UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
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x☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
| EXCHANGE ACT OF 1934 | |
| For the quarterly period ended | September 30, 20182019 |
OR | |
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o☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
| EXCHANGE ACT OF 1934 |
| For the transition period from __________ to __________. |
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| Commission File Number | 001-31303 |
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Black Hills Corporation |
Incorporated in | South Dakota | IRS Identification Number | 46-0458824 |
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7001 Mount Rushmore Road |
| Rapid City | | South Dakota | | 57702 |
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Registrant’s telephone number | (605) | 721-1700 | |
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Former name, former address, and former fiscal year if changed since last report |
NONE |
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.
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).
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.
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| Large accelerated filer Accelerated Filer | x | | Accelerated filer o Filer | ☐ | |
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| Non-accelerated filer o Filer | ☐ | | Smaller reporting company o Reporting Company | ☐ | |
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| | | | Emerging growth company oGrowth Company | |
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If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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Securities registered pursuant to Section 12(b) of the Act: |
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common stock of $1.00 par value | BKH | New York Stock Exchange |
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
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Class | Outstanding at November 1, 2018October 31, 2019 |
Common stock, $1.00 par value | 59,974,62061,454,071 |
| shares |
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TABLE OF CONTENTS |
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| FINANCIAL INFORMATION | | |
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Item 1. | | | |
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| Three and Nine Months Ended September 30, 2018 and 2017 | | |
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| Three and Nine Months Ended September 30, 2018 and 2017 | | |
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| September 30, 2018, December 31, 2017 and September 30, 2017 | | |
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| Nine Months Ended September 30, 2018 and 2017 | | |
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| Notes to | | |
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Item 2. | | | |
Item 3. | | | |
Item 4. | | | |
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Item 3. | Quantitative and Qualitative Disclosures about Market Risk | | |
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Item 4. | Controls and Procedures | | |
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PART II. | OTHER INFORMATION | | |
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Item 1. | | | |
Item 4. | | | |
Item 6. | | | |
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Item 1A. | Risk Factors | | |
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Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | | |
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Item 4. | Mine Safety Disclosures | | |
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Item 5. | Other Information | | |
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Item 6. | Exhibits | | |
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| Signatures | | |
GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
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AFUDC | Allowance for Funds Used During Construction |
AOCI | Accumulated Other Comprehensive Income (Loss) |
APSC | Arkansas Public Service Commission |
Arkansas Gas | Black Hills Energy Arkansas, Inc., a direct, wholly-owned subsidiary of Black Hills Gas Inc. |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update issued by the FASB |
ATM | At-the-market equity offering program |
Availability | The availability factor of a power plant is the percentage of the time that it is available to provide energy. |
Bbl | Barrel |
BHC | Black Hills Corporation; the Company |
Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Black Hills Energy | The name used to conduct the business of our utility companies |
Black Hills Power | Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) |
Black Hills Utility Holdings | Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) |
Black Hills Wyoming | Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation |
Busch Ranch I | Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas.Black Hills Electric Generation. Colorado Electric hasand Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
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Busch Ranch II | Busch Ranch II wind project will be a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement. |
CAPP | Customer Appliance Protection Plan |
Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)Energy and providing electric service) |
Choice Gas Program | The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributesand Wyoming Gas distribute the gas and Black Hills Energy Services, is one of theWyoming Gas and Black Hills Gas Distribution are Choice Gas suppliers. |
CIAC | Contribution In Aid of Construction |
City of Gillette | Gillette, Wyoming |
City of Cheyenne | Cheyenne, Wyoming |
Chief Operating Decision Maker (CODM) | Chief Executive Officer |
Colorado Electric | Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
Colorado Gas | Black Hills Colorado Electric,Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
Colorado IPP | Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation |
Consolidated Indebtedness to Capitalization Ratio | Any Indebtednessindebtedness outstanding at such time, divided by Capitalcapital at such time. Capital being Consolidated Net-Worthconsolidated net-worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs)interest) plus Consolidated Indebtednessconsolidated indebtedness (including letters of credit and certain guarantees issued and excluding RSNs)issued) as defined within the current Revolving Credit Agreement.Facility. |
CDDCooling Degree Day (CDD) | A cooling degree day is equivalent to each degree that the average of the high and low temperaturetemperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.locations. |
CPCN | Certificate of Public Convenience and Necessity |
CP Program | Commercial Paper Program |
CPUC | Colorado Public Utilities Commission |
CT | Combustion turbine |
CVA | Credit Valuation Adjustment |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
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Dth | Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu) |
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Equity Unit | Each Equity Unit hashad a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs that were formerly due 2028 prior to2028. On November 1, 2018, we completed settlement of the successful remarketing on August 17, 2018.stock purchase contracts that are components of the Equity Units issued in November 2015. |
FASB | Financial Accounting Standards Board |
FERC | United States Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
GAAP | Accounting principles generally accepted in the United States of America |
HDDHeating Degree Day (HDD) | A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average. |
Horizon Point | Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.locations. |
IPP | Independent power producer |
IRS | United States Internal Revenue Service |
Kansas Gas | Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
LIBOR | London Interbank Offered Rate |
MMBtu | Million British thermal units |
Moody’s | Moody’s Investors Service, Inc. |
MW | Megawatts |
MWh | Megawatt-hours |
Nebraska Gas | Black Hills Nebraska Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
OCANPSC | Office of Consumer Advocate |
Peak View Wind Project | $109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm |
PCA | Power Cost AdjustmentNebraska Public Service Commission |
PPA | Power Purchase Agreement |
Pueblo Airport Generation Station | Two 100 MW combined cycle gas-fired power generation plants owned by Colorado IPP and located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012.
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Revolving Credit Facility | Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018 and now terminates on July 30, 2023. |
RMNG | Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas in western Colorado (doing business as Black Hills Energy) |
RSNs | Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018. |
SDPUC | South Dakota Public Utilities Commission |
SEC | U. S. Securities and Exchange Commission |
SourceGas | SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy) |
SourceGas Acquisition | The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings |
S&P | Standard and Poor’s, a division of The McGraw-Hill Companies, Inc. |
South Dakota Electric | Includes Black Hills Power, which includes operations in South Dakota, Wyoming and Montana |
SSIR | System Safety and Integrity Rider |
TCJA | Tax Cuts and Jobs Act enacted on December 22, 2017 |
Tech Services | Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts. |
Wind Capacity Factor | Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential |
WPSC | Wyoming Public Service Commission |
WRDC | Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Wyodak Plant | Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacificorpPacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant. |
Wyoming Electric | Includes Cheyenne Light’s electric utility operations
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Wyoming Gas | Black Hills Wyoming Gas, LLC, an indirect and wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | | (unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 |
| (in thousands, except per share amounts) | (in thousands, except per share amounts) |
| | |
Revenue | $ | 321,979 |
| $ | 335,611 |
| $ | 1,253,072 |
| $ | 1,224,968 |
| $ | 325,548 |
| $ | 321,979 |
| $ | 1,257,246 |
| $ | 1,253,072 |
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Operating expenses: | | |
Fuel, purchased power and cost of natural gas sold | 80,244 |
| 86,281 |
| 432,544 |
| 404,222 |
| 73,090 |
| 80,244 |
| 411,695 |
| 432,544 |
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Operations and maintenance | 115,477 |
| 109,258 |
| 350,099 |
| 335,707 |
| 117,037 |
| 115,699 |
| 366,907 |
| 352,092 |
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Depreciation, depletion and amortization | 49,046 |
| 47,109 |
| 146,345 |
| 140,636 |
| 51,884 |
| 49,046 |
| 154,507 |
| 146,345 |
|
Taxes - property, production and severance | 11,905 |
| 12,408 |
| 39,181 |
| 38,866 |
| |
Other operating expenses | 222 |
| 996 |
| 1,993 |
| 5,996 |
| |
Taxes - property and production | | 12,986 |
| 11,905 |
| 39,454 |
| 39,181 |
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Total operating expenses | 256,894 |
| 256,052 |
| 970,162 |
| 925,427 |
| 254,997 |
| 256,894 |
| 972,563 |
| 970,162 |
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Operating income | 65,085 |
| 79,559 |
| 282,910 |
| 299,541 |
| 70,551 |
| 65,085 |
| 284,683 |
| 282,910 |
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Other income (expense): | | |
Interest charges - | | |
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts) | (36,480 | ) | (35,287 | ) | (107,360 | ) | (105,417 | ) | |
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | | (36,200 | ) | (36,380 | ) | (108,232 | ) | (107,183 | ) |
Allowance for funds used during construction - borrowed | 701 |
| 753 |
| 1,345 |
| 2,061 |
| 2,200 |
| 701 |
| 4,555 |
| 1,345 |
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Capitalized interest | 100 |
| 64 |
| 177 |
| 197 |
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Interest income | 382 |
| 402 |
| 1,012 |
| 700 |
| 513 |
| 382 |
| 1,208 |
| 1,012 |
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Allowance for funds used during construction - equity | 193 |
| 696 |
| 503 |
| 1,982 |
| 311 |
| 193 |
| 486 |
| 503 |
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Impairment of investment | | (19,741 | ) | — |
| (19,741 | ) | — |
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Other income (expense), net | (703 | ) | 189 |
| (2,426 | ) | (6 | ) | 269 |
| (703 | ) | (431 | ) | (2,426 | ) |
Total other income (expense), net | (35,807 | ) | (33,183 | ) | (106,749 | ) | (100,483 | ) | |
Total other income (expense) | | (52,648 | ) | (35,807 | ) | (122,155 | ) | (106,749 | ) |
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Income before income taxes | 29,278 |
| 46,376 |
| 176,161 |
| 199,058 |
| 17,903 |
| 29,278 |
| 162,528 |
| 176,161 |
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Income tax benefit (expense) | (7,477 | ) | (13,478 | ) | 11,784 |
| (58,518 | ) | (2,508 | ) | (7,477 | ) | (22,078 | ) | 11,784 |
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Income from continuing operations | 21,801 |
| 32,898 |
| 187,945 |
| 140,540 |
| 15,395 |
| 21,801 |
| 140,450 |
| 187,945 |
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(Loss) from discontinued operations, net of tax | (857 | ) | (1,300 | ) | (5,627 | ) | (3,485 | ) | |
Net (loss) from discontinued operations | | — |
| (857 | ) | — |
| (5,627 | ) |
Net income | 20,944 |
| 31,598 |
| 182,318 |
| 137,055 |
| 15,395 |
| 20,944 |
| 140,450 |
| 182,318 |
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Net income attributable to noncontrolling interest | (3,994 | ) | (3,935 | ) | (10,447 | ) | (10,674 | ) | (3,655 | ) | (3,994 | ) | (10,319 | ) | (10,447 | ) |
Net income available for common stock | $ | 16,950 |
| $ | 27,663 |
| $ | 171,871 |
| $ | 126,381 |
| $ | 11,740 |
| $ | 16,950 |
| $ | 130,131 |
| $ | 171,871 |
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Amounts attributable to common shareholders: | | |
Net income from continuing operations | $ | 17,807 |
| $ | 28,963 |
| $ | 177,498 |
| $ | 129,866 |
| $ | 11,740 |
| $ | 17,807 |
| $ | 130,131 |
| $ | 177,498 |
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Net (loss) from discontinued operations | (857 | ) | (1,300 | ) | (5,627 | ) | (3,485 | ) | — |
| (857 | ) | — |
| (5,627 | ) |
Net income available for common stock | $ | 16,950 |
| $ | 27,663 |
| $ | 171,871 |
| $ | 126,381 |
| $ | 11,740 |
| $ | 16,950 |
| $ | 130,131 |
| $ | 171,871 |
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Earnings per share of common stock: | | |
Earnings (loss) per share, Basic - | | |
Income from continuing operations, per share | $ | 0.33 |
| $ | 0.54 |
| $ | 3.33 |
| $ | 2.44 |
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(Loss) from discontinued operations, per share | (0.02 | ) | (0.02 | ) | (0.10 | ) | (0.06 | ) | |
Earnings per share, Basic (a) | $ | 0.32 |
| $ | 0.52 |
| $ | 3.22 |
| $ | 2.38 |
| |
Earnings (loss) per share of common stock, Basic - | | |
Earnings from continuing operations | | $ | 0.19 |
| $ | 0.33 |
| $ | 2.15 |
| $ | 3.33 |
|
(Loss) from discontinued operations | | — |
| (0.02 | ) | — |
| (0.10 | ) |
Total earnings per share of common stock, Basic | | $ | 0.19 |
| $ | 0.32 |
| $ | 2.15 |
| $ | 3.22 |
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Earnings (loss) per share, Diluted - | | |
Income from continuing operations, per share | $ | 0.32 |
| $ | 0.52 |
| $ | 3.26 |
| $ | 2.35 |
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(Loss) from discontinued operations, per share | (0.02 | ) | (0.02 | ) | (0.10 | ) | (0.06 | ) | |
Earnings per share, Diluted (a) | $ | 0.31 |
| $ | 0.50 |
| $ | 3.15 |
| $ | 2.29 |
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Earnings (loss) per share of common stock, Diluted - | | |
Earnings from continuing operations | | $ | 0.19 |
| $ | 0.32 |
| $ | 2.15 |
| $ | 3.26 |
|
(Loss) from discontinued operations | | — |
| (0.02 | ) | — |
| (0.10 | ) |
Total earnings per share of common stock, Diluted | | $ | 0.19 |
| $ | 0.31 |
| $ | 2.15 |
| $ | 3.15 |
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Weighted average common shares outstanding: | | |
Basic | 53,364 |
| 53,243 |
| 53,346 |
| 53,208 |
| 60,976 |
| 53,364 |
| 60,458 |
| 53,346 |
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Diluted | 54,819 |
| 55,432 |
| 54,508 |
| 55,254 |
| 61,104 |
| 54,819 |
| 60,578 |
| 54,508 |
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Dividends declared per share of common stock | $ | 0.475 |
| $ | 0.445 |
| $ | 1.425 |
| $ | 1.335 |
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(a) EPS may not sum due to rounding.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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(unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | 2018 | 2017 |
| (in thousands) |
| | | | |
Net income | $ | 20,944 |
| $ | 31,598 |
| $ | 182,318 |
| $ | 137,055 |
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| | | | |
Other comprehensive income (loss), net of tax: | | | | |
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $10 and $17 for the three months ended September 30, 2018 and 2017 and $29 and $52 for the nine months ended September 30, 2018 and 2017, respectively) | (34 | ) | (32 | ) | (104 | ) | (94 | ) |
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(138) and $(145) for the three months ended September 30, 2018 and 2017 and $(409) and $(445) for the nine months ended September 30, 2018 and 2017, respectively) | 483 |
| 269 |
| 1,456 |
| 797 |
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Derivative instruments designated as cash flow hedges: | | | | |
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(152) and $(249) for the three months ended September 30, 2018 and 2017 and $(456) and $(779) for the nine months ended September 30, 2018 and 2017, respectively) | 560 |
| 464 |
| 1,682 |
| 1,449 |
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Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $0 and $94 for the three months ended September 30, 2018 and 2017 and $51 and $(442) for the nine months ended September 30, 2018 and 2017, respectively) | 30 |
| (160 | ) | (168 | ) | 755 |
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Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $3 and $95 for the three months ended September 30, 2018 and 2017 and $(187) and $344 for the nine months ended September 30, 2018 and 2017, respectively) | 21 |
| (166 | ) | 615 |
| (590 | ) |
Other comprehensive income, net of tax | 1,060 |
| 375 |
| 3,481 |
| 2,317 |
|
| | | | |
Comprehensive income | 22,004 |
| 31,973 |
| 185,799 |
| 139,372 |
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Less: comprehensive income attributable to noncontrolling interest | (3,994 | ) | (3,935 | ) | (10,447 | ) | (10,674 | ) |
Comprehensive income available for common stock | $ | 18,010 |
| $ | 28,038 |
| $ | 175,352 |
| $ | 128,698 |
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See Note 14 for additional disclosures.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
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(unaudited) | As of |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
| (in thousands) |
ASSETS | | | | | |
Current assets: | | | | | |
Cash and cash equivalents | $ | 10,001 |
| | $ | 15,420 |
| | $ | 13,449 |
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Restricted cash | 3,241 |
| | 2,820 |
| | 2,683 |
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Accounts receivable, net | 152,796 |
| | 248,330 |
| | 150,325 |
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Materials, supplies and fuel | 122,618 |
| | 113,283 |
| | 122,866 |
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Derivative assets, current | 1,392 |
| | 304 |
| | 433 |
|
Income tax receivable, net | 11,025 |
| | — |
| | — |
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Regulatory assets, current | 48,302 |
| | 81,016 |
| | 61,023 |
|
Other current assets | 32,691 |
| | 25,367 |
| | 25,586 |
|
Current assets held for sale | 2,854 |
| | 84,242 |
| | 8,653 |
|
Total current assets | 384,920 |
| | 570,782 |
| | 385,018 |
|
| | | | | |
Investments | 41,202 |
| | 13,090 |
| | 12,947 |
|
| | | | | |
Property, plant and equipment | 5,819,000 |
| | 5,567,518 |
| | 5,499,557 |
|
Less: accumulated depreciation and depletion | (1,118,783 | ) | | (1,026,088 | ) | | (1,000,875 | ) |
Total property, plant and equipment, net | 4,700,217 |
| | 4,541,430 |
| | 4,498,682 |
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| | | | | |
Other assets: | | | | | |
Goodwill | 1,299,454 |
| | 1,299,454 |
| | 1,299,454 |
|
Intangible assets, net | 6,954 |
| | 7,559 |
| | 7,765 |
|
Regulatory assets, non-current | 212,048 |
| | 216,438 |
| | 239,571 |
|
Other assets, non-current | 17,143 |
| | 10,149 |
| | 11,626 |
|
Noncurrent assets held for sale | — |
| | — |
| | 108,685 |
|
Total other assets, non-current | 1,535,599 |
| | 1,533,600 |
| | 1,667,101 |
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| | | | | |
TOTAL ASSETS | $ | 6,661,938 |
| | $ | 6,658,902 |
| | $ | 6,563,748 |
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF COMPREHENSIVE INCOME
(Continued)
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(unaudited) | As of |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
| (in thousands, except share amounts) |
LIABILITIES AND TOTAL EQUITY | | | | | |
Current liabilities: | | | | | |
Accounts payable | $ | 115,900 |
| | $ | 160,887 |
| | $ | 94,790 |
|
Accrued liabilities | 201,353 |
| | 219,462 |
| | 206,779 |
|
Derivative liabilities, current | 1,154 |
| | 2,081 |
| | 1,458 |
|
Accrued income taxes, net | — |
| | 1,022 |
| | 5,587 |
|
Regulatory liabilities, current | 41,442 |
| | 6,832 |
| | 7,042 |
|
Notes payable | 112,100 |
| | 211,300 |
| | 225,170 |
|
Current maturities of long-term debt | 255,743 |
| | 5,743 |
| | 5,743 |
|
Current liabilities held for sale | 2,538 |
| | 41,774 |
| | 7,701 |
|
Total current liabilities | 730,230 |
| | 649,101 |
| | 554,270 |
|
| | | | | |
Long-term debt | 2,951,389 |
| | 3,109,400 |
| | 3,109,864 |
|
| | | | | |
Deferred credits and other liabilities: | | | | | |
Deferred income tax liabilities, net | 292,753 |
| | 336,520 |
| | 618,315 |
|
Regulatory liabilities, non-current | 508,846 |
| | 478,294 |
| | 198,189 |
|
Benefit plan liabilities | 151,613 |
| | 159,646 |
| | 149,803 |
|
Other deferred credits and other liabilities | 105,928 |
| | 105,735 |
| | 113,996 |
|
Non-current liabilities held for sale | — |
| | — |
| | 23,329 |
|
Total deferred credits and other liabilities | 1,059,140 |
| | 1,080,195 |
| | 1,103,632 |
|
| | | | | |
Commitments and contingencies (See Notes 9, 11, 16, 17) |
|
| |
| |
|
| | | | | |
Equity: | | | | | |
Stockholders’ equity — | | | | | |
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,863; 53,579,986; and 53,524,529 shares, respectively | 53,662 |
| | 53,580 |
| | 53,525 |
|
Additional paid-in capital | 1,157,214 |
| | 1,150,285 |
| | 1,147,922 |
|
Retained earnings | 644,154 |
| | 548,617 |
| | 516,371 |
|
Treasury stock, at cost – 72,915; 39,064; and 41,457 shares, respectively | (4,072 | ) | | (2,306 | ) | | (2,448 | ) |
Accumulated other comprehensive income (loss) | (37,703 | ) | | (41,202 | ) | | (32,566 | ) |
Total stockholders’ equity | 1,813,255 |
| | 1,708,974 |
| | 1,682,804 |
|
Noncontrolling interest | 107,924 |
| | 111,232 |
| | 113,178 |
|
Total equity | 1,921,179 |
| | 1,820,206 |
| | 1,795,982 |
|
| | | | | |
TOTAL LIABILITIES AND TOTAL EQUITY | $ | 6,661,938 |
| | $ | 6,658,902 |
| | $ | 6,563,748 |
|
|
| | | | | | | | | | | | |
(unaudited) | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | 2019 | 2018 |
| (in thousands) |
| | | | |
Net income | $ | 15,395 |
| $ | 20,944 |
| $ | 140,450 |
| $ | 182,318 |
|
| | | | |
Other comprehensive income (loss), net of tax: | | | | |
Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $3, $10, $13 and $29, respectively) | (16 | ) | (34 | ) | (45 | ) | (104 | ) |
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(92), $(138), $(197), and $(409), respectively) | (9 | ) | 483 |
| 327 |
| 1,456 |
|
Derivative instruments designated as cash flow hedges: | | | | |
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(165), $(152), $(500), and $(456), respectively) | 548 |
| 560 |
| 1,639 |
| 1,682 |
|
Net unrealized gains (losses) on commodity derivatives (net of tax of $35, $0, $100 and $51, respectively) | (115 | ) | 30 |
| (334 | ) | (168 | ) |
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(5), $3, $142 and $(187), respectively) | 124 |
| 21 |
| (366 | ) | 615 |
|
Other comprehensive income, net of tax | 532 |
| 1,060 |
| 1,221 |
| 3,481 |
|
| | | | |
Comprehensive income | 15,927 |
| 22,004 |
| 141,671 |
| 185,799 |
|
Less: comprehensive income attributable to noncontrolling interest | (3,655 | ) | (3,994 | ) | (10,319 | ) | (10,447 | ) |
Comprehensive income available for common stock | $ | 12,272 |
| $ | 18,010 |
| $ | 131,352 |
| $ | 175,352 |
|
See Note 13 for additional disclosures.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
|
| | | | | | |
(unaudited) | Nine Months Ended September 30, |
| 2018 | 2017 |
Operating activities: | (in thousands) |
Net income | $ | 182,318 |
| $ | 137,055 |
|
Loss from discontinued operations, net of tax | 5,627 |
| 3,485 |
|
Income from continuing operations | 187,945 |
| 140,540 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | |
Depreciation, depletion and amortization | 146,345 |
| 140,636 |
|
Deferred financing cost amortization | 5,682 |
| 6,212 |
|
Stock compensation | 7,544 |
| 7,594 |
|
Deferred income taxes | (14,396 | ) | 65,536 |
|
Employee benefit plans | 10,641 |
| 8,470 |
|
Other adjustments, net | 7,668 |
| (3,549 | ) |
Changes in certain operating assets and liabilities: | | |
Materials, supplies and fuel | (8,380 | ) | (19,511 | ) |
Accounts receivable, unbilled revenues and other operating assets | 72,061 |
| 103,963 |
|
Accounts payable and other operating liabilities | (86,604 | ) | (112,288 | ) |
Regulatory assets - current | 41,655 |
| 1,287 |
|
Regulatory liabilities - current | 21,416 |
| (4,328 | ) |
Contributions to defined benefit pension plans | (12,700 | ) | (27,700 | ) |
Other operating activities, net | 2,007 |
| (1,410 | ) |
Net cash provided by operating activities of continuing operations | 380,884 |
| 305,452 |
|
Net cash provided by (used in) operating activities of discontinued operations | (2,162 | ) | 13,978 |
|
Net cash provided by operating activities | 378,722 |
| 319,430 |
|
| | |
Investing activities: | | |
Property, plant and equipment additions | (278,132 | ) | (238,840 | ) |
Purchase of investment | (24,429 | ) | — |
|
Other investing activities | 2,766 |
| 160 |
|
Net cash provided by (used in) investing activities of continuing operations | (299,795 | ) | (238,680 | ) |
Net cash provided by (used in) investing activities of discontinued operations | 18,024 |
| (17,298 | ) |
Net cash provided by (used in) investing activities | (281,771 | ) | (255,978 | ) |
| | |
Financing activities: | | |
Dividends paid on common stock | (76,309 | ) | (71,334 | ) |
Common stock issued | 1,079 |
| 3,562 |
|
Net (payments) borrowings of short-term debt | (99,200 | ) | 128,570 |
|
Long-term debt - issuances | 700,000 |
| — |
|
Long-term debt - repayments | (603,307 | ) | (104,307 | ) |
Distributions to noncontrolling interest | (13,755 | ) | (12,884 | ) |
Other financing activities | (10,457 | ) | (6,719 | ) |
Net cash provided by (used in) financing activities | (101,949 | ) | (63,112 | ) |
Net change in cash, cash equivalents and restricted cash | (4,998 | ) | 340 |
|
Cash, cash equivalents and restricted cash at beginning of period | 18,240 |
| 15,792 |
|
Cash, cash equivalents and restricted cash at end of period | $ | 13,242 |
| $ | 16,132 |
|
|
| | | | | | | |
(unaudited) | As of |
| September 30, 2019 | | December 31, 2018 |
| (in thousands) |
ASSETS | | | |
Current assets: | | | |
Cash and cash equivalents | $ | 13,087 |
| | $ | 20,776 |
|
Restricted cash | 3,688 |
| | 3,369 |
|
Accounts receivable, net | 148,989 |
| | 269,153 |
|
Materials, supplies and fuel | 123,002 |
| | 117,299 |
|
Derivative assets, current | 412 |
| | 1,500 |
|
Income tax receivable, net | 12,931 |
| | 12,978 |
|
Regulatory assets, current | 46,206 |
| | 48,776 |
|
Other current assets | 29,106 |
| | 29,982 |
|
Total current assets | 377,421 |
| | 503,833 |
|
| | | |
Investments | 21,583 |
| | 41,013 |
|
| | | |
Property, plant and equipment | 6,567,229 |
| | 6,000,015 |
|
Less: accumulated depreciation and depletion | (1,243,794 | ) | | (1,145,136 | ) |
Total property, plant and equipment, net | 5,323,435 |
| | 4,854,879 |
|
| | | |
Other assets: | | | |
Goodwill | 1,299,454 |
| | 1,299,454 |
|
Intangible assets, net | 13,566 |
| | 14,337 |
|
Regulatory assets, non-current | 214,152 |
| | 235,459 |
|
Other assets, non-current | 25,339 |
| | 14,352 |
|
Total other assets, non-current | 1,552,511 |
| | 1,563,602 |
|
| | | |
TOTAL ASSETS | $ | 7,274,950 |
| | $ | 6,963,327 |
|
See Note 15 for supplemental disclosure of cash flow information.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
|
| | | | | | | |
(unaudited) | As of |
| September 30, 2019 | | December 31, 2018 |
| (in thousands, except share amounts) |
LIABILITIES AND TOTAL EQUITY | | | |
Current liabilities: | | | |
Accounts payable | $ | 145,085 |
| | $ | 210,609 |
|
Accrued liabilities | 217,832 |
| | 215,501 |
|
Derivative liabilities, current | 2,396 |
| | 947 |
|
Regulatory liabilities, current | 25,168 |
| | 29,810 |
|
Notes payable | 294,900 |
| | 185,620 |
|
Current maturities of long-term debt | 5,743 |
| | 5,743 |
|
Total current liabilities | 691,124 |
| | 648,230 |
|
| | | |
Long-term debt | 3,049,235 |
| | 2,950,835 |
|
| | | |
Deferred credits and other liabilities: | | | |
Deferred income tax liabilities, net | 347,952 |
| | 311,331 |
|
Regulatory liabilities, non-current | 498,773 |
| | 510,984 |
|
Benefit plan liabilities | 134,150 |
| | 145,147 |
|
Other deferred credits and other liabilities | 120,820 |
| | 109,377 |
|
Total deferred credits and other liabilities | 1,101,695 |
| | 1,076,839 |
|
| | | |
Commitments and contingencies (See Notes 8, 10, 15, 16) |
|
| |
|
| | | |
Equity: | | | |
Stockholders’ equity — | | | |
Common stock $1 par value; 100,000,000 shares authorized; issued 61,480,640 and 60,048,567 shares, respectively | 61,481 |
| | 60,049 |
|
Additional paid-in capital | 1,553,190 |
| | 1,450,569 |
|
Retained earnings | 742,138 |
| | 700,396 |
|
Treasury stock, at cost – 26,572 and 44,253 shares, respectively | (1,636 | ) | | (2,510 | ) |
Accumulated other comprehensive income (loss) | (25,695 | ) | | (26,916 | ) |
Total stockholders’ equity | 2,329,478 |
| | 2,181,588 |
|
Noncontrolling interest | 103,418 |
| | 105,835 |
|
Total equity | 2,432,896 |
| | 2,287,423 |
|
| | | |
TOTAL LIABILITIES AND TOTAL EQUITY | $ | 7,274,950 |
| | $ | 6,963,327 |
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | |
(unaudited) | Nine Months Ended September 30, |
| 2019 | 2018 |
Operating activities: | (in thousands) |
Net income | $ | 140,450 |
| $ | 182,318 |
|
Loss from discontinued operations, net of tax | — |
| 5,627 |
|
Income from continuing operations | 140,450 |
| 187,945 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | |
Depreciation, depletion and amortization | 154,507 |
| 146,345 |
|
Deferred financing cost amortization | 6,326 |
| 5,682 |
|
Impairment of investment | 19,741 |
| — |
|
Stock compensation | 8,332 |
| 7,544 |
|
Deferred income taxes | 24,381 |
| (14,396 | ) |
Employee benefit plans | 7,965 |
| 10,641 |
|
Other adjustments, net | 9,192 |
| 7,668 |
|
Changes in certain operating assets and liabilities: | | |
Materials, supplies and fuel | (4,126 | ) | (8,380 | ) |
Accounts receivable, unbilled revenues and other operating assets | 115,325 |
| 72,061 |
|
Accounts payable and other operating liabilities | (83,436 | ) | (86,604 | ) |
Regulatory assets - current | 12,455 |
| 41,655 |
|
Regulatory liabilities - current | (15,644 | ) | 21,416 |
|
Contributions to defined benefit pension plans | (12,700 | ) | (12,700 | ) |
Other operating activities, net | 3,307 |
| 2,007 |
|
Net cash provided by operating activities of continuing operations | 386,075 |
| 380,884 |
|
Net cash provided by (used in) operating activities of discontinued operations | — |
| (2,162 | ) |
Net cash provided by operating activities | 386,075 |
| 378,722 |
|
| | |
Investing activities: | | |
Property, plant and equipment additions | (592,537 | ) | (278,132 | ) |
Purchase of investment | — |
| (24,429 | ) |
Other investing activities | (735 | ) | 2,766 |
|
Net cash provided by (used in) investing activities of continuing operations | (593,272 | ) | (299,795 | ) |
Net cash provided by investing activities of discontinued operations | — |
| 18,024 |
|
Net cash provided by (used in) investing activities | (593,272 | ) | (281,771 | ) |
| | |
Financing activities: | | |
Dividends paid on common stock | (91,779 | ) | (76,309 | ) |
Common stock issued | 101,361 |
| 1,079 |
|
Net (payments) borrowings of short-term debt | 109,280 |
| (99,200 | ) |
Long-term debt - issuances | 400,000 |
| 700,000 |
|
Long-term debt - repayments | (304,307 | ) | (603,307 | ) |
Distributions to noncontrolling interest | (12,736 | ) | (13,755 | ) |
Other financing activities | (1,992 | ) | (10,457 | ) |
Net cash provided by (used in) financing activities | 199,827 |
| (101,949 | ) |
Net change in cash, cash equivalents and restricted cash | (7,370 | ) | (4,998 | ) |
Cash, cash equivalents and restricted cash at beginning of period | 24,145 |
| 18,240 |
|
Cash, cash equivalents and restricted cash at end of period | $ | 16,775 |
| $ | 13,242 |
|
See Note 14 for supplemental disclosure of cash flow information.
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
(unaudited) | Common Stock | Treasury Stock | | | | | |
(in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non controlling Interest | Total |
December 31, 2018 | 60,048,567 |
| $ | 60,049 |
| 44,253 |
| $ | (2,510 | ) | $ | 1,450,569 |
| $ | 700,396 |
| $ | (26,916 | ) | $ | 105,835 |
| $ | 2,287,423 |
|
Net income available for common stock | — |
| — |
| — |
| — |
| — |
| 103,808 |
| — |
| 3,554 |
| 107,362 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 457 |
| — |
| 457 |
|
Dividends on common stock ($0.505 per share) | — |
| — |
| — |
| — |
| — |
| (30,332 | ) | — |
| — |
| (30,332 | ) |
Share-based compensation | 48,956 |
| 49 |
| (20,497 | ) | 1,078 |
| (589 | ) | — |
| — |
| — |
| 538 |
|
Issuance of common stock | 280,497 |
| 280 |
| — |
| — |
| 19,719 |
| — |
| — |
| — |
| 19,999 |
|
Issuance costs | — |
| — |
| — |
| — |
| (289 | ) | — |
| — |
| — |
| (289 | ) |
Implementation of ASU 2016-02 Leases | — |
| — |
| — |
| — |
| — |
| 3,390 |
| — |
| — |
| 3,390 |
|
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (4,846 | ) | (4,846 | ) |
March 31, 2019 | 60,378,020 |
| $ | 60,378 |
| 23,756 |
| $ | (1,432 | ) | $ | 1,469,410 |
| $ | 777,262 |
| $ | (26,459 | ) | $ | 104,543 |
| $ | 2,383,702 |
|
Net income available for common stock | — |
| — |
| — |
| — |
| — |
| 14,583 |
| — |
| 3,110 |
| 17,693 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 232 |
| — |
| 232 |
|
Dividends on common stock ($0.505 per share) | — |
| — |
| — |
| — |
| — |
| (30,620 | ) | — |
| — |
| (30,620 | ) |
Share-based compensation | 54,767 |
| 54 |
| 1,603 |
| (112 | ) | 3,948 |
| — |
| — |
| — |
| 3,890 |
|
Issuance of common stock | 658,598 |
| 659 |
| — |
| — |
| 49,342 |
| — |
| — |
| — |
| 50,001 |
|
Issuance costs | — |
| — |
| — |
| — |
| (492 | ) | — |
| — |
| — |
| (492 | ) |
Implementation of ASU 2016-02 Leases | — |
| — |
| — |
| — |
| — |
| (3 | ) | — |
| — |
| (3 | ) |
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (4,405 | ) | (4,405 | ) |
June 30, 2019 | 61,091,385 |
| $ | 61,091 |
| 25,359 |
| $ | (1,544 | ) | $ | 1,522,208 |
| $ | 761,222 |
| $ | (26,227 | ) | $ | 103,248 |
| $ | 2,419,998 |
|
Net income (loss) available for common stock | — |
| — |
| — |
| — |
| — |
| 11,740 |
| — |
| 3,655 |
| 15,395 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 532 |
| — |
| 532 |
|
Dividends on common stock ($0.505 per share) | — |
| — |
| — |
| — |
| — |
| (30,827 | ) | — |
| — |
| (30,827 | ) |
Share-based compensation | 18 |
| — |
| 1,213 |
| (92 | ) | 1,769 |
| — |
| — |
| — |
| 1,677 |
|
Issuance of common stock | 389,237 |
| 390 |
| — |
| — |
| 29,611 |
| — |
| — |
| — |
| 30,001 |
|
Issuance costs | — |
| — |
| — |
| — |
| (398 | ) | — |
| — |
| — |
| (398 | ) |
Implementation of ASU 2016-02 Leases | — |
| — |
| — |
| — |
| — |
| 3 |
| — |
| — |
| 3 |
|
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (3,485 | ) | (3,485 | ) |
September 30, 2019 | 61,480,640 |
| $ | 61,481 |
| 26,572 |
| $ | (1,636 | ) | $ | 1,553,190 |
| $ | 742,138 |
| $ | (25,695 | ) | $ | 103,418 |
| $ | 2,432,896 |
|
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | Treasury Stock | | | | | |
(in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non controlling Interest | Total |
December 31, 2017 | 53,579,986 |
| $ | 53,580 |
| 39,064 |
| $ | (2,306 | ) | $ | 1,150,285 |
| $ | 548,617 |
| $ | (41,202 | ) | $ | 111,232 |
| $ | 1,820,206 |
|
Net income available for common stock | — |
| — |
| — |
| — |
| — |
| 133,004 |
| — |
| 3,630 |
| 136,634 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 1,260 |
| — |
| 1,260 |
|
Dividends on common stock ($0.475 per share) | — |
| — |
| — |
| — |
| — |
| (25,444 | ) | — |
| — |
| (25,444 | ) |
Share-based compensation | 64,770 |
| 65 |
| 14,895 |
| (743 | ) | 1,433 |
| — |
| — |
| — |
| 755 |
|
Dividend reinvestment and stock purchase plan | 4,061 |
| 4 |
| — |
| — |
| 215 |
| — |
| — |
| — |
| 219 |
|
Other stock transactions | — |
| — |
| — |
| — |
| — |
| (16 | ) | 18 |
| — |
| 2 |
|
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (5,648 | ) | (5,648 | ) |
March 31, 2018 | 53,648,817 |
| $ | 53,649 |
| 53,959 |
| $ | (3,049 | ) | $ | 1,151,933 |
| $ | 656,161 |
| $ | (39,924 | ) | $ | 109,214 |
| $ | 1,927,984 |
|
Net income available for common stock | — |
| — |
| — |
| — |
| — |
| 21,917 |
| — |
| 2,823 |
| 24,740 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 1,161 |
| — |
| 1,161 |
|
Dividends on common stock ($0.475 per share) | — |
| — |
| — |
| — |
| — |
| (25,435 | ) | — |
| — |
| (25,435 | ) |
Share-based compensation | 13,033 |
| 13 |
| 11,022 |
| (593 | ) | 3,019 |
| — |
| — |
| — |
| 2,439 |
|
Other stock transactions | — |
| — |
| — |
| — |
| (5 | ) | (1 | ) | — |
| — |
| (6 | ) |
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (4,350 | ) | (4,350 | ) |
June 30, 2018 | 53,661,850 |
| $ | 53,662 |
| 64,981 |
| $ | (3,642 | ) | $ | 1,154,947 |
| $ | 652,642 |
| $ | (38,763 | ) | $ | 107,687 |
| $ | 1,926,533 |
|
Net income (loss) available for common stock | — |
| — |
| — |
| — |
| — |
| 16,950 |
| — |
| 3,994 |
| 20,944 |
|
Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 1,060 |
| — |
| 1,060 |
|
Dividends on common stock ($0.475 per share) | — |
| — |
| — |
| — |
| — |
| (25,430 | ) | — |
| — |
| (25,430 | ) |
Share-based compensation | 13 |
| — |
| 7,934 |
| (430 | ) | 2,107 |
| — |
| — |
| — |
| 1,677 |
|
Dividend reinvestment and stock purchase plan | — |
| — |
| — |
| — |
| 1 |
| — |
| — |
| — |
| 1 |
|
Other stock transactions | — |
| — |
| — |
| — |
| 159 |
| (8 | ) | — |
| — |
| 151 |
|
Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (3,757 | ) | (3,757 | ) |
September 30, 2018 | 53,661,863 |
| $ | 53,662 |
| 72,915 |
| $ | (4,072 | ) | $ | 1,157,214 |
| $ | 644,154 |
| $ | (37,703 | ) | $ | 107,924 |
| $ | 1,921,179 |
|
| | | | | | | | | |
BLACK HILLS CORPORATION
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 20172018 Annual Report on Form 10-K)
(1) MANAGEMENT’S STATEMENT
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 20172018 Annual Report on Form 10-K filed with the SEC.
Segment Reporting
We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and 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.
Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 for more information.
On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture in 2018. The Oil and Gas segment assets and liabilities arewere classified as held for sale and the results of operations arewere shown in income (loss) from discontinued operations, excludingexcept for certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of September 30, 2018, we have sold nearly all of our oilAt the time the assets were classified as held for sale, depreciation, depletion and gas assets and we closed our oil and gas officeamortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in August. Transaction closing for the last few assets and final accounting are expected withinaccompanying notes to the fourth quarter.Condensed Consolidated Financial Statements relate to the Company’s continuing operations. See Note 1817 and Note 21 for more information on discontinued operations.
Use of Estimates and Basis of Presentation
The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2018,2019 and December 31, 2017, and September 30, 20172018 financial information and are of a normal recurring nature.information. Certain industries 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 electric utilities is June through August while the normal peak usage season for gas 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, 2019 and September 30, 2018 and September 30, 2017, and our financial condition as of September 30, 2018,2019 and December 31, 2017, and September 30, 2017,2018 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.
Cash and Cash Equivalents and Restricted Cash
For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.
Investments
We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.
Recently Issued Accounting Standards
Leases, ASU 2016-02
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.
We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.
Simplifying the Test for Goodwill Impairment, ASU 2017-04
In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15,1, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standardguidance to have any impact on our financial position, results of operations or cash flows.
Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19
In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19 in November 2018. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, and will be applied on a modified-retrospective basis through a cumulative-effect adjustment to retained earnings as of January 1, 2020. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.
Recently Adopted Accounting Standards
Revenue from Contracts with Customers,Leases, ASU 2014-092016-02
Effective January 1, 2018, we adoptedIn February 2016, the FASB issued ASU 2014-09, Revenue from Contracts with Customers2016-02, Leases (Topic 606),842) to increase transparency and its related amendments (collectively known as ASC 606).comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under thisthe new standard, revenue is recognized when a customer obtains controldisclosures are required to meet the objective of promised goods or services in an amount that reflectsenabling users of financial statements to assess the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contractsleases.
We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with customers.the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We appliedalso elected the five-step method outlinedpractical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.
Adoption of the new standard resulted in the ASU to all in-scope revenue streamsrecording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and elected the modified retrospective implementation method. Implementationan accrued rent receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12
Effective January 1, 2019, we adopted ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows. Implementation
(2) REVENUE
Revenue Recognition
As of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.
Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07
Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits2014-09, Revenue from Contracts with Customers (Topic 715): Improving the Presentation of Net Periodic Pension Cost606), and Net Periodic Post-Retirement Benefit Costits related amendments (collectively known as ASC 606). The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the nine months ended September 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.
Statement of Cash Flows: Restricted Cash, ASU 2016-18
Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.
(2) REVENUE
Revenue Recognition
Revenues areis recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:
Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.
Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.
Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.
Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.
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 reporting segments, for the three and nine months ended September 30, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.
|
| | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
Customer types: | (in thousands) |
Retail | $ | 162,214 |
| $ | 89,810 |
| $ | — |
| $ | 14,992 |
| $ | (8,146 | ) | $ | 258,870 |
|
Transportation | — |
| 29,019 |
| — |
| — |
| (195 | ) | 28,824 |
|
Wholesale | 8,210 |
| — |
| 16,119 |
| — |
| (14,414 | ) | 9,915 |
|
Market - off-system sales | 6,452 |
| 139 |
| — |
| — |
| (1,488 | ) | 5,103 |
|
Transmission/Other | 14,274 |
| 10,965 |
| — |
| — |
| (4,206 | ) | 21,033 |
|
Revenue from contracts with customers | $ | 191,150 |
| $ | 129,933 |
| $ | 16,119 |
| $ | 14,992 |
| $ | (28,449 | ) | $ | 323,745 |
|
Other revenues | 234 |
| 811 |
| 9,692 |
| 560 |
| (9,494 | ) | 1,803 |
|
Total revenues | $ | 191,384 |
| $ | 130,744 |
| $ | 25,811 |
| $ | 15,552 |
| $ | (37,943 | ) | $ | 325,548 |
|
| | | | | | |
Timing of revenue recognition: | | | | | | |
Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 14,992 |
| $ | (8,146 | ) | $ | 6,846 |
|
Services transferred over time | 191,150 |
| 129,933 |
| 16,119 |
| — |
| (20,303 | ) | 316,899 |
|
Revenue from contracts with customers | $ | 191,150 |
| $ | 129,933 |
| $ | 16,119 |
| $ | 14,992 |
| $ | (28,449 | ) | $ | 323,745 |
|
| | | | | | |
| | Three Months Ended September 30, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total | Electric Utilities | Gas Utilities | Power Generation (a) | Mining | Inter-company Revenues (a) | Total |
Customer types: | (in thousands) | |
Customer Types: | | |
Retail | $ | 157,049 |
| $ | 88,559 |
| $ | — |
| $ | 16,751 |
| $ | (7,941 | ) | $ | 254,418 |
| $ | 157,049 |
| $ | 88,559 |
| $ | — |
| $ | 16,751 |
| $ | (7,941 | ) | $ | 254,418 |
|
Transportation | — |
| 30,079 |
| — |
| — |
| (267 | ) | 29,812 |
| — |
| 30,079 |
| — |
| — |
| (267 | ) | 29,812 |
|
Wholesale | 8,255 |
| — |
| 14,485 |
| — |
| (13,047 | ) | 9,693 |
| 8,255 |
| — |
| 15,373 |
| — |
| (13,935 | ) | 9,693 |
|
Market - off-system sales | 9,059 |
| 140 |
| — |
| — |
| (1,349 | ) | 7,850 |
| 9,059 |
| 140 |
| — |
| — |
| (1,349 | ) | 7,850 |
|
Transmission/Other | 10,196 |
| 11,887 |
| — |
| — |
| (3,693 | ) | 18,390 |
| 10,196 |
| 11,887 |
| — |
| — |
| (3,693 | ) | 18,390 |
|
Revenue from contracts with customers | 184,559 |
| 130,665 |
| 14,485 |
| 16,751 |
| (26,297 | ) | 320,163 |
| $ | 184,559 |
| $ | 130,665 |
| $ | 15,373 |
| $ | 16,751 |
| $ | (27,185 | ) | $ | 320,163 |
|
Other revenues | 231 |
| 1,011 |
| 9,118 |
| 550 |
| (9,094 | ) | 1,816 |
| 231 |
| 1,011 |
| 9,118 |
| 550 |
| (9,094 | ) | 1,816 |
|
Total revenues | $ | 184,790 |
| $ | 131,676 |
| $ | 23,603 |
| $ | 17,301 |
| $ | (35,391 | ) | $ | 321,979 |
| |
Total Revenues | | $ | 184,790 |
| $ | 131,676 |
| $ | 24,491 |
| $ | 17,301 |
| $ | (36,279 | ) | $ | 321,979 |
|
| | |
Timing of revenue recognition: | | |
Timing of Revenue Recognition: | | |
Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 16,751 |
| $ | (7,941 | ) | $ | 8,810 |
| $ | — |
| $ | — |
| $ | — |
| $ | 16,751 |
| $ | (7,942 | ) | $ | 8,809 |
|
Services transferred over time | 184,559 |
| 130,665 |
| 14,485 |
| — |
| (18,356 | ) | 311,353 |
| 184,559 |
| 130,665 |
| 15,373 |
| — |
| (19,243 | ) | 311,354 |
|
Revenue from contracts with customers | $ | 184,559 |
| $ | 130,665 |
| $ | 14,485 |
| $ | 16,751 |
| $ | (26,297 | ) | $ | 320,163 |
| $ | 184,559 |
| $ | 130,665 |
| $ | 15,373 |
| $ | 16,751 |
| $ | (27,185 | ) | $ | 320,163 |
|
| | |
|
| | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
Customer types: | (in thousands) |
Retail | $ | 455,409 |
| $ | 567,715 |
| $ | — |
| $ | 43,249 |
| $ | (23,315 | ) | $ | 1,043,058 |
|
Transportation | — |
| 102,159 |
| — |
| — |
| (903 | ) | 101,256 |
|
Wholesale | 23,334 |
| — |
| 46,650 |
| — |
| (40,923 | ) | 29,061 |
|
Market - off-system sales | 16,592 |
| 517 |
| — |
| — |
| (5,047 | ) | 12,062 |
|
Transmission/Other | 42,865 |
| 35,767 |
| — |
| — |
| (12,608 | ) | 66,024 |
|
Revenue from contracts with customers | $ | 538,200 |
| $ | 706,158 |
| $ | 46,650 |
| $ | 43,249 |
| $ | (82,796 | ) | $ | 1,251,461 |
|
Other revenues | 2,465 |
| 1,135 |
| 29,114 |
| 1,777 |
| (28,706 | ) | 5,785 |
|
Total revenues | $ | 540,665 |
| $ | 707,293 |
| $ | 75,764 |
| $ | 45,026 |
| $ | (111,502 | ) | $ | 1,257,246 |
|
| | | | | | |
Timing of revenue recognition: | | | | | | |
Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 43,249 |
| $ | (23,315 | ) | $ | 19,934 |
|
Services transferred over time | 538,200 |
| 706,158 |
| 46,650 |
| — |
| (59,481 | ) | 1,231,527 |
|
Revenue from contracts with customers | $ | 538,200 |
| $ | 706,158 |
| $ | 46,650 |
| $ | 43,249 |
| $ | (82,796 | ) | $ | 1,251,461 |
|
| | | | | | |
|
| | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2018 | Electric Utilities | Gas Utilities | Power Generation (a) | Mining | Inter-company Revenues (a) | Total |
Customer Types: | | | | | | |
Retail | $ | 449,482 |
| $ | 565,816 |
| $ | — |
| $ | 49,653 |
| $ | (23,761 | ) | $ | 1,041,190 |
|
Transportation | — |
| 100,760 |
| — |
| — |
| (977 | ) | 99,783 |
|
Wholesale | 25,497 |
| — |
| 43,744 |
| — |
| (39,457 | ) | 29,784 |
|
Market - off-system sales | 18,142 |
| 728 |
| — |
| — |
| (5,531 | ) | 13,339 |
|
Transmission/Other | 36,622 |
| 36,230 |
| — |
| — |
| (10,967 | ) | 61,885 |
|
Revenue from contracts with customers | $ | 529,743 |
| $ | 703,534 |
| $ | 43,744 |
| $ | 49,653 |
| $ | (80,693 | ) | $ | 1,245,981 |
|
Other revenues | 2,218 |
| 3,106 |
| 27,429 |
| 1,675 |
| (27,337 | ) | 7,091 |
|
Total Revenues | $ | 531,961 |
| $ | 706,640 |
| $ | 71,173 |
| $ | 51,328 |
| $ | (108,030 | ) | $ | 1,253,072 |
|
| | | | | | |
Timing of Revenue Recognition: | | | | | | |
Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 49,653 |
| $ | (23,761 | ) | $ | 25,892 |
|
Services transferred over time | 529,743 |
| 703,534 |
| 43,744 |
| — |
| (56,932 | ) | 1,220,089 |
|
Revenue from contracts with customers | $ | 529,743 |
| $ | 703,534 |
| $ | 43,744 |
| $ | 49,653 |
| $ | (80,693 | ) | $ | 1,245,981 |
|
| | | | | | |
|
| | | | | | |
(a) | | | | | | Due to the changes in our segment disclosures discussed in Note 3, Power Generation Wholesale revenue was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation Wholesale revenue were offset by changes to eliminations in Inter-company Revenues within Corporate and Other and there was no impact to our consolidated Total Revenues. |
|
| | | | | | | | | | | | | | | | | | |
Nine Months Ended September 30, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
Customer types: | (in thousands) |
Retail | $ | 449,482 |
| $ | 565,816 |
| $ | — |
| $ | 49,653 |
| $ | (23,761 | ) | $ | 1,041,190 |
|
Transportation | — |
| 100,760 |
| — |
| — |
| (977 | ) | 99,783 |
|
Wholesale | 25,497 |
| — |
| 41,161 |
| — |
| (36,874 | ) | 29,784 |
|
Market - off-system sales | 18,142 |
| 728 |
| — |
| — |
| (5,531 | ) | 13,339 |
|
Transmission/Other | 36,622 |
| 36,230 |
| — |
| — |
| (10,967 | ) | 61,885 |
|
Revenue from contracts with customers | 529,743 |
| 703,534 |
| 41,161 |
| 49,653 |
| (78,110 | ) | 1,245,981 |
|
Other revenues | 2,218 |
| 3,106 |
| 27,429 |
| 1,675 |
| (27,337 | ) | 7,091 |
|
Total revenues | $ | 531,961 |
| $ | 706,640 |
| $ | 68,590 |
| $ | 51,328 |
| $ | (105,447 | ) | $ | 1,253,072 |
|
| | | | | | |
Timing of revenue recognition: | | | | | | |
Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 49,653 |
| $ | (23,761 | ) | $ | 25,892 |
|
Services transferred over time | 529,743 |
| 703,534 |
| 41,161 |
| — |
| (54,349 | ) | 1,220,089 |
|
Revenue from contracts with customers | $ | 529,743 |
| $ | 703,534 |
| $ | 41,161 |
| $ | 49,653 |
| $ | (78,110 | ) | $ | 1,245,981 |
|
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.
Revenue Not in Scope of ASC 606
Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.
Significant Judgments and Estimates
TCJA Revenue Reserve
The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers and approximately $21 million remains in reserve.
Unbilled Revenue
Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends.
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a revenue contract.
Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series15
We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.
(3) BUSINESS SEGMENT INFORMATION
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation.
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. Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.
Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).
The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.
Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income wereis as follows (in thousands): |
| | | | | | | | | | | | | | | | | |
| | | | | | | |
Three Months Ended September 30, 2019 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | |
Electric Utilities | $ | 185,811 |
| $ | 234 |
|
| $ | 5,339 |
| $ | — |
|
| $ | 191,384 |
|
Gas Utilities | 129,385 |
| 810 |
|
| 549 |
| — |
|
| 130,744 |
|
Power Generation | 1,703 |
| 531 |
|
| 14,415 |
| 9,162 |
|
| 25,811 |
|
Mining | 6,846 |
| 228 |
|
| 8,146 |
| 332 |
|
| 15,552 |
|
Inter-company eliminations | — |
| — |
| | (28,449 | ) | (9,494 | ) | | (37,943 | ) |
Total | $ | 323,745 |
| $ | 1,803 |
| | $ | — |
| $ | — |
| | $ | 325,548 |
|
|
| | | | | | | | | | | | | | | | | |
| | | | | | | |
Three Months Ended September 30, 2018 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | |
Electric Utilities | $ | 179,527 |
| $ | 231 |
| | $ | 5,032 |
| $ | — |
| | $ | 184,790 |
|
Gas Utilities | 130,390 |
| 1,011 |
| | 275 |
| — |
| | 131,676 |
|
Power Generation (a) | 1,437 |
| 348 |
| | 13,936 |
| 8,770 |
| | 24,491 |
|
Mining | 8,809 |
| 226 |
| | 7,942 |
| 324 |
| | 17,301 |
|
Inter-company eliminations (a) | — |
| — |
| | (27,185 | ) | (9,094 | ) | | (36,279 | ) |
Total | $ | 320,163 |
| $ | 1,816 |
| | $ | — |
| $ | — |
| | $ | 321,979 |
|
| | Three Months Ended September 30, 2018 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues | | Net income (loss) from continuing operations | |
Contract Customers | Other Revenues | Contract Customers | Other Revenues | |
Nine Months Ended September 30, 2019 | | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
| Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | | | | | | |
Electric Utilities | $ | 179,527 |
| $ | 231 |
|
| $ | 5,032 |
| $ | — |
|
| $ | 184,790 |
|
| $ | 21,578 |
| $ | 521,614 |
| $ | 2,465 |
| | $ | 16,586 |
| $ | — |
| | $ | 540,665 |
|
Gas Utilities | 130,390 |
| 1,011 |
|
| 275 |
| — |
|
| 131,676 |
|
| (13,277 | ) | 704,188 |
| 1,134 |
| | 1,971 |
| — |
| | 707,293 |
|
Power Generation (b) | 1,437 |
| 348 |
|
| 13,048 |
| 8,770 |
|
| 23,603 |
|
| 6,691 |
| 5,725 |
| 1,401 |
| | 40,924 |
| 27,714 |
| | 75,764 |
|
Mining | 8,809 |
| 226 |
|
| 7,942 |
| 324 |
|
| 17,301 |
|
| 3,572 |
| 19,934 |
| 785 |
| | 23,315 |
| 992 |
| | 45,026 |
|
Corporate and Other | — |
| — |
|
| — |
| — |
|
| — |
|
| (757 | ) | |
Inter-company eliminations | — |
| — |
| | (26,297 | ) | (9,094 | ) | | (35,391 | ) | | — |
| — |
| — |
| | (82,796 | ) | (28,706 | ) | | (111,502 | ) |
Total | $ | 320,163 |
| $ | 1,816 |
| | $ | — |
| $ | — |
| | $ | 321,979 |
| | $ | 17,807 |
| $ | 1,251,461 |
| $ | 5,785 |
| | $ | — |
| $ | — |
| | $ | 1,257,246 |
|
|
| | | | | | | | | | | | | | | | | |
| | | | | | | |
Nine Months Ended September 30, 2018 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | |
Electric Utilities | $ | 513,270 |
| $ | 2,218 |
| | $ | 16,473 |
| $ | — |
| | $ | 531,961 |
|
Gas Utilities | 702,532 |
| 3,106 |
| | 1,002 |
| — |
| | 706,640 |
|
Power Generation (a) | 4,287 |
| 1,066 |
| | 39,457 |
| 26,363 |
| | 71,173 |
|
Mining | 25,892 |
| 701 |
| | 23,761 |
| 974 |
| | 51,328 |
|
Inter-company eliminations (a) | — |
| — |
| | (80,693 | ) | (27,337 | ) | | (108,030 | ) |
Total | $ | 1,245,981 |
| $ | 7,091 |
| | $ | — |
| $ | — |
| | $ | 1,253,072 |
|
Under our modified retrospective adoption
| |
(a) | Due to the changes in our segment disclosures, Power Generation Inter-company Operating Revenue for Contract Customers was revised for the three and nine months ended September 30, 2018 which resulted in an increase of $0.9 million and $2.6 million, respectively. The changes to Power Generation were offset by changes to Inter-company eliminations within Corporate and Other and there was no impact on our consolidated Total revenues. |
|
| | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | External Operating Revenue | | Inter-company Operating Revenue | | Net income (loss) from continuing operations |
|
| Segment: | | | | | |
| Electric Utilities | $ | 181,238 |
| | $ | 2,333 |
| | $ | 27,324 |
|
| Gas Utilities | 142,821 |
| | 73 |
| | (4,329 | ) |
| Power Generation (b) | 1,810 |
| | 21,117 |
| | 6,155 |
|
| Mining | 9,742 |
| | 7,751 |
| | 3,477 |
|
| Corporate and Other | — |
| | — |
| | (3,664 | ) |
| Inter-company eliminations | — |
| | (31,274 | ) | | — |
|
| Total | $ | 335,611 |
| | $ | — |
| | $ | 28,963 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
Nine Months Ended September 30, 2018 | External Operating Revenue | | Inter-company Operating Revenue | | Total Revenues | | Net income (loss) from continuing operations |
Contract Customers | Other Revenues | Contract Customers | Other Revenues |
Segment: | | | | | | | | | |
Electric Utilities | $ | 513,270 |
| $ | 2,218 |
| | $ | 16,473 |
| $ | — |
| | $ | 531,961 |
| | $ | 63,313 |
|
Gas Utilities (a) | 702,532 |
| 3,106 |
| | 1,002 |
| — |
| | 706,640 |
| | 93,182 |
|
Power Generation (b) | 4,287 |
| 1,066 |
| | 36,874 |
| 26,363 |
| | 68,590 |
| | 17,319 |
|
Mining | 25,892 |
| 701 |
| | 23,761 |
| 974 |
| | 51,328 |
| | 9,561 |
|
Corporate and Other | — |
| — |
| | — |
| — |
| | — |
| | (5,877 | ) |
Inter-company eliminations | — |
| — |
| | (78,110 | ) | (27,337 | ) | | (105,447 | ) | | — |
|
Total | $ | 1,245,981 |
| $ | 7,091 |
| | $ | — |
| $ | — |
| | $ | 1,253,072 |
| | $ | 177,498 |
|
|
| | | | | | | | | | | | |
| | | | | | |
| Nine Months Ended September 30, 2017 | External Operating Revenue | | Inter-company Operating Revenue | | Net income (loss) from continuing operations |
|
| Segment: | | | | | |
| Electric Utilities | $ | 518,925 |
| | $ | 9,123 |
| | $ | 68,386 |
|
| Gas Utilities | 674,161 |
| | 90 |
| | 41,409 |
|
| Power Generation (b) | 5,382 |
| | 62,907 |
| | 18,017 |
|
| Mining | 26,500 |
| | 22,485 |
| | 9,048 |
|
| Corporate and Other (c) | — |
| | — |
| | (6,994 | ) |
| Inter-company eliminations | — |
| | (94,605 | ) | | — |
|
| Total | $ | 1,224,968 |
| | $ | — |
| | $ | 129,866 |
|
|
| | | | | | | | | | | | |
| | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | 2019 | 2018 |
Adjusted operating income: | | | | |
Electric Utilities (a) | $ | 50,653 |
| $ | 43,393 |
| $ | 125,219 |
| $ | 123,073 |
|
Gas Utilities | 4,736 |
| 4,240 |
| 116,607 |
| 116,168 |
|
Power Generation (a) | 11,822 |
| 13,079 |
| 33,945 |
| 33,731 |
|
Mining | 3,374 |
| 4,551 |
| 9,351 |
| 12,647 |
|
Corporate and Other (a) | (34 | ) | (178 | ) | (439 | ) | (2,709 | ) |
Operating income | 70,551 |
| 65,085 |
| 284,683 |
| 282,910 |
|
| | | | |
Interest expense, net | (33,487 | ) | (35,297 | ) | (102,469 | ) | (104,826 | ) |
Impairment of investment | (19,741 | ) | — |
| (19,741 | ) | — |
|
Other income (expense), net | 580 |
| (510 | ) | 55 |
| (1,923 | ) |
Income tax benefit (expense) (b) | (2,508 | ) | (7,477 | ) | (22,078 | ) | 11,784 |
|
Income from continuing operations | 15,395 |
| 21,801 |
| 140,450 |
| 187,945 |
|
Net (loss) from discontinued operations | — |
| (857 | ) | — |
| (5,627 | ) |
Net income | 15,395 |
| 20,944 |
| 140,450 |
| 182,318 |
|
Net income attributable to noncontrolling interest | (3,655 | ) | (3,994 | ) | (10,319 | ) | (10,447 | ) |
Net income available for common stock | $ | 11,740 |
| $ | 16,950 |
| $ | 130,131 |
| $ | 171,871 |
|
___________
| |
(a) | NetDue to the changes in our segment disclosures, Adjusted operating income from continuing operations availablewas revised for common stockthe three and nine months ended September 30, 2018, which resulted in an increase (decrease) as follows (in millions):
|
|
| | | | | | |
Segment | Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2018 |
Electric Utilities | $ | 1.6 |
| $ | 4.8 |
|
Power Generation | (1.4 | ) | (4.4 | ) |
Corporate and Other | (0.2 | ) | (0.4 | ) |
| $ | — |
| $ | — |
|
| |
(b) | Income tax benefit (expense) for the nine months ended September 30, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements18 for more information. |
| |
(b) | Net income from continuing operations available for common stock for the three and nine months ended September 30, 2018 and September 30, 2017 reflects net income attributable to noncontrolling interests of $4.0 million and $10.4 million, and $3.9 million and $10.6 million, respectively. |
| |
(c) | Net income (loss) from continuing operations available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. |
Segment information and Corporate and Other balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
|
| | | | | | | |
Total assets (net of inter-company eliminations) as of: | September 30, 2019 | | December 31, 2018 |
Segment: | | | |
Electric Utilities (a) | $ | 2,810,108 |
| | $ | 2,707,695 |
|
Gas Utilities | 3,797,941 |
| | 3,623,475 |
|
Power Generation (a) | 414,526 |
| | 342,085 |
|
Mining | 78,073 |
| | 80,594 |
|
Corporate and Other | 174,302 |
| | 209,478 |
|
Total assets | $ | 7,274,950 |
| | $ | 6,963,327 |
|
|
| | | | | | | | | | | |
Total Assets (net of inter-company eliminations) as of: | September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
Segment: | | | | | |
Electric Utilities (a) | $ | 2,853,414 |
| | $ | 2,906,275 |
| | $ | 2,911,919 |
|
Gas Utilities | 3,433,316 |
| | 3,426,466 |
| | 3,288,104 |
|
Power Generation (a) | 122,428 |
| | 60,852 |
| | 64,357 |
|
Mining | 72,602 |
| | 65,455 |
| | 66,700 |
|
Corporate and Other | 177,324 |
| | 115,612 |
| | 115,330 |
|
Discontinued operations | 2,854 |
| | 84,242 |
| | 117,338 |
|
Total assets | $ | 6,661,938 |
| | $ | 6,658,902 |
| | $ | 6,563,748 |
|
_____________________
| |
(a) | The PPA under which Black Hills Colorado IPP provides generationDue to support Coloradothe changes in our segment disclosures, Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by ourUtilities and Power Generation segment are recorded at Colorado ElectricTotal assets were revised as a capital lease.of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets. |
(4) ACCOUNTS RECEIVABLE
Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | Accounts | Unbilled | Less Allowance for | Accounts | Accounts | Unbilled | Less Allowance for | Accounts |
September 30, 2018 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | |
September 30, 2019 | | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
Electric Utilities | $ | 43,108 |
| $ | 31,381 |
| $ | (386 | ) | $ | 74,103 |
| $ | 39,151 |
| $ | 31,843 |
| $ | (500 | ) | $ | 70,494 |
|
Gas Utilities | 48,638 |
| 24,768 |
| (2,188 | ) | 71,218 |
| 46,265 |
| 24,091 |
| (2,490 | ) | 67,866 |
|
Power Generation | 1,696 |
| — |
| — |
| 1,696 |
| 2,733 |
| — |
| — |
| 2,733 |
|
Mining | 3,749 |
| — |
| — |
| 3,749 |
| 1,804 |
| — |
| — |
| 1,804 |
|
Corporate | 2,030 |
| — |
| — |
| 2,030 |
| 6,261 |
| — |
| (169 | ) | 6,092 |
|
Total | $ | 99,221 |
| $ | 56,149 |
| $ | (2,574 | ) | $ | 152,796 |
| $ | 96,214 |
| $ | 55,934 |
| $ | (3,159 | ) | $ | 148,989 |
|
| | | Accounts | Unbilled | Less Allowance for | Accounts | Accounts | Unbilled | Less Allowance for | Accounts |
December 31, 2017 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | |
December 31, 2018 | | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
Electric Utilities | $ | 39,347 |
| $ | 36,384 |
| $ | (586 | ) | $ | 75,145 |
| $ | 39,721 |
| $ | 35,125 |
| $ | (448 | ) | $ | 74,398 |
|
Gas Utilities | 81,256 |
| 88,967 |
| (2,495 | ) | 167,728 |
| 96,123 |
| 90,521 |
| (2,592 | ) | 184,052 |
|
Power Generation | 1,196 |
| — |
| — |
| 1,196 |
| 1,876 |
| — |
| — |
| 1,876 |
|
Mining | 2,804 |
| — |
| — |
| 2,804 |
| 3,988 |
| — |
| — |
| 3,988 |
|
Corporate | 1,457 |
| — |
| — |
| 1,457 |
| 5,008 |
| — |
| (169 | ) | 4,839 |
|
Total | $ | 126,060 |
| $ | 125,351 |
| $ | (3,081 | ) | $ | 248,330 |
| $ | 146,716 |
| $ | 125,646 |
| $ | (3,209 | ) | $ | 269,153 |
|
|
| | | | | | | | | | | | |
| Accounts | Unbilled | Less Allowance for | Accounts |
September 30, 2017 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
Electric Utilities | $ | 42,716 |
| $ | 29,762 |
| $ | (494 | ) | $ | 71,984 |
|
Gas Utilities | 49,842 |
| 24,516 |
| (1,190 | ) | 73,168 |
|
Power Generation | 1,010 |
| — |
| — |
| 1,010 |
|
Mining | 3,534 |
| — |
| — |
| 3,534 |
|
Corporate | 629 |
| — |
| — |
| 629 |
|
Total | $ | 97,731 |
| $ | 54,278 |
| $ | (1,684 | ) | $ | 150,325 |
|
(5) REGULATORY ACCOUNTING
We had the following regulatory assets and liabilities (in thousands) as of: | | | September 30, 2018 | December 31, 2017 | September 30, 2017 | September 30, 2019 | December 31, 2018 |
Regulatory assets | | |
Deferred energy and fuel cost adjustments (a) | $ | 29,976 |
| $ | 20,187 |
| $ | 20,559 |
| $ | 31,832 |
| $ | 29,661 |
|
Deferred gas cost adjustments (a) | 720 |
| 31,844 |
| 12,833 |
| 3,899 |
| 3,362 |
|
Gas price derivatives (a) | 6,192 |
| 11,935 |
| 11,297 |
| 4,296 |
| 6,201 |
|
Deferred taxes on AFUDC (b) | 7,804 |
| 7,847 |
| 15,645 |
| 7,691 |
| 7,841 |
|
Employee benefit plans (c) | 106,734 |
| 109,235 |
| 105,671 |
| 107,921 |
| 110,524 |
|
Environmental (a) | 972 |
| 1,031 |
| 1,051 |
| 917 |
| 959 |
|
Asset retirement obligations (a) | 526 |
| 517 |
| 514 |
| |
Loss on reacquired debt (a) | 21,431 |
| 20,667 |
| 21,067 |
| 19,710 |
| 21,001 |
|
Renewable energy standard adjustment (a) | 1,131 |
| 1,088 |
| 1,956 |
| 2,871 |
| 1,722 |
|
Deferred taxes on flow through accounting (c) (e) | 29,342 |
| 26,978 |
| 41,900 |
| |
Deferred taxes on flow through accounting (c) | | 37,609 |
| 31,044 |
|
Decommissioning costs (b) | 11,052 |
| 13,287 |
| 13,989 |
| 11,206 |
| 11,700 |
|
Gas supply contract termination (a) | 15,745 |
| 20,001 |
| 21,402 |
| 9,953 |
| 14,310 |
|
Other regulatory assets (a) | 28,725 |
| 32,837 |
| 32,710 |
| 22,453 |
| 45,910 |
|
Total regulatory assets | 260,350 |
| 297,454 |
| 300,594 |
| 260,358 |
| 284,235 |
|
Less current regulatory assets | (48,302 | ) | (81,016 | ) | (61,023 | ) | (46,206 | ) | (48,776 | ) |
Regulatory assets, non-current | $ | 212,048 |
| $ | 216,438 |
| $ | 239,571 |
| $ | 214,152 |
| $ | 235,459 |
|
| | |
Regulatory liabilities | | |
Deferred energy and gas costs (a) | $ | 15,980 |
| $ | 3,427 |
| $ | 3,780 |
| $ | 9,919 |
| $ | 6,991 |
|
Employee benefit plan costs and related deferred taxes (c) (e) | 39,332 |
| 40,629 |
| 66,620 |
| |
Employee benefit plan costs and related deferred taxes (c) | | 42,737 |
| 42,533 |
|
Cost of removal (a) | 146,177 |
| 130,932 |
| 125,360 |
| 162,169 |
| 150,123 |
|
Excess deferred income taxes (c) (d) | 316,625 |
| 301,553 |
| 52 |
| |
Excess deferred income taxes (c) | | 286,587 |
| 310,562 |
|
TCJA revenue reserve | 20,592 |
| — |
| — |
| 2,770 |
| 18,032 |
|
Other regulatory liabilities (c) | 11,582 |
| 8,585 |
| 9,419 |
| 19,759 |
| 12,553 |
|
Total regulatory liabilities | 550,288 |
| 485,126 |
| 205,231 |
| 523,941 |
| 540,794 |
|
Less current regulatory liabilities | (41,442 | ) | (6,832 | ) | (7,042 | ) | (25,168 | ) | (29,810 | ) |
Regulatory liabilities, non-current | $ | 508,846 |
| $ | 478,294 |
| $ | 198,189 |
| $ | 498,773 |
| $ | 510,984 |
|
__________
| |
(a) | RecoveryWe are allowed recovery of costs, but we are not allowed a rate of return. |
| |
(b) | In addition to recovery of costs, we are allowed a rate of return. |
| |
(c) | In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. |
| |
(d) | The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of September 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets. |
| |
(e) | The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA. |
Regulatory Matters
Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 20172018 Annual Report on Form 10-K.
20
TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact
Regulatory Activity
Wyoming Gas
On June 13, 2019, we received approval from the change in the federal tax rate from 35%WPSC to 21% (including the effectsconsolidate our Wyoming gas utility operations into a new utility entity. The Wyoming portion of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating withGas Distribution, LLC, Cheyenne Light’s natural gas utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimatedoperations (Cheyenne Gas and recorded a reserve to revenue of approximately $6.0 millionNortheast Wyoming), and $29 million during the three and nine months ended September 30, 2018, respectively. As of September 30, 2018, $7.9 million has been returned to customers.
A list of states where benefits to customers of federal tax reform have been approved is summarized below.
|
| | | | |
State | Approximate 2018 Benefit for Customers | Start Date for Customer Benefits |
Arkansas | $ | 9.7 | million | October 2018 |
Colorado | $ | 10.8 | million | July 2018 |
Iowa | $ | 2.4 | million | June 2018 |
Kansas | $ | 1.9 | million | April 2018 |
Nebraska | $ | 3.8 | million | July 2018 |
South Dakota | $ | 7.7 | million | October 2018 |
In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) were combined into a new company called Black Hills Wyoming Gas, LLC. On June 3, 2019, Wyoming Gas filed a rate review application with the WPSC to consolidate the rates, tariffs and Rocky Mountain Natural Gas (a pipeline systemservices of its 4 existing gas distribution territories in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.
Rate Reviews
RMNG
In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action.Wyoming. The settlement included $1.1rate review requests $16 million in annualnew revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increaseinvestments in safety, reliability and system integrity. Wyoming Gas is based onalso requesting a return on equity of 9.9%new rider mechanism to recover future safety and a capital structure of 46.63% equityintegrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.
Wyoming Gas
On July 16, 2018,filed with the WPSC reachedon November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a bench decision approving ourexpected by the end of 2019.
South Dakota Electric and Wyoming Gas (Northwest Wyoming) settlementElectric
South Dakota Electric and stipulationWyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the 2 electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the OCA. We receivedSDPUC an amendment seeking approval to increase the final order ingenerating capacity under the third quartertariff for the South Dakota portion by 12.5 MW to a total of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.32.5 MW.
Arkansas GasNebraska
On October 5, 2018, Arkansas29, 2019, Nebraska Gas received approval from the APSC for a generalNPSC to merge its 2 gas distribution companies in Nebraska. A rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gasreview is expected to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.
Wyoming Electric
On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Applicationbe filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide an aggregate $7.0 million in customer credits through the PCA mechanism in 2018, 2019 andby mid-year 2020 to resolve all outstanding issues relating toconsolidate the rates, tariffs and services of its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of September 30, 2018, we have recorded a liability of $4.5 million related to the PCA.2 existing gas distribution companies.
Kansas
Nebraska Gas
On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NSPC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.
Kansas Gas
On June 19, 2018,25, 2019, Kansas Gas received approval from the Kansas Corporation Commission to doublefor an annual eligible investments upincrease in revenue of $1.4 million, effective July 1, 2019, based on updates to $8.0 million for safety related integrity investments under the Gas System Reliability rider.Surcharge Rider.
Wyoming Electric
On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.
Colorado
On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020.
(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:
|
| | | | | | | |
| September 30, 2019 | | December 31, 2018 |
Materials and supplies | $ | 81,382 |
| | $ | 75,081 |
|
Fuel - Electric Utilities | 2,535 |
| | 2,850 |
|
Natural gas in storage held for distribution | 39,085 |
| | 39,368 |
|
Total materials, supplies and fuel | $ | 123,002 |
| | $ | 117,299 |
|
|
| | | | | | | | | | | |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
Materials and supplies | $ | 73,777 |
| | $ | 69,732 |
| | $ | 70,284 |
|
Fuel - Electric Utilities | 2,750 |
| | 2,962 |
| | 2,993 |
|
Natural gas in storage held for distribution | 46,091 |
| | 40,589 |
| | 49,589 |
|
Total materials, supplies and fuel | $ | 122,618 |
| | $ | 113,283 |
| | $ | 122,866 |
|
(7) INVESTMENTS
In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of September 30, 2018.
The following table presents the carrying value of our investments (in thousands) as of:
|
| | | | | | | | | | | |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
Cost method investment | $ | 28,134 |
| | $ | — |
| | $ | — |
|
Cash surrender value of life insurance contracts | 13,068 |
| | 13,090 |
| | 12,947 |
|
Total investments | $ | 41,202 |
| | $ | 13,090 |
| | $ | 12,947 |
|
(87) 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):
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | 2018 | | 2019 | 2018 |
| | | | | |
Net income available for common stock | $ | 11,740 |
| $ | 16,950 |
| | $ | 130,131 |
| $ | 171,871 |
|
| | | | | |
Weighted average shares - basic | 60,976 |
| 53,364 |
| | 60,458 |
| 53,346 |
|
Dilutive effect of: | | | | | |
Equity Units (a) | — |
| 1,344 |
| | — |
| 1,060 |
|
Equity compensation | 128 |
| 111 |
| | 120 |
| 102 |
|
Weighted average shares - diluted | 61,104 |
| 54,819 |
| | 60,578 |
| 54,508 |
|
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
| | | | | |
Net income available for common stock | $ | 16,950 |
| $ | 27,663 |
| | $ | 171,871 |
| $ | 126,381 |
|
| | | | | |
Weighted average shares - basic | 53,364 |
| 53,243 |
| | 53,346 |
| 53,208 |
|
Dilutive effect of: | | | | | |
Equity Units (a) | 1,344 |
| 2,015 |
| | 1,060 |
| 1,872 |
|
Equity compensation | 111 |
| 174 |
| | 102 |
| 174 |
|
Weighted average shares - diluted | 54,819 |
| 55,432 |
| | 54,508 |
| 55,254 |
|
__________
| |
(a) | Calculated using the treasury stock method. On November 1, 2018, we completed settlement of the stock purchase contracts that were components of the Equity Units issued in November 2015. |
The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands):
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | 2018 | | 2019 | 2018 |
| | | | | |
Equity compensation | 2 |
| 12 |
| | 4 |
| 15 |
|
Restricted Stock | — |
| — |
| | 1 |
| — |
|
Anti-dilutive shares | 2 |
| 12 |
| | 5 |
| 15 |
|
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
| | | | | |
Equity compensation | 12 |
| — |
| | 15 |
| — |
|
Anti-dilutive shares | 12 |
| — |
| | 15 |
| — |
|
(98) NOTES PAYABLE, CURRENT MATURITIES AND DEBT
We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
|
| | | | | | | | | | | | |
| September 30, 2019 | December 31, 2018 |
| Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit |
Revolving Credit Facility | $ | 50,000 |
| $ | 18,313 |
| $ | — |
| $ | 22,311 |
|
CP Program | 244,900 |
| — |
| 185,620 |
| — |
|
Total | $ | 294,900 |
| $ | 18,313 |
| $ | 185,620 |
| $ | 22,311 |
|
|
| | | | | | | | | | | | | | | | | | |
| September 30, 2018 | December 31, 2017 | September 30, 2017 |
| Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit |
Revolving Credit Facility | $ | — |
| $ | 15,203 |
| $ | — |
| $ | 26,848 |
| $ | — |
| $ | 25,391 |
|
CP Program | 112,100 |
| — |
| 211,300 |
| — |
| 225,170 |
| — |
|
Total | $ | 112,100 |
| $ | 15,203 |
| $ | 211,300 |
| $ | 26,848 |
| $ | 225,170 |
| $ | 25,391 |
|
Revolving Credit Facility and CP Program
On July 30, 2018, we amended and restated ourOur $750 million corporate Revolving Credit Facility maintaining total commitments of $750 million and extending the termextends through July 30, 2023 with two one-year2, one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion.$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 Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at September 30, 2018.2019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P.2019.
We have 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 payments under the CP Programshort-term borrowings (payments) during the nine months ended September 30, 20182019 were $99 million and our notes outstanding as of$109 million. At September 30, 2018 were $112 million. As of September 30, 2018,2019, the weighted average interest rate on CP Programshort-term borrowings was 2.42%2.43%.
Debt Covenants
Under our Revolving Credit Facility and term loan agreement (before each was amended and restated),agreements, we wereare required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. At September 30, 2018, ourOur Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness, (which includedwhich includes letters of credit and certain guarantees issued, but excluded the RSNs), by (ii) Capital, which isincludes Consolidated Indebtedness plus Consolidated Net Worth, (which excludedwhich excludes noncontrolling interestsinterest in subsidiaries and included the aggregate outstanding amount of the RSNs). Under our amended and restated revolving Credit Facility and amended and restated term loan agreement, we are also required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00, but as of September 30, 2018 only, Consolidated Net Worth will include the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units, rather than the outstanding amount of the RSNs.
Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter:
|
| | | | |
| As of September 30, 2018 | | Covenant Requirement |
Consolidated Indebtedness to Capitalization Ratio | 61.4% | | Less than | 65% |
subsidiaries. As of September 30, 2018,2019, we were in compliance with this covenant.these covenants.
Current MaturitiesDebt Transaction
As of September 30, 2018, our $250 million senior unsecured notes due January 11,On June 17, 2019, and $5.7 million of principal due in the next twelve months onwe amended our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt on our Condensed Consolidated Balance Sheets.
Long-Term Debt
On August 17, 2018, we issuedJuly 30, 2020. This amendment increased total commitments to $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.
The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see subsequent event in Note 10). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).
On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, withfrom $300 million, outstanding at September 30, 2018, will now mature on July 30, 2020extended the term through June 17, 2021, and hashad substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated withnet proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for ourloan.
Subsequent Event - Debt Offering
On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured long-termnotes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:
Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;
Retire the $200 million 5.875% senior notes due July 15, 2020; and
Repay a portion of short-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.000% and 0.700%, respectively, at September 30, 2018.
(10)
(9) EQUITY
A summary of the changes in equity is as follows:
|
| | | | | | | | | |
Nine Months Ended September 30, 2018 | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity |
| | (in thousands) | |
Balance at December 31, 2017 | $ | 1,708,974 |
| $ | 111,232 |
| $ | 1,820,206 |
|
Net income (loss) | 171,871 |
| 10,447 |
| 182,318 |
|
Other comprehensive income | 3,481 |
| — |
| 3,481 |
|
Dividends on common stock | (76,309 | ) | — |
| (76,309 | ) |
Share-based compensation | 4,871 |
| — |
| 4,871 |
|
Dividend reinvestment and stock purchase plan | 220 |
| — |
| 220 |
|
Other stock transactions | 147 |
| — |
| 147 |
|
Distribution to noncontrolling interest | — |
| (13,755 | ) | (13,755 | ) |
Balance at September 30, 2018 | $ | 1,813,255 |
| $ | 107,924 |
| $ | 1,921,179 |
|
|
| | | | | | | | | |
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 |
|
Net income (loss) | 126,381 |
| 10,567 |
| 136,948 |
|
Other comprehensive income | 2,317 |
| — |
| 2,317 |
|
Dividends on common stock | (71,334 | ) | — |
| (71,334 | ) |
Share-based compensation | 5,853 |
| — |
| 5,853 |
|
Dividend reinvestment and stock purchase plan | 2,300 |
| — |
| 2,300 |
|
Redeemable noncontrolling interest | (886 | ) | — |
| (886 | ) |
Cumulative effect of ASU 2016-09 implementation | 3,714 |
| — |
| 3,714 |
|
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 |
|
At-the-Market Equity Offering Program
On August 4, 2017, we renewed ourOur ATM equity offering program which reset the size of the 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 program other than thewith an aggregate value increased from $200 millionof up 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 anyDuring the three months ended September 30, 2019, we issued a total of 389,237 shares of common shares duringstock under the ATM equity offering program for proceeds of $30 million, net of $0.3 million in commissions. During the nine months ended September 30, 2018 or September 30, 20172019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program.
Subsequent Event - Equity Units Settlement
On October 29, 2018, we announced the settlement rateprogram for the stock purchase contracts that are components of the Equity Units issued November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units.
Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299$99 million, net of $1.0 million in exchange for approximately 6.372 million shares of common stock. Proceeds will be used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.
commissions. As of November 1, 2018, after the Equity Units settlement, we hadSeptember 30, 2019, there were no shares outstanding of approximately 59.97 million.that were sold, but not settled.
(1110) RISK MANAGEMENT ACTIVITIES
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation 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 and Credit Policies and Procedures as discussed in our 20172018 Annual Report on Form 10-K.
Market Risk
Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to, the following market risks including, but not limited to:
Commodityto, commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain gas-fired generation assets; andassets.
Interest rate risk associated with our variable rate debt.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
For production and generationother than retail utility activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees,guaranties, prepayments, letters of credit, and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the 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 and any specific customer collection issue that is identified.
Our derivative and hedging activities recorded 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 1211.
Utilities
The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility 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’ 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 state commission guidelines. When the related costs are recovered through our rates, the hedging activity is 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 risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October 20182019 through May 2020;October 2021; a portion of these swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with 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 sold in the accompanying Condensed Consolidated Statements of Income.Sheets. Effectiveness of our hedginghedged position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter.
The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our utilities are composed of both long and short positions. We were in a net long position as of:
|
| | | | | | | | | |
| September 30, 2019 | | December 31, 2018 |
| Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) |
Natural gas futures purchased | 2,350,000 |
| | 15 | | 4,000,000 |
| | 24 |
Natural gas options purchased, net | 8,580,000 |
| | 6 | | 4,320,000 |
| | 13 |
Natural gas basis swaps purchased | 2,090,000 |
| | 15 | | 3,960,000 |
| | 24 |
Natural gas over-the-counter swaps, net (b) | 5,460,000 |
| | 25 | | 3,660,000 |
| | 24 |
Natural gas physical contracts, net (c) | 23,459,639 |
| | 6 | | 18,325,852 |
| | 30 |
|
| | | | | | | | | | | | | | |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
| Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) |
Natural gas futures purchased | 5,300,000 |
| | 27 | | 8,330,000 |
| | 36 | | 10,250,000 |
| | 39 |
Natural gas options purchased, net | 9,670,000 |
| | 16 | | 3,540,000 |
| | 14 | | 7,360,000 |
| | 17 |
Natural gas basis swaps purchased | 5,140,000 |
| | 27 | | 8,060,000 |
| | 36 | | 9,170,000 |
| | 39 |
Natural gas over-the-counter swaps, net (b) | 4,370,000 |
| | 20 | | 3,820,000 |
| | 29 | | 4,600,000 |
| | 20 |
Natural gas physical contracts, net (c) | 19,539,851 |
| | 33 | | 12,826,605 |
| | 35 | | 21,071,714 |
| | 38 |
__________
| |
(a) | Term reflects the maximum forward period hedged. |
| |
(b) | As of September 30, 2018, 2,236,0002019, 1,812,500 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. hedges. |
| |
(c) | Volumes exclude contracts that qualify for the normal purchase, normal sales exception. |
Based on September 30, 20182019 prices, a $0.1$0.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2018,2019, the Company posted $0.7$0.5 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets.
Financing Activities
At September 30, 2018, we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017.
Discontinued Operations
Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of September 30, 2018 or December 31, 2017. At September 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 54,000 Bbls, crude oil option contracts with notional volumes of 9,000 Bbls and natural gas futures and swap contracts with notional volumes of 540,000 MMBtus.
Cash Flow Hedges
The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 20182019 and 20172018. Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
|
| | | | | | |
Three Months Ended September 30, 2019 |
(in thousands) |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income |
Interest rate swaps | | Interest expense | | $ | (713 | ) |
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (129 | ) |
Total | | | | $ | (842 | ) |
|
| | | | | | |
Three Months Ended September 30, 2018 |
(in thousands) |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income |
Interest rate swaps | | Interest expense | | $ | (712 | ) |
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (18 | ) |
Total | | | | $ | (730 | ) |
|
| | | | | | |
Nine Months Ended September 30, 2019 |
(in thousands) |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income |
Interest rate swaps | | Interest expense | | $ | (2,139 | ) |
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | 508 |
|
Total | | | | $ | (1,631 | ) |
|
| | | | | | |
Nine Months Ended September 30, 2018 |
(in thousands) |
Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income |
Interest rate swaps | | Interest expense | | $ | (2,138 | ) |
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (802 | ) |
Total | | | | $ | (2,940 | ) |
The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2019 and 2018.
|
| | | | | | | |
| | | |
| Three Months Ended September 30, |
| 2019 | | 2018 |
| (in thousands) |
Increase (decrease) in fair value: | | | |
Forward commodity contracts | $ | (150 | ) | | $ | 30 |
|
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 713 |
| | 712 |
|
Forward commodity contracts | 129 |
| | 18 |
|
Total other comprehensive income (loss) from hedging | $ | 692 |
| | $ | 760 |
|
|
| | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | 2018 |
| (in thousands) |
Increase (decrease) in fair value: | | | |
Forward commodity contracts | $ | (434 | ) | | $ | (219 | ) |
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 2,139 |
| | 2,138 |
|
Forward commodity contracts | (508 | ) | | 802 |
|
Total other comprehensive income (loss) from hedging | $ | 1,197 |
| | $ | 2,721 |
|
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, 2019 and 2018 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
|
| | | | | | | | | | | | |
Three Months Ended September 30, 2018 |
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 | | $ | (712 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (18 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (730 | ) | | | | $ | — |
|
|
| | | | | | | | |
| | | | |
| | Three Months Ended September 30, |
| | 2019 | | 2018 |
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 | Fuel, purchased power and cost of natural gas sold | $ | (20 | ) | | $ | (96 | ) |
Commodity derivatives | Other income (expense), net | 142 |
| | — |
|
| | $ | 122 |
| | $ | (96 | ) |
|
| | | | | | | | | | | | |
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 | | Net (loss) from discontinued operations | | 295 |
| | Net (loss) from discontinued operations | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (34 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (452 | ) | | | | $ | — |
|
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2019 | | 2018 |
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 | Fuel, purchased power and cost of natural gas sold | $ | (1,180 | ) | | $ | 929 |
|
Commodity derivatives | Other income (expense), net | $ | 142 |
| | $ | — |
|
| | $ | (1,038 | ) | | $ | 929 |
|
|
| | | | | | | | | | | | |
| | | | | | | | |
Nine Months Ended September 30, 2018 |
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 | | $ | (2,138 | ) | | Interest expense | | $ | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (802 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (2,940 | ) | | | | $ | — |
|
|
| | | | | | | | | | | | |
| | | | | | | | |
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 | | Net (loss) from discontinued operations | | 954 |
| | Net (loss) from discontinued operations | | — |
|
Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (20 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
Total | | | | $ | (1,294 | ) | | | | $ | — |
|
The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2018 and 2017. The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred.
|
| | | | | | | |
| Three Months Ended September 30, |
| 2018 | | 2017 |
| (in thousands) |
Increase (decrease) in fair value: | | | |
Forward commodity contracts | $ | 30 |
| | $ | (254 | ) |
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 712 |
| | 713 |
|
Forward commodity contracts | 18 |
| | (261 | ) |
Total other comprehensive income (loss) from hedging | $ | 760 |
| | $ | 198 |
|
|
| | | | | | | |
| | | |
| Nine Months Ended September 30, |
| 2018 | | 2017 |
| (in thousands) |
Increase (decrease) in fair value: | | | |
Forward commodity contracts | $ | (219 | ) | | $ | 1,197 |
|
Recognition of (gains) losses in earnings due to settlements: | | | |
Interest rate swaps | 2,138 |
| | 2,228 |
|
Forward commodity contracts | 802 |
| | (934 | ) |
Total other comprehensive income (loss) from hedging | $ | 2,721 |
| | $ | 2,491 |
|
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, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
|
| | | | | | | | |
| | Three Months Ended September 30, |
| | 2018 | | 2017 |
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 | Net (loss) from discontinued operations | $ | — |
| | $ | (53 | ) |
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (96 | ) | | (322 | ) |
| | $ | (96 | ) | | $ | (375 | ) |
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2018 | | 2017 |
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 | Net (loss) from discontinued operations | $ | — |
| | $ | 90 |
|
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | 929 |
| | (1,822 | ) |
| | $ | 929 |
| | $ | (1,732 | ) |
As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assetsasset or Regulatory liability accounts related to the hedges in our utilities were $4.3 million and $6.2 million $12 million and $11 million atas of September 30, 2018,2019 and December 31, 2017 and September 30, 2017,2018, respectively.
(1211) FAIR VALUE MEASUREMENTS
Derivative Financial Instruments
The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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 20172018 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 Derivatives
Discontinued Operations:
Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18.
Utilities Segments:
The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2) for 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:Nonrecurring Fair Value Measurement
AsA discussion of September 30, 2018, we no longer have derivatives withinthe fair value of our corporate activities as our last interest rate swaps maturedinvestment in January 2017.equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 21.
Recurring Fair Value Measurements
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.
Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy present 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, 2019 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 2,750 |
| $ | — |
| | $ | (2,335 | ) | $ | 415 |
|
Total | $ | — |
| $ | 2,750 |
| $ | — |
| | $ | (2,335 | ) | $ | 415 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 6,080 |
| $ | — |
| | $ | (3,471 | ) | $ | 2,609 |
|
Total | $ | — |
| $ | 6,080 |
| $ | — |
| | $ | (3,471 | ) | $ | 2,609 |
|
|
| | | | | | | | | | | | | | | | |
| As of September 30, 2018 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 5,882 |
| $ | — |
| | $ | (4,469 | ) | $ | 1,413 |
|
Total | $ | — |
| $ | 5,882 |
| $ | — |
| | $ | (4,469 | ) | $ | 1,413 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 10,033 |
| $ | — |
| | $ | (8,777 | ) | $ | 1,256 |
|
Total | $ | — |
| $ | 10,033 |
| $ | — |
| | $ | (8,777 | ) | $ | 1,256 |
|
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2018 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 2,927 |
| $ | — |
| | $ | (1,408 | ) | $ | 1,519 |
|
Total | $ | — |
| $ | 2,927 |
| $ | — |
| | $ | (1,408 | ) | $ | 1,519 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 6,801 |
| $ | — |
| | $ | (5,794 | ) | $ | 1,007 |
|
Total | $ | — |
| $ | 6,801 |
| $ | — |
| | $ | (5,794 | ) | $ | 1,007 |
|
|
| | | | | | | | | | | | | | | | |
| As of December 31, 2017 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 1,586 |
| $ | — |
| | $ | (1,282 | ) | $ | 304 |
|
Total | $ | — |
| $ | 1,586 |
| $ | — |
| | $ | (1,282 | ) | $ | 304 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 13,756 |
| $ | — |
| | $ | (11,497 | ) | $ | 2,259 |
|
Total | $ | — |
| $ | 13,756 |
| $ | — |
| | $ | (11,497 | ) | $ | 2,259 |
|
|
| | | | | | | | | | | | | | | | |
| As of September 30, 2017 |
| Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| (in thousands) |
Assets: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 2,880 |
| $ | — |
| | $ | (2,448 | ) | $ | 432 |
|
Total | $ | — |
| $ | 2,880 |
| $ | — |
| | $ | (2,448 | ) | $ | 432 |
|
| | | | | | |
Liabilities: | | | | | | |
Commodity derivatives — Utilities | $ | — |
| $ | 12,647 |
| $ | — |
| | $ | (11,125 | ) | $ | 1,522 |
|
Total | $ | — |
| $ | 12,647 |
| $ | — |
| | $ | (11,125 | ) | $ | 1,522 |
|
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 presenttable presents the fair value and balance sheet classification of our derivative instruments (in thousands): as of:
|
| | | | | | | | |
As of September 30, 2018 |
| Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
Derivatives designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 142 |
| $ | — |
|
Commodity derivatives | Other assets, non-current | | 21 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 273 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 10 |
|
Total derivatives designated as hedges | | | $ | 163 |
| $ | 283 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 1,250 |
| $ | — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 881 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 92 |
|
Total derivatives not designated as hedges | | | $ | 1,250 |
| $ | 973 |
|
|
| | | | | | | | |
| Balance Sheet Location | | September 30, 2019 | December 31, 2018 |
Derivatives designated as hedges: | | | | |
Asset derivative instruments: | | | | |
Current commodity derivatives | Derivative assets — current | | $ | — |
| $ | 415 |
|
Noncurrent commodity derivatives | Other assets, non-current | | 2 |
| 18 |
|
Liability derivative instruments: | | | | |
Current commodity derivatives | Derivative liabilities — current | | (427 | ) | (114 | ) |
Noncurrent commodity derivatives | Other deferred credits and other liabilities | | (70 | ) | (4 | ) |
Total derivatives designated as hedges | | | $ | (495 | ) | $ | 315 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Asset derivative instruments: | | | | |
Current commodity derivatives | Derivative assets — current | | $ | 412 |
| $ | 1,085 |
|
Noncurrent commodity derivatives | Other assets, non-current | | 1 |
| 1 |
|
Liability derivative instruments: | | | | |
Current commodity derivatives | Derivative liabilities — current | | (1,969 | ) | (833 | ) |
Noncurrent commodity derivatives | Other deferred credits and other liabilities | | (143 | ) | (56 | ) |
Total derivatives not designated as hedges | | | $ | (1,699 | ) | $ | 197 |
|
|
| | | | | | | | |
As of December 31, 2017 |
| Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
Derivatives designated as hedges: | | | | |
Commodity derivatives | Derivative liabilities — current | | $ | — |
| $ | 817 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 67 |
|
Total derivatives designated as hedges | | | $ | — |
| $ | 884 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 304 |
| $ | — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 1,264 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 111 |
|
Total derivatives not designated as hedges | | | $ | 304 |
| $ | 1,375 |
|
|
| | | | | | | | |
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 | | $ | 2 |
| $ | — |
|
Commodity derivatives | Current assets held for sale | | 225 |
| — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 422 |
|
Commodity derivatives | Current liabilities held for sale | | — |
| 89 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 49 |
|
Commodity derivatives | Noncurrent liabilities held for sale | | — |
| 10 |
|
Total derivatives designated as hedges | | | $ | 227 |
| $ | 570 |
|
| | | | |
Derivatives not designated as hedges: | | | | |
Commodity derivatives | Derivative assets — current | | $ | 430 |
| $ | — |
|
Commodity derivatives | Derivative liabilities — current | | — |
| 1,036 |
|
Commodity derivatives | Other deferred credits and other liabilities | | — |
| 15 |
|
Commodity derivatives | Noncurrent liabilities held for sale | | — |
| 15 |
|
Total derivatives not designated as hedges | | | $ | 430 |
| $ | 1,066 |
|
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 18 to the Consolidated Financial Statements included in our 20172018 Annual Report on Form 10-K.
(1312) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of ourOther financial instruments excluding derivativesfor which are presented in Note 12,the carrying value did not equal fair value were as follows (in thousands) as of:
|
| | | | | | | | | | | | | | | | | | | | |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
| Carrying Amount | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 10,001 |
| $ | 10,001 |
| | $ | 15,420 |
| $ | 15,420 |
| | $ | 13,449 |
| $ | 13,449 |
|
Restricted cash (a) | $ | 3,241 |
| $ | 3,241 |
| | $ | 2,820 |
| $ | 2,820 |
| | $ | 2,683 |
| $ | 2,683 |
|
Notes payable (b) | $ | 112,100 |
| $ | 112,100 |
| | $ | 211,300 |
| $ | 211,300 |
| | $ | 225,170 |
| $ | 225,170 |
|
Long-term debt, including current maturities (c) (d) | $ | 3,207,132 |
| $ | 3,289,770 |
| | $ | 3,115,143 |
| $ | 3,350,544 |
| | $ | 3,115,607 |
| $ | 3,362,971 |
|
|
| | | | | | | | | | | | | |
| September 30, 2019 | | December 31, 2018 |
| Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Long-term debt, including current maturities (a) (b) | $ | 3,054,978 |
| $ | 3,424,747 |
| | $ | 2,956,578 |
| $ | 3,039,108 |
|
__________
| |
(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)(b) | Carrying amount of long-term debt is net of deferred financing costs. |
| |
(1413) | OTHER COMPREHENSIVE INCOME (LOSS) |
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 net income. The amounts in parentheses below indicate decreases to net 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 | Location on the Condensed Consolidated Statements of Income | Amount Reclassified from AOCI |
Three Months Ended | | Nine Months Ended | Three Months Ended | | Nine Months Ended |
September 30, 2018 | September 30, 2017 | | September 30, 2018 | September 30, 2017 | September 30, 2019 | September 30, 2018 | | September 30, 2019 | September 30, 2018 |
Gains and (losses) on cash flow hedges: | | | | | | | | |
Interest rate swaps | Interest expense | $ | (712 | ) | $ | (713 | ) | | $ | (2,138 | ) | $ | (2,228 | ) | Interest expense | $ | (713 | ) | $ | (712 | ) | | $ | (2,139 | ) | $ | (2,138 | ) |
Commodity contracts | Net (loss) from discontinued operations | — |
| 295 |
| | — |
| 954 |
| |
Commodity contracts | Fuel, purchased power and cost of natural gas sold
| (18 | ) | (34 | ) | | (802 | ) | (20 | ) | Fuel, purchased power and cost of natural gas sold
| (129 | ) | (18 | ) | | 508 |
| (802 | ) |
| | (730 | ) | (452 | ) | | (2,940 | ) | (1,294 | ) | | (842 | ) | (730 | ) | | (1,631 | ) | (2,940 | ) |
Income tax | Income tax benefit (expense) | 149 |
| 154 |
| | 643 |
| 435 |
| Income tax benefit (expense) | 170 |
| 149 |
| | 358 |
| 643 |
|
Total reclassification adjustments related to cash flow hedges, net of tax | | $ | (581 | ) | $ | (298 | ) | | $ | (2,297 | ) | $ | (859 | ) | | $ | (672 | ) | $ | (581 | ) | | $ | (1,273 | ) | $ | (2,297 | ) |
| | | | | | | | |
Amortization of components of defined benefit plans: | | | | | | | | |
Prior service cost | Operations and maintenance | $ | 44 |
| $ | 49 |
| | $ | 133 |
| $ | 146 |
| Operations and maintenance | $ | 20 |
| $ | 44 |
| | $ | 59 |
| $ | 133 |
|
| | | | | | | | |
Actuarial gain (loss) | Operations and maintenance | (621 | ) | (414 | ) | | (1,865 | ) | (1,242 | ) | Operations and maintenance | (84 | ) | (621 | ) | | (525 | ) | (1,865 | ) |
| | (577 | ) | (365 | ) | | (1,732 | ) | (1,096 | ) | | (64 | ) | (577 | ) | | (466 | ) | (1,732 | ) |
Income tax | Income tax benefit (expense) | 128 |
| 128 |
| | 380 |
| 393 |
| Income tax benefit (expense) | 89 |
| 128 |
| | 184 |
| 380 |
|
Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (449 | ) | $ | (237 | ) | | $ | (1,352 | ) | $ | (703 | ) | | $ | 25 |
| $ | (449 | ) | | $ | (282 | ) | $ | (1,352 | ) |
Total reclassifications | | $ | (1,030 | ) | $ | (535 | ) | | $ | (3,649 | ) | $ | (1,562 | ) | | $ | (647 | ) | $ | (1,030 | ) | | $ | (1,555 | ) | $ | (3,649 | ) |
Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
|
| | | | | | | | | | | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2018 | $ | (17,307 | ) | $ | 328 |
| $ | (9,937 | ) | $ | (26,916 | ) |
Other comprehensive income (loss) | | | | |
before reclassifications | — |
| (334 | ) | — |
| (334 | ) |
Amounts reclassified from AOCI | 1,639 |
| (366 | ) | 282 |
| 1,555 |
|
As of September 30, 2019 | $ | (15,668 | ) | $ | (372 | ) | $ | (9,655 | ) | $ | (25,695 | ) |
| | | | |
| | | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2017 | $ | (19,581 | ) | $ | (518 | ) | $ | (21,103 | ) | $ | (41,202 | ) |
Other comprehensive income (loss) | | | | |
before reclassifications | — |
| (168 | ) | — |
| (168 | ) |
Amounts reclassified from AOCI | 1,682 |
| 615 |
| 1,352 |
| 3,649 |
|
Reclassifications of certain tax effects from AOCI | 15 |
| — |
| 3 |
| 18 |
|
As of September 30, 2018 | $ | (17,884 | ) | $ | (71 | ) | $ | (19,748 | ) | $ | (37,703 | ) |
|
| | | | | | | | | | | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
As of December 31, 2017 | $ | (19,581 | ) | $ | (518 | ) | $ | (21,103 | ) | $ | (41,202 | ) |
Other comprehensive income (loss) | | | | |
before reclassifications | — |
| (168 | ) | — |
| (168 | ) |
Amounts reclassified from AOCI | 1,682 |
| 615 |
| 1,352 |
| 3,649 |
|
Reclassifications of certain tax effects from AOCI | 15 |
| — |
| 3 |
| 18 |
|
Ending Balance September 30, 2018 | $ | (17,884 | ) | $ | (71 | ) | $ | (19,748 | ) | $ | (37,703 | ) |
| | | | |
| | | | |
| Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
Balance 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 | ) |
(1514) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
| | | | | | | |
Nine Months Ended | September 30, 2019 | | September 30, 2018 |
| (in thousands) |
Non-cash investing and financing activities — | | | |
Property, plant and equipment acquired with accrued liabilities | $ | 86,661 |
| | $ | 49,631 |
|
| | | |
Cash (paid) refunded during the period — | | | |
Interest (net of amounts capitalized) | $ | (99,375 | ) | | $ | (104,035 | ) |
Income taxes | $ | 2,255 |
| | $ | (14,842 | ) |
|
| | | | | | | |
Nine Months Ended | September 30, 2018 | | September 30, 2017 |
| (in thousands) |
Non-cash investing and financing activities — | | | |
Property, plant and equipment acquired with accrued liabilities | $ | 49,631 |
| | $ | 33,409 |
|
Increase (decrease) in capitalized assets associated with asset retirement obligations | $ | 155 |
| | $ | 1,362 |
|
| | | |
Cash (paid) refunded during the period — | | | |
Interest (net of amounts capitalized) | $ | (104,035 | ) | | $ | (102,008 | ) |
Income taxes (paid) refunded | $ | (14,842 | ) | | $ | 1 |
|
(1615) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension Plan
The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands):
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | 2018 | | 2019 | 2018 |
Service cost | $ | 1,346 |
| $ | 1,708 |
| | $ | 4,037 |
| $ | 5,125 |
|
Interest cost | 4,344 |
| 3,867 |
| | 13,031 |
| 11,602 |
|
Expected return on plan assets | (6,100 | ) | (6,185 | ) | | (18,300 | ) | (18,555 | ) |
Prior service cost | 6 |
| 15 |
| | 19 |
| 44 |
|
Net loss (gain) | 941 |
| 2,158 |
| | 2,822 |
| 6,473 |
|
Net periodic benefit cost | $ | 537 |
| $ | 1,563 |
| | $ | 1,609 |
| $ | 4,689 |
|
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
Service cost | $ | 1,708 |
| $ | 1,759 |
| | $ | 5,125 |
| $ | 5,276 |
|
Interest cost | 3,867 |
| 3,880 |
| | 11,602 |
| 11,640 |
|
Expected return on plan assets | (6,185 | ) | (6,130 | ) | | (18,555 | ) | (18,388 | ) |
Prior service cost | 15 |
| 15 |
| | 44 |
| 44 |
|
Net loss (gain) | 2,158 |
| 1,002 |
| | 6,473 |
| 3,005 |
|
Net periodic benefit cost | $ | 1,563 |
| $ | 526 |
| | $ | 4,689 |
| $ | 1,577 |
|
Defined Benefit Postretirement Healthcare Plans
The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | 2018 | | 2019 | 2018 |
Service cost | $ | 454 |
| $ | 573 |
| | $ | 1,362 |
| $ | 1,718 |
|
Interest cost | 560 |
| 521 |
| | 1,683 |
| 1,563 |
|
Expected return on plan assets | (57 | ) | (57 | ) | | (172 | ) | (170 | ) |
Prior service cost (benefit) | (99 | ) | (99 | ) | | (298 | ) | (297 | ) |
Net loss (gain) | — |
| 54 |
| | — |
| 162 |
|
Net periodic benefit cost | $ | 858 |
| $ | 992 |
| | $ | 2,575 |
| $ | 2,976 |
|
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
Service cost | $ | 573 |
| $ | 575 |
| | $ | 1,718 |
| $ | 1,725 |
|
Interest cost | 521 |
| 533 |
| | 1,563 |
| 1,600 |
|
Expected return on plan assets | (57 | ) | (79 | ) | | (170 | ) | (237 | ) |
Prior service cost (benefit) | (99 | ) | (109 | ) | | (297 | ) | (327 | ) |
Net loss (gain) | 54 |
| 125 |
| | 162 |
| 375 |
|
Net periodic benefit cost | $ | 992 |
| $ | 1,045 |
| | $ | 2,976 |
| $ | 3,136 |
|
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 September 30, | | Nine Months Ended September 30, |
| 2019 | 2018 | | 2019 | 2018 |
Service cost | $ | 429 |
| $ | 632 |
| | $ | 2,406 |
| $ | 1,347 |
|
Interest cost | 324 |
| 293 |
| | 972 |
| 878 |
|
Prior service cost | — |
| — |
| | 1 |
| 1 |
|
Net loss (gain) | 134 |
| 250 |
| | 402 |
| 750 |
|
Net periodic benefit cost | $ | 887 |
| $ | 1,175 |
| | $ | 3,781 |
| $ | 2,976 |
|
|
| | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
Service cost | $ | 632 |
| $ | 612 |
| | $ | 1,347 |
| $ | 2,048 |
|
Interest cost | 293 |
| 319 |
| | 878 |
| 957 |
|
Prior service cost | — |
| — |
| | 1 |
| 1 |
|
Net loss (gain) | 250 |
| 251 |
| | 750 |
| 751 |
|
Net periodic benefit cost | $ | 1,175 |
| $ | 1,182 |
| | $ | 2,976 |
| $ | 3,757 |
|
For the three and nine months ended September 30, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three and nine months ended September 30, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information.
Contributions
Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 25, 2018, we made a contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 20182019 and anticipated contributions for 20182019 and 20192020 are as follows (in thousands):
|
| | | | | | | | | | | | |
| Contributions Made | Contributions Made | Additional Contributions | Contributions |
| Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 | Anticipated for 2019 | Anticipated for 2020 |
Defined Benefit Pension Plan | $ | 12,700 |
| $ | 12,700 |
| $ | — |
| $ | 12,700 |
|
Non-pension Defined Benefit Postretirement Healthcare Plans | $ | 1,109 |
| $ | 3,326 |
| $ | 1,109 |
| $ | 4,815 |
|
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | $ | 366 |
| $ | 1,098 |
| $ | 366 |
| $ | 1,406 |
|
|
| | | | | | | | | | | | |
| Contributions Made | Contributions Made | Additional Contributions | Contributions |
| Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2018 | Anticipated for 2018 | Anticipated for 2019 |
Defined Benefit Pension Plan | $ | 12,700 |
| $ | 12,700 |
| $ | — |
| $ | 12,700 |
|
Non-pension Defined Benefit Postretirement Healthcare Plans | $ | 1,234 |
| $ | 3,702 |
| $ | 1,234 |
| $ | 3,821 |
|
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | $ | 343 |
| $ | 1,029 |
| $ | 343 |
| $ | 1,623 |
|
(1716) COMMITMENTS AND CONTINGENCIES
There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 20172018 Annual Report on Form 10-K except for those described below.
Busch RanchFuture Purchase Agreement - Related Party
On August 2, 2019, Black Hills Wyoming and Wyoming Electric filed a request with FERC for approval of a new 60 MW PPA. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for 20 additional years. A decision from FERC is pending.
Busch Ranch Wind FarmPlatte River Power Authority PPAs
On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase up to 60 MW of wind energy upon construction completion of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.
On June 26, 2019, Colorado Electric entered into a PPA with Platte River Power Authority to purchase 25 MW of unit contingent energy. This agreement was effective September 1, 2019 and will expire June 30, 2024.
The following is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has a 50% ownership interest in the wind farm. On September 20, 2018, Black Hills Electric Generation agreed toschedule of unconditional purchase AltaGas’s 50% interest in Busch Ranch for $16 million. The purchase, which is subject to FERC approval, is expected to be finalized by the end of 2018.
Dividend Restrictions
Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of September 30, 2018, 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 companyrequired under the Federal25 MW Platte River Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. AsAuthority PPA as of September 30, 2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.2019 (in thousands):
|
| | | |
2019 | $ | 1,369 |
|
2020 | $ | 5,475 |
|
2021 | $ | 5,475 |
|
2022 | $ | 5,475 |
|
2023 | $ | 5,475 |
|
Thereafter | $ | 2,738 |
|
(18)
(17) DISCONTINUED OPERATIONS
Results of operations for discontinued operations have beenwere classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations havewere also been reclassified to reflect consistency within our condensed consolidated financial statements.
Oil and Gas Segment
On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As ofWe completed the divestiture in 2018. See Note 21 for more information.
(18) INCOME TAXES
Income tax benefit (expense) for the Three Months Ended September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by December 31, 2018.
In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent sales of assets and pending sale transactions of our other properties.
There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring after December 31, 2017.
At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no further adjustments made2019 Compared to the fair value of our held for sale assets atThree Months Ended September 30, 2018.
DuringIncome tax benefit (expense) for the ninethree months ended September 30, 2018, we recorded $2.92019 was $(2.5) million compared to $(7.5) million reported for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of expenses comprised of royalty payments and reclamation costs related to final closingtax reform on deferred income taxes.
For the sale of BHEP assets.
Total assets and liabilities of the Oil and Gas segment atthree months ended September 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on2019 the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by the end of 2018. Held for sale assets and liabilities at September 30, 2017 are classified as current and non-current (in thousands):
|
| | | | | | | | | |
| September 30, 2018 | December 31, 2017 | September 30, 2017 |
Other current assets | $ | 75 |
| $ | 10,360 |
| $ | 8,457 |
|
Derivative assets, current and noncurrent | — |
| — |
| 225 |
|
Deferred income tax assets, noncurrent, net
| — |
| 16,966 |
| 12,571 |
|
Property, plant and equipment, net | 2,779 |
| 56,916 |
| 96,085 |
|
Other current liabilities | (2,138 | ) | (18,966 | ) | (7,597 | ) |
Derivative liabilities, current and noncurrent | — |
| — |
| (114 | ) |
Deferred income tax liabilities, noncurrent, net
| (400 | ) | — |
| — |
|
Other noncurrent liabilities | — |
| (22,808 | ) | (23,319 | ) |
Net assets (liabilities) | $ | 316 |
| $ | 42,468 |
| $ | 86,308 |
|
At September 30, 2018, December 31, 2017 and September 30, 2017, the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties.
The Oil and Gas segment’s other current liabilities at September 30, 2018 consisted primarily of accrued royalties, payroll and property taxes. Current liabilities at December 31, 2017 consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at September 30, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 and September 30, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells.
(19) INCOME TAXES
The effective tax rate differs fromwas 14.0% compared to 7.6% excluding the federal statutorytax reform adjustments, for the same period in 2018. The higher effective tax rate as follows:is primarily due to a prior year state tax benefit.
|
| | | | |
| Three Months Ended September 30, |
Tax (benefit) expense | 2018 | 2017 |
Federal statutory rate | 21.0 | % | 35.0 | % |
State income tax (net of federal tax effect) (a) | (6.3 | ) | (3.4 | ) |
Percentage depletion in excess of cost | (0.5 | ) | (0.9 | ) |
Accounting for uncertain tax positions adjustment | — |
| (0.6 | ) |
Noncontrolling interest (b) | (1.3 | ) | (3.0 | ) |
Tax credits (c) | (5.3 | ) | (1.6 | ) |
Effective tax rate adjustment (d) | — |
| 3.9 |
|
Flow-through adjustments | (1.5 | ) | (1.6 | ) |
TCJA change in estimate (e) | 17.6 |
| — |
|
AFUDC equity | (0.1 | ) | — |
|
Other tax differences | 1.9 |
| 1.3 |
|
| 25.5 | % | 29.1 | % |
__________
| |
(a) | Adjustment to the deferred state rate and reduced state tax expense for the quarter. |
| |
(b) | The adjustment reflects the noncontrolling interest attributable to the sale in April 2016 of 49.9% of the membership interests of COIPP LLC. |
| |
(c) | The tax credits are due to the production tax credits for the Peak View wind farm. |
| |
(d) | Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. |
| |
(e) | The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended September 30, 2018, we recorded an additional $5.3 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. |
|
| | | | |
| | |
| Nine Months Ended September 30, |
Tax (benefit) expense | 2018 | 2017 |
Federal statutory rate | 21.0 | % | 35.0 | % |
State income tax (net of federal tax effect) | 0.4 |
| 0.3 |
|
Percentage depletion in excess of cost | (0.4 | ) | (0.6 | ) |
Accounting for uncertain tax positions adjustment | — |
| (0.2 | ) |
Noncontrolling interest | (1.1 | ) | (1.9 | ) |
IRC 172(f) carryback claim (a) | — |
| (1.0 | ) |
Tax credits (b) | (2.6 | ) | (1.6 | ) |
Effective tax rate adjustment | — |
| 0.3 |
|
Flow-through adjustments | (0.8 | ) | (1.2 | ) |
TCJA change in estimate (c) | 4.3 |
| — |
|
AFUDC equity | (0.1 | ) | — |
|
Jurisdictional simplification project (d) | (28.1 | ) | — |
|
Other tax differences | 0.7 |
| 0.3 |
|
| (6.7 | )% | 29.4 | % |
__________
| |
(a) | During the first quarter of 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. |
| |
(b) | The tax credits are due to the production tax credits for the Peak View wind farm. |
| |
(c) | The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the nine months ended September 30, 2018, we recorded an additional $7.5 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. |
| |
(d) | Tax benefit from legal restructuring associated with amortizable goodwill as part of jurisdictional simplification. |
Tax benefit related to legal restructuring
As part of the Company’s ongoing efforts to continue to integrate thelegal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to incomeIncome tax benefit (expense) onfor the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.
TCJA - Deferred Taxes
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuantNine Months Ended September 30, 2019 Compared to the TCJA. The amount of the settlements may change based on decisions and actions by the state regulatory commissions. In addition to current year utility revenue reserves as disclosed in Note 5, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plant and property items, after filing our 2017 tax returns which increased tax expense by $5.3 million for the three months, and decreasedNine Months Ended September 30, 2018.
Income tax benefit by $7.5 million(expense) for the nine months ended September 30, 2019 was $(22) million compared to $12 million reported for the same period in 2018. We will continueThe increase in tax expense was primarily due to evaluate subsequent regulations, clarificationsa prior year $49 million tax benefit resulting from legal entity restructuring partially offset by a prior year $(7.5) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.
For the nine months ended September 30, 2019 the effective tax rate was 13.6% compared to 17.1% excluding the legal entity restructuring and interpretationstax reform adjustments, for the same period in 2018. The lower effective tax rate is primarily due to $5.0 million of the assumptions made, which could change our estimatesfederal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to the TCJA, which we expect to finalize in the fourth quarter.tax reform.
(20)(19) ACCRUED LIABILITIES
The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
|
| | | | | | |
| September 30, 2019 | December 31, 2018 |
Accrued employee compensation, benefits and withholdings | $ | 57,313 |
| $ | 63,742 |
|
Accrued property taxes | 38,937 |
| 42,510 |
|
Customer deposits and prepayments | 56,220 |
| 43,574 |
|
Accrued interest and contract adjustment payments | 35,100 |
| 31,759 |
|
Other (none of which is individually significant) | 30,262 |
| 33,916 |
|
Total accrued liabilities | $ | 217,832 |
| $ | 215,501 |
|
|
| | | | | | | | | |
| September 30, 2018 | December 31, 2017 | September 30, 2017 |
Accrued employee compensation, benefits and withholdings | $ | 57,600 |
| $ | 52,467 |
| $ | 52,841 |
|
Accrued property taxes | 37,660 |
| 42,029 |
| 36,993 |
|
Customer deposits and prepayments | 42,002 |
| 44,420 |
| 41,012 |
|
Accrued interest and contract adjustment payments | 31,139 |
| 33,822 |
| 30,977 |
|
CIAC current portion | 1,552 |
| 1,552 |
| 1,575 |
|
Other (none of which is individually significant) | 31,400 |
| 45,172 |
| 43,381 |
|
Total accrued liabilities | $ | 201,353 |
| $ | 219,462 |
| $ | 206,779 |
|
(20) LEASES
Lessee
We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than one year to 37 years, including options to extend that are reasonably certain to be exercised.
The components of lease expense were as follows (in thousands):
|
| | | | | | | |
| Income Statement Location | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 |
Operating lease cost | Operations and maintenance | $ | 380 |
| $ | 1,076 |
|
Finance lease cost: | | | |
Amortization of right-of-use asset | Depreciation, depletion and amortization | 28 |
| 72 |
|
Interest on lease liabilities | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | 5 |
| 14 |
|
Total lease cost | | $ | 413 |
| $ | 1,162 |
|
Supplemental balance sheet information related to leases was as follows (in thousands):
|
| | | | |
| Balance Sheet Location | As of September 30, 2019 |
Assets: | | |
Operating lease assets | Other assets, non-current | $ | 4,864 |
|
Finance lease assets | Other assets, non-current | 493 |
|
Total lease assets | | $ | 5,357 |
|
| | |
Liabilities: | | |
Current: | | |
Operating leases | Accrued liabilities | $ | 970 |
|
Finance lease | Accrued liabilities | 80 |
|
| | |
Noncurrent: | | |
Operating leases | Other deferred credits and other liabilities | 4,252 |
|
Finance lease | Other deferred credits and other liabilities | 419 |
|
Total lease liabilities | | $ | 5,721 |
|
Supplemental cash flow information related to leases was as follows (in thousands):
|
| | | |
| Nine Months Ended September 30, 2019 |
Cash paid included in the measurement of lease liabilities: | |
Operating cash flows from operating leases | $ | 895 |
|
Operating cash flows from finance lease | $ | 14 |
|
Financing cash flows from finance lease | $ | 66 |
|
Right-of-use assets obtained in exchange for lease obligations: | |
Operating leases | $ | 2,775 |
|
Finance lease | $ | 67 |
|
|
| | |
| As of September 30, 2019 |
Weighted average remaining lease term (years): | |
Operating leases | 8 years |
|
Finance lease | 4 years |
|
| |
Weighted average discount rate: | |
Operating leases | 4.27 | % |
Finance lease | 4.19 | % |
As of September 30, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
|
| | | | | | | | | |
| Operating Leases | Finance Lease | Total |
2019 (a) | $ | 368 |
| $ | 32 |
| $ | 400 |
|
2020 | 992 |
| 126 |
| 1,118 |
|
2021 | 855 |
| 126 |
| 981 |
|
2022 | 736 |
| 126 |
| 862 |
|
2023 | 714 |
| 126 |
| 840 |
|
Thereafter | 2,682 |
| 10 |
| 2,692 |
|
Total lease payments (b) | $ | 6,347 |
| $ | 546 |
| $ | 6,893 |
|
Less imputed interest | 1,125 |
| 47 |
| 1,172 |
|
Present value of lease liabilities | $ | 5,222 |
| $ | 499 |
| $ | 5,721 |
|
| |
(a) | Includes lease liabilities for the remaining three months of 2019. |
| |
(b) | Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance. |
As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):
|
| | | |
| Operating Leases |
2019 | $ | 1,052 |
|
2020 | 464 |
|
2021 | 344 |
|
2022 | 224 |
|
2023 | 216 |
|
Thereafter | 1,776 |
|
Total lease payments | $ | 4,076 |
|
Lessor
We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.
The components of lease revenue were as follows (in thousands):
|
| | | | | | | |
| Income Statement Location | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 |
Operating lease income | Revenue | $ | 544 |
| $ | 1,749 |
|
As of September 30, 2019, scheduled maturities of lease receivables for future years were as follows (in thousands):
|
| | | |
| Operating Leases |
2019 (a) | $ | 551 |
|
2020 | 2,035 |
|
2021 | 1,857 |
|
2022 | 1,793 |
|
2023 | 1,799 |
|
Thereafter | 55,481 |
|
Total lease receivables | $ | 63,516 |
|
| |
(a) | Includes lease receivables for the remaining three months of 2019. |
(21) INVESTMENTS
In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested from our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.
During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three and nine months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment.
The following table presents the carrying value of our investments (in thousands) as of:
|
| | | | | | | |
| September 30, 2019 | | December 31, 2018 |
Investment in privately held oil and gas company | $ | 8,359 |
| | $ | 28,100 |
|
Cash surrender value of life insurance contracts | 12,907 |
| | 12,812 |
|
Other investments | 317 |
| | 101 |
|
Total investments | $ | 21,583 |
| | $ | 41,013 |
|
(22) SUBSEQUENT EVENTS
There are no subsequent events, other than those disclosed in Note 5 and Note 10.8.
| |
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
We are a customer-focused, growth-oriented utility company operating in the United States. We report our operations and results in the following financial segments:
Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 210,000212,000 customers in Colorado, Montana, South Dakota Wyoming, Colorado and Montana.Wyoming. 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 our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distribute and transport natural gas through our pipeline network to approximately 1,042,0001,054,000 natural gas customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as availableas-available basis.
Our Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 52,00047,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-approvedregulator-approved Choice Gas Program. We also sell, install and service air conditioning, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP provide appliance repair services to approximately 63,00062,000 and 31,00028,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.
Mining: Our Mining segment producesextracts coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.
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. All of our non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Effective January 1, 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 3 of the Notes to Condensed Consolidated Financial Statements for more information.
Certain industries 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 utilities is June through August while the normal peak usage season for our gas 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, 20182019 and 20172018, and our financial condition as of September 30, 2018,2019 and December 31, 2017 and September 30, 2017,2018, 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.
|
|
See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 6658. |
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.
Results of Operations
Executive Summary, Significant Events and Overview
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2019 | | 2018 | | 2019 | | 2018 |
(in millions, except per share amounts) | Income | EPS | | Income | EPS | | Income | EPS | | Income | EPS |
| | | | | | | | | | | |
Net income from continuing operations available for common stock | $ | 11.7 |
| $ | 0.19 |
| | $ | 17.8 |
| $ | 0.32 |
| | $ | 130.1 |
| $ | 2.15 |
| | $ | 177.5 |
| $ | 3.26 |
|
Net (loss) from discontinued operations | — |
| — |
| | (0.9 | ) | (0.02 | ) | | — |
| — |
| | (5.6 | ) | (0.10 | ) |
Net income available for common stock | $ | 11.7 |
| $ | 0.19 |
| | $ | 17.0 |
| $ | 0.31 |
| | $ | 130.1 |
| $ | 2.15 |
| | $ | 171.9 |
| $ | 3.15 |
|
Three Months Ended September 30, 20182019 Compared to Three Months Ended September 30, 2017. Net income from continuing operations available for common stock for the three months ended September 30, 2018 was $18 million, or $0.32 per diluted share, compared to $29 million, or $0.52 per diluted share, reported for the same period in 2017. 2018.
The variance to the prior year included the following:
Electric Utilities’ earnings decreased $5.7adjusted operating income increased $7.3 million primarily due ato the prior year Wyoming Electric PCA settlement, agreement with the WPSC which decreased gross margins by $3.4 million, unfavorablewarmer summer weather compared to prior year,in Colorado and Wyoming, increased industrial demand, and increased rider revenues partially offset by higher operating expenses driven by outside services and employee costs and $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;costs;
Gas Utilities’ earnings decreased $8.9adjusted operating income increased $0.5 million primarily due to unfavorable weather compared to prior year, higher operating expenses driven by employee costsnew rates, increased transport and outside servicestransmission, and $2.6 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes;
Power Generation’s earnings increased $0.5 million primarily due to the reduction in the federal tax rate from 35% to 21% from the TCJA; and
Corporate and Other expenses decreased $2.9 million due to lower interest expense and higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operations, largely allocated to operating segments in 2018.
Net income available for common stock for the three months ended September 30, 2018 was $17 million, or $0.31 per diluted share, compared to $28 million, or $0.50 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the three months ended September 30, 2018 was $(0.9) million, or $(0.02) per diluted share compared to $(1.3) million or $(0.02) per diluted share reported for the same period in 2017.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. Net income from continuing operations available for common stock for the nine months ended September 30, 2018 was $177 million, or $3.26 per diluted share, compared to $130 million, or $2.35 per diluted share, reported for the same period in 2017. The variance to the prior year included the following:
Gas Utilities’ earnings increased $52 million primarily due to the recognition of a deferred tax benefit of $49 million resulting fromlegal entity restructuring associated with amortizable goodwill for tax purposes; earnings also benefited from colder winter weather and increased sales of natural gas,customer growth partially offset by an increase in operating expenses;
Electric Utilities’ earnings decreased $5.1 millionlower heating demand from warmer weather, reduced irrigation demand due primarily to a settlement agreement with the WPSC which decreased gross margins by $3.7 million; other variances to the prior year were due toheavy precipitation and higher operating expenses driven by outside services and employee costscosts;
Power Generation’s adjusted operating income decreased $1.3 million primarily due to higher depreciation and $3.2property taxes from new wind assets partially offset by higher revenue from increased wind MWh sold and higher PPA prices;
| |
• | Mining’s adjusted operating income decreased $1.2 million primarily due to lower tons sold driven by unplanned generating facility outages partially offset by lower operating expenses; |
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company; and
A prior year $5.3 million income tax expense associated with changes in the priorpreviously estimated impact of tax reform on deferred income taxes, partially offset by higher rider revenues from recent transmission investments, higher power marketing and wholesale margins, and favorable weather;taxes.
Power Generation’s earnings decreased $0.7
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.
The variance to the prior year included the following:
Electric Utilities’ adjusted operating income increased $2.1 million primarily due to higher operating expenses;
Mining earningsreduced power capacity charges, the prior year Wyoming Electric PCA settlement and increased $0.5 million primarily due to higher coal sales from increased price per ton sold,rider revenues partially offset by higher operating expenses driven by outside services and tax expense.employee costs;
CorporateGas Utilities’ adjusted operating income increased $0.4 million primarily due to new rates offset by higher operating expenses driven by outside services and other expenses decreased $1.1employee costs;
Power Generation’s adjusted operating income increased $0.2 million primarily due to higher tax benefits recognized in therevenue from increased wind MWh sold partially offset by higher depreciation and property taxes from new wind assets;
Mining’s adjusted operating income decreased $3.3 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;
Corporate and Other expenses decreased $2.3 million primarily due to prior year expenses related to the oil and higher prior year operating costs previously allocated to our Oil and Gasgas segment whichthat were not reclassified to discontinued operations, largely allocatedoperations;
A $20 million non-cash impairment of our investment in equity securities of a privately held oil and gas company;
| |
• | A prior year $49 million tax benefit resulting fromlegal entity restructuring partially offset by a prior year $7.5 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes; and |
A lower current year effective tax rate primarily due to operating segments in 2018.$5.0 million of federal production tax credits and related state investment tax credits associated with new wind assets and a $1.0 million tax benefit for deferred tax amortization related to tax reform.
Net income available for common stock for the nine months ended September 30, 2018 was $172 million, or $3.15 per diluted share, compared to $126 million, or $2.29 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the nine months ended September 30, 2018 was $(5.6) million, or $(0.10) per diluted share compared to $(3.5) million or $(0.06) per diluted share reported for the same period in 2017.
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, | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance | 2019 | 2018 | Variance | 2019 | 2018 | Variance |
Revenue | | |
Revenue | $ | 357,370 |
| $ | 366,885 |
| $ | (9,515 | ) | $ | 1,358,519 |
| $ | 1,319,573 |
| $ | 38,946 |
| $ | 363,491 |
| $ | 358,258 |
| $ | 5,233 |
| $ | 1,368,748 |
| $ | 1,361,102 |
| $ | 7,646 |
|
Inter-company eliminations | (35,391 | ) | (31,274 | ) | (4,117 | ) | (105,447 | ) | (94,605 | ) | (10,842 | ) | (37,943 | ) | (36,279 | ) | (1,664 | ) | (111,502 | ) | (108,030 | ) | (3,472 | ) |
| $ | 321,979 |
| $ | 335,611 |
| $ | (13,632 | ) | $ | 1,253,072 |
| $ | 1,224,968 |
| $ | 28,104 |
| $ | 325,548 |
| $ | 321,979 |
| $ | 3,569 |
| $ | 1,257,246 |
| $ | 1,253,072 |
| $ | 4,174 |
|
Net income (loss) from continuing operations available for common stock | | |
Adjusted operating income (a) | | |
Electric Utilities (b) | $ | 21,578 |
| $ | 27,324 |
| $ | (5,746 | ) | $ | 63,313 |
| $ | 68,386 |
| $ | (5,073 | ) | $ | 50,653 |
| $ | 43,393 |
| $ | 7,260 |
| $ | 125,219 |
| $ | 123,073 |
| $ | 2,146 |
|
Gas Utilities (a) (b) | (13,277 | ) | (4,329 | ) | (8,948 | ) | 93,182 |
| 41,409 |
| 51,773 |
| |
Gas Utilities | | 4,736 |
| 4,240 |
| 496 |
| 116,607 |
| 116,168 |
| 439 |
|
Power Generation (b) | 6,691 |
| 6,155 |
| 536 |
| 17,319 |
| 18,017 |
| (698 | ) | 11,822 |
| 13,079 |
| (1,257 | ) | 33,945 |
| 33,731 |
| 214 |
|
Mining (b) | 3,572 |
| 3,477 |
| 95 |
| 9,561 |
| 9,048 |
| 513 |
| 3,374 |
| 4,551 |
| (1,177 | ) | 9,351 |
| 12,647 |
| (3,296 | ) |
Corporate and Other | | (34 | ) | (178 | ) | 144 |
| (439 | ) | (2,709 | ) | 2,270 |
|
Operating income | | 70,551 |
| 65,085 |
| 5,466 |
| 284,683 |
| 282,910 |
| 1,773 |
|
| 18,564 |
| 32,627 |
| (14,063 | ) | 183,375 |
| 136,860 |
| 46,515 |
| |
| |
Corporate and Other (b) | (757 | ) | (3,664 | ) | 2,907 |
| (5,877 | ) | (6,994 | ) | 1,117 |
| |
Net income from continuing operations | 17,807 |
| 28,963 |
| (11,156 | ) | 177,498 |
| 129,866 |
| 47,632 |
| |
(Loss) from discontinued operations, net of tax | (857 | ) | (1,300 | ) | 443 |
| (5,627 | ) | (3,485 | ) | (2,142 | ) | |
Interest expense, net | | (33,487 | ) | (35,297 | ) | 1,810 |
| (102,469 | ) | (104,826 | ) | 2,357 |
|
Impairment of investment | | (19,741 | ) | — |
| (19,741 | ) | (19,741 | ) | — |
| (19,741 | ) |
Other income (expense), net | | 580 |
| (510 | ) | 1,090 |
| 55 |
| (1,923 | ) | 1,978 |
|
Income tax benefit (expense) | | (2,508 | ) | (7,477 | ) | 4,969 |
| (22,078 | ) | 11,784 |
| (33,862 | ) |
Income from continuing operations | | 15,395 |
| 21,801 |
| (6,406 | ) | 140,450 |
| 187,945 |
| (47,495 | ) |
Net (loss) from discontinued operations | | — |
| (857 | ) | 857 |
| — |
| (5,627 | ) | 5,627 |
|
Net income | | 15,395 |
| 20,944 |
| (5,549 | ) | 140,450 |
| 182,318 |
| (41,868 | ) |
Net income attributable to noncontrolling interest | | (3,655 | ) | (3,994 | ) | 339 |
| (10,319 | ) | (10,447 | ) | 128 |
|
Net income available for common stock | $ | 16,950 |
| $ | 27,663 |
| $ | (10,713 | ) | $ | 171,871 |
| $ | 126,381 |
| $ | 45,490 |
| $ | 11,740 |
| $ | 16,950 |
| $ | (5,210 | ) | $ | 130,131 |
| $ | 171,871 |
| $ | (41,740 | ) |
__________
| |
(a) | NetIn 2019, we changed our measure of segment performance to adjusted operating income, (loss) from continuing operationswhich impacted our segment disclosures for the nine months ended September 30, 2018 included a $49 million tax benefit resulting fromlegal entity restructuring.all periods presented. See Note 193 of the Notes to Condensed Consolidated Financial Statements for moreadditional information.
|
| |
(b) | Net income (loss) from continuing operations for the three and nine months ended September 30, 2018 included approximately $5.3 million and $7.5 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes. The impact to our operating segments and Corporate and Other for the three and nine months ended September 30, 2018 was: Electric Utilities $2.8 million and $3.2 million; Gas Utilities $2.6 million and $2.6 million, Mining ($0.0) million and $0.5 million; Power Generation ($0.0) million and $0.7 million; and Corporate and Other ($0.1) million and $0.6 million, respectively. |
Overview of Business Segments and Corporate Activity
Electric Utilities Segment
On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3% annually through 2022.
On October 3, 2018, Colorado Electric set a new winter peak load of 313 MW, exceeding the previous summer peak of 310 MW set in February 2011.
Cooling degree days for the three and nine months ended September 30, 20182019 were 9% higher27% and 29%14% higher than the 30-year average (normal)normal compared to 15%9% and 29% higher than normal for the same periods in 2017.2018.
Heating degree days for the three and nine months ended September 30, 20182019 were 20%36% lower and 5%6% higher than normal, compared to 8%20% and 11%3% lower than normal for the same periods in 2017.2018.
Wyoming Electric and Colorado Electric set new summer peak loads:
On July 10, 2018, Wyoming Electric set a new all-time peak load of 254 MW, exceeding the previous summer peak of 249 MW set in July 2017.
On June 27, 2018, Colorado Electric set a new all-time peak load of 413 MW, exceeding the previous summer peak of 412 MW set in July 2016.
On July 25, 2018,September 17, 2019, South Dakota Electric placed in servicecompleted construction on the first 48-milefinal 94-mile segment of a $70 million, 175-mile 230-kilovoltelectric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The remainingfirst 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.
Colorado Electric and Wyoming Electric set new all-time and summer peak loads:
On July 19, 2019, Colorado Electric set a new peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.
On July 19, 2019, Wyoming Electric set a new peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.
South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready Service Tariffs and related jointly-filed CPCN to construct the $57 million, 40 MW Corriedale Wind Energy Project. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. The project is expected to be in service by the end of 2019.2020. In September 2019, the customer subscription period was completed with customer interest fulfilling the 40 MW of available energy. On November 1, 2019, South Dakota Electric filed with the SDPUC an amendment seeking approval to increase the generating capacity under the tariff for the South Dakota portion by 12.5 MW to a total of 32.5 MW.
Gas Utilities Segment
Heating degree days for the three and nine months ended September 30, 2019 were 62% lower and 7% higher than normal, compared to 27% lower and 0% higher than normal for the same periods in 2018.
Regulatory activity:
| |
◦ | On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies in Nebraska. A rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services of its two existing gas distribution companies. |
| |
◦ | On June 3, 2019, Wyoming Gas filed a rate review application with the WSPC to consolidate the rates, tariffs and services of its four existing gas distribution territories in Wyoming. The rate review requests $16 million in new revenue to recover investments in safety, reliability and system integrity. Wyoming Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A settlement was recently reached with the intervening parties in the rate review filing and filed with the WPSC on November 1, 2019. The stipulation and agreement are subject to review and approval by the WPSC, with a decision expected by the end of 2019. See Note 5 of the Notes to Condensed Consolidated Financial Statements for additional details. |
| |
◦ | On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas is also requesting a new rider mechanism to recover future safety and integrity investments in its system. A decision from the CPUC is expected by March 2020. |
On April 25, 2018, Colorado Electric received approvalMay 10, 2019, Wyoming Gas commenced construction on the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline will interconnect from a supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. Construction of the CPUC to contract with Black Hills Electric Generation forpipeline is nearly complete and the 60 megawatt Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019. This renewable energy will enable Colorado Electric to comply2019, with Colorado's Renewable Energy Standard.the associated investment included in the Wyoming Gas rate review filed on June 3, 2019.
Gas UtilitiesPower Generation Segment
Rate Review updates:
On October 5, 2018, Arkansas Gas received approval from the APSCAugust 2, 2019 Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for a general rate increase. The new rates will generate approximately $12 million of new revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.
In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.
new 60 MW PPA. If approved, Black Hills Wyoming Gas filed for a CPCN on May 18, 2018 with the WPSC to construct a new $54 million, 35-mile natural gas pipeline (Natural Bridge Pipeline) to enhance reliability of supply for approximately 57,000 customers in its Casper division in central Wyoming.
Certain legal entity restructuring transactions occurred on March 31, 2018 as part of the Company’s ongoing efforts towill continue to integrate thelegal entities that the Company has acquired in recentdeliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill thatA decision from FERC is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Condensed Consolidated Statements of Income.
pending.
Heating degree days at the Gas Utilities for the three and nine months ended September 30, 2018 were 27% lower and comparable to the 30-year average (normal), respectively, compared to 22% and 12% lower than normal for the same periods in 2017.
Power Generation
On April 25, 2018,March 11, 2019, Black Hills Electric Generation was selected to providecommenced construction on the $71 million, 60 megawatts of renewable energy to Colorado Electric from theMW Busch Ranch II windWind Farm. The project which is expected to be fully in service by the end ofmid-November 2019.
Mining
In October, negotiations were completed for the price reopener in the contract with Wyodak Plant. The new price was reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton.
Corporate and Other
On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of $299 million in exchange for approximately 6.372 million shares of common stock.
On October 11, 2018, Fitch15, 2019, Moody’s affirmed Black Hills’South Dakota Electric’s credit rating at BBB+ and maintained a Stable outlook.A1.
On August 17, 2018,October 3, 2019, we completed a public debt offering of $400$700 million principal amount of 4.350%in senior unsecured notes. The proceedsProceeds were used to repay the $299$400 million principal amountCorporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.
During the nine months ended September 30, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for net proceeds of $99 million.
On August 29, 2019, Fitch affirmed our RSNsBBB+ rating and maintained a Stable outlook.
On June 17, 2019, we amended our Corporate term loan due 2028July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
On August 9, 2018,April 30, 2019, S&P upgraded Black Hills’ credit rating to BBB+ with a Stable outlook and South Dakota Electric’s credit rating to A.
On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former Revolving Credit Facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and the banks increasing or providing new commitments, to increase total commitments of the facility up to $1.0 billion.
On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, matures on July 30, 2020.
On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.
Discontinued Operations
On November 1, 2017, the BHC Board of Directors approvedFebruary 28, 2019, S&P affirmed our BBB+ rating and maintained a complete divestiture of our Oil and Gas segment. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 of the Notes to Condensed Consolidated Financial Statements for more information.Stable outlook.
Operating Results
A discussion of operating results from our segments and Corporate activities follows.follows in the sections below. Revenues for operating segments in the following sections are presented in total and by retail class. For disaggregation of revenue by contract type and operating segment, see Note 2 of the Notes to Condensed Consolidated Financial Statements for more information.
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, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| (in thousands) |
Revenue (a) | $ | 184,790 |
| $ | 183,571 |
| $ | 1,219 |
| $ | 531,961 |
| $ | 528,048 |
| $ | 3,913 |
|
| | | | | | |
Total fuel and purchased power | 72,928 |
| 68,733 |
| 4,195 |
| 204,334 |
| 199,398 |
| 4,936 |
|
| | | | | | |
Gross margin (b) | 111,862 |
| 114,838 |
| (2,976 | ) | 327,627 |
| 328,650 |
| (1,023 | ) |
| | | | | | |
Operations and maintenance | 45,307 |
| 40,204 |
| 5,103 |
| 135,501 |
| 125,302 |
| 10,199 |
|
Depreciation and amortization | 24,720 |
| 23,446 |
| 1,274 |
| 73,873 |
| 69,427 |
| 4,446 |
|
Total operating expenses | 70,027 |
| 63,650 |
| 6,377 |
| 209,374 |
| 194,729 |
| 14,645 |
|
| | | | | | |
Operating income | 41,835 |
| 51,188 |
| (9,353 | ) | 118,253 |
| 133,921 |
| (15,668 | ) |
| | | | | | |
Interest expense, net | (12,923 | ) | (12,744 | ) | (179 | ) | (39,423 | ) | (39,049 | ) | (374 | ) |
Other income (expense), net | (450 | ) | 649 |
| (1,099 | ) | (1,121 | ) | 1,579 |
| (2,700 | ) |
Income tax benefit (expense) | (6,884 | ) | (11,769 | ) | 4,885 |
| (14,396 | ) | (28,065 | ) | 13,669 |
|
Net income | $ | 21,578 |
| $ | 27,324 |
| $ | (5,746 | ) | $ | 63,313 |
| $ | 68,386 |
| $ | (5,073 | ) |
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | Variance | 2019 | 2018 | Variance |
| (in thousands) |
Revenue | $ | 191,384 |
| $ | 184,790 |
| $ | 6,594 |
| $ | 540,665 |
| $ | 531,961 |
| $ | 8,704 |
|
| | | | | | |
Total fuel and purchased power | 71,593 |
| 74,638 |
| (3,045 | ) | 207,004 |
| 209,317 |
| (2,313 | ) |
| | | | | | |
Gross margin (non-GAAP) | 119,791 |
| 110,152 |
| 9,639 |
| 333,661 |
| 322,644 |
| 11,017 |
|
| | | | | | |
Operations and maintenance | 47,172 |
| 45,307 |
| 1,865 |
| 143,049 |
| 135,501 |
| 7,548 |
|
Depreciation and amortization | 21,966 |
| 21,453 |
| 513 |
| 65,393 |
| 64,070 |
| 1,323 |
|
Total operating expenses | 69,138 |
| 66,760 |
| 2,378 |
| 208,442 |
| 199,571 |
| 8,871 |
|
| | | | | | |
Adjusted operating income (a) | $ | 50,653 |
| $ | 43,392 |
| $ | 7,261 |
| $ | 125,219 |
| $ | 123,073 |
| $ | 2,146 |
|
________________
| |
(a) | TheDue to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Electric Utilities’ Adjusted operating income was revised for the three and nine months ended September 30, 2018, include Horizon Point shared facility revenueswhich resulted in an increase of approximately $2.8$1.6 million and $8.1$4.8 million, respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement is new in 2018 and has no impact on BHC’s consolidated operating results. |
| |
(b) | Non-GAAP measurerespectively. |
Results of Operations for the Electric Utilities for the Three Months Ended September 30, 20182019 Compared to the Three Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Electric Utilities was $22 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $27 million for the three months ended September 30, 2017, as a result of:2018:
Gross margin for the three months ended September 30, 2018 decreased $3.0 million compared to the same period in the prior year2019 increased as a result of:of the following:
|
| | | |
| (in millions) |
TCJA revenue reserve | $ | (5.7 | ) |
Wyoming Electric PCA Stipulation | (3.4 | ) |
Weather | (0.8 | ) |
Commercial and industrial demand | (0.4 | ) |
Horizon Point shared facility revenue (b) | 2.8 |
|
Power Marketing, ancillary wheeling and Tech Services | 2.6 |
|
Residential customer growth | 1.0 |
|
Rider recovery | 0.9 |
|
Total (decrease) in Gross margin (a) | $ | (3.0 | ) |
|
| | | |
| (in millions) |
Prior year Wyoming Electric PCA Stipulation settlement | $ | 3.4 |
|
Weather | 1.8 |
|
Increased industrial demand | 1.7 |
|
Reduction in power capacity charges | 1.7 |
|
Rider recovery | 1.3 |
|
Other | (0.3 | ) |
Total increase in Gross margin (non-GAAP) | $ | 9.6 |
|
________________
| |
(b) | Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results. |
Operations and maintenance expense increased primarily due to $1.2$1.0 million of higher facilityemployee costs $1.3and $0.6 million of higher outside services primarily from distribution and transmission line surveying expenses and $1.5 million higher employee related expenses driven primarily by labor and benefits.expenses.
Depreciation and amortization increased primarily due to a higher asset base driven by the prior year additions
Interest expense, net was comparable to the same period in the prior year.
Other income (expense), net decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.
Income tax benefit (expense): The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $2.8 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.
Results of Operations for the Electric Utilities for the Nine Months Ended September 30, 20182019 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Electric Utilities was $63 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $68 million for the nine months ended September 30, 2017, as a result of:2018:
Gross margin for the nine months ended September 30, 2018 decreased $1.0 million compared to the same period in the prior year2019 increased as a result of:of the following:
|
| | | |
| (in millions) |
TCJA revenue reserve | $ | (17.2 | ) |
Wyoming Electric PCA Stipulation | (3.7 | ) |
Horizon Point shared facility revenue (b) | 8.1 |
|
Rider recovery | 5.0 |
|
Weather | 2.6 |
|
Power Marketing, ancillary wheeling and Tech Services | 2.3 |
|
Residential customer growth | 1.5 |
|
Commercial and industrial demand | 0.4 |
|
Total (decrease) in Gross margin (a) | $ | (1.0 | ) |
|
| | | |
| (in millions) |
Reduction in power capacity charges | $ | 4.9 |
|
Prior year Wyoming Electric PCA Stipulation settlement | 3.7 |
|
Rider recovery | 2.0 |
|
Decreased residential customer usage | (0.9 | ) |
Decreased commercial and industrial demand | (0.2 | ) |
Weather | (0.1 | ) |
Other | 1.6 |
|
Total increase in Gross margin (non-GAAP) | $ | 11.0 |
|
________________
| |
(b) | Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results. |
Operations and maintenance expense increased primarily due to $2.8$3.6 million of higher vegetation management expenses, $3.6 million of shared facility costs and $1.5 million of outside service costs primarily from distribution and transmission line surveying expenses. Higher employee costs and property taxes comprise the remainder$3.4 million of the increase compared to the same period in the prior year.higher outside services expenses.
Depreciation and amortization increased primarily due to a higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line.
Interest expense, net was comparable to the same period in the prior year.
Other income (expense), net decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.expenditures.
Income tax benefit (expense): The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $3.2 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.
Operating Statistics
| | | | Electric Revenue (in thousands) | | Quantities sold (MWh) | | Electric Revenue (in thousands) | | Quantities sold (MWh) |
| | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 | | 2019 | 2018 | 2019 | 2018 | | 2019 | 2018 | 2019 | 2018 |
Residential | | $ | 58,122 |
| $ | 55,866 |
| $ | 163,979 |
| $ | 158,017 |
| | 372,623 |
| 369,466 |
| 1,084,531 |
| 1,038,437 |
| | $ | 58,919 |
| $ | 58,122 |
| $ | 162,257 |
| $ | 163,979 |
| | 384,735 |
| 372,623 |
| 1,075,394 |
| 1,084,531 |
|
Commercial | | 65,794 |
| 68,044 |
| 192,680 |
| 195,495 |
| | 550,791 |
| 557,975 |
| 1,560,911 |
| 1,547,254 |
| | 65,732 |
| 65,794 |
| 186,434 |
| 192,680 |
| | 560,547 |
| 550,791 |
| 1,556,449 |
| 1,560,911 |
|
Industrial | | 31,939 |
| 30,564 |
| 93,959 |
| 91,583 |
| | 429,133 |
| 406,946 |
| 1,248,438 |
| 1,192,316 |
| | 33,937 |
| 31,939 |
| 98,074 |
| 93,959 |
| | 462,809 |
| 429,133 |
| 1,335,260 |
| 1,248,438 |
|
Municipal | | 4,582 |
| 4,958 |
| 13,389 |
| 13,934 |
| | 43,972 |
| 47,389 |
| 122,953 |
| 125,065 |
| | 4,792 |
| 4,582 |
| 13,184 |
| 13,389 |
| | 46,106 |
| 43,972 |
| 121,025 |
| 122,953 |
|
Subtotal Retail Revenue - Electric | | 160,437 |
| 159,432 |
| 464,007 |
| 459,029 |
| | 1,396,519 |
| 1,381,776 |
| 4,016,833 |
| 3,903,072 |
| | 163,380 |
| 160,437 |
| 459,949 |
| 464,007 |
| | 1,454,197 |
| 1,396,519 |
| 4,088,128 |
| 4,016,833 |
|
Contract Wholesale | | 8,256 |
| 8,048 |
| 25,497 |
| 22,593 |
| | 221,327 |
| 185,723 |
| 677,163 |
| 537,720 |
| | 8,211 |
| 8,256 |
| 23,335 |
| 25,497 |
| | 229,369 |
| 221,327 |
| 646,611 |
| 677,163 |
|
Off-system/Power Marketing Wholesale | | 9,059 |
| 5,932 |
| 18,142 |
| 15,110 |
| | 206,791 |
| 159,425 |
| 514,686 |
| 477,283 |
| | 6,452 |
| 9,059 |
| 16,592 |
| 18,142 |
| | 160,357 |
| 206,791 |
| 436,298 |
| 514,686 |
|
Other | | 7,038 |
| 10,159 |
| 24,315 |
| 31,316 |
| | — |
| — |
| — |
| — |
| | 13,341 |
| 7,038 |
| 40,789 |
| 24,315 |
| | — |
| — |
| — |
| — |
|
Total Revenue and Energy Sold | | 184,790 |
| 183,571 |
| 531,961 |
| 528,048 |
| | 1,824,637 |
| 1,726,924 |
| 5,208,682 |
| 4,918,075 |
| | 191,384 |
| 184,790 |
| 540,665 |
| 531,961 |
| | 1,843,923 |
| 1,824,637 |
| 5,171,037 |
| 5,208,682 |
|
Other Uses, Losses or Generation, net | | — |
| — |
| — |
| — |
| | 121,478 |
| 134,595 |
| 337,939 |
| 354,572 |
| | — |
| — |
| — |
| — |
| | 112,172 |
| 121,478 |
| 299,038 |
| 337,939 |
|
Total Revenue and Energy | | 184,790 |
| 183,571 |
| 531,961 |
| 528,048 |
| | 1,946,115 |
| 1,861,519 |
| 5,546,621 |
| 5,272,647 |
| | 191,384 |
| 184,790 |
| 540,665 |
| 531,961 |
| | 1,956,095 |
| 1,946,115 |
| 5,470,075 |
| 5,546,621 |
|
Less cost of fuel and purchased power(a) | | 72,928 |
| 68,733 |
| 204,334 |
| 199,398 |
| | | | 71,593 |
| 74,638 |
| 207,004 |
| 209,317 |
| | |
Gross Margin (a) | | $ | 111,862 |
| $ | 114,838 |
| $ | 327,627 |
| $ | 328,650 |
| | | |
Gross Margin (non-GAAP) (a) | | | $ | 119,791 |
| $ | 110,152 |
| $ | 333,661 |
| $ | 322,644 |
| | |
________________
| |
(a) | Non-GAAP measureDue to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, cost of fuel and purchased power was revised for the three and nine months ended September 30, 2018, which resulted in an increase of $1.6 million and $4.8 million, respectively. There were corresponding decreases to Gross margin for each period. |
| | | | | | | | | | | | | | | | | | | | |
Three Months Ended September 30, | | Electric Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Quantities Sold (MWh) (b) | | Electric Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold (MWh) (a) |
| | 2018 | 2017 | | 2018 | 2017 | | 2018 | 2017 | | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
Colorado Electric (b) | | | $ | 70,771 |
| $ | 68,052 |
| | $ | 41,916 |
| $ | 38,449 |
| | 634,098 |
| 610,079 |
|
South Dakota Electric | | $ | 78,067 |
| $ | 73,939 |
| | $ | 52,860 |
| $ | 51,096 |
| | 874,962 |
| 835,285 |
| | 77,022 |
| 78,067 |
| | 55,217 |
| 52,860 |
| | 835,725 |
| 874,962 |
|
Wyoming Electric | | 38,671 |
| 40,670 |
| | 18,843 |
| 22,990 |
| | 461,074 |
| 434,945 |
| | 43,591 |
| 38,671 |
| | 22,658 |
| 18,843 |
| | 486,272 |
| 461,074 |
|
Colorado Electric | | 68,052 |
| 68,962 |
| | 40,159 |
| 40,752 |
| | 610,079 |
| 591,289 |
| |
Total Electric Revenue, Gross Margin, and Quantities Sold | | $ | 184,790 |
| $ | 183,571 |
| | $ | 111,862 |
| $ | 114,838 |
| | 1,946,115 |
| 1,861,519 |
| |
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold | | | $ | 191,384 |
| $ | 184,790 |
| | $ | 119,791 |
| $ | 110,152 |
| | 1,956,095 |
| 1,946,115 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
Nine Months Ended September 30, | | Electric Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Quantities Sold (MWh) (a) |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
Colorado Electric (b) | | $ | 186,030 |
| $ | 188,937 |
| | $ | 104,411 |
| $ | 105,997 |
| | 1,611,126 |
| 1,639,607 |
|
South Dakota Electric | | 225,309 |
| 222,558 |
| | 162,390 |
| 154,158 |
| | 2,438,366 |
| 2,541,082 |
|
Wyoming Electric | | 129,326 |
| 120,466 |
| | 66,860 |
| 62,489 |
| | 1,420,583 |
| 1,365,932 |
|
Total Electric Revenue, Gross Margin (non-GAAP), and Quantities Sold | | $ | 540,665 |
| $ | 531,961 |
| | $ | 333,661 |
| $ | 322,644 |
| | 5,470,075 |
| 5,546,621 |
|
________________
| |
(b) | Total MWh for 2019 includes Other Uses, Losses or Generation, net, which are approximately 5%6%, 7%5%, and 7%6% for Colorado Electric, South Dakota Electric, and Wyoming Electric, and Colorado Electric, respectively. |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
Nine Months Ended September 30, | | Electric Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Quantities Sold (MWh) (b) |
| | 2018 | 2017 | | 2018 | 2017 | | 2018 | 2017 |
South Dakota Electric | | $ | 222,558 |
| $ | 213,785 |
| | $ | 154,158 |
| $ | 149,182 |
| | 2,541,082 |
| 2,399,995 |
|
Wyoming Electric | | 120,466 |
| 123,299 |
| | 62,489 |
| 68,215 |
| | 1,365,932 |
| 1,298,009 |
|
Colorado Electric | | 188,937 |
| 190,964 |
| | 110,980 |
| 111,253 |
| | 1,639,607 |
| 1,574,643 |
|
Total Electric Revenue, Gross Margin, and Quantities Sold | | $ | 531,961 |
| $ | 528,048 |
| | $ | 327,627 |
| $ | 328,650 |
| | 5,546,621 |
| 5,272,647 |
|
________________
| |
(b) | Total MWh includes Other Uses, Losses or Generation, net,Due to the changes in our segment disclosures discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Gross margin was revised for the three and nine months ended September 30, 2018, which are approximately 5%, 6%,resulted in a decrease of $(1.6) million and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric,$(4.8) million, respectively. |
| | | Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended September 30, | Nine Months Ended September 30, |
Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 |
| | |
Coal-fired | 608,417 |
| 625,590 |
| 1,772,750 |
| 1,663,935 |
| 564,220 |
| 608,417 |
| 1,621,355 |
| 1,772,750 |
|
Natural Gas and Oil | 199,351 |
| 156,465 |
| 345,978 |
| 249,065 |
| 234,366 |
| 199,351 |
| 445,498 |
| 345,978 |
|
Wind | 54,450 |
| 38,773 |
| 196,932 |
| 167,429 |
| 55,407 |
| 54,450 |
| 167,331 |
| 196,932 |
|
Total Generated | 862,218 |
| 820,828 |
| 2,315,660 |
| 2,080,429 |
| 853,993 |
| 862,218 |
| 2,234,184 |
| 2,315,660 |
|
Purchased | 1,083,897 |
| 1,040,691 |
| 3,230,961 |
| 3,192,218 |
| 1,102,102 |
| 1,083,897 |
| 3,235,891 |
| 3,230,961 |
|
Total Generated and Purchased | 1,946,115 |
| 1,861,519 |
| 5,546,621 |
| 5,272,647 |
| 1,956,095 |
| 1,946,115 |
| 5,470,075 |
| 5,546,621 |
|
| | | Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended September 30, | Nine Months Ended September 30, |
Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2018 | 2017 | 2019 | 2018 | 2019 | 2018 |
Generated: | | |
Colorado Electric | | 149,509 |
| 163,276 |
| 341,925 |
| 388,251 |
|
South Dakota Electric | 469,680 |
| 478,232 |
| 1,293,713 |
| 1,177,131 |
| 489,042 |
| 469,680 |
| 1,262,336 |
| 1,293,713 |
|
Wyoming Electric | 229,262 |
| 227,391 |
| 633,696 |
| 601,780 |
| 215,442 |
| 229,262 |
| 629,923 |
| 633,696 |
|
Colorado Electric | 163,276 |
| 115,205 |
| 388,251 |
| 301,518 |
| |
Total Generated | 862,218 |
| 820,828 |
| 2,315,660 |
| 2,080,429 |
| 853,993 |
| 862,218 |
| 2,234,184 |
| 2,315,660 |
|
Purchased: | | |
Colorado Electric | | 484,589 |
| 446,803 |
| 1,269,201 |
| 1,251,356 |
|
South Dakota Electric | 405,282 |
| 357,053 |
| 1,247,369 |
| 1,222,864 |
| 346,683 |
| 405,282 |
| 1,176,030 |
| 1,247,369 |
|
Wyoming Electric | 231,812 |
| 207,554 |
| 732,236 |
| 696,229 |
| 270,830 |
| 231,812 |
| 790,660 |
| 732,236 |
|
Colorado Electric | 446,803 |
| 476,084 |
| 1,251,356 |
| 1,273,125 |
| |
Total Purchased | 1,083,897 |
| 1,040,691 |
| 3,230,961 |
| 3,192,218 |
| 1,102,102 |
| 1,083,897 |
| 3,235,891 |
| 3,230,961 |
|
| | |
Total Generated and Purchased | 1,946,115 |
| 1,861,519 |
| 5,546,621 |
| 5,272,647 |
| 1,956,095 |
| 1,946,115 |
| 5,470,075 |
| 5,546,621 |
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Three Months Ended September 30, |
Degree Days | | | 2018 | | 2017 | | | 2019 | | 2018 |
| Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average | Actual | | Variance from Normal | | Actual Variance to Prior Year | | Actual | | Variance from Normal |
Heating Degree Days: | | | | | | | | | | | | | | |
Colorado Electric | | 4 |
| | (96 | )% | | (89)% | | 35 |
| | (64 | )% |
South Dakota Electric | 236 |
| | 5 | % | | 17% | | 202 |
| | (10 | )% | 175 |
| | (22 | )% | | (26)% | | 236 |
| | 5 | % |
Wyoming Electric | 248 |
| | (19 | )% | | (15)% | | 292 |
| | (4 | )% | 120 |
| | (77 | )% | | (52)% | | 248 |
| | (19 | )% |
Colorado Electric | 35 |
| | (64 | )% | | (60)% | | 87 |
| | (11 | )% | |
Combined (a) | 147 |
| | (20 | )% | | (13)% | | 168 |
| | (8 | )% | 86 |
| | (36 | )% | | (41)% | | 147 |
| | (20 | )% |
| | | | | | | | | | | | | | |
Cooling Degree Days: | | | | | | | | | | | | | | |
Colorado Electric | | 1,079 |
| | 58 | % | | 19% | | 910 |
| | 33 | % |
South Dakota Electric | 356 |
| | (33 | )% | | (40)% | | 595 |
| | 11 | % | 366 |
| | (31 | )% | | 3% | | 356 |
| | (33 | )% |
Wyoming Electric | 328 |
| | 10 | % | | (15)% | | 388 |
| | 30 | % | 433 |
| | 45 | % | | 32% | | 328 |
| | 10 | % |
Colorado Electric | 910 |
| | 33 | % | | 16% | | 784 |
| | 14 | % | |
Combined (a) | 603 |
| | 9 | % | | (6)% | | 640 |
| | 15 | % | 705 |
| | 27 | % | | 17% | | 603 |
| | 9 | % |
|
| | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | | | 2018 |
Heating Degree Days | Actual | | Variance from Normal | | Actual Variance to Prior Year | | Actual | | Variance from Normal |
| | | | | | | | | |
Colorado Electric | 3,156 |
| | (6 | )% | | 9% | | 2,901 |
| | (14 | )% |
South Dakota Electric | 5,370 |
| | 20 | % | | 8% | | 4,972 |
| | 11 | % |
Wyoming Electric | 4,677 |
| | 5 | % | | 9% | | 4,285 |
| | (9 | )% |
Combined (a) | 4,198 |
| | 6 | % | | 8% | | 3,888 |
| | (3 | )% |
| | | | | | | | | |
Cooling Degree Days: | | | | | | | | | |
Colorado Electric | 1,226 |
| | 37 | % | | (13)% | | 1,404 |
| | 57 | % |
South Dakota Electric | 404 |
| | (36 | )% | | (17)% | | 488 |
| | (23 | )% |
Wyoming Electric | 462 |
| | 33 | % | | 7% | | 430 |
| | 24 | % |
Combined (a) | 791 |
| | 14 | % | | (12)% | | 895 |
| | 29 | % |
__________
| |
(a) | Combined actuals are calculated based on the weighted average number of total customers by state. |
|
| | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, |
Degree Days | 2018 | | | | 2017 |
| Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Heating Degree Days: | | | | | | | | | |
South Dakota Electric | 4,972 |
| | 11 | % | | 17% | | 4,242 |
| | (5 | )% |
Wyoming Electric | 4,285 |
| | (9 | )% | | 2% | | 4,186 |
| | (11 | )% |
Colorado Electric | 2,901 |
| | 9 | % | | 5% | | 2,773 |
| | (17 | )% |
Combined (a) | 3,888 |
| | 5 | % | | 9% | | 3,559 |
| | (11 | )% |
| | | | | | | | | |
Cooling Degree Days: | | | | | | | | | |
South Dakota Electric | 488 |
| | (23 | )% | | (31)% | | 709 |
| | 12 | % |
Wyoming Electric | 430 |
| | 24 | % | | —% | | 429 |
| | 23 | % |
Colorado Electric | 1,404 |
| | 57 | % | | 37% | | 1,027 |
| | 15 | % |
Combined (a) | 895 |
| | 29 | % | | 12% | | 798 |
| | 15 | % |
|
| | | | | | | | |
Electric Utilities Power Plant Availability | Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | 2019 | 2018 |
Coal-fired plants (a) | 94.6 | % | 95.7 | % | 90.0 | % | 94.0 | % |
Natural gas-fired plants and Other plants (b) | 89.6 | % | 97.0 | % | 89.8 | % | 97.2 | % |
Wind | 93.7 | % | 96.9 | % | 95.0 | % | 96.9 | % |
Total availability | 91.5 | % | 96.6 | % | 90.3 | % | 96.1 | % |
| | | | |
Wind capacity factor | 33.8 | % | 33.1 | % | 37.1 | % | 41.8 | % |
__________
| |
(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, |
| 2018 | 2017 | 2018 | | 2017 | |
Coal-fired plants (a) | 95.7 | % | | 98.3 | % | | 94.0 | % | | 88.1 | % | |
Natural gas-fired plants and Other plants | 97.0 | % | | 94.6 | % | | 97.2 | % | | 95.8 | % | |
Wind | 96.9 | % | | 91.0 | % | | 96.9 | % | | 92.0 | % | |
Total availability | 96.6 | % | | 95.5 | % | | 96.1 | % | | 93.0 | % | |
| | | | | | | | |
Wind capacity factor | 33.1 | % | | 23.6 | % | | 41.8 | % | | 34.3 | % | |
__________
| |
(a) | 20172019 included planned outages at Neil Simpson II and Wygen IIIII and unplanned outages at Wyodak Plant and Wygen III. |
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 5 of the Notes to Condensed Consolidated Financial Statements of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2 and Part II, Item 8 of our 2017 Annual Report on Form 10-K filed with the SEC.
Gas Utilities
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| (in thousands) |
Revenue: | | | | | | |
Natural gas — regulated | $ | 117,070 |
| $ | 123,210 |
| $ | (6,140 | ) | $ | 648,550 |
| $ | 602,745 |
| $ | 45,805 |
|
Other — non-regulated services (a) | 14,606 |
| 19,684 |
| (5,078 | ) | 58,090 |
| 71,506 |
| (13,416 | ) |
Total revenue | 131,676 |
| 142,894 |
| (11,218 | ) | 706,640 |
| 674,251 |
| 32,389 |
|
| | | | | | |
Cost of sales: | | | | | | |
Natural gas — regulated | 30,612 |
| 33,376 |
| (2,764 | ) | 298,149 |
| 255,410 |
| 42,739 |
|
Other — non-regulated services (a) | 5,514 |
| 11,917 |
| (6,403 | ) | 15,716 |
| 33,615 |
| (17,899 | ) |
Total cost of sales | 36,126 |
| 45,293 |
| (9,167 | ) | 313,865 |
| 289,025 |
| 24,840 |
|
| | | | | | |
Gross margin (b) | 95,550 |
| 97,601 |
| (2,051 | ) | 392,775 |
| 385,226 |
| 7,549 |
|
| | | | | | |
Operations and maintenance | 69,746 |
| 65,390 |
| 4,356 |
| 212,319 |
| 201,105 |
| 11,214 |
|
Depreciation and amortization | 21,564 |
| 20,937 |
| 627 |
| 64,288 |
| 62,658 |
| 1,630 |
|
Total operating expenses | 91,310 |
| 86,327 |
| 4,983 |
| 276,607 |
| 263,763 |
| 12,844 |
|
| | | | | | |
Operating income | 4,240 |
| 11,274 |
| (7,034 | ) | 116,168 |
| 121,463 |
| (5,295 | ) |
| | | | | | |
Interest expense, net | (20,433 | ) | (19,527 | ) | (906 | ) | (59,456 | ) | (58,919 | ) | (537 | ) |
Other income (expense), net | (478 | ) | (294 | ) | (184 | ) | (1,239 | ) | (342 | ) | (897 | ) |
Income tax benefit (expense) | 3,394 |
| 4,218 |
| (824 | ) | 37,709 |
| (20,686 | ) | 58,395 |
|
Net income (loss) | (13,277 | ) | (4,329 | ) | (8,948 | ) | 93,182 |
| 41,516 |
| 51,666 |
|
Net (income) loss attributable to noncontrolling interest | — |
| — |
| — |
| — |
| (107 | ) | 107 |
|
Net income (loss) available for common stock | $ | (13,277 | ) | $ | (4,329 | ) | $ | (8,948 | ) | $ | 93,182 |
| $ | 41,409 |
| $ | 51,773 |
|
__________
| |
(a) | The three and nine months ended September 30, 2018 include certain non-utility trading activities which are reported on a net basis. These trading activities are presented on a gross basis in the prior year. This change in presentation had no impact on gross margin. |
| |
(b) | Non-GAAP measure2019 included planned outages at Neil Simpson CT and Lange CT. |
Gas Utilities
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | Variance | 2019 | 2018 | Variance |
| (in thousands) |
Revenue: | | | | | | |
Natural gas - regulated | $ | 117,549 |
| $ | 117,070 |
| $ | 479 |
| $ | 651,366 |
| $ | 648,550 |
| $ | 2,816 |
|
Other - non-regulated services | 13,195 |
| 14,606 |
| (1,411 | ) | 55,927 |
| 58,090 |
| (2,163 | ) |
Total revenue | 130,744 |
| 131,676 |
| (932 | ) | 707,293 |
| 706,640 |
| 653 |
|
| | | | | | |
Cost of sales: | | | | | | |
Natural gas - regulated | 28,154 |
| 30,612 |
| (2,458 | ) | 280,312 |
| 298,149 |
| (17,837 | ) |
Other - non-regulated services | 4,870 |
| 5,514 |
| (644 | ) | 16,975 |
| 15,716 |
| 1,259 |
|
Total cost of sales | 33,024 |
| 36,126 |
| (3,102 | ) | 297,287 |
| 313,865 |
| (16,578 | ) |
| | | | | | |
Gross margin (non-GAAP) | 97,720 |
| 95,550 |
| 2,170 |
| 410,006 |
| 392,775 |
| 17,231 |
|
| | | | | | |
Operations and maintenance | 70,170 |
| 69,746 |
| 424 |
| 225,239 |
| 212,319 |
| 12,920 |
|
Depreciation and amortization | 22,814 |
| 21,564 |
| 1,250 |
| 68,160 |
| 64,288 |
| 3,872 |
|
Total operating expenses | 92,984 |
| 91,310 |
| 1,674 |
| 293,399 |
| 276,607 |
| 16,792 |
|
| | | | | | |
Adjusted operating income | $ | 4,736 |
| $ | 4,240 |
| $ | 496 |
| $ | 116,607 |
| $ | 116,168 |
| $ | 439 |
|
Results of Operations for the Gas Utilities for the Three Months Ended September 30, 20182019 Compared to the Three Months Ended September 30, 2017: Net (loss) from continuing operations available for common stock for the Gas Utilities was $(13.3) million2018:
Gross margin for the three months ended September 30, 2018, compared to Net loss from continuing operations available for common stock of $(4.3) million2019 increased as a result of:
|
| | | |
| (in millions) |
New rates | $ | 3.0 |
|
Customer growth - distribution | 0.8 |
|
Increased transport and transmission | 0.7 |
|
Weather (a) | (3.4 | ) |
Other | 1.1 |
|
Total increase in Gross margin (non-GAAP) | $ | 2.2 |
|
(a) Weather impacts for the three months ended September 30, 2017, as a result of:
Gross margin for the three months ended September 30, 2018 decreased $2.1 million2019 compared to the same period in the prior year as a result of:include reduced heating demand due to warmer temperatures and reduced irrigation loads to agriculture customers in our Nebraska Gas service territory due to higher precipitation.
|
| | | |
| (in millions) |
Weather | $ | (2.3 | ) |
TCJA revenue reserve | (2.2 | ) |
Rate review and rider recovery | (0.3 | ) |
Non-utility - Tech Services and appliance repair | 1.2 |
|
Customer growth - distribution | 0.8 |
|
Mark-to-market gains on non-utility natural gas commodity contracts | 0.4 |
|
Other | 0.3 |
|
Total increase (decrease) in Gross margin (a) | $ | (2.1 | ) |
________________
Operations and maintenance expense increased primarily due to $1.4 million higher facilityemployee costs higher bad debt expense of approximately $0.5 million related to increased year-to-date revenues, $1.3 million ofand higher outside services primarily from line locating services and $0.3 million higher employee costs driven primarily by increased headcount.expenses.
Depreciation and amortization increased primarily due to a higher asset base driven by previousprior and current year capital expenditures.
Interest expense, netincreased due to higher corporate allocations from financing activities compared to the same period in the prior year.
46
Other income (expense), net decreased from the prior year due primarily to the presentation change
Income tax benefit (expense) decreased from the prior year due to the lower tax rate as a result of the reduction of the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018 partially offset by $2.6 million of tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.
Results of Operations for the Gas Utilities for the Nine Months Ended September 30, 20182019 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Gas Utilities was $93 million2018:
Gross margin for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $42 million for the nine months ended September 30, 2017,2019 increased as a result of:
Gross margin for the nine months ended September 30, 2018 increased $7.5 million compared to the same period in the prior year as a result of:
|
| | | |
| (in millions) |
Weather | $ | 7.6 |
|
Customer growth - distribution | 3.6 |
|
Mark-to-market gains on non-utility natural gas commodity contracts | 2.9 |
|
Rate review and rider recovery | 2.8 |
|
Natural gas volumes sold | 1.9 |
|
Transportation and Transmission | 0.9 |
|
Non-utility - Tech Services and appliance repair | 0.8 |
|
Other | 0.5 |
|
TCJA revenue reserve | (13.5 | ) |
Total increase (decrease) in Gross margin (a) | $ | 7.5 |
|
|
| | | |
| (in millions) |
New rates | $ | 15.5 |
|
Customer growth - distribution | 3.7 |
|
Increased transport and transmission | 1.8 |
|
Decreased mark-to-market on non-utility natural gas commodity contracts | (2.7 | ) |
Excess deferred taxes returned to customers | (2.5 | ) |
Weather | (0.6 | ) |
Other | 2.0 |
|
Total increase in Gross margin (non-GAAP) | $ | 17.2 |
|
________________
Operations and maintenance expense increased primarily due to higher employee costs of approximately $2.6 million driven by labor, benefits and increased corporate allocations, higher bad debt expense of approximately $2.6 million driven by the current year increase in revenues, $1.6$7.2 million of higher outside services primarily from line locating servicesexpenses, $4.1 million of higher employee costs and an increase in facility costs$1.3 million of $4.2 million.
Depreciation and amortization increasedhigher property taxes due to a higher asset base driven by previousprior and current year capital expenditures.
Interest expense, net was comparable to the same period in the prior year.
Other income (expense), net decreased from the prior yearDepreciation and amortization increased primarily due to the presentation change of non-service pension costs to Other income (expense) in thea higher asset base driven by prior and current year previously reported in Operations and maintenance.capital expenditures.
Income tax benefit (expense): The 2018 tax benefit is due to legal restructuring to enable jurisdictional simplification that resulted in the recognition of a deferred tax benefit of approximately $49 million associated with amortizable goodwill for tax purposes. The current year effective tax rate also reflects the reduction of the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
Operating Statistics
|
| | | | | | | | | | | | | | | | | | | |
| | Gas Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth) |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | | | | | | | | |
Residential | | $ | 57,244 |
| $ | 58,221 |
| | $ | 43,441 |
| $ | 42,598 |
| | 3,599,549 |
| 3,708,196 |
|
Commercial | | 19,629 |
| 19,639 |
| | 11,589 |
| 10,880 |
| | 2,298,919 |
| 2,278,304 |
|
Industrial | | 8,770 |
| 8,258 |
| | 2,493 |
| 2,028 |
| | 2,960,930 |
| 2,304,098 |
|
Other (a) | | 2,499 |
| 487 |
| | 2,499 |
| 487 |
| | — |
| — |
|
Total Distribution | | 88,142 |
| 86,605 |
| | 60,022 |
| 55,993 |
| | 8,859,398 |
| 8,290,598 |
|
| | | | | | | | | |
Transportation and Transmission | | 29,407 |
| 30,465 |
| | 29,373 |
| 30,465 |
| | 31,538,815 |
| 29,808,567 |
|
| | | | | | | | | |
Total Regulated | | 117,549 |
| 117,070 |
| | 89,395 |
| 86,458 |
| | 40,398,213 |
| 38,099,165 |
|
| | | | | | | | | |
Non-regulated Services | | 13,195 |
| 14,606 |
| | 8,325 |
| 9,092 |
| | | |
| | | | | | | | | |
Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 130,744 |
| $ | 131,676 |
| | $ | 97,720 |
| $ | 95,550 |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Gas Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth) |
| | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 | | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | | | | | | | | | |
Residential | | $ | 58,221 |
| $ | 57,804 |
| $ | 383,972 |
| $ | 344,407 |
| | $ | 42,598 |
| $ | 42,012 |
| $ | 192,072 |
| $ | 182,256 |
| | $ | 383,466 |
| $ | 383,972 |
| | $ | 201,168 |
| $ | 192,072 |
| | 44,356,725 |
| 42,642,021 |
|
Commercial | | 19,639 |
| 21,366 |
| 148,675 |
| 134,156 |
| | 10,880 |
| 11,097 |
| 57,890 |
| 54,931 |
| | 146,752 |
| 148,675 |
| | 61,673 |
| 57,890 |
| | 21,484,646 |
| 20,842,996 |
|
Industrial | | 8,258 |
| 9,472 |
| 20,805 |
| 18,699 |
| | 2,028 |
| 2,157 |
| 5,341 |
| 4,665 |
| | 18,764 |
| 20,805 |
| | 5,830 |
| 5,341 |
| | 5,141,399 |
| 5,235,417 |
|
Other (b) | | 487 |
| 2,099 |
| (6,789 | ) | 6,363 |
| | 487 |
| 2,099 |
| (6,789 | ) | 6,363 |
| |
Other (a) | | | (968 | ) | (6,789 | ) | | (968 | ) | (6,789 | ) | | — |
| — |
|
Total Distribution | | 86,605 |
| 90,741 |
| 546,663 |
| 503,625 |
| | 55,993 |
| 57,365 |
| 248,514 |
| 248,215 |
| | 548,014 |
| 546,663 |
| | 267,703 |
| 248,514 |
| | 70,982,770 |
| 68,720,434 |
|
| | | | | | | | | | |
Transportation and Transmission | | 30,465 |
| 32,469 |
| 101,887 |
| 99,120 |
| | 30,465 |
| 32,470 |
| 101,887 |
| 99,121 |
| | 103,352 |
| 101,887 |
| | 103,351 |
| 101,887 |
| | 110,622,285 |
| 107,388,321 |
|
| | | | | | | | | | |
Total Regulated | | 117,070 |
| 123,210 |
| 648,550 |
| 602,745 |
| | 86,458 |
| 89,835 |
| 350,401 |
| 347,336 |
| | 651,366 |
| 648,550 |
| | 371,054 |
| 350,401 |
| | 181,605,055 |
| 176,108,755 |
|
| | | | | | | | | | |
Non-regulated Services | | 14,606 |
| 19,684 |
| 58,090 |
| 71,506 |
| | 9,092 |
| 7,766 |
| 42,374 |
| 37,890 |
| | 55,927 |
| 58,090 |
| | 38,952 |
| 42,374 |
| | |
| | | | | | | | | | |
Total Gas Revenue & Gross Margin | | $ | 131,676 |
| $ | 142,894 |
| $ | 706,640 |
| $ | 674,251 |
| | $ | 95,550 |
| $ | 97,601 |
| $ | 392,775 |
| $ | 385,226 |
| | $ | 707,293 |
| $ | 706,640 |
| | $ | 410,006 |
| $ | 392,775 |
| | |
__________
| |
(b) | Includes current year reserve toOther revenue to reflectreflects the reductionimpact of the lower federal income tax rate fromrevenue reserved in accordance with the TCJA on our existing rate tariffs..
|
| | | | Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth)
|
| | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | Nine Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 | | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | | | | | | | | | |
Arkansas | | $ | 18,743 |
| $ | 19,276 |
| $ | 116,226 |
| $ | 104,519 |
| | $ | 13,415 |
| $ | 13,485 |
| $ | 65,803 |
| $ | 66,362 |
| | $ | 21,387 |
| $ | 18,743 |
| | $ | 16,249 |
| $ | 13,415 |
| | 4,094,454 |
| 4,022,089 |
|
Colorado | | 22,362 |
| 21,823 |
| 125,898 |
| 120,667 |
| | 15,210 |
| 16,068 |
| 66,917 |
| 69,241 |
| | 22,632 |
| 22,362 |
| | 15,667 |
| 15,210 |
| | 3,806,360 |
| 2,893,029 |
|
Nebraska | | 40,553 |
| 47,577 |
| 196,307 |
| 191,288 |
| | 31,264 |
| 33,290 |
| 117,925 |
| 112,418 |
| |
Iowa | | 16,982 |
| 17,709 |
| 111,968 |
| 98,619 |
| | 12,556 |
| 12,564 |
| 49,630 |
| 48,278 |
| | 16,381 |
| 16,982 |
| | 13,135 |
| 12,556 |
| | 5,686,772 |
| 5,595,205 |
|
Kansas | | 18,497 |
| 20,114 |
| 81,880 |
| 77,389 |
| | 11,129 |
| 11,207 |
| 40,896 |
| 39,810 |
| | 19,013 |
| 18,497 |
| | 12,309 |
| 11,129 |
| | 7,602,758 |
| 6,164,821 |
|
Nebraska | | | 35,715 |
| 40,553 |
| | 28,046 |
| 31,264 |
| | 13,999,302 |
| 13,831,306 |
|
Wyoming | | 14,539 |
| 16,395 |
| 74,361 |
| 81,769 |
| | 11,976 |
| 10,987 |
| 51,604 |
| 49,117 |
| | 15,616 |
| 14,539 |
| | 12,314 |
| 11,976 |
| | 5,208,567 |
| 5,592,715 |
|
Total Gas Revenue & Gross Margin | | $ | 131,676 |
| $ | 142,894 |
| $ | 706,640 |
| $ | 674,251 |
| | $ | 95,550 |
| $ | 97,601 |
| $ | 392,775 |
| $ | 385,226 |
| |
Total Gas Revenue & Gross Margin (non-GAAP) | | | $ | 130,744 |
| $ | 131,676 |
| | $ | 97,720 |
| $ | 95,550 |
| | 40,398,213 |
| 38,099,165 |
|
__________
|
| | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
Gas Utilities Quantities Sold & Transported (Dth) | 2018 | 2017 | 2018 | 2017 |
| | | | |
Residential | 3,708,196 |
| 3,682,944 |
| 42,642,021 |
| 36,052,414 |
|
Commercial | 2,278,304 |
| 2,445,847 |
| 20,842,996 |
| 18,111,118 |
|
Industrial | 2,304,098 |
| 2,722,173 |
| 5,235,417 |
| 4,690,092 |
|
Total Distribution Quantities Sold | 8,290,598 |
| 8,850,964 |
| 68,720,434 |
| 58,853,624 |
|
| | | | |
Transportation and Transmission | 29,808,567 |
| 30,577,487 |
| 107,388,321 |
| 102,314,665 |
|
| | | | |
Total Quantities Sold & Transported | 38,099,165 |
| 39,428,451 |
| 176,108,755 |
| 161,168,289 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | Revenue (in thousands) | | Gross Margin (non-GAAP) (in thousands) | | Gas Utilities Quantities Sold & Transported (Dth)
|
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| | | | | | | | | |
Arkansas | | $ | 127,014 |
| $ | 116,226 |
| | $ | 79,148 |
| $ | 65,803 |
| | 21,061,567 |
| 21,183,322 |
|
Colorado | | 135,816 |
| 125,898 |
| | 73,022 |
| 66,917 |
| | 23,050,638 |
| 19,301,834 |
|
Iowa | | 105,736 |
| 111,968 |
| | 50,773 |
| 49,630 |
| | 28,834,731 |
| 28,527,522 |
|
Kansas | | 77,609 |
| 81,880 |
| | 42,385 |
| 40,896 |
| | 24,336,744 |
| 23,391,905 |
|
Nebraska | | 183,827 |
| 196,307 |
| | 111,828 |
| 117,925 |
| | 57,815,316 |
| 58,223,856 |
|
Wyoming | | 77,291 |
| 74,361 |
| | 52,850 |
| 51,604 |
| | 26,506,059 |
| 25,480,316 |
|
Total Gas Revenue & Gross Margin (non-GAAP) | | $ | 707,293 |
| $ | 706,640 |
| | $ | 410,006 |
| $ | 392,775 |
| | 181,605,055 |
| 176,108,755 |
|
|
| | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
Gas Utilities Quantities Sold & Transported (Dth) | 2018 | 2017 | 2018 | 2017 |
| | | | |
Arkansas | 4,022,089 |
| 3,950,107 |
| 21,183,322 |
| 18,232,131 |
|
Colorado | 2,893,029 |
| 3,111,653 |
| 19,301,834 |
| 19,156,708 |
|
Nebraska | 13,831,306 |
| 14,620,729 |
| 58,223,856 |
| 52,802,084 |
|
Iowa | 5,595,205 |
| 5,345,911 |
| 28,527,522 |
| 25,472,681 |
|
Kansas | 6,164,821 |
| 7,270,229 |
| 23,391,905 |
| 20,975,597 |
|
Wyoming | 5,592,715 |
| 5,129,822 |
| 25,480,316 |
| 24,529,088 |
|
Total Quantities Sold & Transported | 38,099,165 |
| 39,428,451 |
| 176,108,755 |
| 161,168,289 |
|
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 | 2018 | | | | 2017 |
Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Arkansas (a) | 12 | | (72)% | | (20)% | | 15 | | (66)% |
Colorado | 109 | | (49)% | | (42)% | | 187 | | (13)% |
Nebraska | 101 | | (7)% | | 53% | | 66 | | (40)% |
Iowa | 128 | | (7)% | | 42% | | 90 | | (35)% |
Kansas (a) | 54 | | (2)% | | 46% | | 37 | | (32)% |
Wyoming | 236 | | (23)% | | (23)% | | 307 | | 1% |
Combined (b) | 109 | | (27)% | | (7)% | | 117 | | (22)% |
|
| | | | | | | | | |
| Three Months Ended September 30, |
| 2019 | | | | 2018 |
Heating Degree Days | Actual | | Variance from Normal | | Actual Variance to Prior Year | | Actual | | Variance from Normal |
Arkansas (a) | — | | (100)% | | (100)% | | 12 | | (72)% |
Colorado | 68 | | (68)% | | (38)% | | 109 | | (49)% |
Iowa | 43 | | (69)% | | (66)% | | 128 | | (7)% |
Kansas (a) | — | | (101)% | | (100)% | | 54 | | (2)% |
Nebraska | 22 | | (80)% | | (78)% | | 101 | | (7)% |
Wyoming | 183 | | (37)% | | (22)% | | 236 | | (23)% |
Combined (b) | 53 | | (62)% | | (51)% | | 109 | | (27)% |
|
| | | | | | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, |
Degree Days | 2018 | | | | 2017 |
Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Arkansas (a) | 2,460 |
| | (1 | )% | | 35% | | 1,826 |
| | (26 | )% |
Colorado | 3,548 |
| | (14 | )% | | —% | | 3,541 |
| | (14 | )% |
Nebraska | 4,016 |
| | 6 | % | | 22% | | 3,280 |
| | (13 | )% |
Iowa | 4,460 |
| | 6 | % | | 22% | | 3,641 |
| | (13 | )% |
Kansas (a) | 3,032 |
| | 2 | % | | 17% | | 2,584 |
| | (13 | )% |
Wyoming | 4,552 |
| | (4 | )% | | 2% | | 4,468 |
| | (5 | )% |
Combined (b) | 4,008 |
| | — | % | | 14% | | 3,521 |
| | (12 | )% |
|
| | | | | | | | | |
| | | | | | | | | |
| Nine Months Ended September 30, |
| 2019 | | | | 2018 |
Heating Degree Days: | Actual | | Variance from Normal | | Actual Variance to Prior Year | | Actual | | Variance from Normal |
Arkansas (a) | 2,347 | | (5)% | | (5)% | | 2,460 | | (1)% |
Colorado | 4,115 | | —% | | 16% | | 3,548 | | (14)% |
Iowa | 4,611 | | 10% | | 3% | | 4,460 | | 6% |
Kansas (a) | 3,204 | | 8% | | 6% | | 3,032 | | 2% |
Nebraska | 4,169 | | 10% | | 4% | | 4,016 | | 6% |
Wyoming | 5,093 | | 9% | | 12% | | 4,552 | | (4)% |
Combined (b) | 4,297 | | 7% | | 7% | | 4,008 | | —% |
__________
| |
(a) | Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and certain business rate schedules. Kansas Gas has a weather normalization mechanism within its residential and business rate structure. 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. Thehave weather normalization mechanisms in both Arkansas and Kansas minimizethat mitigate the weather impact on gross margins. |
| |
(b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April. |
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 5 of the Notes to Condensed Consolidated Financial Statements of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2 and Part II, Item 8 of our 20172018 Annual Report on Form 10-K filed with the SEC.
Power Generation
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| (in thousands) |
Revenue (a) | $ | 23,603 |
| $ | 22,927 |
| $ | 676 |
| $ | 68,590 |
| $ | 68,289 |
| $ | 301 |
|
| | | | | | |
Operations and maintenance | 7,434 |
| 7,646 |
| (212 | ) | 25,520 |
| 24,228 |
| 1,292 |
|
Depreciation and amortization (a) | 1,692 |
| 1,036 |
| 656 |
| 4,927 |
| 3,312 |
| 1,615 |
|
Total operating expense | 9,126 |
| 8,682 |
| 444 |
| 30,447 |
| 27,540 |
| 2,907 |
|
| | | | | | |
Operating income | 14,477 |
| 14,245 |
| 232 |
| 38,143 |
| 40,749 |
| (2,606 | ) |
| | | | | | |
Interest expense, net | (1,264 | ) | (724 | ) | (540 | ) | (3,753 | ) | (2,015 | ) | (1,738 | ) |
Other income (expense), net | (34 | ) | (5 | ) | (29 | ) | (75 | ) | (36 | ) | (39 | ) |
Income tax (expense) benefit | (2,494 | ) | (3,426 | ) | 932 |
| (6,549 | ) | (10,114 | ) | 3,565 |
|
| | | | | | |
Net income | 10,685 |
| 10,090 |
| 595 |
| 27,766 |
| 28,584 |
| (818 | ) |
Net income attributable to noncontrolling interest | (3,994 | ) | (3,935 | ) | (59 | ) | (10,447 | ) | (10,567 | ) | 120 |
|
Net income available for common stock | $ | 6,691 |
| $ | 6,155 |
| $ | 536 |
| $ | 17,319 |
| $ | 18,017 |
| $ | (698 | ) |
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | Variance | 2019 | 2018 | Variance |
| (in thousands) |
Revenue | $ | 25,811 |
| $ | 24,491 |
| $ | 1,320 |
| $ | 75,764 |
| $ | 71,173 |
| $ | 4,591 |
|
| | | | | | |
Operations and maintenance | 9,229 |
| 7,434 |
| 1,795 |
| 27,750 |
| 25,520 |
| 2,230 |
|
Depreciation and amortization | 4,760 |
| 3,978 |
| 782 |
| 14,069 |
| 11,922 |
| 2,147 |
|
Total operating expense | 13,989 |
| 11,412 |
| 2,577 |
| 41,819 |
| 37,442 |
| 4,377 |
|
| | | | | | |
Adjusted operating income (a) | $ | 11,822 |
| $ | 13,079 |
| $ | (1,257 | ) | $ | 33,945 |
| $ | 33,731 |
| $ | 214 |
|
____________________________
| |
(a) | The generating facility locatedDue to the changes 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 costour segment disclosures discussed in Note 3 of the facility is recorded at Colorado ElectricNotes to Condensed Consolidated Financial Statements, Power Generation Adjusted operating income was revised for the three and is being depreciated by Colorado Electric for segment reporting purposes.nine months ended September 30, 2018, which resulted in a decrease of $(1.4) million and $(4.4) million, respectively. |
In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Colorado IPP. 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 Colorado Electric. Net income available for common stock for the three months ended September 30, 2018 and September 30, 2017 was reduced by $4.0 million and $3.9 million, respectively, attributable to this noncontrolling interest.
Results of Operations for Power Generation for the Three and Nine Months Ended September 30, 20182019 Compared to the Three and Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Power Generation segment was $6.7 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $6.2 million for the same period in 2017. 2018:
Revenue increased in the current year due to increased wind MWh sold and higher PPA prices and an increase in MWh sold.prices. Operating expenses were comparable to the same period in the prior year reflecting lower maintenance expenses, offset by higher depreciation. Interest expense increased from the same period in the prior year due to higher interest rates. The variance in tax expense reflects the reduction in the federal tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
Results of Operations for Power Generation for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Power Generation segment was $17 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $18 million for the same period in 2017. Revenue increased in the current year as a result of higher PPA prices and an increase in MWh sold. Operating expenses increased from the same period in the prior yearprimarily due to higher maintenance expenses primarily related to outage costs at Wygen Idepreciation and higher depreciation. Interest expense increasedproperty taxes from the same period in the prior year due to higher interest rates. The variance in tax expense reflects the reduction in the federal tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $0.7 million of additional tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.new wind assets.
The following table summarizes MWh for our Power Generation segment:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 | 2019 | 2018 | | 2019 | 2018 |
Quantities Sold, Generated and Purchased (MWh) (a) | | | | | | |
Sold | | | | | | |
Black Hills Colorado IPP (b) | 304,102 |
| 256,895 |
| | 745,365 |
| 725,919 |
| 275,867 |
| 304,102 |
| | 692,156 |
| 745,365 |
|
Black Hills Wyoming (c) | 160,011 |
| 163,690 |
| | 470,072 |
| 476,659 |
| 162,668 |
| 160,011 |
| | 476,430 |
| 470,072 |
|
Black Hills Electric Generation (d) | | 30,912 |
| — |
| | 112,461 |
| — |
|
Total Sold | 464,113 |
| 420,585 |
| | 1,215,437 |
| 1,202,578 |
| 469,447 |
| 464,113 |
| | 1,281,047 |
| 1,215,437 |
|
| | | | | | |
Generated | | | | | | |
Black Hills Colorado IPP (b) | 304,102 |
| 256,895 |
| | 745,365 |
| 725,919 |
| 275,867 |
| 304,102 |
| | 692,156 |
| 745,365 |
|
Black Hills Wyoming (c) | 144,476 |
| 140,081 |
| | 407,324 |
| 407,775 |
| 142,219 |
| 144,476 |
| | 407,001 |
| 407,324 |
|
Black Hills Electric Generation (d) | | 30,912 |
| — |
| | 112,461 |
| — |
|
Total Generated | 448,578 |
| 396,976 |
| | 1,152,689 |
| 1,133,694 |
| 448,998 |
| 448,578 |
| | 1,211,618 |
| 1,152,689 |
|
| | | | | | |
Purchased | | | | | | |
Black Hills Colorado IPP | — |
| — |
| | — |
| — |
| |
Black Hills Wyoming (c) | 16,685 |
| 20,246 |
| | 65,724 |
| 52,463 |
| 16,865 |
| 16,685 |
| | 56,205 |
| 65,724 |
|
Total Purchased | 16,685 |
| 20,246 |
| | 65,724 |
| 52,463 |
| 16,865 |
| 16,685 |
| | 56,205 |
| 65,724 |
|
____________
| |
(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 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. |
| |
(d) | Increase from prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets. |
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, |
| 2019 | 2018 | | 2019 | 2018 |
Contracted power plant fleet availability: | | | | | |
Coal-fired plant | 98.0 | % | 97.9 | % | | 95.2 | % | 93.9 | % |
Natural gas-fired plants (a) | 97.6 | % | 99.3 | % | | 98.4 | % | 99.4 | % |
Wind (b) | 81.9 | % | N/A |
| | 93.4 | % | N/A |
|
Total availability | 93.6 | % | 98.9 | % | | 96.5 | % | 98.0 | % |
| | | | | |
Wind capacity factor (b) | 15.0 | % | N/A |
| | 22.1 | % | N/A |
|
|
| | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 |
Contracted power plant fleet availability: | | | | | |
Coal-fired plant | 97.9 | % | 97.1 | % | | 93.9 | % | 95.8 | % |
Natural gas-fired plants | 99.3 | % | 99.2 | % | | 99.4 | % | 99.1 | % |
Total availability | 98.9 | % | 98.7 | % | | 98.0 | % | 98.3 | % |
____________ | |
(a) | 2019 included a planned outage at Pueblo Airport Generating Station. |
| |
(b) | Change from the prior year is driven by Black Hills Electric Generation’s acquisition of new wind assets. |
Mining
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| (in thousands) |
Revenue | $ | 17,301 |
| $ | 17,493 |
| $ | (192 | ) | $ | 51,328 |
| $ | 48,985 |
| $ | 2,343 |
|
| | | | | | |
Operations and maintenance | 10,761 |
| 11,235 |
| (474 | ) | 32,807 |
| 32,162 |
| 645 |
|
Depreciation, depletion and amortization | 1,989 |
| 2,004 |
| (15 | ) | 5,874 |
| 6,231 |
| (357 | ) |
Total operating expenses | 12,750 |
| 13,239 |
| (489 | ) | 38,681 |
| 38,393 |
| 288 |
|
| | | | | | |
Operating income | 4,551 |
| 4,254 |
| 297 |
| 12,647 |
| 10,592 |
| 2,055 |
|
| | | | | | |
Interest expense, net | (51 | ) | (47 | ) | (4 | ) | (384 | ) | (146 | ) | (238 | ) |
Other income (expense), net | (70 | ) | 567 |
| (637 | ) | (190 | ) | 1,644 |
| (1,834 | ) |
Income tax benefit (expense) | (858 | ) | (1,297 | ) | 439 |
| (2,512 | ) | (3,042 | ) | 530 |
|
| | | | | | |
Net income | $ | 3,572 |
| $ | 3,477 |
| $ | 95 |
| $ | 9,561 |
| $ | 9,048 |
| $ | 513 |
|
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | Variance | 2019 | 2018 | Variance |
| (in thousands) |
Revenue | $ | 15,552 |
| $ | 17,301 |
| $ | (1,749 | ) | $ | 45,026 |
| $ | 51,328 |
| $ | (6,302 | ) |
| | | | | | |
Operations and maintenance | 9,900 |
| 10,761 |
| (861 | ) | 28,988 |
| 32,807 |
| (3,819 | ) |
Depreciation, depletion and amortization | 2,278 |
| 1,989 |
| 289 |
| 6,687 |
| 5,874 |
| 813 |
|
Total operating expenses | 12,178 |
| 12,750 |
| (572 | ) | 35,675 |
| 38,681 |
| (3,006 | ) |
| | | | | | |
Adjusted operating income | $ | 3,374 |
| $ | 4,551 |
| $ | (1,177 | ) | $ | 9,351 |
| $ | 12,647 |
| $ | (3,296 | ) |
The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2018 | 2017 | | 2018 | 2017 | 2019 | 2018 | | 2019 | 2018 |
Tons of coal sold | 1,078 |
| 1,151 |
| | 3,119 |
| 3,127 |
| 969 |
| 1,078 |
| | 2,720 |
| 3,119 |
|
Cubic yards of overburden moved | 2,361 |
| 2,316 |
| | 6,763 |
| 6,381 |
| 2,341 |
| 2,361 |
| | 6,380 |
| 6,763 |
|
| | | | | | |
Revenue per ton | $ | 15.54 |
| $ | 15.20 |
| | $ | 15.92 |
| $ | 15.67 |
| $ | 15.47 |
| $ | 15.54 |
| | $ | 15.90 |
| $ | 15.92 |
|
Results of Operations for Mining for the Three Months Ended September 30, 20182019 Compared to the Three Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Mining segment was $3.6 million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $3.5 million for the same period in 2017. Revenue was comparable to the prior year reflecting a 6% decrease in tons sold and a 2% increase in price per ton sold driven by contract price adjustments based on actual mining costs. 2018:
Current year revenue is also reflectivedecreased due to 10% fewer tons sold driven primarily by unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues.
Results of leaseOperations for Mining for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018:
Current year revenue decreased due to 13% fewer tons sold driven primarily by planned and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 49% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
unplanned generation facility outages. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor and major maintenance expenses. Other income (expense), net decreased from the prior year due to the presentation change
Results of Operations for Mining for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net income from continuing operations available for common stock for the Mining segment was $9.6 million for the nine months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $9.0 million for the same period in 2017. Revenue increased primarily due to a 2% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 49% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operating expenses increased primarily due to higher overburden removal and higher fuel expenses. Other income (expense), net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income (expense), net. The variance in tax expense to the prior year reflects the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by $0.5 million of additional tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes.
Corporate and Other
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| (in thousands) |
Operating (loss) (a) | $ | (16 | ) | $ | (1,401 | ) | $ | 1,385 |
| $ | (2,301 | ) | $ | (7,183 | ) | $ | 4,882 |
|
| | | | | | |
Other income (expense): | | | | | | |
Interest (expense) income, net (a) | (626 | ) | (1,028 | ) | 402 |
| (1,810 | ) | (2,331 | ) | 521 |
|
Other income (expense), net | 520 |
| (31 | ) | 551 |
| 702 |
| (869 | ) | 1,571 |
|
Income tax benefit (expense) | (635 | ) | (1,204 | ) | 569 |
| (2,468 | ) | 3,389 |
| (5,857 | ) |
| | | | | | |
Net income (loss) | $ | (757 | ) | $ | (3,664 | ) | $ | 2,907 |
| $ | (5,877 | ) | $ | (6,994 | ) | $ | 1,117 |
|
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | Nine Months Ended September 30, |
| 2019 | 2018 | Variance | 2019 | 2018 | Variance |
| (in thousands) |
Adjusted operating income (loss) (a) | $ | (34 | ) | $ | (178 | ) | $ | 144 |
| $ | (439 | ) | $ | (2,709 | ) | $ | 2,270 |
|
____________________________
| |
(a) | Includes certain generalDue to the changes in our segment disclosures as discussed in Note 3 of the Notes to Condensed Consolidated Financial Statements, Corporate and administrative expensesOther Adjusted operating income (loss) was revised for the three and interest expenses that are not reported as discontinued operationsnine months ended September 30, 2018, which resulted in 2017.a decrease of $(0.2) million and $(0.4) million, respectively. |
Results of Operations for Corporate and Other for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net loss from continuing operations available for common stock for Corporate and Other was $(0.8) million for the three months ended September 30, 2018, compared to Net income from continuing operations available for common stock of $(3.7) million for the three months ended September 30, 2017. The variance was driven by higher prior year operating costs previously allocated to our Oil and Gas segment in 2017, which were not reclassified to discontinued operations in 2017, and are allocated to our operating segments in 2018. Income tax benefit (expense) increased in the current year due to higher state income tax expense.
Results of Operations for Corporate and Other for the Nine Months Ended September 30, 20182019 Compared to the Three and Nine Months Ended September 30, 2018:
The variance in Adjusted operating income (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.
Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018.
Impairment of Investment
For the three months ended September 30, 2019, we recorded a non-cash write-down of $20 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for additional details.
Income Tax Benefit (Expense)
Income tax benefit (expense) for the three months ended September 30, 2019 was $(2.5) million compared to $(7.5) million for the same period in 2018. The decrease in tax expense was primarily due to a prior year $(5.3) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.
For the three months ended September 30, 2019 the effective tax rate was 14.0% compared to 7.6% excluding the tax reform adjustments, for the same period in 2018. The higher effective tax rate is primarily due to a prior year state tax benefit.
Consolidated Interest expense, Impairment of investment, Other income (expense) and Income tax benefit (expense) for the Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2017: Net loss from continuing operations available2018.
Impairment of Investment
For the nine months ended September 30, 2019, we recorded a non-cash write-down of $20 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. See Note 21 of the Notes to Condensed Consolidated Financial Statements for common stock for Corporate and Other was $(5.9) millionadditional details.
Income Tax Benefit (Expense)
Income tax benefit (expense) for the nine months ended September 30, 2018,2019 was $(22) million compared to Net loss from continuing operations available for common stock of $(7.0)$12 million reported for the nine months ended September 30, 2017.same period in 2018. The variance to the prior year was driven by higher prior year operating costs previously allocated to our Oil and Gas segment which were not reclassified to discontinued operationsincrease in 2017, which are allocated to our operating segments in 2018 and transition and acquisition expenses which occurred in the prior year. The variance in Income tax benefit (expense)expense was primarily due to a prior year $49 million tax benefit of $1.4 million comprised primarily of benefitsresulting from a carryback claim for specified liability losses involving prior tax years and current year tax expense.
Discontinued Operations
Results of Discontinued Operations for the Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017: Net loss from discontinued operations was $(0.9) million for the three months ended September 30, 2018, compared to Net loss from discontinued operations of $(1.3) million for the same period in 2017. The variance to the prior year is driven by lower revenues due to property sales and higher losses on sales of operating assets,legal entity restructuring partially offset by lower oil and gas operating expenses and lower employee costs. Depreciation and depletiona prior year $(7.5) million income tax expense was recordedassociated with changes in the prior year under full cost accounting, which ceased November 1, 2017 due to reclassification to assets held for sale.previously estimated impact of tax reform on deferred income taxes.
Results of Discontinued Operations for the Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017: Net loss from discontinued operations was $(5.6) million forFor the nine months ended September 30, 2018,2019 the effective tax rate was 13.6% compared to Net loss from discontinued operations of $(3.5) million17.1% excluding the legal entity restructuring and tax reform adjustments, for the same period in 2017.2018. The variance to the prior yearlower effective tax rate is driven by lower revenuesprimarily due to property sales$5.0 million of federal production tax credits and higher losses on sales of operatingrelated state investment tax credits associated with new wind assets, partially offset by lower oil and gas operating expenses and lower employee costs. Current year depreciation expense is representative of thea $1.0 million tax benefit for deferred tax amortization of the remaining book value of accounting software. Depreciation and depletion expense was recorded in the prior year under full cost accounting, which ceased November 1, 2017 duerelated to reclassification to assets held for sale.tax reform.
Critical Accounting Estimates
There have been no material changes in our critical accounting estimates from those reported in our 20172018 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting estimates, see Part II, Item 7 of our 20172018 Annual Report on Form 10-K.
Liquidity and Capital Resources
OVERVIEW
Our Company requires significant cash to supportThere have been no material changes in Liquidity and growCapital Resources from those reported in Item 7 of 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. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying2018 Annual Report on Form 10-K filed with the TCJA and the impact of providing TCJA benefits to customers.SEC except as described below.
The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.Collateral Requirements
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, 2018,2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Income Tax
The TCJA legislation was signed into law on December 22, 2017. The new tax law required revaluation at December 31, 2017 of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%. As a result of the revaluation, deferred tax assetsWe have reached agreements with regulators in seven states and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is relatedare working with FERC regarding returning benefits to our regulated utilities and is reclassified to a regulatory liability. During the nine months ended September 30, 2018, we recorded approximately $16 million of additional regulatory liability associated with TJCA related items. This regulatory liability will generally be amortized over the remaining life of the related assets as specifically prescribed in the TCJA.
We expect an increase incustomers. Our working capital requirements increased as a result of complying with the TCJA and providing the impactbenefits of providingthe TCJA benefits to customers. We estimate the lower tax rateThese agreements will negatively impact the Company’sour cash flows by approximately $40 million to $45 million annuallyper year for each of the next several years. Each of our utilities is working with their respective regulators to address the impact of tax reform and the appropriate benefit to customers. See Note 5 for more information on regulatory matters.
Cash Flow Activities
The following table summarizes our cash flows for the threenine months ended September 30, 2019 (in thousands):
| | Cash provided by (used in): | 2018 | 2017 | Increase (Decrease) | 2019 | 2018 | Variance |
Operating activities | $ | 378,722 |
| $ | 319,430 |
| $ | 59,292 |
| $ | 386,075 |
| $ | 378,722 |
| $ | 7,353 |
|
Investing activities | $ | (281,771 | ) | $ | (255,978 | ) | $ | (25,793 | ) | $ | (593,272 | ) | $ | (281,771 | ) | $ | (311,501 | ) |
Financing activities | $ | (101,949 | ) | $ | (63,112 | ) | $ | (38,837 | ) | $ | 199,827 |
| $ | (101,949 | ) | $ | 301,776 |
|
Year-to-Date 20182019 Compared to Year-to-Date 20172018
Operating Activities
Net cash provided by operating activities was $379$386 million for the nine months ended September 30, 2018,2019, compared to net cash provided by operating activities of $319$379 million for the same period in 20172018 for an increase of $59$7 million. The variance was primarily attributable to:
Cash earnings (income from continuing operations plus non-cash adjustments) were $14$19 million lowerhigher for the nine months ended September 30, 20182019 compared to the same period in the prior year;
Net cash inflows from changes in operating assets and liabilities were $29$28 million for the nine months ended September 30, 2018,2019, compared to net cash outflowsinflows of $60$42 million in the same period in the prior year. This $90$14 million increasedecrease was primarily due to:
| |
◦ | Cash inflows increased by approximately $48 million primarily as a result of higher collections of accounts receivable for the nine months ended September 30, 2019 compared to the same period in the prior year; |
| |
◦ | Cash outflows increased by approximately $3 million as a result of decreases in accounts payable and accrued liabilities driven by higher employee costs and other working capital requirements; and |
| |
◦ | Cash inflows decreased by approximately $21 million primarily as a result of increases in pre-paid tax assets and lower collections of accounts receivable, partially offset by lower natural gas in storage for the nine months ended September 30, 2018 compared to the same period in the prior year; |
| |
◦ | Cash outflows decreased by approximately $26 million as a result of increases in accounts payable and accrued liabilities driven by changes in prior year accrued interest and contract payments and other working capital requirements; |
| |
◦ | Cash inflows increased by approximately $66 million as a result of changes in our current regulatory assets and liabilities driven by differences inthe timing of recovery from fuel cost adjustments and cash collected from customers that will be refundedas well as revenue reserved in the prior year due to the TCJA tax rate change; andchange that has subsequently been returned to customers. |
| |
◦ | Net cash outflows decreased by $15 million due to additional pension contributions made in the prior year. |
Investing Activities
Net cash used in investing activities was $282$593 million for the nine months ended September 30, 2018,2019, compared to net cash used in investing activities of $256$282 million for the same period in 20172018 for a variance of $26$311 million. The variance was primarily attributable to:
Capital expenditures of approximately $278$593 million for the nine months ended September 30, 20182019 compared to $239$278 million for the same period in the prior year. Higher current year expenditures are driven by higher programmatic safety, reliability and integrity spending at our gas utilities, miningGas Utilities and power generationElectric Utilities segments, arethe 35-mile Natural Bridge pipeline project at our Gas Utilities segment, the Busch Ranch II wind project at our Power Generation segment and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska at our Electric Utilities segment.
A $24 million investment made in the prior year partially offset by higher prior year expenditures at our electric utilities which included completion of the second segment of the 144-mile long Teckla-Lange transmission line and construction of our Horizon Point facility.
A $35an $18 million change in net cash provided by investing activities from discontinued operations primarily due to the prior year sale of assets held for sale partially offset by a $24 million investment.sale.
Financing Activities
Net cash used inprovided by financing activities for the nine months ended September 30, 20182019 was $102$200 million, compared to $63$102 million of net cash used in financing activities for the same period in 20172018 for a variance of $39$302 million. This variance is primarily due to:
Long–We amended our Corporate term borrowingsloan due July 30, 2020, which increased dueour debt to the$400 million from $300 million;
Current year issuance of $400common stock for net proceeds of $99 million principal amount senior secured notes in 2018, a portionthrough our ATM equity offering program;
Current year net short-term borrowings of which were issued in exchange for $299$109 million principal amount of our RSNs due 2028 (which were immediately retired) and a portion of which were sold todriven by increased capital expenditures;
In the public withprior year, $99 million of net proceeds from the August 17, 2018 debt transaction was used to pay downrepay short-term debt;
We amended and restated our $300 million unsecured term loan due August 2019;
Prior year net short-term borrowings of $129 million offset by prior year long-term debt repayments of $104 million;
$5.015 million of higher current year dividend payments; and
Increased paymentsPayments for other financing activities of approximately $3.7decreased by $8.4 million, which was primarily driven primarily by prior year financing costs associated with the July 30, 2018 and August 17, 2018 debt transactions.
Dividends
Dividends paid on our common stock totaled $76$92 million for the nine months ended September 30, 2018,2019, or $0.475$0.505 per share per quarter. On October 30, 2018,31, 2019, our board of directors declared a quarterly dividend of $0.505$0.535 per share payable December 1, 2018,2019, equivalent to an annual dividend of $2.02$2.14 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 July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. See Note 9 for more information.
We have 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. See Note 9 for more information.
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 | | Current | Short-term borrowings at | Letters of Credit at | Available Capacity at |
Credit Facility | Expiration | Capacity | September 30, 2018 | September 30, 2018 | Expiration | Capacity | September 30, 2019 | September 30, 2019 |
Revolving Credit Facility | July 30, 2023 | $ | 750 |
| $ | — |
| $ | 112 |
| $ | 15 |
| $ | 623 |
| |
Revolving Credit Facility and CP Program | | July 30, 2023 | $ | 750 |
| $ | 295 |
| $ | 18 |
| $ | 437 |
|
The weighted average interest rate on CP Programshort-term borrowings at September 30, 20182019 was 2.42%2.43%. Revolving Credit Facility and CP Program financingShort-term borrowing activity for the nine months ended September 30, 20182019 was (dollars in millions):
|
| | | |
| For the Nine Months Ended September 30, 2018 |
Maximum amount outstanding - commercial paper (based on daily outstanding balances) | $ | 231 |
|
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | — |
|
Average amount outstanding - commercial paper (based on daily outstanding balances) | $ | 135 |
|
Average amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | — |
|
Weighted average interest rates - commercial paper | 2.16 | % |
Weighted average interest rates - revolving credit facility | — | % |
|
| | | |
| For the Nine Months Ended September 30, 2019 |
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 295 |
|
Average amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 171 |
|
Weighted average interest rates - short-term borrowing | 2.59 | % |
Covenant Requirements
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 and certain guarantees issued but excludes the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs or, with respect to the calculation as of September 30, 2018 only, the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units). 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, 2018.
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, 2018 consisted2019. See Note 8 of the following:
Short-term borrowings from our CP Program.
On August 17, 2018, we completed a public debt offering of $400 million principal amount, 4.350% senior unsecured notes due 2033. The proceeds were usedNotes to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt. Through this offering, we successfully remarketed the $299 million principal amount of the existing subordinated notes, which were originally issued as a part of the Company's Equity Units on November 23, 2015. See Note 9Condensed Consolidated Financial Statements for more information.
On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, will now mature July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. See Note 9 for more information.
On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued
November 23, 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. See Note 10 for more information.
On August 4, 2017, we renewed the ATM equity offering program 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 for the nine months ended September 30, 2018.
Future Financing Plans
Evaluating refinancing options for our $200 million senior notes due July 15, 2020 and the $300 million senior notes due July 30, 2020.
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 andCovenants within 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, 2018, 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 loan 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 and certain guarantees issued but excludes the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs or, with respect to the calculation as of September 30, 2018 only, the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units). Additionally, covenants within Cheyenne Light’sElectric’s financing agreements require Cheyenne LightWyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2018,2019, we were in compliance with these covenants.
ThereFinancing Activities
Financing activities for the nine months ended September 30, 2019 consisted of the following:
We issued a total of 1,328,332 shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.0 million in commissions. As of September 30, 2019, there were no shares that were sold, but not settled.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continues to have been no other material changessubstantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
Short-term borrowings from our CP Program and Revolver.
On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, repay a portion of short-term debt.
Future Financing Plans
We will continue to assess debt and equity needs to support our financing transactions and short-term liquidity from those reported in Item 7 of our 2017 Annual Report on Form 10-K filed with the SEC.capital expenditure plan.
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, 2018:2019:
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Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
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(a) | On August 9, 2018,February 28, 2019, S&P upgraded toaffirmed our BBB+ rating and revised the outlook to Stable.maintained a Stable outlook. |
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(b) | On December 12, 2017,2018, Moody’s affirmed our Baa2 rating and maintained a Stable outlook. |
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(c) | On October 11, 2018,August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook. |
The following table represents the credit ratings of South Dakota Electric at September 30, 2018:
2019:
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Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s(b) | A1 |
Fitch (b)(c) | A |
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(a) | On August 9, 2018,April 30, 2019, S&P upgraded toaffirmed A rating. |
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(b) | On July 19, 2018,October 15, 2019, Moody’s affirmed A1 rating. |
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(c) | On August 29, 2019, Fitch affirmed A rating. |
Capital Requirements
Capital Expenditures
Actual and forecasted capital requirements are as follows (in thousands):
| | | Expenditures for the | | Total | | Total | | Total | Actual | Planned |
| Nine Months Ended September 30, 2018 (a) | | 2018 Planned Expenditures (b) | | 2019 Planned Expenditures | | 2020 Planned Expenditures | |
Electric Utilities | $ | 105,295 |
| | $ | 141,000 |
| | $ | 192,000 |
| | $ | 165,000 |
| |
Capital Expenditures by Segment | | Nine Months Ended September 30, 2019 (a) | 2019 (b) | 2020 | 2021 | 2022 | 2023 |
(in millions) | | |
Electric Utilities (c) | | $ | 147 |
| $ | 215 |
| $ | 229 |
| $ | 203 |
| $ | 170 |
| $ | 137 |
|
Gas Utilities (c) | 172,599 |
| | 270,000 |
| | 374,000 |
| | 273,000 |
| 367 |
| 490 |
| 361 |
| 297 |
| 274 |
| 303 |
|
Power Generation (d) | 4,350 |
| | 46,000 |
| | 60,000 |
| | 9,000 |
| |
Power Generation | | 79 |
| 84 |
| 7 |
| 9 |
| 11 |
| 6 |
|
Mining | 11,982 |
| | 19,000 |
| | 8,000 |
| | 7,000 |
| 6 |
| 8 |
| 8 |
| 12 |
| 9 |
| 9 |
|
Corporate and Other | 8,426 |
| | 12,000 |
| | 17,000 |
| | 21,000 |
| 15 |
| 23 |
| 18 |
| 22 |
| 11 |
| 12 |
|
| $ | 302,652 |
| | $ | 488,000 |
| | $ | 651,000 |
| | $ | 475,000 |
| $ | 614 |
| $ | 820 |
| $ | 623 |
| $ | 543 |
| $ | 475 |
| $ | 467 |
|
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(a) Expenditures for the nine months ended September 30, 20182019 include the impact of accruals for property, plant and equipment.
(b) Includes actual capital expenditures for the nine months ended September 30, 2018.2019.
(c) Planned capital expenditures increased for 2018, 2019 and 2020 increasedthrough 2023 primarily due to higherincreased programmatic safety, reliability and integrity spending.
(d) Planned capital expenditures for 2018 increased due to purchase of AltaGas’s interest in Busch Ranch I.
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.
Contractual Obligations
There have been no significant changes in contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 20172018 Annual Report on Form 10-K.10-K except for the items described in Notes 8, 16, and 20 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
Guarantees
Off-Balance Sheet Commitments
There have been no significant changes to guaranteesoff-balance sheet commitments from those previously disclosed in Item 7 of our 2018 Annual Report on Form 10-K filed with the SEC except for the items described in Note 208 of the Notes to theCondensed Consolidated Financial Statements in our 2017 Annualthis Quarterly Report on Form 10-K.10-Q.
New Accounting Pronouncements
Other than the pronouncements reported in our 20172018 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 the statement was made. 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 20172018 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 20172018 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. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Information regarding our quantitative and qualitative disclosures about market risk is disclosed in Item 7A of our Annual Report on Form 10-K. During the nine months ended September 30, 2019, there were no material changes to our quantitative and qualitative disclosures about market risk.
Utilities
Our utility customers are exposed 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, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. We also reduce the commodity price risk in the unregulated area of our business by using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales. The fair value of our utilities’ derivative contracts is summarized below (in thousands) as of:
|
| | | | | | | | | | | |
| September 30, 2018 | | December 31, 2017 | | September 30, 2017 |
Net derivative (liabilities) assets | $ | (1,869 | ) | | $ | (6,644 | ) | | $ | (6,541 | ) |
Cash collateral offset in Derivatives | 4,308 |
| | 7,694 |
| | 5,452 |
|
Cash collateral included in Other current assets | 4,677 |
| | 562 |
| | 2,841 |
|
Net asset (liability) position | $ | 7,116 |
| | $ | 1,612 |
| | $ | 1,752 |
|
Financing Activities
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 debt refinancings. At September 30, 2018, December 31, 2017 and September 30, 2017, we had no outstanding interest rate swap agreements.
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) as of September 30, 2018.2019. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2018.2019.
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’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, 2018,2019, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
BLACK HILLS CORPORATION
Part II — Other Information
For information regarding legal proceedings, see Note 19 in Item 8 of our 20172018 Annual Report on Form 10-K and Note 1716 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1716 is incorporated by reference into this item.
There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2017 Annual Report on Form 10-K filed with the SEC.
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ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
There were no unregistered securities sold during the nine months ended September 30, 2018.
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ITEM 4. | Mine Safety Disclosures |
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.
None.
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Exhibit Number | Description |
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Exhibit 3.1* | |
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Exhibit 3.2* | |
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Exhibit 4.1* | |
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Exhibit 4.2* | |
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Exhibit 4.3* | |
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Exhibit 4.4* | |
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Exhibit 4.5* | |
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Exhibit 4.6* | |
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Exhibit 10.1*10.1 | Third Amended and Restated Credit AgreementFirst Amendment dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1June 17, 2019 to the Registrant’s Form 8–K filed on July 31, 2018). |
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Exhibit 10.2* | Amended and Restated Credit Agreement dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.210.1 to the Registrant’s Form 8–K filed on July 31, 2018)June 17, 2019). |
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Exhibit 31.1 | |
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Exhibit 31.2 | |
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Exhibit 32.1 | |
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Exhibit 32.2 | |
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Exhibit 95 | |
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101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
101.SCH | XBRL Taxonomy Extension Schema Document |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
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104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101 | Financial Statements for XBRL Format.101) |
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* | Previously filed as part of the filing indicated and incorporated by reference herein. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BLACK HILLS CORPORATION
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| | |
| | /s/ DavidLinden R. EmeryEvans |
| | DavidLinden R. Emery, ChairmanEvans, President and |
| | Chief Executive Officer |
| | |
| | /s/ Richard W. Kinzley |
| | Richard W. Kinzley, Senior Vice President and |
| | Chief Financial Officer |
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Dated: | November 6, 20185, 2019 | |