Washington, D.C. 20549
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.
The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
|
| | | | | | | | | | | | | | | | | |
| (unaudited) | Common Stock | | | | |
| (in thousands, except share amounts) | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Total |
| December 31, 2019 | 23,416,396 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 389,312 |
| $ | (1,380 | ) | $ | 450,923 |
|
| Net income | — |
| — |
| — |
| 13,335 |
| — |
| 13,335 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| 37 |
| 37 |
|
| Dividend to Parent company | — |
| — |
| — |
| (20,000 | ) | — |
| (20,000 | ) |
| Implementation of ASU 2016-13 Financial Instruments -- Credit Losses | — |
| — |
| — |
| (19 | ) | — |
| (19 | ) |
| March 31, 2020 | 23,416,396 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 382,628 |
| $ | (1,343 | ) | $ | 444,276 |
|
|
| | | | | | | | | | | | | | | | | |
| | Common Stock | | | | |
| (in thousands except share amounts) | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Total |
| December 31, 2018 | 23,416,396 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 342,145 |
| $ | (891 | ) | $ | 404,245 |
|
| Net income | — |
| — |
| — |
| 15,497 |
| — |
| 15,497 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| 12 |
| 12 |
|
| Implementation of ASU 2016-02 Leases | — |
| — |
| — |
| (7 | ) | — |
| (7 | ) |
| Other adjustments | — |
| — |
| — |
| 1 |
| — |
| 1 |
|
| March 31, 2019 | 23,416,396 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 357,636 |
| $ | (879 | ) | $ | 419,748 |
|
BLACK HILLS POWER, INC.
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 20162019 Annual Report on Form 10-K)
(1) MANAGEMENT’S STATEMENT(1) Management’s Statement
The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the(“South Dakota Electric”, the “Company,” “we,” “us,”“us” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 20162019 Annual Report on Form 10-K filed with the SEC.
The information furnished in the accompanying condensed 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, 2017, March 31, 2020, December 31, 20162019 and September 30, 2016March 31, 2019 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2017March 31, 2020 and September 30, 2016,March 31, 2019, and our financial condition as of September 30, 2017March 31, 2020 and December 31, 20162019 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
RevisionsCOVID-19 Pandemic
Certain revisions have beenIn March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric utilities as “critical” in providing essential services during this emergency. As a provider of critical services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of its employees and the communities in which it operates while assuring the continuity of its business operations.
The Company’s Condensed Financial Statements reflect estimates and assumptions made to prior year’s financial information to conformby management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Condensed Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that for the three months ended March 31, 2020, there were no material adverse impacts on the Company’s results of operations.
Change in Accounting Principle - Pension Accounting Asset Method
Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the current year presentation.
We revised our presentationchange, the Company used a calculated value for determining market-related value of
cashplan assets which amortized the effects of gains and
certain cash transactions processed on behalf of affiliates as of December 31, 2016. We have banking arrangements at certain financial institutions whereby if required, payments of one account are clearedlosses over a five-year period. Effective with
cash from other accounts at the
same financial institution; therefore, book overdrafts are presented onaccounting change, the Company will continue to use a
combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 millioncalculated value for the
nine months ended September 30, 2016. We assessedreturn-seeking assets (equities) in the
materiality of these changes, taking into account quantitativeportfolio and
qualitative factors, and determined themchange to
be immaterial to the balance sheet as of September 30, 2016 and to the Statements of Cash Flowsfair value for the
nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss)liability-hedging assets (fixed income). See Note 6 for any period reported.additional information.
Recently Issued Accounting Standards
Revenue from Contracts with Customers,Simplifying the Accounting for Income Taxes, ASU 2014-092019-12
In May 2014,December 2019, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model2019-12, Simplifying the Accounting for useIncome Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance.a franchise tax (or similar tax) that is partially based on income. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annualinterim and interim reportingannual periods beginning after December 15, 20172020 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.
We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We have substantially completed our assessment of all sources of revenue and are currently determiningreviewing this standard to assess the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority
Recently Adopted Accounting Standards
Financial Instruments -- Credit Losses: Measurement of revenue recognition for regulated tariff based sales. WeCredit Losses on Financial Instruments, ASU 2018-19
also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.
Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07
In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
In AugustJune 2016, the FASB issued ASU 2016-15, Statement2016-13, Financial Instruments -- Credit Losses: Measurement of Cash Flows (Topic 230): ClassificationCredit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses.
We adopted this standard on January 1, 2020, with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of Certain Cash Receipts and Cash Payments (a consensusexpected losses on unbilled revenue. The cumulative effect of the Emerging Issues Task Force). Thisadoption, net of tax impact, was recorded as an adjustment to retained earnings.
Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU requires changes2018-15
In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the presentationrequirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of certain items including but not limitedimplementation costs that previously would have been charged to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds fromexpense as incurred are now capitalized as prepayments and amortized over the settlementterm of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.arrangement. We will use the retrospective transition method to adoptadopted this standard with fiscal years beginning after December 15, 2017. This standard willprospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
Leases, ASU 2016-02
In February 2016,(2) Revenue
Our revenue contracts generally provide for performance obligations that are: fulfilled and transfer control to customers over time; represent a series of distinct services that are substantially the FASB issued ASU No. 2016-02, Leases (Topic 842),same; involve the same pattern of transfer to the customer; and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which supersedes ASC 840, Leases. This ASU requires lesseeswe have a right to recognize a right-of-use assetinvoice. The following tables depict the disaggregation of revenue from contracts with customers by customer type and lease liability ontiming of revenue recognition for each of the reporting segments for the three months ended March 31, 2020 and 2019. Sales tax and other similar taxes are excluded from revenues.
|
| | | | | | |
| | Three Months Ended March 31, 2020 | Three Months Ended March 31, 2019 |
| | (in thousands) |
| Customer types: | | |
| Retail | $ | 51,427 |
| $ | 53,076 |
|
| Wholesale | 4,382 |
| 8,343 |
|
| Market - off-system sales | 2,377 |
| 4,670 |
|
| Transmission/Other | 13,300 |
| 12,831 |
|
| Revenue from contracts with customers | 71,486 |
| 78,920 |
|
| Other revenues | 125 |
| 121 |
|
| Total revenues | $ | 71,611 |
| $ | 79,041 |
|
| | | |
| Timing of revenue recognition: | | |
| Services transferred over time | $ | 71,486 |
| $ | 78,920 |
|
| Revenue from contracts with customers | $ | 71,486 |
| $ | 78,920 |
|
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance sheet for all leases within our Accounts Receivable and is further discussed in Note 3. We do not typically incur costs that would be capitalized to obtain or fulfill a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.revenue contract.
We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.
| |
(2)
(3) | ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTSAccounts Receivable |
Following is a summary of Receivables - customers,Accounts receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
|
| | | | | | |
| | March 31, 2020 | December 31, 2019 |
| Accounts receivable, trade | $ | 15,577 |
| $ | 14,778 |
|
| Unbilled revenues | 10,059 |
| 10,914 |
|
| Less allowance for credit losses | (358 | ) | (160 | ) |
| Accounts receivable, net | $ | 25,278 |
| $ | 25,532 |
|
The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 7. The Company did not experience material credit losses or customer defaults during the three months ended March 31, 2020.
|
| | | | | | |
| | September 30, 2017 | December 31, 2016 |
| Accounts receivable trade | $ | 17,356 |
| $ | 16,972 |
|
| Unbilled revenues | 10,348 |
| 13,799 |
|
| Allowance for doubtful accounts | (125 | ) | (157 | ) |
| Receivables - customers, net | $ | 27,579 |
| $ | 30,614 |
|
| |
(3)
(4) | REGULATORY ACCOUNTINGRegulatory Matters |
Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject toWe had the Uniform System of Accounts of the FERC.
Ourfollowing regulatory assets and liabilities were as follows (in thousands) as of:
|
| | | | | | | |
| | March 31, 2020 | | December 31, 2019 |
| Regulatory assets: | | | |
Loss on reacquired debt (a) | $ | 921 |
| | $ | 989 |
|
Deferred taxes on AFUDC (b) | 4,882 |
| | 4,927 |
|
Employee benefit plans and related deferred taxes (c)
| 20,866 |
| | 20,661 |
|
Deferred energy and fuel cost adjustments (b) | 23,854 |
| | 23,203 |
|
Deferred taxes on flow through accounting (c) | 10,297 |
| | 9,801 |
|
Decommissioning costs (a) | 5,767 |
| | 6,211 |
|
Vegetation management (a) | 7,486 |
| | 8,062 |
|
Other regulatory assets (a) | 1,633 |
| | 1,843 |
|
| Total regulatory assets | $ | 75,706 |
| | $ | 75,697 |
|
| Less current regulatory assets | (25,344 | ) | | (21,588 | ) |
| Regulatory assets, non-current | $ | 50,362 |
| | $ | 54,109 |
|
|
| | | | | | | | |
| | Maximum Amortization (in years) | September 30, 2017 | | December 31, 2016 |
| Regulatory assets: | | | | |
Unamortized loss on reacquired debt (a) | 8 | $ | 1,604 |
| | $ | 1,815 |
|
Deferred taxes on AFUDC (b) | 45 | 10,192 |
| | 9,367 |
|
Employee benefit plans(c)
| 12 | 20,180 |
| | 20,100 |
|
Deferred energy and fuel cost adjustments - current (a) | 1 | 13,754 |
| | 18,119 |
|
Deferred gas cost adjustments (a) (e) | 1 | 5,324 |
| | 4,897 |
|
Deferred taxes on flow through accounting (a) | 35 | 14,906 |
| | 12,545 |
|
Decommissioning costs, net of amortization(d) | 6 | 10,766 |
| | 12,456 |
|
Other regulatory assets (a) (d) | 6 | 15,271 |
| | 12,835 |
|
| Total regulatory assets | | $ | 91,997 |
| | $ | 92,134 |
|
|
| | | | | | | |
| Regulatory liabilities: | | | |
Cost of removal for utility plant (a) | $ | 58,422 |
| | $ | 57,318 |
|
Employee benefit plan costs and related deferred taxes (c) | 6,986 |
| | 7,023 |
|
Excess deferred income taxes (c) | 97,741 |
| | 98,228 |
|
| TCJA revenue reserve | 3,548 |
| | 3,162 |
|
Other regulatory liabilities (c) | 549 |
| | 440 |
|
| Total regulatory liabilities | $ | 167,246 |
| | $ | 166,171 |
|
| Less current regulatory liabilities | (3,548 | ) | | (3,162 | ) |
| Regulatory liabilities, non-current | $ | 163,698 |
| | $ | 163,009 |
|
|
| | | | | | | | |
| Regulatory liabilities: | | | | |
Cost of removal for utility plant (a) | 61 | $ | 43,518 |
| | $ | 41,541 |
|
Employee benefit plan costs and related deferred taxes (c) | 12 | 12,304 |
| | 12,304 |
|
| Other regulatory liabilities | 13 | 825 |
| | 105 |
|
| Total regulatory liabilities | | $ | 56,647 |
| | $ | 53,950 |
|
____________________
| |
| (a) | We are allowed a recovery of costs, but we are not allowed a rate of return. |
| |
| (b) | In addition to recovery of costs, we are 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. |
| |
(d) | In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million. |
| |
(e) | Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. |
Regulatory Activity
There have been no significant changes to our Regulatory Matters from those previously disclosed in Note 7 of the Notes to the Financial Statements in our 2019 Annual Report on Form 10-K.
| |
(4)(5) | RELATED-PARTY TRANSACTIONSRelated-Party Transactions |
Dividend to Parent
For the three months ended March 31, 2020, we paid a $20 million dividend to BHC. We did not record any dividends for the three months ended March 31, 2019.
Receivables and Payables
We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands) as of:
|
| | | | | | |
| | March 31, 2020 | December 31, 2019 |
| Accounts receivable from affiliates | $ | 8,149 |
| $ | 7,838 |
|
| Accounts payable to affiliates | $ | 32,620 |
| $ | 32,121 |
|
|
| | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| Receivables - affiliates | $ | 5,498 |
| | $ | 9,526 |
|
| Accounts payable - affiliates | $ | 26,828 |
| | $ | 31,799 |
|
Money Pool Notes Receivable and Notes Payable
On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.
We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement or, if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0%. At September 30, 2017,March 31, 2020, the average cost of borrowing under the Utility Money Pool was 1.66%1.92%.
We had the following balances with the Utility Money Pool (in thousands) as of:
|
| | | | | | |
| | March 31, 2020 | December 31, 2019 |
| Money pool notes payable | $ | 60,068 |
| $ | 57,585 |
|
|
| | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| Money pool notes receivable, net | $ | 8,881 |
| | $ | 28,409 |
|
Our net interest income (expense) relating to balances with the Utility Money Pool was as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Net interest income (expense) | $ | (287 | ) | $ | (273 | ) |
Notes payable to Parent
On March 1, 2020, we entered into a $45 million, 4.11% short-term promissory note with BHC. This note is eligible for annual renewal at December 31, 2020. The current note replaces the prior $25 million short-term promissory note entered into on June 1, 2019 and renewed at December 31, 2019. We had the following balances for our Notes payable to Parent balance (in thousands) as of:
|
| | | | | | |
| | March 31, 2020 | December 31, 2019 |
| Notes payable to Parent | $ | 45,000 |
| $ | 25,000 |
|
Our Net interest income (expense) relating to balances of the Notes Payable to Parent was as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Net interest income (expense) | $ | (388 | ) | $ | — |
|
|
| | | | | | | | | | | | |
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2017 | 2016 | 2017 | 2016 |
| Net interest income (expense) | $ | 53 |
| $ | 277 |
| $ | 269 |
| $ | 845 |
|
Other related party activity was as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Revenue: | | |
| Energy sold to Wyoming Electric | $ | 294 |
| $ | 574 |
|
| Rent from electric properties | $ | 989 |
| $ | 896 |
|
| Horizon Point shared facility revenue | $ | 2,840 |
| $ | 3,007 |
|
| | | |
Fuel and purchased power: | | |
| Purchases from WRDC mine | $ | 4,317 |
| $ | 4,657 |
|
| Purchase of excess energy from Wyoming Electric | $ | 161 |
| $ | 132 |
|
| Purchase of renewable wind energy from Wyoming Electric - Happy Jack | $ | 792 |
| $ | 535 |
|
| Purchase of renewable wind energy from Wyoming Electric - Silver Sage | $ | 1,392 |
| $ | 983 |
|
| Gas transportation service agreement with Wyoming Electric for firm and interruptible gas transportation | $ | 82 |
| $ | 76 |
|
| | | |
| Operations and maintenance: | | |
| Corporate support services and fees from BHSC | $ | 10,419 |
| $ | 10,191 |
|
| Wygen III ground lease with WRDC | $ | 251 |
| $ | 246 |
|
|
| | | | | | | | | | | | |
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2017 | 2016 | 2017 | 2016 |
| Revenue: | | | | |
| Energy sold to Cheyenne Light | $ | 361 |
| $ | 599 |
| $ | 1,866 |
| $ | 1,908 |
|
| Rent from electric properties | $ | 935 |
| $ | 1,229 |
| $ | 2,805 |
| $ | 3,817 |
|
| | | | | |
Fuel and purchased power: | | | | |
| Purchases of coal from WRDC | $ | 4,054 |
| $ | 4,122 |
| $ | 11,386 |
| $ | 12,275 |
|
| Purchase of excess energy from Cheyenne Light | $ | 208 |
| $ | 64 |
| $ | 324 |
| $ | 172 |
|
| Purchase of renewable wind energy from Cheyenne Light - Happy Jack | $ | 199 |
| $ | 312 |
| $ | 1,174 |
| $ | 1,329 |
|
| Purchase of renewable wind energy from Cheyenne Light - Silver Sage | $ | 351 |
| $ | 547 |
| $ | 2,007 |
| $ | 2,276 |
|
| | | | | |
| Gas transportation service agreement: | | | | |
| Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation | $ | 99 |
| $ | 100 |
| $ | 297 |
| $ | 300 |
|
| | | | | |
| Corporate support: | | | | |
| Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings | $ | 6,626 |
| $ | 6,257 |
| $ | 20,346 |
| $ | 19,155 |
|
| |
(5)
(6) | EMPLOYEE BENEFIT PLANSEmployee Benefit Plans |
Change in Accounting Principle - Pension Accounting Asset Method
Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will continue to use a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for remeasurement.
We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a $0.1 million decrease to prior service costs, as recorded in Other income (expense), net within the accompanying Condensed Statements of Comprehensive Income for the three months ended March 31, 2020.
Defined Benefit Pension Plan
The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Service cost | $ | 92 |
| $ | 91 |
|
| Interest cost | 463 |
| 603 |
|
| Expected return on plan assets | (781 | ) | (851 | ) |
| Prior service cost | — |
| 2 |
|
| Net loss (gain) | 511 |
| 305 |
|
| Net periodic benefit cost | $ | 285 |
| $ | 150 |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Service cost | $ | 137 |
| | $ | 151 |
| | $ | 409 |
| | $ | 453 |
|
| Interest cost | 585 |
| | 625 |
| | 1,755 |
| | 1,875 |
|
| Expected return on plan assets | (898 | ) | | (908 | ) | | (2,692 | ) | | (2,724 | ) |
| Prior service cost | 10 |
| | 11 |
| | 32 |
| | 33 |
|
| Net loss (gain) | 308 |
| | 498 |
| | 922 |
| | 1,496 |
|
| Net periodic benefit cost | $ | 142 |
| | $ | 377 |
| | $ | 426 |
| | $ | 1,133 |
|
Defined Benefit Postretirement Healthcare Plan
The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Service cost | $ | 39 |
| $ | 37 |
|
| Interest cost | 32 |
| 47 |
|
| Prior service cost (benefit) | (84 | ) | (84 | ) |
| Net periodic benefit cost | $ | (13 | ) | $ | — |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Service cost | $ | 52 |
| | $ | 51 |
| | $ | 155 |
| | $ | 153 |
|
| Interest cost | 44 |
| | 47 |
| | 132 |
| | 141 |
|
| Prior service cost (benefit) | (84 | ) | | (84 | ) | | (252 | ) | | (252 | ) |
| Net periodic benefit cost | $ | 12 |
| | $ | 14 |
| | $ | 35 |
| | $ | 42 |
|
Supplemental Non-qualified Defined Benefit Plans
The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):
|
| | | | | | |
| | Three Months Ended March 31, |
| | 2020 | 2019 |
| Interest cost | $ | 21 |
| $ | 29 |
|
| Net loss (gain) | 31 |
| 16 |
|
| Net periodic benefit cost | $ | 52 |
| $ | 45 |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Interest cost | $ | 29 |
| | $ | 30 |
| | $ | 87 |
| | $ | 90 |
|
| Net loss (gain) | 22 |
| | 20 |
| | 65 |
| | 62 |
|
| Net periodic benefit cost | $ | 51 |
| | $ | 50 |
| | $ | 152 |
| | $ | 152 |
|
Contributions
Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributionsContributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. Contributions to thePostretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 20172020 and anticipated contributions for 20172020 and 20182021 are as follows (in thousands):
|
| | | | | | | | | |
| | Contributions | Remaining Anticipated Contributions for | Anticipated Contributions for |
| | Three Months Ended March 31, 2020 | 2020 | 2021 |
| Defined Benefit Pension Plan | $ | — |
| $ | 1,739 |
| $ | 1,703 |
|
| Defined Benefit Postretirement Healthcare Plan | $ | 147 |
| $ | 440 |
| $ | 597 |
|
| Supplemental Non-qualified Defined Benefit Plans | $ | 80 |
| $ | 241 |
| $ | 304 |
|
|
| | | | | | | | | |
| | Contributions Nine Months Ended September 30, 2017 | Remaining Anticipated Contributions for 2017 | Anticipated Contributions for 2018 |
| Defined Benefit Pension Plan | $ | 4,000 |
| $ | — |
| $ | 1,834 |
|
| Defined Benefit Postretirement Healthcare Plan | $ | 406 |
| $ | 135 |
| $ | 565 |
|
| Supplemental Non-qualified Defined Benefit Plans | $ | 185 |
| $ | 62 |
| $ | 246 |
|
| |
(6)(7) | FAIR VALUE OF FINANCIAL INSTRUMENTSDerivatives and Fair Values |
Our activities in the regulated and non-regulated energy sectors 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 to commodity price risk associated with our purchased power costs which include market fluctuations due to unpredictable factors such as weather, market speculation, transmission constraints, and other factors that may impact electric power supply and demand.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
For production and generation activities, 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, prepayments, letters of credit, and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based on 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 and any specific customer collection issue that is identified.
Although we did not experience material credit losses or customer defaults for the three months ended March 31, 2020, we are monitoring COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify future financial impacts to allowance for credit losses.
Derivatives
We have wholesale power purchase and sale contracts used to manage purchased power costs and customer load requirements associated with serving our electric customers that are considered derivative instruments. Changes in the fair value of these commodity derivatives are recorded in Fuel and purchased power, net of amounts credited to customers under margin-sharing mechanisms.
The contract or notional amounts and terms of the derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of:
|
| | | | | | | |
| | March 31, 2020 | | December 31, 2019 |
| | MWh | | Maximum Term (months) | | MWh | | Maximum Term (months) |
Wholesale power contracts (a) | 195,825 | | 9 | | — | | 0 |
__________
| |
| (a) | Volumes exclude contracts that qualify for the normal purchases and normal sales exception. |
From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt or to lock in the Treasury yield component associated with anticipated issuance of senior notes. For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of March 31, 2020, we had no outstanding interest rate swap agreements.
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:
|
| | | | | | | | |
| | Balance Sheet Location | | March 31, 2020 | December 31, 2019 |
| | | | | |
| Derivatives not designated as hedges: | | | | |
| Asset derivative instruments: | | | | |
| Current commodity derivatives | Other current assets | | $ | 1,362 |
| $ | — |
|
| Total derivatives not designated as hedges | | | $ | 1,362 |
| $ | — |
|
Derivatives Designated as Hedges
Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $50 million of our First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds.
|
| | | | | | | | | | | | | |
| | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2020 | 2019 | | 2020 | 2019 |
| Derivatives in Cash Flow Hedging Relationships | Gain/(Loss) Recognized in OCI | Income Statement Location | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | (in thousands) | | (in thousands) |
| Interest rate swaps | $ | 16 |
| $ | — |
| Interest expense | $ | (16 | ) | $ | — |
|
| Total | $ | 16 |
| $ | — |
| | $ | (16 | ) | $ | — |
|
Derivatives Not Designated as Hedges
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Statements of Comprehensive Income for the three months ended March 31, 2020 and 2019. Note that this presentation does not reflect 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 March 31, |
| | | 2020 | 2019 |
| Derivatives Not Designated as Hedging Instruments | Income Statement Location | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | | (in thousands) |
| Commodity derivatives | Fuel and purchased power | $ | 1,362 |
| $ | — |
|
| | | $ | 1,362 |
| $ | — |
|
As discussed above, financial instruments used to manage lowest cost resources for our customers are not designated as cash flow hedges. The unrealized gains and losses arising from these derivatives are recognized in the Condensed Statements of Comprehensive Income.
Fair Value
We use the following fair value is defined ashierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the pricefollowing fair value categories:
Level 1 — Unadjusted quoted prices available in active markets that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participantsare accessible at the measurement date. Accountingdate 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. We currently do not have any Level 3 investments.
Recurring Fair Value Measurements
Derivatives
Our commodity contracts are valued using the market approach and include wholesale power contracts that do not meet the normal purchases and normal sales exception. For these derivative instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value.
|
| | | | | | | | | | | | | | | |
| | As of March 31, 2020 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| | (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives | $ | — |
| $ | 1,362 |
| $ | — |
| | $ | — |
| 1,362 |
|
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2019 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives | $ | — |
| $ | — |
| $ | — |
| | $ | — |
| $ | — |
|
Pension and Postretirement Plan Assets
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance onrequires employers to annually disclose information about the fair value measurements establishesof their assets of a hierarchy for groupingdefined benefit pension or other postretirement plan. The fair value of these assets and liabilities, based on significance of inputs. For additional information seewas presented in Note 112 to the Financial Statements included in our 20162019 Annual Report on Form 10-K filed with the SEC.10-K.
The estimated fair valuesCompany has concluded that the market volatility associated with COVID-19 does not require interim re-measurement of our financialpension plan assets or defined benefit obligations.
Other fair value measures
Financial instruments for which the carrying amount did not equal the fair value were as follows (in thousands) as of:
|
| | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 1,171 |
| $ | 1,171 |
| | $ | 234 |
| $ | 234 |
|
Long-term debt, including current maturities (b) (c) | $ | 339,860 |
| $ | 439,973 |
| | $ | 339,756 |
| $ | 410,466 |
|
|
| | | | | | | | | | | | |
| | March 31, 2020 | December 31, 2019 |
| | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
Long-term debt, including current maturities (a) | $ | 337,356 |
| $ | 451,419 |
| $ | 340,176 |
| $ | 458,286 |
|
_________________
| |
| (a) | Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy. |
| |
(b) | 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. |
| |
(c) | Carrying amount of long-term debt is net of deferred financing costs. |
| |
(7) | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
| | | | | | | |
| Nine months ended September 30, | 2017 | | 2016 |
| | (in thousands) |
| Non-cash investing and financing activities - | | | |
| Property, plant and equipment acquired with accrued liabilities | $ | 10,242 |
| | $ | 5,565 |
|
| Non-cash (decrease) to money pool notes receivable, net | $ | (32,000 | ) | | $ | (36,500 | ) |
| Non-cash dividend to Parent | $ | 32,000 |
| | $ | 36,500 |
|
| | | | |
| Cash (paid) refunded during the period for - | | | |
| Interest (net of amounts capitalized) | $ | (12,838 | ) | | $ | (13,486 | ) |
| |
| (8) | COMMITMENTS AND CONTINGENCIESCommitments and Contingencies |
There have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our 20162019 Annual Report on Form 10-K.
Series 94A Debt
On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020.
We evaluated all subsequent event activity and concluded that no subsequent events have occurred that would require recognition in the condensed financial statements or disclosures.
There are many uncertainties regarding the COVID-19 pandemic, and the Company is closely monitoring the impact of the pandemic on all aspects of its business, including how it will impact its customers, employees, suppliers, vendors, and business partners. We are unable to predict the impact that COVID-19 will have on our financial position and operating results due to numerous uncertainties. The Company expects to continue to assess the evolving impact of COVID-19 and intends to make adjustments to its responses accordingly.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Amounts are presented on a pre-tax basis unless otherwise indicated.
Minor differences in amounts may result due to rounding.
Significant EventsCOVID-19 Pandemic
Regulatory Matters
On June 16, 2017, South Dakota Electric received approval fromOne of the SDPUC on a settlement reachedCompany’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our employees, customers, business partners and the communities we serve. We have executed our business continuity plan with the SDPUC staff agreeinggoal of continuing to provide safe and reliable service during the COVID-19 pandemic.
For the three months ended March 31, 2020, we did not experience significant impacts to our financial results and operational activities due to COVID-19.
Decline in revenues and customer loads for the three months ended March 31, 2020, when compared to the same period in the prior year, were driven primarily by weather. We continue to closely monitor loads and have proactively communicated with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We did not experience a six-year moratorium period effective July 1, 2017. As partsignificant increase in bad debt expense for the three months ended March 31, 2020. We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We continue to monitor the impacts of this agreement, South Dakota Electric willCOVID-19 on our cash flows and bad debt expense.
We continue to maintain adequate liquidity to operate our business and fund our capital investment program. The Company has no material upcoming debt maturities until August 2032. We have not increase base rates, absent an extraordinary event. The moratorium periodhad any changes to our credit ratings. We also includescontinue to monitor the funding status of our employee benefit plan obligations, which had not materially changed as of March 31, 2020.
We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts to supply chains including availability of supplies and materials and lead times. Capital projects are ongoing without material disruption to schedules. Our third party resources continue to support our business plans without disruption. Contingency plans are ongoing due to the impacts of COVID-19, including the potential for rescheduling projects. We currently do not anticipate a suspensionsignificant impact to our capital investment plan for 2020.
We continue to work closely with local health, public safety and government officials to minimize the spread of bothCOVID-19 and minimize the Transmission Facility Adjustmentimpact to our employees and the Environmental Improvement Adjustment,service we provide to our customers. Some of the actions the Company has taken include implementing protocols for our field operations personnel to continue to safely and a $1.0 million increaseeffectively interact with our customers, asking employees to work from home to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million relatedextent possible, quarantining employees if they had traveled to decommissioningan at-risk area, limiting travel to mission critical purposes and Winter Storm Atlas willsequestering essential employees.
As we look forward, we anticipate that our 2020 operating results could potentially be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.
The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:
|
| | | | | | |
| Jurisdiction | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Effective Date | Tariffs and Rate Matters | Percentage of Power Marketing Profit Shared with Customers |
| SD | Global Settlement | 7.76% | Global Settlement | 10/2014 | ECA,TCA, Energy Efficiency Cost Recovery/ DSM | 70% |
Transmission
Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.
Tax Matters - Potential Corporate Tax Reform
President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as to the ultimate legislation that will be enacted into law. We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flowsimpacted as a result of COVID-19, including impact related to the following:
Increased residential and decreased commercial and industrial load and demand;
Increased allowance for credit losses and bad debt expense as a result of suspending disconnections and delayed or non-payment from customers;
Disruption in our supply chains impacting our ability to timely execute our capital investment and maintenance project plans;
Volatility in cost of sales due to changes in commodity prices;
Rate actions from our regulators;
Decreased training, travel and outside services related expenses;
Increased operation and maintenance costs if we experience a shortage of labor availability which would lead to deferral of capital projects and sequestration costs for employees deemed critical at our generating facilities; and
Increased tax benefits for employee retention tax credits and reduced cash tax payments for the payroll tax deferral provision from the CARES Act
During these uncertain times, we remain highly focused on the safety and health of our employees, customers, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential changes cannot yetfor supply chain disruption that may impact our capital and maintenance project plans and the availability of resources to execute our plans.
Company Highlights
Construction continues on the $79 million Corriedale project, which is expected to be determinedplaced in service by year-end 2020. As a result of COVID-19, we regularly communicate with our key suppliers to maintain visibility into any disruptions they are experiencing in the receipt of supplies and such changesmaterials from their suppliers. At this time, we have not experienced significant disruption in our supply chain due to COVID-19 which would cause us to adjust the in-service date for this project. If significant disruptions occur and we were unable to complete the project by December 31, 2020, we could be material.experience loss of production tax credits.
On April 16, 2020, S&P affirmed our credit rating at A.
Results of Operations
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
Gross margin is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in purchased power, purchases, natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.
Our gross margin measure may not be comparable to other companies’ gross margin measure.measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
The following tables provide certain financial information and operating statistics:
| | | | Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance | 2020 | 2019 | Variance |
| | (in thousands) | (in thousands) |
Revenue | $ | 73,938 |
| $ | 66,728 |
| $ | 7,210 |
| $ | 213,785 |
| $ | 197,389 |
| $ | 16,396 |
| $ | 71,611 |
| $ | 79,041 |
| $ | (7,430 | ) |
Fuel and purchased power | 22,843 |
| 18,421 |
| 4,422 |
| 64,604 |
| 55,375 |
| 9,229 |
| 15,987 |
| 22,733 |
| (6,746 | ) |
| Gross margin | 51,095 |
| 48,307 |
| 2,788 |
| 149,181 |
| 142,014 |
| 7,167 |
| |
| Gross margin (non-GAAP) | | 55,624 |
| 56,308 |
| (684 | ) |
| | | |
| Operating expenses | 27,397 |
| 25,897 |
| 1,500 |
| 84,395 |
| 79,888 |
| 4,507 |
| 34,431 |
| 31,666 |
| 2,765 |
|
| Operating income | 23,698 |
| 22,410 |
| 1,288 |
| 64,786 |
| 62,126 |
| 2,660 |
| 21,193 |
| 24,642 |
| (3,449 | ) |
| | | |
| Interest income (expense), net | (4,779 | ) | (4,625 | ) | (154 | ) | (15,216 | ) | (14,478 | ) | (738 | ) | (5,798 | ) | (5,432 | ) | (366 | ) |
| Other income (expense), net | 679 |
| 654 |
| 25 |
| 1,745 |
| 1,670 |
| 75 |
| 359 |
| (375 | ) | 734 |
|
| Income tax expense | (5,772 | ) | (6,429 | ) | 657 |
| (15,632 | ) | (16,316 | ) | 684 |
| |
| Income tax (expense) | | (2,419 | ) | (3,338 | ) | 919 |
|
| Net income | $ | 13,826 |
| $ | 12,010 |
| $ | 1,816 |
| $ | 35,683 |
| $ | 33,002 |
| $ | 2,681 |
| $ | 13,335 |
| $ | 15,497 |
| $ | (2,162 | ) |
____________________
| |
| (a) | Revenue and purchased power for the three months ended March 31, 2020, as well as associated quantities, for a certain wholesale contract have been presented on a net basis. This resulted in a decrease of $3.6 million to both revenue and fuel and purchased power. Amounts for the three months ended March 31, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin. |
Three Months Ended September 30, 2017March 31, 2020 Compared to Three Months Ended September 30, 2016.March 31, 2019. Net income was $14$13 million compared to $12$15 million for the same period in the prior year primarily due to the following:
Gross margin increased over the prior year reflecting decreased primarily due to a $2.8$1.4 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling degree days weredecline from lower heating residential demand from warmer winter weather and $1.2 million of lower off-system power marketing margins partially offset by lower usage per customera $1.4 million mark-to-market gain on wholesale energy contracts and lower commercial and industrial demand. Cooling degree days were 11%$0.6 million of higher than normal in the current year compared to 18% lower than normal for the same period in the prior year.rider revenues.
Operating expenses increased primarily due to higher employee related costs, ashigher generation expenses due to timing of a result ofplanned outage at Neil Simpson II and higher depreciation due to a higher asset base driven by prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from outages.capital expenditures.
Interest expense, net and other income, net were comparable to the same period in the prior year.
23
Income tax expense: The effective tax rate was lower than the prior year, primarily due to higher flow-through benefits in the current year.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income was $36 million compared to $33 million for the same period in the prior year primarily due to the following:
Gross margin increased over the prior year reflecting a $4.0 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling degree days were slightly offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 12% higher than normal in the current year compared to 3% lower than normal for the same period in the prior year.
Operating expenses increased primarily due to higher employee costs as a result of prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from higher outages.
Interest expense, net and other income, net were comparable to the same period in the prior year.
Income tax expense: The effective tax rate was lower than the prior year, primarily due to higher flow-through benefits in the current year.
Operating Statistics
| | | | Electric Revenue by Customer Type | | Electric Revenue | | Quantities Sold |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | | (in thousands) | | (MWh) |
| | (in thousands) | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2017 | | Percentage Change | | 2016 | | 2017 | | Percentage Change | | 2016 | | 2020 | 2019 | | 2020 | 2019 |
| Residential | $ | 18,020 |
| | 3% | | $ | 17,501 |
| | $ | 53,724 |
| | 1% | | $ | 53,057 |
| | $ | 19,681 |
| $ | 21,190 |
| | 153,037 |
| 169,936 |
|
| Commercial | 25,459 |
| | (1)% | | 25,714 |
| | 72,608 |
| | (1)% | | 73,026 |
| | 22,226 |
| 23,144 |
| | 185,961 |
| 194,794 |
|
| Industrial | 8,149 |
| | (2)% | | 8,275 |
| | 24,774 |
| | 1% | | 24,540 |
| | 9,086 |
| 8,357 |
| | 118,558 |
| 108,196 |
|
| Municipal | 1,071 |
| | 2% | | 1,053 |
| | 2,849 |
| | —% | | 2,844 |
| | 771 |
| 781 |
| | 7,439 |
| 7,573 |
|
| Total retail revenue | 52,699 |
| | —% | | 52,543 |
| | 153,955 |
| | —% | | 153,467 |
| | 51,764 |
| 53,472 |
| | 464,995 |
| 480,499 |
|
Contract wholesale (a) | 8,048 |
| | 75% | | 4,596 |
| | 22,593 |
| | 78% | | 12,717 |
| |
Wholesale off-system (b) | 4,787 |
| | 20% | | 3,984 |
| | 11,044 |
| | (2)% | | 11,304 |
| |
Wholesale (a) | | | 4,382 |
| 8,343 |
| | 81,737 |
| 223,020 |
|
| Market - off-system sales | | | 2,377 |
| 4,670 |
| | 105,744 |
| 99,572 |
|
Other revenue (c) | 8,404 |
| | 50% | | 5,605 |
| | 26,193 |
| | 32% | | 19,901 |
| | 13,088 |
| 12,556 |
| | — |
| — |
|
| Total Revenue and Energy Sold | | | 71,611 |
| 79,041 |
| | 652,476 |
| 803,091 |
|
Other Uses, Losses or Generation, net (b) | | | — |
| — |
| | 32,748 |
| 41,910 |
|
| Total revenue | $ | 73,938 |
| | 11% | | $ | 66,728 |
| | $ | 213,785 |
| | 8% | | $ | 197,389 |
| | $ | 71,611 |
| $ | 79,041 |
| | 685,224 |
| 845,001 |
|
____________________
| |
| (a) | IncreaseRevenue and purchased power for the three and nine months ended September 30, 2017 was primarilyMarch 31, 2020, as well as associated quantities, for certain wholesale contracts have been presented on a net basis, which resulted in a decrease of $3.6 million, or 135,327 MWh. Amounts for the three months ended March 31, 2019, were presented on a gross basis and, due to a new 50 MW power sales agreement effective January 1, 2017.their immaterial nature, were not revised. This presentation change has no impact on Gross margin. |
| |
| (b) | Increase for three months ended September 30, 2017 was driven by higher commodity prices on similar MWh quantities sold. For the nine months ended September 30, 2017 higher commodity prices primarily offset lower MWh quantities sold. |
| |
(c) | Increase from the prior year is primarily due to higher transmission revenues. |
|
| | | | | | | | | | | | | | | |
| | Megawatt Hours Sold by Customer Type |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | Percentage Change | | 2016 | | 2017 | | Percentage Change | | 2016 |
| Residential | 129,616 |
| | 5% | | 124,012 |
| | 386,709 |
| | 1% | | 381,616 |
|
| Commercial | 212,773 |
| | —% | | 213,276 |
| | 582,899 |
| | (2)% | | 592,371 |
|
| Industrial | 109,745 |
| | —% | | 110,220 |
| | 323,038 |
| | 1% | | 320,861 |
|
| Municipal | 10,156 |
| | 2% | | 9,927 |
| | 25,865 |
| | —% | | 25,855 |
|
| Total retail quantity sold | 462,290 |
| | 1% | | 457,435 |
| | 1,318,511 |
| | —% | | 1,320,703 |
|
Contract wholesale (a) | 185,723 |
| | 197% | | 62,547 |
| | 537,720 |
| | 195% | | 182,087 |
|
Wholesale off-system (b) | 130,825 |
| | 2% | | 128,415 |
| | 388,287 |
| | (12)% | | 438,852 |
|
| Total quantity sold | 778,838 |
| | 20% | | 648,397 |
| | 2,244,518 |
| | 16% | | 1,941,642 |
|
Losses and company use (c) | 56,447 |
| | 36% | | 41,585 |
| | 155,477 |
| | 40% | | 111,437 |
|
| Total energy | 835,285 |
| | 21% | | 689,982 |
| | 2,399,995 |
| | 17% | | 2,053,079 |
|
____________________
| |
(a) | Increase for the three and nine months ended September 30, 2017 was primarily due to a new 50 MW power sales agreement effective January 1, 2017. |
| |
(b) | Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales. |
| |
(c) | Includes company uses, line losses, and excess exchange production. |
|
| | | | | | | | | | | | | | | |
| | Megawatt Hours Generated and Purchased |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Generated - | 2017 | | Percentage Change | | 2016 | | 2017 | | Percentage Change | | 2016 |
| Coal-fired | 423,766 |
| | 6% | | 401,231 |
| | 1,101,291 |
| | 4% | | 1,054,264 |
|
Natural Gas and Oil (a) | 54,466 |
| | 31% | | 41,654 |
| | 75,840 |
| | (22)% | | 96,649 |
|
| Total generated | 478,232 |
| | 8% | | 442,885 |
| | 1,177,131 |
| | 2% | | 1,150,913 |
|
| | | | | | | | | | | | |
Total purchased (b) | 357,053 |
| | 44% | | 247,097 |
| | 1,222,864 |
| | 36% | | 902,166 |
|
Total generated and purchased (b) | 835,285 |
| | 21% | | 689,982 |
| | 2,399,995 |
| | 17% | | 2,053,079 |
|
|
| | | | |
| Quantities Generated and Purchased (MWh) | Three Months Ended March 31, |
| | 2020 | 2019 |
| Coal-fired | 380,495 |
| 409,666 |
|
| Natural Gas and Oil | 92,471 |
| 47,703 |
|
| Total generated | 472,966 |
| 457,369 |
|
| | | |
Purchased (a) | 212,258 |
| 387,632 |
|
| Total generated and purchased | 685,224 |
| 845,001 |
|
________________
| |
| (a) | Purchased power quantities for the three months ended March 31, 2020, for certain wholesale contracts have been presented on a net basis, which resulted in a decrease of 135,327 MWh. Amounts for the three months ended March 31, 2019, were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin. |
|
| | | | |
Contracted Power Plant Fleet Availability (a) | Three Months Ended March 31, |
| | 2020 | 2019 |
Coal-fired plants (b) | 91.8 | % | 98.2 | % |
Other plants (c) | 98.1 | % | 87.3 | % |
| Total availability | 95.1 | % | 92.4 | % |
____________________
| |
| (a) | Variances for the three and nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market atTotal availability is calculated using a lower or higher cost than to generate.weighted average based on capacity of our generating fleet. |
| |
| (b) | Increase in 2017 is primarily driven by resource needs from2020 includes a new 50 MW power sales agreement effective January 1, 2017.planned outage at Neil Simpson II. |
|
| | | | | | | | | | | |
| | Power Plant Availability |
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2017 | 2016 | 2017 | | 2016 |
Coal-fired plants (a) | 97.5 | % | | 92.8 | % | | 84.8 | % | | 83.2 | % |
| Other plants | 93.7 | % | | 97.7 | % | | 97.0 | % | | 98.4 | % |
| Total availability | 95.5 | % | | 95.6 | % | | 91.3 | % | | 91.8 | % |
____________________
| |
(a)(c) | Both years included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 20162019 included a planned outage at Wygen III and an extended planned outage at Wyodak.Lange CT. |
| | | | Degree Days | | Degree Days | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, | |
| | 2017 | | 2016 | | 2017 | | 2016 | |
| Degree Days | | Three Months Ended March 31, |
| | Actual | Variance from 30-year Average | | Actual | Variance from 30-year Average | | Actual | Variance from 30-year Average | | Actual | Variance from 30-year Average | 2020 | | 2019 |
| | | | | | | | | Actual | Variance from Normal | | Actual | Variance from Normal |
| Heating degree days | 202 |
| (10 | )% | | 161 |
| (23 | )% | | 4,242 |
| (5 | )% | | 3,844 |
| (13 | )% | 3,111 |
| (3 | )% | | 3,916 |
| 22 | % |
| Cooling degree days | 595 |
| 11 | % | | 460 |
| (18 | )% | | 709 |
| 12 | % | | 646 |
| (3 | )% | — |
| — | % | | — |
| — | % |
Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. The following table represents our secured credit rating from each agency’s review which was in effect at September 30, 2017:March 31, 2020:
FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains 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. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as the COVID-19 pandemic, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in Item 1A of our 20162019 Annual Report on Form 10-K, including statements contained within Item 1A - Risk Factors and Part II, Item 1A of this Quarterly Report on Form 10-Q.
| |
| ITEM 4. | CONTROLS AND PROCEDURES |
This section should be read in conjunction with Item 9A, “Controls and Procedures” included in our Annual Report on Form 10-K for the year ended December 31, 2016.
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)1934, as amended (the “Exchange Act”)) as of September 30, 2017.March 31, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of September 30, 2017.at March 31, 2020.
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 Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’sSEC’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, 2017,March 31, 2020, there have been no changes in our internal controlcontrols over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. Although we have altered some work routines due to the COVID-19 pandemic, the changes in our work environment (i.e. remote work arrangements) have not materially impacted our internal controls over financial reporting and have not adversely affected the Company’s ability to maintain operations, including financial reporting systems, ICFR, and disclosure controls and procedures.
BLACK HILLS POWER, INC.
Part II - Other Information
PART II. OTHER INFORMATION
| |
ItemITEM 1. | Legal ProceedingsLEGAL PROCEEDINGS |
For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 20162019 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 is incorporated by reference into this item.10-Q.
| |
ItemITEM 1A. | Risk FactorsRISK FACTORS |
There are no material changes to the Risk Factorsrisk factors previously disclosed in Item 1A of Part I in our 2019 Annual Report on Form 10-K filed with the SEC except as shown below:
Our business, results of operations and financial condition could be adversely affected by the recent coronavirus (COVID-19) outbreak.
We are responding to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread. We provide an essential service to our customers which means it is critical we keep our employees who operate our business healthy and minimize unnecessary exposure to the virus. We continue to execute our business continuity plan and have implemented a comprehensive set of actions for the yearhealth and safety of our customers, employees, business partners and the communities we serve. We have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities and we have implemented work from home policies where appropriate. We have implemented sequestration plans for employees critical to maintaining reliable service.
We have informed both our customers and regulators that disconnections for non-payment will be temporarily suspended. We have instituted measures to ensure our supply chain remains open to us. We continue to implement strong physical and cyber-security measures to ensure our systems remain functional to both serve our operational needs with a remote workforce and to provide uninterrupted service to our customers.
For the three months ended DecemberMarch 31, 2016.2020, the impacts of COVID-19 had a minimal financial impact on our business, operations and financial condition. In particular, we experienced minimal financial impacts to the following due to COVID-19:
Volatility in electricity usage from our residential, commercial and industrial customers resulting in a minimal decrease in total demand;
Delayed payments from an isolated population of our commercial and industrial customers within hard-hit industries;
Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plans as planned;
Reduced availability and productivity of our employees;
Minimal impacts to the availability of our third-party resources;
Minimal decline in the funded status of our pension plan;
Increased costs due to sequestration of mission critical and essential employees; and
Reduced training, travel and outside services related expenses.
Should the COVID-19 pandemic continue for a prolonged period, or impact the areas we serve more significantly than it has today, our business, operations and financial condition could be impacted in more significant ways. The continued spread of COVID-19 and efforts to contain the virus could have the following impacts, in addition to exacerbating the impacts described above:
Adversely impact our strategic business plans, growth strategy and capital investment plans;
Adversely impact electricity demand from our customers, particularly from businesses, commercial and industrial customers;
Reduce the availability and productivity of our employees and third-party resources;
Cause us to experience an increase in costs as a result of our emergency measures;
| |
| • | Result in increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment; |
Cause delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;
Cause delays and disruptions in the supply chain resulting in disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and potential damages in our power purchase agreements;
Cause a deterioration of the credit quality of our counterparties, including power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;
Cause impairment of long-lived assets;
Adversely impact our ability to develop, construct and operate facilities;
Cause a deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;
Cause a delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;
Cause delays in our ability to change rates through regulatory proceedings; and
Cause other risks to impact us, such as the risks described in the “Risk Factors” section of our 2019 Annual Report on Form 10-K, and our ability to meet our financial obligations.
To date, we have not experienced significant impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our business, results of operations, financial condition and cash flows.
| |
ItemITEM 6. | ExhibitsEXHIBITS |
| |
| Exhibit 4.1* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014). |
| |
| 101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
| |
| 101.SCH | XBRL Taxonomy Extension Schema Document |
| |
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
| |
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
| |
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
| |
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
| |
| 104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101 | Financial Statements for XBRL Format101) |
_________________________
| |
| * | Previously filed as part of the filing indicated and incorporated by reference herein. |
Signatures
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BLACK HILLS POWER, INC.
|
| | |
| | /s/ Linden R. Evans |
| | Linden R. Evans, Chairman, President and |
| | Chief Executive Officer |
| | |
| | /s/ Richard W. Kinzley |
| | Richard W. Kinzley, Senior Vice President and |
| | Chief Financial Officer |
| | |
| Dated: | May 5, 2020 | |
/S/ DAVID R. EMERY
David R. Emery, Chairman
and Chief Executive Officer
/S/ RICHARD W. KINZLEY
Richard W. Kinzley, Senior Vice President
and Chief Financial Officer
Dated: November 3, 2017