BLACK HILLS CORP quarterly report, Q2 FY2021

Black Hills Corporation — Q2 2021 Form 10-Q

Reporting period: Quarter and six months ended June 30, 2021. Black Hills provides regulated electric and natural gas service to approximately 1.3 million customers in eight states, alongside power generation and coal mining operations. Amounts below are in U.S. dollars; financial statement figures are in millions unless noted.

Financial performance and position

Metric	Q2 2021	Q2 2020	Six months 2021	Six months 2020
Revenue	$372.6	$326.9	$1,006.0	$864.0
Operating income	$67.3	$66.9	$205.6	$220.1
Net income	$28.3	$24.7	$128.8	$121.9
Net income available to common shareholders	$25.2	$21.0	$121.5	$114.1
Diluted EPS	$0.40	$0.33	$1.93	$1.83

Q2 revenue rose about 14% and common net income about 20% year over year. For the first half, revenue rose about 16% and common net income about 6%, while operating income fell about 7%.
Q2 electric utility non-GAAP gross margin increased $5.5 million to $109.7 million; first-half margin decreased $8.8 million to $205.0 million. Gas utility non-GAAP gross margin increased $6.4 million to $122.9 million in Q2 and $10.5 million to $332.4 million for the first half. The company cautions that gross margin is a non-GAAP measure.
Cash provided by operating activities was negative $250.2 million for the first half, versus positive $309.0 million a year earlier. The primary driver was a $572 million cash outflow from changes in regulatory assets and liabilities, largely related to Winter Storm Uri.
Capital expenditures were $319.5 million in the first half. Cash and cash equivalents were $1.2 million at June 30; restricted cash was $4.6 million. Current liabilities were $1.23 billion.
Debt included $829.9 million of notes payable (including a $600 million term-loan balance and $229.9 million commercial paper) and $3.53 billion of long-term debt, net of current maturities. The company had $507 million of available Revolving Credit Facility and CP capacity, after borrowings and letters of credit.
The debt-to-capitalization covenant ratio was 62.3%, against a maximum of 65%; the company reported compliance. The term loan matures November 24, 2021 and bears LIBOR plus 75 basis points. The company expects to refinance a portion with longer-term debt.

Material changes and drivers

February’s Winter Storm Uri generated substantial incremental energy and gas costs. The company recorded $559 million of costs as a regulatory asset in Q1; at June 30, the Uri regulatory asset was $541.4 million. Utilities sought recovery of $546 million over a weighted-average 3.7 years, with recovery timing and carrying costs subject to regulatory decisions. Some commissions approved or authorized interim recovery; $4.6 million had been recovered from customers by June 30.
Electric Utilities’ first-half adjusted operating income declined $12.3 million, mainly from TCJA-related customer bill credits, Uri impacts and unfavorable wholesale energy mark-to-market adjustments. Management said $5.1 million of first-half mark-to-market losses on fixed-price wholesale contracts were expected to reverse as contracts settled in the second half of 2021.
Gas Utilities’ first-half adjusted operating income increased $1.0 million, reflecting new rates and colder weather, partly offset by Uri costs incurred by non-regulated Black Hills Energy Services and customer bill credits. Those Uri costs for the non-regulated gas supply business were not recoverable through a regulatory mechanism.
Power Generation’s Q2 adjusted operating income decreased $3.2 million, mainly due to planned outages. First-half results were approximately flat. Mining revenue fell as fewer tons were sold, primarily due to outages at the Gillette energy complex.
Interest expense increased $2.7 million in Q2 and $4.8 million for the first half, reflecting higher debt balances, partly offset by lower rates. First-half 2020 included a $6.9 million non-cash investment impairment that did not recur.
Effective tax rates were 2.0% in Q2 and 0.8% for the first half, versus 16.4% and 14.6%, respectively, a year earlier. Management attributed the decreases primarily to tax benefits, including TCJA-related bill credits, repair-related flow-through benefits and, year to date, production tax credits. Bill credits were largely offset by lower income tax expense, with minimal net-income effect.

Outlook, financing and risks

The filing does not provide a full-year earnings or EPS forecast. It forecasts 2021 capital expenditures of $647 million, including $377 million for Gas Utilities and $240 million for Electric Utilities; 2022–2025 annual capital expenditures are forecast at approximately $600–$612 million, including projects still under evaluation.
Management expected to fund second-half 2021 capital needs with operating cash flow, the revolving facility and CP program, and an additional $60–$80 million of common stock issuance under the ATM program. The company issued $40 million net of costs through the ATM in the first half.
The board declared a quarterly dividend of $0.565 per share, equivalent to $2.26 annualized, payable September 1, 2021. Future dividends remain subject to financial condition, capital needs, facility restrictions and business prospects.
On July 19, 2021, after quarter-end, the company amended and restated its $750 million revolving credit facility, extending maturity to July 19, 2026, with two one-year extension options subject to lender consent.
Regulatory developments include pending rate reviews in Colorado, Iowa and Kansas seeking additional annual revenue, and approved Nebraska Gas rates expected to produce $6.5 million of new annual revenue. Colorado Gas also received approval for a three-year safety and integrity investment rider.
Strategic plans include a 200 MW Colorado solar PPA with expected completion by the end of 2023. An electric utility resource plan proposed 100 MW of renewable generation, conversion of Neil Simpson II to natural gas in 2025, and consideration of up to 20 MW of battery storage.
Key exposures include regulatory approval and timing for Uri cost recovery, commodity prices and extreme weather, refinancing the November 2021 term loan, seasonal demand, and potential effects of COVID-19. Management reported no significant COVID-19 impact on first-half results, liquidity or operations. It also cautioned that interim results are seasonal and may not indicate full-year performance.

Important facts for investors to verify

Progress and final commission decisions on recovery of Uri costs, including carrying costs, recovery periods and any disallowances.
Term-loan refinancing or repayment before its November 24, 2021 maturity, and liquidity and covenant headroom under the updated credit facility.
Whether expected wholesale contract mark-to-market reversals occur in the second half and how outage-related costs and generation availability develop.
Execution of the planned ATM issuance and the $647 million 2021 capital program, alongside operating cash flow and dividend funding.
Outcomes and effective dates of pending utility rate cases, and timing and costs of renewable and other resource projects.