Washington, D.C. 20549
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the Registrant 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.
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)..Yes ☐ No ☒
The following terms and abbreviations appear in the text of this report and have the definitions described below:
The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,”“Company”, “us”, “we” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with 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 Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 20162020 Annual Report on Form 10-K filed with the SEC.10-K.
We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation Mining and Oil and Gas.Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
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 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 we have a right to invoice. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three months ended March 31, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues. | | | | | | | | | | | | | | | | | | | | |
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(a) | We are allowed recovery of costs, but we are not allowed a rate of return. |
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(b) | In addition to recovery of costs, we are allowed a rate of return. |
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(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. |
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(d) | Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities 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. |
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(e) | In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, 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.
(6) MATERIALS, SUPPLIES AND FUEL
The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
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| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
Materials and supplies | $ | 73,938 |
| | $ | 68,456 |
| | $ | 67,257 |
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Fuel - Electric Utilities | 2,993 |
| | 3,667 |
| | 4,282 |
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Natural gas in storage held for distribution | 49,589 |
| | 35,087 |
| | 41,936 |
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Total materials, supplies and fuel | $ | 126,520 |
| | $ | 107,210 |
| | $ | 113,475 |
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(7) EARNINGS PER SHARE
A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
| | | | | |
Net income available for common stock | $ | 27,663 |
| $ | 14,131 |
| | $ | 126,381 |
| $ | 54,802 |
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Weighted average shares - basic | 53,243 |
| 52,184 |
| | 53,208 |
| 51,583 |
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Dilutive effect of: | | | | | |
Equity Units (a) | 2,015 |
| 1,414 |
| | 1,872 |
| 1,191 |
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Equity compensation | 174 |
| 135 |
| | 174 |
| 119 |
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Weighted average shares - diluted | 55,432 |
| 53,733 |
| | 55,254 |
| 52,893 |
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__________
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(a) | Calculated using the treasury stock method. | | | | | |
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Three Months Ended March 31, 2021 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
Customer types: | (in thousands) |
Retail | $ | 198,500 | | $ | 341,605 | | $ | 0 | | $ | 14,083 | | $ | (7,107) | | $ | 547,081 | |
Transportation | 0 | | 47,951 | | 0 | | 0 | | (110) | | 47,841 | |
Wholesale | 5,922 | | 0 | | 28,692 | | 0 | | (24,451) | | 10,163 | |
Market - off-system sales | 7,656 | | 73 | | 0 | | 0 | | (2,884) | | 4,845 | |
Transmission/Other | 15,193 | | 10,390 | | 0 | | 0 | | (5,296) | | 20,287 | |
Revenue from contracts with customers | $ | 227,271 | | $ | 400,019 | | $ | 28,692 | | $ | 14,083 | | $ | (39,848) | | $ | 630,217 | |
Other revenues | 137 | | 2,500 | | 471 | | 589 | | (482) | | 3,215 | |
Total revenues | $ | 227,408 | | $ | 402,519 | | $ | 29,163 | | $ | 14,672 | | $ | (40,330) | | $ | 633,432 | |
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Timing of revenue recognition: | | | | | | |
Services transferred at a point in time | $ | 0 | | $ | 0 | | $ | 0 | | $ | 14,083 | | $ | (7,107) | | $ | 6,976 | |
Services transferred over time | 227,271 | | 400,019 | | 28,692 | | 0 | | (32,741) | | 623,241 | |
Revenue from contracts with customers | $ | 227,271 | | $ | 400,019 | | $ | 28,692 | | $ | 14,083 | | $ | (39,848) | | $ | 630,217 | |
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Three Months Ended March 31, 2020 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
Customer Types: | | | | | | |
Retail | $ | 148,640 | | $ | 298,247 | | $ | 0 | | $ | 14,403 | | $ | (7,839) | | $ | 453,451 | |
Transportation | 0 | | 44,108 | | 0 | | 0 | | (139) | | 43,969 | |
Wholesale | 5,552 | | 0 | | 25,467 | | 0 | | (23,612) | | 7,407 | |
Market - off-system sales | 4,867 | | 138 | | 0 | | 0 | | (2,639) | | 2,366 | |
Transmission/Other | 14,857 | | 12,572 | | 0 | | 0 | | (4,413) | | 23,016 | |
Revenue from contracts with customers | $ | 173,916 | | $ | 355,065 | | $ | 25,467 | | $ | 14,403 | | $ | (38,642) | | $ | 530,209 | |
Other revenues | 223 | | 5,708 | | 499 | | 802 | | (391) | | 6,841 | |
Total Revenues | $ | 174,139 | | $ | 360,773 | | $ | 25,966 | | $ | 15,205 | | $ | (39,033) | | $ | 537,050 | |
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Timing of Revenue Recognition: | | | | | | |
Services transferred at a point in time | $ | 0 | | $ | 0 | | $ | 0 | | $ | 14,403 | | $ | (7,839) | | $ | 6,564 | |
Services transferred over time | 173,916 | | 355,065 | | 25,467 | | 0 | | (30,803) | | 523,645 | |
Revenue from contracts with customers | $ | 173,916 | | $ | 355,065 | | $ | 25,467 | | $ | 14,403 | | $ | (38,642) | | $ | 530,209 | |
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Contract Balances
The following outstanding securities were excludednature 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 the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):our Accounts Receivable further discussed in Note 13.
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
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Equity compensation | — |
| 2 |
| | — |
| 4 |
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Anti-dilutive shares | — |
| 2 |
| | — |
| 4 |
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(5) Financing
(8) NOTES PAYABLE AND LONG-TERM DEBTShort-term debt
We had the following notesNotes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
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| March 31, 2021 | December 31, 2020 |
| Balance Outstanding | Letters of Credit (a) | Balance Outstanding | Letters of Credit (a) |
Term Loan | $ | 600,000 | | $ | 0 | | $ | 0 | | $ | 0 | |
Revolving Credit Facility | 0 | | 16,629 | | 0 | | 24,730 | |
CP Program | 215,870 | | 0 | | 234,040 | | 0 | |
Total Notes payable | $ | 815,870 | | $ | 16,629 | | $ | 234,040 | | $ | 24,730 | |
_______________ |
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| September 30, 2017 | December 31, 2016 | September 30, 2016 |
| Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit |
Revolving Credit Facility | $ | — |
| $ | 25,391 |
| $ | 96,600 |
| $ | 36,000 |
| $ | 75,000 |
| $ | 30,500 |
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CP Program | 225,170 |
| — |
| — |
| — |
| — |
| — |
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Total | $ | 225,170 |
| $ | 25,391 |
| $ | 96,600 |
| $ | 36,000 |
| $ | 75,000 |
| $ | 30,500 |
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(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.
Term Loan
On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan, which matures on November 24, 2021, has an interest rate based on LIBOR plus 75 basis points, carries 0 prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. The interest rate on term loan borrowings on March 31, 2021 was 0.86%.
We expect to refinance a portion of the term loan with longer-term debt prior to maturity. In the event we are unable to refinance the remaining obligation, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations.
Revolving Credit Facility and CP Program
On August 9, 2016, we amended and restatedOur net short-term borrowings related to our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options (subject to consent from lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase total commitments of the facility up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at September 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.
On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net amount borrowed under the CP Program during the ninethree months ended September 30, 2017 and our notes outstanding as of September 30, 2017 were $225March 31, 2021 decreased by $18 million. As of September 30, 2017, theThe weighted average interest rate on CP Programshort-term borrowings was 1.46%.
Debt Covenants
On December 7, 2016, we amendedrelated to our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) fromCP Program at March 31, 2021 was 0.23%.
Debt Covenants
Under our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio iswas calculated by dividing (i) Consolidated Indebtedness,consolidated indebtedness, which includes letters of credit and certain guarantees issued, and excludes RSNs by (ii) Capital,capital, which includes Consolidated Indebtednessconsolidated indebtedness plus Net Worth,consolidated net worth, which excludes noncontrolling interestsinterest in subsidiariessubsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and includes the aggregate outstanding amount of the RSNs.accelerate all principal and interest outstanding.
Our Revolving Credit Facility and our Term Loansterm loans require compliance with the following financial covenant, at the end of each quarter:
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| As of September 30, 2017 | | Covenant Requirement |
Consolidated Indebtedness to Capitalization Ratio | 61% | | Less than | 65% |
As of September 30, 2017,which we were in compliance with this covenant.at March 31, 2021:
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| As of March 31, 2021 | | Covenant Requirement |
Consolidated Indebtedness to Capitalization Ratio | 62.6% | | Less than | 65% |
Long-Term Debt
On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were
(6) Earnings Per Share
A reconciliation of share amounts used to fund the payments on the Corporate term loan.
(9) EQUITY
A summary of the changes in equity is as follows:
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Nine Months Ended September 30, 2017 | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity |
| | (in thousands) | |
Balance at December 31, 2016 | $ | 1,614,639 |
| $ | 115,495 |
| $ | 1,730,134 |
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Net income (loss) | 126,381 |
| 10,567 |
| 136,948 |
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Other comprehensive income (loss) | 2,317 |
| — |
| 2,317 |
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Dividends on common stock | (71,334 | ) | — |
| (71,334 | ) |
Share-based compensation | 5,853 |
| — |
| 5,853 |
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Issuance of common stock | — |
| — |
| — |
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Dividend reinvestment and stock purchase plan | 2,300 |
| — |
| 2,300 |
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Redeemable noncontrolling interest | (886 | ) | — |
| (886 | ) |
Cumulative effect of ASU 2016-09 implementation | 3,714 |
| — |
| 3,714 |
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Other stock transactions | (180 | ) | — |
| (180 | ) |
Distribution to noncontrolling interest | — |
| (12,884 | ) | (12,884 | ) |
Balance at September 30, 2017 | $ | 1,682,804 |
| $ | 113,178 |
| $ | 1,795,982 |
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Nine Months Ended September 30, 2016 | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity |
| | (in thousands) | |
Balance at December 31, 2015 | $ | 1,465,867 |
| $ | — |
| $ | 1,465,867 |
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Net income (loss) | 54,802 |
| 6,402 |
| 61,204 |
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Other comprehensive income (loss) | (23,896 | ) | — |
| (23,896 | ) |
Dividends on common stock | (65,247 | ) | — |
| (65,247 | ) |
Share-based compensation | 3,822 |
| — |
| 3,822 |
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Issuance of common stock | 105,238 |
| — |
| 105,238 |
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Dividend reinvestment and stock purchase plan | 2,242 |
| — |
| 2,242 |
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Other stock transactions | (24 | ) | — |
| (24 | ) |
Sale of noncontrolling interest | 61,838 |
| 115,496 |
| 177,334 |
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Distribution to noncontrolling interest | — |
| (4,516 | ) | (4,516 | ) |
Balance at September 30, 2016 | $ | 1,604,642 |
| $ | 117,382 |
| $ | 1,722,024 |
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At-the-Market Equity Offering Program
On August 4, 2017, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the nine months ended September 30, 2017 under the ATM equity offering program. During the three months ended September 30, 2016, we sold 819,442 shares of common stock for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the nine months ended September 30, 2016, we sold and issued under the ATM equity offering program an aggregate of 1,750,091 shares of common stock, with settlement dates through September 30, 2016, for $106 million, net of $1.1 million in commissions.
Sale of Noncontrolling Interest in Subsidiary
Black Hills Colorado IPP owns a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric.
This partial sale was recorded as an equity transaction with no resulting gain or loss on the sale. Further, GAAP requires that noncontrolling interests in subsidiaries and affiliates be reportedcompute earnings per share in the equity sectionaccompanying Condensed Consolidated Statements of a company’s balance sheet. Distributions of net income attributable to the noncontrolling interest are due within 30 daysIncome was as follows (in thousands):
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| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
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Net income available for common stock | | | | $ | 96,316 | | $ | 93,174 | |
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Weighted average shares - basic | | | | 62,633 | | 61,778 | |
Dilutive effect of: | | | | | |
Equity compensation | | | | 58 | | 78 | |
Weighted average shares - diluted | | | | 62,691 | | 61,856 | |
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Earnings per share of common stock: | | | | | |
Earnings per share, Basic | | | | $ | 1.54 | | $ | 1.51 | |
Earnings per share, Diluted | | | | $ | 1.54 | | $ | 1.51 | |
The following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.
Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other supportsecurities were excluded from the Company outsidediluted earnings per share computation because of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debttheir anti-dilutive nature (in thousands):
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| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
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Equity compensation | | | | 14 | | 12 | |
Restricted stock | | | | 19 | | 26 | |
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Anti-dilutive shares | | | | 33 | | 38 | |
(7) Risk Management and its cash flows from operations are sufficient to support its ongoing operations.Derivatives
We have recorded the following assetsMarket and liabilities on our consolidated balance sheets related to the VIE described above as of:Credit Risk Disclosures
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| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
| (in thousands) |
Assets | | | | | |
Current assets | $ | 14,732 |
| | $ | 12,627 |
| | $ | 14,191 |
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Property, plant and equipment of variable interest entities, net | $ | 211,380 |
| | $ | 218,798 |
| | $ | 220,818 |
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Liabilities | | | | | |
Current liabilities | $ | 3,275 |
| | $ | 4,342 |
| | $ | 3,353 |
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(10) RISK MANAGEMENT ACTIVITIES
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operationoperations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2016 Annual Report on Form 10-K.
Market Risk
Market risk is the potential loss that mightmay occur as a result of an adverse change in market price, rate or rate.supply. We are exposed to the following market risks, including, but not limited to commodityto:
•Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production, our retail natural gas and wholesale electric power marketing activities, andas well as our fuel procurement for certainseveral of our gas-fired generation assets.assets, which include market fluctuations due to unpredictable factors such as Winter Storm Uri, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and
•Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
For production and generation activities, weWe 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,cash collateral requirements, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based onupon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified.
Derivatives and Hedging Activity
Our derivative and hedging activities recordedincluded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 118.
Oil and Gas
We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.
To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on our futures and swaps. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.
The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income.
The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of:
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| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
| Crude Oil Futures | Crude Oil Options | Natural Gas Futures and Swaps | | Crude Oil Futures | Crude Oil Options | Natural Gas Futures and Swaps | | Crude Oil Futures | Crude Oil Options | Natural Gas Futures and Swaps |
Notional (a) | 54,000 |
| 9,000 |
| 540,000 |
| | 108,000 |
| 36,000 |
| 2,700,000 |
| | 159,000 |
| 36,000 |
| 1,625,000 |
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Maximum terms in months (b) | 15 |
| 3 |
| 3 |
| | 24 |
| 12 |
| 12 |
| | 27 |
| 15 |
| 15 |
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__________ | |
(a) | Crude oil futures and call options in Bbls, natural gas in MMBtus. |
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(b) | Term reflects the maximum forward period hedged. |
Based on September 30, 2017 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Concurrent with the divestiture of our Oil and Gas Business, our existing oil and gas derivative contracts are expected to be unwound within the next six months. Accordingly, we have de-designated our hedge positions in our Oil and Gas Business effective November 1, 2017. See Note 20.
Utilities
The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generationgenerating facilities plants or those plantsfacilities under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices.price volatility. Therefore, as allowed or required by state utilityregulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.
For our regulated utilities’Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income.
We periodically use wholesale power purchase and sale contracts to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchases and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Condensed Consolidated Statements of Income.
We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risksrisk using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/orand sales during time frames ranging from October 2017April 2021 through December 2020.August 2023. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas soldreclassified into earnings in the accompanying Condensed Consolidated Statements of Income.same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.least quarterly.
The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in ahad the following net long positionpositions as of:
| | | September 30, 2017 | | December 31, 2016 | | September 30, 2016 | | March 31, 2021 | | December 31, 2020 | |
| Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | | Units | Notional Amounts | | Maximum Term (months) (a) | | Notional Amounts | | Maximum Term (months) (a) | |
Natural gas futures purchased | 10,250,000 |
| | 39 | | 14,770,000 |
| | 48 | | 17,740,000 |
| | 51 | Natural gas futures purchased | MMBtus | 0 | | | 0 | | 620,000 | | | 3 | |
Natural gas options purchased, net | 7,360,000 |
| | 17 | | 3,020,000 |
| | 5 | | 6,540,000 |
| | 17 | Natural gas options purchased, net | MMBtus | 0 | | | 0 | | 3,160,000 | | | 3 | |
Natural gas basis swaps purchased | 9,170,000 |
| | 39 | | 12,250,000 |
| | 48 | | 13,650,000 |
| | 51 | Natural gas basis swaps purchased | MMBtus | 0 | | | 0 | | 900,000 | | | 3 | |
Natural gas over-the-counter swaps, net (b) | 4,600,000 |
| | 20 | | 4,622,302 |
| | 28 | | 4,749,000 |
| | 20 | Natural gas over-the-counter swaps, net (b) | MMBtus | 3,590,000 | | | 29 | | 3,850,000 | | | 17 | |
Natural gas physical contracts, net | 21,071,714 |
| | 38 | | 21,504,378 |
| | 10 | | 15,666,202 |
| | 13 | |
Natural gas physical contracts, net (c) | | Natural gas physical contracts, net (c) | MMBtus | 3,107,817 | | | 12 | | 17,513,061 | | | 22 | |
Electric wholesale contracts (c) | | Electric wholesale contracts (c) | MWh | 183,025 | | | 9 | | 219,000 | | | 12 | |
|
| | | | | | | | | | | | |
Three Months Ended September 30, 2017 |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) |
Interest rate swaps | | Interest expense | | $ | (713 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Revenue | | 295 |
| | Revenue | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (34 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (452 | ) | | | | $ | — |
|
|
| | | | | | | | | | | | |
Three Months Ended September 30, 2016 |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) |
Interest rate swaps | | Interest expense | | $ | (840 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Revenue | | 2,201 |
| | Revenue | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | 128 |
| | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | 1,489 |
| | | | $ | — |
|
|
| | | | | | | | | | | | |
| | | | | | | | |
Nine Months Ended September 30, 2017 |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) |
Interest rate swaps | | Interest expense | | $ | (2,228 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Revenue | | 954 |
| | Revenue | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (20 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (1,294 | ) | | | | $ | — |
|
| | | | | | | | |
|
| | | | | | | | | | | | |
| | | | | | | | |
Nine Months Ended September 30, 2016 |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) |
Interest rate swaps | | Interest expense | | $ | (2,530 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Revenue | | 9,140 |
| | Revenue | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (23 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | 6,587 |
| | | | $ | — |
|
|
| | | | | | | |
| Three Months Ended September 30, |
| 2017 | | 2016 |
| (In thousands) |
Increase (decrease) in fair value: | | | |
Interest rate swaps | $ | — |
| | $ | (787 | ) |
Forward commodity contracts | (254 | ) | | 174 |
|
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 713 |
| | 1,162 |
|
Forward commodity contracts | (261 | ) | | (2,329 | ) |
Total other comprehensive income (loss) from hedging | $ | 198 |
| | $ | (1,780 | ) |
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2017 | | 2016 |
| (In thousands) |
Increase (decrease) in fair value: | | | |
Interest rate swaps | $ | — |
| | $ | (31,452 | ) |
Forward commodity contracts | 1,197 |
| | (92 | ) |
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 2,228 |
| | 2,852 |
|
Forward commodity contracts | (934 | ) | | 4,459 |
|
Total other comprehensive income (loss) from hedging | $ | 2,491 |
| | $ | (24,233 | ) |
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2017March 31, 2021 and 2016 (in thousands).2020. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit or loss we realized when the underlying physical and financial transactions were settled.
|
| | | | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 |
Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | | | |
Commodity derivatives | Revenue | $ | (53 | ) | | $ | — |
|
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (322 | ) | | (342 | ) |
| | $ | (375 | ) | | $ | (342 | ) |
| | | | | | | | | | | |
| | Three Months Ended March 31, |
| | 2021 | 2020 |
Derivatives Not Designated as Hedging Instruments | Income Statement Location | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | (in thousands) |
Commodity derivatives - Electric | Fuel, purchased power and cost of natural gas sold | $ | (1,524) | | $ | 1,362 | |
Commodity derivatives - Natural Gas | Fuel, purchased power and cost of natural gas sold | 366 | | 766 | |
| | $ | (1,158) | | $ | 2,128 | |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | | | |
Commodity derivatives | Revenue | $ | 90 |
| | $ | — |
|
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (1,822 | ) | | 2,492 |
|
| | $ | (1,732 | ) | | $ | 2,492 |
|
As discussed above, financial instruments used in our regulated utilitiesGas Utilities are not designated as cash flow hedges. However, thereThere is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets.assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assetsasset or Regulatory liability related to the hedges in our Gas Utilities were $11 million, $8.8$0.3 million and $14$2.2 million at September 30, 2017,as of March 31, 2021 and December 31, 20162020, respectively. For our Electric Utilities, the unrealized gains and September 30, 2016, respectively.losses arising from these derivatives are recognized in the Condensed Consolidated Statements of Income.
(8) Fair Value Measurements
(11) FAIR VALUE MEASUREMENTS
Derivative Financial Instruments
The accounting guidance forWe use the following fair value measurements requires certain disclosures abouthierarchy for determining inputs for our financial instruments. Our assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observabilityfinancial instruments are classified and disclosed in one of the following fair value categories:
Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.
Level 2 — Pricing inputs utilized in measuringinclude quoted prices for identical or similar assets and liabilities atin 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. 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. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2016 Annual Report on Form 10-K filed with the SEC.
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.
Valuation Methodologies for
Recurring Fair Value Measurements
Derivatives
Oil and Gas Segment:
The commodity contracts for our Oil and Gas segmentUtilities segments are valued using the market approach and include exchange-traded futures, basis swaps and call options. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure.
Utilities Segments:
The commodity contracts for our Utilities Segments, are valued using the market approach and includeforward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.
Corporate Activities:
As of September 30, 2017, we no longer have derivatives within our corporate activities as our interest rate swaps matured in January 2017. The interest rate swaps that were in place prior to January 2017 were valued using the market approach. We established fair value by obtaining price quotes directly from the counterparty which were based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty was validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives included a CVA component. The CVA considered the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilized observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that took into account our credit ratings, and the credit ratingadditional information, see Note 1 of our counterparty.Notes to the Consolidated Financial Statements in our 2020 Annual Report on Form 10-K.
| | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2021 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Gas Utilities | $ | 0 | | $ | 1,389 | | $ | 0 | | | $ | 0 | | $ | 1,389 | |
Commodity derivatives — Electric Utilities | $ | 0 | | $ | 564 | | $ | 0 | | | $ | 0 | | $ | 564 | |
Total | $ | 0 | | $ | 1,953 | | $ | 0 | | | $ | 0 | | $ | 1,953 | |
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Gas Utilities | $ | 0 | | $ | 625 | | $ | 0 | | | $ | 0 | | $ | 625 | |
Commodity derivatives — Electric Utilities | $ | 0 | | $ | 1,944 | | $ | 0 | | | $ | 0 | | $ | 1,944 | |
Total | $ | 0 | | $ | 2,569 | | $ | 0 | | | $ | 0 | | $ | 2,569 | |
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2020 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Gas Utilities | $ | 0 | | $ | 2,504 | | $ | 0 | | | $ | (1,527) | | $ | 977 | |
Commodity derivatives — Electric Utilities | $ | 0 | | $ | 1,065 | | $ | 0 | | | $ | 0 | | $ | 1,065 | |
Total | $ | 0 | | $ | 3,569 | | $ | 0 | | | $ | (1,527) | | $ | 2,042 | |
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Gas Utilities | $ | 0 | | $ | 2,675 | | $ | 0 | | | $ | (1,552) | | $ | 1,123 | |
Commodity derivatives — Electric Utilities | $ | 0 | | $ | 921 | | $ | 0 | | | $ | 0 | | $ | 921 | |
Total | $ | 0 | | $ | 3,596 | | $ | 0 | | | $ | (1,552) | | $ | 2,044 | |
Recurring Fair Value Measurements
Pension and Postretirement Plan Assets
There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.
The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.
|
| | | | | | | | | | | | | | | | |
| As of September 30, 2017 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 769 |
| $ | — |
| | $ | (544 | ) | $ | 225 |
|
Commodity derivatives — Utilities | — |
| 2,880 |
| — |
| | (2,448 | ) | 432 |
|
Total | $ | — |
| $ | 3,649 |
| $ | — |
| | $ | (2,992 | ) | $ | 657 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 114 |
| $ | — |
| | $ | — |
| $ | 114 |
|
Commodity derivatives — Utilities | — |
| 12,647 |
| — |
| | (11,125 | ) | 1,522 |
|
Total | $ | — |
| $ | 12,761 |
| $ | — |
| | $ | (11,125 | ) | $ | 1,636 |
|
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2016 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 2,886 |
| $ | — |
| | $ | (2,733 | ) | $ | 153 |
|
Commodity derivatives —Utilities | — |
| 7,469 |
| — |
| | (3,262 | ) | 4,207 |
|
Total | $ | — |
| $ | 10,355 |
| $ | — |
| | $ | (5,995 | ) | $ | 4,360 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 1,586 |
| $ | — |
| | $ | — |
| $ | 1,586 |
|
Commodity derivatives — Utilities | — |
| 12,201 |
| — |
| | (11,144 | ) | 1,057 |
|
Interest rate swaps | — |
| 90 |
| — |
| | — |
| 90 |
|
Total | $ | — |
| $ | 13,877 |
| $ | — |
| | $ | (11,144 | ) | $ | 2,733 |
|
|
| | | | | | | | | | | | | | | | |
| As of September 30, 2016 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 2,882 |
| $ | — |
| | $ | — |
| $ | 2,882 |
|
Commodity derivatives — Utilities | — |
| 5,330 |
| — |
| | (3,647 | ) | 1,683 |
|
Total | $ | — |
| $ | 8,212 |
| $ | — |
| | $ | (3,647 | ) | $ | 4,565 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Oil and Gas | $ | — |
| $ | 705 |
| $ | — |
| | $ | — |
| $ | 705 |
|
Commodity derivatives — Utilities | — |
| 16,130 |
| — |
| | (15,231 | ) | 899 |
|
Interest rate swaps | — |
| 654 |
| — |
| | — |
| 654 |
|
Total | $ | — |
| $ | 17,489 |
| $ | — |
| | $ | (15,231 | ) | $ | 2,258 |
|
Fair Value Measures 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 permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.
The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
|
| | | | | | | | |
As of September 30, 2017 |
| Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
Derivatives designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 227 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | — |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 511 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 59 |
|
Total derivatives designated as hedges | | | $ | 227 |
| $ | 570 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 430 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | — |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 1,051 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 15 |
|
Total derivatives not designated as hedges | | | $ | 430 |
| $ | 1,066 |
|
|
| | | | | | | | |
As of December 31, 2016 |
| Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
Derivatives designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 1,161 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | 124 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 1,090 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 238 |
|
Interest rate swaps | Derivative liabilities — current | | — |
| 90 |
|
Total derivatives designated as hedges | | | $ | 1,285 |
| $ | 1,418 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 2,977 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | 98 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 1,279 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 36 |
|
Total derivatives not designated as hedges | | | $ | 3,075 |
| $ | 1,315 |
|
|
| | | | | | | | |
As of September 30, 2016 |
| Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
Derivatives designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 2,919 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | 66 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 479 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 256 |
|
Interest rate swaps | Derivative liabilities — current | | — |
| 654 |
|
Total derivatives designated as hedges | | | $ | 2,985 |
| $ | 1,389 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 1,463 |
| $ | — |
|
Commodity derivatives | Derivative assets — non-current | | 117 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 808 |
|
Commodity derivatives | Derivative liabilities — non-current | | — |
| 61 |
|
Total derivatives not designated as hedges | | | $ | 1,580 |
| $ | 869 |
|
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 1815 to the Consolidated Financial Statements included in our 20162020 Annual Report on Form 10-K.
24
(12) FAIR VALUE OF FINANCIAL INSTRUMENTS
Other fair value measures
The estimatedcarrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and fair values of our financial instruments excluding derivatives which are presented in Note 11, were as followsnot recorded at fair value on the Condensed Consolidated Balance Sheets (in thousands) as of:
|
| | | | | | | | | | | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
| Carrying Amount | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 13,510 |
| $ | 13,510 |
| | $ | 13,580 |
| $ | 13,580 |
| | $ | 31,814 |
| $ | 31,814 |
|
Restricted cash and equivalents (a) | $ | 2,683 |
| $ | 2,683 |
| | $ | 2,274 |
| $ | 2,274 |
| | $ | 2,140 |
| $ | 2,140 |
|
Notes payable (b) | $ | 225,170 |
| $ | 225,170 |
| | $ | 96,600 |
| $ | 96,600 |
| | $ | 75,000 |
| $ | 75,000 |
|
Long-term debt, including current maturities (c) (d) | $ | 3,115,607 |
| $ | 3,362,971 |
| | $ | 3,216,932 |
| $ | 3,351,305 |
| | $ | 3,217,511 |
| $ | 3,525,362 |
|
| | | | | | | | | | | | | | | | | |
| March 31, 2021 | | December 31, 2020 |
| Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Long-term debt, including current maturities (a) | $ | 3,536,158 | | $ | 3,938,977 | | | $ | 3,536,536 | | $ | 4,208,167 | |
__________
| |
(a) | Carrying value approximates fair value due to either the 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) | Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. |
| |
(c) | 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. |
| |
(d) | (a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs. |
| |
(13)
| OTHER COMPREHENSIVE INCOME (LOSS) |
(9) Other Comprehensive Income
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.
The following table details reclassifications out of AOCI and into netNet income. The amounts in parentheses below indicate decreases to netNet income in the Condensed Consolidated Statements of Income for the period net of tax (in thousands):
| | | | | | | | | | | | | | |
| Location on the Condensed Consolidated Statements of Income | | | | Amount Reclassified from AOCI |
| | Three Months Ended March 31, |
| | | 2021 | 2020 |
Gains and (losses) on cash flow hedges: | | | | | | |
Interest rate swaps | Interest expense | | | | $ | (713) | | $ | (713) | |
Commodity contracts | Fuel, purchased power and cost of natural gas sold | | | | (31) | | (486) | |
| | | | | (744) | | (1,199) | |
Income tax | Income tax benefit | | | | 198 | | 285 | |
Total reclassification adjustments related to cash flow hedges, net of tax | | | | | $ | (546) | | $ | (914) | |
| | | | | | |
Amortization of components of defined benefit plans: | | | | | | |
Prior service cost | Operations and maintenance | | | | $ | 25 | | $ | 30 | |
Actuarial gain (loss) | Operations and maintenance | | | | (598) | | (597) | |
| | | | | (573) | | (567) | |
Income tax | Income tax benefit | | | | 208 | | 88 | |
Total reclassification adjustments related to defined benefit plans, net of tax | | | | | $ | (365) | | $ | (479) | |
Total reclassifications | | | | | $ | (911) | | $ | (1,393) | |
|
| | | | | | | | | | | | | | |
| Location on the Condensed Consolidated Statements of Income | Amount Reclassified from AOCI |
Three Months Ended | | Nine Months Ended |
September 30, 2017 | September 30, 2016 | | September 30, 2017 | September 30, 2016 |
Gains and (losses) on cash flow hedges: | | | | | | |
Interest rate swaps | Interest expense | $ | (713 | ) | $ | (840 | ) | | $ | (2,228 | ) | $ | (2,530 | ) |
Commodity contracts | Revenue | 295 |
| 2,201 |
| | 954 |
| 9,140 |
|
Commodity contracts | Fuel, purchased power and cost of natural gas sold
| (34 | ) | 128 |
| | (20 | ) | (23 | ) |
| | (452 | ) | 1,489 |
| | (1,294 | ) | 6,587 |
|
Income tax | Income tax benefit (expense) | 154 |
| (566 | ) | | 435 |
| (2,450 | ) |
Total reclassification adjustments related to cash flow hedges, net of tax | | $ | (298 | ) | $ | 923 |
| | $ | (859 | ) | $ | 4,137 |
|
| | | | | | |
Amortization of components of defined benefit plans: | | | | | | |
Prior service cost | Operations and maintenance | $ | 49 |
| $ | 55 |
| | $ | 146 |
| $ | 165 |
|
Actuarial gain (loss) | Operations and maintenance | (414 | ) | (494 | ) | | (1,242 | ) | (1,483 | ) |
| | (365 | ) | (439 | ) | | (1,096 | ) | (1,318 | ) |
Income tax | Income tax benefit (expense) | 128 |
| 152 |
| | 393 |
| 460 |
|
Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (237 | ) | $ | (287 | ) | | $ | (703 | ) | $ | (858 | ) |
Total reclassifications | | $ | (535 | ) | $ | 636 |
| | $ | (1,562 | ) | $ | 3,279 |
|
Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
| | | | | | | | | | | | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2020 | $ | (12,558) | | $ | 2 | | $ | (14,790) | | $ | (27,346) | |
Other comprehensive income (loss) | | | | |
before reclassifications | 0 | | 107 | | 0 | | 107 | |
Amounts reclassified from AOCI | 523 | | 23 | | 365 | | 911 | |
As of March 31, 2021 | $ | (12,035) | | $ | 132 | | $ | (14,425) | | $ | (26,328) | |
| | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2019 | $ | (15,122) | | $ | (456) | | $ | (15,077) | | $ | (30,655) | |
Other comprehensive income (loss) | | | | |
before reclassifications | 0 | | (175) | | 55 | | (120) | |
Amounts reclassified from AOCI | 543 | | 371 | | 479 | | 1,393 | |
As of March 31, 2020 | $ | (14,579) | | $ | (260) | | $ | (14,543) | | $ | (29,382) | |
(10) Employee Benefit Plans
|
| | | | | | | | | | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2016 | $ | (18,109 | ) | $ | (233 | ) | $ | (16,541 | ) | $ | (34,883 | ) |
Other comprehensive income (loss) | | | | |
before reclassifications | — |
| 755 |
| — |
| 755 |
|
Amounts reclassified from AOCI | 1,449 |
| (590 | ) | 703 |
| 1,562 |
|
Ending Balance September 30, 2017 | $ | (16,660 | ) | $ | (68 | ) | $ | (15,838 | ) | $ | (32,566 | ) |
| | | | |
| | | | |
| Derivatives Designated as Cash Flow Hedges | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
Balance as of December 31, 2015 | $ | (341 | ) | $ | 7,066 |
| $ | (15,780 | ) | $ | (9,055 | ) |
Other comprehensive income (loss) | | | | |
before reclassifications | (20,200 | ) | (417 | ) | — |
| (20,617 | ) |
Amounts reclassified from AOCI | 1,644 |
| (5,781 | ) | 858 |
| (3,279 | ) |
Ending Balance September 30, 2016 | $ | (18,897 | ) | $ | 868 |
| $ | (14,922 | ) | $ | (32,951 | ) |
(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
| | | | | | | |
Nine Months Ended | September 30, 2017 | | September 30, 2016 |
| (in thousands) |
Non-cash investing and financing activities— | | | |
Property, plant and equipment acquired with accrued liabilities | $ | 35,065 |
| | $ | 44,140 |
|
Increase (decrease) in capitalized assets associated with asset retirement obligations | $ | 1,362 |
| | $ | (2,285 | ) |
| | | |
Cash (paid) refunded during the period — | | | |
Interest (net of amounts capitalized) | $ | (101,840 | ) | | $ | (82,639 | ) |
Income taxes, net | $ | 1 |
| | $ | (1,168 | ) |
(15) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension PlansPlan
The components of net periodic benefit cost for the Defined Benefit Pension PlansPlan were as follows (in thousands):
| | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
Service cost | | | | $ | 1,259 | | $ | 1,353 | |
Interest cost | | | | 2,328 | | 3,357 | |
Expected return on plan assets | | | | (5,219) | | (5,648) | |
| | | | | |
Net loss (gain) | | | | 1,829 | | 2,093 | |
Net periodic benefit cost | | | | $ | 197 | | $ | 1,155 | |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Service cost | $ | 1,759 |
| $ | 2,078 |
| | $ | 5,276 |
| $ | 6,234 |
|
Interest cost | 3,880 |
| 3,936 |
| | 11,640 |
| 11,808 |
|
Expected return on plan assets | (6,130 | ) | (5,766 | ) | | (18,388 | ) | (17,297 | ) |
Prior service cost | 15 |
| 15 |
| | 44 |
| 45 |
|
Net loss (gain) | 1,002 |
| 1,793 |
| | 3,005 |
| 5,379 |
|
Net periodic benefit cost | $ | 526 |
| $ | 2,056 |
| | $ | 1,577 |
| $ | 6,169 |
|
Defined Benefit Postretirement Healthcare PlansPlan
The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare PlansPlan were as follows (in thousands):
| | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
Service cost | | | | $ | 559 | | $ | 514 | |
Interest cost | | | | 265 | | 412 | |
Expected return on plan assets | | | | (34) | | (45) | |
Prior service cost (benefit) | | | | (109) | | (137) | |
Net loss (gain) | | | | 117 | | 5 | |
Net periodic benefit cost | | | | $ | 798 | | $ | 749 | |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Service cost | $ | 575 |
| $ | 467 |
| | $ | 1,725 |
| $ | 1,401 |
|
Interest cost | 533 |
| 485 |
| | 1,600 |
| 1,455 |
|
Expected return on plan assets | (79 | ) | (70 | ) | | (237 | ) | (210 | ) |
Prior service cost (benefit) | (109 | ) | (107 | ) | | (327 | ) | (321 | ) |
Net loss (gain) | 125 |
| 84 |
| | 375 |
| 252 |
|
Net periodic benefit cost | $ | 1,045 |
| $ | 859 |
| | $ | 3,136 |
| $ | 2,577 |
|
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
| | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
Service cost | | | | $ | 693 | | $ | (1,370) | |
Interest cost | | | | 177 | | 275 | |
| | | | | |
Net loss (gain) | | | | 439 | | 426 | |
Net periodic benefit cost | | | | $ | 1,309 | | $ | (669) | |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Service cost | $ | 612 |
| $ | 623 |
| | $ | 2,048 |
| $ | 1,530 |
|
Interest cost | 319 |
| 314 |
| | 957 |
| 943 |
|
Prior service cost | — |
| 1 |
| | 1 |
| 2 |
|
Net loss (gain) | 251 |
| 207 |
| | 751 |
| 621 |
|
Net periodic benefit cost | $ | 1,182 |
| $ | 1,145 |
| | $ | 3,757 |
| $ | 3,096 |
|
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 $13 million. On September 15, 2017, we made an additional contribution of $15 million to reduce our 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 in 2017the first quarter of 2021 and anticipated contributions for 20172021 and 20182022 are as follows (in thousands):
| | | | | | | | | | | | |
| | Contributions Made | Additional Contributions | Contributions |
| | Three Months Ended March 31, 2021 | Anticipated for 2021 | Anticipated for 2022 |
Defined Benefit Pension Plan | | $ | 0 | | $ | 0 | | $ | 3,788 | |
Non-pension Defined Benefit Postretirement Healthcare Plan | | $ | 1,382 | | $ | 4,145 | | $ | 5,241 | |
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | | $ | 482 | | $ | 1,445 | | $ | 1,967 | |
(11) Income Taxes
|
| | | | | | | | | | | | |
| Contributions Made | Contributions Made | Additional Contributions | Contributions |
| Three Months Ended September 30, 2017 | Nine Months Ended September 30, 2017 | Anticipated for 2017 | Anticipated for 2018 |
Defined Benefit Pension Plan | $ | 27,700 |
| $ | 27,700 |
| $ | — |
| $ | 12,700 |
|
Non-pension Defined Benefit Postretirement Healthcare Plans | $ | 1,270 |
| $ | 3,810 |
| $ | 1,270 |
| $ | 5,115 |
|
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | $ | 395 |
| $ | 1,187 |
| $ | 396 |
| $ | 1,682 |
|
Winter Storm Uri
(16) COMMITMENTS AND CONTINGENCIESAs discussed in Note 2 above, $559 million of the incremental costs from Winter Storm Uri are recoverable through our Utilities’ regulatory mechanisms, and we recorded these costs as regulatory assets at March 31, 2021. We expect to recover these costs from customers over several years. Winter Storm Uri costs, which will be deductible in our 2021 tax return, created a net deferred tax liability of approximately $132 million at March 31, 2021. The deferred tax liability will reverse with the same timing as the costs are recovered from our customers.
There have beenThe income tax deduction recognized from Winter Storm Uri will create an NOL in our 2021 federal and state income tax returns. Our federal NOL carryforwards no significantlonger expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2021 to 2040. We do not anticipate material changes to commitmentsour valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of March 31, 2021.
Income Tax Benefit (Expense) and contingencies from those previously disclosed in Note 19 of our NotesEffective Tax Rates
Three Months Ended March 31, 2021 Compared to the Consolidated Financial StatementsThree Months Ended March 31, 2020
Income tax (expense) for the three months ended March 31, 2021 was $(0.5) million compared to $(16) million reported for the same period in our 2016 Annual Report on Form 10-K.
Dividend Restrictions
Our Revolving Credit Facility and other debt obligations contain restrictions on2020. For the paymentthree months ended March 31, 2021 the effective tax rate was 0.5% compared to 14.1% for the same period in 2020. The lower effective tax rate is primarily due to $7.6 million of cash dividends upon a default or eventincreased tax benefits from Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced revenue), $1.5 million of default. Asincreased tax benefits from amortization of September 30, 2017, we were in compliance with the debt covenants.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.
Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.
(17) IMPAIRMENT OF ASSETS
Long-lived Assets
Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These capitalized costs, less accumulated amortization and relatedexcess deferred income taxes and $1.3 million of increased tax benefits from federal production tax credits associated with new wind assets.
(12) Business Segment Information
Our reportable segments are subject to a ceiling testbased on our method of internal reporting, which limitsis generally segregated by differences in products, services and regulation. All of our operations and assets are located within the pooledUnited States.
Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the Chief Operating Decision Maker (CODM) assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written offassets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a non-cash charge.finance lease. This presentation of segment information does not impact consolidated financial results.
There were no impairments for the nine months ended September 30, 2017. In determining the ceiling value of our assets under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. At September 30, 2017, the average NYMEX natural gas priceSegment information was $3.00 per Mcf, adjusted to $2.66 per Mcf at the wellhead; the average NYMEX crude oil price was $49.81 per barrel, adjusted to $45.58 per barrel at the wellhead. At September 30, 2016, the average NYMEX natural gas price was $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead; the average NYMEX crude oil price was $41.68 per barrel, adjusted to $35.88 per barrel at the wellhead. During the three and nine months ended September 30, 2016, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $12 million and $38 million, respectively.as follows (in thousands):
| | | | | | | | | | | |
Total assets (net of intercompany eliminations) as of: | March 31, 2021 | | December 31, 2020 |
Electric Utilities | $ | 3,217,474 | | | $ | 3,120,928 | |
Gas Utilities | 4,900,939 | | | 4,376,204 | |
Power Generation | 406,742 | | | 404,220 | |
Mining | 76,097 | | | 77,085 | |
Corporate and Other | 94,947 | | | 110,349 | |
Total assets | $ | 8,696,199 | | | $ | 8,088,786 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2021 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | |
Electric Utilities | $ | 220,500 | | $ | 137 | | | $ | 6,771 | | $ | 0 | | | $ | 227,408 | |
Gas Utilities | 398,499 | | 2,408 | | | 1,520 | | 92 | | | 402,519 | |
Power Generation | 4,241 | | 421 | | | 24,451 | | 50 | | | 29,163 | |
Mining | 6,977 | | 249 | | | 7,106 | | 340 | | | 14,672 | |
Inter-company eliminations | — | | — | | | (39,848) | | (482) | | | (40,330) | |
Total | $ | 630,217 | | $ | 3,215 | | | $ | 0 | | $ | 0 | | | $ | 633,432 | |
During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
Three Months Ended March 31, 2020 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | |
Electric Utilities | $ | 167,503 | | $ | 223 | | | $ | 6,413 | | $ | 0 | | | $ | 174,139 | |
Gas Utilities | 354,287 | | 5,708 | | | 778 | | 0 | | | 360,773 | |
Power Generation | 1,855 | | 443 | | | 23,612 | | 56 | | | 25,966 | |
Mining | 6,564 | | 467 | | | 7,839 | | 335 | | | 15,205 | |
Inter-company eliminations | — | | — | | | (38,642) | | (391) | | | (39,033) | |
Total | $ | 530,209 | | $ | 6,841 | | | $ | 0 | | $ | 0 | | | $ | 537,050 | |
(18) INCOME TAXES
The effective tax rate differs from the federal statutory rate as follows:
|
| | | | |
| Three Months Ended September 30, |
Tax (benefit) expense | 2017 | 2016 |
Federal statutory rate | 35.0 | % | 35.0 | % |
State income tax (net of federal tax effect) (a) | (1.0 | ) | (4.0 | ) |
Percentage depletion in excess of cost | (1.1 | ) | (2.3 | ) |
Accounting for uncertain tax positions adjustment | (0.9 | ) | (2.4 | ) |
Noncontrolling interest (b) | (3.0 | ) | (3.7 | ) |
Tax credits (c) | (1.5 | ) | — |
|
Effective tax rate adjustment (d) | 3.9 |
| 7.2 |
|
Flow-through adjustments | (1.7 | ) | (2.2 | ) |
AFUDC equity | (0.4 | ) | (0.6 | ) |
Other tax differences | 1.1 |
| 0.1 |
|
| 30.4 | % | 27.1 | % |
__________
| | | | | | | | | | | | | | | | | | | | | | | |
(a) | In the three months ending September 30, 2017 and 2016, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies. Under flow-through accounting the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. | | | | | | |
| | | | | |
| | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| |
(b) | The adjustment reflects the noncontrolling interest attributable to the sale of 49.9% of the membership interests of Colorado IPP in April 2016. |
| | | | | | | | | | | | | | | | | | | |
(c) | The increase in tax credits is due to the production tax credits for the Peak View wind farm and marginal gas well tax credit for the oil and gas segment. |
| | | | | |
(d) | Adjustment to reflect the projected annual effective tax rate, pursuant to ASC 740-270. |
|
| | | | |
| | |
| Nine Months Ended September 30, |
Tax (benefit) expense | 2017 | 2016 |
Federal statutory rate | 35.0 | % | 35.0 | % |
State income tax (net of federal tax effect) (a) | 0.5 |
| 1.7 |
|
Percentage depletion in excess of cost (b) | (0.7 | ) | (9.7 | ) |
Accounting for uncertain tax positions adjustment (c) | (0.2 | ) | (7.7 | ) |
Noncontrolling interest (d) | (1.9 | ) | (2.5 | ) |
IRC 172(f) carryback claim (e) | (1.0 | ) | — |
|
Tax credits (f) | (1.7 | ) | — |
|
Effective tax rate adjustment (g) | 0.3 |
| 0.1 |
|
Flow-through adjustments (h) | (1.2 | ) | (1.9 | ) |
Transaction costs | — |
| 1.4 |
|
Other tax differences | 0.5 |
| (0.9 | ) |
| 29.6 | % | 15.5 | % |
__________
| | | |
(a) | The lower state income tax expense in 2017 is lower primarily attributable to favorable flow-through adjustments. Under flow-through accounting the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. |
| |
(b) | The tax benefit for the nine months ended September 30, 2016 relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. |
| | | | | |
(c) | The tax benefit for the nine months ended September 30, 2016 relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. |
| | | | | |
(d) | Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. |
| | | | | |
(e) | In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company's accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. |
| | | | | |
(f) | The tax credits for the nine months ended September 30, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016. |
| | | | | |
(g) | Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270. |
| | | | | |
(h) | The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. | | | | | | |
| | | | | | | | | | |
| | | | |
| | Three Months Ended March 31, |
| | | 2021 | 2020 |
Adjusted operating income: | | | | |
Electric Utilities | | | $ | 21,813 | | $ | 35,650 | |
Gas Utilities | | | 102,094 | | 102,897 | |
Power Generation | | | 14,269 | | 11,349 | |
Mining | | | 3,261 | | 3,129 | |
Corporate and Other | | | (3,122) | | 160 | |
Operating income | | | 138,315 | | 153,185 | |
| | | | |
Interest expense, net | | | (37,600) | | (35,453) | |
Impairment of investment | | | 0 | | (6,859) | |
Other income (expense), net | | | 266 | | 2,353 | |
Income tax (expense) | | | (494) | | (16,002) | |
Net income | | | 100,487 | | 97,224 | |
Net income attributable to noncontrolling interest | | | (4,171) | | (4,050) | |
Net income available for common stock | | | $ | 96,316 | | $ | 93,174 | |
(13) Selected Balance Sheet Information
Accounts Receivable and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subjectAllowance for Credit Losses
Following is a summary of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 million of the liability for unrecognized tax benefits, including interest, during the first quarter of 2016. The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilitiesAccounts receivable, net included in the first quarteraccompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | |
| March 31, 2021 | | December 31, 2020 |
Accounts receivable, trade | $ | 199,548 | | | $ | 146,899 | |
Unbilled revenue | 91,085 | | | 126,065 | |
Less: Allowance for credit losses | (8,251) | | | (7,003) | |
Accounts receivable, net | $ | 282,382 | | | $ | 265,961 | |
Changes to allowance for credit losses for the three months ended March 31, 2021 and 2020, respectively, were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Balance at Beginning of Year | | | | Additions Charged to Costs and Expenses | | Recoveries and Other Additions | | Write-offs and Other Deductions | | Balance at March 31, |
2021 | | $ | 7,003 | | | | | $ | 1,877 | | | $ | 1,014 | | | $ | (1,643) | | | $ | 8,251 | |
2020 | | $ | 2,444 | | | | | $ | 3,519 | | | $ | 922 | | | $ | (1,723) | | | $ | 5,162 | |
Materials, Supplies and Fuel
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | | | | |
| March 31, 2021 | | December 31, 2020 |
Materials and supplies | $ | 88,088 | | | $ | 85,250 | |
Fuel - Electric Utilities | 1,590 | | | 1,531 | |
Natural gas in storage | 12,925 | | | 30,619 | |
Total materials, supplies and fuel | $ | 102,603 | | | $ | 117,400 | |
Accrued Liabilities
(19) ACCRUED LIABILITIES
The following amounts by major classification are included in Accrued liabilities inon the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | | | | | |
| March 31, 2021 | December 31, 2020 |
Accrued employee compensation, benefits and withholdings | $ | 57,347 | | $ | 77,806 | |
Accrued property taxes | 49,267 | | 47,105 | |
Customer deposits and prepayments | 50,194 | | 52,185 | |
Accrued interest | 45,896 | | 31,520 | |
Other (none of which is individually significant) | 27,740 | | 34,996 | |
Total accrued liabilities | $ | 230,444 | | $ | 243,612 | |
|
| | | | | | | | | |
| September 30, 2017 | December 31, 2016 | September 30, 2016 |
Accrued employee compensation, benefits and withholdings | $ | 54,134 |
| $ | 56,926 |
| $ | 57,203 |
|
Accrued property taxes | 39,564 |
| 40,004 |
| 37,156 |
|
Customer deposits and prepayments | 45,711 |
| 51,628 |
| 51,137 |
|
Accrued interest and contract adjustment payments | 30,977 |
| 45,503 |
| 42,612 |
|
CIAC current portion | 1,575 |
| — |
| 5,465 |
|
Other (none of which is individually significant) | 41,610 |
| 49,973 |
| 34,949 |
|
Total accrued liabilities | $ | 213,571 |
| $ | 244,034 |
| $ | 228,522 |
|
(20) SUBSEQUENT EVENTS
Divestiture of Oil and Gas Business
On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. We have initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate selling or otherwise disposing of all remaining oil and gas properties and assets by year-end 2018 and have retained advisors to accelerate the marketing and sales process. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and for the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, as we did not meet the criteria for classifying assets as held for sale and presenting the segment’s activities as discontinued operations. Effective in the fourth quarter of 2017, our Oil and Gas segment assets and liabilities will be classified as held for sale, and the Oil and Gas results of operations and cash flows will be presented as discontinued operations. When these assets are classified as held for sale, they will be reviewed for impairment which could result in further impairment charges in the future.
Revenue and net loss for our Oil and Gas segment for the three and nine months ended September 30, 2017 and 2016 were as follows:
|
| | | | | | | | | | | | | |
| Three Months Ended | | Nine Months Ended |
(in thousands) | September 30, 2017 | September 30, 2016 | | September 30, 2017 | September 30, 2016 |
Revenue | $ | 6,527 |
| $ | 9,639 |
| | $ | 19,151 |
| $ | 25,660 |
|
Net (loss) available for common stock | $ | (2,712 | ) | $ | (8,828 | ) | | $ | (7,609 | ) | $ | (35,277 | ) |
| |
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in the 2020 Form 10-K.
Executive Summary
We are a customer-focused, growth-oriented utility company operating in the United States. We report our operationselectric and results in the following financial segments:
Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.
Gas Utilities: Our Gas Utilities conduct natural gas utility operations through ourcompany with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming subsidiaries. Our Gas Utilities distributeWyoming.
Recent Developments
Winter Storm Uri
In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and transportenergy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, our net pre-tax incremental fuel, purchased power and natural gas costs during the three months ended March 31, 2021 were approximately $571 million. This amount does not include potential pipeline transportation charges from certain suppliers who have requested and received approval from the FERC to delay billings. The pre-tax incremental costs for the three months ended March 31, 2021 from Winter Storm Uri were as follows:
| | | | | |
| (in millions) |
Incremental fuel, purchased power and natural gas costs recorded to regulatory assets | $ | 558.8 | |
| |
Electric Utilities wholesale power margin sharing | $ | 3.2 | |
Electric Utilities non-recoverable fuel costs | 2.1 | |
Black Hills Energy Services non-recoverable natural gas costs | 8.2 | |
Interest expense from $800 million term loan | 0.7 | |
Less Power Generation favorable net impact | (1.7) | |
Incremental costs recorded as expenses, net | $ | 12.5 | |
| |
Total incremental costs related to Winter Storm Uri, net | $ | 571.3 | |
On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The nine-month term loan has no prepayment penalty and is subject to the same covenants as our Revolving Credit Facility. As of March 31, 2021, we have repaid $200 million of this term loan and expect to refinance a portion with longer-term debt later in 2021. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional term loan information.
Our Utilities have regulatory mechanisms to recover approximately $559 million of incremental costs from Winter Storm Uri. However, given the extraordinary impact of these higher costs to our customers, our regulators are performing a heightened review. We are engaged with our regulators to determine appropriate recovery periods for Winter Storm Uri incremental costs with consideration of the impacts to our customers’ bills. Our estimate of the recoverable incremental costs is based on anticipated filings that we expect to complete in the second quarter of 2021 and is subject to adjustments as applications are submitted and final decisions are issued. See Note 2 of the Notes to Condensed Consolidated Financial Statements for information regarding estimated Winter Storm Uri incremental costs by jurisdiction.
For the three months ended March 31, 2021, we expensed $12.5 million of Winter Storm Uri net incremental costs as a result of negative impacts to our Utilities and financing costs partially offset by favorable impacts to our Power Generation segment. Our Electric Utilities incurred a $3.2 million negative impact to regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our pipeline network to approximately 1,030,800 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.
We also provide non-regulated services through Black Hills Energy Services.fuel cost recovery mechanisms. Black Hills Energy Services provides approximately 55,000 retail distribution customers in Nebraska and Wyoming with unbundledoffers fixed contract pricing for non-regulated gas supply services to our regulated natural gas commodity offerings undercustomers and $8.2 million of increased cost of natural gas sold during Winter Storm Uri is not recoverable through the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP primarily provide appliance repair servicesregulatory construct. Additionally, we incurred $0.7 million of interest expense for the three months ended March 31, 2021, related to approximately 61,000 and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Power Generation:$800 million term loan. Our non-regulated Power Generation segment produces electric powerbenefited from its generating plantsa $1.7 million favorable impact to operating income from Winter Storm Uri. We expect opportunities in 2021 to mitigate these negative impacts through cost management and sells the electric capacity and energy principally to our utilities under long-term contracts.regulatory actions.
Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.COVID-19 Update
Oil and Gas: Our Oil and Gas segment engages in the production of crude oil and natural gas, primarily in the Rocky Mountain region. In the fourth quarter of 2017, we initiated the process of divesting of all remaining Oil and Gas segment assets in order to fully exit the oil and gas business. We anticipate the divestiture process will be complete by year-end 2018. The Company’s Condensed Consolidated Financial Statements and accompanying Notes as of and forFor the three and nine months ended September 30, 2017 include the Oil and Gas segment’s assets and liabilities, results of operations and cash flows within continuing operations, asMarch 31, 2021, we did not meetexperience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the criteriapotential for classifying assetssupply chain disruption that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.
We continue to provide periodic status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions regarding our right to preserve deferred regulatory treatment for certain COVID-19 related costs and to seek recovery of these costs at a later date.
As we look forward, our operating results from COVID-19 could be affected as held for sale and presentingdiscussed in the segment’s activities as discontinued operations during the quarter. See Note 20“Risk Factors” section in Part I, Item 1A of the Condensed Consolidated Financial Statements in this Quarterlyour 2020 Annual Report on Form 10-Q10-K.
Business Segment Highlights and Corporate Activity
Electric Utilities Segment
•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Colorado Solar, LLC, which is expected to be completed by the end of 2023. This agreement will expire 15 years after construction completion. The utility-scale solar project represents Colorado Electric’s preferred bid in a competitive solicitation process completed in September 2020 through its Renewable Advantage plan. With the addition of 200 MW of solar energy on its system, more than half of the Colorado Electric’s generation is forecasted to be sourced from renewable energy resources by 2023, leading to a 70% reduction in carbon emissions by 2024 compared to the 2005 base year.
•On February 11, 2021, South Dakota Electric set a new winter peak load of 326 MW, surpassing the previous winter peak of 320 MW set in February 2019.
Gas Utilities Segment
•On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021 and are expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and an authorized return on equity of 9.5%. The approval also includes an extension of the SSIR for more information.five years and an expansion of this mechanism across the consolidated jurisdictions.
•On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on infrastructure investments in its 7,000-mile natural gas pipeline system. On January 6, 2021, the CPUC issued an Order dismissing the rate review. Colorado Gas plans to file a rate review in the second quarter of 2021.
On September 11, 2020, in accordance with the final order from the earlier rate review filed February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. A decision from the CPUC is expected by mid-2021.
Results of Operations
The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.
Certain industrieslines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices.requirements. In particular, the normal peak usage season for our electric utilitiesElectric Utilities is June through August while the normal peak usage season for our gas utilitiesGas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2017March 31, 2021 and 2016,2020, and our financial condition as of September 30, 2017,March 31, 2021 and December 31, 2016 and September 30, 2016,2020, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
Consolidated Summary and Overview |
|
See Forward-Looking Information in the Liquidity and Capital Resources section | | | | | | | | | | | | | | | Three Months Ended March 31, | | | | | 2021 | 2020 | | | | | | (in thousands except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adjusted operating income (a) | | | | | | | Electric Utilities | | | | $ | 21,813 | | $ | 35,650 | | | Gas Utilities | | | | 102,094 | | 102,897 | | | Power Generation | | | | 14,269 | | 11,349 | | | Mining | | | | 3,261 | | 3,129 | | | Corporate and Other | | | | (3,122) | | 160 | | | Operating income | | | | 138,315 | | 153,185 | | | | | | | | | | Interest expense, net | | | | (37,600) | | (35,453) | | | Impairment of investment | | | | — | | (6,859) | | | Other income (expense), net | | | | 266 | | 2,353 | | | Income tax (expense) | | | | (494) | | (16,002) | | | Net income | | | | 100,487 | | 97,224 | | | Net income attributable to noncontrolling interest | | | | (4,171) | | (4,050) | | | Net income available for common stock | | | | 96,316 | | 93,174 | | | | | | | | | | Total earnings per share of common stock, Diluted | | | | $ | 1.54 | | $ | 1.51 | | |
__________ (a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of this Item 2, beginning on Page 73. |
The segment information does not include inter-company eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.impact consolidated financial results.
Results of Operations
Executive Summary, Significant Events and Overview
Three Months Ended September 30, 2017March 31, 2021 Compared to Three Months Ended September 30, 2016. Net income available for common stock for the three months ended September 30, 2017 was $28 million, or $0.50 per share, compared to Net income available for common stock of $14 million, or $0.26 per share, reported for the same period in 2016. The Net income available for common stock for the three months ended September 30, 2017 increased over the same period in the prior year primarily due to a decrease in after-tax impairment charges on our oil and gas properties, lower after-tax corporate expenses, and higher earnings at our Electric Utilities. These are partially offset by lower earnings at our Gas Utilities. March 31, 2020
The variance to the prior year included the following:
A decrease in non-cash after-tax impairment charges of approximately $7.9•Electric Utilities’ adjusted operating income decreased $14 million primarily due to Colorado Electric’s TCJA-related bill credits to customers, impacts from Winter Storm Uri and unfavorable mark-to-market adjustments on our oilwholesale energy contracts partially offset by increased rider revenues and gas properties;lower operating expenses;
•Gas Utilities’ adjusted operating income decreased $0.8 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services and higher operating expenses mostly offset by new rates and higher heating demand from colder winter weather;
•Power Generation’s adjusted operating income increased $2.9 million primarily due to favorable impacts from Winter Storm Uri;
•Corporate and Other expenses decreasedincreased $3.3 million primarily due to a reduction of $3.8 million of after-tax acquisition and transition costs;
Electric Utilities’ earnings increased $3.1 million driven primarily by returns on prior year generation investments; and
Gas Utilities’ earnings decreased $1.4 million primarily duefavorable true-up of employee costs allocated to the impact of cooler summer temperatures and higher precipitation on summer irrigation load delivered to agricultural customers.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income available for common stock for the nine months ended September 30, 2017 was $126 million, or $2.29 per share, compared to Net income available for common stock of $55 million, or $1.04 per share, reported for the same period in 2016. The Net income available for common stock for the nine months ended September 30, 2017 increased over the same periodour subsidiaries in the priorcurrent year, primarilywhich is offset in our reportable segments;
•A $2.1 million increase in interest expense due to higher earnings at our Gas Utilities, Electric Utilities and Mining segments, lower corporate expenses, and a decrease in impairment charges on our oil and gas properties,debt balances partially offset by lower earnings at our Power Generation segment and by tax benefits realized during the same period in the prior year. The variance to therates;
•A prior year included the following:$6.9 million pre-tax non-cash impairment of our investment in equity securities of a privately held oil and gas company;
32
Earnings at our Oil and Gas segment increased $28
•A $2.1 million decrease in other income primarily due to prior year non-cash after-tax impairmentscredits for our non-qualified benefit plan driven by market performance on our oilplan assets; and gas properties of approximately $33
•A $15.5 million partially offset bydecrease in income tax expense due to lower pre-tax income and a prior year $5.8 millionlower effective tax benefit recognized from additional percentage depletion deductions claimed with respect to our oil and gas properties;
Corporate expenses decreased $27 million compared to the same period in the prior yearrate driven primarily by a $23 million reductiontax benefits from Colorado Electric’s TCJA-related bill credits, amortization of after-tax acquisitionexcess deferred income taxes and transition costs;federal production tax credits associated with new wind assets.
Gas Utilities’ earnings increased $11 million with a full nine months of earnings from our acquired SourceGas utilities compared to approximately 7.5 months in the same period of the prior year;
Electric Utilities’ earnings increased $5.8 million driven primarily by returns on prior year generation investments;
Earnings at our Mining segment increased $2.1 million due to an increase in tons sold as a result of an extended outage in the prior year; and
Earnings at our Power Generation segment decreased $1.9 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full nine months in 2017 compared to approximately 5.5 months in the same period of the prior year.
The following table summarizes select financial results by operating segment and details significant items (in thousands):
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
Revenue | | | | | | |
Revenue | $ | 373,412 |
| $ | 365,742 |
| $ | 7,670 |
| $ | 1,338,724 |
| $ | 1,205,305 |
| $ | 133,419 |
|
Inter-company eliminations | (31,274 | ) | (31,956 | ) | 682 |
| (94,605 | ) | (96,119 | ) | 1,514 |
|
| $ | 342,138 |
| $ | 333,786 |
| $ | 8,352 |
| $ | 1,244,119 |
| $ | 1,109,186 |
| $ | 134,933 |
|
| | | | | | |
Net income (loss) available for common stock | | | | | | |
Electric Utilities | $ | 27,324 |
| $ | 24,181 |
| $ | 3,143 |
| $ | 68,386 |
| $ | 62,625 |
| $ | 5,761 |
|
Gas Utilities | (4,329 | ) | (2,939 | ) | (1,390 | ) | 41,409 |
| 29,975 |
| 11,434 |
|
Power Generation (a) | 6,155 |
| 5,642 |
| 513 |
| 18,017 |
| 19,907 |
| (1,890 | ) |
Mining | 3,477 |
| 3,307 |
| 170 |
| 9,048 |
| 6,969 |
| 2,079 |
|
Oil and Gas (b) (c) | (2,712 | ) | (8,828 | ) | 6,116 |
| (7,609 | ) | (35,277 | ) | 27,668 |
|
| 29,915 |
| 21,363 |
| 8,552 |
| 129,251 |
| 84,199 |
| 45,052 |
|
| | | | | | |
Corporate activities and eliminations (d) (e) | (2,252 | ) | (7,232 | ) | 4,980 |
| (2,870 | ) | (29,397 | ) | 26,527 |
|
| | | | | | |
Net income available for common stock | $ | 27,663 |
| $ | 14,131 |
| $ | 13,532 |
| $ | 126,381 |
| $ | 54,802 |
| $ | 71,579 |
|
__________
| |
(a) | Net income available for common stock for the three and nine months ended September 30, 2017 is net of net income attributable to noncontrolling interest of $3.9 million and $11 million, respectively, and $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively. |
| |
(b) | Net (loss) available for common stock for the three and nine months ended September 30, 2016 included non-cash after-tax impairments of our oil and gas properties of $7.9 million and $33 million, respectively. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
| |
(c) | Net (loss) available for common stock for the nine months ended September 30, 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior tax years. |
| |
(d) | Net (loss) available for common stock for the three and nine months ended September 30, 2017 included incremental, non-recurring acquisition costs, after-tax of $0.2 million and $1.5 million, respectively, as compared to $4.0 million and $24 million for the same periods in the prior year. The three and nine months ended September 30, 2016 also included after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million, respectively. |
| |
(e) | Net (loss) available for common stock for the nine months ended September 30, 2017 included a net tax benefit of approximately $1.4 million from a carryback claim for specified liability losses involving prior tax years. Net (loss) available for common stock for the nine months ended September 30, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
Overview of Business Segments and Corporate Activity
Electric Utilities Segment
Electric Utilities experienced milder summer weather during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016. Cooling degree days for the three and nine months ended September 30, 2017 were both 15% higher than normal, compared to 15% and 26% higher than normal for the same periods in 2016. Compared to the same periods in the prior year, cooling degree days were 5% and 14% lower, respectively. Heating degree days for the three and nine months ended September 30, 2017 were 8% and 11% lower than normal, respectively, compared to 34% and 13% lower than normal for the same periods in 2016.
On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 megawatts of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to construct new generation and plans to present the results to the CPUC by year-end.
On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver County District Court on July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.
Construction was completed on the 144 mile 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.
On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.
Gas Utilities Segment
On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022.
Gas Utilities experienced milder weather during the non-peak three months ended September 30, 2017 compared to the three months ended September 30, 2016. Heating degree days for the three months ended September 30, 2017 were 22% lower than normal compared to 2% lower than normal for the same period in 2016. For the nine months ended September 30, 2017, Gas Utilities experienced slightly colder weather compared to the nine months ended September 30, 2016. Heating degree days were 12% lower than normal for the nine months ended September 30, 2017 compared to 20% lower than normal for the same period in 2016.
The Gas Utilities also experienced cooler summer temperatures and higher precipitation levels during the three months ended September 30, 2017 than the same period in 2016, which reduced the irrigation load delivered to agricultural customers, primarily in our Nebraska service territory.
Oil and Gas Segment
On November 1, 2017, our board of directors authorized the sale of all remaining oil and gas assets and the exit of the business. The segment will be reported as discontinued operations beginning with fourth quarter results. The company has retained advisors to support its ongoing property sales efforts and plans to divest all remaining properties by year-end 2018.
We recently signed agreements to sell our San Juan Basin assets in New Mexico and certain Powder River Basin assets in Wyoming for a combined $28 million. The San Juan Basin transaction is subject to final approval from the
U.S. Bureau of Indian Affairs and U.S. Bureau of Land Management. Both transactions are expected to close by year-end.
Oil and Gas production volumes decreased 9% and 17% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The decrease in production was due to the 2016 sales of non-core properties, and limiting natural gas production to meet minimum daily quantity contractual gas processing commitments in the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for natural gas decreased 15% for the three months ended September 30, 2017 and increased 21% for the nine months ended September 30, 2017 compared to the same periods in 2016, respectively. The average hedged price received for oil decreased 11% and 14% for the three and nine months ended September 30, 2017 compared to the same periods in 2016, respectively.
Corporate Activities
On August 4, 2017, we renewed the ATM equity offering program initiated in March 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program with the exception that the aggregate value increased $100 million.
We utilized favorable short-term borrowings from our CP program to pay down $100 million on a Corporate term loan due in 2019 with principal payments of $50 million paid in May and an additional $50 million paid in July.
On July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.
On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and changed its outlook from Negative to Stable, citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.
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.
Operating Results
A discussion of operating results from our business segments and Corporate activities follows.
Non-GAAP Financial Measure
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 for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas purchases 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.
Electric Utilities
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| (in thousands) |
Revenue | $ | 183,571 |
| $ | 174,501 |
| $ | 9,070 |
| $ | 528,048 |
| $ | 503,258 |
| $ | 24,790 |
|
| | | | | | |
Total fuel and purchased power | 68,733 |
| 66,953 |
| 1,780 |
| 199,398 |
| 194,477 |
| 4,921 |
|
| | | | | | |
Gross margin | 114,838 |
| 107,548 |
| 7,290 |
| 328,650 |
| 308,781 |
| 19,869 |
|
| | | | | | |
Operations and maintenance | 40,204 |
| 38,108 |
| 2,096 |
| 125,302 |
| 116,312 |
| 8,990 |
|
Depreciation and amortization | 23,446 |
| 21,063 |
| 2,383 |
| 69,427 |
| 62,794 |
| 6,633 |
|
Total operating expenses | 63,650 |
| 59,171 |
| 4,479 |
| 194,729 |
| 179,106 |
| 15,623 |
|
| | | | | | |
Operating income | 51,188 |
| 48,377 |
| 2,811 |
| 133,921 |
| 129,675 |
| 4,246 |
|
| | | | | | |
Interest expense, net | (12,744 | ) | (12,046 | ) | (698 | ) | (39,049 | ) | (36,676 | ) | (2,373 | ) |
Other income (expense), net | 649 |
| 1,335 |
| (686 | ) | 1,579 |
| 2,828 |
| (1,249 | ) |
Income tax benefit (expense) | (11,769 | ) | (13,485 | ) | 1,716 |
| (28,065 | ) | (33,202 | ) | 5,137 |
|
Net income | $ | 27,324 |
| $ | 24,181 |
| $ | 3,143 |
| $ | 68,386 |
| $ | 62,625 |
| $ | 5,761 |
|
Results of OperationsOperating results for the Electric Utilities for the were as follows (in thousands):
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | | | 2021 | 2020 | Variance |
| | | | |
Revenue | | | | $ | 227,408 | | $ | 174,139 | | $ | 53,269 | |
| | | | | | |
Total fuel and purchased power | | | | 132,069 | | 64,460 | | 67,609 | |
| | | | | | |
Gross margin (non-GAAP) | | | | 95,339 | | 109,679 | | (14,340) | |
| | | | | | |
Operations and maintenance | | | | 48,577 | | 50,499 | | (1,922) | |
Depreciation and amortization | | | | 24,949 | | 23,530 | | 1,419 | |
Total operating expenses | | | | 73,526 | | 74,029 | | (503) | |
| | | | | | |
Adjusted operating income | | | | $ | 21,813 | | $ | 35,650 | | $ | (13,837) | |
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $27 millionMarch 31, 2020:
Gross margin for the three months ended September 30, 2017, compared to Net income available for common stock of $24 million for the three months ended September 30, 2016, as a result of:
Gross margin increased due primarily to a $3.3 million increase in rider revenues primarily related to transmission investment recovery and a $3.0 million return on investment from the Peak View Wind Project.
Operations and maintenance increased primarily due to $1.4 million of higher generation outage and major maintenance expenses for turbine, generator, pulverizer and boiler work as compared to the prior year. Employee costs increased $0.9 millionMarch 31, 2021 decreased as a result of the following:
| | | | | |
| (in millions) |
TCJA-related bill credits (a) | $ | (9.3) | |
Winter Storm Uri impacts (b) | (5.3) | |
Mark-to-market on wholesale energy contracts | (2.9) | |
Rider recovery | 1.3 | |
Weather | 1.1 | |
Residential customer growth | 0.3 | |
Other | 0.5 | |
Total change in Gross margin (non-GAAP) | $ | (14.3) | |
________________
(a) In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net Income.
(b) As a result of Winter Storm Uri, our Electric Utilities incurred a $3.2 million negative impact to our regulated wholesale power margins due to higher fuel costs and $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms.
Operations and maintenance expense decreased primarily due to prior year integration activities and transition expenses chargedrelated to the Corporate segment. In addition, operating expenses increased $0.4 million from the addition of the Peak View Wind Project and the 40-megawatt gas turbine at themunicipalization efforts in Pueblo, Airport Generating Station.Colorado.
Depreciation and amortization increased primarily due to a higher asset base driven by the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.
Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to the prior year.
Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.expenditures.
Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.
Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Electric Utilities was $68 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $63 million for the nine months ended September 30, 2016, as a result of:
Gross margin increased over the prior year reflecting a $7.5 million return on investment from the Peak View Wind Project, a $6.4 million increase in rider revenues primarily related to transmission investment recovery and a $3.3 million increase in commercial and industrial margins driven by increased demand largely associated with data centers in Cheyenne, Wyoming. A variety of smaller items contribute to the remainder of the increase.
Operations and maintenance increased primarily due to $4.2 million of higher employee costs as a result of prior year integration activities and transition expenses charged to the Corporate segment, $2.0 million increase in generation outage and major maintenance expenses with increased scope of work, $1.9 million of higher property taxes with an increased asset base, and $1.3 million of higher operating expenses from the Peak View Wind Project and 40-megawatt gas turbine at the Pueblo Airport Generating Station.
Depreciation and amortization increased primarily due to a higher asset base driven by the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.
Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to prior year.
Other income (expense), net decreased due to reduced AFUDC with lower current year capital spend.
Income tax benefit (expense): The effective tax rate was lower than the prior year due primarily to wind production tax credits related to the Peak View Wind Project.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Revenue - Electric (in thousands) | 2017 | | 2016 | | 2017 | | 2016 |
Residential: | | | | | | | |
South Dakota Electric | $ | 18,020 |
| | $ | 17,501 |
| | $ | 53,724 |
| | $ | 53,057 |
|
Wyoming Electric | 10,083 |
| | 9,585 |
| | 29,571 |
| | 29,283 |
|
Colorado Electric | 27,763 |
| | 27,460 |
| | 74,722 |
| | 73,721 |
|
Total Residential | 55,866 |
| | 54,546 |
| | 158,017 |
| | 156,061 |
|
| | | | | | | |
Commercial: | | | | | | | |
South Dakota Electric | 25,459 |
| | 25,714 |
| | 72,608 |
| | 73,026 |
|
Wyoming Electric | 16,389 |
| | 16,306 |
| | 48,565 |
| | 47,818 |
|
Colorado Electric | 26,196 |
| | 25,907 |
| | 74,322 |
| | 72,782 |
|
Total Commercial | 68,044 |
| | 67,927 |
| | 195,495 |
| | 193,626 |
|
| | | | | | | |
Industrial: | | | | | | | |
South Dakota Electric | 8,149 |
| | 8,275 |
| | 24,774 |
| | 24,540 |
|
Wyoming Electric | 12,104 |
| | 11,904 |
| | 37,737 |
| | 32,353 |
|
Colorado Electric | 10,311 |
| | 9,870 |
| | 29,072 |
| | 28,917 |
|
Total Industrial | 30,564 |
| | 30,049 |
| | 91,583 |
| | 85,810 |
|
| | | | | | | |
Municipal: | | | | | | | |
South Dakota Electric | 1,071 |
| | 1,053 |
| | 2,849 |
| | 2,844 |
|
Wyoming Electric | 542 |
| | 543 |
| | 1,588 |
| | 1,606 |
|
Colorado Electric | 3,345 |
| | 3,299 |
| | 9,497 |
| | 8,879 |
|
Total Municipal | 4,958 |
| | 4,895 |
| | 13,934 |
| | 13,329 |
|
| | | | | | | |
Total Retail Revenue - Electric | 159,432 |
| | 157,417 |
| | 459,029 |
| | 448,826 |
|
| | | | | | | |
Contract Wholesale: | | | | | | | |
Total Contract Wholesale - South Dakota Electric (a) | 8,048 |
| | 4,596 |
| | 22,593 |
| | 12,717 |
|
| | | | | | | |
Off-system Wholesale: | | | | | | | |
South Dakota Electric | 4,787 |
| | 3,984 |
| | 11,044 |
| | 11,304 |
|
Wyoming Electric | 758 |
| | 924 |
| | 3,505 |
| | 3,777 |
|
Colorado Electric | 387 |
| | 522 |
| | 561 |
| | 1,229 |
|
Total Off-system Wholesale | 5,932 |
| | 5,430 |
| | 15,110 |
| | 16,310 |
|
| | | | | | | |
Other Revenue: | | | | | | | |
South Dakota Electric | 8,404 |
| | 5,605 |
| | 26,193 |
| | 19,901 |
|
Wyoming Electric | 794 |
| | 325 |
| | 2,333 |
| | 1,435 |
|
Colorado Electric | 961 |
| | 1,128 |
| | 2,790 |
| | 4,069 |
|
Total Other Revenue | 10,159 |
| | 7,058 |
| | 31,316 |
| | 25,405 |
|
| | | | | | | |
Total Revenue - Electric | $ | 183,571 |
| | $ | 174,501 |
| | $ | 528,048 |
| | $ | 503,258 |
|
__________
| | | | | |
| |
(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. |
|
| | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Quantities Generated and Purchased (in MWh) | 2017 | | 2016 | | 2017 | | 2016 |
Generated — | | | | | | | |
Coal-fired: | | | | | | | |
South Dakota Electric | 423,766 |
| | 401,231 |
| | 1,101,291 |
| | 1,054,264 |
|
Wyoming Electric (d) | 201,824 |
| | 188,739 |
| | 562,644 |
| | 548,513 |
|
Total Coal-fired | 625,590 |
| | 589,970 |
| | 1,663,935 |
| | 1,602,777 |
|
| | | | | | | |
Natural Gas and Oil: | | | | | | | |
South Dakota Electric (a) | 54,466 |
| | 41,654 |
| | 75,840 |
| | 96,649 |
|
Wyoming Electric (a) | 25,567 |
| | 23,874 |
| | 39,136 |
| | 58,944 |
|
Colorado Electric | 76,432 |
| | 64,507 |
| | 134,089 |
| | 128,397 |
|
Total Natural Gas and Oil | 156,465 |
| | 130,035 |
| | 249,065 |
| | 283,990 |
|
| | | | | | | |
Wind: | | | | | | | |
Colorado Electric (b) | 38,773 |
| | 10,676 |
| | 167,429 |
| | 34,325 |
|
Total Wind | 38,773 |
| | 10,676 |
| | 167,429 |
| | 34,325 |
|
| | | | | | | |
Total Generated: | | | | | | | |
South Dakota Electric | 478,232 |
| | 442,885 |
| | 1,177,131 |
| | 1,150,913 |
|
Wyoming Electric (a) | 227,391 |
| | 212,613 |
| | 601,780 |
| | 607,457 |
|
Colorado Electric (b) | 115,205 |
| | 75,183 |
| | 301,518 |
| | 162,722 |
|
Total Generated | 820,828 |
| | 730,681 |
| | 2,080,429 |
| | 1,921,092 |
|
| | | | | | | |
Purchased — | | | | | | | |
South Dakota Electric (c) | 357,053 |
| | 247,097 |
| | 1,222,864 |
| | 902,166 |
|
Wyoming Electric (d) | 207,554 |
| | 215,257 |
| | 696,229 |
| | 624,137 |
|
Colorado Electric (b) | 476,084 |
| | 527,947 |
| | 1,273,125 |
| | 1,473,195 |
|
Total Purchased | 1,040,691 |
| | 990,301 |
| | 3,192,218 |
| | 2,999,498 |
|
| | | | | | | |
Total Generated and Purchased: | | | | | | | |
South Dakota Electric (c) | 835,285 |
| | 689,982 |
| | 2,399,995 |
| | 2,053,079 |
|
Wyoming Electric | 434,945 |
| | 427,870 |
| | 1,298,009 |
| | 1,231,594 |
|
Colorado Electric | 591,289 |
| | 603,130 |
| | 1,574,643 |
| | 1,635,917 |
|
Total Generated and Purchased | 1,861,519 |
| | 1,720,982 |
| | 5,272,647 |
| | 4,920,590 |
|
__________
| |
(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 at a lower or higher cost than to generate. |
| |
(b) | Increase in generation in 2017 is due to the addition of the Peak View Wind Project in November 2016. This generation replaced resources provided by PPAs in 2016, reducing the quantities purchased. |
| |
(c) | Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement effective January 1, 2017. |
| |
(d) | Year over year increase for nine months ended September 30, 2017 is primarily driven by new load supporting data centers in Cheyenne, Wyoming. |
Operating Statistics
| | | | | | | | | | | | | | | | | | | | | |
| | | Revenue (in thousands) | | | | Quantities Sold (MWh) |
| | Three Months Ended March 31, | | | Three Months Ended March 31, |
| | | 2021 | 2020 | | | | 2021 | 2020 |
| | | | | | | | | |
Residential | | | $ | 72,760 | | $ | 54,505 | | | | | 396,086 | | 373,150 | |
Commercial | | | 77,007 | | 57,823 | | | | | 492,955 | | 494,308 | |
Industrial | | | 43,009 | | 32,169 | | | | | 415,191 | | 460,632 | |
Municipal | | | 5,020 | | 3,878 | | | | | 36,242 | | 36,399 | |
Subtotal Retail Revenue - Electric | | | 197,796 | | 148,375 | | | | | 1,340,474 | | 1,364,489 | |
Contract Wholesale (a) | | | 8,465 | | 5,553 | | | | | 156,995 | | 131,778 | |
Off-system/Power Marketing Wholesale | | | 5,113 | | 4,867 | | | | | 127,583 | | 165,785 | |
Other | | | 16,034 | | 15,344 | | | | | — | | — | |
Total Revenue and Energy Sold | | | 227,408 | | 174,139 | | | | | 1,625,052 | | 1,662,052 | |
Other Uses, Losses or Generation, net | | | — | | — | | | | | 130,975 | | 90,871 | |
Total Revenue and Energy | | | 227,408 | | 174,139 | | | | | 1,756,027 | | 1,752,923 | |
Less cost of fuel and purchased power | | | 132,069 | | 64,460 | | | | | | |
Gross Margin (non-GAAP) | | | $ | 95,339 | | $ | 109,679 | | | | | | |
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Quantity Sold (in MWh) | 2017 | 2016 | | 2017 | 2016 |
Residential: | | | | | |
South Dakota Electric | 129,616 |
| 124,012 |
| | 386,709 |
| 381,616 |
|
Wyoming Electric | 65,723 |
| 63,505 |
| | 190,087 |
| 191,405 |
|
Colorado Electric | 174,127 |
| 176,900 |
| | 461,641 |
| 470,246 |
|
Total Residential | 369,466 |
| 364,417 |
| | 1,038,437 |
| 1,043,267 |
|
| | | | | |
Commercial: | | | | | |
South Dakota Electric | 212,773 |
| 213,276 |
| | 582,899 |
| 592,371 |
|
Wyoming Electric | 137,169 |
| 137,534 |
| | 398,178 |
| 398,414 |
|
Colorado Electric | 208,033 |
| 211,716 |
| | 566,177 |
| 572,062 |
|
Total Commercial | 557,975 |
| 562,526 |
| | 1,547,254 |
| 1,562,847 |
|
| | | | | |
Industrial: | | | | | |
South Dakota Electric | 109,745 |
| 110,220 |
| | 323,038 |
| 320,861 |
|
Wyoming Electric (a) | 182,844 |
| 175,188 |
| | 545,640 |
| 468,262 |
|
Colorado Electric | 114,357 |
| 116,073 |
| | 323,638 |
| 329,016 |
|
Total Industrial | 406,946 |
| 401,481 |
| | 1,192,316 |
| 1,118,139 |
|
| | | | | |
Municipal: | | | | | |
South Dakota Electric | 10,156 |
| 9,927 |
| | 25,865 |
| 25,855 |
|
Wyoming Electric | 2,154 |
| 2,201 |
| | 6,643 |
| 6,848 |
|
Colorado Electric | 35,079 |
| 34,507 |
| | 92,557 |
| 91,116 |
|
Total Municipal | 47,389 |
| 46,635 |
| | 125,065 |
| 123,819 |
|
| | | | | |
Total Retail Quantity Sold | 1,381,776 |
| 1,375,059 |
| | 3,903,072 |
| 3,848,072 |
|
| | | | | |
Contract Wholesale: | | | | | |
Total Contract Wholesale-South Dakota Electric (b) | 185,723 |
| 62,547 |
| | 537,720 |
| 182,087 |
|
| | | | | |
Off-system Wholesale: | | | | | |
South Dakota Electric (c) | 130,825 |
| 128,415 |
| | 388,287 |
| 438,852 |
|
Wyoming Electric | 17,981 |
| 18,788 |
| | 72,517 |
| 77,534 |
|
Colorado Electric (c) | 10,619 |
| 17,949 |
| | 16,479 |
| 53,644 |
|
Total Off-system Wholesale | 159,425 |
| 165,152 |
| | 477,283 |
| 570,030 |
|
| | | | | |
Total Quantity Sold: | | | | | |
South Dakota Electric | 778,838 |
| 648,397 |
| | 2,244,518 |
| 1,941,642 |
|
Wyoming Electric | 405,871 |
| 397,216 |
| | 1,213,065 |
| 1,142,463 |
|
Colorado Electric | 542,215 |
| 557,145 |
| | 1,460,492 |
| 1,516,084 |
|
Total Quantity Sold | 1,726,924 |
| 1,602,758 |
| | 4,918,075 |
| 4,600,189 |
|
| | | | | |
Other Uses, Losses or Generation, net (d): | | | | | |
South Dakota Electric | 56,447 |
| 41,585 |
| | 155,477 |
| 111,437 |
|
Wyoming Electric | 29,074 |
| 30,654 |
| | 84,944 |
| 89,131 |
|
Colorado Electric | 49,074 |
| 45,985 |
| | 114,151 |
| 119,833 |
|
Total Other Uses, Losses and Generation, net | 134,595 |
| 118,224 |
| | 354,572 |
| 320,401 |
|
| | | | | |
Total Energy | 1,861,519 |
| 1,720,982 |
| | 5,272,647 |
| 4,920,590 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
Three Months Ended March 31, | | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold (MWh)(a) |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
Colorado Electric | | $ | 79,741 | | $ | 58,558 | | | $ | 24,091 | | $ | 32,270 | | | 606,343 | | 550,771 | |
South Dakota Electric | | 95,336 | | 71,611 | | | 49,550 | | 55,624 | | | 657,779 | | 685,224 | |
Wyoming Electric | | 52,331 | | 43,970 | | | 21,698 | | 21,785 | | | 491,905 | | 516,928 | |
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold | | $ | 227,408 | | $ | 174,139 | | | $ | 95,339 | | $ | 109,679 | | | 1,756,027 | | 1,752,923 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
__________________________
(a) Year over year increases are driven by new load supporting data centers in Cheyenne, Wyoming.Includes company uses, line losses, and excess exchange production.
| | | | | | | | | | |
| | Three Months Ended March 31, |
Quantities Generated and Purchased (MWh) | | | 2021 | 2020 |
| | | | |
Generated: | | | | |
Coal | | | 482,978 | | 547,829 | |
Natural Gas and Oil | | | 132,105 | | 167,744 | |
Wind | | | 62,295 | | 73,550 | |
Total Generated | | | 677,378 | | 789,123 | |
Purchased | | | 1,078,649 | | 963,800 | |
Total Generated and Purchased | | | 1,756,027 | | 1,752,923 | |
| | | | | | | | | | |
| | Three Months Ended March 31, |
Quantities Generated and Purchased (MWh) | | | 2021 | 2020 |
Generated: | | | | |
Colorado Electric | | | 90,256 | | 94,051 | |
South Dakota Electric | | | 434,322 | | 472,966 | |
Wyoming Electric | | | 152,800 | | 222,106 | |
Total Generated | | | 677,378 | | 789,123 | |
| | | | |
Purchased: | | | | |
Colorado Electric | | | 516,087 | | 456,720 | |
South Dakota Electric | | | 223,457 | | 212,258 | |
Wyoming Electric | | | 339,105 | | 294,822 | |
Total Purchased | | | 1,078,649 | | 963,800 | |
| | | | |
Total Generated and Purchased | | | 1,756,027 | | 1,752,923 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| |
(b) | 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. |
| | | | | |
(c) | Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales. |
| | | | | | | |
(d) | Includes company uses, line losses, and excess exchange production. |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, |
Degree Days | | | 2017 | | | | 2016 |
| Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Heating Degree Days: | | | | | | | | | |
South Dakota Electric | 202 |
| | (10 | )% | | 25% | | 161 |
| | (23 | )% |
Wyoming Electric | 292 |
| | (4 | )% | | 39% | | 210 |
| | (19 | )% |
Colorado Electric | 87 |
| | (11 | )% | | 335% | | 20 |
| | (77 | )% |
Combined (a) | 168 |
| | (8 | )% | | 57% | | 107 |
| | (34 | )% |
| | | | | | | | | |
Cooling Degree Days: | | | | | | | | | |
South Dakota Electric | 595 |
| | 11 | % | | 29% | | 460 |
| | (18 | )% |
Wyoming Electric | 388 |
| | 30 | % | | 8% | | 358 |
| | 19 | % |
Colorado Electric | 784 |
| | 14 | % | | (19)% | | 968 |
| | 33 | % |
Combined (a) | 640 |
| | 15 | % | | (5)% | | 673 |
| | 15 | % |
|
| | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, |
Degree Days | 2017 | | | | 2016 |
| Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Heating Degree Days: | | | | | | | | | |
South Dakota Electric | 4,242 |
| | (5 | )% | | 10% | | 3,844 |
| | (13 | )% |
Wyoming Electric | 4,186 |
| | (11 | )% | | 2% | | 4,120 |
| | (12 | )% |
Colorado Electric | 2,773 |
| | (17 | )% | | (2)% | | 2,821 |
| | (15 | )% |
Combined (a) | 3,559 |
| | (11 | )% | | 4% | | 3,430 |
| | (13 | )% |
| | | | | | | | | |
Cooling Degree Days: | | | | | | | | | |
South Dakota Electric | 709 |
| | 12 | % | | 10% | | 646 |
| | (3 | )% |
Wyoming Electric | 429 |
| | 23 | % | | (7)% | | 460 |
| | 31 | % |
Colorado Electric | 1,027 |
| | 15 | % | | (23)% | | 1,337 |
| | 40 | % |
Combined (a) | 798 |
| | 15 | % | | (14)% | | 926 |
| | 26 | % |
__________
| | | | | | | |
(a) | Combined actuals are calculated based on the weighted average number of total customers by state. |
|
| | | | | | | | | | | | |
Electric Utilities Power Plant Availability | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | 2017 | | 2016 | |
Coal-fired plants (a) | 98.3 | % | | 94.8 | % | | 88.1 | % | | 88.0 | % | |
Natural gas fired plants and Other plants | 94.6 | % | | 98.4 | % | | 95.8 | % | | 97.0 | % | |
Wind (b) | 91.0 | % | | 99.1 | % | | 92.0 | % | | 99.2 | % | |
Total availability | 95.5 | % | | 97.1 | % | | 93.0 | % | | 93.7 | % | |
| | | | | | | | |
Wind capacity factor | 23.6 | % | | 33.5 | % | | 34.3 | % | | 36.1 | % | |
__________
| | | | | | | |
(a) | Both the nine months ended September 30, 2017 and 2016 included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak. |
| | | | | | | |
(b) | 2017 is lower than the prior year primarily due to the addition of the Peak View Wind Project for which 2017 is the first year of commercial operation. | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, |
| 2021 | | 2020 |
Heating Degree Days | Actual | | Variance from Normal | | Actual | | Variance from Normal |
| | | | | | | |
Colorado Electric | 2,731 | | | 3 | % | | 2,456 | | | (7) | % |
South Dakota Electric | 3,324 | | | 3 | % | | 3,111 | | | (3) | % |
Wyoming Electric | 3,261 | | | 8 | % | | 2,999 | | | (1) | % |
Combined (a) | 3,040 | | | 4 | % | | 2,789 | | | (4) | % |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
____________________
(a) Combined actuals are calculated based on the weighted average number of total customers by state.
| | | | | | | | | | |
| | Three Months Ended March 31, |
Contracted generating facilities availability by fuel type (a) | | | 2021 | 2020 |
Coal (b) | | | 83.7 | % | 90.8 | % |
Natural Gas and diesel oil (b) (c) | | | 87.6 | % | 83.5 | % |
Wind | | | 93.5 | % | 99.0 | % |
Total availability | | | 87.2 | % | 87.1 | % |
| | | | |
Wind capacity factor | | | 43.1 | % | 45.6 | % |
____________________
(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2021 included a planned outage at Wygen II and unplanned outages at Neil Simpson II and Pueblo Airport Generation.
(c) 2020 included an unplanned outage at Pueblo Airport Generation.
Gas Utilities
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| (in thousands) |
Revenue: | | | | | | |
Natural gas — regulated | $ | 126,865 |
| $ | 123,699 |
| $ | 3,166 |
| $ | 618,924 |
| $ | 515,963 |
| $ | 102,961 |
|
Other — non-regulated services | 16,029 |
| 17,746 |
| (1,717 | ) | 55,327 |
| 47,916 |
| 7,411 |
|
Total revenue | 142,894 |
| 141,445 |
| 1,449 |
| 674,251 |
| 563,879 |
| 110,372 |
|
| | | | | | |
Cost of sales | | | | | | |
Natural gas — regulated | 33,376 |
| 29,330 |
| 4,046 |
| 255,410 |
| 202,244 |
| 53,166 |
|
Other — non-regulated services | 11,917 |
| 12,400 |
| (483 | ) | 33,615 |
| 25,755 |
| 7,860 |
|
Total cost of sales | 45,293 |
| 41,730 |
| 3,563 |
| 289,025 |
| 227,999 |
| 61,026 |
|
| | | | | | |
Gross margin | 97,601 |
| 99,715 |
| (2,114 | ) | 385,226 |
| 335,880 |
| 49,346 |
|
| | | | | | |
Operations and maintenance | 65,390 |
| 64,921 |
| 469 |
| 201,105 |
| 179,845 |
| 21,260 |
|
Depreciation and amortization | 20,937 |
| 21,193 |
| (256 | ) | 62,658 |
| 57,096 |
| 5,562 |
|
Total operating expenses | 86,327 |
| 86,114 |
| 213 |
| 263,763 |
| 236,941 |
| 26,822 |
|
| | | | | | |
Operating income | 11,274 |
| 13,601 |
| (2,327 | ) | 121,463 |
| 98,939 |
| 22,524 |
|
| | | | | | |
Interest expense, net | (19,527 | ) | (21,267 | ) | 1,740 |
| (58,919 | ) | (53,858 | ) | (5,061 | ) |
Other income (expense), net | (294 | ) | (418 | ) | 124 |
| (342 | ) | (28 | ) | (314 | ) |
Income tax benefit (expense) | 4,218 |
| 5,128 |
| (910 | ) | (20,686 | ) | (15,065 | ) | (5,621 | ) |
Net income (loss) | (4,329 | ) | (2,956 | ) | (1,373 | ) | 41,516 |
| 29,988 |
| 11,528 |
|
Net (income) loss attributable to noncontrolling interest | — |
| 17 |
| (17 | ) | (107 | ) | (13 | ) | (94 | ) |
Net income (loss) available for common stock | $ | (4,329 | ) | $ | (2,939 | ) | $ | (1,390 | ) | $ | 41,409 |
| $ | 29,975 |
| $ | 11,434 |
|
Results of OperationsOperating results for the Gas Utilities for the were as follows (in thousands):
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | | | 2021 | 2020 | Variance |
Revenue: | | | | | | |
Natural gas - regulated | | | | $ | 378,077 | | $ | 335,897 | | $ | 42,180 | |
Other - non-regulated services | | | | 24,442 | | 24,876 | | (434) | |
Total revenue | | | | 402,519 | | 360,773 | | 41,746 | |
| | | | | | |
Cost of sales: | | | | | | |
Natural gas - regulated | | | | 182,967 | | 153,999 | | 28,968 | |
Other - non-regulated services | | | | 10,083 | | 1,363 | | 8,720 | |
Total cost of sales | | | | 193,050 | | 155,362 | | 37,688 | |
| | | | | | |
Gross margin (non-GAAP) | | | | 209,469 | | 205,411 | | 4,058 | |
| | | | | | |
Operations and maintenance | | | | 82,200 | | 77,293 | | 4,907 | |
Depreciation and amortization | | | | 25,175 | | 25,221 | | (46) | |
Total operating expenses | | | | 107,375 | | 102,514 | | 4,861 | |
| | | | | | |
Adjusted operating income | | | | $ | 102,094 | | $ | 102,897 | | $ | (803) | |
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for the Gas Utilities was $(4.3) millionMarch 31, 2020
Gross margin for the three months ended September 30, 2017, compared to Net loss available for common stock of $(3.0) million for the three months ended September 30, 2016,March 31, 2021 increased as a result of:
| | | | | |
| (in millions) |
New rates | $ | 9.2 | |
Weather | 7.5 | |
Black Hills Energy Services Winter Storm Uri costs (a) | (8.2) | |
Non-utility Gas Supply Services | (1.2) | |
Mark-to-market on non-utility natural gas commodity contracts | (0.4) | |
Other | (2.8) | |
Total increase in Gross margin (non-GAAP) | $ | 4.1 | |
Gross margin decreased primarily due__________
(a) Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri is not recoverable through a $3.4 million weather impact from cooler summer temperatures and higher precipitation driving lower irrigation load to agriculture customers in our Nebraska Gas service territory as compared to the same period in the prior year. This is partially offset by gas utilities' customer growth and higher rider revenue.regulatory mechanism.
Operations and maintenance expense increased primarily due to $1.2$5.5 million of higher employee related costs and outside services expenses as a result of prior year integration activitiesdriven by higher headcount and transition expenses chargedhigher stock compensation expense related to the Corporate segment,market performance partially offset by $1.0 million of lower pensiontravel and training expenses.
Depreciation and amortization was comparable to the same period in the prior year.
Interest expense, net decreased primarilyyear due to the August 2016 refinancing of the debt assumed in the SourceGas Acquisition.
Other income (expense), net was comparable to the same period in the prior year.
Income tax benefit (expense): The 2017 effective tax rate is lower than 2016 due to increased flow-through benefits and no changes to uncertain tax positions as compared to 2016.
Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Gas Utilities was $41 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $30 million for the nine months ended September 30, 2016, as a result of:
Gross margin increased primarily due to additional margins of approximately $51 million contributed by the SourceGas utilities in the first quarter of 2017 compared to the first quarter of 2016 which included approximately 1.5 months of SourceGas results. 2017 reflects a full nine months of SourceGas results as compared to approximately 7.5 months in 2016. This is partially offset by lower irrigation loads delivered to agriculture customers primarilydepreciation rates approved in the Nebraska service territoryGas and Colorado Gas rate reviews mostly offset by increased depreciation due to cooler summer temperatures anda higher precipitation in the third quarter of 2017.
Operations and maintenance increased primarily due to additional operating costs of approximately $19 million for the acquired SourceGas utilities, reflecting a full nine months of results in 2017 as compared to approximately 7.5 months in 2016. In addition, employee related expenses increased $5.2 million for the Black Hills legacy gas utilities as a result ofasset base driven by prior year integration activities and transition expenses charged to the Corporate segment. A variety of smaller items contribute to the partially offsetting decrease in operations and maintenance expenses.capital expenditures.
Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas utilities.
Interest expense, net increased primarily due to additional interest expense from the acquired SourceGas utilities.
Other income (expense), net was comparable to the same period in the prior year.
Income tax benefit (expense): The effective tax rate was comparable to the same period in the prior year.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Revenue (in thousands) (a) | 2017 | | 2016 | | 2017 | | 2016 |
Residential: | | | | | | | |
Arkansas | $ | 9,085 |
| | $ | 8,201 |
| | $ | 57,992 |
| | $ | 33,778 |
|
Colorado | 12,911 |
| | 12,144 |
| | 80,351 |
| | 65,285 |
|
Nebraska (b) | 12,622 |
| | 12,259 |
| | 72,965 |
| | 69,132 |
|
Iowa | 10,314 |
| | 9,694 |
| | 60,618 |
| | 57,328 |
|
Kansas | 8,128 |
| | 7,760 |
| | 44,309 |
| | 39,428 |
|
Wyoming (b) | 4,744 |
| | 4,895 |
| | 28,172 |
| | 23,663 |
|
Total Residential | $ | 57,804 |
| | $ | 54,953 |
| | $ | 344,407 |
| | $ | 288,614 |
|
| | | | | | | |
Commercial: | | | | | | | |
Arkansas | $ | 5,281 |
| | $ | 4,123 |
| | $ | 30,465 |
| | $ | 16,652 |
|
Colorado | 4,893 |
| | 4,971 |
| | 29,967 |
| | 23,107 |
|
Nebraska | 2,994 |
| | 3,123 |
| | 20,567 |
| | 19,462 |
|
Iowa | 3,425 |
| | 3,144 |
| | 24,522 |
| | 22,617 |
|
Kansas | 2,672 |
| | 2,298 |
| | 14,695 |
| | 12,558 |
|
Wyoming | 2,101 |
| | 2,315 |
| | 13,940 |
| | 11,495 |
|
Total Commercial | $ | 21,366 |
| | $ | 19,974 |
| | $ | 134,156 |
| | $ | 105,891 |
|
| | | | | | | |
Industrial: | | | | | | | |
Arkansas | $ | 1,801 |
| | $ | 1,463 |
| | $ | 5,382 |
| | $ | 3,071 |
|
Colorado | 906 |
| | 808 |
| | 1,588 |
| | 1,340 |
|
Nebraska | 158 |
| | 143 |
| | 363 |
| | 330 |
|
Iowa | 119 |
| | 189 |
| | 1,158 |
| | 1,014 |
|
Kansas | 5,734 |
| | 5,204 |
| | 7,716 |
| | 7,793 |
|
Wyoming | 754 |
| | 692 |
| | 2,492 |
| | 2,349 |
|
Total Industrial | $ | 9,472 |
| | $ | 8,499 |
| | $ | 18,699 |
| | $ | 15,897 |
|
| | | | | | | |
Transportation: | | | | | | | |
Arkansas | $ | 2,335 |
| | $ | 1,997 |
| | $ | 7,750 |
| | $ | 5,730 |
|
Colorado | 738 |
| | 766 |
| | 2,940 |
| | 2,531 |
|
Nebraska (b) (c) | 20,343 |
| | 23,222 |
| | 54,202 |
| | 49,147 |
|
Iowa | 967 |
| | 970 |
| | 3,557 |
| | 3,525 |
|
Kansas | 1,598 |
| | 1,736 |
| | 4,851 |
| | 5,134 |
|
Wyoming (b) | 4,387 |
| | 4,245 |
| | 18,849 |
| | 14,382 |
|
Total Transportation | $ | 30,368 |
| | $ | 32,936 |
| | $ | 92,149 |
| | $ | 80,449 |
|
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Revenue (in thousands) (continued) | 2017 | | 2016 | | 2017 | | 2016 |
Transmission: | | | | | | | |
Arkansas | $ | 448 |
| | $ | 19 |
| | $ | 1,660 |
| | $ | 44 |
|
Colorado | 4,014 |
| | 3,572 |
| | 17,778 |
| | 12,334 |
|
Wyoming | 1,211 |
| | 1,209 |
| | 3,712 |
| | 3,386 |
|
Total Transmission | $ | 5,673 |
| | $ | 4,800 |
| | $ | 23,150 |
| | $ | 15,764 |
|
| | | | | | | |
Other Sales Revenue: | | | | | | | |
Arkansas | $ | 218 |
| | $ | 398 |
| | $ | 880 |
| | $ | 1,687 |
|
Colorado | 208 |
| | 315 |
| | 687 |
| | 770 |
|
Nebraska | 937 |
| | 912 |
| | 2,724 |
| | 2,587 |
|
Iowa | 96 |
| | 96 |
| | 357 |
| | 409 |
|
Kansas | 494 |
| | 582 |
| | 936 |
| | 3,215 |
|
Wyoming | 229 |
| | 234 |
| | 779 |
| | 680 |
|
Total Other Sales Revenue | $ | 2,182 |
| | $ | 2,537 |
| | $ | 6,363 |
| | $ | 9,348 |
|
| | | | | | | |
Total Regulated Revenue | $ | 126,865 |
| | $ | 123,699 |
| | $ | 618,924 |
| | $ | 515,963 |
|
| | | | | | | |
Non-regulated Services | 16,029 |
| | 17,746 |
| | 55,327 |
| | 47,916 |
|
| | | | | | | |
Total Revenue | $ | 142,894 |
| | $ | 141,445 |
| | $ | 674,251 |
| | $ | 563,879 |
|
__________
| | | | | |
| |
(a) | Certain prior year revenue classes have been revised to conform to current year presentation; total revenue did not change. |
| |
(b) | Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class. |
(c) Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year. |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Gross Margin (in thousands) (a) | 2017 | | 2016 | | 2017 | | 2016 |
Residential: | | | | | | | |
Arkansas | $ | 6,934 |
| | $ | 6,735 |
| | $ | 38,020 |
| | $ | 24,116 |
|
Colorado | 7,533 |
| | 7,235 |
| | 33,784 |
| | 28,531 |
|
Nebraska (b) | 9,333 |
| | 9,214 |
| | 38,383 |
| | 37,634 |
|
Iowa | 8,430 |
| | 8,252 |
| | 31,442 |
| | 30,848 |
|
Kansas | 6,033 |
| | 5,872 |
| | 24,031 |
| | 22,401 |
|
Wyoming (b) | 3,749 |
| | 3,863 |
| | 16,596 |
| | 15,164 |
|
Total Residential | $ | 42,012 |
| | $ | 41,171 |
| | $ | 182,256 |
| | $ | 158,694 |
|
| | | | | | | |
Commercial: | | | | | | | |
Arkansas | $ | 2,904 |
| | $ | 2,551 |
| | $ | 16,053 |
| | $ | 9,595 |
|
Colorado | 2,198 |
| | 2,385 |
| | 10,660 |
| | 8,612 |
|
Nebraska | 1,606 |
| | 1,652 |
| | 7,952 |
| | 7,865 |
|
Iowa | 1,930 |
| | 1,894 |
| | 8,504 |
| | 8,351 |
|
Kansas | 1,371 |
| | 1,289 |
| | 5,846 |
| | 5,300 |
|
Wyoming | 1,088 |
| | 1,217 |
| | 5,916 |
| | 5,596 |
|
Total Commercial | $ | 11,097 |
| | $ | 10,988 |
| | $ | 54,931 |
| | $ | 45,319 |
|
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Gross Margin (in thousands) (continued) | 2017 | | 2016 | | 2017 | | 2016 |
Industrial: | | | | | | | |
Arkansas | $ | 566 |
| | $ | 582 |
| | $ | 1,727 |
| | $ | 1,268 |
|
Colorado | 292 |
| | 326 |
| | 513 |
| | 594 |
|
Nebraska | 57 |
| | 54 |
| | 134 |
| | 149 |
|
Iowa | 33 |
| | 40 |
| | 169 |
| | 127 |
|
Kansas | 1,052 |
| | 986 |
| | 1,638 |
| | 1,754 |
|
Wyoming | 157 |
| | 163 |
| | 484 |
| | 513 |
|
Total Industrial | $ | 2,157 |
| | $ | 2,151 |
| | $ | 4,665 |
| | $ | 4,405 |
|
| | | | | | | |
Transportation: | | | | | | | |
Arkansas | $ | 2,335 |
| | $ | 1,997 |
| | $ | 7,750 |
| | $ | 5,730 |
|
Colorado | 738 |
| | 539 |
| | 2,940 |
| | 2,293 |
|
Nebraska (b) (c) | 20,343 |
| | 23,222 |
| | 54,202 |
| | 49,147 |
|
Iowa | 967 |
| | 970 |
| | 3,557 |
| | 3,525 |
|
Kansas | 1,598 |
| | 1,736 |
| | 4,851 |
| | 5,134 |
|
Wyoming (b) | 4,387 |
| | 4,245 |
| | 18,849 |
| | 14,382 |
|
Total Transportation | $ | 30,368 |
| | $ | 32,709 |
| | $ | 92,149 |
| | $ | 80,211 |
|
| | | | | | | |
Transmission: | | | | | | | |
Arkansas | $ | 448 |
| | $ | 19 |
| | $ | 1,660 |
| | $ | 44 |
|
Colorado | 4,014 |
| | 3,572 |
| | 17,778 |
| | 12,334 |
|
Wyoming | 1,211 |
| | 1,209 |
| | 3,712 |
| | 3,362 |
|
Total Transmission | $ | 5,673 |
| | $ | 4,800 |
| | $ | 23,150 |
| | $ | 15,740 |
|
| | | | | | | |
Other Sales Margins: | | | | | | | |
Arkansas | $ | 218 |
| | $ | 398 |
| | $ | 880 |
| | $ | 1,688 |
|
Colorado | 208 |
| | 315 |
| | 687 |
| | 770 |
|
Nebraska | 937 |
| | 912 |
| | 2,724 |
| | 2,586 |
|
Iowa | 96 |
| | 96 |
| | 357 |
| | 409 |
|
Kansas | 494 |
| | 595 |
| | 936 |
| | 3,217 |
|
Wyoming | 229 |
| | 234 |
| | 779 |
| | 680 |
|
Total Other Sales Margins | $ | 2,182 |
| | $ | 2,550 |
| | $ | 6,363 |
| | $ | 9,350 |
|
| | | | | | | |
Total Regulated Gross Margin | $ | 93,489 |
| | $ | 94,369 |
| | $ | 363,514 |
| | $ | 313,719 |
|
| | | | | | | |
Non-regulated Services | 4,112 |
| | 5,346 |
| | 21,712 |
| | 22,161 |
|
| | | | | | | |
Total Gross Margin | $ | 97,601 |
| | $ | 99,715 |
| | $ | 385,226 |
| | $ | 335,880 |
|
__________
| |
(a) | Certain prior year revenue classes have been revised to conform to current year presentation. |
| |
(b) | Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class. |
(c) Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year.
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
Gas Utilities Quantities Sold and Transportation (in Dth) (a) | 2017 | 2016 | | 2017 | 2016 |
Residential: | | | | | |
Arkansas | 530,573 |
| 531,564 |
| | 5,058,717 |
| 3,277,167 |
|
Colorado | 1,114,728 |
| 1,067,081 |
| | 9,385,555 |
| 8,012,982 |
|
Nebraska | 747,053 |
| 719,880 |
| | 7,496,171 |
| 7,375,926 |
|
Iowa | 544,429 |
| 478,158 |
| | 6,691,008 |
| 6,744,086 |
|
Kansas | 431,594 |
| 416,971 |
| | 4,066,531 |
| 4,071,723 |
|
Wyoming | 314,567 |
| 335,772 |
| | 3,354,432 |
| 2,951,579 |
|
Total Residential | 3,682,944 |
| 3,549,426 |
| | 36,052,414 |
| 32,433,463 |
|
| | | | | |
Commercial: | | | | | |
Arkansas | 586,224 |
| 526,937 |
| | 3,630,598 |
| 2,377,038 |
|
Colorado | 479,409 |
| 539,304 |
| | 3,700,032 |
| 2,973,962 |
|
Nebraska | 317,867 |
| 384,546 |
| | 2,764,350 |
| 2,800,616 |
|
Iowa | 438,185 |
| 423,084 |
| | 3,729,944 |
| 3,725,512 |
|
Kansas | 284,647 |
| 220,650 |
| | 1,831,946 |
| 1,771,050 |
|
Wyoming | 339,515 |
| 382,503 |
| | 2,454,248 |
| 2,194,570 |
|
Total Commercial | 2,445,847 |
| 2,477,024 |
| | 18,111,118 |
| 15,842,748 |
|
| | | | | |
Industrial: | | | | | |
Arkansas | 304,556 |
| 305,910 |
| | 914,235 |
| 651,815 |
|
Colorado | 234,770 |
| 212,997 |
| | 357,806 |
| 345,126 |
|
Nebraska | 33,050 |
| 29,531 |
| | 64,960 |
| 62,243 |
|
Iowa | 30,136 |
| 52,092 |
| | 225,464 |
| 243,902 |
|
Kansas | 1,931,919 |
| 1,645,891 |
| | 2,483,575 |
| 2,575,314 |
|
Wyoming | 187,742 |
| 185,299 |
| | 644,052 |
| 673,366 |
|
Total Industrial | 2,722,173 |
| 2,431,720 |
| | 4,690,092 |
| 4,551,766 |
|
| | | | | |
Total Quantities Sold | 8,850,964 |
| 8,458,170 |
| | 58,853,624 |
| 52,827,977 |
|
| | | | | |
Transportation: | | | | | |
Arkansas | 2,528,754 |
| 2,225,478 |
| | 8,628,581 |
| 5,774,791 |
|
Colorado | 1,282,746 |
| 668,591 |
| | 5,713,315 |
| 2,267,404 |
|
Nebraska (b) | 13,522,759 |
| 15,123,440 |
| | 42,476,603 |
| 38,723,621 |
|
Iowa | 4,333,161 |
| 4,394,260 |
| | 14,826,265 |
| 14,860,343 |
|
Kansas | 4,622,069 |
| 4,598,060 |
| | 12,593,545 |
| 11,646,066 |
|
Wyoming | 4,287,998 |
| 4,707,013 |
| | 18,076,356 |
| 17,194,446 |
|
Total Transportation | 30,577,487 |
| 31,716,842 |
| | 102,314,665 |
| 90,466,671 |
|
| | | | | |
Total Quantities Sold and Transportation | 39,428,451 |
| 40,175,012 |
| | 161,168,289 |
| 143,294,648 |
|
__________
| |
(a) | Certain prior year revenue classes have been revised to conform to current year presentation. |
Operating Statistics | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold & Transported (Dth) |
| | Three Months Ended March 31, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| | | | | | | | | |
Residential | | $ | 234,397 | | $ | 207,231 | | | $ | 110,148 | | $ | 103,121 | | | 30,568,738 | | 28,230,795 | |
Commercial | | 91,089 | | 80,236 | | | 35,484 | | 33,519 | | | 13,812,321 | | 12,834,803 | |
Industrial | | 4,902 | | 5,200 | | | 1,789 | | 2,043 | | | 898,289 | | 1,061,052 | |
Other | | (472) | | (1,242) | | | (472) | | (1,242) | | | — | | — | |
Total Distribution | | 329,916 | | 291,425 | | | 146,949 | | 137,441 | | | 45,279,348 | | 42,126,650 | |
| | | | | | | | | |
Transportation and Transmission | | 48,161 | | 44,472 | | | 48,161 | | 44,457 | | | 45,314,438 | | 45,055,507 | |
| | | | | | | | | |
Total Regulated | | 378,077 | | 335,897 | | | 195,110 | | 181,898 | | | 90,593,786 | | 87,182,157 | |
| | | | | | | | | |
Non-regulated Services | | 24,442 | | 24,876 | | | 14,359 | | 23,513 | | | | |
| | | | | | | | | |
Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 402,519 | | $ | 360,773 | | | $ | 209,469 | | $ | 205,411 | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth) |
| | Three Months Ended March 31, | | Three Months Ended March 31, | | Three Months Ended March 31, |
| | 2021 | 2020 | | 2021 | 2020 | | 2021 | 2020 |
| | | | | | | | | |
Arkansas Gas | | $ | 86,994 | | $ | 74,845 | | | $ | 51,949 | | $ | 48,855 | | | 13,306,734 | | 10,962,948 | |
Colorado Gas | | 79,122 | | 72,606 | | | 38,212 | | 38,006 | | | 13,366,015 | | 13,096,405 | |
Iowa Gas | | 56,754 | | 54,824 | | | 22,631 | | 21,328 | | | 14,313,973 | | 14,280,273 | |
Kansas Gas | | 40,063 | | 33,494 | | | 18,766 | | 18,603 | | | 10,462,797 | | 9,914,858 | |
Nebraska Gas | | 93,098 | | 83,666 | | | 49,932 | | 51,666 | | | 27,284,101 | | 26,509,036 | |
Wyoming Gas | | 46,488 | | 41,338 | | | 27,979 | | 26,953 | | | 11,860,166 | | 12,418,637 | |
Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 402,519 | | $ | 360,773 | | | $ | 209,469 | | $ | 205,411 | | | 90,593,786 | | 87,182,157 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| |
(b) | Decrease for the three months ended September 30, 2017 is primarily driven by lower irrigation load in 2017 compared to the prior year. |
Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Approximately 70% of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for, and certain expenses of, these operations fluctuate significantly among quarters. Depending upon the geographic location in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.
|
| | | | | | | | | |
| Three Months Ended September 30, |
Degree Days | 2017 | | | | 2016 |
Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Arkansas (a) (d) | 15 | | (66)% | | 67% | | 9 | | (79)% |
Colorado | 187 | | (13)% | | 22% | | 153 | | (29)% |
Nebraska | 66 | | (40)% | | (65)% | | 191 | | 74% |
Iowa | 90 | | (35)% | | 32% | | 68 | | (51)% |
Kansas (a) | 37 | | (32)% | | 42% | | 26 | | (54)% |
Wyoming | 307 | | 1% | | (2)% | | 314 | | 3% |
Combined (b) (d) | 117 | | (22)% | | (20)% | | 146 | | (2)% |
|
| | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, |
Degree Days | 2017 | | | | 2016 |
Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year (c) | | Actual | | Variance from 30-Year Average |
Arkansas (a) (d) | 1,826 |
| | (26 | )% | | 52% | | 1,198 |
| | (52 | )% |
Colorado | 3,541 |
| | (14 | )% | | (4)% | | 3,670 |
| | (6 | )% |
Nebraska | 3,280 |
| | (13 | )% | | (1)% | | 3,312 |
| | (13 | )% |
Iowa | 3,641 |
| | (13 | )% | | (4)% | | 3,783 |
| | (11 | )% |
Kansas (a) | 2,584 |
| | (13 | )% | | —% | | 2,596 |
| | (13 | )% |
Wyoming | 4,468 |
| | (5 | )% | | 3% | | 4,334 |
| | (7 | )% |
Combined (b) (d) | 3,521 |
| | (12 | )% | | 10% | | 3,215 |
| | (20 | )% |
__________
| | | |
(a) | Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and business rate schedules. Kansas Gas has an approved weather normalization mechanism within its residential and business rate structure, which minimizes weather impact on gross margins. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, compared to Kansas, which uses multiple locations. The weather normalization mechanism in Arkansas minimizes weather impact, but does not eliminate the impact. |
| | | | | | | |
(b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas Distribution is partially excluded based on the weather normalization mechanism in effect from November through April. |
| | | | | | | |
(c) | The actual variance in heating degree days for the nine months ended September 30, 2017 compared to prior year is not a reasonable measurement of weather impacts due to the exclusion of the pre-acquisition heating degree days for the SourceGas utilities in Arkansas, Colorado, Nebraska and Wyoming. These utilities were acquired on February 12, 2016. |
| | | | | | | |
(d) | In 2016, the 30-year weather average for Arkansas was calculated on average actual daily temperatures. To conform to current year comparisons to normal, the 2016 variances for Arkansas compared to normal and the 2016 combined variance compared to normal have been updated for both the three and nine months ended September 30, 2016. | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Three Months Ended March 31, |
| 2021 | | | | 2020 |
Heating Degree Days: | Actual | | Variance from Normal | | | | Actual | | Variance from Normal |
Arkansas Gas (a) | 2,121 | | 1% | | | | 1,659 | | (21)% |
Colorado Gas | 2,965 | | 1% | | | | 2,829 | | (3)% |
Iowa Gas | 3,422 | | 1% | | | | 3,181 | | (6)% |
Kansas Gas (a) | 2,576 | | 5% | | | | 2,304 | | (7)% |
Nebraska Gas | 3,097 | | 2% | | | | 2,835 | | (7)% |
Wyoming Gas | 3,425 | | 7% | | | | 3,217 | | 1% |
Combined Gas (b) | 3,186 | | 3% | | | | 2,918 | | (6)% |
__________
(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas is partially excluded based on the weather normalization mechanism in effect from November through April.
Regulatory Matters
For more information on recent regulatory activity and enacted regulatory provisions with respect to the states in which our Utilities operate, see Note 2 of the Notes to Condensed Consolidated Financial Statements and Part I, Items 1 and 2 and Part II, Item 8 of our 20162020 Annual Report on Form 10-K filed with the SEC.10-K.
Electric Utilities Rates and Rate Activity
South Dakota Electric Settlement
On June 16, 2017, South Dakota Electric received approval from the SDPUC 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 suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 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 are being amortized over the moratorium period. These balances were previously being 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:
|
| | | | | | | | |
Subsidiary | Jurisdiction | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Tariff and Rate Matters | Percentage of Power Marketing Profit Shared with Customers |
South Dakota Electric | SD | Global Settlement | 7.76% | Global Settlement | $543.9 | 10/2014 | ECA, TCA, Energy Efficiency Cost Recovery/DSM | 70% |
Colorado Electric Rate Case filing
On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver District Court on July 10, 2017. The briefing schedule runs through November 2017. The timing of a ruling is uncertain.
We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations.
Gas Utilities Rates and Rate Activity
RMNG Rate Review
On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022.
The following table summarizes recent activity of certain state and federal rate reviews, riders and surcharges (dollars in millions):
|
| | | | | | | | | |
| Type of Service | Date Requested | Effective Date | Revenue Amount Requested | Revenue Amount Approved |
Arkansas Stockton Storage (a) | Gas - storage | 11/2016 | 1/2017 | $ | 2.6 |
| $ | 2.6 |
|
Arkansas MRP/ARMRP (b) | Gas | 9/2017 | 9/2017 | $ | 2.7 |
| $ | 2.7 |
|
Kansas Gas (c) | Gas | 5/2017 | 6/2017 | $ | 1.4 |
| $ | 1.4 |
|
RMNG (d) | Gas - transmission and storage | 11/2016 | 1/2017 | $ | 2.9 |
| $ | 2.9 |
|
Nebraska Gas Dist. (e) | Gas | 10/2016 | 2/2017 | $ | 6.5 |
| $ | 6.5 |
|
____________________
| |
(a) | On November 15, 2016, Arkansas Gas filed for the recovery of the Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism with the rider effective January 1, 2017. This recovery mechanism was initially approved on October 15, 2015 for the Stockton Storage acquisition. |
| |
(b) | On September 1, 2017, Arkansas Gas filed for recovery of $2.2 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.5 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates went into effect on the date of the filing. |
| |
(c) | On February 21, 2017, Kansas Gas filed with the KCC requesting recovery of $1.4 million, which includes $0.6 million of new revenue related to the Gas System Reliability Surcharge rider (“GSRS”). This GSRS filing was approved by the KCC on May 23, 2017 and went into effect on June 1, 2017. |
| |
(d) | On November 3, 2016, RMNG filed with the CPUC requesting recovery of $2.9 million, which includes $1.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2017. This SSIR request was approved by the CPUC in December 2016, and went into effect on January 1, 2017. |
| |
(e) | On October 3, 2016, Nebraska Gas Dist. filed with the NPSC requesting recovery of $6.5 million, which includes $1.7 million of new revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2017, and went into effect on February 1, 2017. |
Power Generation
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| (in thousands) |
Revenue (a) | $ | 22,927 |
| $ | 23,337 |
| $ | (410 | ) | $ | 68,289 |
| $ | 68,359 |
| $ | (70 | ) |
| | | | | | |
Operations and maintenance | 7,646 |
| 7,465 |
| 181 |
| 24,228 |
| 24,155 |
| 73 |
|
Depreciation and amortization (a) | 1,036 |
| 996 |
| 40 |
| 3,312 |
| 3,080 |
| 232 |
|
Total operating expense | 8,682 |
| 8,461 |
| 221 |
| 27,540 |
| 27,235 |
| 305 |
|
| | | | | | |
Operating income | 14,245 |
| 14,876 |
| (631 | ) | 40,749 |
| 41,124 |
| (375 | ) |
| | | | | | |
Interest expense, net | (724 | ) | (409 | ) | (315 | ) | (2,015 | ) | (1,343 | ) | (672 | ) |
Other (expense) income, net | (5 | ) | (9 | ) | 4 |
| (36 | ) | (5 | ) | (31 | ) |
Income tax (expense) benefit | (3,426 | ) | (5,046 | ) | 1,620 |
| (10,114 | ) | (13,467 | ) | 3,353 |
|
| | | | | | |
Net income | 10,090 |
| 9,412 |
| 678 |
| 28,584 |
| 26,309 |
| 2,275 |
|
Net income attributable to noncontrolling interest | (3,935 | ) | (3,770 | ) | (165 | ) | (10,567 | ) | (6,402 | ) | (4,165 | ) |
Net income available for common stock | $ | 6,155 |
| $ | 5,642 |
| $ | 513 |
| $ | 18,017 |
| $ | 19,907 |
| $ | (1,890 | ) |
____________
| |
(a) | The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes. |
On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock for the three and nine months ended September 30, 2017, was reduced by $3.9 million and $11 million, respectively, and reduced by $3.8 million and $6.4 million for the three and nine months ended September 30, 2016, respectively, attributable to this noncontrolling interest.
Results of Operations forOur Power Generation for the segment operating results were as follows (in thousands):
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | | | 2021 | 2020 | Variance |
| | | | |
Revenue | | | | $ | 29,163 | | $ | 25,966 | | $ | 3,197 | |
| | | | | | |
Fuel expense | | | | 2,671 | | 2,285 | | 386 | |
Operations and maintenance | | | | 7,358 | | 6,997 | | 361 | |
Depreciation and amortization | | | | 4,865 | | 5,335 | | (470) | |
Total operating expense | | | | 14,894 | | 14,617 | | 277 | |
| | | | | | |
Adjusted operating income | | | | $ | 14,269 | | $ | 11,349 | | $ | 2,920 | |
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended March 31, 2020:
Operating income increased $1.7 million due to Winter Storm Uri’s favorable impact to Black Hills Wyoming under the economy energy PSA. Revenue also increased due to higher Wygen I MWh sold driven by a prior year planned outage.
Operating Statistics | | | | | | | | | | | | | | | | | |
| Revenue (in thousands) | | Quantities Sold (MWh) (a) |
Three Months Ended March 31, | 2021 | 2020 | | 2021 | 2020 |
Black Hills Colorado IPP | $ | 14,254 | | $ | 14,179 | | | 239,194 | | 265,225 | |
Black Hills Wyoming (b) | 13,433 | | 10,158 | | | 164,957 | | 156,352 | |
Black Hills Electric Generation | 1,476 | | 1,629 | | | 96,294 | | 97,279 | |
Total Power Generation Revenue and Quantities Sold | $ | 29,163 | | $ | 25,966 | | | 500,445 | | 518,856 | |
| | | | | | | | | | | | | | |
| | | | Three Months Ended March 31, |
Quantities Generated and Purchased (MWh) (a) | Fuel Type | | | | 2021 | 2020 |
Generated | | | | | | |
Black Hills Colorado IPP | Natural Gas | | | | 239,194 | | 265,225 | |
Black Hills Wyoming (b) | Coal | | | | 136,104 | | 126,485 | |
Black Hills Electric Generation | Wind | | | | 96,294 | | 97,279 | |
Total Generated | | | | | 471,592 | | 488,989 | |
| | | | | | |
Purchased | | | | | | |
Black Hills Wyoming (b) | Various | | | | 29,567 | | 29,856 | |
Total Purchased | | | | | 29,567 | | 29,856 | |
____________
(a) Company uses and losses are not included in the quantities sold, generated, and purchased.
(b) Under the 20-year economy energy PSA with the City of Gillette effective September 30, 2016: Net2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement that Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
| | | | | | | | | | | |
| | | Three Months Ended March 31, |
Contracted generating facilities availability by fuel type (a) | | | | 2021 | 2020 |
| | | | | |
Coal (b) | | | | 97.0 | % | 89.3 | % |
Natural gas | | | | 98.6 | % | 99.5 | % |
Wind | | | | 94.2 | % | 99.3 | % |
Total availability | | | | 96.7 | % | 97.8 | % |
| | | | | |
Wind capacity factor | | | | 32.6 | % | 30.4 | % |
____________________
(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2020 included a planned outage at Wygen I.
Mining
Our Mining segment operating results were as follows (in thousands):
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | | | 2021 | 2020 | Variance |
| | | | |
Revenue | | | | $ | 14,672 | | $ | 15,205 | | $ | (533) | |
| | | | | | |
Operations and maintenance | | | | 9,197 | | 9,826 | | (629) | |
Depreciation, depletion and amortization | | | | 2,214 | | 2,250 | | (36) | |
Total operating expenses | | | | 11,411 | | 12,076 | | (665) | |
| | | | | | |
Adjusted operating income | | | | $ | 3,261 | | $ | 3,129 | | $ | 132 | |
Three Months Ended March 31, 2021 Compared to the Three Months Ended March 31, 2020:
Adjusted operating income available for common stock for the Power Generation segment was $6.2 million for the three months ended September 30, 2017, compared to Net income available for common stock of $5.6 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year. The variance to the prior year was driven by a lower 2017 effective tax rate compared to 2016 due to the greater impact of minority interest and higher 2016 adjustments to the filed tax return.
Results of Operations for Power Generation for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Power Generation segment was $18 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $20 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year. The variance to the prior year was due to Black Hills Colorado IPP going from a single member LLC, wholly owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. Net income attributable to noncontrolling interest also increased by $4.2 million as a result of the noncontrolling interest sale in April 2016.Operating Statistics
The following table summarizes MWh for our Power Generation segment:
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Quantities Sold, Generated and Purchased (MWh) (a) | | | | | |
Sold | | | | | |
Black Hills Colorado IPP (b) | 256,895 |
| 327,793 |
| | 725,919 |
| 972,113 |
|
Black Hills Wyoming (c) | 163,690 |
| 167,670 |
| | 476,659 |
| 476,677 |
|
Total Sold | 420,585 |
| 495,463 |
| | 1,202,578 |
| 1,448,790 |
|
| | | | | |
Generated | | | | | |
Black Hills Colorado IPP (b) | 256,895 |
| 327,793 |
| | 725,919 |
| 972,113 |
|
Black Hills Wyoming (c) | 140,081 |
| 142,388 |
| | 407,775 |
| 401,292 |
|
Total Generated | 396,976 |
| 470,181 |
| | 1,133,694 |
| 1,373,405 |
|
| | | | | |
Purchased | | | | | |
Black Hills Colorado IPP | — |
| — |
| | — |
| — |
|
Black Hills Wyoming (c) | 20,246 |
| 23,558 |
| | 52,463 |
| 68,797 |
|
Total Purchased | 20,246 |
| 23,558 |
| | 52,463 |
| 68,797 |
|
____________
| |
(a) | Company uses and losses are not included in the quantities sold, generated, and purchased. |
| |
(b) | Decrease from the prior year is a result of the 2017 impact of Colorado Electric’s wind generation replacing natural-gas generation. |
| |
(c) | Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances. |
The following table provides certain operating statistics for our plants within the Power Generation segment:
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Contracted power plant fleet availability: | | | | | |
Coal-fired plant | 97.1 | % | 98.7 | % | | 95.8 | % | 94.1 | % |
Natural gas-fired plants | 99.2 | % | 99.1 | % | | 99.1 | % | 99.2 | % |
Total availability | 98.7 | % | 99.0 | % | | 98.3 | % | 97.9 | % |
Mining
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| (in thousands) |
Revenue | $ | 17,493 |
| $ | 16,820 |
| $ | 673 |
| $ | 48,985 |
| $ | 44,149 |
| $ | 4,836 |
|
| | | | | | |
Operations and maintenance | 11,235 |
| 10,465 |
| 770 |
| 32,162 |
| 29,186 |
| 2,976 |
|
Depreciation, depletion and amortization | 2,004 |
| 2,342 |
| (338 | ) | 6,231 |
| 7,269 |
| (1,038 | ) |
Total operating expenses | 13,239 |
| 12,807 |
| 432 |
| 38,393 |
| 36,455 |
| 1,938 |
|
| | | | | | |
Operating income | 4,254 |
| 4,013 |
| 241 |
| 10,592 |
| 7,694 |
| 2,898 |
|
| | | | | | |
Interest (expense) income, net | (47 | ) | (100 | ) | 53 |
| (146 | ) | (283 | ) | 137 |
|
Other income, net | 567 |
| 559 |
| 8 |
| 1,644 |
| 1,625 |
| 19 |
|
Income tax benefit (expense) | (1,297 | ) | (1,165 | ) | (132 | ) | (3,042 | ) | (2,067 | ) | (975 | ) |
| | | | | | |
Net income | $ | 3,477 |
| $ | 3,307 |
| $ | 170 |
| $ | 9,048 |
| $ | 6,969 |
| $ | 2,079 |
|
The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
| | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | 2021 | 2020 |
Tons of coal sold | | | | 875 | | 896 | |
Cubic yards of overburden moved | | | | 1,822 | | 2,267 | |
| | | | | |
Revenue per ton | | | | $ | 16.09 | | $ | 16.08 | |
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Tons of coal sold | 1,151 |
| 1,106 |
| | 3,127 |
| 2,722 |
|
Cubic yards of overburden moved (a) | 2,316 |
| 2,065 |
| | 6,381 |
| 5,516 |
|
| | | | | |
Revenue per ton | $ | 15.20 |
| $ | 15.20 |
| | $ | 15.67 |
| $ | 16.21 |
|
____________
| |
(a) | Increase is driven by mining in areas with more overburden than in the prior year as well as higher production. |
Corporate and Other
Corporate and Other operating results were as follows (in thousands):
Results of Operations for Mining for the | | | | | | | | | | | | | | |
| | Three Months Ended March 31, |
| | | | 2021 | 2020 | Variance |
| | | | |
Adjusted operating income (loss) | | | | $ | (3,122) | | $ | 160 | | $ | (3,282) | |
Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: NetMarch 31, 2020:
The variance in Adjusted operating income available for common stock for the Mining segment(loss) was $3.5 million for the three months ended September 30, 2017, compared to Net income available for common stock of $3.3 million for the same period in 2016 as a result of:
Revenue increased due to a 4% increase in tons sold, with comparable pricing to the same period last year. The increased tons sold were driven primarily by Wyodak plant generating requirements. During the current period, approximately 47% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operations and maintenance increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.
Depreciation, depletion and amortization decreased primarily due to a reduction in asset retirement obligation costs.
Interest (expense) income, netprior year favorable true-up of employee costs which was comparableallocated to the same periodour subsidiaries in the priorcurrent year. This allocation was offset in our reportable segments and had no impact to consolidated results.
Consolidated Interest Expense, Impairment of Investment, Other income, net was comparable to the same period in the prior year.Income (Expense) and Income Tax (Expense)
Income tax benefit (expense): The effective tax rate is comparable to the same period last year. | | | | | | | | | | | |
| Three Months Ended March 31, |
| 2021 | 2020 | Variance |
| (in thousands) |
Interest expense, net | $ | (37,600) | | $ | (35,453) | | $ | (2,147) | |
Impairment of investment | — | | (6,859) | | $ | 6,859 | |
Other income (expense), net | 266 | | 2,353 | | $ | (2,087) | |
Income tax (expense) | (494) | | (16,002) | | $ | 15,508 | |
Results of Operations for Mining for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net income available for common stock for the Mining segment was $9.0 million for the nine months ended September 30, 2017, compared to Net income available for common stock of $7.0 million for the same period in 2016 as a result of:
Revenue increased due to a 15% increase in tons sold, partially offset by a 3% decrease in price per ton sold. The increased tons sold were driven primarily by an 11-week outage at the Wyodak plant in the prior year. The decrease in price per ton sold was driven by higher volumes sold under fixed price contracts. During the current period, approximately 46% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operations and maintenance increased primarily due to increased overburden removal and higher royalties and production taxes on increased revenues.
Depreciation, depletion and amortization decreased primarily due to lower asset retirement obligation costs and lower plant in service.
Interest (expense) income, net was comparable to the same period in the prior year.
Other income, net was comparable to the same period in the prior year.
Income tax benefit (expense): The effective tax rate increased reflecting a prior year tax benefit of percentage depletion.
Oil and Gas
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| (in thousands) |
Revenue | $ | 6,527 |
| $ | 9,639 |
| $ | (3,112 | ) | $ | 19,151 |
| $ | 25,660 |
| $ | (6,509 | ) |
| | | | | | |
Operations and maintenance | 6,076 |
| 7,592 |
| (1,516 | ) | 20,385 |
| 24,539 |
| (4,154 | ) |
Depreciation, depletion and amortization | 2,391 |
| 3,483 |
| (1,092 | ) | 6,300 |
| 11,415 |
| (5,115 | ) |
Impairment of long-lived assets | — |
| 12,293 |
| (12,293 | ) | — |
| 52,286 |
| (52,286 | ) |
Total operating expenses | 8,467 |
| 23,368 |
| (14,901 | ) | 26,685 |
| 88,240 |
| (61,555 | ) |
| | | | | | |
Operating (loss) | (1,940 | ) | (13,729 | ) | 11,789 |
| (7,534 | ) | (62,580 | ) | 55,046 |
|
| | | | | | |
Interest income (expense), net | (1,269 | ) | (1,295 | ) | 26 |
| (3,459 | ) | (3,529 | ) | 70 |
|
Other income (expense), net | (3 | ) | 16 |
| (19 | ) | 14 |
| 85 |
| (71 | ) |
Income tax benefit (expense) | 500 |
| 6,180 |
| (5,680 | ) | 3,370 |
| 30,747 |
| (27,377 | ) |
| | | | | | |
Net (loss) | $ | (2,712 | ) | $ | (8,828 | ) | $ | 6,116 |
| $ | (7,609 | ) | $ | (35,277 | ) | $ | 27,668 |
|
Results of Operations for Oil and Gas for the Three Months Ended September 30, 2017March 31, 2021 Compared to the Three Months Ended September 30, 2016: Net loss availableMarch 31, 2020.
Interest Expense
The increase in Interest expense, net was due to higher debt balances driven by the February 2021 term loan and the June 2020 senior unsecured notes partially offset by lower interest rates.
Impairment of Investment
In the prior year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company.
Other Income (Expense)
The decrease in Other income was primarily due to prior year credits for common stock for the Oil and Gas segment was $(2.7) million forour non-qualified benefit plan driven by market performance on plan assets.
Income Tax (Expense)
For the three months ended September 30, 2017,March 31, 2021, the effective tax rate was 0.5% compared to Net loss available for common stock of $(8.8) million14.1% for the same period in 2016 as a result of:
Revenue decreased primarily due to a 9% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties, and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016.2020. The average hedged price received for crude oil sold decreased 11%. The average hedged price received for natural gas sold decreased by 15%.
Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.
Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.
Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The prior year ceiling test write-down of $12 million used a trailing 12 month average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.
Interest income (expense), net was comparable to the same period last year.
Other income (expense), net was comparable to the same period in the prior year.
Income tax (expense) benefit: Each period represents a tax benefit. The current period effective tax rate is lower due primarily to a reduction to the marginal well credit compared to the same period last year.
Results of Operations for Oil and Gas for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for the Oil and Gas segment was $(7.6) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(35) million for the same period in 2016 as a result of:
Revenue decreased primarily due to a 17% production decrease compared$7.6 million of increased tax benefits from Colorado Electric’s TCJA-related bill credits to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 14%. The lower production volumes and crude oil pricing were partiallycustomers (which is offset by a 21% increase in the average hedged price received for natural gas sold.
Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.
Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.
Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The prior year write down of $52 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $38 million. The ceiling test write-down for the nine months ended September 30, 2016 used an average NYMEX natural gas price of $2.28 per Mcf, adjusted to $1.03 per Mcf at the well head, and $41.68 per barrel for crude oil, adjusted to $35.88 per barrel at the wellhead.
Interest income (expense), net was comparable to the same period last year.
Other income (expense), net was comparable to the same period in the prior year.
Income tax (expense) benefit: Each period represents a tax benefit. The effective tax rate for the nine months ended September 30, 2016 reflects a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respect to a change in estimate for tax purposes. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.
The following tables provide certain operating statistics for our Oil and Gas segment:
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Production: | | | | | |
Bbls of oil sold | 45,240 |
| 89,569 |
| | 139,642 |
| 263,788 |
|
Mcf of natural gas sold | 2,379,189 |
| 2,426,892 |
| | 6,392,999 |
| 7,148,952 |
|
Bbls of NGL sold | 30,810 |
| 27,640 |
| | 82,539 |
| 105,535 |
|
Mcf equivalent sales | 2,835,487 |
| 3,130,147 |
| | 7,726,083 |
| 9,364,891 |
|
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | 2016 | | 2017 | 2016 |
Average price received: (a) | | | | | |
Oil/Bbl | $ | 50.22 |
| $ | 56.64 |
| | $ | 46.95 |
| $ | 54.38 |
|
Gas/Mcf | $ | 1.39 |
| $ | 1.63 |
| | $ | 1.55 |
| $ | 1.28 |
|
NGL/Bbl | $ | 21.79 |
| $ | 11.31 |
| | $ | 19.99 |
| $ | 10.95 |
|
| | | | | |
Depletion expense/Mcfe | $ | 0.52 |
| $ | 0.81 |
| | $ | 0.46 |
| $ | 0.86 |
|
__________
| |
(a) | Net of hedge settlement gains and losses. |
The following is a summary of certain average operating expenses per Mcfe:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Three Months Ended September 30, 2016 |
Producing Basin | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total |
San Juan | $ | 1.60 |
| $ | 1.04 |
| $ | 0.36 |
| $ | 3.00 |
| | $ | 1.69 |
| $ | 1.19 |
| $ | 0.38 |
| $ | 3.26 |
|
Piceance | 0.20 |
| 1.65 |
| 0.06 |
| 1.91 |
| | 0.24 |
| 1.84 |
| 0.16 |
| 2.24 |
|
Powder River | 1.78 |
| — |
| 0.68 |
| 2.46 |
| | 1.89 |
| — |
| 0.20 |
| 2.09 |
|
Williston | — |
| — |
| — |
| — |
| | 0.84 |
| — |
| 1.64 |
| 2.48 |
|
All other properties | 1.00 |
| — |
| 0.28 |
| 1.28 |
| | 0.30 |
| — |
| 0.22 |
| 0.52 |
|
Total weighted average | $ | 0.75 |
| $ | 1.25 |
| $ | 0.22 |
| $ | 2.22 |
| | $ | 0.84 |
| $ | 1.19 |
| $ | 0.33 |
| $ | 2.36 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
Producing Basin | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total |
San Juan | $ | 1.67 |
| $ | 1.11 |
| $ | 0.38 |
| $ | 3.16 |
| | $ | 1.65 |
| $ | 1.11 |
| $ | 0.31 |
| $ | 3.07 |
|
Piceance | 0.42 |
| 1.83 |
| 0.05 |
| 2.30 |
| | 0.31 |
| 1.86 |
| 0.13 |
| 2.30 |
|
Powder River | 2.30 |
| — |
| 0.72 |
| 3.02 |
| | 2.52 |
| — |
| 0.45 |
| 2.97 |
|
Williston | — |
| — |
| — |
| — |
| | 1.22 |
| — |
| 1.02 |
| 2.24 |
|
All other properties | 1.39 |
| — |
| 0.30 |
| 1.69 |
| | 0.37 |
| — |
| 0.12 |
| 0.49 |
|
Total weighted average | $ | 1.03 |
| $ | 1.34 |
| $ | 0.23 |
| $ | 2.60 |
| | $ | 1.00 |
| $ | 1.18 |
| $ | 0.27 |
| $ | 2.45 |
|
__________
| |
(a) | These costs include both third-party costs and operations costs. |
In the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, for which we incur processing, gathering, compression and transportation fees. The sales price for natural gas, condensate and NGLs is reduced for these third-party costs, while the cost of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paid to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.
We have a ten-year gas gathering and processing contract for our natural gas production in the Piceance Basin which became effective in March of 2014. This take-or-pay contract requires us to pay a fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the table above, will be higher in periods when we are not meeting the minimum contract requirements.
Corporate Activity
Results of Operations for Corporate activities for the Three Months Ended September 30, 2017 Compared to the Three Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.3) million for the three months ended September 30, 2017, compared to Net loss available for common stock of $(7.2) million for the three months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. The third quarter of 2017 included approximately $0.2 million of non-recurring after-tax acquisition and transition costs compared to approximately $4.0 million of after-tax non-recurring acquisition and transition costs in the third quarter of 2016. The third quarter of 2016 included $1.7 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments and also included lower income tax expense compared to the third quarter of 2017.
Results of Operations for Corporate activities for the Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016: Net loss available for common stock for Corporate was $(2.9) million for the nine months ended September 30, 2017, compared to Net loss available for common stock of $(29) million for the nine months ended September 30, 2016. The variance from the prior year was primarily due to higher corporate expenses incurred in the prior year related to the SourceGas Acquisition. Current year corporate expenses included approximatelyrevenue), $1.5 million of after-tax non-recurring acquisitionincreased tax benefits from amortization of excess deferred income taxes and transition costs, compared to a total of approximately $24$1.3 million of after-tax non-recurring acquisitionincreased tax benefits from federal production tax credits associated with new wind assets.
Liquidity and transition costs and approximately $7.4 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments. During the nine months ended September 30, 2017, we recognized a tax benefit of approximately $1.4 million tax benefit from a carryback claim for specified liability losses involving prior years. The same period in the prior year included a tax benefit of approximately $4.4 million recognized as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.Capital Resources
Critical Accounting Estimates
There have been no material changes in our critical accounting estimatesLiquidity and Capital Resources from those reported in Item 7 of our 20162020 Annual Report on Form 10-K filed withexcept as described below.
For the SEC. For more information onthree months ended March 31, 2021, we did not experience significant impacts to our critical accounting estimates, see Part II, Item 7 ofliquidity or financial condition due to the COVID-19 pandemic.
In response to the February 2021 Winter Storm Uri, we took steps to maintain adequate liquidity to operate our 2016 Annual Report on Form 10-K.
Liquiditybusinesses and Capital Resources
OVERVIEW
Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate.
The most significant uses of cash arefund our capital
expenditures,investment program as discussed in the
purchase of natural gas for our Gas UtilitiesRecent Developments above and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak monthsin further detail in Note 5 of the winter heating season dueNotes to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.Condensed Consolidated Financial Statements.
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
Significant Factors Affecting Liquidity
Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At September 30, 2017, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Cash Flow Activities
The following table summarizes our cash flows for the ninethree months ended September 30March 31, (in thousands):
| | | | | | | | | | | |
Cash provided by (used in): | 2021 | 2020 | Variance |
Operating activities | $ | (386,086) | | $ | 191,969 | | $ | (578,055) | |
Investing activities | $ | (146,224) | | $ | (173,084) | | $ | 26,860 | |
Financing activities | $ | 539,496 | | $ | 25,621 | | $ | 513,875 | |
|
| | | | | | | | | |
Cash provided by (used in): | 2017 | 2016 | Increase (Decrease) |
Operating activities | $ | 319,430 |
| $ | 209,201 |
| $ | 110,229 |
|
Investing activities | $ | (256,388 | ) | $ | (1,459,196 | ) | $ | 1,202,808 |
|
Financing activities | $ | (63,112 | ) | $ | 840,948 |
| $ | (904,060 | ) |
Year-to-Date 2017Three Months Ended March 31, 2021 Compared to Year-to-Date 2016Three Months Ended March 31, 2020
Operating ActivitiesActivities:
Net cash provided by operating activities was $319$578 million for the nine months ended September 30, 2017, compared to net cash provided by operating activities of $209 million forlower than the same period in 2016 for a2020. The variance of $110 million. The varianceto the prior year was primarily attributable to:
•Cash earnings (net income plus non-cash adjustments) were $65$15 million higherlower for the ninethree months ended September 30, 2017March 31, 2021 compared to the same period in the prior year;year primarily driven by lower operating income at our Electric Utilities;
•Net cash outflowsinflows from changes in certain operating assets and liabilities were $17$563 million for the nine months ended September 30, 2017, compared to net cashlower, primarily attributable to:
◦Cash outflows of $44 million in the same period in the prior year. This $27 million variance was primarily due to:
| |
◦ | Cash outflows decreased due to an increase in cash inflows of approximately $14 million for the nine months ended September 30, 2017 primarily as a result of changes in our accounts receivable, partially offset by higher natural gas in storage for the nine months ended September 30, 2017 compared to the same period in the prior year; |
| |
◦ | Cash outflows decreased by approximately $16 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements, primarily related to acquisition and transaction costs that took place in the prior year; |
| |
◦ | Cash outflows increased by approximately $3.3 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts on working capital compared to the same period in the prior year; |
Net cash outflows decreased by approximately $29$560 million as a result of changes in our regulatory assets and liabilities primarily driven by incremental costs from Winter Storm Uri;
◦Cash inflows decreased by $23 million primarily as a prior year interest rate settlement;result of changes in natural gas in storage and lower collections of accounts receivable; and
◦Cash outflows decreased by $20 million as a result of increases in accounts payable and accrued liabilities primarily driven by payment timing of natural gas and power purchases and other working capital requirements.
Net cash outflows•Cash inflows increased by $14$0.8 million due to additional pension contributions made in the current year.for other operating activities.
Investing ActivitiesActivities:
Net cash used in investing activities was $256$27 million for the nine months ended September 30, 2017, compared to net cash used in investing activities of $1.5 billion forlower than the same period in 2016 for a variance of $1.2 billion. This variance was primarily due to:
The prior year’s cash outflows included $1.124 billion for the acquisition of SourceGas, net of $760 million of long term debt assumed (see Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details); and
Capital expenditures of approximately $256 million for the nine months ended September 30, 2017 compared to $334 million for the nine months ended September 30, 2016.2020. The variance to the prior year was due primarily attributable to:
•Capital expenditures of $146 million for the three months ended March 31, 2021 compared to higher$172 million for the same period in the prior year. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities and Electric Utilities segments and the prior year capital expendituresCorriedale wind project at our Electric Utilities primarily from generation investments at Colorado Electric, partially offsetsegment.
•Cash outflows decreased by higher current year capital expenditures at our Gas Utilities.$1.3 million for other investing activities.
Financing ActivitiesActivities:
Net cash used in financing activities for the nine months ended September 30, 2017 was $63 million, compared to $841 million of net cash provided by financing activities forwas $514 million higher than the same period in 2016 for a2020. The variance to the prior year was primarily attributable to:
•Cash inflows increased $615 million due to borrowings of $904 million.short-term debt in excess of short-term and long-term debt repayments. This varianceincrease was primarily driven by:by $600 million net borrowings from our term loan;
Long-term borrowings•Cash inflows decreased by $1.8 billion$99 million due to the 2016 financings which consistedprior year issuance of $693common stock;
•Cash outflows increased $2.6 million due to increased dividends paid on common stock; and
•Cash outflows decreased by $0.7 million for other financing activities.
Capital Sources
Term Loan
See Note 5 of the Notes to Condensed Consolidated Financial Statements for information relating to our term loan.
Revolving Credit Facility and CP Program
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
| | | | | | | | | | | | | | | | | |
| | Current | Short-term borrowings at | Letters of Credit (a) at | Available Capacity at |
Credit Facility | Expiration | Capacity | March 31, 2021 | March 31, 2021 | March 31, 2021 |
Revolving Credit Facility and CP Program | July 30, 2023 | $ | 750 | | $ | 216 | | $ | 17 | | $ | 517 | |
__________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.
The weighted average interest rate on short-term borrowings related to our Revolving Credit Facility and CP Program at March 31, 2021 was 0.23%. Short-term borrowing activity related to our Revolving Credit Facility and CP Program for the three months ended March 31, 2021 was:
| | | | | |
| (dollars in millions) |
Maximum amount outstanding (based on daily outstanding balances) | $ | 311 | |
Average amount outstanding (based on daily outstanding balances) | $ | 199 | |
Weighted average interest rates | 0.24 | % |
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of March 31, 2021 See Note 5 of the Notes to Condensed Consolidated Financial Statements for more information.
Future Financing Plans
We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of net proceeds fromcommon stock under the August 19, 2016 public debt offering used to refinance the debt assumedATM. As discussed in the SourceGas Acquisition, $500 millionRecent Developments above and in further detail in Note 5 of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering usedNotes to partially finance the SourceGas Acquisition and proceeds from a $29Condensed Consolidated Financial Statements, on February 24, 2021, we entered into an $800 million term loan usedmaturing on November 24, 2021. We expect to fundrefinance a portion of the early settlementterm loan with longer-term debt.
Credit Ratings
Payments on long-term debt decreased by $1.1 billion due
After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the 2016 refinancingcapital markets at prevailing market rates for companies with comparable credit ratings.
The following table represents the credit ratings and outlook and risk profile of BHC at March 31, 2021:
| | | | | | | | |
Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
__________
(a) On April 10, 2020, S&P reported BBB+ rating and maintained a Stable outlook.
(b) On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c) On August 20, 2020, Fitch reported BBB+ rating and maintained a Stable outlook.
The following table represents the $760 millioncredit ratings of long-term debt assumedSouth Dakota Electric at March 31, 2021:
| | | | | |
Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s (b) | A1 |
Fitch (c) | A |
__________
(a) On April 16, 2020, S&P reported A rating.
(b) On December 21, 2020, Moody’s reported A1 rating.
(c) On August 20, 2020, Fitch reported A rating.
Capital Requirements
Capital Expenditures
| | | | | | | | | | | | | | | | | | | | | | | |
| Actual | | Forecasted |
Capital Expenditures by Segment | Three Months Ended March 31, 2021 (a) | | 2021 (b) | 2022 | 2023 | 2024 | 2025 |
(in millions) | | | | | | | |
Electric Utilities | $ | 52 | | | $ | 240 | | $ | 180 | | $ | 143 | | $ | 156 | | $ | 154 | |
Gas Utilities | 73 | | | 377 | | 347 | | 339 | | 330 | | 326 | |
Power Generation | 3 | | | 10 | | 9 | | 6 | | 4 | | 5 | |
Mining | 1 | | | 9 | | 9 | | 9 | | 9 | | 10 | |
Corporate and Other | 3 | | | 11 | | 5 | | 13 | | 13 | | 13 | |
Incremental Projects (c) | — | | | — | | 50 | | 100 | | 100 | | 100 | |
| $ | 132 | | | $ | 647 | | $ | 600 | | $ | 610 | | $ | 612 | | $ | 608 | |
__________
(a) Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the SourceGas Acquisition and lower current year payments on term loans, $104 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016.
(b) Includes actual capital expenditures for the three months ended March 31, 2021.
Net short-term borrowings increased(c) These represent projects that are being evaluated by $130 million primarily due to CP borrowings used to pay down long-term debt;our segments for timing, cost and other factors.
Proceeds from common stock decreased by approximately $104 million due to prior year stock issuances under our ATM equity offering program;
Distributions to noncontrolling interests increased by $8.4 million compared to the prior year;
Increased dividend payments of approximately $6.1 million; and
Lower other financing activities of approximately $10 million driven primarily by higher financing costs incurred in the prior year from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017.
Dividends
Dividends paid on our common stock totaled $71$36 million for the ninethree months ended September 30, 2017,March 31, 2021, or $0.445$0.565 per share per quarter. On November 1, 2017,April 26, 2021, our board of directors declared a quarterly dividend of $0.475$0.565 per share payable DecemberJune 1, 2017, which brings our total2021, equivalent to an annual dividend for 2017 to $1.81of $2.26 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.
Debt
Financing Transactions and Short-Term Liquidity
Our principal sources to meet day-to-day operating cash requirements are cash from operations, our CP Program and our corporate Revolving Credit Facility.
Revolving Credit Facility and CP Program
On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021 with two one-year extension options. This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consentTable of the administrative agent and issuing agents, to increase total commitments of the facility to up to $1 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at September 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.
On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.
Our Revolving Credit Facility had the following borrowings, outstanding letters of credit, and available capacity (in millions):
|
| | | | | | | | | | | | | | | | |
| | Current | Revolver Borrowings at | CP Program Borrowings at | Letters of Credit at | Available Capacity at |
Credit Facility | Expiration | Capacity | September 30, 2017 | September 30, 2017 | September 30, 2017 | September 30, 2017 |
Revolving Credit Facility | August 9, 2021 | $ | 750 |
| $ | — |
| $ | 225 |
| $ | 25 |
| $ | 500 |
|
The weighted average interest rate on CP Program borrowings at September 30, 2017 was 1.46%. Revolving Credit Facility and CP Program financing activity for the nine months ended September 30, 2017 was (dollars in millions):
|
| | | |
| For the Nine Months Ended September 30, 2017 |
Maximum amount outstanding - commercial paper (based on daily outstanding balances) | $ | 238 |
|
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | 97 |
|
Average amount outstanding - commercial paper (based on daily outstanding balances) (a) | $ | 107 |
|
Average amount outstanding - revolving credit facility (based on daily outstanding balances) (a) | $ | 55 |
|
Weighted average interest rates - commercial paper (a) | 1.28 | % |
Weighted average interest rates - revolving credit facility (a) | 2.07 | % |
__________
| |
(a) | Averages for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program. |
The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of September 30, 2017.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
Financing Activities
Financing activities for the nine months ended September 30, 2017 consisted of short-term borrowings from our Revolving Credit Facility and CP Program. We also made principal payments of $50 million each on May 16, 2017 and July 17, 2017 on our Corporate term loan due August 9, 2019. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. On August 4, 2017, we renewed the ATM equity offering program initiated in 2016 which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program.
Financing activities from the prior year consisted of completing the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued a total of 1.97 million shares of common stock throughout 2016 for net proceeds of approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million in April 2016.
Future Financing Plans
We anticipate the following financing activities:
Remarketing the junior subordinated notes maturing in 2018;
Evaluating a one-to-two year extension of our Revolving Credit Facility and CP program to be completed in 2018; and
Evaluating refinancing options for term loan and short-term borrowings under our Revolving Credit Facility and CP program.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of September 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The only financial covenant under our Revolving Credit Facility and existing term loans is a Consolidated Indebtedness to Capitalization Ratio, which requires us to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 at the end of any fiscal quarter. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Additionally, covenants within Cheyenne Light’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2017, we were in compliance with these covenants.
There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2016 Annual Report on Form 10-K filed with the SEC.
Credit Ratings
Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings and outlook and risk profile of BHC at September 30, 2017:
|
| | |
Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a)
| BBB | Stable |
Moody’s (b)
| Baa2 | Stable |
Fitch (c)
| BBB+ | Stable |
__________
| |
(a) | On July 21, 2017, S&P affirmed BBB rating and maintained a Stable outlook. |
| |
(b) | On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition. |
| |
(c) | On October 4, 2017, Fitch affirmed BBB+ rating and maintained a Stable outlook. |
The following table represents the credit ratings of Black Hills Power at September 30, 2017:
|
| |
Rating Agency | Senior Secured Rating |
S&P | A- |
Moody’s | A1 |
Fitch | A |
There were no rating changes for Black Hills Power from previously disclosed ratings.
Capital Requirements
Capital Expenditures
Actual and forecasted capital requirements are as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| Expenditures for the | | Total | | Total | | Total |
| Nine Months Ended September 30, 2017 (a) | | 2017 Planned Expenditures (b) | | 2018 Planned Expenditures | | 2019 Planned Expenditures |
Electric Utilities | $ | 113,199 |
| | $ | 134,000 |
| | $ | 149,000 |
| | $ | 193,000 |
|
Gas Utilities | 122,482 |
| | 187,000 |
| | 263,000 |
| | 279,000 |
|
Power Generation | 1,899 |
| | 1,000 |
| | 2,000 |
| | 14,000 |
|
Mining | 4,315 |
| | 7,000 |
| | 7,000 |
| | 7,000 |
|
Oil and Gas (c) | 16,951 |
| | 21,000 |
| | — |
| | — |
|
Corporate | 5,075 |
| | 7,000 |
| | 9,000 |
| | 13,000 |
|
| $ | 263,921 |
| | $ | 357,000 |
| | $ | 430,000 |
| | $ | 506,000 |
|
__________
(a) Expenditures for the nine months ended September 30, 2017 include the impact of accruals for property, plant and equipment.
(b) Includes actual capital expenditures for the nine months ended September 30, 2017.
| |
(c) | Expenditures reflect the completion of two wells previously drilled in 2015 to meet minimum daily quantity requirements for the Piceance Basin gathering and processing contract. |
We have updated our planned 2018 and 2019 capital expenditures to primarily reflect the following:
additional planned transmission and distribution investments at our Electric Utilities in 2018 and 2019; and
additional planned growth and integrity investments in our Gas utilities, primarily as a result of gaining further knowledge of the SourceGas utilities.
We continue to evaluate potential future acquisitions and other growth opportunities when they arise. As a result, capital expenditures may vary significantly from the estimates identified above.
ContractualUnconditional Purchase Obligations
Guarantees
Critical Accounting Policies Involving Significant Estimates
There have been no significantmaterial changes to guaranteesin our critical accounting estimates from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statementsreported in our 20162020 Annual Report on Form 10-K. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability through regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities, and contingent liabilities. For more information on our critical accounting estimates, see Part II, Item 7 of our 2020 Annual Report on Form 10-K.
New Accounting Pronouncements
Other than the pronouncements reported in our 20162020 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.
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 was 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 was made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, 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 our 2016 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2016 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.
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ITEM 3. | ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Utilities
Our utility customers are exposedThere have been no material changes to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, optionsour quantitative and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair valuequalitative disclosures about market risk previously disclosed in Item 7A of our Utilities Group’s derivative contracts is summarized below (in thousands) as of:
|
| | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
Net derivative (liabilities) assets | $ | (6,541 | ) | | $ | (4,733 | ) | | $ | (10,800 | ) |
Cash collateral offset in Derivatives | 5,452 |
| | 7,882 |
| | 11,584 |
|
Cash collateral included in Other current assets | 2,841 |
| | 4,840 |
| | 4,602 |
|
Net asset (liability) position | $ | 1,752 |
| | $ | 7,989 |
| | $ | 5,386 |
|
Oil and Gas Activities
We have entered into agreements to hedge a portion of our estimated 2017 and 2018 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at September 30, 2017, were as follows:
Natural Gas
|
| | | | | | | | | | | | | | | |
| March 31 | June 30 | September 30 | December 31 | Total Year |
2017 | | | | | |
Swaps - MMBtu | — |
| — |
| — |
| 540,000 |
| 540,000 |
|
Weighted Average Price per MMBtu | $ | — |
| $ | — |
| $ | — |
| $ | 3.04 |
| $ | 3.04 |
|
Crude Oil
|
| | | | | | | | | | | | | | | |
| March 31 | June 30 | September 30 | December 31 | Total Year |
2017 | | | | | |
Swaps - Bbls | — |
| — |
| — |
| 18,000 |
| 18,000 |
|
Weighted Average Price per Bbl | $ | — |
| $ | — |
| $ | — |
| $ | 52.33 |
| $ | 52.33 |
|
| | | | | |
Calls - Bbls | — |
| — |
| — |
| 9,000 |
| 9,000 |
|
Weighted Average Price per Bbl | $ | — |
| $ | — |
| $ | — |
| $ | 50.00 |
| $ | 50.00 |
|
| | | | | |
2018 | | | | | |
Swaps - Bbls | 9,000 |
| 9,000 |
| 9,000 |
| 9,000 |
| 36,000 |
|
Weighted Average Price per Bbl | $ | 49.58 |
| $ | 49.85 |
| $ | 50.12 |
| $ | 50.45 |
| $ | 50.00 |
|
The fair value of our Oil and Gas segment’s derivative contracts is summarized below (in thousands) as of:
|
| | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
Net derivative (liabilities) assets | $ | 110 |
| | $ | (1,433 | ) | | $ | 2,177 |
|
Cash collateral offset in Derivatives | 544 |
| | 2,733 |
| | — |
|
Net asset (liability) position | $ | 654 |
| | $ | 1,300 |
| | $ | 2,177 |
|
Financing Activities
We engage in activities to manage risks associated with changes in interest rates. Historically, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated long-term refinancings. Further details of the swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K and in Note 10 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.10-K.
The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
|
| | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 | | September 30, 2016 |
| Designated Interest Rate Swaps | | Designated Interest Rate Swap (a) | | Designated Interest Rate Swaps (a) |
Notional | $ | — |
| | $ | 50,000 |
| | $ | 75,000 |
|
Weighted average fixed interest rate | — | % | | 4.94 | % | | 4.97 | % |
Maximum terms in months | 0 |
| | 1 |
| | 4 |
|
Derivative assets, non-current | $ | — |
| | $ | — |
| | $ | — |
|
Derivative liabilities, current | $ | — |
| | $ | 90 |
| | $ | 654 |
|
Derivative liabilities, non-current | $ | — |
| | $ | — |
| | $ | — |
|
Pre-tax accumulated other comprehensive income (loss) | $ | — |
| | $ | (90 | ) | | $ | (654 | ) |
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(a) | The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. |
ITEM 4.CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934)1934, as amended (the “Exchange Act”)) as of September 30, 2017.March 31, 2021. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2017.March 31, 2021.
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, 2021, 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.
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BLACK HILLS CORPORATION
Part II — Other InformationPART II. OTHER INFORMATION
ITEM 1.LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 193 in Item 8 of our 20162020 Annual Report on Form 10-K and Note 163 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.10-Q.
ITEM 1A.RISK FACTORS
There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 20162020 Annual Report on Form 10-K filed with the SEC, except those stated below:10-K.
While we plan to sell Black Hills Exploration and Production, Inc. (”BHEP”), our oil and gas exploration business, and we have initiated a sales process and retained advisors to facilitate the process, there is no assurance that we can complete the transaction or recognize any particular level of proceeds.
We plan to divest all of our oil and gas assets and fully exit our oil and gas business. Such a divestiture and exit is subject to various risks, including: suitable purchasers may not be available or willing to purchase the assets on terms and conditions reasonable to us or may only be interested in acquiring a portion of the assets; we may incur substantial costs in connection with the marketing and sale of the assets; uncertainties associated with the sale may cause a loss of key management personnel at BHEP which could make it more difficult to sell the assets or operate the business in the event that we are unable to sell it; and we may be required to record an additional impairment charge that could have an adverse effect on our financial condition and results of operations.
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ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
There were no unregistered
The following table contains monthly information about our acquisitions of equity securities sold duringfor the ninethree months ended September 30, 2017.March 31, 2021:
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Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs |
January 1, 2021 - January 31, 2021 | 116.0 | $ | 60.06 | | — | | — | |
February 1, 2021 - February 28, 2021 | 11,696.0 | 61.92 | | — | | — | |
March 1, 2021 - March 31, 2021 | 1.4 | 59.86 | | — | | — | |
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Total | 11,813 | | $ | 61.90 | | — | | — | |
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(a) Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.