credits to customers (which were offset by reduced income tax expense), increased rider revenues, prior year mark-to-market adjustments on wholesale energy contacts and increased transmission and off-system energy sales partially offset by higher operating expenses and lower pricing on the new Wygen I PPA; •Gas Utilities' operating income increased$30 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$1.3 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$1.5 million due to higher interest rates and higher debt balances primarily driven by Winter Storm Uri; •Other income increased$2.2 million primarily due to lower costs for our non-qualified benefit plans which were driven by market performance; •Income tax expense increased$13 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits fromColorado 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$1.4 million due to lower net income from Black Hills Colorado IPP primarily driven by a planned outage. 35
--------------------------------------------------------------------------------
Table of Contents
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 the 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
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Variance 2022 2021 Variance
Revenue:
Electric - regulated $ 194,197 $ 181,503 $ 12,694 $ 389,921 $ 404,599 $ (14,678)
Other - non-regulated 10,182 9,513 669 20,995 21,821 (826)
Total revenue 204,379 191,016 13,363 410,917 426,420 (15,503)
Cost of fuel and purchased power:
Electric - regulated 55,723 44,607 11,116 107,202 144,076 (36,874)
Other - non-regulated 909 956 (47) 1,840 1,786 54
Total cost of fuel and purchased
power 56,632 45,563 11,069 109,042 145,862 (36,820)
Electric Utility margin (non-GAAP) 147,747 145,453 2,294
301,875 280,558 21,317
Operations and maintenance 69,000 65,301 3,699 138,669 129,035 9,634 Depreciation and amortization 33,521 32,690 831 67,234 64,718 2,516 Total operating expenses 102,521 97,991 4,530 205,903 193,753 12,150 Operating income$ 45,226 $ 47,462 $ (2,236) $ 95,972 $ 86,805 $ 9,167 36
-------------------------------------------------------------------------------- Table of Contents Three Months EndedJune 30, 2022 Compared to the Three Months EndedJune 30, 2021 :
Electric Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery $ 4.2
Prior year mark-to-market on wholesale energy contracts 3.6
Lower pricing on new Wygen I PPA (2.6)
Prior year Winter Storm Uri impacts (a) (2.4)
Other (0.5)
Total increase in Electric Utility margin $ 2.3
__________
(a) In the first quarter 2021, ourElectric Utilities accrued$3.2 million of negative impacts to our regulated wholesale power margins due to the higher fuel costs associated with Winter Storm Uri. Through regulatory actions in the second quarter of 2021, ourElectric Utilities were able to reduce$2.4 million of that negative impact. Operations and maintenance expense increased primarily due to higher outside services expenses, higher cloud computing licensing costs and increased property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
Six Months Ended
Electric Utility margin increased as a result of the following:
(in millions)
Prior year TCJA-related bill credits (a) $ 9.3
New rates and rider recovery 6.3
Prior year mark-to-market on wholesale energy contracts 5.1
Transmission services and off-system energy sales 2.6
Customer load growth 1.8
Prior year Winter Storm Uri impacts (b) 1.2
Lower pricing on new Wygen I PPA (5.1)
Weather (0.2)
Other 0.3
Total increase in Electric Utility margin $ 21.3
__________
(a) InFebruary 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) As a result of Winter Storm Uri, ourElectric 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 maintenance expenses driven by planned generation outages, higher fuel costs, higher outside services expenses and increased property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
37
--------------------------------------------------------------------------------
Table of Contents
Operating Statistics
Revenue (in thousands) Quantities Sold (MWh)
Three Months Ended Six Months Ended Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2022 2021 2022 2021 2022 2021 2022 2021
Residential $ 52,853 $ 53,451 $ 115,102 $ 126,211 323,775 335,063 715,357 731,149
Commercial 68,756 66,809 133,109 143,816 509,830 501,463 1,000,248 994,418
Industrial 38,190 35,186 73,598 78,195 464,928 441,793 928,696 856,984
Municipal 4,992 4,382 9,567 9,402 40,240 39,863 75,545 76,105
Subtotal Retail Revenue - Electric 164,791 159,828 331,377 357,624 1,338,773 1,318,182 2,719,846 2,658,656
Contract Wholesale 4,339 3,010 10,262 8,932 150,645 129,763 332,852 286,758
Off-system/Power Marketing
Wholesale 8,666 7,266 15,820 12,038 144,425 148,981 304,866 209,202
Other (a) 16,400 11,399 32,463 26,005 - - - -
Total Regulated 194,197 181,503 389,921 404,599 1,633,843 1,596,926 3,357,564 3,154,616
Non-Regulated (b) 10,182 9,513 20,995 21,821 72,770 61,408 161,864 140,923
Total Revenue and Quantities Sold
1,706,613 1,658,334 3,519,428 3,295,539
Other Uses, Losses or Generation, net (c) 98,323 94,932 211,609 227,680 Total Energy 1,804,936 1,753,266 3,731,037 3,523,219 __________
(a) Primarily related to transmission revenues from the Common Use System.
(b) Includes Integrated Generation and non-regulated services to our retail
customers under the Service Guard
Revenue (in thousands) Quantities Sold (MWh)
Three Months Ended June 30, Six Months Ended June 30, Three Months Ended June 30,
Six Months Ended
2022 2021 2022 2021 2022 2021 2022 2021
Colorado Electric $ 71,197 $ 64,009 $ 146,642 $ 143,446 568,890 596,364 1,188,478 1,150,344
South Dakota Electric 76,195 72,640 154,792 166,769 600,172 581,628 1,244,395 1,163,476
Wyoming Electric 47,146 45,601 89,235 95,551 464,781 418,934 924,691 840,796
Integrated Generation 9,841 8,766 20,248 20,654 72,770 61,408 161,864 140,923
Total Revenue and Quantities
Sold $ 204,379 $ 191,016 $ 410,917 $ 426,420 1,706,613 1,658,334 3,519,428 3,295,539
Three Months Ended June 30, Six Months Ended June 30,
Quantities Generated and Purchased by Fuel
Type (MWh) 2022 2021 2022 2021
Generated:
Coal 589,438 623,822 1,252,876 1,241,956Natural Gas and Oil 262,157 377,155 558,579 750,941 Wind 244,456 195,736 498,024 409,583 Total Generated 1,096,051 1,196,713 2,309,479 2,402,480
Purchased:
Coal, Natural Gas, Oil and Other Market
Purchases 608,045 481,346 1,196,205 945,887
Wind 100,840 75,207 225,353 174,852
Total Purchased 708,885 556,553 1,421,558 1,120,739
Total Generated and Purchased 1,804,936 1,753,266 3,731,037 3,523,219
38
--------------------------------------------------------------------------------
Table of Contents
Three Months Ended June 30, Six Months Ended June 30,
Quantities Generated and Purchased (MWh) 2022 2021 2022 2021
Generated:
Colorado Electric 112,117 110,821 197,548 201,077
South Dakota Electric 367,936 442,665 823,541 911,481
Wyoming Electric 225,720 222,540 430,318 396,530
Integrated Generation 390,278 420,687 858,072 893,392
Total Generated 1,096,051 1,196,713 2,309,479 2,402,480
Purchased:
Colorado Electric 255,969 251,648 556,366 471,893
South Dakota Electric 248,625 154,633 445,688 296,635
Wyoming Electric 185,932 135,177 376,737 307,602
Integrated Generation 18,359 15,095 42,767 44,609
Total Purchased 708,885 556,553 1,421,558 1,120,739
Total Generated and Purchased 1,804,936 1,753,266 3,731,037 3,523,219
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
Variance from Variance from Variance from Variance from
Degree Days Actual Normal Actual Normal Actual Normal Actual Normal
Heating Degree Days:
Colorado Electric 556 (5) % 595 (6) % 3,271 5 % 3,326 2 %
South Dakota Electric 1,221 13 % 1,048 2 % 4,469 3 % 4,372 3 %
Wyoming Electric 1,159 (3) % 1,221 2 % 4,291 2 % 4,482 6 %
Combined (a) 904 3 % 875 - % 3,885 4 % 3,915 3 %
Cooling Degree Days:
Colorado Electric 333 24 % 300 44 % 333 24 % 300 44 %
South Dakota Electric 107 15 % 167 69 % 107 15 % 167 69 %
Wyoming Electric 121 102 % 117 134 % 121 102 % 117 134 %
Combined (a) 213 28 % 218 56 % 213 28 % 218 56 %
__________
(a) Degree days are calculated based on a weighted average of total customers
by state.
Three Months Ended June 30, Six Months Ended June 30,
Contracted generating facilities Availability
by fuel type (a) 2022 2021 2022 2021
Coal (b) (c) 82.1 % 86.1 % 86.3 % 86.2 %
Natural gas and diesel oil 95.1 % 97.6 % 95.2 % 93.8 %
Wind 93.8 % 96.8 % 94.7 % 95.3 %
Total Availability 91.4 % 94.4 % 92.7 % 92.1 %
Wind Capacity Factor 39.8 % 31.0 % 40.9 % 34.1 %
__________(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet. (b) 2022 included planned outages at Neil Simpson II and Wyodak Plant. (c) 2021 included planned outages at Neil Simpson II, Wygen, Wygen II, and Wygen III and unplanned outages at Neil Simpson II and Wyodak Plant.
39--------------------------------------------------------------------------------
Table of ContentsGas Utilities
Operating results for the
Three Months Ended June 30 ,
Six Months Ended
2022 2021 Variance 2022 2021 Variance
Revenue:
Natural gas - regulated $ 258,349 $ 172,465 $ 85,884 $ 854,807 $ 550,542 $ 304,265
Other - non-regulated 15,821 13,585 2,236 40,755 38,027 2,728
Total revenue 274,169 186,050 88,119 895,561 588,569 306,992
Cost of natural gas sold:
Natural gas - regulated 126,704 62,317 64,387 510,416 245,284 265,132
Other - non-regulated 5,040 798 4,242 6,055 10,881 (4,826) Total cost of natural gas sold 131,744 63,115 68,629 516,471 256,165 260,306
Gas Utility margin (non-GAAP) 142,425 122,935 19,490 379,090 332,404 46,686
Operations and maintenance 83,689 77,263 6,426 170,130 159,463 10,667 Depreciation and amortization 30,541 25,687 4,854 57,225 50,862 6,363 Total operating expenses 114,230 102,950 11,280 227,355 210,325 17,030 Operating income$ 28,195 $ 19,985 $ 8,210 $ 151,735 $ 122,079 $ 29,656
Three Months Ended
Gas Utility margin increased as a result of the following:
(in millions)
Carrying costs on Winter Storm Uri regulatory asset (a) $ 12.3 New rates and rider recovery
4.6
Current and prior year TCJA-related bill credits (b)
2.2
Increased transportation and transmission volumes
1.9
Residential customer growth and increased usage per customer
1.5
Mark-to-market on non-utility natural gas commodity contracts (4.3) Weather (0.2) Other 1.5 Total increase in Gas Utility margin $
19.5
__________
(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 three months endedJune 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) InJune 2021 ,Nebraska Gas provided$2.9 million TCJA-related bill credits to its customers. For the three months endedJune 30, 2022 ,Kansas Gas provided$0.7 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 an immateriall impact to Net income.
Operations and maintenance expense increased primarily due to higher outside services and materials expenses, increased bad debt expense primarily attributable to higher billings, higher cloud computing licensing costs and higher vehicle expenses due to higher fuel costs.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
40--------------------------------------------------------------------------------
Table of Contents
Six Months Ended
Gas Utility margin increased as a result of the following:
(in millions)
New rates and rider recovery $ 17.4
Carrying costs on Winter Storm Uri regulatory asset (a) 14.6
Prior year Black Hills Energy Services Winter Storm Uri costs (b)
8.2
Residential customer growth and increased usage per customer 4.5
Increased transportation and transmission volumes 1.5
Current and prior year TCJA-related bill credits (c) 1.4
Weather (1.0)
Mark-to-market on non-utility natural gas commodity contracts (0.9)
Other 1.0
Total increase in Gas Utility margin $ 46.7
__________
(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 six months endedJune 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) InJune 2021 ,Nebraska Gas provided$2.9 million TCJA-related bill credits to its customers. For the three months endedJune 30, 2022 ,Kansas Gas provided$1.5 million of TCJA and state tax reform bill credits to customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income. Operations and maintenance expense increased primarily due to higher cloud computing licensing costs, higher outside services and materials expenses, increased bad debt expense primarily attributable to higher billings, higher vehicle expenses due to higher fuel costs and increased property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to a higher asset base driven by prior year capital expenditures.
Operating Statistics
Revenue (in thousands) Quantities Sold and Transported (Dth)
Three Months Ended Six Months Ended Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2022 2021 2022 2021 2022 2021 2022 2021
Residential $ 143,127 $ 98,370 $ 519,171 $ 332,767 8,523,755 8,575,051 40,338,005 39,143,789
Commercial 61,182 36,888 219,824 127,977 4,499,245 4,493,931 19,130,948 18,306,252
Industrial 16,875 5,811 26,113 10,713 2,150,532 1,337,672 3,315,115 2,235,961
Other 2,300 (418) 5,072 (890) - - - -
Total Distribution 223,483 140,651 770,179 470,567 15,173,532 14,406,654 62,784,068 59,686,002
Transportation and
Transmission 34,865 31,814 84,627 79,975 37,623,610 34,074,214 82,668,813 79,388,652
Total Regulated 258,349 172,465 854,807 550,542 52,797,142 48,480,868 145,452,881 139,074,654
Non-regulated Services 15,821 13,585 40,755 38,027 - - - -
Total Revenue and
Quantities Sold $ 274,169 $ 186,050 $ 895,561 $ 588,569 52,797,142 48,480,868 145,452,881 139,074,654
41
--------------------------------------------------------------------------------
Table of Contents
Revenue (in thousands) Quantities Sold & Transported (Dth)
Three Months Ended Six Months Ended Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2022 2021 2022 2021 2022 2021 2022 2021
Arkansas Gas $ 51,815 $ 32,994 $ 179,624 $ 119,988 5,445,450 5,718,417 18,373,186 19,025,151
Colorado Gas 50,328 34,190 170,381 113,312 6,365,777 5,957,285 19,784,461 19,323,300
Iowa Gas 42,050 29,831 162,629 86,585 8,178,613 7,016,613 23,554,795 21,330,586
Kansas Gas 35,482 21,163 94,333 61,226 8,762,807 7,155,427 19,751,874 17,618,224
Nebraska Gas 62,337 43,037 196,571 136,135 16,714,480 15,822,880 44,050,254 43,106,981
Wyoming Gas 32,157 24,835 92,023 71,323 7,330,015 6,810,246 19,938,311 18,670,412
Total Revenue and
Quantities Sold $ 274,169 $ 186,050 $ 895,561 $ 588,569 52,797,142 48,480,868 145,452,881 139,074,654
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
Variance Variance Variance Variance
Heating Degree Days Actual from Normal Actual from Normal Actual from Normal Actual from Normal
Arkansas Gas (a) 271 (18)% 383 16% 2,370 (3)% 2,504 3%
Colorado Gas 817 (14)% 865 (9)% 3,763 (3)% 3,830 (1)%
Iowa Gas 803 17% 691 1% 4,382 8% 4,113 1%
Kansas Gas (a) 436 (2)% 493 10% 3,020 4% 3,069 5%
Nebraska Gas 679 7% 624 (1)% 3,720 1% 3,721 1%
Wyoming Gas 1,326 9% 1,200 (1)% 4,598 4% 4,625 5%
Combined (b) 768 2% 739 1% 3,933 2% 3,925 2%
__________
(a) Arkansas Gas and Kansas Gas have weather normalization mechanisms that
mitigate the weather impact on gross margins.
(b) The combined heating degree days are calculated based on a weighted average
of total customers by state excluding Kansas Gas due to its weather
normalization mechanism. Arkansas Gas is partially excluded based on the weather
normalization mechanism in effect from November through April.
Corporate and Other
Corporate and Other operating results were as follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Variance 2022 2021 Variance
Operating (loss)
Three Months Ended
Operating (loss) was comparable to the same period in the prior year.
Six Months Ended
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.
42
--------------------------------------------------------------------------------
Table of Contents
Consolidated Interest Expense, Other Income and Income Tax Expense
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Variance 2022 2021 Variance
(in thousands)
Interest expense, net $ (38,764) $ (38,202) $ (562) $ (77,309) $ (75,802) $ (1,507)
Other income, net 1,563 (191) $ 1,754 $ 2,267 $ 75 $ 2,192
Income tax benefit (expense) 658 (586) $
1,244
Three Months Ended
Interest Expense, net
Interest expense, net was comparable to the same period in the prior year.
Other Income, net
The increase in Other income, net was due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by higher non-service pension costs primarily driven by a higher discount rate.
Income Tax Benefit (Expense)
Income tax benefit increased due to a lower effective tax rate partially offset
by higher pre-tax income. For the three months ended
Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances.
Six Months Ended
Interest Expense, net
The increase in Interest expense, net was due to higher interest rates and higher debt balances primarily driven by Winter Storm Uri.
Other Income, net
The increase in Other income, net was due to lower costs for our non-qualified benefit plans which were driven by market performance partially offset by higher non-service pension costs primarily driven by a higher discount rate.
Income Tax Benefit (Expense)
Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the six months endedJune 30, 2022 , the effective tax rate was 8.1% compared to 0.8% for the same period in 2021. See Note 11 of the Notes to Condensed Consolidated Financial Statements for discussion of effective tax rate variances. 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 six months ended
Cash provided by (used in): 2022 2021 Variance
Operating activities $ 442,030 $ (250,173) $ 692,203
Investing activities $ (291,385) $ (309,737) $ 18,352
Financing activities $ (149,093) $ 554,905 $ (703,998)
43
--------------------------------------------------------------------------------
Table of Contents
Six Months Ended
Operating Activities:
Net cash provided by (used in) operating activities was
•Cash earnings (net income plus non-cash adjustments) were$26 million higher for the six months endedJune 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
•Cash inflows increased by$679 million as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers;
•Cash inflows decreased by
•Cash outflows decreased by$36 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
Investing Activities:
Net cash used in investing activities was
•Capital expenditures of$294 million for the six months endedJune 30, 2022 compared to$319 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 andElectric Utilities ; and •Cash inflows decreased by$7.3 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 used in financing activities was
•Cash inflows decreased
•Cash inflows decreased
•Cash outflows increased
•Cash inflows increased by
44
--------------------------------------------------------------------------------Table of Contents Capital Resources Short-term Debt
Revolving Credit Facility and CP Program
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit and available capacity (in millions):
Short-term borrowings Letters of Credit (a)
Current at at Available Capacity at
Credit Facility Expiration Capacity June 30, 2022 June 30, 2022 June 30, 2022
Revolving Credit
Facility and CP
Program July 19, 2026 $ 750 $ 335 $ 14 $ 401
__________(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit 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
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances) $ 429
Average amount outstanding (based on daily outstanding balances) $
326
Weighted average interest rates 0.82 %
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric's financing agreements
contain covenant requirements. We were in compliance with these covenants as of
June 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, our Revolving Credit Facility and CP Program and issuing common stock under the ATM. Credit Ratings After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.
The following table represents the credit ratings, outlook and risk profile of
BHC at
Rating Agency Senior Unsecured Rating Outlook
S&P (a) BBB+ Stable
Moody's (b) Baa2 Stable
Fitch (c) BBB+ Stable
__________
(a) On October 20, 2021 , 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 September 17, 2021 , Fitch reported BBB+ rating and maintained a Stable
outlook.
45
-------------------------------------------------------------------------------- Table of Contents The following table represents the credit ratings ofSouth Dakota Electric atJune 30, 2022 : Rating Agency Senior Secured Rating S&P (a) A Fitch (b) A __________ (a) OnMarch 31, 2022 , S&P reported A rating. (b) OnSeptember 17, 2021 , Fitch reported A rating. Capital Requirements Capital Expenditures Actual Forecasted Capital Expenditures by Six Months Ended Segment June 30, 2022 (a) 2022 (b) 2023 2024 2025 2026 (in millions) Electric Utilities $ 120$ 239 $ 205 $ 285 $ 231 $ 155 Gas Utilities 150 363 383 386 349 346 Corporate and Other 4 9 12 13 13 13 Incremental Projects (c) - - - - 60 140 $ 274$ 611 $ 600 $ 684 $ 653 $ 654 __________ (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 six months endedJune 30, 2022 . (c) These represent projects that are being evaluated by our segments for timing, cost and other factors.
Dividends
Dividends paid on our common stock totaled$77 million for the six months endedJune 30, 2022 , or$0.595 per share per quarter. OnJuly 25, 2022 , our board of directors declared a quarterly dividend of$0.595 per share payableSeptember 1, 2022 , equivalent to an annual dividend of$2.38 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.
Unconditional Purchase Obligations
See Note 3 of the Notes to Condensed Consolidated Financial Statements for recent updates to our purchase obligations.
Critical Accounting 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.
© Edgar Online, source
