The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.
BLACK HILLS POWER, INC.
The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.
BLACK HILLS POWER, INC.
The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS
|
| | | | | | |
(unaudited) | Three Months Ended March 31, |
| 2019 | 2018 |
| (in thousands) |
Operating activities: | | |
Net income | $ | 15,497 |
| $ | 11,760 |
|
Adjustments to reconcile net income to net cash provided by operating activities- | | |
Depreciation and amortization | 10,077 |
| 9,884 |
|
Deferred income tax | 1,718 |
| (898 | ) |
Employee benefits | 195 |
| 380 |
|
Other adjustments, net | 1,044 |
| 1,018 |
|
Change in operating assets and liabilities - | | |
Accounts receivable and other current assets | (2,437 | ) | (2,478 | ) |
Accounts payable and other current liabilities | 6,210 |
| 3,320 |
|
Regulatory assets - current | (1,413 | ) | 1,807 |
|
Regulatory liabilities - current | (444 | ) | 3,171 |
|
Other operating activities, net | (594 | ) | 35 |
|
Net cash provided by (used in) operating activities | 29,853 |
| 27,999 |
|
| | |
Investing activities: | | |
Property, plant and equipment additions | (24,386 | ) | (13,533 | ) |
Proceeds from sale of assets | — |
| 4,994 |
|
Other investing activities | (169 | ) | (3,608 | ) |
Net cash provided by (used in) investing activities | (24,555 | ) | (12,147 | ) |
| | |
Financing activities: | | |
Change in money pool notes payable, net | (5,390 | ) | (15,856 | ) |
Other financing activities | (15 | ) | — |
|
Net cash provided by (used in) financing activities | (5,405 | ) | (15,856 | ) |
| | |
Net change in cash | (107 | ) | (4 | ) |
| | |
Cash, beginning of period | 112 |
| 16 |
|
Cash, end of period | $ | 5 |
| $ | 12 |
|
See Note 8 for supplemental cash flow information.
The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.
BLACK HILLS POWER, INC.
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 20162018 Annual Report on Form 10-K)
(1)(1) MANAGEMENT’S STATEMENT
The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “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 20162018 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, 2019, December 31, 20162018 and September 30, 2016March 31, 2018 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2017March 31, 2019 and September 30, 2016,March 31, 2018, and our financial condition as of September 30, 2017March 31, 2019 and December 31, 20162018 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
Revisions
Certain revisions have been made to prior year’s financial information to conform to the current year presentation.
We revised our presentation of cash 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 cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on 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 million for the nine months ended September 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.
Recently IssuedAdopted Accounting Standards
Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. 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 annual and interim reporting periods beginning after December 15, 2017 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 determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. We
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 August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement 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.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.
Leases, ASU 2016-02
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize aincrease transparency and comparability among organizations by requiring the recognition of right-of-use assetassets and lease liabilityliabilities on the balance sheet for allmost leases, with a term greater than 12 months, whereas todaypreviously only financing typefinancing-type lease liabilities (capital leases) arewere recognized on the balance sheet. In addition,Under the definitionnew standard, disclosures are required to meet the objective of a lease has been revised in regardsenabling users of financial statements to when an arrangement conveysassess the right to control the useamount, timing and uncertainty 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 arising 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.leases.
We currently expect to adopt thisadopted the standard oneffective January 1, 2019. We continueelected the option to evaluatenot recast comparative periods presented with transitioning to the impactnew lease standard and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of thispractical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment of existing land easement agreements.
Adoption of the new standard resulted in the recording of an operating lease right-of-use asset and an off-setting operating lease obligation liability of $14 million as of January 1, 2019. The lease standard did not materially impact our net earnings and had no impact on cash flows.
(2) REVENUE
Revenue Recognition
As of January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our financial position, resultscustomers. The following table depicts the disaggregation of operationsrevenue, from contracts with customers by customer type and cash flows as well as monitor emerging guidance on such topics as easementstiming of revenue recognition for the three months ended March 31, 2019 and right of ways, pipeline laterals, purchase power agreements,2018. Sales tax and other industry-related areas.similar taxes are excluded from revenues.
|
| | | | | | |
| Three Months Ended March 31, 2019 | Three Months Ended March 31, 2018 |
| (in thousands) |
Customer types: | | |
Retail | $ | 53,076 |
| $ | 50,641 |
|
Wholesale | 8,343 |
| 9,050 |
|
Market - off-system sales | 4,670 |
| 2,275 |
|
Transmission/Other | 12,831 |
| 11,718 |
|
Revenue from contracts with customers | 78,920 |
| 73,684 |
|
Other revenues | 121 |
| 131 |
|
Total revenues | $ | 79,041 |
| $ | 73,815 |
|
| | |
Timing of revenue recognition: | | |
Services transferred over time | $ | 78,920 |
| $ | 73,684 |
|
Revenue from contracts with customers | $ | 78,920 |
| $ | 73,684 |
|
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts receivable and is further discussed in Note 3. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.do not typically incur costs that would be capitalized, to obtain or fulfill a revenue contract.
| |
(2) (3) | ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS |
Following is a summary of Receivables - customers,Accounts receivable, net included in the accompanying Condensed Balance Sheets (in thousands) as of:
|
| | | | | | |
| March 31, 2019 | December 31, 2018 |
Accounts receivable trade | $ | 18,196 |
| $ | 16,236 |
|
Unbilled revenues | 10,356 |
| 12,333 |
|
Allowance for doubtful accounts | (198 | ) | (138 | ) |
Accounts receivable, net | $ | 28,354 |
| $ | 28,431 |
|
|
| | | | | | |
| 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 ACCOUNTING |
Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.
Our regulatory assets and liabilities were as follows (in thousands) as of:
|
| | | | | | | |
| March 31, 2019 | | December 31, 2018 |
Regulatory assets: | | | |
Loss on reacquired debt (a) | $ | 1,191 |
| | $ | 1,259 |
|
Deferred taxes on AFUDC (b) | 5,048 |
| | 5,020 |
|
Employee benefit plans and related deferred taxes (c)
| 20,085 |
| | 19,868 |
|
Deferred energy and fuel cost adjustments (b) | 21,649 |
| | 20,334 |
|
Deferred taxes on flow through accounting (c) | 9,045 |
| | 8,749 |
|
Decommissioning costs (a) | 7,682 |
| | 8,196 |
|
Vegetation management (a) | 9,790 |
| | 10,366 |
|
Other regulatory assets (a) | 1,866 |
| | 1,940 |
|
Total regulatory assets | $ | 76,356 |
| | $ | 75,732 |
|
Less current regulatory assets | (23,215 | ) | | (19,052 | ) |
Regulatory assets, non-current | $ | 53,141 |
| | $ | 56,680 |
|
|
| | | | | | | | |
| 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) | $ | 53,758 |
| | $ | 52,366 |
|
Employee benefit plan costs and related deferred taxes (c) | 7,518 |
| | 7,518 |
|
Excess deferred income taxes (c) | 99,846 |
| | 100,276 |
|
TCJA revenue reserve | 2,079 |
| | 2,523 |
|
Other regulatory liabilities (c) | 592 |
| | 533 |
|
Total regulatory liabilities | $ | 163,793 |
| | $ | 163,216 |
|
Less current regulatory liabilities | (2,079 | ) | | (2,574 | ) |
Regulatory liabilities, non-current | $ | 161,714 |
| | $ | 160,642 |
|
|
| | | | | | | | |
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 Matters
There have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2018 Annual Report on Form 10-K.
| |
(4)(5) | RELATED-PARTY TRANSACTIONS |
Dividend to Parent
We recorded non-cash dividends to our Parent of $16 million and decreased the utility Money pool note receivable by $16 million for the three months ended March 31, 2018. 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, 2019 | December 31, 2018 |
Accounts receivable from affiliates | $ | 9,903 |
| $ | 8,119 |
|
Accounts payable to affiliates | $ | 26,966 |
| $ | 25,804 |
|
|
| | | | | | | |
| 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, 2019, the average cost of borrowing under the Utility Money Pool was 1.66%2.88%.
We had the following balances with the Utility Money Pool (in thousands) as of:
|
| | | | | | |
| March 31, 2019 | December 31, 2018 |
Money pool notes payable | $ | 33,300 |
| $ | 38,690 |
|
|
| | | | | | | |
| 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, |
| 2019 | 2018 |
Net interest income (expense) | $ | (273 | ) | $ | (36 | ) |
|
| | | | | | | | | | | | |
| 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, |
| 2019 | 2018 |
Revenue: | | |
Energy sold to Cheyenne Light | $ | 574 |
| $ | 703 |
|
Rent from electric properties | $ | 896 |
| $ | 909 |
|
Horizon Point shared facility revenues | $ | 3,007 |
| $ | 2,769 |
|
| | |
Fuel and purchased power: | | |
Purchases of coal from WRDC | $ | 4,657 |
| $ | 4,067 |
|
Purchase of excess energy from Cheyenne Light | $ | 132 |
| $ | 86 |
|
Purchase of renewable wind energy from Cheyenne Light - Happy Jack | $ | 535 |
| $ | 641 |
|
Purchase of renewable wind energy from Cheyenne Light - Silver Sage | $ | 983 |
| $ | 1,093 |
|
| | |
Gas transportation service agreement: | | |
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation | $ | 76 |
| $ | 96 |
|
| | |
Corporate support: | | |
Corporate support services and fees from Black Hills Service Company | $ | 10,191 |
| $ | 7,606 |
|
|
| | | | | | | | | | | | |
| 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 |
|
Horizon Point Agreement
We have a shared facility agreement among South Dakota Electric and Black Hills Service Company where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.
| |
(5) (6) | EMPLOYEE BENEFIT PLANS |
The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
|
| | | | | | |
| Three Months Ended March 31, |
| 2019 | 2018 |
Service cost | $ | 91 |
| $ | 129 |
|
Interest cost | 603 |
| 548 |
|
Expected return on plan assets | (851 | ) | (886 | ) |
Prior service cost | 2 |
| 11 |
|
Net loss (gain) | 305 |
| 516 |
|
Net periodic benefit cost | $ | 150 |
| $ | 318 |
|
|
| | | | | | | | | | | | | | | |
| 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, |
| 2019 | 2018 |
Service cost | $ | 37 |
| $ | 48 |
|
Interest cost | 47 |
| 45 |
|
Prior service cost (benefit) | (84 | ) | (84 | ) |
Net periodic benefit cost | $ | — |
| $ | 9 |
|
|
| | | | | | | | | | | | | | | |
| 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, |
| 2019 | 2018 |
Interest cost | $ | 29 |
| $ | 27 |
|
Net loss (gain) | 16 |
| 26 |
|
Net periodic benefit cost | $ | 45 |
| $ | 53 |
|
|
| | | | | | | | | | | | | | | |
| 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 20172019 and anticipated contributions for 20172019 and 20182020 are as follows (in thousands):
|
| | | | | | | | | |
| Contributions Three Months Ended March 31, 2019 | Remaining Anticipated Contributions for 2019 | Anticipated Contributions for 2020 |
Defined Benefit Pension Plan | $ | — |
| $ | 1,753 |
| $ | 1,841 |
|
Defined Benefit Postretirement Healthcare Plan | $ | 117 |
| $ | 349 |
| $ | 466 |
|
Supplemental Non-qualified Defined Benefit Plans | $ | 58 |
| $ | 172 |
| $ | 240 |
|
|
| | | | | | | | | |
| 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 INSTRUMENTS |
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our 20162018 Annual Report on Form 10-K filed with the SEC.
The estimated fair values of our financial instruments were as follows (in thousands) as of:
| | | September 30, 2017 | | December 31, 2016 | March 31, 2019 | December 31, 2018 |
| Carrying Amount | Fair Value | | Carrying Amount | Fair Value | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 1,171 |
| $ | 1,171 |
| | $ | 234 |
| $ | 234 |
| |
Cash (a) | | $ | 5 |
| $ | 5 |
| $ | 112 |
| $ | 112 |
|
Long-term debt, including current maturities (b) (c) | $ | 339,860 |
| $ | 439,973 |
| | $ | 339,756 |
| $ | 410,466 |
| $ | 340,070 |
| $ | 428,498 |
| $ | 340,035 |
| $ | 412,894 |
|
_________________
| |
(a) | CarryingThe cash fair value approximates faircarrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified inas Level 1 in the fair value hierarchy. We believe that the market risk arising from cash in a bank account is minimal. |
| |
(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)(8) | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
| | | | | | |
| Three Months Ended March 31, |
| 2019 | 2018 |
| (in thousands) |
Non-cash investing and financing activities - | | |
Property, plant and equipment acquired with accrued liabilities | $ | 8,633 |
| $ | 7,556 |
|
Non-cash (decrease) to money pool notes receivable, net | $ | — |
| $ | (16,000 | ) |
Non-cash dividend to Parent | $ | — |
| $ | 16,000 |
|
| | |
Cash (paid) refunded during the period for - | | |
Interest (net of amounts capitalized) | $ | (3,345 | ) | $ | (3,088 | ) |
Income taxes, net | $ | — |
| $ | — |
|
|
| | | | | | | |
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)(9) | COMMITMENTS 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 20162018 Annual Report on Form 10-K.
We have a ground lease for the Wygen III generating facility with an affiliate and communication tower site and operation center facility leases with third parties. Our leases have remaining terms ranging from less than one year to 31 years.
The components of lease expense were as follows (in thousands):
|
| | | | |
| Income Statement Location | Three Months Ended March 31, 2019 |
Operating lease cost | Operations and maintenance | $ | 228 |
|
Variable lease cost | Operations and maintenance | 43 |
|
Total lease cost | | $ | 271 |
|
Supplemental balance sheet information related to leases was as follows (in thousands):
|
| | | | |
| Balance Sheet Location | As of March 31, 2019 |
Assets: | | |
Operating lease assets | Other assets, non-current | $ | 14,316 |
|
Total lease assets | | $ | 14,316 |
|
| | |
Liabilities: | | |
Current: | | |
Operating leases | Accrued liabilities | $ | 279 |
|
| | |
Noncurrent: | | |
Operating leases | Other deferred credits and other liabilities | 14,054 |
|
Total lease liabilities | | $ | 14,333 |
|
Supplemental cash flow information related to leases was as follows (in thousands):
|
| | | |
| Three Months Ended March 31, 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | |
Operating cash flows from operating leases | $ | 223 |
|
Right-of-use assets obtained in exchange for lease obligations: | |
Operating leases | $ | — |
|
|
| | |
| As of March 31, 2019 |
Weighted average remaining lease term (years): | |
Operating leases | 31 years |
|
| |
Weighted average discount rate: | |
Operating leases | 4.4 | % |
Scheduled maturities of operating lease liabilities for future years were as follows (in thousands):
|
| | | |
| Total |
2019 (a) | $ | 681 |
|
2020 | 856 |
|
2021 | 855 |
|
2022 | 856 |
|
2023 | 853 |
|
Thereafter | 21,947 |
|
Total lease payments | $ | 26,048 |
|
Less imputed interest | 11,715 |
|
Present value of lease liabilities | $ | 14,333 |
|
| |
(a) | Includes lease obligations for the remaining nine months of 2019. |
A summary of the changes in equity is as follows:
|
| | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2019 | Common Stock | | | | |
(in thousands except share amounts) | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Total |
December 31, 2018 | 23,416 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 342,145 |
| $ | (891 | ) | $ | 404,245 |
|
Net income (loss) available for common stock | — |
| — |
| — |
| 15,497 |
| — |
| 15,497 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| 12 |
| 12 |
|
Cumulative effect of ASU 2016-02, Leases implementation | — |
| — |
| — |
| (7 | ) | — |
| (7 | ) |
Other adjustments | — |
| — |
| — |
| 1 |
| — |
| 1 |
|
March 31, 2019 | 23,416 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 357,636 |
| $ | (879 | ) | $ | 419,748 |
|
|
| | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2018 | Common Stock | | | | |
(in thousands except share amounts) | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Total |
December 31, 2017 | 23,416 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 332,499 |
| $ | (1,258 | ) | $ | 394,232 |
|
Net income (loss) available for common stock | — |
| — |
| — |
| 11,760 |
| — |
| 11,760 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| 27 |
| 27 |
|
Non-cash dividend to Parent company | — |
| — |
| — |
| (16,000 | ) | — |
| (16,000 | ) |
Other adjustments | — |
| — |
| — |
| 1 |
| — |
| 1 |
|
March 31, 2018 | 23,416 |
| $ | 23,416 |
| $ | 39,575 |
| $ | 328,260 |
| $ | (1,231 | ) | $ | 390,020 |
|
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 Events
Regulatory Matters
On June 16, 2017,April 30, 2019, S&P affirmed South Dakota Electric’s credit rating at A.
During the first quarter, South Dakota Electric received approval from the SDPUCcontinued construction on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0$70 million, increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will 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-long175-mile electric transmission line connecting the Teckla Substation in northeast Wyomingfrom Stegall, Nebraska to the Lange Substation near Rapid City, South Dakota. The first94-mile final segment of this project connecting Tecklathe transmission line is expected to Osage, WY wasbe completed and placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.the fall of 2019.
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 flows as a result of the potential changes cannot yet be determined and such changes could be material.
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 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. 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 | 2019 | 2018 | Variance |
| (in thousands) | (in thousands) |
Revenue | $ | 73,938 |
| $ | 66,728 |
| $ | 7,210 |
| $ | 213,785 |
| $ | 197,389 |
| $ | 16,396 |
| $ | 79,041 |
| $ | 73,815 |
| $ | 5,226 |
|
Fuel and purchased power | 22,843 |
| 18,421 |
| 4,422 |
| 64,604 |
| 55,375 |
| 9,229 |
| 22,733 |
| 22,440 |
| 293 |
|
Gross margin | 51,095 |
| 48,307 |
| 2,788 |
| 149,181 |
| 142,014 |
| 7,167 |
| |
Gross margin (non-GAAP) | | 56,308 |
| 51,375 |
| 4,933 |
|
| | |
Operating expenses | 27,397 |
| 25,897 |
| 1,500 |
| 84,395 |
| 79,888 |
| 4,507 |
| 31,666 |
| 31,011 |
| 655 |
|
Operating income | 23,698 |
| 22,410 |
| 1,288 |
| 64,786 |
| 62,126 |
| 2,660 |
| 24,642 |
| 20,364 |
| 4,278 |
|
| | |
Interest income (expense), net | (4,779 | ) | (4,625 | ) | (154 | ) | (15,216 | ) | (14,478 | ) | (738 | ) | (5,432 | ) | (5,424 | ) | (8 | ) |
Other income (expense), net | 679 |
| 654 |
| 25 |
| 1,745 |
| 1,670 |
| 75 |
| (375 | ) | (117 | ) | (258 | ) |
Income tax expense | (5,772 | ) | (6,429 | ) | 657 |
| (15,632 | ) | (16,316 | ) | 684 |
| (3,338 | ) | (3,063 | ) | (275 | ) |
Net income | $ | 13,826 |
| $ | 12,010 |
| $ | 1,816 |
| $ | 35,683 |
| $ | 33,002 |
| $ | 2,681 |
| $ | 15,497 |
| $ | 11,760 |
| $ | 3,737 |
|
Three Months Ended September 30, 2017March 31, 2019 Compared to Three Months Ended September 30, 2016.March 31, 2018. Net income was $14$15 million compared to $12 million for the same period in the prior year primarily due to the following:
Gross margin increased overprimarily due to $2.4 million of higher power marketing revenue, customer growth, and favorable weather. A $1.6 million reduction in the prior year reflecting a $2.8 million increase inpurchased power capacity charges and higher rider revenues of $0.9 million, primarily related to transmission investment recovery. Higher cooling degree days were offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 11% higher than normal inrecovery, comprised the current year compared to 18% lower than normal forremainder of the same period in the prior year.increase.
Operating expenses increased primarily due to higher outside services expenses and higher employee costs asdriven by labor and benefits partially offset by a result of prior year integration activities and transitiondecrease in expenses chargeddue 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.generation outage timing.
Interest expense, net, Other income (expense), net, and other income, netIncome tax expense were all 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.
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.
| | | Electric Revenue by Customer Type | Electric Revenue by Customer Type |
| Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| (in thousands) | (in thousands) |
| 2017 | | Percentage Change | | 2016 | | 2017 | | Percentage Change | | 2016 | 2019 | | Percentage Change | | 2018 |
Residential | $ | 18,020 |
| | 3% | | $ | 17,501 |
| | $ | 53,724 |
| | 1% | | $ | 53,057 |
| $ | 21,190 |
| | 1% | | $ | 21,061 |
|
Commercial | 25,459 |
| | (1)% | | 25,714 |
| | 72,608 |
| | (1)% | | 73,026 |
| 23,144 |
| | (2)% | | 23,544 |
|
Industrial | 8,149 |
| | (2)% | | 8,275 |
| | 24,774 |
| | 1% | | 24,540 |
| 8,357 |
| | 1% | | 8,276 |
|
Municipal | 1,071 |
| | 2% | | 1,053 |
| | 2,849 |
| | —% | | 2,844 |
| 781 |
| | (4)% | | 811 |
|
Total retail revenue | 52,699 |
| | —% | | 52,543 |
| | 153,955 |
| | —% | | 153,467 |
| 53,472 |
| | —% | | 53,692 |
|
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 | | 8,343 |
| | (8)% | | 9,050 |
|
Market - off-system sales (a) | | 4,670 |
| | 105% | | 2,275 |
|
Other revenue (c)(b) | 8,404 |
| | 50% | | 5,605 |
| | 26,193 |
| | 32% | | 19,901 |
| 12,556 |
| | 43% | | 8,798 |
|
Total revenue | $ | 73,938 |
| | 11% | | $ | 66,728 |
| | $ | 213,785 |
| | 8% | | $ | 197,389 |
| $ | 79,041 |
| | 7% | | $ | 73,815 |
|