UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
|
| |
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
| | EXCHANGE ACT OF 1934 |
| | For the quarterly period ended June 30, 20172018 |
| OR | |
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
| | EXCHANGE ACT OF 1934 |
| | For the transition period from __________ to __________. |
| | |
| | Commission File Number 001-31303 |
|
| |
| Black Hills Corporation |
| Incorporated in South Dakota | IRS Identification Number 46-0458824 |
625 Ninth Street7001 Mount Rushmore Road |
Rapid City, South Dakota 5770157702 |
| Registrant’s telephone number (605) 721-1700 |
| 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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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.
|
| | | | |
| | Large accelerated filer x | | Accelerated filer o | |
| | | | | |
| | Non-accelerated filer o | (Do not check if a smaller reporting company) |
| | | | | |
| | | | Smaller reporting company o | |
| | | | | |
| | | | Emerging growth company o | |
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).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
|
| | | |
| Class | Outstanding at July 31, 20172018 |
| Common stock, $1.00 par value | 53,475,19053,594,876 |
| shares |
|
| | | |
| TABLE OF CONTENTS |
| | | | Page |
| | Glossary of Terms and Abbreviations | | |
| | | | |
| PART I. | FINANCIAL INFORMATION | | |
| | | | |
| Item 1. | Financial Statements | | |
| | | | |
| | Condensed Consolidated Statements of Income - unaudited | | |
| | Three and Six Months Ended June 30, 20172018 and 20162017 | | |
| | | | |
| | Condensed Consolidated Statements of Comprehensive Income - unaudited | | |
| | Three and Six Months Ended June 30, 20172018 and 20162017 | | |
| | | | |
| | Condensed Consolidated Balance Sheets - unaudited | | |
| | June 30, 2017,2018, December 31, 20162017 and June 30, 20162017 | | |
| | | | |
| | Condensed Consolidated Statements of Cash Flows - unaudited | | |
| | Six Months Ended June 30, 20172018 and 20162017 | | |
| | | | |
| | Notes to Condensed Consolidated Financial Statements - unaudited | | |
| | | | |
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | | |
| | | | |
| Item 3. | Quantitative and Qualitative Disclosures about Market Risk | | |
| | | | |
| Item 4. | Controls and Procedures | | |
| | | | |
| PART II. | OTHER INFORMATION | | |
| | | | |
| Item 1. | Legal Proceedings | | |
| | | | |
| Item 1A. | Risk Factors | | |
| | | | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | | |
| | | | |
| Item 4. | Mine Safety Disclosures | | |
| | | | |
| Item 5. | Other Information | | |
| | | | |
| Item 6. | Exhibits | | |
| | | | |
| | Signatures | | |
| | | |
| Index to Exhibits | | |
GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
|
| |
| 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. |
Stockton Storage | Arkansas Gas storage facility |
ARMRP | At-Risk Meter Relocation Program |
| 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 Gas | Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC |
Black Hills Gas Holdings | Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC |
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 Energy Arkansas Gas | Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations |
Black Hills Energy Colorado Electric | Includes Colorado Electric’s utility operations |
Black Hills Energy Colorado Gas | Includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG |
Black Hills Energy Iowa Gas | Includes Black Hills Energy Iowa gas utility operations |
Black Hills Energy Kansas Gas | Includes Black Hills Energy Kansas gas utility operations |
Black Hills Energy Nebraska Gas | Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations |
Black Hills Energy South Dakota Electric | Includes Black Hills Power operations in South Dakota, Wyoming and Montana |
Black Hills Energy Wyoming Electric | Includes Cheyenne Light’s electric utility operations |
Black Hills Energy Wyoming Gas | Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations |
Black Hills Gas Distribution | Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC. |
Black Hills Non-regulated Holdings | Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation |
| 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 |
Btu | British thermal unit |
| CAPP | Customer Appliance Protection Plan |
|
| |
Ceiling Test | Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using prices and a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. |
| Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) |
| 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 distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers.
|
| CIAC | Contribution In Aid of Construction |
| City of Gillette | Gillette, Wyoming |
| Colorado Electric | Black Hills Colorado Electric, Utility Company, LP, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
Colorado Gas | Black Hills Colorado Gas Utility Company, LP,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 Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement. |
Cooling Degree DayCDD | A cooling degree day is equivalent to each degree that the average of the high and low temperature 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. |
CostCPCN | Certificate of Service Gas Program (COSG) | Proposed Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.Public Convenience and Necessity |
| CP Program | Commercial Paper Program |
| CPUC | Colorado Public Utilities Commission |
| CVA | Credit Valuation Adjustment |
| Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
DSM | Demand Side Management |
| Dth | Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu) |
ECA |
| Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers. |
| Equity Unit | Each Equity Unit has 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 due 2028. |
| 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 |
Global Settlement | Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders. |
GSRS | Gas System Reliability Surcharge |
Heating Degree DayHDD | 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. |
Iowa GasHorizon Point | Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017. |
| 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) |
KCC | Kansas Corporation Commission |
kV | Kilovolt |
| LIBOR | London Interbank Offered Rate |
LOE | Lease Operating Expense |
Mcf | Thousand cubic feet |
Mcfe | Thousand cubic feet equivalent |
| MMBtu | Million British thermal units |
| Moody’s | Moody’s Investors Service, Inc. |
MRP | Meter Relocation Program |
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) |
NGLOCA | Natural Gas Liquids (1 barrel equals 6 Mcfe) |
NOL | Net Operating Loss |
NPSC | Nebraska Public Service Commission |
NYMEX | New York Mercantile Exchange |
NYSE | New York Stock ExchangeOffice of Consumer Advocate |
| Peak View Wind Project | $109 million 60 MW wind generating project for Colorado Electric, adjacent to Busch Ranch wind farm |
| PPA | Power Purchase Agreement |
| Revolving Credit Facility | Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2021.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 |
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 |
SourceGas Transaction | On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. |
| S&P | Standard and Poor’s, a division of The McGraw-Hill Companies, Inc. |
| South Dakota Electric | Includes Black Hills Power operations in South Dakota, Wyoming and Montana |
| SSIR | System Safety and Integrity Rider |
TCATCJA | Transmission Cost Adjustment -- adjustments passed through to the customer basedTax Cuts and Jobs Act enacted on transmission costs that are higher or lower than the costs approved in the rate case.December 22, 2017 |
| VIE | Variable interest entity |
Winter Storm AtlasWPSC | An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history. |
WRDC | Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated HoldingsWyoming Public Service Commission |
| Wyodak Plant | Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by Pacificorp 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
|
Wyoming Gas | Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations |
BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
| | | (unaudited) | Three Months Ended
June 30, | Six Months Ended
June 30, | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | 2017 | 2016 | 2018 | 2017 | 2018 | 2017 |
| | (in thousands, except per share amounts) | (in thousands, except per share amounts) |
| | | |
| Revenue | $ | 347,978 |
| $ | 325,441 |
| $ | 901,981 |
| $ | 775,400 |
| $ | 355,704 |
| $ | 341,829 |
| $ | 931,093 |
| $ | 889,357 |
|
| | | |
| Operating expenses: | | |
| Fuel, purchased power and cost of natural gas sold | 98,164 |
| 84,489 |
| 317,941 |
| 256,345 |
| 104,661 |
| 98,164 |
| 352,300 |
| 317,941 |
|
| Operations and maintenance | 117,374 |
| 112,541 |
| 239,504 |
| 219,603 |
| 118,282 |
| 111,897 |
| 234,378 |
| 226,449 |
|
| Depreciation, depletion and amortization | 48,663 |
| 47,305 |
| 97,310 |
| 91,712 |
| 48,709 |
| 46,825 |
| 97,299 |
| 93,527 |
|
| Taxes - property, production and severance | 13,743 |
| 12,760 |
| 27,712 |
| 24,877 |
| 13,976 |
| 13,072 |
| 27,276 |
| 26,458 |
|
| Impairment of long-lived assets | — |
| 25,497 |
| — |
| 39,993 |
| |
| Other operating expenses | 1,168 |
| 7,551 |
| 3,137 |
| 33,982 |
| 525 |
| 2,075 |
| 2,015 |
| 5,000 |
|
| Total operating expenses | 279,112 |
| 290,143 |
| 685,604 |
| 666,512 |
| 286,153 |
| 272,033 |
| 713,268 |
| 669,375 |
|
| | | |
| Operating income | 68,866 |
| 35,298 |
| 216,377 |
| 108,888 |
| 69,551 |
| 69,796 |
| 217,825 |
| 219,982 |
|
| | | |
| Other income (expense): | | |
| Interest charges - | | |
| Interest expense incurred (including amortization of debt issuance costs, premiums and discounts) | (35,098 | ) | (34,609 | ) | (70,194 | ) | (66,683 | ) | (35,425 | ) | (35,072 | ) | (70,880 | ) | (70,130 | ) |
| Allowance for funds used during construction - borrowed | 822 |
| 754 |
| 1,308 |
| 1,255 |
| 511 |
| 822 |
| 644 |
| 1,308 |
|
| Capitalized interest | 130 |
| 268 |
| 299 |
| 503 |
| 60 |
| 58 |
| 77 |
| 133 |
|
| Interest income | 257 |
| 946 |
| 298 |
| 1,601 |
| 320 |
| 257 |
| 630 |
| 298 |
|
| Allowance for funds used during construction - equity | 794 |
| 982 |
| 1,286 |
| 1,689 |
| 242 |
| 794 |
| 310 |
| 1,286 |
|
| Other income (expense), net | (58 | ) | (47 | ) | (160 | ) | 641 |
| (1,551 | ) | (76 | ) | (1,723 | ) | (195 | ) |
| Total other income (expense), net | (33,153 | ) | (31,706 | ) | (67,163 | ) | (60,994 | ) | (35,843 | ) | (33,217 | ) | (70,942 | ) | (67,300 | ) |
| | | |
| Income before income taxes | 35,713 |
| 3,592 |
| 149,214 |
| 47,894 |
| 33,708 |
| 36,579 |
| 146,883 |
| 152,682 |
|
| Income tax benefit (expense) | (10,402 | ) | (309 | ) | (43,757 | ) | (4,561 | ) | (6,541 | ) | (10,652 | ) | 19,261 |
| (45,040 | ) |
| Income from continuing operations | | 27,167 |
| 25,927 |
| 166,144 |
| 107,642 |
|
| (Loss) from discontinued operations, net of tax | | (2,427 | ) | (616 | ) | (4,770 | ) | (2,185 | ) |
| Net income | 25,311 |
| 3,283 |
| 105,457 |
| 43,333 |
| 24,740 |
| 25,311 |
| 161,374 |
| 105,457 |
|
| Net income attributable to noncontrolling interest | (3,116 | ) | (2,614 | ) | (6,739 | ) | (2,662 | ) | (2,823 | ) | (3,116 | ) | (6,453 | ) | (6,739 | ) |
| Net income available for common stock | $ | 22,195 |
| $ | 669 |
| $ | 98,718 |
| $ | 40,671 |
| $ | 21,917 |
| $ | 22,195 |
| $ | 154,921 |
| $ | 98,718 |
|
| | | |
| Amounts attributable to common shareholders: | | |
| Net income from continuing operations | | $ | 24,344 |
| $ | 22,811 |
| $ | 159,691 |
| $ | 100,903 |
|
| Net (loss) from discontinued operations | | (2,427 | ) | (616 | ) | (4,770 | ) | (2,185 | ) |
| Net income available for common stock | | $ | 21,917 |
| $ | 22,195 |
| $ | 154,921 |
| $ | 98,718 |
|
| | | |
| Earnings per share of common stock: | | |
| Earnings (loss) per share, Basic - | | |
| Income from continuing operations, per share | | $ | 0.46 |
| $ | 0.43 |
| $ | 2.99 |
| $ | 1.90 |
|
| (Loss) from discontinued operations, per share | | (0.05 | ) | (0.01 | ) | (0.09 | ) | (0.04 | ) |
| Earnings per share, Basic | $ | 0.42 |
| $ | 0.01 |
| $ | 1.86 |
| $ | 0.79 |
| $ | 0.41 |
| $ | 0.42 |
| $ | 2.90 |
| $ | 1.86 |
|
| | | |
| Earnings (loss) per share, Diluted - | | |
| Income from continuing operations, per share | | $ | 0.45 |
| $ | 0.41 |
| $ | 2.94 |
| $ | 1.83 |
|
| (Loss) from discontinued operations, per share | | (0.05 | ) | (0.01 | ) | (0.09 | ) | (0.04 | ) |
| Earnings per share, Diluted | $ | 0.40 |
| $ | 0.01 |
| $ | 1.79 |
| $ | 0.78 |
| $ | 0.40 |
| $ | 0.40 |
| $ | 2.85 |
| $ | 1.79 |
|
| Weighted average common shares outstanding: | | |
| Basic | 53,229 |
| 51,514 |
| 53,191 |
| 51,279 |
| 53,355 |
| 53,229 |
| 53,337 |
| 53,191 |
|
| Diluted | 55,384 |
| 52,986 |
| 55,179 |
| 52,454 |
| 54,520 |
| 55,384 |
| 54,361 |
| 55,179 |
|
| | | |
| Dividends declared per share of common stock | $ | 0.445 |
| $ | 0.420 |
| $ | 0.890 |
| $ | 0.840 |
| $ | 0.475 |
| $ | 0.445 |
| $ | 0.950 |
| $ | 0.890 |
|
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 (LOSS)
|
| | | | | | | | | | | | |
| (unaudited) | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | 2017 | 2016 | 2017 | 2016 |
| | (in thousands) |
| | | | | |
| Net income (loss) | $ | 25,311 |
| $ | 3,283 |
| $ | 105,457 |
| $ | 43,333 |
|
| | | | | |
| Other comprehensive income (loss), net of tax: | | | | |
| Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $18 and $19 for the three months ended June 30, 2017 and 2016 and $35 and $38 for the six months ended June 30, 2017 and 2016, respectively) | (31 | ) | (36 | ) | (62 | ) | (72 | ) |
| Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(146) and $(173) for the three months ended June 30, 2017 and 2016 and $(300) and $(346) for the six months ended June 30, 2017 and 2016, respectively) | 268 |
| 321 |
| 528 |
| 643 |
|
| Derivative instruments designated as cash flow hedges: | | | | |
| Net unrealized gains (losses) on interest rate swaps (net of tax of $0 and $4,440 for the three months ended June 30, 2017 and 2016 and $0 and $10,767 for the six months ended June 30, 2017 and 2016, respectively) | — |
| (8,174 | ) | — |
| (19,898 | ) |
| Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(249) and $(294) for the three months ended June 30, 2017 and 2016 and $(530) and $(592) for the six months ended June 30, 2017 and 2016, respectively) | 464 |
| 546 |
| 985 |
| 1,098 |
|
| Net unrealized gains (losses) on commodity derivatives (net of tax of $(194) and $906 for the three months ended June 30, 2017 and 2016 and $(536) and $98 for the six months ended June 30, 2017 and 2016, respectively) | 331 |
| (1,546 | ) | 915 |
| (168 | ) |
| Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $143 and $1,176 for the three months ended June 30, 2017 and 2016 and $249 and $2,476 for the six months ended June 30, 2017 and 2016, respectively) | (243 | ) | (2,050 | ) | (424 | ) | (4,312 | ) |
| Other comprehensive income (loss), net of tax | 789 |
| (10,939 | ) | 1,942 |
| (22,709 | ) |
| | | | | |
| Comprehensive income (loss) | 26,100 |
| (7,656 | ) | 107,399 |
| 20,624 |
|
| Less: comprehensive income attributable to noncontrolling interest | (3,116 | ) | (2,614 | ) | (6,739 | ) | (2,662 | ) |
| Comprehensive income (loss) available for common stock | $ | 22,984 |
| $ | (10,270 | ) | $ | 100,660 |
| $ | 17,962 |
|
|
| | | | | | | | | | | | |
| (unaudited) | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | 2018 | 2017 | 2018 | 2017 |
| | (in thousands) |
| | | | | |
| Net income | $ | 24,740 |
| $ | 25,311 |
| $ | 161,374 |
| $ | 105,457 |
|
| | | | | |
| Other comprehensive income (loss), net of tax: | | | | |
| Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $9 and $18 for the three months ended June 30, 2018 and 2017 and $19 and $35 for the six months ended June 30, 2018 and 2017, respectively) | (35 | ) | (31 | ) | (70 | ) | (62 | ) |
| Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(135) and $(146) for the three months ended June 30, 2018 and 2017 and $(271) and $(300) for the six months ended June 30, 2018 and 2017, respectively) | 487 |
| 268 |
| 973 |
| 528 |
|
| 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 June 30, 2018 and 2017 and $(304) and $(530) for the six months ended June 30, 2018 and 2017, respectively) | 561 |
| 464 |
| 1,122 |
| 985 |
|
| Net unrealized gains (losses) on commodity derivatives (net of tax (expense) benefit of $(18) and $(194) for the three months ended June 30, 2018 and 2017 and $51 and $(536) for the six months ended June 30, 2018 and 2017, respectively) | 30 |
| 331 |
| (198 | ) | 915 |
|
| Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax (expense) benefit of $(45) and $143 for the three months ended June 30, 2018 and 2017 and $(190) and $249 for the six months ended June 30, 2018 and 2017, respectively) | 118 |
| (243 | ) | 594 |
| (424 | ) |
| Other comprehensive income, net of tax | 1,161 |
| 789 |
| 2,421 |
| 1,942 |
|
| | | | | |
| Comprehensive income | 25,901 |
| 26,100 |
| 163,795 |
| 107,399 |
|
| Less: comprehensive income attributable to noncontrolling interest | (2,823 | ) | (3,116 | ) | (6,453 | ) | (6,739 | ) |
| Comprehensive income available for common stock | $ | 23,078 |
| $ | 22,984 |
| $ | 157,342 |
| $ | 100,660 |
|
See Note 1314 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
| | | (unaudited) | As of | As of |
| | June 30,
2017 | | December 31, 2016 | | June 30,
2016 | June 30,
2018 | | December 31, 2017 | | June 30,
2017 |
| | (in thousands) | (in thousands) |
| ASSETS | | | | | | | | | | |
| Current assets: | | | | | | | | | | |
| Cash and cash equivalents | $ | 11,590 |
| | $ | 13,580 |
| | $ | 61,859 |
| $ | 8,630 |
| | $ | 15,420 |
| | $ | 11,528 |
|
| Restricted cash and equivalents | 2,534 |
| | 2,274 |
| | 1,975 |
| |
| Restricted cash | | 3,084 |
| | 2,820 |
| | 2,534 |
|
| Accounts receivable, net | 169,957 |
| | 263,289 |
| | 150,227 |
| 175,612 |
| | 248,330 |
| | 166,760 |
|
| Materials, supplies and fuel | 99,126 |
| | 107,210 |
| | 85,189 |
| 95,454 |
| | 113,283 |
| | 95,488 |
|
| Derivative assets, current | 1,148 |
| | 4,138 |
| | 4,030 |
| 666 |
| | 304 |
| | 639 |
|
| Income tax receivable, net | | 11,653 |
| | — |
| | — |
|
| Regulatory assets, current | 53,061 |
| | 49,260 |
| | 54,856 |
| 50,565 |
| | 81,016 |
| | 53,061 |
|
| Other current assets | 21,840 |
| | 27,063 |
| | 30,652 |
| 31,431 |
| | 25,367 |
| | 20,768 |
|
| Current assets held for sale | | 3,557 |
| | 84,242 |
| | 8,478 |
|
| Total current assets | 359,256 |
| | 466,814 |
| | 388,788 |
| 380,652 |
| | 570,782 |
| | 359,256 |
|
| | | | | | | | | | | |
| Investments | 12,761 |
| | 12,561 |
| | 12,363 |
| 41,148 |
| | 13,090 |
| | 12,761 |
|
| | | | | | | | | | | |
| Property, plant and equipment | 6,533,581 |
| | 6,412,223 |
| | 6,209,816 |
| 5,702,065 |
| | 5,567,518 |
| | 5,423,160 |
|
| Less: accumulated depreciation and depletion | (1,981,880 | ) | | (1,943,234 | ) | | (1,819,886 | ) | (1,087,689 | ) | | (1,026,088 | ) | | (964,549 | ) |
| Total property, plant and equipment, net | 4,551,701 |
| | 4,468,989 |
| | 4,389,930 |
| 4,614,376 |
| | 4,541,430 |
| | 4,458,611 |
|
| | | | | | | | | | | |
| Other assets: | | | | | | | | | | |
| Goodwill | 1,299,454 |
| | 1,299,454 |
| | 1,303,453 |
| 1,299,454 |
| | 1,299,454 |
| | 1,299,454 |
|
| Intangible assets, net | 7,972 |
| | 8,392 |
| | 9,164 |
| 7,155 |
| | 7,559 |
| | 7,972 |
|
| Regulatory assets, non-current | 244,099 |
| | 246,882 |
| | 220,556 |
| 210,137 |
| | 216,438 |
| | 244,099 |
|
| Derivative assets, non-current | 37 |
| | 222 |
| | 226 |
| |
| Other assets, non-current | 13,812 |
| | 12,130 |
| | 15,438 |
| 17,207 |
| | 10,149 |
| | 13,594 |
|
| Noncurrent assets held for sale | | — |
| | — |
| | 113,999 |
|
| Total other assets, non-current | 1,565,374 |
| | 1,567,080 |
| | 1,548,837 |
| 1,533,953 |
| | 1,533,600 |
| | 1,679,118 |
|
| | | | | | | | | | | |
| TOTAL ASSETS | $ | 6,489,092 |
| | $ | 6,515,444 |
| | $ | 6,339,918 |
| $ | 6,570,129 |
| | $ | 6,658,902 |
| | $ | 6,509,746 |
|
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 | As of |
| | June 30,
2017 | | December 31, 2016 | | June 30,
2016 | June 30,
2018 | | December 31, 2017 | | June 30,
2017 |
| | (in thousands, except share amounts) | (in thousands, except share amounts) |
| LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY | | | | | | |
| LIABILITIES AND TOTAL EQUITY | | | | | | |
| Current liabilities: | | | | | | | | | | |
| Accounts payable | $ | 99,970 |
| | $ | 153,477 |
| | $ | 115,203 |
| $ | 104,718 |
| | $ | 160,887 |
| | $ | 99,296 |
|
| Accrued liabilities | 201,993 |
| | 244,034 |
| | 218,250 |
| 190,339 |
| | 219,462 |
| | 191,806 |
|
| Derivative liabilities, current | 719 |
| | 2,459 |
| | 28,855 |
| 485 |
| | 2,081 |
| | 676 |
|
| Accrued income taxes, net | 5,160 |
| | 12,552 |
| | 10,624 |
| — |
| | 1,022 |
| | 5,160 |
|
| Regulatory liabilities, current | 17,305 |
| | 13,067 |
| | 34,275 |
| 52,102 |
| | 6,832 |
| | 17,305 |
|
| Notes payable | 107,975 |
| | 96,600 |
| | 75,000 |
| 121,800 |
| | 211,300 |
| | 107,975 |
|
| Current maturities of long-term debt | 5,743 |
| | 5,743 |
| | 930,743 |
| 255,743 |
| | 5,743 |
| | 5,743 |
|
| Current liabilities held for sale | | 5,448 |
| | 41,774 |
| | 10,904 |
|
| Total current liabilities | 438,865 |
| | 527,932 |
| | 1,412,950 |
| 730,635 |
| | 649,101 |
| | 438,865 |
|
| | | | | | | | | | | |
| Long-term debt | 3,160,302 |
| | 3,211,189 |
| | 2,221,347 |
| 2,858,068 |
| | 3,109,400 |
| | 3,160,302 |
|
| | | | | | | | | | | |
| Deferred credits and other liabilities: | | | | | | | | | | |
| Deferred income tax liabilities, net, non-current | 589,189 |
| | 535,606 |
| | 530,746 |
| |
| Derivative liabilities, non-current | 88 |
| | 274 |
| | 231 |
| |
| Deferred income tax liabilities, net | | 289,814 |
| | 336,520 |
| | 609,843 |
|
| Regulatory liabilities, non-current | 199,005 |
| | 193,689 |
| | 195,166 |
| 497,929 |
| | 478,294 |
| | 199,005 |
|
| Benefit plan liabilities | 176,102 |
| | 173,682 |
| | 173,347 |
| 162,199 |
| | 159,646 |
| | 176,102 |
|
| Other deferred credits and other liabilities | 135,510 |
| | 138,643 |
| | 122,015 |
| 104,951 |
| | 105,735 |
| | 112,550 |
|
| Non-current liabilities held for sale | | — |
| | — |
| | 23,048 |
|
| Total deferred credits and other liabilities | 1,099,894 |
| | 1,041,894 |
| | 1,021,505 |
| 1,054,893 |
| | 1,080,195 |
| | 1,120,548 |
|
| | | | | | | | | | | |
| Commitments and contingencies (See Notes 8, 10, 15, 16) |
|
| |
| |
| |
| | | | | | | |
| Redeemable noncontrolling interest | — |
| | 4,295 |
| | 4,171 |
| |
| Commitments and contingencies (See Notes 9, 11, 16, 17) | |
|
| |
| |
|
| | | | | | | | | | | |
| Equity: | | | | | | | | | | |
| Stockholders’ equity — | | | | | | | | | | |
| Common stock $1 par value; 100,000,000 shares authorized; issued 53,513,521; 53,397,467; and 52,299,075 shares, respectively | 53,514 |
| | 53,397 |
| | 52,299 |
| |
| Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,850; 53,579,986; and 53,513,521 shares, respectively | | 53,662 |
| | 53,580 |
| | 53,514 |
|
| Additional paid-in capital | 1,145,493 |
| | 1,138,982 |
| | 1,072,927 |
| 1,154,947 |
| | 1,150,285 |
| | 1,145,493 |
|
| Retained earnings | 512,498 |
| | 457,934 |
| | 469,940 |
| 652,642 |
| | 548,617 |
| | 512,498 |
|
| Treasury stock, at cost – 39,329; 15,258; and 18,900 shares, respectively | (2,325 | ) | | (791 | ) | | (975 | ) | |
| Treasury stock, at cost – 64,981; 39,064; and 39,329 shares, respectively | | (3,642 | ) | | (2,306 | ) | | (2,325 | ) |
| Accumulated other comprehensive income (loss) | (32,941 | ) | | (34,883 | ) | | (31,764 | ) | (38,763 | ) | | (41,202 | ) | | (32,941 | ) |
| Total stockholders’ equity | 1,676,239 |
| | 1,614,639 |
| | 1,562,427 |
| 1,818,846 |
| | 1,708,974 |
| | 1,676,239 |
|
| Noncontrolling interest | 113,792 |
| | 115,495 |
| | 117,518 |
| 107,687 |
| | 111,232 |
| | 113,792 |
|
| Total equity | 1,790,031 |
| | 1,730,134 |
| | 1,679,945 |
| 1,926,533 |
| | 1,820,206 |
| | 1,790,031 |
|
| | | | | | | | | | | |
| TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY | $ | 6,489,092 |
| | $ | 6,515,444 |
| | $ | 6,339,918 |
| |
| TOTAL LIABILITIES AND TOTAL EQUITY | | $ | 6,570,129 |
| | $ | 6,658,902 |
| | $ | 6,509,746 |
|
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) | Six Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | 2018 | 2017 |
| Operating activities: | (in thousands) | (in thousands) |
| Net income (loss) | $ | 105,457 |
| $ | 40,671 |
| |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | |
| Net income | | $ | 161,374 |
| $ | 105,457 |
|
| Loss from discontinued operations, net of tax | | 4,770 |
| 2,185 |
|
| Income from continuing operations | | 166,144 |
| 107,642 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | |
| Depreciation, depletion and amortization | 97,310 |
| 91,712 |
| 97,299 |
| 93,527 |
|
| Deferred financing cost amortization | 4,138 |
| 2,857 |
| 3,694 |
| 4,138 |
|
| Impairment of long-lived assets | — |
| 39,993 |
| |
| Stock compensation | 6,589 |
| 7,054 |
| 5,221 |
| 6,589 |
|
| Deferred income taxes | 51,153 |
| 32,606 |
| (21,419 | ) | 52,385 |
|
| Employee benefit plans | 5,717 |
| 7,782 |
| 6,911 |
| 5,717 |
|
| Other adjustments, net | (6,515 | ) | (6,332 | ) | 4,884 |
| (6,445 | ) |
| Changes in certain operating assets and liabilities: | | |
| Materials, supplies and fuel | 7,720 |
| 17,722 |
| 18,492 |
| 7,753 |
|
| Accounts receivable, unbilled revenues and other operating assets | 97,902 |
| 82,361 |
| 50,711 |
| 94,591 |
|
| Accounts payable and other operating liabilities | (113,541 | ) | (124,695 | ) | (96,394 | ) | (117,134 | ) |
| Regulatory assets - current | 3,086 |
| 1,862 |
| 55,637 |
| 3,086 |
|
| Regulatory liabilities - current | 5,908 |
| 2,994 |
| 19,990 |
| 5,908 |
|
| Contributions to defined benefit pension plans | — |
| (10,200 | ) | |
| Other operating activities, net | (2,055 | ) | (2,884 | ) | (1,372 | ) | (125 | ) |
| Net cash provided by (used in) operating activities | 262,869 |
| 183,503 |
| |
| Net cash provided by operating activities of continuing operations | | 309,798 |
| 257,632 |
|
| Net cash provided by operating activities of discontinued operations | | 903 |
| 5,237 |
|
| Net cash provided by operating activities | | 310,701 |
| 262,869 |
|
| | | |
| Investing activities: | | |
| Property, plant and equipment additions | (163,768 | ) | (199,854 | ) | (156,748 | ) | (154,294 | ) |
| Acquisition, net of long term debt assumed | — |
| (1,124,238 | ) | |
| Purchase of investment | | (24,429 | ) | — |
|
| Other investing activities | (22 | ) | (649 | ) | (373 | ) | 238 |
|
| Net cash provided by (used in) investing activities of continuing operations | | (181,550 | ) | (154,056 | ) |
| Net cash provided by (used in) investing activities of discontinued operations | | 18,024 |
| (9,474 | ) |
| Net cash provided by (used in) investing activities | (163,790 | ) | (1,324,741 | ) | (163,526 | ) | (163,530 | ) |
| | | |
| Financing activities: | | |
| Dividends paid on common stock | (47,544 | ) | (43,265 | ) | (50,879 | ) | (47,544 | ) |
| Common stock issued | 2,965 |
| 57,490 |
| 1,074 |
| 2,965 |
|
| Sale of noncontrolling interest | — |
| 216,370 |
| |
| Net (payments) borrowings of short-term debt | 11,375 |
| (1,800 | ) | (89,500 | ) | 11,375 |
|
| Long-term debt - issuances | — |
| 574,672 |
| |
| Long-term debt - repayments | (52,871 | ) | (41,436 | ) | (2,871 | ) | (52,871 | ) |
| Distributions to noncontrolling interest | (8,335 | ) | — |
| (9,998 | ) | (8,335 | ) |
| Other financing activities | (6,659 | ) | 205 |
| (1,527 | ) | (6,659 | ) |
| Net cash provided by (used in) financing activities | (101,069 | ) | 762,236 |
| (153,701 | ) | (101,069 | ) |
| Net change in cash and cash equivalents | (1,990 | ) | (379,002 | ) | |
| Cash and cash equivalents, beginning of period | 13,580 |
| 440,861 |
| |
| Cash and cash equivalents, end of period | $ | 11,590 |
| $ | 61,859 |
| |
| Net change in cash, cash equivalents and restricted cash | | (6,526 | ) | (1,730 | ) |
| Cash, cash equivalents and restricted cash at beginning of period | | 18,240 |
| 15,792 |
|
| Cash, cash equivalents and restricted cash at end of period | | $ | 11,714 |
| $ | 14,062 |
|
See Note 1415 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
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 20162017 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,” 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 20162017 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 Mining and Oil and Gas.Mining. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. See Note 18 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 June 30, 20172018, December 31, 2016,2017, and June 30, 20162017 financial information and are of a normal recurring nature. 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. 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 six months ended June 30, 20172018 and June 30, 20162017, and our financial condition as of June 30, 20172018, December 31, 2016,2017, and June 30, 20162017, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. June 30, 2017 reflects a full six months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the six months ended June 30, 2016 which reflects a partial period of approximately 4.5 months. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.
RevisionsCash and Cash Equivalents and Restricted Cash
Certain revisions have been made to prior years’ financial information to conform toFor purposes of the current year presentation.
The Company revised its presentationcash flow statements, we consider all highly liquid investments with original maturities of cash as of December 31, 2016. The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accountsthree months or less at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $55 million astime of June 30, 2016, and decreased net cash flows provided by operations by $39 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined thempurchase to be immaterialcash 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 condensed consolidated balance sheet asoperating and financial policies of June 30, 2016the investee. The cost method investments are recorded at cost and to the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Condensed Consolidated Statements of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported.we record dividend income when applicable dividends are declared.
Recently Issued and Adopted Accounting Standards
Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07
In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.
Improvements to Employee Share-Based Payment Accounting, ASU 2016-09
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.
Leases, ASU 2016-02
In February 2016, the FASB issued ASU No. 2016-02,Leases Leases (Topic 842), which supersedes ASC 840, Leases.Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for allmost leases, with a term greater than 12 months, whereas today only financing typefinancing-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. LesseesUnder 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 currently 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 and the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easementsflows. We are finalizing the process of identifying and right of ways, pipeline laterals, purchase power agreements, pole attachmentscategorizing our lease contracts and other industry-related areas.evaluating our current business processes relating to leases. We have selected and configured a new lease software solution that we are currently testing. We also expectcontinue to implement changesmonitor utility industry lease implementation guidance that may change existing and future lease classification.
Derivatives and Hedging: Targeted Improvements to systems, processesAccounting for Hedging Activities, ASU 2017-12
In August 2017, the FASB issued ASU 2017-12, Derivatives and proceduresHedging (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 orderan amount equal to recognizethat excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and measure leases recordedannual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the balance sheet that are currently classified as operating leases.adoption of this standard to have any impact on our financial position, results of operations or cash flows.
Recently Adopted Accounting Standards
Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issuedEffective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). TheUnder this standard, provides companies withrevenue is recognized when a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue whencustomer obtains control of thepromised goods or services transfersin an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the customer. The newstandard requires disclosure requirements will provide information aboutof the nature, amount, timing and uncertainty of revenue and cash flows arising from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will haveWe applied the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earningsfive-step method outlined in the period of adoption.ASU to all in-scope revenue
We currently expect to implement
streams and elected the modified retrospective implementation method. Implementation of the standard ondid not have a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine thematerial impact that adoption of the new standard will have on our financial position, results of operations andor cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for easeImplementation of implementation. A majoritythe standard did not have a significant impact on the measurement or recognition of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalentrevenue; therefore, no cumulative adoption adjustment to the electricity or gas deliveredopening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in that period. Therefore,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 do not expect there will be a significant shiftadopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the timingsame line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. 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 six months ended June 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 patternregulatory 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 revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, includingthe standard did not have a material impact on our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.
(2) ACQUISITION
2016 Acquisition of SourceGas
On February 12, 2016, Black Hills Corporation acquired SourceGas (now referred to as Black Hills Gas Holdings). We acquired SourceGas for $1.1 billion of cash plus the assumption of $760 million of long-term debt. We finalized our purchase price allocation at December 31, 2016. See Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details.
Pro Forma Results
The following unaudited pro forma financial information reflects the consolidatedposition, results of operations as if the SourceGas Acquisition had taken place onor cash flows.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
Effective January 1, 2015. The unaudited pro forma financial information is presented for illustrative purposes only2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and is not necessarily indicativeCash Payments (a consensus of the consolidatedEmerging 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 are recognized in an amount that wouldreflects 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 been achievedregulated 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 future consolidated results.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 pro forma financial information does not reflect any potential cost savingsfollowing tables depict the disaggregation of revenue, including intercompany revenue, from operating efficiencies resulting fromcontracts with customers by customer type and timing of revenue recognition for each of the acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma resultsreporting segments, for the three and six months ended June 30, 2016 exclude approximately $4.0 million and $20 million, respectively, of after-tax transaction costs, professional fees, employee related expenses2018. Sales tax and other miscellaneous costs.similar taxes are excluded from revenues.
|
| | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 145,377 |
| $ | 135,863 |
| $ | — |
| $ | 16,345 |
| $ | (7,979 | ) | $ | 289,606 |
|
| Transportation | — |
| 29,011 |
| — |
| — |
| (301 | ) | 28,710 |
|
| Wholesale | 8,191 |
| — |
| 12,743 |
| — |
| (11,613 | ) | 9,321 |
|
| Market - off-system sales | 4,938 |
| 162 |
| — |
| — |
| (1,660 | ) | 3,440 |
|
| Transmission/Other | 13,356 |
| 11,672 |
| — |
| — |
| (3,644 | ) | 21,384 |
|
| Revenue from contracts with customers | 171,862 |
| 176,708 |
| 12,743 |
| 16,345 |
| (25,197 | ) | 352,461 |
|
| Other revenues | 1,754 |
| 912 |
| 9,141 |
| 554 |
| (9,118 | ) | 3,243 |
|
| Total revenues | $ | 173,616 |
| $ | 177,620 |
| $ | 21,884 |
| $ | 16,899 |
| $ | (34,315 | ) | $ | 355,704 |
|
| | | | | | | |
| Timing of revenue recognition: | | | | | | |
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 16,345 |
| $ | (7,978 | ) | $ | 8,367 |
|
| Services transferred over time | 171,862 |
| 176,708 |
| 12,743 |
| — |
| (17,219 | ) | 344,094 |
|
| Revenue from contracts with customers | $ | 171,862 |
| $ | 176,708 |
| $ | 12,743 |
| $ | 16,345 |
| $ | (25,197 | ) | $ | 352,461 |
|
|
| | | | | | |
| | Three Months Ended June 30, 2016 | Six Months Ended June 30, 2016 |
| | (in thousands, except per share amounts) |
| Revenue | $ | 325,441 |
| $ | 854,362 |
|
| Net income (loss) available for common stock | $ | 4,658 |
| $ | 72,978 |
|
| Earnings (loss) per share, Basic | $ | 0.09 |
| $ | 1.42 |
|
| Earnings (loss) per share, Diluted | $ | 0.09 |
| $ | 1.39 |
|
|
| | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 292,434 |
| $ | 477,257 |
| $ | — |
| $ | 32,902 |
| $ | (15,821 | ) | $ | 786,772 |
|
| Transportation | — |
| 70,681 |
| — |
| — |
| (710 | ) | 69,971 |
|
| Wholesale | 17,241 |
| — |
| 26,676 |
| — |
| (23,826 | ) | 20,091 |
|
| Market - off-system sales | 9,082 |
| 589 |
| — |
| — |
| (4,182 | ) | 5,489 |
|
| Transmission/Other | 26,427 |
| 24,341 |
| — |
| — |
| (7,275 | ) | 43,493 |
|
| Revenue from contracts with customers | 345,184 |
| 572,868 |
| 26,676 |
| 32,902 |
| (51,814 | ) | 925,816 |
|
| Other revenues | 1,987 |
| 2,096 |
| 18,311 |
| 1,125 |
| (18,242 | ) | 5,277 |
|
| Total revenues | $ | 347,171 |
| $ | 574,964 |
| $ | 44,987 |
| $ | 34,027 |
| $ | (70,056 | ) | $ | 931,093 |
|
| | | | | | | |
| Timing of revenue recognition: | | | | | | |
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 32,902 |
| $ | (15,820 | ) | $ | 17,082 |
|
| Services transferred over time | 345,184 |
| 572,868 |
| 26,676 |
| — |
| (35,994 | ) | 908,734 |
|
| Revenue from contracts with customers | $ | 345,184 |
| $ | 572,868 |
| $ | 26,676 |
| $ | 32,902 |
| $ | (51,814 | ) | $ | 925,816 |
|
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.
Redemption of seller’s noncontrolling interest
As partRevenue 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 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 SourceGas Transaction,TCJA. We estimated and recorded a seller retainedreserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018, respectively. As of June 30, 2018, $3.3 million has been returned to customers and approximately $19 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 0.5% noncontrolling interestcontract.
Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.
We have revenue contract performance obligations with similar characteristics, and we entered into an associated option agreement withreasonably expect that the holderfinancial statement impact of applying the 0.5% retained interest. The termsnew revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the agreement provided us a call option to purchaseindividual contracts or performance obligations within the remaining interest beginning 366 days afterportfolio. Therefore, we have elected the initial close ofportfolio approach in applying the SourceGas Transaction. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million.new revenue guidance.
(3) BUSINESS SEGMENT INFORMATION
Segment information and Corporate activitiesand Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands):
| | | Three Months Ended June 30, 2017 | | External Operating Revenue | | Inter-company Operating Revenue | | Net Income (Loss) Available for Common Stock | |
| Three Months Ended June 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 | | $ | 165,517 |
| | $ | 2,936 |
| | $ | 18,832 |
| $ | 166,565 |
| $ | 1,754 |
|
| $ | 5,297 |
| $ | — |
|
| $ | 173,616 |
|
| $ | 21,890 |
|
| Gas | | 166,439 |
| | 8 |
| | (272 | ) | 176,399 |
| 912 |
|
| 309 |
| — |
|
| 177,620 |
|
| (1,161 | ) |
Power Generation (b) | | 1,470 |
| | 20,325 |
| | 5,332 |
| 1,130 |
| 348 |
|
| 11,613 |
| 8,793 |
|
| 21,884 |
|
| 4,772 |
|
| Mining | | 8,403 |
| | 6,543 |
| | 2,681 |
| 8,367 |
| 229 |
|
| 7,978 |
| 325 |
|
| 16,899 |
|
| 3,005 |
|
| Oil and Gas | | 6,149 |
| | — |
| | (1,946 | ) | |
Corporate activities (c) | | — |
| | — |
| | (2,432 | ) | |
| Corporate and Other | | — |
| — |
|
| — |
| — |
|
| — |
|
| (4,162 | ) |
| Inter-company eliminations | | — |
| | (29,812 | ) | | — |
| — |
| — |
| | (25,197 | ) | (9,118 | ) | | (34,315 | ) | | — |
|
| Total | | $ | 347,978 |
| | $ | — |
| | $ | 22,195 |
| $ | 352,461 |
| $ | 3,243 |
| | $ | — |
| $ | — |
| | $ | 355,704 |
| | $ | 24,344 |
|
Under our modified retrospective adoption of ASU 2014-09, revenues for the three and six months ended June 30, 2017 are not presented by contract type.
|
| | | | | | | | | | | | |
| | Three Months Ended June 30, 2017 | External Operating Revenue | | Inter-company Operating Revenue | | Net income (loss) from continuing operations |
| |
| | Segment: | | | | | |
| | Electric. | $ | 165,517 |
| | $ | 2,936 |
| | $ | 18,832 |
|
| | Gas | 166,439 |
| | 8 |
| | (272 | ) |
| | Power Generation (b) | 1,470 |
| | 20,325 |
| | 5,332 |
|
| | Mining | 8,403 |
| | 6,543 |
| | 2,681 |
|
| | Corporate and Other | — |
| | — |
| | (3,762 | ) |
| | Inter-company eliminations | — |
| | (29,812 | ) | | — |
|
| | Total | $ | 341,829 |
| | $ | — |
| | $ | 22,811 |
|
| | | Three Months Ended June 30, 2016 | | External Operating Revenue | | Inter-company Operating Revenue | | Net Income (Loss) Available for Common Stock | |
| | | | | | | | | |
| Six Months Ended June 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. | | $ | 158,560 |
| | $ | 2,921 |
| | $ | 19,229 |
| |
| Gas | | 153,767 |
| | (1,806 | ) | | 987 |
| |
| Electric | | $ | 333,743 |
| $ | 1,987 |
| | $ | 11,441 |
| $ | — |
| | $ | 347,171 |
| | $ | 41,735 |
|
Gas (a) | | 572,141 |
| 2,096 |
| | 727 |
| — |
| | 574,964 |
| | 106,459 |
|
Power Generation (b) | | 1,546 |
| | 20,168 |
| | 5,683 |
| 2,850 |
| 718 |
| | 23,826 |
| 17,593 |
| | 44,987 |
| | 10,628 |
|
| Mining | | 3,922 |
| | 7,125 |
| | 724 |
| 17,082 |
| 476 |
| | 15,820 |
| 649 |
| | 34,027 |
| | 5,989 |
|
Oil and Gas (e) | | 7,646 |
| | — |
| | (19,424 | ) | |
Corporate activities (c) | | — |
| | — |
| | (6,530 | ) | |
| Corporate and Other | | — |
| — |
| | — |
| — |
| | — |
| | (5,120 | ) |
| Inter-company eliminations | | — |
| | (28,408 | ) | | — |
| — |
| — |
| | (51,814 | ) | (18,242 | ) | | (70,056 | ) | | — |
|
| Total | | $ | 325,441 |
| | $ | — |
| | $ | 669 |
| $ | 925,816 |
| $ | 5,277 |
| | $ | — |
| $ | — |
| | $ | 931,093 |
| | $ | 159,691 |
|
|
| | | | | | | | | | | | |
| | | | | | | |
| Six Months Ended June 30, 2017 | | External Operating Revenue | | Inter-company Operating Revenue | | Net Income (Loss) Available for Common Stock |
| Segment: | | | | | | |
| Electric | | $ | 337,687 |
| | $ | 6,790 |
| | $ | 41,062 |
|
Gas (a) | | 531,340 |
| | 17 |
| | 45,738 |
|
Power Generation (b) | | 3,572 |
| | 41,790 |
| | 11,862 |
|
| Mining | | 16,758 |
| | 14,734 |
| | 5,571 |
|
| Oil and Gas | | 12,624 |
| | — |
| | (4,897 | ) |
Corporate activities (c)(d) | | — |
| | — |
| | (618 | ) |
| Inter-company eliminations | | — |
| | (63,331 | ) | | — |
|
| Total | | $ | 901,981 |
| | $ | — |
| | $ | 98,718 |
|
|
| | | | | | | | | | | | |
| | | | | | | |
| Six Months Ended June 30, 2016 | | External Operating Revenue | | Inter-company Operating Revenue | | Net Income (Loss) Available for Common Stock |
| Segment: | | | | | | |
| Electric | | $ | 322,091 |
| | $ | 6,666 |
| | $ | 38,444 |
|
Gas (a) | | 422,434 |
| | — |
| | 32,914 |
|
Power Generation (b) | | 3,398 |
| | 41,624 |
| | 14,265 |
|
| Mining | | 11,456 |
| | 15,873 |
| | 3,662 |
|
Oil and Gas (e) | | 16,021 |
| | — |
| | (26,448 | ) |
Corporate activities (c)(d) | | — |
| | — |
| | (22,166 | ) |
| Inter-company eliminations | | — |
| | (64,163 | ) | | — |
|
| Total | | $ | 775,400 |
| | $ | — |
| | $ | 40,671 |
|
|
| | | | | | | | | | | | |
| | | | | | | |
| | Six Months Ended June 30, 2017 | External Operating Revenue | | Inter-company Operating Revenue | | Net income (loss) from continuing operations |
| |
| | Segment: | | | | | |
| | Electric | $ | 337,687 |
| | $ | 6,790 |
| | $ | 41,062 |
|
| | Gas | 531,340 |
| | 17 |
| | 45,738 |
|
| | Power Generation (b) | 3,572 |
| | 41,790 |
| | 11,862 |
|
| | Mining | 16,758 |
| | 14,734 |
| | 5,571 |
|
| | Corporate and Other (c) | — |
| | — |
| | (3,330 | ) |
| | Inter-company eliminations | — |
| | (63,331 | ) | | — |
|
| | Total | $ | 889,357 |
| | $ | — |
| | $ | 100,903 |
|
___________
| |
| (a) | Gas Utility revenue increasedNet income from continuing operations available for common stock for the six months ended June 30, 2017 compared to the same periods in the prior year primarily due to the addition2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note 19 Income Taxes of the SourceGas utilities on February 12, 2016.Notes to Condensed Consolidated Financial Statements for more information. |
| |
| (b) | Net income (loss)from continuing operations available for common stock for the three and six months ended June 30, 2018 and June 30, 2017 was net ofreflects net income attributable to noncontrolling interests of $2.8 million and $6.5 million, and $3.1 million and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016.respectively. |
| |
| (c) | Net income (loss) available for common stock for the three and six months ended June 30, 2017 andJune 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.3 million and $1.2 million, and $4.1 million and $20 million respectively. The three and six months ended June 30, 2016 also included $2.0 million and $5.7 million, respectively, of after-tax internal labor costs attributable to the acquisition. |
| |
(d) | Net income (loss)from continuing operations available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Net income (loss) available for common stock for the six months ended June 30, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18. |
| |
(e) | Net income (loss) available for common stock for the three and six months ended June 30, 2016 included non-cash after-tax impairments of oil and gas properties of $16 million and $25 million. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
| | | Total Assets (net of inter-company eliminations) as of: | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| Segment: | | | | | | | | | | |
Electric (a) | $ | 2,901,570 |
| | $ | 2,859,559 |
| | $ | 2,755,695 |
| $ | 2,902,925 |
| | $ | 2,906,275 |
| | $ | 2,901,570 |
|
| Gas | 3,242,461 |
| | 3,307,967 |
| | 3,118,626 |
| 3,367,247 |
| | 3,426,466 |
| | 3,242,461 |
|
Power Generation (a) | 66,292 |
| | 73,445 |
| | 80,360 |
| 49,628 |
| | 60,852 |
| | 66,292 |
|
| Mining | 67,365 |
| | 67,347 |
| | 71,319 |
| 68,154 |
| | 65,455 |
| | 67,365 |
|
Oil and Gas (b) | 103,044 |
| | 96,435 |
| | 171,239 |
| |
| Corporate activities | 108,360 |
| | 110,691 |
| | 142,679 |
| |
| Corporate and Other | | 178,618 |
| | 115,612 |
| | 109,581 |
|
| Discontinued operations | | 3,557 |
| | 84,242 |
| | 122,477 |
|
| Total assets | $ | 6,489,092 |
| | $ | 6,515,444 |
| | $ | 6,339,918 |
| $ | 6,570,129 |
| | $ | 6,658,902 |
| | $ | 6,509,746 |
|
__________
| |
| (a) | The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. |
| |
(b) | As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $107 million for the year ended December 31, 2016 and $40 million for the six months ended June 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
(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 |
| June 30, 2017 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | |
| June 30, 2018 | | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
| Electric Utilities | $ | 41,635 |
| $ | 33,686 |
| $ | (466 | ) | $ | 74,855 |
| $ | 44,577 |
| $ | 34,940 |
| $ | (503 | ) | $ | 79,014 |
|
| Gas Utilities | 62,908 |
| 26,584 |
| (2,535 | ) | 86,957 |
| 70,244 |
| 23,557 |
| (3,517 | ) | 90,284 |
|
| Power Generation | 877 |
| — |
| — |
| 877 |
| 1,681 |
| — |
| — |
| 1,681 |
|
| Mining | 2,904 |
| — |
| — |
| 2,904 |
| 3,158 |
| — |
| — |
| 3,158 |
|
| Oil and Gas | 3,280 |
| — |
| (83 | ) | 3,197 |
| |
| Corporate | 1,167 |
| — |
| — |
| 1,167 |
| 1,475 |
| — |
| — |
| 1,475 |
|
| Total | $ | 112,771 |
| $ | 60,270 |
| $ | (3,084 | ) | $ | 169,957 |
| $ | 121,135 |
| $ | 58,497 |
| $ | (4,020 | ) | $ | 175,612 |
|
| | | | Accounts | Unbilled | Less Allowance for | Accounts | Accounts | Unbilled | Less Allowance for | Accounts |
| December 31, 2016 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | |
| December 31, 2017 | | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
| Electric Utilities | $ | 41,730 |
| $ | 36,463 |
| $ | (353 | ) | $ | 77,840 |
| $ | 39,347 |
| $ | 36,384 |
| $ | (586 | ) | $ | 75,145 |
|
| Gas Utilities | 88,168 |
| 88,329 |
| (2,026 | ) | 174,471 |
| 81,256 |
| 88,967 |
| (2,495 | ) | 167,728 |
|
| Power Generation | 1,420 |
| — |
| — |
| 1,420 |
| 1,196 |
| — |
| — |
| 1,196 |
|
| Mining | 3,352 |
| — |
| — |
| 3,352 |
| 2,804 |
| — |
| — |
| 2,804 |
|
| Oil and Gas | 3,991 |
| — |
| (13 | ) | 3,978 |
| |
| Corporate | 2,228 |
| — |
| — |
| 2,228 |
| 1,457 |
| — |
| — |
| 1,457 |
|
| Total | $ | 140,889 |
| $ | 124,792 |
| $ | (2,392 | ) | $ | 263,289 |
| $ | 126,060 |
| $ | 125,351 |
| $ | (3,081 | ) | $ | 248,330 |
|
| | | | Accounts | Unbilled | Less Allowance for | Accounts | Accounts | Unbilled | Less Allowance for | Accounts |
| June 30, 2016 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | |
| June 30, 2017 | | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net |
| Electric Utilities | $ | 40,991 |
| $ | 34,174 |
| $ | (716 | ) | $ | 74,449 |
| $ | 41,635 |
| $ | 33,686 |
| $ | (466 | ) | $ | 74,855 |
|
| Gas Utilities | 47,600 |
| 23,124 |
| (2,997 | ) | 67,727 |
| 62,908 |
| 26,584 |
| (2,535 | ) | 86,957 |
|
| Power Generation | 1,229 |
| — |
| — |
| 1,229 |
| 877 |
| — |
| — |
| 877 |
|
| Mining | 1,114 |
| — |
| — |
| 1,114 |
| 2,904 |
| — |
| — |
| 2,904 |
|
| Oil and Gas | 3,094 |
| — |
| (13 | ) | 3,081 |
| |
| Corporate | 2,627 |
| — |
| — |
| 2,627 |
| 1,167 |
| — |
| — |
| 1,167 |
|
| Total | $ | 96,655 |
| $ | 57,298 |
| $ | (3,726 | ) | $ | 150,227 |
| $ | 109,491 |
| $ | 60,270 |
| $ | (3,001 | ) | $ | 166,760 |
|
(5) REGULATORY ACCOUNTING
We had the following regulatory assets and liabilities (in thousands): as of: |
| | | | | | | | | | |
| | Maximum | As of | As of | As of |
| | Amortization | June 30, 2017 | December 31, 2016 | June 30, 2016 |
| | (in years) | | | |
| Regulatory assets | | | | |
Deferred energy and fuel cost adjustments - current (a)(d) | 1 | $ | 20,761 |
| $ | 17,491 |
| $ | 20,603 |
|
Deferred gas cost adjustments (a)(d) | 1 | 9,060 |
| 15,329 |
| 12,122 |
|
Gas price derivatives (a) | 3.5 | 11,159 |
| 8,843 |
| 11,515 |
|
Deferred taxes on AFUDC (b) | 45 | 15,322 |
| 15,227 |
| 13,879 |
|
Employee benefit plans (c) | 12 | 107,419 |
| 108,556 |
| 109,522 |
|
Environmental (a) | subject to approval | 1,070 |
| 1,108 |
| 1,144 |
|
Asset retirement obligations (a) | 44 | 510 |
| 505 |
| 505 |
|
Loss on reacquired debt (a) | 30 | 21,466 |
| 22,266 |
| 3,061 |
|
Renewable energy standard adjustment (b) | 5 | 768 |
| 1,605 |
| 2,679 |
|
Deferred taxes on flow through accounting (c) | 35 | 40,586 |
| 37,498 |
| 31,554 |
|
Decommissioning costs (e) | 6 | 14,681 |
| 16,859 |
| 18,399 |
|
| Gas supply contract termination | 5 | 22,793 |
| 26,666 |
| 28,385 |
|
Other regulatory assets (a) (e) | 15 | 31,565 |
| 24,189 |
| 22,044 |
|
| | | $ | 297,160 |
| $ | 296,142 |
| $ | 275,412 |
|
| | | | | |
| Regulatory liabilities | | | | |
Deferred energy and gas costs (a) (d) | 1 | $ | 16,767 |
| $ | 10,368 |
| $ | 32,868 |
|
Employee benefit plan costs and related deferred taxes (c) | 12 | 67,297 |
| 68,654 |
| 62,712 |
|
Cost of removal (a) | 44 | 125,247 |
| 118,410 |
| 126,002 |
|
| Revenue subject to refund | 1 | 1,518 |
| 2,485 |
| 1,616 |
|
Other regulatory liabilities (c) | 25 | 5,481 |
| 6,839 |
| 6,243 |
|
| | | $ | 216,310 |
| $ | 206,756 |
| $ | 229,441 |
|
|
| | | | | | | | | | |
| | Maximum Amortization (in years) | June 30, 2018 | December 31, 2017 | June 30, 2017 |
| Regulatory assets | | | | |
Deferred energy and fuel cost adjustments (a) | 1 | $ | 26,725 |
| $ | 20,187 |
| $ | 20,761 |
|
Deferred gas cost adjustments (a) | 1 | 962 |
| 31,844 |
| 8,962 |
|
Gas price derivatives (a) | 3 | 9,120 |
| 11,935 |
| 11,159 |
|
Deferred taxes on AFUDC (b) (f) | 45 | 7,813 |
| 7,847 |
| 15,322 |
|
Employee benefit plans (c) | 12 | 108,366 |
| 109,235 |
| 107,419 |
|
Environmental (a) | subject to approval | 1,000 |
| 1,031 |
| 1,070 |
|
Asset retirement obligations (a) | 44 | 523 |
| 517 |
| 510 |
|
Loss on reacquired debt (a) | 28 | 19,868 |
| 20,667 |
| 21,466 |
|
Renewable energy standard adjustment (a) | subject to approval | 1,179 |
| 1,088 |
| 768 |
|
Deferred taxes on flow through accounting (c) (f) | 54 | 28,193 |
| 26,978 |
| 40,586 |
|
| Decommissioning costs | 10 | 11,806 |
| 13,287 |
| 14,681 |
|
Gas supply contract termination (a) | 4 | 17,171 |
| 20,001 |
| 22,793 |
|
Other regulatory assets (a) | 30 | 27,976 |
| 32,837 |
| 31,663 |
|
| Total regulatory assets | | 260,702 |
| 297,454 |
| 297,160 |
|
| Less current regulatory assets | | (50,565 | ) | (81,016 | ) | (53,061 | ) |
| Regulatory assets, non-current | | $ | 210,137 |
| $ | 216,438 |
| $ | 244,099 |
|
| | | | | |
| Regulatory liabilities | | | | |
Deferred energy and gas costs (a) | 1 | $ | 27,188 |
| $ | 3,427 |
| $ | 13,693 |
|
Employee benefit plan costs and related deferred taxes (c) (f) | 12 | 39,820 |
| 40,629 |
| 67,297 |
|
Cost of removal (a) | 44 | 141,954 |
| 130,932 |
| 125,598 |
|
Excess deferred income taxes (c) (d) | 40 | 310,132 |
| 301,553 |
| 56 |
|
TCJA revenue reserve (e) | subject to approval | 19,312 |
| — |
| — |
|
Other regulatory liabilities (c) | 25 | 11,625 |
| 8,585 |
| 9,666 |
|
| Total regulatory liabilities | | 550,031 |
| 485,126 |
| 216,310 |
|
| Less current regulatory liabilities | | (52,102 | ) | (6,832 | ) | (17,305 | ) |
| Regulatory liabilities, non-current | | $ | 497,929 |
| $ | 478,294 |
| $ | 199,005 |
|
__________
| |
| (a) | We are allowed recoveryRecovery 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) | OurThe increase in the regulatory tax liability is primarily related to the revaluation of deferred energy, fuel cost,income tax balances at the lower income tax rate. As of June 30, 2018 and gas cost adjustments representDecember 31, 2017, all of the costliability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of electricityregulatory tax liability amortized and gas deliveredreturned to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refundedthrough rate reductions of other revenue offsets in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.2018. |
| |
| (e) | In accordance with a settlement agreement approved by the SDPUC onAs of June 16, 2017,30, 2018, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million,periods are yet to be determined and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. subject to approval by our regulators. |
| |
| (f) | The vegetation management costs were previously unamortized. The change in amortizationvariance to the prior periods for these costs will increase annual amortization expense by approximately $2.7 million.is primarily due to 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 2017 Annual Report on Form 10-K.
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 of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. 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 now received state utility commission approvals to provide the benefits of federal tax reform to utility customers in four states. Discussions are underway with utility commissions in the remaining states and final approval is expected prior to year-end. We estimated and recorded a reserve to revenue of approximately $8.0 million and $23 million during the three and six months ended June 30, 2018, respectively. As of June 30, 2018, $3.3 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 Annual Benefit for Customers | Start Date for Customer Benefits |
| Colorado | $ | 10.8 | million | July 2018 |
| Iowa | $ | 2.2 | million | June 2018 |
| Kansas | $ | 1.9 | million | April 2018 |
| Nebraska | $ | 3.8 | million | July 2018 |
In support of returning benefits to customers, the three rate review requests filed in late 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.
Rate Reviews - 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 December 31, 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.
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We expect 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, will be effective September 1, 2018.
An Arkansas rate review was filed in December 2017 with the APSC requesting $30 million of annual revenue to recover more than $160 million of new infrastructure investment. The revenue request was subsequently adjusted to $19 million primarily related to a lower corporate income tax rate of 21%. The APSC previously issued a procedural schedule for the rate review. To date, testimony has been filed by the intervenors and Arkansas Gas filed rebuttal testimony on June 26, 2018. The APSC issued an order on July 26 requiring investor owned utilities to provide within 30 days their plans to return tax reform benefits to customers. Arkansas Gas is reviewing the order and its impacts to customers and may amend its current rate review if necessary. A final order and new rates are expected to be effective in the fourth quarter of 2018.
(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:
| | | | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| Materials and supplies | $ | 72,397 |
| | $ | 68,456 |
| | $ | 67,440 |
| $ | 73,075 |
| | $ | 69,732 |
| | $ | 68,759 |
|
| Fuel - Electric Utilities | 3,106 |
| | 3,667 |
| | 4,659 |
| 2,821 |
| | 2,962 |
| | 3,106 |
|
| Natural gas in storage held for distribution | 23,623 |
| | 35,087 |
| | 13,090 |
| 19,558 |
| | 40,589 |
| | 23,623 |
|
| Total materials, supplies and fuel | $ | 99,126 |
| | $ | 107,210 |
| | $ | 85,189 |
| $ | 95,454 |
| | $ | 113,283 |
| | $ | 95,488 |
|
(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 June 30, 2018.
The following table presents the carrying value of our investments (in thousands) as of:
|
| | | | | | | | | | | |
| | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| Cost method investment | $ | 28,134 |
| | $ | — |
| | $ | — |
|
| Cash surrender value of life insurance contracts | 13,014 |
| | 13,090 |
| | 12,761 |
|
| Total investments | $ | 41,148 |
| | $ | 13,090 |
| | $ | 12,761 |
|
(78) 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 June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| | | | | | | |
| Net income (loss) available for common stock | $ | 22,195 |
| $ | 669 |
| | $ | 98,718 |
| $ | 40,671 |
| |
| Net income available for common stock | | $ | 21,917 |
| $ | 22,195 |
| | $ | 154,921 |
| $ | 98,718 |
|
| | | | | | | |
| Weighted average shares - basic | 53,229 |
| 51,514 |
| | 53,191 |
| 51,279 |
| 53,355 |
| 53,229 |
| | 53,337 |
| 53,191 |
|
| Dilutive effect of: | | | | | | |
Equity Units (a) | 1,977 |
| 1,362 |
| | 1,796 |
| 1,068 |
| 1,057 |
| 1,977 |
| | 904 |
| 1,796 |
|
| Equity compensation | 178 |
| 110 |
| | 192 |
| 107 |
| 108 |
| 178 |
| | 120 |
| 192 |
|
| Weighted average shares - diluted | 55,384 |
| 52,986 |
| | 55,179 |
| 52,454 |
| 54,520 |
| 55,384 |
| | 54,361 |
| 55,179 |
|
__________
| |
| (a) | Calculated using the treasury stock method. |
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 June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| | | | | | | |
| Equity compensation | — |
| 4 |
| | — |
| 10 |
| 15 |
| — |
| | 17 |
| — |
|
| Anti-dilutive shares | — |
| 4 |
| | — |
| 10 |
| 15 |
| — |
| | 17 |
| — |
|
(89) NOTES PAYABLE, CURRENT MATURITIES AND LONG-TERM DEBT
We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | June 30, 2017 | December 31, 2016 | June 30, 2016 | June 30, 2018 | December 31, 2017 | June 30, 2017 |
| | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit |
| Revolving Credit Facility | $ | — |
| $ | 24,540 |
| $ | 96,600 |
| $ | 36,000 |
| $ | 75,000 |
| $ | 24,700 |
| $ | — |
| $ | 11,448 |
| $ | — |
| $ | 26,848 |
| $ | — |
| $ | 24,540 |
|
| CP Program | 107,975 |
| — |
| — |
| — |
| — |
| — |
| 121,800 |
| — |
| 211,300 |
| — |
| 107,975 |
| — |
|
| Total | $ | 107,975 |
| $ | 24,540 |
| $ | 96,600 |
| $ | 36,000 |
| $ | 75,000 |
| $ | 24,700 |
| $ | 121,800 |
| $ | 11,448 |
| $ | 211,300 |
| $ | 26,848 |
| $ | 107,975 |
| $ | 24,540 |
|
Revolving Credit Facility and CP Program
On August 9, 2016,July 30, 2018, we amended and restated our corporate Revolving Credit Facility, to increasemaintaining total commitments toof $750 million from $500 million and extendextending the term through August 9, 2021July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former agreement,revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, andthe issuing agents and each bank increasing or providing a new commitment, to increase total commitments of the facility up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P, or Moody’sFitch, 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 0.250%, 1.250%, and 1.250%, respectively, at June 30, 2017. A2018 and are unchanged under our amended and restated Revolving Credit Facility. Based on our credit ratings, a 0.200% commitment fee iswas charged on the unused amount of theat June 30, 2018. This commitment fee requirement is unchanged under our amended and restated Revolving Credit Facility.
On December 22, 2016, we implementedWe 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 amount borrowedpayments under the CP Program during the six months ended June 30, 20172018 were $90 million and our notes outstanding as of June 30, 20172018 were $108$122 million. As of June 30, 2017,2018, the weighted average interest rate on CP Program borrowings was 1.41%2.29%.
Debt Covenants
On December 7, 2016, we amendedUnder our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under theagreement (before each was amended and restated Revolving Credit Facility and term loan agreements,restated), we arewere required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. OurAt June 30, 2018, our Consolidated Indebtedness to Capitalization Ratio iswas calculated by dividing (i) Consolidated Indebtedness which includes(which included letters of credit and certain guarantees issued and excludes RSNsbut excluded the RSNs), by (ii) Capital, which includesis Consolidated Indebtedness plus Consolidated Net Worth which excludes(which excluded noncontrolling interests in subsidiaries and includesincluded 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 our Term Loansterm loans require compliance with the following financial covenant at the end of each quarter:
|
| | | | |
| | As of June 30, 2017 | | Covenant Requirement |
| Consolidated Indebtedness to Capitalization Ratio | 61% | | Less than | 65% |
|
| | | | |
| | As of June 30, 2018 | | Covenant Requirement |
| Consolidated Indebtedness to Capitalization Ratio | 58% | | Less than | 65% |
As of June 30, 2017,2018, we were in compliance with this covenant.
Long-Term Debt
On May 16, 2017, we paid down $50
Current Maturities
As of June 30, 2018, our $250 million Senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 millionJune 7, 2021 are classified as Current maturities of long-term debt on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.
Condensed Consolidated Balance Sheets.
(9)Long-Term Debt
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 June 30, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is 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 and Eurodollar borrowings were 0.050% and 1.050%, respectively, at June 30, 2018, and are 0.000% and 0.750%, respectively, under our amended and restated Revolving Credit Facility.
(10) EQUITY
A summary of the changes in equity is as follows:
| | | Six Months Ended June 30, 2017 | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity | |
| Six Months Ended June 30, 2018 | | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity |
| | | (in thousands) | | | (in thousands) | |
| Balance at December 31, 2016 | $ | 1,614,639 |
| $ | 115,495 |
| $ | 1,730,134 |
| |
| Balance at December 31, 2017 | | $ | 1,708,974 |
| $ | 111,232 |
| $ | 1,820,206 |
|
| Net income (loss) | 98,718 |
| 6,632 |
| 105,350 |
| 154,921 |
| 6,453 |
| 161,374 |
|
| Other comprehensive income (loss) | 1,942 |
| — |
| 1,942 |
| 2,421 |
| — |
| 2,421 |
|
| Dividends on common stock | (47,544 | ) | — |
| (47,544 | ) | (50,879 | ) | — |
| (50,879 | ) |
| Share-based compensation | 4,133 |
| — |
| 4,133 |
| 3,194 |
| — |
| 3,194 |
|
| Issuance of common stock | — |
| — |
| — |
| |
| Dividend reinvestment and stock purchase plan | 1,530 |
| — |
| 1,530 |
| 219 |
| — |
| 219 |
|
| Redeemable noncontrolling interest | (886 | ) | — |
| (886 | ) | |
| Cumulative effect of ASU 2016-09 implementation | 3,714 |
| — |
| 3,714 |
| |
| Other stock transactions | (7 | ) | — |
| (7 | ) | (4 | ) | — |
| (4 | ) |
| Distribution to noncontrolling interest | — |
| (8,335 | ) | (8,335 | ) | — |
| (9,998 | ) | (9,998 | ) |
| Balance at June 30, 2017 | $ | 1,676,239 |
| $ | 113,792 |
| $ | 1,790,031 |
| |
| Balance at June 30, 2018 | | $ | 1,818,846 |
| $ | 107,687 |
| $ | 1,926,533 |
|
| | | Six Months Ended June 30, 2016 | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity | |
| Six Months Ended June 30, 2017 | | Total Stockholders’ Equity | Noncontrolling Interest | Total Equity |
| | | (in thousands) | | | (in thousands) | |
| Balance at December 31, 2015 | $ | 1,465,867 |
| $ | — |
| $ | 1,465,867 |
| |
| Balance at December 31, 2016 | | $ | 1,614,639 |
| $ | 115,495 |
| $ | 1,730,134 |
|
| Net income (loss) | 40,671 |
| 2,632 |
| 43,303 |
| 98,718 |
| 6,632 |
| 105,350 |
|
| Other comprehensive income (loss) | (22,709 | ) | — |
| (22,709 | ) | 1,942 |
| — |
| 1,942 |
|
| Dividends on common stock | (43,270 | ) | — |
| (43,270 | ) | (47,544 | ) | — |
| (47,544 | ) |
| Share-based compensation | 2,192 |
| — |
| 2,192 |
| 4,133 |
| — |
| 4,133 |
|
| Issuance of common stock | 55,802 |
| — |
| 55,802 |
| |
| Dividend reinvestment and stock purchase plan | 1,478 |
| — |
| 1,478 |
| 1,530 |
| — |
| 1,530 |
|
| Redeemable noncontrolling interest | | (886 | ) | — |
| (886 | ) |
| Cumulative effect of ASU 2016-09 implementation | | 3,714 |
| — |
| 3,714 |
|
| Other stock transactions | (20 | ) | — |
| (20 | ) | (7 | ) | — |
| (7 | ) |
| Sale of noncontrolling interest | 62,416 |
| 114,886 |
| 177,302 |
| |
| Balance at June 30, 2016 | $ | 1,562,427 |
| $ | 117,518 |
| $ | 1,679,945 |
| |
| Distribution to noncontrolling interest | | — |
| (8,335 | ) | (8,335 | ) |
| Balance at June 30, 2017 | | $ | 1,676,239 |
| $ | 113,792 |
| $ | 1,790,031 |
|
At-the-Market Equity Offering Program
On March 18, 2016,August 4, 2017, we implemented anrenewed our ATM equity offering program allowingwhich 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, with anis the same as the prior program other than the aggregate value of upincreased from $200 million to $200$300 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016.August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the six months ended June 30, 2017. During the three months ended2018 and June 30, 2016, we sold 809,649 common shares for $49 million, net of $0.5 million in commissions,2017 under the ATM equity offering program. During the six months ended June 30, 2016, we sold and issued an aggregate of 930,649 shares of common stock under the ATM equity offering program for $56 million, net of $0.6 million in commissions with settlement dates through June 30, 2016. On August 4, 2017, the Company plans to file for renewal of the ATM equity offering program initiated in 2016 which resets the size of the ATM equity offering program to an aggregate sales price of up to $300 million.
Sale of
Noncontrolling Interest in Subsidiary
Black Hills Colorado IPP owns a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric.
This partial sale was required to be recorded as an equity transaction with no resulting gain or loss on the sale. Further, GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.
Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.
We have recorded the following assets and liabilities on our consolidated balance sheetsCondensed Consolidated Balance Sheets related to the VIE described above as of:
| | | | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| | (in thousands) | (in thousands) |
| Assets | | | | | | | | | | |
| Current assets | $ | 12,042 |
| | $ | 12,627 |
| | $ | 12,681 |
| $ | 11,462 |
| | $ | 14,837 |
| | $ | 12,042 |
|
| Property, plant and equipment of variable interest entities, net | $ | 214,239 |
| | $ | 218,798 |
| | $ | 224,128 |
| $ | 203,308 |
| | $ | 208,595 |
| | $ | 214,239 |
|
| | | | | | | | | | | |
| Liabilities | | | | | | | | | | |
| Current liabilities | $ | 2,651 |
| | $ | 4,342 |
| | $ | 4,174 |
| $ | 2,946 |
| | $ | 4,565 |
| | $ | 2,651 |
|
(1011) 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 Policies and Procedures as discussed in our 20162017 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 natural long position in crude oil and natural gas reserves and production, our retail natural gas marketing activities and our fuel procurement for certain of our gas-fired generation assets.assets; and
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 generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the 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 1112.
Oil and Gas
We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.
To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on our futures and swaps. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.
The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income.
The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of:
|
| | | | | | | | | | | | | | | | | | |
| | June 30, 2017 | | December 31, 2016 | | June 30, 2016 |
| | Crude Oil Futures | Crude Oil Options | Natural Gas Futures and Swaps | | Crude Oil Futures | Crude Oil Options | Natural Gas Futures and Swaps | | Crude Oil Futures | Natural Gas Futures and Swaps |
Notional (a) | 72,000 |
| 18,000 |
| 1,080,000 |
| | 108,000 |
| 36,000 |
| 2,700,000 |
| | 210,000 |
| 2,530,000 |
|
Maximum terms in months (b) | 18 |
| 6 |
| 6 |
| | 24 |
| 12 |
| 12 |
| | 30 |
| 18 |
|
__________ | |
(a) | Crude oil futures and call options in Bbls, natural gas in MMBtus. |
| |
(b) | Term reflects the maximum forward period hedged. |
Based on June 30, 2017 prices, a $0.5 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.
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 approvedcommission-approved hedging programs utilizing natural gas futures, options, fixed to floatover-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, or the Condensed Consolidated Statements of Comprehensive 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 July 20172018 through DecemberMay 2020. A portion of our over-the-counter 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. Effectiveness of our hedging position is evaluated at least quarterly.
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 Utilitiesutilities are composed of both long and short positions. We were in a net long position as of:
| | | | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) | | Notional (MMBtus) | | Maximum Term (months) (a) |
| Natural gas futures purchased | 11,060,000 |
| | 42 | | 14,770,000 |
| | 48 | | 18,080,000 |
| | 54 | 5,680,000 |
| | 30 | | 8,330,000 |
| | 36 | | 11,060,000 |
| | 42 |
| Natural gas options purchased, net | 1,640,000 |
| | 20 | | 3,020,000 |
| | 5 | | 3,770,000 |
| | 20 | 1,140,000 |
| | 9 | | 3,540,000 |
| | 14 | | 1,640,000 |
| | 20 |
| Natural gas basis swaps purchased | 10,070,000 |
| | 42 | | 12,250,000 |
| | 48 | | 15,320,000 |
| | 54 | 5,720,000 |
| | 30 | | 8,060,000 |
| | 36 | | 10,070,000 |
| | 42 |
Natural gas over-the-counter swaps, net (b) | 5,200,000 |
| | 23 | | 4,622,302 |
| | 28 | | 5,029,500 |
| | 23 | 4,950,000 |
| | 23 | | 3,820,000 |
| | 29 | | 5,200,000 |
| | 23 |
Natural gas physical contracts, net | 8,427,119 |
| | 10 | | 21,504,378 |
| | 10 | | 1,666,800 |
| | 9 | 3,866,648 |
| | 210 | | 12,826,605 |
| | 35 | | 8,427,119 |
| | 10 |
__________
| |
| (a) | Term reflects the maximum forward period hedged. |
| |
| (b) | 2,480,000As of June 30, 2018, 2,452,000 MMBtus were designated as cash flow hedges for the natural gas fixedover-the-counter swaps purchased. |
| |
| (c) | Volumes exclude contracts that qualify for float swaps purchased.the normal purchase, normal sales exception. |
Based on June 30, 20172018 prices, a $0.2$0.1 million loss 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.
Financing Activities
In October 2015 and January 2016, we entered into forward starting interest rate swaps withWe 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 notional value totaling $400 million to reduce the interest rate risk associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 millionnegotiated line of unsecured ten-year senior notes on August 10, 2016. The effective portion ofcredit. At June 30, 2018, the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten-year life of the $400 million unsecured senior note issued on August 19, 2016. Amortization of approximately $2.9 million, which includes the amortization of the $28 million loss currently deferred in AOCI will be recognized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. The ineffective portion of $1.0Company posted $0.7 million related to the timing of the debt issuance, was recognizedsuch provisions, which is included in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflectedOther current assets on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:Sheets.
|
| | | | | | | | | | | | | | | | | |
| | June 30, 2017 | | December 31, 2016 | | June 30, 2016 |
| | Designated
Interest Rate
Swaps | | Designated
Interest Rate
Swap (a) | | Designated
Interest Rate
Swap (b) | Designated
Interest Rate
Swap (b) | Designated
Interest Rate
Swaps (a) |
| Notional | $ | — |
| | $ | 50,000 |
| | $ | 150,000 |
| $ | 250,000 |
| $ | 75,000 |
|
| Weighted average fixed interest rate | — | % | | 4.94 | % | | 2.09 | % | 2.29 | % | 4.97 | % |
| Maximum terms in months | 0 |
| | 1 |
| | 10 |
| 10 |
| 6 |
|
| Derivative liabilities, current | $ | — |
| | $ | 90 |
| | $ | 8,553 |
| $ | 18,500 |
| $ | 1,505 |
|
__________
| |
(a) | The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. |
| |
(b) | These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt. |
Financing Activities
At June 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 June 30, 2018 or December 31, 2017. At June 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 72,000 Bbls, crude oil option contracts with notional volumes of 18,000 Bbls and natural gas futures and swap contracts with notional volumes of 1,080,000 MMBtus.
Cash Flow Hedges
The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and six months ended June 30, 20172018 and 20162017 (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 gross profit or loss we realized when the underlying physical and financial transactions were settled.
| | | Three Months Ended June 30, 2017 | |
| Three Months Ended June 30, 2018 | | Three Months Ended June 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) | | 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 | | $ | — |
| | Interest expense | | $ | (713 | ) | | Interest expense | | $ | — |
|
| Commodity derivatives | | Revenue | | 430 |
| | Revenue | | — |
| | Fuel, purchased power and cost of natural gas sold | | (163 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
| Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (44 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
| |
| Total | | $ | (327 | ) | | $ | — |
| | $ | (876 | ) | | $ | — |
|
|
| | | | | | | | | | | | |
| Three Months Ended June 30, 2016 |
| Derivatives in Cash Flow Hedging Relationships | | Location of Reclassifications from AOCI into Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) |
| Interest rate swaps | | Interest expense | | $ | (840 | ) | | Interest expense | | $ | — |
|
| Commodity derivatives | | Revenue | | 3,287 |
| | Revenue | | — |
|
| Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (61 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
| Total | | | | $ | 2,386 |
| | | | $ | — |
|
| | | | | | | | |
| Six Months Ended June 30, 2017 | |
| Three Months Ended June 30, 2017 | | Three Months Ended June 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) | | 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 | | $ | (1,515 | ) | | Interest expense | | $ | — |
| | Interest expense | | $ | (713 | ) | | Interest expense | | $ | — |
|
| Commodity derivatives | | Revenue | | 659 |
| | Revenue | | — |
| | Net (loss) from discontinued operations | | 430 |
| | Net (loss) from discontinued operations | | — |
|
| Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | 14 |
| | Fuel, purchased power and cost of natural gas sold | | — |
| | Fuel, purchased power and cost of natural gas sold | | (44 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
| Total | | $ | (842 | ) | | $ | — |
| | $ | (327 | ) | | $ | — |
|
| | | | | | |
| | | | | | | | | | | |
| Six Months Ended June 30, 2016 | |
| Six Months Ended June 30, 2018 | | Six Months Ended June 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) | | 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 | | $ | (1,690 | ) | | Interest expense | | $ | — |
| | Interest expense | | $ | (1,426 | ) | | Interest expense | | $ | — |
|
| Commodity derivatives | | Revenue | | 6,939 |
| | Revenue | | — |
| | Fuel, purchased power and cost of natural gas sold | | (784 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
|
| Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | (151 | ) | | Fuel, purchased power and cost of natural gas sold | | — |
| |
| Total | | $ | 5,098 |
| | $ | — |
| | $ | (2,210 | ) | | $ | — |
|
|
| | | | | | | | | | | | |
| | | | | | | | | |
| Six Months Ended June 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 | | $ | (1,515 | ) | | Interest expense | | $ | — |
|
| Commodity derivatives | | Net (loss) from discontinued operations | | 659 |
| | Net (loss) from discontinued operations | | — |
|
| Commodity derivatives | | Fuel, purchased power and cost of natural gas sold | | 14 |
| | Fuel, purchased power and cost of natural gas sold | | — |
|
| Total | | | | $ | (842 | ) | | | | $ | — |
|
The following table summarizestables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and six months ended June 30, 20172018 and 2016.2017. The amounts included in the tabletables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Net Income as incurred.
| | | | Three Months Ended June 30, | Three Months Ended June 30, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (In thousands) | (in thousands) |
| Increase (decrease) in fair value: | | | | | | |
| Interest rate swaps | $ | — |
| | $ | (12,614 | ) | |
| Forward commodity contracts | 525 |
| | (2,452 | ) | $ | 48 |
| | $ | 525 |
|
| Recognition of (gains) losses in earnings due to settlements: | | | | | | |
| Interest rate swaps | 713 |
| | 840 |
| 713 |
| | 713 |
|
| Forward commodity contracts | (386 | ) | | (3,226 | ) | 163 |
| | (386 | ) |
| Total other comprehensive income (loss) from hedging | $ | 852 |
| | $ | (17,452 | ) | $ | 924 |
| | $ | 852 |
|
| | | | | | | | | |
| | Six Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (In thousands) | (in thousands) |
| Increase (decrease) in fair value: | | | | | | |
| Interest rate swaps | $ | — |
| | $ | (30,665 | ) | |
| Forward commodity contracts | 1,451 |
| | (266 | ) | $ | (249 | ) | | $ | 1,451 |
|
| Recognition of (gains) losses in earnings due to settlements: | | | | | | |
| Interest rate swaps | 1,515 |
| | 1,690 |
| 1,426 |
| | 1,515 |
|
| Forward commodity contracts | (673 | ) | | 6,788 |
| 784 |
| | (673 | ) |
| Total other comprehensive income (loss) from hedging | $ | 2,293 |
| | $ | (22,453 | ) | $ | 1,961 |
| | $ | 2,293 |
|
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 six months ended June 30, 20172018 and 20162017 (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 gross profit or loss we realized when the underlying physical and financial transactions were settled.
| | | | | Three Months Ended June 30, | | Three Months Ended June 30, |
| | | 2017 | | 2016 | | 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 | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | | | | | | | | |
| Commodity derivatives | Revenue | $ | 26 |
| | $ | — |
| Net (loss) from discontinued operations | $ | — |
| | $ | 26 |
|
| Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (691 | ) | | 2,201 |
| Fuel, purchased power and cost of natural gas sold | 771 |
| | (691 | ) |
| | | $ | (665 | ) | | $ | 2,201 |
| | $ | 771 |
| | $ | (665 | ) |
| | | | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | | 2017 | | 2016 | | 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 | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | | Amount of Gain/(Loss) on Derivatives Recognized in Income |
| | | | | | | | | |
| Commodity derivatives | Revenue | $ | 143 |
| | $ | — |
| Net (loss) from discontinued operations | $ | — |
| | $ | 143 |
|
| Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (1,500 | ) | | 2,835 |
| Fuel, purchased power and cost of natural gas sold | 1,025 |
| | (1,500 | ) |
| | | $ | (1,357 | ) | | $ | 2,835 |
| | $ | 1,025 |
| | $ | (1,357 | ) |
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.assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our Utilitiesutilities were $11$9.1 million, $8.8$12 million and $12$11 million at June 30, 2017,2018, December 31, 20162017 and June 30, 2016,2017, respectively.
(1112) 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 20162017 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
Oil and Gas Segment:Discontinued Operations:
The commodity contracts for our Oil and Gas segmentgas derivative instruments are valued using the market approachincluded in assets and include exchange-traded futures, basis swaps and call options. Fair value was derived using exchange quoted settlement prices from third party brokersliabilities held for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure.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:
As of June 30, 2017,2018, we no longer have derivatives within our corporate activities as our last interest rate swaps matured in January 2017. The interest rate swaps that were in place prior to January 2017 were valued using the market approach. We established fair value by obtaining price quotes directly from the counterparty which were based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty was validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives included a CVA component. The CVA considered the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilized observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that took into account our credit ratings, and the credit rating of our counterparty.
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 arepresent 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 June 30, 2017 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| | (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 770 |
| $ | — |
| | $ | (230 | ) | $ | 540 |
|
| Commodity derivatives — Utilities | — |
| 1,622 |
| — |
| | (977 | ) | 645 |
|
| Total | $ | — |
| $ | 2,392 |
| $ | — |
| | $ | (1,207 | ) | $ | 1,185 |
|
| | | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 44 |
| $ | — |
| | $ | — |
| $ | 44 |
|
| Commodity derivatives — Utilities | — |
| 12,331 |
| — |
| | (11,568 | ) | 763 |
|
| Total | $ | — |
| $ | 12,375 |
| $ | — |
| | $ | (11,568 | ) | $ | 807 |
|
| | | | As of December 31, 2016 | As of June 30, 2018 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| | (in thousands) | (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 2,886 |
| $ | — |
| | $ | (2,733 | ) | $ | 153 |
| |
| Commodity derivatives —Utilities | — |
| 7,469 |
| — |
| | (3,262 | ) | 4,207 |
| |
| Commodity derivatives — Utilities | | $ | — |
| $ | 1,035 |
| $ | — |
| | $ | (363 | ) | $ | 672 |
|
| Total | $ | — |
| $ | 10,355 |
| $ | — |
| | $ | (5,995 | ) | $ | 4,360 |
| $ | — |
| $ | 1,035 |
| $ | — |
| | $ | (363 | ) | $ | 672 |
|
| | | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 1,586 |
| $ | — |
| | $ | — |
| $ | 1,586 |
| |
| Commodity derivatives — Utilities | — |
| 12,201 |
| — |
| | (11,144 | ) | 1,057 |
| $ | — |
| $ | 9,808 |
| $ | — |
| | $ | (9,144 | ) | $ | 664 |
|
| Interest rate swaps | — |
| 90 |
| — |
| | — |
| 90 |
| |
| Total | $ | — |
| $ | 13,877 |
| $ | — |
| | $ | (11,144 | ) | $ | 2,733 |
| $ | — |
| $ | 9,808 |
| $ | — |
| | $ | (9,144 | ) | $ | 664 |
|
| | | | As of June 30, 2016 | As of December 31, 2017 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| | (in thousands) | (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 2,748 |
| $ | — |
| | $ | (1,150 | ) | $ | 1,598 |
| |
| Commodity derivatives — Utilities | — |
| 6,833 |
| — |
| | (4,175 | ) | 2,658 |
| $ | — |
| $ | 1,586 |
| $ | — |
| | $ | (1,282 | ) | $ | 304 |
|
| Total | $ | — |
| $ | 9,581 |
| $ | — |
| | $ | (5,325 | ) | $ | 4,256 |
| $ | — |
| $ | 1,586 |
| $ | — |
| | $ | (1,282 | ) | $ | 304 |
|
| | | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Oil and Gas | $ | — |
| $ | 228 |
| $ | — |
| | $ | — |
| $ | 228 |
| |
| Commodity derivatives — Utilities | — |
| 14,727 |
| — |
| | (14,427 | ) | 300 |
| $ | — |
| $ | 13,756 |
| $ | — |
| | $ | (11,497 | ) | $ | 2,259 |
|
| Interest rate swaps | — |
| 28,558 |
| — |
| | — |
| 28,558 |
| |
| Total | $ | — |
| $ | 43,513 |
| $ | — |
| | $ | (14,427 | ) | $ | 29,086 |
| $ | — |
| $ | 13,756 |
| $ | — |
| | $ | (11,497 | ) | $ | 2,259 |
|
|
| | | | | | | | | | | | | | | | |
| | As of June 30, 2017 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| | (in thousands) |
| Assets: | | | | | | |
| Commodity derivatives — Utilities | $ | — |
| $ | 1,622 |
| $ | — |
| | $ | (977 | ) | $ | 645 |
|
| Total | $ | — |
| $ | 1,622 |
| $ | — |
| | $ | (977 | ) | $ | 645 |
|
| | | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives — Utilities | $ | — |
| $ | 12,331 |
| $ | — |
| | $ | (11,568 | ) | $ | 763 |
|
| Total | $ | — |
| $ | 12,331 |
| $ | — |
| | $ | (11,568 | ) | $ | 763 |
|
Fair Value Measures by Balance Sheet Classification
As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.
The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
| | | As of June 30, 2017 | |
| As of June 30, 2018 | | As of June 30, 2018 |
| | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
| Derivatives designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 548 |
| $ | — |
| Derivative assets — current | | $ | 128 |
| $ | — |
|
| Commodity derivatives | Derivative assets — non-current | | 31 |
| — |
| Other assets, non-current | | 6 |
| — |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 167 |
| Derivative liabilities — current | | — |
| 305 |
|
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 32 |
| Other deferred credits and other liabilities | | — |
| 16 |
|
| Total derivatives designated as hedges | | $ | 579 |
| $ | 199 |
| | $ | 134 |
| $ | 321 |
|
| | | | | |
| Derivatives not designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 600 |
| $ | — |
| Derivative assets — current | | $ | 538 |
| $ | — |
|
| Commodity derivatives | Derivative assets — non-current | | 6 |
| — |
| Other assets, non-current | | — |
| — |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 552 |
| Derivative liabilities — current | | — |
| 180 |
|
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 56 |
| Other deferred credits and other liabilities | | — |
| 163 |
|
| Total derivatives not designated as hedges | | $ | 606 |
| $ | 608 |
| | $ | 538 |
| $ | 343 |
|
| | | As of December 31, 2016 | |
| As of December 31, 2017 | | As of December 31, 2017 |
| | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
| Derivatives designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 1,161 |
| $ | — |
| Derivative liabilities — current | | $ | — |
| $ | 817 |
|
| Commodity derivatives | Derivative assets — non-current | | 124 |
| — |
| Other deferred credits and other liabilities | | — |
| 67 |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 1,090 |
| |
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 238 |
| |
| Interest rate swaps | Derivative liabilities — current | | — |
| 90 |
| |
| Total derivatives designated as hedges | | $ | 1,285 |
| $ | 1,418 |
| | $ | — |
| $ | 884 |
|
| | | | | |
| Derivatives not designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 2,977 |
| $ | — |
| Derivative assets — current | | $ | 304 |
| $ | — |
|
| Commodity derivatives | Derivative assets — non-current | | 98 |
| — |
| Derivative liabilities — current | | — |
| 1,264 |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 1,279 |
| Other deferred credits and other liabilities | | — |
| 111 |
|
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 36 |
| |
| Total derivatives not designated as hedges | | $ | 3,075 |
| $ | 1,315 |
| | $ | 304 |
| $ | 1,375 |
|
| | | As of June 30, 2016 | |
| As of June 30, 2017 | | As of June 30, 2017 |
| | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | Balance Sheet Location | | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives |
| Derivatives designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 2,549 |
| $ | — |
| Derivative assets — current | | $ | 39 |
| $ | — |
|
| Commodity derivatives | Derivative assets — non-current | | 81 |
| — |
| Current assets held for sale | | 509 |
| — |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 44 |
| Noncurrent assets held for sale | | 31 |
| — |
|
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 226 |
| Derivative liabilities — current | | — |
| 140 |
|
| Interest rate swaps | Derivative liabilities — current | | — |
| 28,558 |
| |
| Commodity derivatives | | Other deferred credits and other liabilities | | — |
| 32 |
|
| Commodity derivatives | | Current liabilities held for sale | | — |
| 27 |
|
| Total derivatives designated as hedges | | $ | 2,630 |
| $ | 28,828 |
| | $ | 579 |
| $ | 199 |
|
| | | | | |
| Derivatives not designated as hedges: | | | | |
| Commodity derivatives | Derivative assets — current | | $ | 1,481 |
| $ | — |
| Derivative assets — current | | $ | 600 |
| $ | — |
|
| Commodity derivatives | Derivative assets — non-current | | 145 |
| — |
| Other assets, non-current | | 6 |
| — |
|
| Commodity derivatives | Derivative liabilities — current | | — |
| 254 |
| Derivative liabilities — current | | — |
| 536 |
|
| Commodity derivatives | Derivative liabilities — non-current | | — |
| 4 |
| Other deferred credits and other liabilities | | — |
| 55 |
|
| Commodity derivatives | | Current liabilities held for sale | | — |
| 17 |
|
| Total derivatives not designated as hedges | | $ | 1,626 |
| $ | 258 |
| | $ | 606 |
| $ | 608 |
|
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 20162017 Annual Report on Form 10-K.
(1213) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 11,12, were as follows (in thousands) as of:
| | | | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| | Carrying Amount | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | Fair Value | Carrying Amount | Fair Value | | Carrying Amount | Fair Value | | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 11,590 |
| $ | 11,590 |
| | $ | 13,580 |
| $ | 13,580 |
| | $ | 61,859 |
| $ | 61,859 |
| $ | 8,630 |
| $ | 8,630 |
| | $ | 15,420 |
| $ | 15,420 |
| | $ | 11,528 |
| $ | 11,528 |
|
Restricted cash and equivalents (a) | $ | 2,534 |
| $ | 2,534 |
| | $ | 2,274 |
| $ | 2,274 |
| | $ | 1,975 |
| $ | 1,975 |
| |
Restricted cash (a) | | $ | 3,084 |
| $ | 3,084 |
| | $ | 2,820 |
| $ | 2,820 |
| | $ | 2,534 |
| $ | 2,534 |
|
Notes payable (b) | $ | 107,975 |
| $ | 107,975 |
| | $ | 96,600 |
| $ | 96,600 |
| | $ | 75,000 |
| $ | 75,000 |
| $ | 121,800 |
| $ | 121,800 |
| | $ | 211,300 |
| $ | 211,300 |
| | $ | 107,975 |
| $ | 107,975 |
|
Long-term debt, including current maturities, net of deferred financing costs (c) | $ | 3,166,045 |
| $ | 3,377,891 |
| | $ | 3,216,932 |
| $ | 3,351,305 |
| | $ | 3,152,090 |
| $ | 3,427,587 |
| |
Long-term debt, including current maturities (c) (d) | | $ | 3,113,811 |
| $ | 3,234,780 |
| | $ | 3,115,143 |
| $ | 3,350,544 |
| | $ | 3,166,045 |
| $ | 3,377,891 |
|
__________
| |
| (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) | Carrying amount of long-term debt is net of deferred financing costs. |
| |
(1314) | 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 | | Six Months Ended | Three Months Ended | | Six Months Ended |
| June 30, 2017 | June 30, 2016 | | June 30, 2017 | June 30, 2016 | June 30, 2018 | June 30, 2017 | | June 30, 2018 | June 30, 2017 |
| Gains and (losses) on cash flow hedges: | | | | | | | | |
| Interest rate swaps | Interest expense | $ | (713 | ) | $ | (840 | ) | | $ | (1,515 | ) | $ | (1,690 | ) | Interest expense | $ | (713 | ) | $ | (713 | ) | | $ | (1,426 | ) | $ | (1,515 | ) |
| Commodity contracts | Revenue | 430 |
| 3,287 |
| | 659 |
| 6,939 |
| Net (loss) from discontinued operations | — |
| 430 |
| | — |
| 659 |
|
| Commodity contracts | Fuel, purchased power and cost of natural gas sold
| (44 | ) | (61 | ) | | 14 |
| (151 | ) | Fuel, purchased power and cost of natural gas sold
| (163 | ) | (44 | ) | | (784 | ) | 14 |
|
| | | (327 | ) | 2,386 |
| | (842 | ) | 5,098 |
| | (876 | ) | (327 | ) | | (2,210 | ) | (842 | ) |
| Income tax | Income tax benefit (expense) | 106 |
| (882 | ) | | 281 |
| (1,884 | ) | Income tax benefit (expense) | 197 |
| 106 |
| | 494 |
| 281 |
|
| Total reclassification adjustments related to cash flow hedges, net of tax | | $ | (221 | ) | $ | 1,504 |
| | $ | (561 | ) | $ | 3,214 |
| | $ | (679 | ) | $ | (221 | ) | | $ | (1,716 | ) | $ | (561 | ) |
| | | | | | | | | |
| Amortization of components of defined benefit plans: | | | | | | | | |
| Prior service cost | Operations and maintenance | $ | 49 |
| $ | 55 |
| | $ | 97 |
| $ | 110 |
| Operations and maintenance | $ | 44 |
| $ | 49 |
| | $ | 89 |
| $ | 97 |
|
| | | | | | |
| Actuarial gain (loss) | Operations and maintenance | (414 | ) | (494 | ) | | (828 | ) | (989 | ) | Operations and maintenance | (622 | ) | (414 | ) | | (1,244 | ) | (828 | ) |
| | | (365 | ) | (439 | ) | | (731 | ) | (879 | ) | | (578 | ) | (365 | ) | | (1,155 | ) | (731 | ) |
| Income tax | Income tax benefit (expense) | 128 |
| 154 |
| | 265 |
| 308 |
| Income tax benefit (expense) | 126 |
| 128 |
| | 252 |
| 265 |
|
| Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (237 | ) | $ | (285 | ) | | $ | (466 | ) | $ | (571 | ) | | $ | (452 | ) | $ | (237 | ) | | $ | (903 | ) | $ | (466 | ) |
| Total reclassifications | | $ | (458 | ) | $ | 1,219 |
| | $ | (1,027 | ) | $ | 2,643 |
| | $ | (1,131 | ) | $ | (458 | ) | | $ | (2,619 | ) | $ | (1,027 | ) |
Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
| | | | Derivatives Designated as Cash Flow Hedges | | Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2017 | | $ | (19,581 | ) | $ | (518 | ) | $ | (21,103 | ) | $ | (41,202 | ) |
| Other comprehensive income (loss) | | |
| before reclassifications | | — |
| (198 | ) | — |
| (198 | ) |
| Amounts reclassified from AOCI | | 1,122 |
| 594 |
| 903 |
| 2,619 |
|
| Reclassifications of certain tax effects from AOCI | | 15 |
| — |
| 3 |
| 18 |
|
| Ending Balance June 30, 2018 | | $ | (18,444 | ) | $ | (122 | ) | $ | (20,197 | ) | $ | (38,763 | ) |
| | Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total | |
| As of December 31, 2016 | $ | (18,109 | ) | $ | (233 | ) | $ | (16,541 | ) | $ | (34,883 | ) | |
| | | |
| | | 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 | — |
| 915 |
| — |
| 915 |
| — |
| 915 |
| — |
| 915 |
|
| Amounts reclassified from AOCI | 985 |
| (424 | ) | 466 |
| 1,027 |
| 985 |
| (424 | ) | 466 |
| 1,027 |
|
| Ending Balance June 30, 2017 | $ | (17,124 | ) | $ | 258 |
| $ | (16,075 | ) | $ | (32,941 | ) | $ | (17,124 | ) | $ | 258 |
| $ | (16,075 | ) | $ | (32,941 | ) |
| | | |
| | | |
| | Derivatives Designated as Cash Flow Hedges | | |
| | Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total | |
| Balance as of December 31, 2015 | $ | (341 | ) | $ | 7,066 |
| $ | (15,780 | ) | $ | (9,055 | ) | |
| Other comprehensive income (loss) | | |
| before reclassifications | (19,898 | ) | (168 | ) | — |
| (20,066 | ) | |
| Amounts reclassified from AOCI | 1,098 |
| (4,312 | ) | 571 |
| (2,643 | ) | |
| Ending Balance June 30, 2016 | $ | (19,141 | ) | $ | 2,586 |
| $ | (15,209 | ) | $ | (31,764 | ) | |
(1415) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
| | | Six Months Ended | June 30, 2017 | | June 30, 2016 | June 30, 2018 | | June 30, 2017 |
| | (in thousands) | (in thousands) |
| Non-cash investing and financing activities— | | | | |
| Non-cash investing and financing activities — | | | | |
| Property, plant and equipment acquired with accrued liabilities | $ | 37,601 |
| | $ | 52,917 |
| $ | 37,168 |
| | $ | 31,579 |
|
| | | | | | | |
| Cash (paid) refunded during the period — | | | | | | |
| Interest (net of amounts capitalized) | $ | (65,820 | ) | | $ | (48,139 | ) | $ | (67,119 | ) | | $ | (65,820 | ) |
| Income taxes, net | $ | 1 |
| | $ | (1,162 | ) | |
| Income taxes (paid) refunded | | $ | (14,837 | ) | | $ | 1 |
|
(1516) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension PlansPlan
The components of net periodic benefit cost for the Defined Benefit Pension PlansPlan were as follows (in thousands):
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| Service cost | $ | 1,759 |
| $ | 2,078 |
| | $ | 3,517 |
| $ | 4,156 |
| $ | 1,709 |
| $ | 1,759 |
| | $ | 3,417 |
| $ | 3,517 |
|
| Interest cost | 3,880 |
| 3,936 |
| | 7,760 |
| 7,872 |
| 3,868 |
| 3,880 |
| | 7,735 |
| 7,760 |
|
| Expected return on plan assets | (6,129 | ) | (5,766 | ) | | (12,258 | ) | (11,531 | ) | (6,185 | ) | (6,129 | ) | | (12,370 | ) | (12,258 | ) |
| Prior service cost | 15 |
| 15 |
| | 29 |
| 30 |
| 14 |
| 15 |
| | 29 |
| 29 |
|
| Net loss (gain) | 1,001 |
| 1,793 |
| | 2,003 |
| 3,586 |
| 2,157 |
| 1,001 |
| | 4,315 |
| 2,003 |
|
| Net periodic benefit cost | $ | 526 |
| $ | 2,056 |
| | $ | 1,051 |
| $ | 4,113 |
| $ | 1,563 |
| $ | 526 |
| | $ | 3,126 |
| $ | 1,051 |
|
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 June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| Service cost | $ | 575 |
| $ | 467 |
| | $ | 1,150 |
| $ | 934 |
| $ | 572 |
| $ | 575 |
| | $ | 1,145 |
| $ | 1,150 |
|
| Interest cost | 534 |
| 485 |
| | 1,067 |
| 970 |
| 521 |
| 534 |
| | 1,042 |
| 1,067 |
|
| Expected return on plan assets | (79 | ) | (70 | ) | | (158 | ) | (140 | ) | (56 | ) | (79 | ) | | (113 | ) | (158 | ) |
| Prior service cost (benefit) | (109 | ) | (107 | ) | | (218 | ) | (214 | ) | (99 | ) | (109 | ) | | (198 | ) | (218 | ) |
| Net loss (gain) | 125 |
| 84 |
| | 250 |
| 168 |
| 54 |
| 125 |
| | 108 |
| 250 |
|
| Net periodic benefit cost | $ | 1,046 |
| $ | 859 |
| | $ | 2,091 |
| $ | 1,718 |
| $ | 992 |
| $ | 1,046 |
| | $ | 1,984 |
| $ | 2,091 |
|
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 June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| Service cost | $ | 609 |
| $ | 878 |
| | $ | 1,436 |
| $ | 907 |
| $ | 435 |
| $ | 609 |
| | $ | 715 |
| $ | 1,436 |
|
| Interest cost | 319 |
| 315 |
| | 638 |
| 629 |
| 292 |
| 319 |
| | 585 |
| 638 |
|
| Prior service cost | — |
| 1 |
| | 1 |
| 1 |
| 1 |
| — |
| | 1 |
| 1 |
|
| Net loss (gain) | 250 |
| 207 |
| | 500 |
| 414 |
| 250 |
| 250 |
| | 500 |
| 500 |
|
| Net periodic benefit cost | $ | 1,178 |
| $ | 1,401 |
| | $ | 2,575 |
| $ | 1,951 |
| $ | 978 |
| $ | 1,178 |
| | $ | 1,801 |
| $ | 2,575 |
|
For the three and six months ended June 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 six months ended June 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 accounts.account. On July 24, 2017,25, 2018, we made contributionsa contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan in the amount of approximately $13 million.Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 20172018 and anticipated contributions for 20172018 and 20182019 are as follows (in thousands):
| | | | Contributions Made | Additional Contributions | Contributions | Contributions Made | Additional Contributions | Contributions |
| | Three Months Ended June 30, 2017 | Six Months Ended June 30, 2017 | Anticipated for 2017 | Anticipated for 2018 | Three Months Ended June 30, 2018 | Six Months Ended June 30, 2018 | Anticipated for 2018 | Anticipated for 2019 |
| Defined Benefit Pension Plan | $ | — |
| $ | — |
| $ | 12,700 |
| $ | 12,700 |
| $ | — |
| $ | — |
| $ | 12,700 |
| $ | 12,700 |
|
| Non-pension Defined Benefit Postretirement Healthcare Plans | $ | 1,270 |
| $ | 2,540 |
| $ | 2,540 |
| $ | 5,115 |
| $ | 1,234 |
| $ | 2,468 |
| $ | 2,468 |
| $ | 4,802 |
|
| Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | $ | 396 |
| $ | 792 |
| $ | 792 |
| $ | 1,682 |
| $ | 343 |
| $ | 686 |
| $ | 686 |
| $ | 1,921 |
|
(1617) 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 20162017 Annual Report on Form 10-K except for those described below.10-K.
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 June 30, 20172018, we were in compliance with the debt covenants.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.
Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of June 30, 2017,2018, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.
(17) IMPAIRMENT OF ASSETS
(18) DISCONTINUED OPERATIONS
Long-lived AssetsResults of operations for discontinued operations have been 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 have also been reclassified to reflect consistency within our condensed consolidated financial statements.
OurOil and Gas Segment
On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by September 30, 2018.
In the process of divesting our Oil and Gas segment, accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject towe performed a ceiling test which limits the pooled costs to the aggregatefair value assessment of the discounted value of future net revenue attributable to proved natural gasassets and crude oil reserves using a discount rate defined by the SEC plusliabilities 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 orto sell. The market valueapproach was based on our recent sales of unevaluatedassets and pending sale transactions of our other properties. Any costs in excess of the ceiling are written off as a non-cash charge.
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 impairmentsfurther adjustments made to the fair value of our held for sale assets at June 30, 2018.
During the six months ended June 30, 2017. In determining2018, we recorded $2.2 million of expenses comprised of royalty payments and reclamation costs related to final closing on the ceiling valuesale of ourBHEP assets, underwhich are presented as Loss on the full cost accounting rulessale of assets in the SEC, we utilizedtable below.
Total assets and liabilities of BHEP at June 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the average ofaccompanying Condensed Consolidated Balance Sheets due to the quoted prices from the first day of each month from the previous 12 months. Atexpected final disposals occurring by September 30, 2018. Held for sale assets and liabilities at June 30, 2017 the average NYMEX natural gas price was $3.01 per Mcf, adjusted to $2.70 per Mcf at the wellhead; the average NYMEX crude oil price was $48.95 per barrel, adjusted to $44.42 per barrel at the wellhead. are classified as current and non-current (in thousands) as of.
|
| | | | | | | | | |
| | June 30, 2018 | December 31, 2017 | June 30, 2017 |
| Other current assets | $ | 378 |
| $ | 10,360 |
| $ | 8,193 |
|
| Derivative assets, current and noncurrent | — |
| — |
| 541 |
|
Deferred income tax assets, noncurrent, net
| — |
| 16,966 |
| 20,654 |
|
| Property, plant and equipment, net | 3,179 |
| 56,916 |
| 93,089 |
|
| Other current liabilities | (4,295 | ) | (18,966 | ) | (10,860 | ) |
| Derivative liabilities, current and noncurrent | — |
| — |
| (44 | ) |
Deferred income tax liabilities, noncurrent, net
| (1,153 | ) | — |
| — |
|
| Other noncurrent liabilities | — |
| (22,808 | ) | (23,048 | ) |
| Net assets (liabilities) | $ | (1,891 | ) | $ | 42,468 |
| $ | 88,525 |
|
At June 30, 2016, the average NYMEX natural gas price was $2.24 per Mcf, adjusted to $1.01 per Mcf at the wellhead; the average NYMEX crude oil price was $43.12 per barrel, adjusted to $37.19 per barrel at the wellhead. During the three2018, December 31, 2017 and six months ended June 30, 2016, we recorded pre-tax non-cash impairments2017, the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties.
BHEP’s other current liabilities at June 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 June 30, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 and June 30, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas assets included in our Oil and Gas segment of $11 million and $25 million, respectively.wells.
DuringOperating results of the second quarter of 2016, in advancing our Oil and Gas strategy, certain non-core assetssegment included in Discontinued operations on the accompanying Condensed Consolidated Statements of Income were identified that are not suitableas follows (in thousands) for inclusion in a possible Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above.period ended:
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2018 | 2017 | | 2018 | 2017 |
| Revenue | $ | 1,284 |
| $ | 6,149 |
| | $ | 5,199 |
| $ | 12,624 |
|
| | | | | | |
| Operations and maintenance | 2,718 |
| 5,491 |
| | 8,407 |
| 12,696 |
|
| Loss (gain) on sale of assets | 1,991 |
| (249 | ) | | 2,203 |
| (249 | ) |
| Depreciation, depletion and amortization | — |
| 1,838 |
| | 1,300 |
| 3,783 |
|
| Total operating expenses | 4,709 |
| 7,080 |
| | 11,910 |
| 16,230 |
|
| | | | | | |
| Operating (loss) | (3,425 | ) | (931 | ) | | (6,711 | ) | (3,606 | ) |
| | | | | | |
| Other income (expense), net | 90 |
| 65 |
| | 119 |
| 138 |
|
| Income tax benefit (expense) | 908 |
| 250 |
| | 1,822 |
| 1,283 |
|
| | | | | | |
| (Loss) from discontinued operations | $ | (2,427 | ) | $ | (616 | ) | | $ | (4,770 | ) | $ | (2,185 | ) |
(18)(19) INCOME TAXES
The effective tax rate differs from the federal statutory rate as follows:
| | | | Three Months Ended June 30, | Three Months Ended June 30, |
| Tax (benefit) expense | 2017 | 2016 | 2018 | 2017 |
| Federal statutory rate | 35.0 | % | 35.0 | % | 21.0 | % | 35.0 | % |
State income tax (net of federal tax effect) (a) | (0.1 | ) | 16.9 |
| 1.7 |
| (0.1 | ) |
| Percentage depletion in excess of cost | (1.2 | ) | (5.9 | ) | (0.4 | ) | (1.2 | ) |
| Accounting for uncertain tax positions adjustment | — |
| 1.9 |
| |
Noncontrolling interest (b) | (3.1 | ) | (25.1 | ) | |
Tax credits (c) | (3.6 | ) | — |
| |
Effective tax rate adjustment (d) | 4.4 |
| 1.7 |
| |
Flow-through adjustments (e) | (2.6 | ) | (10.6 | ) | |
Noncontrolling interest (a) | | (1.0 | ) | (3.1 | ) |
Tax credits (b) | | (2.1 | ) | (3.6 | ) |
Effective tax rate adjustment (c) | | — |
| 4.4 |
|
| Flow-through adjustments | | (0.7 | ) | (2.6 | ) |
TCJA change in estimate (d) | | 0.3 |
| — |
|
AFUDC equity (f) | (0.6 | ) | (5.8 | ) | (0.1 | ) | (0.6 | ) |
| Other tax differences | 0.9 |
| 0.5 |
| 0.7 |
| 0.9 |
|
| | 29.1 | % | 8.6 | % | 19.4 | % | 29.1 | % |
__________
| |
| (a) | In the three months ending June 30, 2017, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies. |
| |
(b) | The adjustment reflects the noncontrollingnon-controlling interest attributable to the sale of 49.9% of the membership interests of Colorado IPPCOIPP LLC in April 2016. |
| |
(c)(b) | The increase in tax credits isare due to Peak View Wind Projectthe production tax credits andfor the marginal gas well tax credit on the oil and gas segment.Peak View wind farm. |
| |
(d)(c) | Adjustment to reflect theour projected annual effective tax rate, pursuant to ASC 740-270. |
| |
(e)(d) | 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 endingended June 30, 2016,2018, certain estimated items associated with the increase in flow-through was primarily attributable to the Section 263A change of accounting method 481(a) adjustment. This change resulted in a basis difference whose tax benefit is flowed through versus being normalized as federal tax depreciation.revaluation have been updated. |
| |
(f) | In the three months ending June 30, 2016, AFUDC equity benefit increased primarily due to the Peak View Wind Project. |
The lower pre-tax income for the second quarter of 2016 caused some of the percentages to not be reflective of the expected impact on full year operating results.
|
| | | | |
| | | |
| | Six Months Ended June 30, |
| Tax (benefit) expense | 2017 | 2016 |
| Federal statutory rate | 35.0 | % | 35.0 | % |
State income tax (net of federal tax effect) (a) | 1.0 |
| 3.8 |
|
Percentage depletion in excess of cost (b) | (0.6 | ) | (13.5 | ) |
Accounting for uncertain tax positions adjustment (c) | — |
| (10.4 | ) |
Noncontrolling interest (d) | (1.6 | ) | (1.9 | ) |
IRC 172(f) carryback claim (e) | (1.3 | ) | — |
|
Tax credits (f) | (1.8 | ) | — |
|
Effective tax rate adjustment (g) | (0.8 | ) | (3.5 | ) |
Flow-through adjustments (h) | (1.0 | ) | (1.7 | ) |
| Transaction costs | — |
| 2.3 |
|
| Other tax differences | 0.4 |
| (0.6 | ) |
| | 29.3 | % | 9.5 | % |
|
| | | | |
| | | |
| | Six Months Ended June 30, |
| Tax (benefit) expense | 2018 | 2017 |
| Federal statutory rate | 21.0 | % | 35.0 | % |
| State income tax (net of federal tax effect) | 1.7 |
| 1.0 |
|
| Percentage depletion in excess of cost | (0.4 | ) | (0.6 | ) |
| Noncontrolling interest | (1.0 | ) | (1.6 | ) |
IRC 172(f) carryback claim (a) | — |
| (1.3 | ) |
| Tax credits | (2.1 | ) | (1.8 | ) |
| Effective tax rate adjustment | — |
| (0.8 | ) |
| Flow-through adjustments | (0.7 | ) | (1.0 | ) |
TCJA change in estimate (b) | 1.6 |
| — |
|
| AFUDC equity | (0.1 | ) | — |
|
Jurisdictional simplification project (c) | (33.7 | ) | — |
|
| Other tax differences | 0.6 |
| 0.4 |
|
| | (13.1 | )% | 29.3 | % |
__________
| |
| (a) | The state income tax expense is lower primarily attributable to favorable flow-through adjustments. |
| |
(b) | The tax benefit forDuring the six months ended June 30, 2016 relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the resultfirst quarter of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. |
| |
(c) | The tax benefit for the six months ended June 30, 2016 relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. |
| |
(d) | Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. |
| |
(e) | In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company'sCompany’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. |
| |
(f)(b) | The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax credits forassets 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 six months ended June 30, 2017 are2018, certain estimated items associated with the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016. revaluation have been updated. |
| |
(g)(c) | Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270. |
| |
(h) | The flow-through adjustments related primarily to an accounting method change for tax purpose that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognitionTax benefit from legal restructuring associated with amortizable goodwill as part of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.ongoing jurisdictional simplification. |
In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatmentTax benefit related to the 2008 IPP Transaction and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 millionlegal restructuring
As part of the liability for unrecognized tax benefits, including interest, duringCompany’s ongoing efforts to continue to integrate the first quarter of 2016. The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilitieslegal entities that the Company has acquired in the first quarter of 2016. The cash taxes due asrecent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to income tax benefit (expense) on the agreement in principleCondensed 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
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. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with IRS Appeals is estimated to be $8.0 million excluding interest.the assumptions made, which could materially change our estimate.
(19)(20) ACCRUED LIABILITIES
The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
| | | | June 30, 2017 | December 31, 2016 | June 30, 2016 | June 30, 2018 | December 31, 2017 | June 30, 2017 |
| Accrued employee compensation, benefits and withholdings | $ | 45,767 |
| $ | 56,926 |
| $ | 45,991 |
| $ | 49,225 |
| $ | 52,467 |
| $ | 44,658 |
|
| Accrued property taxes | 34,683 |
| 40,004 |
| 33,295 |
| 34,664 |
| 42,029 |
| 32,440 |
|
| Customer deposits and prepayments | 41,067 |
| 51,628 |
| 44,200 |
| 36,993 |
| 44,420 |
| 41,068 |
|
| Accrued interest and contract adjustment payments | 33,914 |
| 45,503 |
| 42,330 |
| 33,767 |
| 33,822 |
| 33,914 |
|
| CIAC current portion | 1,575 |
| — |
| 20,211 |
| 1,552 |
| 1,552 |
| 1,575 |
|
| Other (none of which is individually significant) | 44,987 |
| 49,973 |
| 32,223 |
| 34,138 |
| 45,172 |
| 38,151 |
|
| Total accrued liabilities | $ | 201,993 |
| $ | 244,034 |
| $ | 218,250 |
| $ | 190,339 |
| $ | 219,462 |
| $ | 191,806 |
|
| |
| 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 208,500210,000 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.
Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities distribute and transport natural gas through our pipeline network to approximately 1,030,8001,042,000 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.affiliates, on an as available basis.
WeOur Gas Utilities also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 55,00052,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-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 primarily provide appliance repair services to approximately 61,00063,000 and 33,00031,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Power Generation: 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 produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.
OilOur reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and Gas: Our Oilregulation. All of our operations and Gas segment engages inassets are located within the productionUnited States. All of crude oilour non-utility business segments support our utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and natural gas, primarily in the Rocky Mountain region. We are divesting non-core oil and gas assets while retaining those best suited for a possible future cost of service gas program and we have refocused our professional staff on assisting our utilities with the implementation of a cost of service gas program.Other.
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. 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 six months ended June 30, 20172018 and 20162017, and our financial condition as of June 30, 20172018, December 31, 20162017 and June 30, 20162017, 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 7364. |
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 June 30, 20172018 Compared to Three Months Ended June 30, 2016.2017. Net income (loss)from continuing operations available for common stock for the three months ended June 30, 20172018 was $22$24 million, or $0.40$0.45 per diluted share, compared to Net income (loss) available for common stock of $0.7$23 million, or $0.01$0.41 per diluted share, reported for the same period in 2016.2017. The variance to the prior year included the following:
Electric Utilities’ earnings increased $3.1 million driven primarily by recent transmission investments, higher commercial and industrial demand, and favorable weather, partially offset by higher operating expenses;
Gas Utilities’ earnings decreased $0.9 million primarily due to higher operating expenses, partially offset by favorable weather and increased sales of natural gas;
The Mining segment’s earnings increased $0.3 million primarily due to higher sales, partially offset by higher operating expenses; and
Power Generation’s earnings decreased $0.6 million primarily due to higher maintenance expenses.
Net income (loss) available for common stock for the three months ended June 30, 2017 increased over2018 was $22 million, or $0.40 per diluted share, compared to $22 million, or $0.40 per diluted share reported for the same period in 2017. (Loss) from discontinued operations for the prior year primarily duethree months ended June 30, 2018 was $(2.4) million, or $(0.05) per diluted share compared to a decrease$(0.6) million or $(0.01) per diluted share reported for the same period in after-tax impairment charges of approximately $16 million on our oil and gas properties, lower after-tax corporate expenses of approximately $4.1 million primarily due to acquisition and transition costs incurred in the prior year, and higher earnings of $2.0 million at our Mining segment resulting from an increase in tons sold driven by a prior year outage. These are partially offset by lower earnings of $1.3 million at our Gas Utilities.2017.
Six Months Ended June 30, 20172018 Compared to Six Months Ended June 30, 2016.2017. Net income (loss)from continuing operations available for common stock for the six months ended June 30, 20172018 was $99$160 million, or $1.79$2.94 per diluted share, compared to Net income (loss) available for common stock of $41$101 million, or $0.78$1.83 per diluted share, reported for the same period in 2016.2017. The variance to the prior year included the following:
Gas Utilities’ earnings increased $61 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;
Electric Utilities’ earnings increased $0.7 million driven primarily by recent transmission investments, higher commercial and industrial demand, and favorable weather, partially offset by higher operating expenses;
Corporate and other expenses increased $1.8 million primarily due to higher tax benefits recognized in the prior year, partially offset by a reduction in corporate operating expenses; and
Power Generation’s earnings decreased $1.2 million primarily due to lower MWh sold and higher operating expenses.
Net income (loss) available for common stock for the six months ended June 30, 2017 increased over2018 was $155 million, or $2.85 per diluted share, compared to $99 million, or $1.79 per diluted share reported for the same period in the prior year primarily due to higher earnings at our Gas Utilities, Electric Utilities and Mining segments, lower corporate expenses, and a decrease in impairment charges on our oil and gas properties, partially offset by lower earnings at our Power Generation segment and by tax benefits realized during the same period in the prior year.
Net income (loss) available for common stock2017. (Loss) from discontinued operations for the six months ended June 30, 2017 included a $132018 was $(4.8) million, increase in our Gas Utilities’ earnings with a full six months of earnings from our acquired SourceGas utilitiesor $(0.09) per diluted share compared to approximately 4.5 months in the same period of the prior year. Corporate expenses decreased by a total of $22$(2.2) million after-tax compared toor $(0.04) per diluted share reported for the same period in the prior year driven primarily by a $19 million after-tax reduction of acquisition and transition costs. Our Electric Utilities’ earnings increased approximately $2.6 million driven primarily by returns on prior year generation investments. Earnings at our Mining segment increased $1.9 million due to an increase in tons sold as a result of an extended outage in the prior year. The Net income (loss) available for common stock for the six months ended June 30, 2017 is net of $6.7 million of net income attributable to noncontrolling interests compared to $2.7 million in the same period of the prior year. We recognized a $1.4 million tax benefit from a carryback claim during the six months ended June 30, 2017 compared to the same period in the prior year. The prior year included approximately $11 million in tax benefits recognized from additional percentage depletion deductions claimed with respect to our oil and gas properties and the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. The six months ended June 30, 2016 also included non-cash after-tax impairments on our oil and gas properties of $25 million.
2017.
The following table summarizes select financial results by operating segment and details significant items (in thousands):
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| Revenue | | | | | | |
| Revenue | $ | 377,790 |
| $ | 353,849 |
| $ | 23,941 |
| $ | 965,312 |
| $ | 839,563 |
| $ | 125,749 |
|
| Inter-company eliminations | (29,812 | ) | (28,408 | ) | (1,404 | ) | (63,331 | ) | (64,163 | ) | 832 |
|
| | $ | 347,978 |
| $ | 325,441 |
| $ | 22,537 |
| $ | 901,981 |
| $ | 775,400 |
| $ | 126,581 |
|
| | | | | | | |
| Net income (loss) available for common stock | | | | | | |
| Electric Utilities | $ | 18,832 |
| $ | 19,229 |
| $ | (397 | ) | $ | 41,062 |
| $ | 38,444 |
| $ | 2,618 |
|
| Gas Utilities | (272 | ) | 987 |
| (1,259 | ) | 45,738 |
| 32,914 |
| 12,824 |
|
Power Generation (a) | 5,332 |
| 5,683 |
| (351 | ) | 11,862 |
| 14,265 |
| (2,403 | ) |
| Mining | 2,681 |
| 724 |
| 1,957 |
| 5,571 |
| 3,662 |
| 1,909 |
|
Oil and Gas (b) (c) | (1,946 | ) | (19,424 | ) | 17,478 |
| (4,897 | ) | (26,448 | ) | 21,551 |
|
| | 24,627 |
| 7,199 |
| 17,428 |
| 99,336 |
| 62,837 |
| 36,499 |
|
| | | | | | | |
Corporate activities and eliminations (d) (e) | (2,432 | ) | (6,530 | ) | 4,098 |
| (618 | ) | (22,166 | ) | 21,548 |
|
| | | | | | | |
| Net income (loss) available for common stock | $ | 22,195 |
| $ | 669 |
| $ | 21,526 |
| $ | 98,718 |
| $ | 40,671 |
| $ | 58,047 |
|
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| Revenue | | | | | | |
| Revenue | $ | 390,019 |
| $ | 371,641 |
| $ | 18,378 |
| $ | 1,001,149 |
| $ | 952,688 |
| $ | 48,461 |
|
| Inter-company eliminations | (34,315 | ) | (29,812 | ) | (4,503 | ) | (70,056 | ) | (63,331 | ) | (6,725 | ) |
| | $ | 355,704 |
| $ | 341,829 |
| $ | 13,875 |
| $ | 931,093 |
| $ | 889,357 |
| $ | 41,736 |
|
| Net income (loss) from continuing operations available for common stock | | | | | | |
Electric Utilities (b) | $ | 21,890 |
| $ | 18,832 |
| $ | 3,058 |
| $ | 41,735 |
| $ | 41,062 |
| $ | 673 |
|
Gas Utilities (a) | (1,161 | ) | (272 | ) | (889 | ) | 106,459 |
| 45,738 |
| 60,721 |
|
Power Generation (b) | 4,772 |
| 5,332 |
| (560 | ) | 10,628 |
| 11,862 |
| (1,234 | ) |
Mining (b) | 3,005 |
| 2,681 |
| 324 |
| 5,989 |
| 5,571 |
| 418 |
|
| | 28,506 |
| 26,573 |
| 1,933 |
| 164,811 |
| 104,233 |
| 60,578 |
|
Corporate and Other (b) | (4,162 | ) | (3,762 | ) | (400 | ) | (5,120 | ) | (3,330 | ) | (1,790 | ) |
| Net income from continuing operations | 24,344 |
| 22,811 |
| 1,533 |
| 159,691 |
| 100,903 |
| 58,788 |
|
| (Loss) from discontinued operations, net of tax | (2,427 | ) | (616 | ) | (1,811 | ) | (4,770 | ) | (2,185 | ) | (2,585 | ) |
| Net income available for common stock | $ | 21,917 |
| $ | 22,195 |
| $ | (278 | ) | $ | 154,921 |
| $ | 98,718 |
| $ | 56,203 |
|
__________
| |
| (a) | Net income (loss) availablefrom continuing operations for common stock for the three and six months ended June 30, 2017 is net2018 included a $49 million tax benefit resulting fromlegal entity restructuring. See Note 19 of net income attributablethe Notes to noncontrolling interest of $3.1 million and $6.6 million, respectively, and $2.6 millionCondensed Consolidated Financial Statements for both the three and six months ended June 30, 2016.more information. |
| |
| (b) | Net income (loss) available for common stock for the three and six months ended June 30, 2016 included non-cash after-tax impairments of our oil and gas properties of $16 million and $25 million. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
| |
(c) | Net income (loss) available for common stockfrom continuing operations for the six months ended June 30, 20162018 included aapproximately $2.3 million of income tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior tax years. |
| |
(d) | Net income (loss) available for common stock for the three and six months ended June 30, 2017 included incremental, non-recurring acquisition costs, after-tax of $0.3 million and $1.2 million, respectively, as compared to $4.1 million and $20 million for the same periods in the prior year. The three and six months ended June 30, 2016 also included after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million, respectively. |
| |
(e) | Net income (loss) available for common stock for the six months ended June 30, 2017 included a net tax benefit of approximately $1.4 million from a carryback claim for specified liability losses involving prior tax years. Net income (loss) available for common stock for the six months ended June 30, 2016 included tax benefits of approximately $4.4 millionexpense recorded primarily as a result of the re-measurement of the liability for uncertainan increase to a valuation allowance associated with tax positions predicated on an agreement reached with IRS Appealsreform related changes in early 2016. See Note 18 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.estimated future taxable income. The impact to our operating segments and Corporate and Other was: Electric Utilities $0.4 million; Mining $0.5 million; Power Generation $0.7 million; and Corporate and Other $0.7 million. |
Overview of Business Segments and Corporate Activity
Electric Utilities Segment
Electric Utilities experienced milderhotter summer weather during the three and six months ended June 30, 20172018 compared to the three and six months ended June 30, 2016.2017. Cooling degree days for the three and six months ended June 30, 20172018 were 14%109% higher than normalthe 30-year average (normal) compared to 68%14% higher than normal for the same periods in 2016. Compared to the same periods in the prior year, cooling degree days were 38% lower. 2017.
Heating degree days for the three and six months ended June 30, 20172018 were 12% lower and 7% higher than normal compared to 9% and 11% lower than normal, respectively, compared to 14% and 13% lower than normal for the same periods in 2017.
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 January 17, 2017,April 25, 2018, Colorado Electric received approval from the CPUC for a settlement agreement of its electric resource plan which provides for the addition ofto contract with Black Hills Electric Generation to purchase 60 megawatts of wind energy through a 25-year power purchase agreement. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.
On July 25, 2018, South Dakota Electric placed in service the first 48-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The remaining segment is expected to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarterend of 2017, Colorado Electric issued a request for proposals to construct new generation and plans to present the results to the CPUC by year-end.2019.
On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver District Court on July 10, 2017.
Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.
On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.
Gas Utilities Segment
Rate Review updates:
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We expect 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, will be 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.
Arkansas Gas filed a rate review in December 2017 with the APSC requesting $30 million of annual revenue to recover more than $160 million of new infrastructure investment. The revenue request was subsequently adjusted to $19 million primarily related to a lower corporate income tax rate of 21%. The APSC previously issued a procedural schedule for the rate review. To date, testimony has been filed by the intervenors and Arkansas Gas filed rebuttal testimony on June 26, 2018. The APSC issued an order on July 26 requiring investor owned utilities to provide within 30 days their plans to return tax reform benefits to customers. Arkansas Gas is reviewing the order and its impacts to customers and may amend its current rate review if necessary. A final order and new rates are expected to be effective in the fourth quarter of 2018.
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 to continue to integrate thelegal entities that the Company has acquired in recent years. As a result of these transactions, additional deferred income tax assets of $49 million, related to goodwill that is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Condensed Consolidated Statements of Income.
Gas Utilities experienced slightly colder winter and spring weather during the three and six months ended June 30, 20172018 compared to the three and six months ended June 30, 2016.2017. Heating degree days for the three and six months ended June 30, 20172018 were 1% lower and 1% higher than the 30-year average (normal) compared to 9% and 12% lower than normal, respectively, compared to 17% and 20% lower than normal for the same periods in 2016.2017.
Oil and Gas SegmentPower Generation
Oil and Gas production volumes decreased 23% and 22% forOn April 25, 2018, Black Hills Electric Generation was selected to provide 60 megawatts of renewable energy to Colorado Electric from a new wind project through a 25-year power purchase agreement. The $71 million Busch Ranch II wind project is expected to be in service by the three and six months ended June 30, 2017 compared to the same periods in 2016, respectively. The decrease in production was due to the 2016 salesend of non-core properties, and limiting natural gas production to meet minimum daily quantity contractual gas processing commitments in the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for natural gas increased 68% and 48% for the three and six months ended June 30, 2017 compared to the same periods in 2016, respectively. The average hedged price received for oil decreased 25% and 15% for the three and six months ended June 30, 2017 compared to the same periods in 2016, respectively.
2019.
Corporate Activities
We utilized favorable short-term borrowings from our CP program to pay down $100 million on a Corporate term loan due in 2019 with principal payments of $50 million paid in May and an additional $50 million paid in July.Other
On July 21, 2017,30, 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 June 30, 2018, matures on July 30, 2020.
On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.
On March 8, 2018, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.revised the outlook to Positive.
Discontinued Operations
On March 29,November 1, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ ratingthe BHC Board of Directors approved a complete divestiture of our Oil and changed its outlook from NegativeGas segment. As of June 30, 2018, we have sold nearly all oil and gas assets. Transaction closing for the last few assets and final accounting are expected within the third quarter. The closing of the oil and gas office will occur in August. See Note 18 of the Notes to Stable, citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.
Condensed Consolidated Financial Statements for more information.
Operating Results
A discussion of operating results from our segments and Corporate activities follows. 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 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 June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) | (in thousands) |
Revenue | $ | 168,453 |
| $ | 161,481 |
| $ | 6,972 |
| $ | 344,477 |
| $ | 328,757 |
| $ | 15,720 |
| $ | 173,616 |
| $ | 168,453 |
| $ | 5,163 |
| $ | 347,171 |
| $ | 344,477 |
| $ | 2,694 |
|
| | | |
| Total fuel and purchased power | 62,265 |
| 61,418 |
| 847 |
| 130,665 |
| 127,524 |
| 3,141 |
| 64,283 |
| 62,265 |
| 2,018 |
| 131,406 |
| 130,665 |
| 741 |
|
| | | |
Gross margin | 106,188 |
| 100,063 |
| 6,125 |
| 213,812 |
| 201,233 |
| 12,579 |
| 109,333 |
| 106,188 |
| 3,145 |
| 215,765 |
| 213,812 |
| 1,953 |
|
| | | |
| Operations and maintenance | 44,315 |
| 38,879 |
| 5,436 |
| 85,098 |
| 78,204 |
| 6,894 |
| 45,101 |
| 44,315 |
| 786 |
| 90,194 |
| 85,098 |
| 5,096 |
|
| Depreciation and amortization | 23,120 |
| 20,473 |
| 2,647 |
| 45,981 |
| 41,731 |
| 4,250 |
| 24,640 |
| 23,120 |
| 1,520 |
| 49,153 |
| 45,981 |
| 3,172 |
|
| Total operating expenses | 67,435 |
| 59,352 |
| 8,083 |
| 131,079 |
| 119,935 |
| 11,144 |
| 69,741 |
| 67,435 |
| 2,306 |
| 139,347 |
| 131,079 |
| 8,268 |
|
| | | |
| Operating income | 38,753 |
| 40,711 |
| (1,958 | ) | 82,733 |
| 81,298 |
| 1,435 |
| 39,592 |
| 38,753 |
| 839 |
| 76,418 |
| 82,733 |
| (6,315 | ) |
| | | |
| Interest expense, net | (12,893 | ) | (12,131 | ) | (762 | ) | (26,305 | ) | (24,630 | ) | (1,675 | ) | (13,209 | ) | (12,893 | ) | (316 | ) | (26,500 | ) | (26,305 | ) | (195 | ) |
| Other income (expense), net | 590 |
| 838 |
| (248 | ) | 930 |
| 1,493 |
| (563 | ) | (490 | ) | 590 |
| (1,080 | ) | (671 | ) | 930 |
| (1,601 | ) |
| Income tax benefit (expense) | (7,618 | ) | (10,189 | ) | 2,571 |
| (16,296 | ) | (19,717 | ) | 3,421 |
| (4,003 | ) | (7,618 | ) | 3,615 |
| (7,512 | ) | (16,296 | ) | 8,784 |
|
| Net income | $ | 18,832 |
| $ | 19,229 |
| $ | (397 | ) | $ | 41,062 |
| $ | 38,444 |
| $ | 2,618 |
| $ | 21,890 |
| $ | 18,832 |
| $ | 3,058 |
| $ | 41,735 |
| $ | 41,062 |
| $ | 673 |
|
________________
| |
| (a) | The three and six months ended June 30, 2018 include Horizon Point shared facility revenues of approximately $2.7 million and $5.3 million, respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement has no impact on BHC’s consolidated operating results. |
Results of Operations for the Electric Utilities for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 20162017: Net income from continuing operations available for common stock for the Electric Utilities was $19$22 million for the three months ended June 30, 20172018, compared to Net income from continuing operations available for common stock of $19 million for the three months ended June 30, 20162017, as a result of:
Gross margin increased primarily due to a $2.3 million return on investment from the Peak View Wind Project, a $1.9$1.7 million increase in commercial and industrialresidential margins driven by increased demand largely associated with data centersfrom warmer weather in Cheyenne, Wyoming, a $1.6 million increase due to priorthe current year, billing true-ups, and a $1.5 million increase inhigher rider revenues of $2.3 million primarily related to transmission investment recovery. Partially offsetting theserecovery, higher commercial and industrial demand of $1.1 million and higher non-energy revenue of $2.9 million primarily from Horizon Point shared facility revenue (this shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results). These increases was $1.2were partially offset by a $5.3 million inreserve to revenue to reflect the lower residential margins driven primarily by lower cooling degree days as compared to prior year. Cooling degree days were 14 percent higher than normal infederal income tax rate from the current year as compared to 68 percent higher than normal for the same period in the prior year.TCJA on our existing rate tariffs.
Operations and maintenance increased primarily due to $1.7 millionhigher facility costs of higher employee costs as a result of prior year integration activities and transition expenses charged to the Corporate segment. Generation outage-related expenses increased by $1.3 million, due to the timing of current year outagespartially offset by lower vegetation management expenses compared to the same period in the prior year and operating expenses increased $0.5 million from the addition of the Peak View Wind Project and the 40-megawatt gas turbine at the Pueblo Airport Generating Station. Property taxes associated with increased asset base increased $0.7 million. A variety of smaller items contributed to the remainder of the increase.year.
Depreciation and amortization increased primarily due to a higher asset base driven by the additionprior year additions of the Peak View Wind ProjectHorizon Point and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.Teckla-Lange transmission line.
Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments as compared to prior year.
Other income (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 was lower thandecreased from the prior year due primarily to wind production tax credits related to the Peak View Wind Project.reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
Results of Operations for the Electric Utilities for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 20162017: Net income from continuing operations available for common stock for the Electric Utilities was $42 million for the six months ended June 30, 2018, compared to Net income from continuing operations available for common stock of $41 million for the six months ended June 30, 2017, compared to Net income available for common stock of $38 million for the six months ended June 30, 2016, as a result of:
Gross margin increased over the prior year reflectingprimarily due to a $4.5 million return on investment from the Peak View Wind Project, a $3.7$3.3 million increase in commercial and industrialresidential margins driven by increased demand largely associated with data centersfrom favorable weather in Cheyenne, Wyoming, a $2.9 million increase inthe current year, higher rider revenues of $3.5 million primarily related to transmission investment recovery, higher commercial and a $1.5industrial demand of $0.6 million increase dueand higher non-energy revenue of $5.7 million primarily from Horizon Point shared facility revenue (this shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results). These increases were partially offset by an $11 million reserve to a prior year billing true-up.revenue to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs.
Operations and maintenance increased primarily due to $4.6$2.1 million of higher vegetation management expenses and $2.6 million of shared facility costs. Higher employee costs as a resultand property taxes comprise the remainder of prior year integration activities and transition expenses chargedthe increase compared to the Corporate segment, $1.4 million of higher property taxes with increased asset base, and $1.0 million of higher operating expenses fromsame period in the Peak View Wind Project and Pueblo Airport Generating Station gas turbine additions.prior year.
Depreciation and amortization increased primarily due to a higher asset base driven by the additionprior year additions of the Peak View Wind ProjectHorizon Point and the 40-megawatt gas turbine at the Pueblo Airport Generating Station.Teckla-Lange transmission line.
Interest expense, net increased primarily duewas comparable to higher intercompany debt resulting from additional investments as compared tothe same period in the prior year.
Other income (expense), net was comparabledecreased due to the same periodpresentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year.year AFUDC associated with higher prior year capital spend.
Income tax benefit (expense): The effective tax rate was lower thandecreased from the prior year due primarily to wind production tax credits related to the Peak View Wind Project.reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
Operating Statistics
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| Revenue - Electric (in thousands) | 2017 | | 2016 | | 2017 | | 2016 |
| Residential: | | | | | | | |
| South Dakota Electric | $ | 15,633 |
| | $ | 16,241 |
| | $ | 35,704 |
| | $ | 35,556 |
|
| Wyoming Electric | 9,077 |
| | 9,241 |
| | 19,488 |
| | 19,698 |
|
| Colorado Electric | 23,223 |
| | 23,148 |
| | 46,959 |
| | 46,261 |
|
| Total Residential | 47,933 |
| | 48,630 |
| | 102,151 |
| | 101,515 |
|
| | | | | | | | |
| Commercial: | | | | | | | |
| South Dakota Electric | 22,858 |
| | 23,723 |
| | 47,149 |
| | 47,312 |
|
| Wyoming Electric | 16,205 |
| | 15,839 |
| | 32,176 |
| | 31,512 |
|
| Colorado Electric | 24,875 |
| | 24,392 |
| | 48,126 |
| | 46,875 |
|
| Total Commercial | 63,938 |
| | 63,954 |
| | 127,451 |
| | 125,699 |
|
| | | | | | | | |
| Industrial: | | | | | | | |
| South Dakota Electric | 8,171 |
| | 7,764 |
| | 16,625 |
| | 16,265 |
|
| Wyoming Electric | 12,831 |
| | 10,352 |
| | 25,633 |
| | 20,449 |
|
| Colorado Electric | 9,734 |
| | 9,782 |
| | 18,761 |
| | 19,047 |
|
| Total Industrial | 30,736 |
| | 27,898 |
| | 61,019 |
| | 55,761 |
|
| | | | | | | | |
| Municipal: | | | | | | | |
| South Dakota Electric | 942 |
| | 960 |
| | 1,778 |
| | 1,791 |
|
| Wyoming Electric | 543 |
| | 552 |
| | 1,046 |
| | 1,063 |
|
| Colorado Electric | 3,191 |
| | 2,885 |
| | 6,152 |
| | 5,580 |
|
| Total Municipal | 4,676 |
| | 4,397 |
| | 8,976 |
| | 8,434 |
|
| | | | | | | | |
| Total Retail Revenue - Electric | 147,283 |
| | 144,879 |
| | 299,597 |
| | 291,409 |
|
| | | | | | | | |
| Contract Wholesale: | | | | | | | |
Total Contract Wholesale - South Dakota Electric (a) | 6,702 |
| | 3,947 |
| | 14,545 |
| | 8,121 |
|
| | | | | | | | |
| Off-system Wholesale: | | | | | | | |
| South Dakota Electric | 2,424 |
| | 2,734 |
| | 6,257 |
| | 7,320 |
|
| Wyoming Electric | 1,081 |
| | 1,007 |
| | 2,747 |
| | 2,853 |
|
| Colorado Electric | 163 |
| | 573 |
| | 174 |
| | 707 |
|
| Total Off-system Wholesale | 3,668 |
| | 4,314 |
| | 9,178 |
| | 10,880 |
|
| | | | | | | | |
| Other Revenue: | | | | | | | |
| South Dakota Electric | 9,322 |
| | 6,650 |
| | 17,788 |
| | 14,296 |
|
| Wyoming Electric | 614 |
| | 520 |
| | 1,539 |
| | 1,110 |
|
| Colorado Electric | 864 |
| | 1,171 |
| | 1,830 |
| | 2,941 |
|
| Total Other Revenue | 10,800 |
| | 8,341 |
| | 21,157 |
| | 18,347 |
|
| | | | | | | | |
| Total Revenue - Electric | $ | 168,453 |
| | $ | 161,481 |
| | $ | 344,477 |
| | $ | 328,757 |
|
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Electric Revenue (in thousands) | | Quantities sold (MWh) |
| | | Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 |
| Residential | | $ | 50,116 |
| $ | 47,933 |
| $ | 105,857 |
| $ | 102,151 |
| | 328,638 |
| 306,866 |
| 711,908 |
| 668,971 |
|
| Commercial | | 64,902 |
| 63,938 |
| 126,886 |
| 127,451 |
| | 509,984 |
| 485,205 |
| 1,010,120 |
| 989,279 |
|
| Industrial | | 31,220 |
| 30,736 |
| 62,020 |
| 61,019 |
| | 418,596 |
| 394,796 |
| 819,305 |
| 785,370 |
|
| Municipal | | 4,666 |
| 4,676 |
| 8,807 |
| 8,976 |
| | 42,657 |
| 40,704 |
| 78,981 |
| 77,676 |
|
| Subtotal Retail Revenue - Electric | | 150,904 |
| 147,283 |
| 303,570 |
| 299,597 |
| | 1,299,875 |
| 1,227,571 |
| 2,620,314 |
| 2,521,296 |
|
| Contract Wholesale | | 8,191 |
| 6,702 |
| 17,241 |
| 14,545 |
| | 218,132 |
| 165,881 |
| 455,836 |
| 351,997 |
|
| Off-system/Power Marketing Wholesale | | 4,939 |
| 3,668 |
| 9,083 |
| 9,178 |
| | 178,854 |
| 130,423 |
| 307,895 |
| 317,858 |
|
| Other | | 9,582 |
| 10,800 |
| 17,277 |
| 21,157 |
| | — |
| — |
| — |
| — |
|
| Total Revenue and Energy Sold | | 173,616 |
| 168,453 |
| 347,171 |
| 344,477 |
| | 1,696,861 |
| 1,523,875 |
| 3,384,045 |
| 3,191,151 |
|
| Other Uses, Losses or Generation, net | | — |
| — |
| — |
| — |
| | 125,606 |
| 116,642 |
| 216,461 |
| 219,977 |
|
| Total Revenue and Energy | | 173,616 |
| 168,453 |
| 347,171 |
| 344,477 |
| | 1,822,467 |
| 1,640,517 |
| 3,600,506 |
| 3,411,128 |
|
| Less cost of fuel and purchased power | | 64,283 |
| 62,265 |
| 131,406 |
| 130,665 |
| | | | | |
Gross Margin (a) | | $ | 109,333 |
| $ | 106,188 |
| $ | 215,765 |
| $ | 213,812 |
| | | | | |
__________________________
| |
| (a) | Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.Non-GAAP measure |
|
| | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| Quantities Generated and Purchased (in MWh) | 2017 | | 2016 | | 2017 | | 2016 |
| Generated — | | | | | | | |
| Coal-fired: | | | | | | | |
| South Dakota Electric | 289,540 |
| | 265,032 |
| | 677,525 |
| | 653,033 |
|
| Wyoming Electric | 176,725 |
| | 180,081 |
| | 360,820 |
| | 359,774 |
|
| Total Coal-fired | 466,265 |
| | 445,113 |
| | 1,038,345 |
| | 1,012,807 |
|
| | | | | | | | |
| Natural Gas and Oil: | | | | | | | |
South Dakota Electric (a) | 11,024 |
| | 39,433 |
| | 21,374 |
| | 54,995 |
|
Wyoming Electric (a) | 7,292 |
| | 27,191 |
| | 13,569 |
| | 35,070 |
|
| Colorado Electric | 45,755 |
| | 61,123 |
| | 57,657 |
| | 63,890 |
|
| Total Natural Gas and Oil | 64,071 |
| | 127,747 |
| | 92,600 |
| | 153,955 |
|
| | | | | | | | |
| Wind: | | | | | | | |
Colorado Electric (b) | 58,113 |
| | 10,588 |
| | 128,656 |
| | 23,649 |
|
| Total Wind | 58,113 |
| | 10,588 |
| | 128,656 |
| | 23,649 |
|
| | | | | | | | |
| Total Generated: | | | | | | | |
| South Dakota Electric | 300,564 |
| | 304,465 |
| | 698,899 |
| | 708,028 |
|
Wyoming Electric (a) | 184,017 |
| | 207,272 |
| | 374,389 |
| | 394,844 |
|
Colorado Electric (b) | 103,868 |
| | 71,711 |
| | 186,313 |
| | 87,539 |
|
| Total Generated | 588,449 |
| | 583,448 |
| | 1,259,601 |
| | 1,190,411 |
|
| | | | | | | | |
| Purchased — | | | | | | | |
South Dakota Electric (c) | 418,314 |
| | 315,379 |
| | 865,811 |
| | 655,069 |
|
Wyoming Electric (d) | 239,140 |
| | 186,085 |
| | 488,675 |
| | 408,880 |
|
Colorado Electric (b) | 394,614 |
| | 467,365 |
| | 797,041 |
| | 945,248 |
|
| Total Purchased | 1,052,068 |
| | 968,829 |
| | 2,151,527 |
| | 2,009,197 |
|
| | | | | | | | |
| Total Generated and Purchased: | | | | | | | |
South Dakota Electric (c) | 718,878 |
| | 619,844 |
| | 1,564,710 |
| | 1,363,097 |
|
| Wyoming Electric | 423,157 |
| | 393,357 |
| | 863,064 |
| | 803,724 |
|
| Colorado Electric | 498,482 |
| | 539,076 |
| | 983,354 |
| | 1,032,787 |
|
| Total Generated and Purchased | 1,640,517 |
| | 1,552,277 |
| | 3,411,128 |
| | 3,199,608 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Electric Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Quantities Sold (MWh) (b) |
| | | 2018 | 2017 | | 2018 | 2017 | | 2018 | 2017 |
| South Dakota Electric | | $ | 70,676 |
| $ | 66,052 |
| | $ | 49,922 |
| $ | 47,441 |
| | 837,943 |
| 718,878 |
|
| Wyoming Electric | | 40,408 |
| 40,351 |
| | 21,951 |
| 22,439 |
| | 441,996 |
| 423,157 |
|
| Colorado Electric | | 62,532 |
| 62,050 |
| | 37,460 |
| 36,308 |
| | 542,528 |
| 498,482 |
|
| Total Electric Revenue, Gross Margin, and Quantities Sold | | $ | 173,616 |
| $ | 168,453 |
| | $ | 109,333 |
| $ | 106,188 |
| | 1,822,467 |
| 1,640,517 |
|
________________
| |
| (b) | Total MWh includes Other Uses, Losses or Generation, net, which are approximately 7%, 6%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively. |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Six Months Ended June 30, | | Electric Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Quantities Sold (MWh) (b) |
| | | 2018 | 2017 | | 2018 | 2017 | | 2018 | 2017 |
| South Dakota Electric | | $ | 144,491 |
| $ | 139,846 |
| | $ | 101,298 |
| $ | 98,086 |
| | 1,666,120 |
| 1,564,710 |
|
| Wyoming Electric | | 81,795 |
| 82,629 |
| | 43,646 |
| 45,225 |
| | 904,858 |
| 863,064 |
|
| Colorado Electric | | 120,885 |
| 122,002 |
| | 70,821 |
| 70,501 |
| | 1,029,528 |
| 983,354 |
|
| Total Electric Revenue, Gross Margin, and Quantities Sold | | $ | 347,171 |
| $ | 344,477 |
| | $ | 215,765 |
| $ | 213,812 |
| | 3,600,506 |
| 3,411,128 |
|
________________
| |
| (b) | Total MWh includes Other Uses, Losses or Generation, net, which are approximately 5%, 6%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively. |
|
| | | | | | | | |
| | Three Months Ended
June 30, | Six Months Ended
June 30, |
| Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2018 | 2017 |
| | | | | |
| Coal-fired | 568,733 |
| 466,265 |
| 1,164,333 |
| 1,038,345 |
|
| Natural Gas and Oil | 105,304 |
| 64,071 |
| 146,627 |
| 92,600 |
|
| Wind | 68,501 |
| 58,113 |
| 142,482 |
| 128,656 |
|
| Total Generated | 742,538 |
| 588,449 |
| 1,453,442 |
| 1,259,601 |
|
| Purchased | 1,079,929 |
| 1,052,068 |
| 2,147,064 |
| 2,151,527 |
|
| Total Generated and Purchased | 1,822,467 |
| 1,640,517 |
| 3,600,506 |
| 3,411,128 |
|
|
| | | | | | | | |
| | Three Months Ended
June 30, | Six Months Ended
June 30, |
| Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2018 | 2017 |
| Generated: | | | | |
| South Dakota Electric | 411,839 |
| 300,564 |
| 824,033 |
| 698,899 |
|
| Wyoming Electric | 197,772 |
| 184,017 |
| 404,434 |
| 374,389 |
|
| Colorado Electric | 132,927 |
| 103,868 |
| 224,975 |
| 186,313 |
|
| Total Generated | 742,538 |
| 588,449 |
| 1,453,442 |
| 1,259,601 |
|
| Purchased: | | | | |
| South Dakota Electric | 426,104 |
| 418,314 |
| 842,087 |
| 865,811 |
|
| Wyoming Electric | 244,224 |
| 239,140 |
| 500,424 |
| 488,675 |
|
| Colorado Electric | 409,601 |
| 394,614 |
| 804,553 |
| 797,041 |
|
| Total Purchased | 1,079,929 |
| 1,052,068 |
| 2,147,064 |
| 2,151,527 |
|
| | | | | |
| Total Generated and Purchased | 1,822,467 |
| 1,640,517 |
| 3,600,506 |
| 3,411,128 |
|
|
| | | | | | | | | | | | | |
| | Three Months Ended June 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 | 1,037 |
| | 1 | % | | 14% | | 910 |
| | (11 | )% |
| Wyoming Electric | 1,053 |
| | (14 | )% | | (10)% | | 1,164 |
| | (5 | )% |
| Colorado Electric | 460 |
| | (27 | )% | | (19)% | | 567 |
| | (10 | )% |
Combined (a) | 777 |
| | (12 | )% | | (3)% | | 804 |
| | (9 | )% |
| | | | | | | | | | |
| Cooling Degree Days: | | | | | | | | | |
| South Dakota Electric | 132 |
| | 33 | % | | 16% | | 114 |
| | 15 | % |
| Wyoming Electric | 102 |
| | 104 | % | | 149% | | 41 |
| | (18 | )% |
| Colorado Electric | 494 |
| | 136 | % | | 103% | | 243 |
| | 16 | % |
Combined (a) | 292 |
| | 109 | % | | 85% | | 158 |
| | 14 | % |
__________
| |
| (a) | Decrease is primarily due toCombined actuals are calculated based on the ability to purchase excess generation in the open market at a lower cost than to generate for the three and six months ended June 30, 2017.weighted average number of total customers by state. |
| |
(b) | Increase in 2017 is due to the addition of the Peak View Wind Project in November 2016. This generation replaced resources provided by PPAs in 2016. |
| |
(c) | Increase in 2017 is primarily driven by resource needs from a new 50MW power sales agreement with Cargill effective January 1, 2017. |
| |
(d) | Year over year increases are primarily driven by new load supporting data centers in Cheyenne, Wyoming. |
|
| | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| Quantity Sold (in MWh) | 2017 | 2016 | | 2017 | 2016 |
| Residential: | | | | | |
| South Dakota Electric | 107,521 |
| 114,851 |
| | 257,093 |
| 257,604 |
|
| Wyoming Electric | 57,191 |
| 59,587 |
| | 124,364 |
| 127,900 |
|
| Colorado Electric | 142,154 |
| 144,318 |
| | 287,514 |
| 293,346 |
|
| Total Residential | 306,866 |
| 318,756 |
| | 668,971 |
| 678,850 |
|
| | | | | | |
| Commercial: | | | | | |
| South Dakota Electric | 173,720 |
| 190,207 |
| | 370,126 |
| 379,095 |
|
| Wyoming Electric | 128,827 |
| 130,550 |
| | 261,009 |
| 260,880 |
|
| Colorado Electric | 182,658 |
| 184,150 |
| | 358,144 |
| 360,346 |
|
| Total Commercial | 485,205 |
| 504,907 |
| | 989,279 |
| 1,000,321 |
|
| | | | | | |
| Industrial: | | | | | |
| South Dakota Electric | 103,497 |
| 102,620 |
| | 213,293 |
| 210,641 |
|
Wyoming Electric (a) | 184,809 |
| 150,332 |
| | 362,796 |
| 293,074 |
|
| Colorado Electric | 106,490 |
| 113,454 |
| | 209,281 |
| 212,943 |
|
| Total Industrial | 394,796 |
| 366,406 |
| | 785,370 |
| 716,658 |
|
| | | | | | |
| Municipal: | | | | | |
| South Dakota Electric | 8,104 |
| 8,487 |
| | 15,709 |
| 15,928 |
|
| Wyoming Electric | 2,006 |
| 2,102 |
| | 4,489 |
| 4,647 |
|
| Colorado Electric | 30,594 |
| 30,026 |
| | 57,478 |
| 56,609 |
|
| Total Municipal | 40,704 |
| 40,615 |
| | 77,676 |
| 77,184 |
|
| | | | | | |
| Total Retail Quantity Sold | 1,227,571 |
| 1,230,684 |
| | 2,521,296 |
| 2,473,013 |
|
| | | | | | |
| Contract Wholesale: | | | | | |
Total Contract Wholesale-South Dakota Electric (b) | 165,881 |
| 56,087 |
| | 351,997 |
| 119,540 |
|
| | | | | | |
| Off-system Wholesale: | | | | | |
South Dakota Electric (c) | 102,966 |
| 117,064 |
| | 257,462 |
| 310,437 |
|
| Wyoming Electric | 22,183 |
| 21,253 |
| | 54,536 |
| 58,746 |
|
Colorado Electric (c) | 5,274 |
| 28,233 |
| | 5,860 |
| 35,695 |
|
| Total Off-system Wholesale | 130,423 |
| 166,550 |
| | 317,858 |
| 404,878 |
|
| | | | | | |
| Total Quantity Sold: | | | | | |
| South Dakota Electric | 661,689 |
| 589,316 |
| | 1,465,680 |
| 1,293,245 |
|
| Wyoming Electric | 395,016 |
| 363,824 |
| | 807,194 |
| 745,247 |
|
| Colorado Electric | 467,170 |
| 500,181 |
| | 918,277 |
| 958,939 |
|
| Total Quantity Sold | 1,523,875 |
| 1,453,321 |
| | 3,191,151 |
| 2,997,431 |
|
| | | | | | |
Other Uses, Losses or Generation, net (d): | | | | | |
| South Dakota Electric | 57,189 |
| 30,528 |
| | 99,030 |
| 69,852 |
|
| Wyoming Electric | 28,141 |
| 29,533 |
| | 55,870 |
| 58,477 |
|
| Colorado Electric | 31,312 |
| 38,895 |
| | 65,077 |
| 73,848 |
|
| Total Other Uses, Losses and Generation, net | 116,642 |
| 98,956 |
| | 219,977 |
| 202,177 |
|
| | | | | | |
| Total Energy | 1,640,517 |
| 1,552,277 |
| | 3,411,128 |
| 3,199,608 |
|
__________
(a) Year over year increases are driven by new load supporting data centers in Cheyenne, Wyoming.
| |
(b) | Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017. |
| |
(c) | Decrease in 2017 generation was primarily driven by commodity prices that impacted power marketing sales. |
| |
(d) | Includes company uses, line losses, and excess exchange production. |
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, |
| Degree Days | | | 2017 | | | | 2016 |
| | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
| Heating Degree Days: | | | | | | | | | |
| South Dakota Electric | 910 |
| | (11 | )% | | 4% | | 877 |
| | (13 | )% |
| Wyoming Electric | 1,164 |
| | (5 | )% | | 3% | | 1,134 |
| | (15 | )% |
| Colorado Electric | 567 |
| | (10 | )% | | 10% | | 516 |
| | (15 | )% |
Combined (a) | 804 |
| | (9 | )% | | 6% | | 762 |
| | (14 | )% |
| | | | | | | | | | |
| Cooling Degree Days: | | | | | | | | | |
| South Dakota Electric | 114 |
| | 15 | % | | (39)% | | 186 |
| | 74 | % |
| Wyoming Electric | 41 |
| | (18 | )% | | (60)% | | 102 |
| | 100 | % |
| Colorado Electric | 243 |
| | 16 | % | | (34)% | | 369 |
| | 63 | % |
Combined (a) | 158 |
| | 14 | % | | (38)% | | 253 |
| | 68 | % |
| | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | Six Months Ended June 30, |
| Degree Days | 2017 | | 2016 | 2018 | | 2017 |
| | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
| Heating Degree Days: | | | | | | | | | | | | | | |
| South Dakota Electric | 4,040 |
| | (5 | )% | | 10% | | 3,683 |
| | (13 | )% | 4,736 |
| | 12 | % | | 17% | | 4,040 |
| | (5 | )% |
| Wyoming Electric | 3,894 |
| | (12 | )% | | —% | | 3,910 |
| | (12 | )% | 4,037 |
| | (9 | )% | | 4% | | 3,894 |
| | (12 | )% |
| Colorado Electric | 2,686 |
| | (17 | )% | | (4)% | | 2,801 |
| | (13 | )% | 2,866 |
| | 12 | % | | 7% | | 2,686 |
| | (17 | )% |
Combined (a) | 3,391 |
| | (11 | )% | | 2% | | 3,323 |
| | (13 | )% | 3,741 |
| | 7 | % | | 10% | | 3,391 |
| | (11 | )% |
| | | | | | | | | | | | | | | |
| Cooling Degree Days: | | | | | | | | | | | | | | |
| South Dakota Electric | 114 |
| | 15 | % | | (39)% | | 186 |
| | 74 | % | 132 |
| | 33 | % | | 16% | | 114 |
| | 15 | % |
| Wyoming Electric | 41 |
| | (18 | )% | | (60)% | | 102 |
| | 100 | % | 102 |
| | 104 | % | | 149% | | 41 |
| | (18 | )% |
| Colorado Electric | 243 |
| | 16 | % | | (34)% | | 369 |
| | 63 | % | 494 |
| | 136 | % | | 103% | | 243 |
| | 16 | % |
Combined (a) | 158 |
| | 14 | % | | (38)% | | 253 |
| | 68 | % | 292 |
| | 109 | % | | 85% | | 158 |
| | 14 | % |
__________
| |
| (a) | Combined actuals are calculated based on the weighted average number of total customers by state. |
| | | Electric Utilities Power Plant Availability | Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | 2017 | | 2016 | | 2018 | 2017 | 2018 | | 2017 | |
Coal-fired plants (a) | 74.8 | % | | 75.1 | % | | 83.0 | % | | 84.5 | % | | 91.2 | % | | 74.8 | % | | 93.1 | % | | 83.0 | % | |
| Natural gas fired plants and Other plants | 94.5 | % | | 97.6 | % | | 96.5 | % | | 96.2 | % | | |
| Natural gas-fired plants and Other plants | | 98.1 | % | | 94.5 | % | | 97.2 | % | | 96.5 | % | |
Wind (b) | 93.4 | % | | 99.3 | % | | 92.4 | % | | 99.3 | % | | 96.7 | % | | 93.4 | % | | 96.9 | % | | 92.4 | % | |
| Total availability | 88.0 | % | | 89.5 | % | | 91.8 | % | | 92.0 | % | | 95.8 | % | | 88.0 | % | | 95.9 | % | | 91.8 | % | |
| | | | | | | | | | | | | | | | | |
| Wind capacity factor | 35.8 | % | | 33.6 | % | | 39.7 | % | | 37.5 | % | | 41.7 | % | | 35.8 | % | | 46.1 | % | | 39.7 | % | |
__________
| |
| (a) | Both years included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II and 2016 includedWygen III. |
Gas Utilities
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) |
| Revenue: | | | | | | |
| Natural gas — regulated | $ | 161,212 |
| $ | 146,839 |
| $ | 14,373 |
| $ | 531,480 |
| $ | 479,535 |
| $ | 51,945 |
|
Other — non-regulated services (a) | 16,408 |
| 19,608 |
| (3,200 | ) | 43,484 |
| 51,822 |
| (8,338 | ) |
| Total revenue | 177,620 |
| 166,447 |
| 11,173 |
| 574,964 |
| 531,357 |
| 43,607 |
|
| | | | | | | |
| Cost of sales: | | | | | | |
| Natural gas — regulated | 62,453 |
| 52,332 |
| 10,121 |
| 267,537 |
| 222,034 |
| 45,503 |
|
Other — non-regulated services (a) | 5,601 |
| 10,018 |
| (4,417 | ) | 10,202 |
| 21,698 |
| (11,496 | ) |
| Total cost of sales | 68,054 |
| 62,350 |
| 5,704 |
| 277,739 |
| 243,732 |
| 34,007 |
|
| | | | | | | |
Gross margin (b) | 109,566 |
| 104,097 |
| 5,469 |
| 297,225 |
| 287,625 |
| 9,600 |
|
| | | | | | | |
| Operations and maintenance | 71,667 |
| 64,956 |
| 6,711 |
| 142,573 |
| 135,715 |
| 6,858 |
|
| Depreciation and amortization | 21,414 |
| 20,924 |
| 490 |
| 42,724 |
| 41,721 |
| 1,003 |
|
| Total operating expenses | 93,081 |
| 85,880 |
| 7,201 |
| 185,297 |
| 177,436 |
| 7,861 |
|
| | | | | | | |
| Operating income | 16,485 |
| 18,217 |
| (1,732 | ) | 111,928 |
| 110,189 |
| 1,739 |
|
| | | | | | | |
| Interest expense, net | (19,257 | ) | (19,610 | ) | 353 |
| (39,023 | ) | (39,392 | ) | 369 |
|
| Other income (expense), net | (916 | ) | (225 | ) | (691 | ) | (761 | ) | (48 | ) | (713 | ) |
| Income tax benefit (expense) | 2,527 |
| 1,346 |
| 1,181 |
| 34,315 |
| (24,904 | ) | 59,219 |
|
| Net income (loss) | (1,161 | ) | (272 | ) | (889 | ) | 106,459 |
| 45,845 |
| 60,614 |
|
| Net (income) loss attributable to noncontrolling interest | — |
| — |
| — |
| — |
| (107 | ) | 107 |
|
| Net income (loss) available for common stock | $ | (1,161 | ) | $ | (272 | ) | $ | (889 | ) | $ | 106,459 |
| $ | 45,738 |
| $ | 60,721 |
|
__________
| |
| (a) | The three and six months ended June 30, 2018 include certain BHES trading activities which are reported on a planned outage at Wygen III and an extended planned outage at Wyodak.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) | 2017 is lower than the prior year primarily due to the addition of the Peak View Wind Project for which 2017 is the first year of commercial operation.Non-GAAP measure |
Gas Utilities
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| | (in thousands) |
| Revenue: | | | | | | |
| Natural gas — regulated | $ | 150,426 |
| $ | 137,840 |
| $ | 12,586 |
| $ | 492,059 |
| $ | 392,264 |
| $ | 99,795 |
|
| Other — non-regulated services | 16,021 |
| 14,121 |
| 1,900 |
| 39,298 |
| 30,170 |
| 9,128 |
|
| Total revenue | 166,447 |
| 151,961 |
| 14,486 |
| 531,357 |
| 422,434 |
| 108,923 |
|
| | | | | | | |
| Cost of sales | | | | | | |
| Natural gas — regulated | 52,332 |
| 43,149 |
| 9,183 |
| 222,034 |
| 172,914 |
| 49,120 |
|
| Other — non-regulated services | 10,018 |
| 5,156 |
| 4,862 |
| 21,698 |
| 13,355 |
| 8,343 |
|
| Total cost of sales | 62,350 |
| 48,305 |
| 14,045 |
| 243,732 |
| 186,269 |
| 57,463 |
|
| | | | | | | |
| Gross margin | 104,097 |
| 103,656 |
| 441 |
| 287,625 |
| 236,165 |
| 51,460 |
|
| | | | | | | |
| Operations and maintenance | 64,956 |
| 62,237 |
| 2,719 |
| 135,715 |
| 114,924 |
| 20,791 |
|
| Depreciation and amortization | 20,924 |
| 19,931 |
| 993 |
| 41,721 |
| 35,903 |
| 5,818 |
|
| Total operating expenses | 85,880 |
| 82,168 |
| 3,712 |
| 177,436 |
| 150,827 |
| 26,609 |
|
| | | | | | | |
| Operating income (loss) | 18,217 |
| 21,488 |
| (3,271 | ) | 110,189 |
| 85,338 |
| 24,851 |
|
| | | | | | | |
| Interest expense, net | (19,610 | ) | (19,074 | ) | (536 | ) | (39,392 | ) | (32,591 | ) | (6,801 | ) |
| Other income (expense), net | (225 | ) | (261 | ) | 36 |
| (48 | ) | 390 |
| (438 | ) |
| Income tax benefit (expense) | 1,346 |
| (1,184 | ) | 2,530 |
| (24,904 | ) | (20,193 | ) | (4,711 | ) |
| Net income (loss) | (272 | ) | 969 |
| (1,241 | ) | 45,845 |
| 32,944 |
| 12,901 |
|
| Net (income) loss attributable to noncontrolling interest | — |
| 18 |
| (18 | ) | (107 | ) | (30 | ) | (77 | ) |
| Net income (loss) available for common stock | $ | (272 | ) | $ | 987 |
| $ | (1,259 | ) | $ | 45,738 |
| $ | 32,914 |
| $ | 12,824 |
|
Results of Operations for the Gas Utilities for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 2016:2017: Net loss(loss) from continuing operations available for common stock for the Gas Utilities was $(1.2) million for the three months ended June 30, 2018, compared to Net loss from continuing operations available for common stock of $(0.3) million for the three months ended June 30, 2017, compared to Net income available for common stock of $1.0 million for the three months ended June 30, 2016, as a result of:
Gross margin was comparablebenefited from a $2.8 million increase driven by higher natural gas volumes sold and a $0.9 million weather impact from colder spring temperatures as our service territories experienced colder weather in the current period compared to the same period in the prior year with comparable heatingyear. Heating degree days were 1 percent below normal in an off-peak quarter.the current year compared to 9 percent below normal for the same period in the prior year. Compared to the prior year, mark-to-market gains on non-utility natural gas commodity contracts increased $1.6 million, customer growth added $1.0 million in additional margin and rider revenues increased by $1.3 million primarily from our capital integrity recovery riders. These increases compared to the prior year are partially offset by a $2.2 million current year reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing utility rate tariffs.
Operations and maintenance increased primarily due to $2.3 million higher employee related expenses as a resultcosts of approximately $3.3 million driven primarily by labor, benefits and increased corporate allocations. Other increases compared to the prior year integration activitieswere from bad debt expense, which increased approximately $1.5 million driven by the current year increase in revenues, an increase in net facility costs of $1.3 million and transition expenses charged to the Corporate segment.higher property taxes.
Depreciation and amortization increased due to additional depreciation from thea higher asset base.base driven by previous year capital expenditures.
Interest expense, net increased primarily due to refinancing from variable to fixed rate debt, partially off-set by reduced borrowings.
Other income (expense), net was comparable to the same period in the prior year.
Other income (expense), net decreased from the prior year due primarily to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance.
Income tax benefit (expense): The effective increased from the prior year due to greater flow through benefits and lower state taxes, partially offset by the lower tax rate is different dueas a result of the reduction of the federal corporate income tax rate from 35% to pretax loss in 2017 and pretax income in 2016.21% from the TCJA, effective January 1, 2018.
Results of Operations for the Gas Utilities for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 2016:2017: Net income from continuing operations available for common stock for the Gas Utilities was $106 million for the six months ended June 30, 2018, compared to Net income from continuing operations available for common stock of $46 million for the six months ended June 30, 2017, compared to Net income available for common stock of $33 million for the six months ended June 30, 2016, as a result of:
Gross margin increased primarily due to margins of approximately $51a $10 million contributed byweather impact from colder winter temperatures as our service territories experienced colder weather in the SourceGas utilities reflecting a full six months of results in 2017 ascurrent period compared to approximately 4.5 monthsthe same period in 2016.the prior year. Heating degree days were 1 percent higher than normal in the current year compared to 12 percent below normal for the same period in the prior year. An increase in natural gas volumes sold added $2.3 million, customer growth added $2.8 million in additional margin over the prior year, rider revenues increased by $3.1 million primarily from our capital integrity recovery riders and mark-to-market gains on non-utility natural gas commodity contracts increased $2.5 million. These increases over the prior year are partially offset by a $11 million current year reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs.
Operations and maintenance increased primarily due to additional operatinghigher employee costs of approximately $19$3.6 million fordriven by labor, benefits and increased corporate allocations, higher bad debt expense of approximately $2.1 million driven by the acquired SourceGas utilities, reflectingcurrent year increase in revenues and a full six monthsnet increase in facility costs of results in 2017 as compared to$2.8 million. These increases are partially offset by lower outside service expenses of approximately 4.5 months in 2016. This $19 million increase included approximately $2.9 million of prior year integration activities and transition expenses charged to the Corporate segment. In addition, employee related expenses increased by $2.9 million for the Black Hills legacy gas utilities as a result of prior year integration activities and transition expenses charged to the Corporate segment.$1.8 million.
Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas utilities.a higher asset base driven by previous year capital expenditures.
Interest expense, net increased primarily due to additional interest expense from the acquired SourceGas utilities.
Other income (expense), net was comparable to the same period in the prior year.
Other income (expense), net decreased from the prior year due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance.
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 was lower as comparedalso reflects the reduction of the federal corporate income tax rate from 35% to 21% from the same period in the prior year primarily due to greater flow through benefit.TCJA, effective January 1, 2018.
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
Revenue (in thousands) (a) | 2017 | | 2016 | | 2017 | | 2016 |
| Residential: | | | | | | | |
| Arkansas | $ | 12,551 |
| | $ | 9,799 |
| | $ | 48,907 |
| | $ | 25,577 |
|
| Colorado | 20,659 |
| | 21,361 |
| | 67,440 |
| | 53,141 |
|
Nebraska (b) | 15,841 |
| | 14,327 |
| | 60,343 |
| | 56,873 |
|
| Iowa | 13,991 |
| | 12,787 |
| | 50,304 |
| | 47,634 |
|
| Kansas | 10,097 |
| | 9,320 |
| | 36,181 |
| | 31,668 |
|
Wyoming (b) | 8,112 |
| | 7,652 |
| | 23,428 |
| | 18,768 |
|
| Total Residential | $ | 81,251 |
| | $ | 75,246 |
| | $ | 286,603 |
| | $ | 233,661 |
|
| | | | | | | | |
| Commercial: | | | | | | | |
| Arkansas | $ | 7,131 |
| | $ | 4,801 |
| | $ | 25,184 |
| | $ | 12,529 |
|
| Colorado | 8,127 |
| | 7,939 |
| | 25,074 |
| | 18,136 |
|
| Nebraska | 3,671 |
| | 3,256 |
| | 17,573 |
| | 16,339 |
|
| Iowa | 5,133 |
| | 4,336 |
| | 21,097 |
| | 19,473 |
|
| Kansas | 3,107 |
| | 2,090 |
| | 12,023 |
| | 10,260 |
|
| Wyoming | 3,885 |
| | 3,477 |
| | 11,839 |
| | 9,180 |
|
| Total Commercial | $ | 31,054 |
| | $ | 25,899 |
| | $ | 112,790 |
| | $ | 85,917 |
|
| | | | | | | | |
| Industrial: | | | | | | | |
| Arkansas | $ | 1,361 |
| | $ | 771 |
| | $ | 3,581 |
| | $ | 1,608 |
|
| Colorado | 313 |
| | 278 |
| | 682 |
| | 532 |
|
| Nebraska | 55 |
| | 69 |
| | 205 |
| | 187 |
|
| Iowa | 228 |
| | 250 |
| | 1,039 |
| | 825 |
|
| Kansas | 1,585 |
| | 1,959 |
| | 1,982 |
| | 2,589 |
|
| Wyoming | 739 |
| | 703 |
| | 1,738 |
| | 1,657 |
|
| Total Industrial | $ | 4,281 |
| | $ | 4,030 |
| | $ | 9,227 |
| | $ | 7,398 |
|
| | | | | | | | |
| Transportation: | | | | | | | |
| Arkansas | $ | 2,415 |
| | $ | 2,110 |
| | $ | 5,415 |
| | $ | 3,733 |
|
| Colorado | 819 |
| | 860 |
| | 2,202 |
| | 1,765 |
|
Nebraska (b) | 15,219 |
| | 14,148 |
| | 33,859 |
| | 25,925 |
|
| Iowa | 1,119 |
| | 1,080 |
| | 2,590 |
| | 2,555 |
|
| Kansas | 1,311 |
| | 1,355 |
| | 3,253 |
| | 3,398 |
|
Wyoming (b) | 5,431 |
| | 5,505 |
| | 14,462 |
| | 10,137 |
|
| Total Transportation | $ | 26,314 |
| | $ | 25,058 |
| | $ | 61,781 |
| | $ | 47,513 |
|
Operating Statistics
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| Revenue (in thousands) (continued) | 2017 | | 2016 | | 2017 | | 2016 |
| Transmission: | | | | | | | |
| Arkansas | $ | 450 |
| | $ | 12 |
| | $ | 1,212 |
| | $ | 25 |
|
| Colorado | 4,018 |
| | 3,683 |
| | 13,764 |
| | 8,762 |
|
| Wyoming | 1,223 |
| | 1,118 |
| | 2,501 |
| | 2,177 |
|
| Total Transmission | $ | 5,691 |
| | $ | 4,813 |
| | $ | 17,477 |
| | $ | 10,964 |
|
| | | | | | | | |
| Other Sales Revenue: | | | | | | | |
| Arkansas | $ | 76 |
| | $ | 520 |
| | $ | 662 |
| | $ | 1,289 |
|
| Colorado | 149 |
| | 292 |
| | 479 |
| | 455 |
|
| Nebraska | 788 |
| | 874 |
| | 1,787 |
| | 1,675 |
|
| Iowa | 152 |
| | 213 |
| | 261 |
| | 313 |
|
| Kansas | 408 |
| | 643 |
| | 442 |
| | 2,633 |
|
| Wyoming | 262 |
| | 252 |
| | 550 |
| | 446 |
|
| Total Other Sales Revenue | $ | 1,835 |
| | $ | 2,794 |
| | $ | 4,181 |
| | $ | 6,811 |
|
| | | | | | | | |
| Total Regulated Revenue | $ | 150,426 |
| | $ | 137,840 |
| | $ | 492,059 |
| | $ | 392,264 |
|
| | | | | | | | |
| Non-regulated Services | 16,021 |
| | 14,121 |
| | 39,298 |
| | 30,170 |
|
| | | | | | | | |
| Total Revenue | $ | 166,447 |
| | $ | 151,961 |
| | $ | 531,357 |
| | $ | 422,434 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gas Revenue (in thousands) | | Gross Margin (a) (in thousands) |
| | | Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 |
| | | | | | | | | | | |
| Residential | | $ | 91,000 |
| $ | 81,251 |
| $ | 325,751 |
| $ | 286,603 |
| | $ | 52,697 |
| $ | 49,193 |
| $ | 149,474 |
| $ | 140,244 |
|
| Commercial | | 34,031 |
| 31,054 |
| 129,036 |
| 112,790 |
| | 14,807 |
| 14,035 |
| 47,010 |
| 43,834 |
|
| Industrial | | 6,565 |
| 4,281 |
| 12,547 |
| 9,227 |
| | 1,639 |
| 1,026 |
| 3,313 |
| 2,508 |
|
Other (b) | | 255 |
| 1,876 |
| (7,276 | ) | 4,264 |
| | 255 |
| 1,876 |
| (7,276 | ) | 4,264 |
|
| Total Distribution | | 131,851 |
| 118,462 |
| 460,058 |
| 412,884 |
| | 69,398 |
| 66,130 |
| 192,521 |
| 190,850 |
|
| | | | | | | | | | | |
| Transportation and Transmission | | 29,361 |
| 28,377 |
| 71,422 |
| 66,651 |
| | 29,361 |
| 28,377 |
| 71,422 |
| 66,651 |
|
| | | | | | | | | | | |
| Total Regulated | | 161,212 |
| 146,839 |
| 531,480 |
| 479,535 |
| | 98,759 |
| 94,507 |
| 263,943 |
| 257,501 |
|
| | | | | | | | | | | |
| Non-regulated Services | | 16,408 |
| 19,608 |
| 43,484 |
| 51,822 |
| | 10,807 |
| 9,590 |
| 33,282 |
| 30,124 |
|
| | | | | | | | | | | |
| Total Gas Revenue & Gross Margin | | $ | 177,620 |
| $ | 166,447 |
| $ | 574,964 |
| $ | 531,357 |
| | $ | 109,566 |
| $ | 104,097 |
| $ | 297,225 |
| $ | 287,625 |
|
__________
| |
| (a) | Certain prior year revenue classes have been revised to conform to current year presentation; total revenue did not change.Non-GAAP measure |
| |
| (b) | Change in priorIncludes current year duereserve to reclassificationrevenue to reflect the reduction of Residential Choice customersthe lower federal income tax rate from Residential to Transportation class.the TCJA on our existing rate tariffs. |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
Gross Margin (in thousands) (a) | 2017 | | 2016 | | 2017 | | 2016 |
| Residential: | | | | | | | |
| Arkansas | $ | 8,642 |
| | $ | 7,752 |
| | $ | 31,086 |
| | $ | 17,381 |
|
| Colorado | 9,419 |
| | 9,819 |
| | 26,251 |
| | 21,296 |
|
Nebraska (b) | 10,313 |
| | 9,936 |
| | 29,050 |
| | 28,420 |
|
| Iowa | 9,221 |
| | 8,989 |
| | 23,012 |
| | 22,596 |
|
| Kansas | 6,557 |
| | 6,444 |
| | 17,998 |
| | 16,529 |
|
Wyoming (b) | 5,041 |
| | 5,001 |
| | 12,847 |
| | 11,301 |
|
| Total Residential | $ | 49,193 |
| | $ | 47,941 |
| | $ | 140,244 |
| | $ | 117,523 |
|
| | | | | | | | |
| Commercial: | | | | | | | |
| Arkansas | $ | 3,578 |
| | $ | 3,012 |
| | $ | 13,149 |
| | $ | 7,044 |
|
| Colorado | 3,311 |
| | 3,072 |
| | 8,462 |
| | 6,227 |
|
| Nebraska | 1,798 |
| | 1,756 |
| | 6,346 |
| | 6,213 |
|
| Iowa | 2,203 |
| | 2,168 |
| | 6,574 |
| | 6,457 |
|
| Kansas | 1,464 |
| | 1,100 |
| | 4,475 |
| | 4,011 |
|
| Wyoming | 1,681 |
| | 1,715 |
| | 4,828 |
| | 4,379 |
|
| Total Commercial | $ | 14,035 |
| | $ | 12,823 |
| | $ | 43,834 |
| | $ | 34,331 |
|
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Revenue (in thousands) | | Gross Margin (a) (in thousands) |
| Gross Margin (in thousands) (continued) | 2017 | | 2016 | | 2017 | | 2016 | |
| Industrial: | | | | | | | | |
| | | | Three Months Ended
June 30, | Six Months Ended
June 30, | | Three Months Ended
June 30, | Six Months Ended
June 30, |
| | | | 2018 | 2017 | 2018 | 2017 | | 2018 | 2017 | 2018 | 2017 |
| | | | | | |
| Arkansas | $ | 311 |
| | $ | 368 |
| | $ | 1,161 |
| | $ | 686 |
| | $ | 27,095 |
| $ | 24,145 |
| $ | 97,483 |
| $ | 85,243 |
| | $ | 16,471 |
| $ | 15,568 |
| $ | 52,388 |
| $ | 52,877 |
|
| Colorado | 108 |
| | 148 |
| | 221 |
| | 268 |
| | 32,138 |
| 31,665 |
| 103,536 |
| 98,844 |
| | 18,562 |
| 18,810 |
| 51,707 |
| 53,173 |
|
| Nebraska | 25 |
| | 50 |
| | 77 |
| | 95 |
| | 48,993 |
| 45,396 |
| 155,754 |
| 143,711 |
| | 32,801 |
| 29,376 |
| 86,661 |
| 79,128 |
|
| Iowa | 46 |
| | 44 |
| | 136 |
| | 87 |
| | 27,102 |
| 23,462 |
| 94,986 |
| 80,910 |
| | 14,648 |
| 14,262 |
| 37,074 |
| 35,714 |
|
| Kansas | 379 |
| | 539 |
| | 586 |
| | 768 |
| | 21,002 |
| 18,326 |
| 63,383 |
| 57,275 |
| | 11,870 |
| 11,140 |
| 29,767 |
| 28,603 |
|
| Wyoming | 157 |
| | 147 |
| | 327 |
| | 350 |
| | 21,290 |
| 23,453 |
| 59,822 |
| 65,374 |
| | 15,214 |
| 14,941 |
| 39,628 |
| 38,130 |
|
| Total Industrial | $ | 1,026 |
| | $ | 1,296 |
| | $ | 2,508 |
| | $ | 2,254 |
| |
| | | | | | | | | |
| Transportation: | | | | | | | | |
| Arkansas | $ | 2,415 |
| | $ | 2,110 |
| | $ | 5,415 |
| | $ | 3,733 |
| |
| Colorado | 819 |
| | 860 |
| | 2,202 |
| | 1,765 |
| |
Nebraska (b) | 15,219 |
| | 14,148 |
| | 33,859 |
| | 25,925 |
| |
| Iowa | 1,119 |
| | 1,080 |
| | 2,590 |
| | 2,555 |
| |
| Kansas | 1,311 |
| | 1,355 |
| | 3,253 |
| | 3,398 |
| |
Wyoming (b) | 5,431 |
| | 5,505 |
| | 14,462 |
| | 10,137 |
| |
| Total Transportation | $ | 26,314 |
| | $ | 25,058 |
| | $ | 61,781 |
| | $ | 47,513 |
| |
| | | | | | | | | |
| Transmission: | | | | | | | | |
| Arkansas | $ | 450 |
| | $ | 12 |
| | $ | 1,212 |
| | $ | 25 |
| |
| Colorado | 4,018 |
| | 3,613 |
| | 13,764 |
| | 8,751 |
| |
| Wyoming | 1,223 |
| | 1,154 |
| | 2,501 |
| | 2,153 |
| |
| Total Transmission | $ | 5,691 |
| | $ | 4,779 |
| | $ | 17,477 |
| | $ | 10,929 |
| |
| | | | | | | | | |
| Other Sales Margins: | | | | | | | | |
| Arkansas | $ | 76 |
| | $ | 521 |
| | $ | 662 |
| | $ | 1,290 |
| |
| Colorado | 149 |
| | 292 |
| | 479 |
| | 455 |
| |
| Nebraska | 788 |
| | 873 |
| | 1,787 |
| | 1,674 |
| |
| Iowa | 152 |
| | 213 |
| | 261 |
| | 313 |
| |
| Kansas | 408 |
| | 643 |
| | 442 |
| | 2,622 |
| |
| Wyoming | 262 |
| | 252 |
| | 550 |
| | 446 |
| |
| Total Other Sales Margins | $ | 1,835 |
| | $ | 2,794 |
| | $ | 4,181 |
| | $ | 6,800 |
| |
| | | | | | | | | |
| Total Regulated Gross Margin | $ | 98,094 |
| | $ | 94,691 |
| | $ | 270,025 |
| | $ | 219,350 |
| |
| | | | | | | | | |
| Non-regulated Services | 6,003 |
| | 8,965 |
| | 17,600 |
| | 16,815 |
| |
| | | | | | | | | |
| Total Gross Margin | $ | 104,097 |
| | $ | 103,656 |
| | $ | 287,625 |
| | $ | 236,165 |
| |
| Total Gas Revenue & Gross Margin | | | $ | 177,620 |
| $ | 166,447 |
| $ | 574,964 |
| $ | 531,357 |
| | $ | 109,566 |
| $ | 104,097 |
| $ | 297,225 |
| $ | 287,625 |
|
__________
| |
| (a) | Certain prior year revenue classes have been revised to conform to current year presentation. |
| |
(b) | Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class.Non-GAAP measure |
|
| | | | | | | | |
| | Three Months Ended
June 30, | Six Months Ended
June 30, |
| Gas Utilities Quantities Sold & Transported (Dth) | 2018 | 2017 | 2018 | 2017 |
| | | | | |
| Residential | 8,837,588 |
| 7,101,336 |
| 38,933,825 |
| 32,369,470 |
|
| Commercial | 4,615,571 |
| 3,960,957 |
| 18,564,692 |
| 15,665,271 |
|
| Industrial | 1,747,702 |
| 1,041,032 |
| 2,931,319 |
| 1,967,919 |
|
| Total Distribution Quantities Sold | 15,200,861 |
| 12,103,325 |
| 60,429,836 |
| 50,002,660 |
|
| | | | | |
| Transportation and Transmission | 32,846,279 |
| 30,924,304 |
| 77,579,754 |
| 71,737,178 |
|
| | | | | |
| Total Quantities Sold & Transported | 48,047,140 |
| 43,027,629 |
| 138,009,590 |
| 121,739,838 |
|
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended
June 30, | Six Months Ended
June 30, |
Gas Utilities Quantities Sold and Transportation (in Dth) (a) | 2017 | 2016 | | 2017 | 2016 | |
| Residential: | | | | |
| Gas Utilities Quantities Sold & Transported (Dth) | | 2018 | 2017 | 2018 | 2017 |
| | | |
| Arkansas | 964,399 |
| 852,523 |
| | 4,528,144 |
| 2,745,603 |
| 5,282,607 |
| 5,069,939 |
| 17,161,233 |
| 14,282,024 |
|
| Colorado | 2,233,388 |
| 2,528,067 |
| | 8,270,827 |
| 6,945,901 |
| 4,705,454 |
| 5,057,411 |
| 16,408,805 |
| 16,045,055 |
|
Nebraska (b) | 1,220,650 |
| 1,171,552 |
| | 6,749,118 |
| 6,656,046 |
| 16,405,326 |
| 13,908,566 |
| 44,392,550 |
| 38,181,355 |
|
| Iowa | 1,116,176 |
| 1,227,179 |
| | 6,146,579 |
| 6,265,928 |
| 7,429,328 |
| 6,631,758 |
| 22,932,317 |
| 20,126,770 |
|
| Kansas | 706,934 |
| 736,678 |
| | 3,634,937 |
| 3,654,752 |
| 6,929,756 |
| 5,196,050 |
| 17,227,084 |
| 13,705,368 |
|
Wyoming (b) | 859,789 |
| 908,572 |
| | 3,039,865 |
| 2,615,807 |
| 7,294,669 |
| 7,163,905 |
| 19,887,601 |
| 19,399,266 |
|
| Total Residential | 7,101,336 |
| 7,424,571 |
| | 32,369,470 |
| 28,884,037 |
| |
| | | | | |
| Commercial: | | | | |
| Arkansas | 871,222 |
| 696,526 |
| | 3,044,374 |
| 1,850,100 |
| |
| Colorado | 962,873 |
| 991,492 |
| | 3,220,623 |
| 2,434,658 |
| |
| Nebraska | 422,759 |
| 425,341 |
| | 2,446,483 |
| 2,416,070 |
| |
| Iowa | 691,573 |
| 728,477 |
| | 3,291,759 |
| 3,302,428 |
| |
| Kansas | 345,772 |
| 275,512 |
| | 1,547,299 |
| 1,550,400 |
| |
| Wyoming | 666,758 |
| 660,367 |
| | 2,114,733 |
| 1,812,068 |
| |
| Total Commercial | 3,960,957 |
| 3,777,715 |
| | 15,665,271 |
| 13,365,724 |
| |
| | | | | |
| Industrial: | | | | |
| Arkansas | 259,590 |
| 184,213 |
| | 609,679 |
| 345,905 |
| |
| Colorado | 60,849 |
| 92,781 |
| | 123,036 |
| 132,129 |
| |
| Nebraska | 8,544 |
| 14,375 |
| | 31,910 |
| 32,712 |
| |
| Iowa | 49,208 |
| 64,611 |
| | 195,328 |
| 191,810 |
| |
Kansas (c) | 469,807 |
| 765,078 |
| | 551,656 |
| 929,423 |
| |
| Wyoming | 193,034 |
| 215,516 |
| | 456,310 |
| 488,067 |
| |
| Total Industrial | 1,041,032 |
| 1,336,574 |
| | 1,967,919 |
| 2,120,046 |
| |
| | | | | |
| Total Quantities Sold | 12,103,325 |
| 12,538,860 |
| | 50,002,660 |
| 44,369,807 |
| |
| | | | | |
| Transportation: | | | | |
| Arkansas | 2,974,728 |
| 2,137,721 |
| | 6,099,827 |
| 3,549,313 |
| |
| Colorado | 1,800,301 |
| 800,220 |
| | 4,430,569 |
| 1,598,813 |
| |
Nebraska (b) | 12,256,613 |
| 11,429,087 |
| | 28,953,844 |
| 23,600,182 |
| |
| Iowa | 4,774,801 |
| 4,635,739 |
| | 10,493,104 |
| 10,466,083 |
| |
| Kansas | 3,673,537 |
| 3,234,621 |
| | 7,971,476 |
| 7,048,006 |
| |
Wyoming (b) | 5,444,324 |
| 7,185,846 |
| | 13,788,358 |
| 12,451,629 |
| |
| Total Transportation | 30,924,304 |
| 29,423,234 |
| | 71,737,178 |
| 58,714,026 |
| |
| | | | | |
| Total Quantities Sold and Transportation | 43,027,629 |
| 41,962,094 |
| | 121,739,838 |
| 103,083,833 |
| |
| Total Quantities Sold & Transported | | 48,047,140 |
| 43,027,629 |
| 138,009,590 |
| 121,739,838 |
|
__________
| |
(a) | Certain prior year revenue classes have been revised to conform to current year presentation. |
| |
(b) | Change in prior year due to reclassification of Residential Choice customers from Residential to Transportation class. |
| |
(c) | Decrease is primarily driven by lower irrigation load in 2017 compared to the prior year. |
Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. OverApproximately 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 June 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) | 400 | | 21% | | 65% | | 242 | | (27)% |
| Colorado | 735 | | (23)% | | (17)% | | 889 | | (7)% |
| Nebraska | 708 | | 12% | | 25% | | 567 | | (11)% |
| Iowa | 801 | | 17% | | 29% | | 619 | | (10)% |
Kansas (a) | 508 | | 14% | | 14% | | 445 | | —% |
| Wyoming | 1,072 | | (12)% | | (9)% | | 1,177 | | (4)% |
Combined (b) | 740 | | (1)% | | 8% | | 686 | | (9)% |
|
| | | | | | | | | |
| | Three Months Ended June 30, |
| Degree Days | 2017 | | | | 2016 |
| Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Arkansas (a) (d) | 242 | | (27)% | | 4% | | 232 | | (30)% |
| Colorado | 889 | | (7)% | | —% | | 889 | | 3% |
| Nebraska | 567 | | (11)% | | 29% | | 440 | | (30)% |
| Iowa | 619 | | (10)% | | (2)% | | 633 | | (8)% |
Kansas (a) | 445 | | —% | | 9% | | 407 | | (9)% |
| Wyoming | 1,177 | | (4)% | | 1% | | 1,171 | | (12)% |
Combined (b) (d) | 686 | | (9)% | | 11% | | 620 | | (17)% |
| | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | Six Months Ended June 30, |
| Degree Days | 2017 | | 2016 | 2018 | | 2017 |
| Heating Degree Days: | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year (c) | | Actual | | Variance from 30-Year Average | Actual | | Variance from 30-Year Average | | Actual Variance to Prior Year | | Actual | | Variance from 30-Year Average |
Arkansas (a) (d) | 1,811 |
| | (26 | )% | | 52% | | 1,189 |
| | (51 | )% | |
Arkansas (a) | | 2,448 |
| | 1 | % | | 35% | | 1,811 |
| | (26 | )% |
| Colorado | 3,354 |
| | (14 | )% | | (5)% | | 3,517 |
| | (7 | )% | 3,439 |
| | (12 | )% | | 3% | | 3,354 |
| | (14 | )% |
| Nebraska | 3,214 |
| | (12 | )% | | 3% | | 3,121 |
| | (16 | )% | 3,915 |
| | 7 | % | | 22% | | 3,214 |
| | (12 | )% |
| Iowa | 3,551 |
| | (13 | )% | | (4)% | | 3,715 |
| | (9 | )% | 4,332 |
| | 7 | % | | 22% | | 3,551 |
| | (13 | )% |
Kansas (a) | 2,547 |
| | (13 | )% | | (1)% | | 2,570 |
| | (13 | )% | 2,978 |
| | 2 | % | | 17% | | 2,547 |
| | (13 | )% |
| Wyoming | 4,161 |
| | (6 | )% | | 4% | | 4,020 |
| | (9 | )% | 4,316 |
| | (2 | )% | | 4% | | 4,161 |
| | (6 | )% |
Combined (b) (d) | 3,404 |
| | (12 | )% | | 11% | | 3,069 |
| | (20 | )% | |
Combined (b) | | 3,899 |
| | 1 | % | | 15% | | 3,404 |
| | (12 | )% |
__________
| |
| (a) | Arkansas has a weather normalization mechanism in effect during the months of November through April for customers with residential and business rate schedules. Kansas Gas has an approveda weather normalization mechanism within its residential and business rate structure, which minimizes weather impact on gross margins. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, compared to Kansas, which uses multiple locations. The weather normalization mechanism in Arkansas minimizes weather impact, but does not eliminate the impact. |
| |
| (b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas Distribution is partially excluded based on the weather normalization mechanism in effect from November through April. |
| |
(c) | The actual variance in heating degree days for the six months ended June 30, 2017 compared to prior year is not a reasonable measurement of weather impacts due to the exclusion of the pre-acquisition heating degree days for the SourceGas utilities in Arkansas, Colorado, Nebraska and Wyoming. These utilities were acquired on February 12, 2016. |
| |
(d) | In 2016, the 30-year weather average for Arkansas was calculated on average actual daily temperatures. To conform to current year comparisons to normal, the 2016 variances for Arkansas compared to normal and the 2016 combined variance compared to normal have been updated for both of the three and six months ended June 30, 2016. |
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 20162017 Annual Report on Form 10-K filed with the SEC.
South Dakota Electric Settlement
On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.
The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:
|
| | | | | | | | |
| Subsidiary | Jurisdiction | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Tariff and Rate Matters | Percentage of Power Marketing Profit Shared with Customers |
| South Dakota Electric | SD | Global Settlement | 7.76% | Global Settlement | $543.9 | 10/2014 | ECA, TCA, Energy Efficiency Cost Recovery/DSM | 70% |
Colorado Electric Rate Case filing
On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air-Clean Jobs Act construction financing rider. The turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. An authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.
On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver District Court on July 10, 2017.
We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations.
Gas Utilities Rates and Rate Activity
The following table summarizes recent activity of certain state and federal rate reviews, riders and surcharges (dollars in millions):
|
| | | | | | | | | |
| | Type of Service | Date Requested | Effective Date | Revenue Amount Requested | Revenue Amount Approved |
Arkansas Stockton Storage (a) | Gas - storage | 11/2016 | 1/2017 | $ | 2.6 |
| $ | 2.6 |
|
Arkansas MRP/ARMRP (b) | Gas | 6/2017 | 6/2017 | $ | 2.1 |
| $ | 2.1 |
|
Kansas Gas (c) | Gas | 5/2017 | 6/2017 | $ | 1.4 |
| $ | 1.4 |
|
RMNG (d) | Gas - transmission and storage | 11/2016 | 1/2017 | $ | 2.9 |
| $ | 2.9 |
|
Nebraska Gas Dist. (e) | Gas | 10/2016 | 2/2017 | $ | 6.5 |
| $ | 6.5 |
|
____________________
| |
(a) | On November 15, 2016, Arkansas Gas filed for the recovery of the Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism with the rider effective January 1, 2017. This recovery mechanism was initially approved on October 15, 2015 for the Stockton Storage acquisition. |
| |
(b) | On June 30, 2017 Arkansas Gas filed for recovery of $1.7 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.4 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates go into effect on the date of the filing. |
| |
(c) | On February 21, 2017, Kansas Gas filed with the KCC requesting recovery of $1.4 million, which includes $0.6 million of new revenue related to the Gas System Reliability Surcharge rider (“GSRS”). This GSRS filing was approved by the KCC on May 23, 2017 and went into effect on June 1, 2017. |
| |
(d) | On November 3, 2016, RMNG filed with the CPUC requesting recovery of $2.9 million, which includes $1.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2017. This SSIR request was approved by the CPUC in December 2016, and went into effect on January 1, 2017. |
| |
(e) | On October 3, 2016, Nebraska Gas Dist. filed with the NPSC requesting recovery of $6.5 million, which includes $1.7 million of new revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2017, and went into effect on February 1, 2017. |
Power Generation
| | | | Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) | (in thousands) |
Revenue (a) | $ | 21,795 |
| $ | 21,714 |
| $ | 81 |
| $ | 45,362 |
| $ | 45,022 |
| $ | 340 |
| $ | 21,884 |
| $ | 21,795 |
| $ | 89 |
| $ | 44,987 |
| $ | 45,362 |
| $ | (375 | ) |
| | | |
| Operations and maintenance | 8,528 |
| 8,648 |
| (120 | ) | 16,582 |
| 16,690 |
| (108 | ) | 9,959 |
| 8,528 |
| 1,431 |
| 18,086 |
| 16,582 |
| 1,504 |
|
Depreciation and amortization (a) | 1,069 |
| 1,053 |
| 16 |
| 2,276 |
| 2,084 |
| 192 |
| 1,633 |
| 1,069 |
| 564 |
| 3,235 |
| 2,276 |
| 959 |
|
| Total operating expense | 9,597 |
| 9,701 |
| (104 | ) | 18,858 |
| 18,774 |
| 84 |
| 11,592 |
| 9,597 |
| 1,995 |
| 21,321 |
| 18,858 |
| 2,463 |
|
| | | |
| Operating income | 12,198 |
| 12,013 |
| 185 |
| 26,504 |
| 26,248 |
| 256 |
| 10,292 |
| 12,198 |
| (1,906 | ) | 23,666 |
| 26,504 |
| (2,838 | ) |
| | | |
| Interest expense, net | (704 | ) | (120 | ) | (584 | ) | (1,291 | ) | (934 | ) | (357 | ) | (1,316 | ) | (704 | ) | (612 | ) | (2,489 | ) | (1,291 | ) | (1,198 | ) |
| Other (expense) income, net | (13 | ) | (19 | ) | 6 |
| (31 | ) | 4 |
| (35 | ) | |
| Other income (expense), net | | (47 | ) | (13 | ) | (34 | ) | (41 | ) | (31 | ) | (10 | ) |
| Income tax (expense) benefit | (3,033 | ) | (3,559 | ) | 526 |
| (6,688 | ) | (8,421 | ) | 1,733 |
| (1,334 | ) | (3,033 | ) | 1,699 |
| (4,055 | ) | (6,688 | ) | 2,633 |
|
| | | |
| Net income | 8,448 |
| 8,315 |
| 133 |
| 18,494 |
| 16,897 |
| 1,597 |
| 7,595 |
| 8,448 |
| (853 | ) | 17,081 |
| 18,494 |
| (1,413 | ) |
| Net income attributable to noncontrolling interest | (3,116 | ) | (2,632 | ) | (484 | ) | (6,632 | ) | (2,632 | ) | (4,000 | ) | (2,823 | ) | (3,116 | ) | 293 |
| (6,453 | ) | (6,632 | ) | 179 |
|
| Net income (loss) available for common stock | $ | 5,332 |
| $ | 5,683 |
| $ | (351 | ) | $ | 11,862 |
| $ | 14,265 |
| $ | (2,403 | ) | |
| Net income available for common stock | | $ | 4,772 |
| $ | 5,332 |
| $ | (560 | ) | $ | 10,628 |
| $ | 11,862 |
| $ | (1,234 | ) |
____________
| |
| (a) | The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, revenue and depreciation expense are impacted by the accounting for this lease. Under the lease, the original cost of the facility is recorded at Colorado Electric and is being depreciated by Colorado Electric for segment reporting purposes. |
On April 14,In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million.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 Black Hills Colorado Electric. Net income available for common stock for the three and six months ended June 30, 2018 and June 30, 2017 was reduced by $2.8 million and $3.1 million, and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016, attributable to this noncontrolling interest.
Results of Operations for Power Generation for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 2016:2017: Net income from continuing operations available for common stock for the Power Generation segment was $5.3$4.8 million for the three months ended June 30, 2017,2018, compared to Net income from continuing operations available for common stock of $5.7$5.3 million for the same period in 2016 as a result of:
2017. Revenue was comparable to the same period in the prior year.
Operations and maintenance was comparable to Operating expenses increased from the same period in the prior year.
Depreciationyear due to higher maintenance expenses primarily related to outage costs at Wygen I, turbine maintenance expenses at the generating facility in Pueblo and amortization was comparable tohigher depreciation. Interest expense increased from the same period in the prior year.
Interest expense, net increasedyear due to prior year higher interest income associated withrates. The variance in tax expense reflects the proceedsreduction in the federal tax rate from 35% to 21% from the noncontrolling interest sale in April 2016.
Other (expense) income, net was comparable to the same period in the prior year.
Income tax (expense) benefit: Black Hills Colorado IPP went from a single member LLC, wholly owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9 percent of its membership interest in April 2016. TheTCJA, effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded.
Net income attributable to noncontrolling interest: Net income attributable to noncontrolling interest increased by $0.5 million as a result of the noncontrolling interest sale in April 14, 2016.January 1, 2018.
Results of Operations for Power Generation for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 2016:2017: Net income from continuing operations available for common stock for the Power Generation segment was $12$11 million for the six months ended June 30, 2017,2018, compared to Net income from continuing operations available for common stock of $14$12 million for the same period in 20162017. Revenue decreased in the current year as a result of:
Revenue was comparableof lower Wygen I MWh sold due to current year outages. Operating expenses increased from the same period in the prior year.
Operationsyear due to higher maintenance expenses primarily related to outage costs at Wygen I and maintenance was comparable tohigher depreciation. Interest expense increased from the same period in the prior year.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 recorded on a valuation allowance due to changes in estimated future taxable income subsequent to the TCJA.
Depreciation and amortization was comparable to the same period in the prior year.
Interest expense, net increased due to prior year higher interest income associated with the proceeds from the noncontrolling interest sale in April 2016.
Other (expense) income, net was comparable to the same period in the prior year.
Income tax (expense) benefit: Black Hills Colorado IPP went from a single member LLC, wholly owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded.
Net income attributable to noncontrolling interest: Net income attributable to noncontrolling interest increased by $4.0 million as a result of the noncontrolling interest sale in April 2016.
The following table summarizes MWh for our Power Generation segment:
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
Quantities Sold, Generated and Purchased (MWh) (a) | | | | | | |
| Sold | | | | | | |
Black Hills Colorado IPP (b) | 214,059 |
| 310,442 |
| | 469,024 |
| 644,320 |
| 208,888 |
| 214,059 |
| | 441,263 |
| 469,024 |
|
Black Hills Wyoming (c) | 142,593 |
| 141,976 |
| | 312,969 |
| 309,007 |
| 144,460 |
| 142,593 |
| | 310,061 |
| 312,969 |
|
| Total Sold | 356,652 |
| 452,418 |
| | 781,993 |
| 953,327 |
| 353,348 |
| 356,652 |
| | 751,324 |
| 781,993 |
|
| | | | | | | |
| Generated | | | | | | |
Black Hills Colorado IPP (b) | 214,059 |
| 310,442 |
| | 469,024 |
| 644,320 |
| 208,888 |
| 214,059 |
| | 441,263 |
| 469,024 |
|
Black Hills Wyoming (c) | 127,454 |
| 119,985 |
| | 267,694 |
| 258,904 |
| 128,819 |
| 127,454 |
| | 262,848 |
| 267,694 |
|
| Total Generated | 341,513 |
| 430,427 |
| | 736,718 |
| 903,224 |
| 337,707 |
| 341,513 |
| | 704,111 |
| 736,718 |
|
| | | | | | | |
| Purchased | | | | | | |
| Black Hills Colorado IPP | — |
| — |
| | — |
| — |
| — |
| — |
| | — |
| — |
|
Black Hills Wyoming (c) | 10,962 |
| 16,936 |
| | 32,217 |
| 45,239 |
| 17,122 |
| 10,962 |
| | 49,039 |
| 32,217 |
|
| Total Purchased | 10,962 |
| 16,936 |
| | 32,217 |
| 45,239 |
| 17,122 |
| 10,962 |
| | 49,039 |
| 32,217 |
|
____________
| |
| (a) | Company uses and losses are not included in the quantities sold, generated, and purchased. |
| |
| (b) | Decrease from the prior year is a result of the 2017 impact of Colorado Electric’s wind generation replacing natural-gas generation. |
| |
| (c) | Under the 20-year economy energy PPA with the City of Gillette effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances. |
The following table provides certain operating statistics for our plants within the Power Generation segment:
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 | 2018 | 2017 | | 2018 | 2017 |
| Contracted power plant fleet availability: | | | | | | |
| Coal-fired plant | 90.4 | % | 85.9 | % | | 95.2 | % | 91.8 | % | 89.1 | % | 90.4 | % | | 91.9 | % | 95.2 | % |
| Natural gas-fired plants | 99.1 | % | 99.2 | % | | 99.1 | % | 99.3 | % | 99.5 | % | 99.1 | % | | 99.5 | % | 99.1 | % |
| Total availability | 96.9 | % | 95.8 | % | | 98.1 | % | 97.4 | % | 96.8 | % | 96.9 | % | | 97.5 | % | 98.1 | % |
Mining
| | | | Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) | (in thousands) |
| Revenue | $ | 14,946 |
| $ | 11,047 |
| $ | 3,899 |
| $ | 31,492 |
| $ | 27,329 |
| $ | 4,163 |
| $ | 16,899 |
| $ | 14,946 |
| $ | 1,953 |
| $ | 34,027 |
| $ | 31,492 |
| $ | 2,535 |
|
| | | |
| Operations and maintenance | 9,833 |
| 8,287 |
| 1,546 |
| 20,927 |
| 18,721 |
| 2,206 |
| 11,124 |
| 9,833 |
| 1,291 |
| 22,046 |
| 20,927 |
| 1,119 |
|
| Depreciation, depletion and amortization | 2,062 |
| 2,448 |
| (386 | ) | 4,227 |
| 4,927 |
| (700 | ) | 1,950 |
| 2,062 |
| (112 | ) | 3,885 |
| 4,227 |
| (342 | ) |
| Total operating expenses | 11,895 |
| 10,735 |
| 1,160 |
| 25,154 |
| 23,648 |
| 1,506 |
| 13,074 |
| 11,895 |
| 1,179 |
| 25,931 |
| 25,154 |
| 777 |
|
| | | |
| Operating income (loss) | 3,051 |
| 312 |
| 2,739 |
| 6,338 |
| 3,681 |
| 2,657 |
| |
| Operating income | | 3,825 |
| 3,051 |
| 774 |
| 8,096 |
| 6,338 |
| 1,758 |
|
| | | |
| Interest (expense) income, net | (74 | ) | (91 | ) | 17 |
| (99 | ) | (183 | ) | 84 |
| |
| Other income, net | 536 |
| 532 |
| 4 |
| 1,077 |
| 1,066 |
| 11 |
| |
| Interest expense, net | | (233 | ) | (74 | ) | (159 | ) | (333 | ) | (99 | ) | (234 | ) |
| Other income (expense), net | | (94 | ) | 536 |
| (630 | ) | (120 | ) | 1,077 |
| (1,197 | ) |
| Income tax benefit (expense) | (832 | ) | (29 | ) | (803 | ) | (1,745 | ) | (902 | ) | (843 | ) | (493 | ) | (832 | ) | 339 |
| (1,654 | ) | (1,745 | ) | 91 |
|
| | | |
| Net income (loss) | $ | 2,681 |
| $ | 724 |
| $ | 1,957 |
| $ | 5,571 |
| $ | 3,662 |
| $ | 1,909 |
| |
| Net income | | $ | 3,005 |
| $ | 2,681 |
| $ | 324 |
| $ | 5,989 |
| $ | 5,571 |
| $ | 418 |
|
The following table provides certain operating statistics for our Mining segment (in thousands, except for Revenue per ton):
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 |
| Tons of coal sold | 927 |
| 614 |
| | 1,976 |
| 1,616 |
|
Cubic yards of overburden moved (a) | 1,961 |
| 1,686 |
| | 4,065 |
| 3,451 |
|
| | | | | | |
| Revenue per ton | $ | 16.12 |
| $ | 17.99 |
| | $ | 15.94 |
| $ | 16.91 |
|
____________
| |
(a) | Increase is driven by mining in areas with more overburden than in the prior year as well as higher production. |
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2018 | 2017 | | 2018 | 2017 |
| Tons of coal sold | 963 |
| 927 |
| | 2,041 |
| 1,976 |
|
| Cubic yards of overburden moved | 2,380 |
| 1,961 |
| | 4,402 |
| 4,065 |
|
| | | | | | |
| Revenue per ton | $ | 16.97 |
| $ | 16.12 |
| | $ | 16.12 |
| $ | 15.94 |
|
Results of Operations for Mining for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 2016:2017: Net income from continuing operations available for common stock for the Mining segment was $2.7$3.0 million for the three months ended June 30, 2017,2018, compared to Net income from continuing operations available for common stock of $0.7$2.7 million for the same period in 2016 as a result of:
2017. Revenue increased due to a 51%4% increase in tons sold partially offset byand a 10% decrease5% increase in price per ton sold. The increased tons sold were driven by an 11-week outage at the Wyodak plant last year. The decrease in price per ton sold was driven by contract price adjustments based on actual mining costs. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 46%51% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operations and maintenanceOperating expenses increased primarily due to higher major maintenance costsincreased overburden removal and higher royalties and production taxes on increased revenues.
Depreciation, depletion and amortization Other income (expense), net decreased primarilyfrom the prior year due to athe 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 asset retirement obligation costs.
Interest (expense)the federal corporate income net was comparable to the same period in the prior year.
Other income, net was comparable to the same period in the prior year.
Income tax benefit (expense): The effective tax rate increased reflecting a prior year tax benefit of percentage depletion.from 35% to 21% from the TCJA, effective January 1, 2018.
Results of Operations for Mining for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 2016:2017: Net income from continuing operations available for common stock for the Mining segment was $5.6$6.0 million for the six months ended June 30, 2017,2018, compared to Net income from continuing operations available for common stock of $3.7$5.6 million for the same period in 2016 as a result of:
2017. Revenue increased due to a 22%3% increase in tons sold partially offset byand a 6% decrease1% increase in price per ton sold. The increased tons sold were driven by an 11-week outage at the Wyodak plant last year. The decreaseCurrent year revenue is also reflective of lease and rental revenue, previously reported in price per ton sold was driven by contract price adjustments based on actual mining costs.Other income (expense), net. During the current period, approximately 46%49% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operations and maintenance
Operating expenses increased primarily due to increased overburden removal and higher major maintenance costs and royalties and production taxes on increased revenues. 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 related to previous years' other comprehensive items pursuant to the TCJA.
Corporate and amortization decreased primarily due to lower asset retirement obligation costs.Other
Interest (expense) income, net was comparable to the same period in the prior year.
Other income, net was comparable to the same period in the prior year.
Income tax benefit (expense): The effective tax rate increased reflecting a prior year tax benefit of percentage depletion.
Oil and Gas
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | 2016 | Variance | 2017 | 2016 | Variance |
| | (in thousands) |
| Revenue | $ | 6,149 |
| $ | 7,646 |
| $ | (1,497 | ) | $ | 12,624 |
| $ | 16,021 |
| $ | (3,397 | ) |
| | | | | | | |
| Operations and maintenance | 6,149 |
| 7,912 |
| (1,763 | ) | 14,309 |
| 16,947 |
| (2,638 | ) |
| Depreciation, depletion and amortization | 1,902 |
| 3,819 |
| (1,917 | ) | 3,909 |
| 7,932 |
| (4,023 | ) |
| Impairment of long-lived assets | — |
| 25,497 |
| (25,497 | ) | — |
| 39,993 |
| (39,993 | ) |
| Total operating expenses | 8,051 |
| 37,228 |
| (29,177 | ) | 18,218 |
| 64,872 |
| (46,654 | ) |
| | | | | | | |
| Operating income (loss) | (1,902 | ) | (29,582 | ) | 27,680 |
| (5,594 | ) | (48,851 | ) | 43,257 |
|
| | | | | | | |
| Interest income (expense), net | (1,083 | ) | (1,159 | ) | 76 |
| (2,190 | ) | (2,233 | ) | 43 |
|
| Other income (expense), net | 11 |
| 30 |
| (19 | ) | 17 |
| 69 |
| (52 | ) |
| Income tax benefit (expense) | 1,028 |
| 11,287 |
| (10,259 | ) | 2,870 |
| 24,567 |
| (21,697 | ) |
| | | | | | | |
| Net income (loss) | $ | (1,946 | ) | $ | (19,424 | ) | $ | 17,478 |
| $ | (4,897 | ) | $ | (26,448 | ) | $ | 21,551 |
|
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) |
Operating (loss) (a) | $ | (645 | ) | $ | (2,423 | ) | $ | 1,778 |
| $ | (2,285 | ) | $ | (5,782 | ) | $ | 3,497 |
|
| | | | | | | |
| Other income (expense): | | | | | | |
Interest (expense) income, net (a) | (519 | ) | (653 | ) | 134 |
| (1,184 | ) | (1,303 | ) | 119 |
|
| Other income (expense), net | 240 |
| (171 | ) | 411 |
| 182 |
| (838 | ) | 1,020 |
|
| Income tax benefit (expense) | (3,238 | ) | (515 | ) | (2,723 | ) | (1,833 | ) | 4,593 |
| (6,426 | ) |
| | | | | | | |
| Net income (loss) | $ | (4,162 | ) | $ | (3,762 | ) | $ | (400 | ) | $ | (5,120 | ) | $ | (3,330 | ) | $ | (1,790 | ) |
____________
| |
| (a) | Includes certain general and administrative expenses and interest expenses that are not reported as discontinued operations. |
Results of Operations for OilCorporate and GasOther for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 2016:2017: Net loss from continuing operations available for common stock for the OilCorporate and Gas segmentOther was $(1.9)$(4.2) million for the three months ended June 30, 2017,2018, compared to Net lossincome from continuing operations available for common stock of $(19)$(3.8) million for the same periodthree months ended June 30, 2017. The variance was driven by higher prior year operating costs previously allocated to BHEP which were not reclassified to discontinued operations. Income tax benefit (expense) increased in 2016 as a result of:
Revenue decreased primarilythe current year due to a 23% production decrease comparedhigher state income tax expense impacting our quarterly adjustment to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties, and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 25%. The lower production volumes and crude oil pricing was partially offset by a 68% increase in the average hedged price received for natural gas sold.
Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.
Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.
Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The prior year write-down of $25 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $11 million. The ceiling test write-down in the second quarter of 2016 used a trailing 12 month average NYMEX natural gas price of $2.24 per Mcf, adjusted to $1.01 per Mcf at the wellhead, and $43.12 per barrel for crude oil, adjusted to $37.19 per barrel at the wellhead.
Interest income (expense), net was comparable to the same period last year.
Other income (expense), net was comparable to the same period in the prior year.
Income tax (expense) benefit: Each period represents a tax benefit. Theprojected annual effective tax rate is comparable to the same period last year.rate.
Results of Operations for OilCorporate and GasOther for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 2016:2017: Net loss from continuing operations available for common stock for the OilCorporate and Gas segmentOther was $(4.9)$(5.1) million for the six months ended June 30, 2017,2018, compared to Net loss from continuing operations available for common stock of $(26)$(3.3) million for the same period in 2016 as a result of:
Revenue decreased primarily due to a 22% production decrease compared to the same period in the prior year. Natural gas production decreased primarily due to the 2016 sales of non-core properties and the intentional limiting of gas production to the minimum daily quantities required to meet contractual processing commitments in the Piceance Basin. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016. The average hedged price received for crude oil sold decreased 15%. The lower production volumes and crude oil pricing were partially offset by a 48% increase in the average hedged price received for natural gas sold.
Operations and maintenance decreased primarily due to lower employee costs and lower production and ad valorem taxes on lower revenue.
Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool resulting from the ceiling test impairments incurred in the prior year.
Impairment of long-lived assets represents a prior year non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The write down of $40 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $26 million. The ceiling test write-down for the six months ended June 30, 2016 used an average NYMEX natural gas price of $2.24 per Mcf, adjusted to $1.01 per Mcf at the well head, and $43.12 per barrel for crude oil, adjusted to $37.19 per barrel at the wellhead.
Interest income (expense), net was comparable2017. The variance to the same period last year.
Other income (expense), netprior year was comparabledriven by higher prior year operating costs previously allocated to the same periodBHEP which were not reclassified to discontinued operations and transition and acquisition expenses which occurred in the prior year.
The variance in Income tax benefit (expense) benefit: Each period representswas primarily due to a prior year tax benefit. Thebenefit of $1.4 million comprised primarily of benefits from a carryback claim for specified liability losses involving prior tax years, current year tax expense driven primarily by the adjustment to the projected annual effective tax rate for the six months ended June 30, 2016 reflects a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respectcompared to a change in estimate for tax purposes. Such deductions were primarily the result of a changebenefit recorded in the applicationprior year, and approximately $0.6 million of current year tax expense recorded pursuant to the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.TCJA.
The following tables provide certain operating statistics for our Oil and Gas segment:
|
| | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 |
| Production: | | | | | |
| Bbls of oil sold | 51,200 |
| 76,152 |
| | 94,402 |
| 174,219 |
|
| Mcf of natural gas sold | 1,962,088 |
| 2,435,454 |
| | 4,013,810 |
| 4,722,060 |
|
| Bbls of NGL sold | 26,986 |
| 40,892 |
| | 51,729 |
| 77,895 |
|
| Mcf equivalent sales | 2,431,204 |
| 3,137,718 |
| | 4,890,596 |
| 6,234,744 |
|
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | 2016 | | 2017 | 2016 |
Average price received: (a) | | | | | |
| Oil/Bbl | $ | 45.02 |
| $ | 60.16 |
| | $ | 45.38 |
| $ | 53.22 |
|
Gas/Mcf | $ | 1.56 |
| $ | 0.93 |
| | $ | 1.64 |
| $ | 1.11 |
|
| NGL/Bbl | $ | 16.04 |
| $ | 11.23 |
| | $ | 18.92 |
| $ | 10.82 |
|
| | | | | | |
| Depletion expense/Mcfe | $ | 0.41 |
| $ | 0.83 |
| | $ | 0.43 |
| $ | 0.88 |
|
__________
| |
(a) | Net of hedge settlement gains and losses. |
The following is a summary of certain average operating expenses per Mcfe:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2017 | | Three Months Ended June 30, 2016 |
| Producing Basin | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total |
| San Juan | $ | 1.55 |
| $ | 1.03 |
| $ | 0.34 |
| $ | 2.92 |
| | $ | 1.51 |
| $ | 1.05 |
| $ | 0.23 |
| $ | 2.79 |
|
| Piceance | 0.51 |
| 1.99 |
| 0.07 |
| 2.57 |
| | 0.34 |
| 1.80 |
| 0.09 |
| 2.23 |
|
| Powder River | 2.23 |
| — |
| 0.75 |
| 2.98 |
| | 2.95 |
| — |
| 0.57 |
| 3.52 |
|
| Williston | — |
| — |
| — |
| — |
| | 2.88 |
| — |
| 1.00 |
| 3.88 |
|
| All other properties | 1.57 |
| — |
| 0.24 |
| 1.81 |
| | 0.19 |
| — |
| 0.12 |
| 0.31 |
|
| Total weighted average | $ | 1.09 |
| $ | 1.37 |
| $ | 0.26 |
| $ | 2.72 |
| | $ | 1.07 |
| $ | 1.20 |
| $ | 0.23 |
| $ | 2.50 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| | Six Months Ended June 30, 2017 | | Six Months Ended June 30, 2016 |
| Producing Basin | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total |
| San Juan | $ | 1.71 |
| $ | 1.15 |
| $ | 0.39 |
| $ | 3.25 |
| | $ | 1.63 |
| $ | 1.07 |
| $ | 0.27 |
| $ | 2.97 |
|
| Piceance | 0.56 |
| 1.94 |
| 0.04 |
| 2.54 |
| | 0.34 |
| 1.87 |
| 0.11 |
| 2.32 |
|
| Powder River | 2.56 |
| — |
| 0.74 |
| 3.30 |
| | 2.78 |
| — |
| 0.56 |
| 3.34 |
|
| Williston | — |
| — |
| — |
| — |
| | 1.53 |
| — |
| 0.52 |
| 2.05 |
|
| All other properties | 1.58 |
| — |
| 0.31 |
| 1.89 |
| | 0.40 |
| — |
| 0.07 |
| 0.47 |
|
| Total weighted average | $ | 1.18 |
| $ | 1.39 |
| $ | 0.24 |
| $ | 2.81 |
| | $ | 1.08 |
| $ | 1.17 |
| $ | 0.24 |
| $ | 2.49 |
|
__________
| |
(a) | These costs include both third-party costs and operations costs. |
In the Piceance and San Juan Basins, our natural gas is transported through our own and third-party gathering systems and pipelines, for which we incur processing, gathering, compression and transportation fees. The sales price for natural gas, condensate and NGLs is reduced for these third-party costs, while the cost of operating our own gathering systems is included in operations and maintenance. The gathering, compression, processing and transportation costs shown in the tables above include amounts paid to third parties, as well as costs incurred in operations associated with our own gas gathering, compression, processing and transportation.
We have a ten-year gas gathering and processing contract for our natural gas production in the Piceance Basin which became effective in March of 2014. This take-or-pay contract requires us to pay a fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. Our gathering, compression and processing costs on a per Mcfe basis, as shown in the table above, will be higher in periods when we are not meeting the minimum contract requirements.
Corporate ActivityDiscontinued Operations
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | Six Months Ended June 30, |
| | 2018 | 2017 | Variance | 2018 | 2017 | Variance |
| | (in thousands) |
| Revenue | $ | 1,284 |
| $ | 6,149 |
| $ | (4,865 | ) | $ | 5,199 |
| $ | 12,624 |
| $ | (7,425 | ) |
| | | | | | | |
| Operations and maintenance | 2,718 |
| 5,491 |
| (2,773 | ) | 8,407 |
| 12,696 |
| (4,289 | ) |
| Loss (gain) on sale of operating assets | 1,991 |
| (249 | ) | 2,240 |
| 2,203 |
| (249 | ) | 2,452 |
|
| Depreciation, depletion and amortization | — |
| 1,838 |
| (1,838 | ) | 1,300 |
| 3,783 |
| (2,483 | ) |
| Total operating expenses | 4,709 |
| 7,080 |
| (2,371 | ) | 11,910 |
| 16,230 |
| (4,320 | ) |
| | | | | | | |
| Operating (loss) | (3,425 | ) | (931 | ) | (2,494 | ) | (6,711 | ) | (3,606 | ) | (3,105 | ) |
| | | | | | | |
| Other income (expense), net | 90 |
| 65 |
| 25 |
| 119 |
| 138 |
| (19 | ) |
| Income tax benefit (expense) | 908 |
| 250 |
| 658 |
| 1,822 |
| 1,283 |
| 539 |
|
| |
|
| | | | |
| (Loss) from discontinued operations available for common stock | $ | (2,427 | ) | $ | (616 | ) | $ | (1,811 | ) | $ | (4,770 | ) | $ | (2,185 | ) | $ | (2,585 | ) |
Results of Discontinued Operations for Corporate activities for the Three Months Ended June 30, 20172018 Compared to the Three Months Ended June 30, 2016: 2017:Net loss available for common stock for Corporatefrom discontinued operations was $(2.4) million for the three months ended June 30, 2017,2018, compared to Net loss available for common stockfrom discontinued operations of $(6.5)$(0.6) million for the three months ended June 30, 2016.same period in 2017. The variance fromto the prior year was primarilyis driven by lower revenues due to current year and prior year property sales and higher corporatelosses on sales of operating assets, partially offset by lower oil and gas operating expenses incurredand lower employee costs. Depreciation and depletion expense in the prior year related to the SourceGas Acquisition. The second quarteris reflective of 2016 included approximately $6.1 million of after-tax acquisition and transition costs, including $4.1 million of incremental non-recurring acquisition costs and $2.0 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments. The second quarter of 2016 also included lower income tax expense compared to the second quarter offull cost accounting, which continued through November 1, 2017.
Results of Discontinued Operations for Corporate activities for the Six Months Ended June 30, 20172018 Compared to the Six Months Ended June 30, 2016: 2017:Net loss available for common stock for Corporatefrom discontinued operations was $(0.6)$(4.8) million for the six months ended June 30, 2017,2018, compared to Net loss available for common stockfrom discontinued operations of $(22)$(2.2) million for the six months ended June 30, 2016.same period in 2017. The variance fromto the prior year was primarilyis driven by lower revenues due to current year and prior year property sales and higher corporatelosses on sales of operating assets, partially offset by lower oil and gas operating expenses incurredand lower employee costs. Current year depreciation expense is representative of the write-down of the remaining book value of accounting software. Depreciation and depletion expense in the prior year related to the SourceGas Acquisition. Current year corporate expenses include approximately $1.2 millionis reflective of after-tax acquisition and transition costs, compared to a total of approximately $26 million of after-tax acquisition and transition costs,full cost accounting, which included $20 million of non-recurring incremental acquisition and transition costs and approximately $5.7 million of after-tax internal labor related to the SourceGas Acquisition that otherwise would have been charged to other business segments. During the six months ended June 30, 2017, we recognized a tax benefit of approximately $1.4 million tax benefit from a carryback claim for specified liability losses involving prior years. The same period in the prior year included a tax benefit of approximately $4.4 million recognized as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.continued through November 1, 2017.
Critical Accounting Estimates
There have been no material changes in our critical accounting estimates from those reported in our 20162017 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 20162017 Annual Report on Form 10-K.
Liquidity and Capital Resources
OVERVIEW
Our Company requires significant cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we expect an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.
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.
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 Utilitiesutilities 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 June 30, 2017, we had $2.5 million of collateral posted related to our wholesale commodity contracts transactions. At June 30, 2017,2018, we had sufficient liquidity to cover any additional 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 assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. 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 in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers. We estimate the lower tax rate will negatively impact the Company’s cash flows by approximately $35 million to $45 million annually for 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 sixthree months ended June 30 (in thousands):
| | | Cash provided by (used in): | 2017 | 2016 | Increase (Decrease) | 2018 | 2017 | Increase (Decrease) |
| Operating activities | $ | 262,869 |
| $ | 183,503 |
| $ | 79,366 |
| $ | 310,701 |
| $ | 262,869 |
| $ | 47,832 |
|
| Investing activities | $ | (163,790 | ) | $ | (1,324,741 | ) | $ | 1,160,951 |
| $ | (163,526 | ) | $ | (163,530 | ) | $ | 4 |
|
| Financing activities | $ | (101,069 | ) | $ | 762,236 |
| $ | (863,305 | ) | $ | (153,701 | ) | $ | (101,069 | ) | $ | (52,632 | ) |
Year-to-Date 20172018 Compared to Year-to-Date 20162017
Operating Activities
Net cash provided by operating activities was $263$311 million for the six months ended June 30, 2017,2018, compared to net cash provided by operating activities of $184$263 million for the same period in 20162017 for a variance of $79$48 million. The variance was primarily attributable to:
Cash earnings (net income(income from continuing operations plus non-cash adjustments) were $48$0.8 million higherlower for the six months ended June 30, 20172018 compared to the same period in the prior year;
Net cash inflows from changes in operating assets and liabilities were $1.1$47 million for the six months ended June 30, 2017,2018, compared to net cash outflows of $20$6 million in the same period in the prior year. This $21$53 million variance was primarily due to:
| |
| ◦ | Cash inflows increaseddecreased by approximately $5.5$33 million for the six months ended June 30, 2017 primarily as a result of changesincreases in our accounts receivable and other operating assets driven by higher commodity prices,current year increase in revenues, partially offset by higherlower natural gas in storage for the six months ended June 30, 20172018 compared to the same period in the prior year; |
| |
| ◦ | Cash outflows decreased by approximately $11$21 million as a result of changesincreases in accounts payable and accrued liabilities driven by changes in working capital requirements, primarily related to acquisitionrequirements; and transaction costs that took place in the prior year; |
| |
| ◦ | Cash inflows increased by approximately $4.1$67 million as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impactscash collected from customers on working capitalbillings that do not reflect benefits of the TCJA compared to the same period in the prior year; andyear. |
Net cash outflows decreased by $10 million due to pension contributions made in the prior year.
Investing Activities
Net cash used in investing activities was $164 million for the six months ended June 30, 2017,2018, compared to net cash used in investing activities of $1.325 billion$164 million for the same period in 2016. The variance was primarily driven by:
The prior year’s cash outflows included $1.124 billion for2017. These were approximately the acquisition of SourceGas, net of $760 million of long term debt assumed (see Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details); andsame due to:
Capital expenditures of approximately $164$157 million for the six months ended June 30, 20172018 compared to $200$154 million for the six months ended June 30, 2016. The variance tosame period in the prior year. Higher current year was due primarily to higher prior year capital expenditures at our Electric Utilitiesgas utilities are offset by higher prior 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 $24 million investment partially offset by a $27 million change in net cash provided by investing activities from discontinued operations primarily from generation investments at Colorado Electric.due to the sale of assets held for sale.
Financing Activities
Net cash used in financing activities for the six months ended June 30, 20172018 was $101$154 million, compared to $762$101 million of net cash provided byused in financing activities for the same period in 2016. The $8632017 for a variance of $53 million. This variance is primarily due to higher current year short-term debt repayments of $101 million, variance was primarily driven by:
Proceeds of $216partially offset by a $50 million from the sale of a 49.9% noncontrolling interest of Colorado IPP that took place in the prior year;
Long-term borrowings were higherterm loan payment in the prior year due to the $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract;higher current year dividend payments.
Net short-term borrowings increased by $13 million primarily due to CP borrowings used to pay down other long-term debt;
Proceeds from common stock decreased by approximately $54 million due to prior year stock issuances under our ATM equity offering program;
Current year distributions to noncontrolling interests of $8.3 million;
Increased dividend payments of approximately $4.3 million;
Higher current year payments on long-term debt of $11 million; and
Higher other financing activities in the current year primarily driven by the $5.6 million paid for a redeemable noncontrolling interest in March 2017.
Dividends
Dividends paid on our common stock totaled $48$51 million for the six months ended June 30, 2017,2018, or $0.445$0.475 per share.share per quarter. On July 26, 2017,25, 2018, our board of directors declared a quarterly dividend of $0.445$0.475 per share payable September 1, 2017, which is2018, equivalent to an annual dividend rate of $1.78$1.90 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.
Debt
Financing Transactions and Short-Term Liquidity
Our principal sources to meet day-to-day operating cash requirements are cash from operations, our CP Program and our corporate Revolving Credit Facility.
Revolving Credit Facility and CP Program
On August 9, 2016,July 30, 2018, we amended and restated our corporate Revolving Credit Facility, to increasemaintaining total commitments toof $750 million from $500 million and extendedextending the term through August 9, 2021July 30, 2023 with two one-year extension options.options (subject to consent from lenders). This facility is similar to the former agreement,revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, andthe issuing agents and each bank increasing or providing a new commitment, to increase total commitments of the facility to up to $1$1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P or Moody’sSee Note 9 for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at June 30, 2017. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.more information.
On December 22, 2016, we implementedWe 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.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 | Revolver Borrowings at | CP Program Borrowings at | Letters of Credit at | Available Capacity at |
| Credit Facility | Expiration | Capacity | June 30, 2017 | June 30, 2017 | Expiration | Capacity | June 30, 2018 | June 30, 2018 |
| Revolving Credit Facility | August 9, 2021 | $ | 750 |
| $ | — |
| $ | 108 |
| $ | 25 |
| $ | 617 |
| July 30, 2023 | $ | 750 |
| $ | — |
| $ | 122 |
| $ | 11 |
| $ | 617 |
|
The weighted average interest rate on CP Program borrowings at June 30, 20172018 was 1.41%2.29%. Revolving Credit Facility and CP Program financing activity for the six months ended June 30, 20172018 was (dollars in millions):
| | | | For the Six Months Ended June 30, 2017 | For the Six Months Ended June 30, 2018 |
| Maximum amount outstanding - commercial paper (based on daily outstanding balances) | $ | 122 |
| $ | 231 |
|
| Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | 97 |
| $ | — |
|
Average amount outstanding - commercial paper (based on daily outstanding balances) (a) | $ | 72 |
| $ | 146 |
|
Average amount outstanding - revolving credit facility (based on daily outstanding balances) (a) | $ | 55 |
| $ | — |
|
Weighted average interest rates - commercial paper (a) | 1.19 | % | 2.13 | % |
Weighted average interest rates - revolving credit facility (a) | 2.07 | % | — | % |
__________
| |
(a) | Averages for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program. |
The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness which(which includes letters of credit and certain guarantees issued andbut excludes RSNsthe RSNs), by (ii) Capital, which includesis Consolidated Indebtedness plus Consolidated Net Worth which(which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs.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 June 30, 2017.2018.
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 six months ended June 30, 20172018 consisted of short-term borrowings from our Revolving Credit Facility and CP Program. We also made a principal paymentOn August 4, 2017, we renewed the ATM equity offering program which reset the size of $50 million on our Corporate term loan due August 9, 2019. An additional $50 million was paid on the same term loan on July 17, 2017. Short-term borrowings from our CPATM equity offering program were used to fund the payments on the Corporate term loan.an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program.program for the six months ended June 30, 2018.
In addition toOn 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 June 30, 2018, will now mature July 30, 2020 and has substantially similar terms and covenants as the CP Programamended and amendedrestated Revolving Credit Facility discussed above, other financing activities from the prior year consisted of completing the permanent financingFacility. See Note 9 for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued a total of 1.97 million shares of common stock throughout 2016 for net proceeds of approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million in April 2016.more information.
Future Financing Plans
The terms of the Equity Units require us to remarket the RSNs on behalf of the holders of the Equity Units in advance of November 1, 2018, the scheduled settlement of the purchase contracts included in the Equity Units. We intend to satisfy this requirement by conducting an optional remarketing of the RSNs. We will not directly receive the proceeds of the remarketing. Instead, the proceeds from the sale of the RSNs will be invested on behalf of the holders of our Equity Units in a portfolio of treasury securities, which will be pledged to secure (and may eventually be used to satisfy) the obligations of the holders of the Equity Units to purchase $299 million of our common stock on November 1, 2018 in settlement of the purchase contracts included in the Equity Units. We anticipate using the following financing activities:net proceeds from such settlement to pay down debt and for general corporate purposes.
Renewing our shelf registrationIn connection with the optional remarketing of the RSNs, we also expect to undertake a series of transactions that may result in the exchange or modification of the RSNs, which would result in modification of the interest rate, maturity, covenants, seniority, and ATM equity offering program; expected filing on August 4, 2017;
Remarketingother terms, and may also include the junior subordinatedissuance of additional senior unsecured notes maturing in 2018;
Evaluating a one-to-two year extension of our Revolving Credit Facilitythe same series as the RSNs as so modified. We anticipate using any net proceeds from the issuance of any such additional senior unsecured notes to pay down debt and CP program to be completed in 2018; and
Evaluating refinancing options for term loan and short-term borrowings under Revolving Credit Facility and CP program.general corporate purposes.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. As of June 30, 20172018, 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 loansloan 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(which includes letters of credit and certain guarantees issued andbut excludes RSNsthe RSNs), by (ii) Capital, which includesis Consolidated Indebtedness plus Consolidated Net Worth which(which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs.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’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of June 30, 2017,2018, we were in compliance with these covenants.
There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 20162017 Annual Report on Form 10-K filed with the SEC.
Credit Ratings
Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and the credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings and outlook and risk profile of BHC at June 30, 2017:2018:
|
| | |
| Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB | StablePositive |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
__________
| |
| (a) | On July 21, 2017,March 8, 2018, S&P affirmed BBB rating and revised the outlook to Positive. |
| |
| (b) | On December 12, 2017, Moody’s affirmed our Baa2 rating and maintained a Stable outlook. |
| |
(b) | On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition. |
| |
| (c) | On March 29,October 4, 2017, Fitch affirmed BBB+ rating and changed their outlook from Negative tomaintained a Stable citing successful integration of SourceGas, a low business risk profile focused on utility operations and expected improvement of credit metrics.outlook. |
The following table represents the credit ratings of Black Hills PowerSouth Dakota Electric at June 30, 2017:2018:
|
| |
| Rating Agency | Senior Secured Rating |
| S&P | A- |
| Moody’s | A1 |
Fitch(a) | A |
__________
There were no rating changes for Black Hills Power from previously disclosed ratings.
| |
| (a) | On July 19, 2018, Fitch affirmed A rating. |
Capital Requirements
Capital Expenditures
Actual and forecasted capital requirements are as follows (in thousands):
| | | | Expenditures for the | | Total | | Total | | Total | Expenditures for the | | Total | | Total | | Total |
| | Six Months Ended June 30, 2017 (a) | | 2017 Planned Expenditures (b) | | 2018 Planned Expenditures | | 2019 Planned Expenditures | Six Months Ended June 30, 2018 (a) | | 2018 Planned Expenditures (b) | | 2019 Planned Expenditures | | 2020 Planned Expenditures |
| Electric Utilities | $ | 80,529 |
| | $ | 126,000 |
| | $ | 128,000 |
| | $ | 192,000 |
| $ | 55,729 |
| | $ | 149,000 |
| | $ | 193,000 |
| | $ | 141,000 |
|
Gas Utilities | 73,696 |
| | 185,000 |
| | 213,000 |
| | 260,000 |
| 98,691 |
| | 268,000 |
| | 328,000 |
| | 245,000 |
|
Power Generation | 1,823 |
| | 2,000 |
| | 3,000 |
| | 8,000 |
| 1,721 |
| | 32,000 |
| | 56,000 |
| | 5,000 |
|
| Mining | 4,037 |
| | 7,000 |
| | 7,000 |
| | 8,000 |
| 6,210 |
| | 19,000 |
| | 7,000 |
| | 7,000 |
|
Oil and Gas (c) | 11,782 |
| | 20,000 |
| | 1,000 |
| | — |
| |
| Corporate | 2,603 |
| | 10,000 |
| | 12,000 |
| | 10,000 |
| |
| Corporate and Other | | 5,075 |
| | 10,000 |
| | 13,000 |
| | 8,000 |
|
| | $ | 174,470 |
| | $ | 350,000 |
| | $ | 364,000 |
| | $ | 478,000 |
| $ | 167,426 |
| | $ | 478,000 |
| | $ | 597,000 |
| | $ | 406,000 |
|
__________
(a) Expenditures for the six months ended June 30, 20172018 include the impact of accruals for property, plant and equipment.
(b) Includes actual capital expenditures for the six months ended June 30, 2017.
| |
(c) | Expenditures reflect the completion of two wells previously drilled in 2015 to meet minimum daily quantity requirements for the Piceance Basin gathering and processing contract. |
2018.
We have updated our planned(c) Planned capital expenditures for 2018 and 2019 increased due to the Busch Ranch II wind project.
(d) Planned capital expenditures to primarily reflect the following:
additional planned transmission and distribution investments at our Electric Utilities infor 2018 and 2019; and
additional planned growth and integrity investments in our Gas utilities, primarily as a result of gaining further knowledge of2019 increased due to the SourceGas utilities.Natural Bridge Pipeline project.
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 20162017 Annual Report on Form 10-K except for those described in Note 16 of the Notes to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.10-K.
Guarantees
There have been no significant changes to guarantees from those previously disclosed in Note 20 of the Notes to the Consolidated Financial Statements in our 20162017 Annual Report on Form 10-K.
New Accounting Pronouncements
Other than the pronouncements reported in our 20162017 Annual Report on Form 10-K filed with the SEC and those discussed in Note 1 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial position, results of operations, or cash flows.
FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement was made, and themade. 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 20162017 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 20162017 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.
| |
| ITEM 3. | 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 Group’sutilities’ derivative contracts is summarized below (in thousands) as of:
| | | | June 30, 2017 | | December 31, 2016 | | June 30, 2016 | June 30, 2018 | | December 31, 2017 | | June 30, 2017 |
| Net derivative (liabilities) assets | $ | (7,075 | ) | | $ | (4,733 | ) | | $ | (7,894 | ) | $ | (5,117 | ) | | $ | (6,644 | ) | | $ | (7,075 | ) |
| Cash collateral offset in Derivatives | 6,950 |
| | 7,882 |
| | 10,251 |
| 3,997 |
| | 7,694 |
| | 6,950 |
|
| Cash collateral included in Other current assets | 2,339 |
| | 4,840 |
| | 8,067 |
| 1,913 |
| | 562 |
| | 2,339 |
|
| Net asset (liability) position | $ | 2,214 |
| | $ | 7,989 |
| | $ | 10,424 |
| $ | 793 |
| | $ | 1,612 |
| | $ | 2,214 |
|
Oil and Gas Activities
We have entered into agreements to hedge a portion of our estimated 2017 and 2018 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at June 30, 2017, were as follows:
Natural Gas
|
| | | | | | | | | | | | | | | |
| | March 31 | June 30 | September 30 | December 31 | Total Year |
| 2017 | | | | | |
| Swaps - MMBtu | — |
| — |
| 540,000 |
| 540,000 |
| 1,080,000 |
|
| Weighted Average Price per MMBtu | $ | — |
| $ | — |
| $ | 3.04 |
| $ | 3.04 |
| $ | 3.04 |
|
Crude Oil
|
| | | | | | | | | | | | | | | |
| | March 31 | June 30 | September 30 | December 31 | Total Year |
| 2017 | | | | | |
| Swaps - Bbls | — |
| — |
| 18,000 |
| 18,000 |
| 36,000 |
|
| Weighted Average Price per Bbl | $ | — |
| $ | — |
| $ | 51.55 |
| $ | 52.33 |
| $ | 51.94 |
|
| | | | | | |
| Calls - Bbls | — |
| — |
| 9,000 |
| 9,000 |
| 18,000 |
|
| Weighted Average Price per Bbl | $ | — |
| $ | — |
| $ | 50.00 |
| $ | 50.00 |
| $ | 50.00 |
|
| | | | | | |
| 2018 | | | | | |
| Swaps - Bbls | 9,000 |
| 9,000 |
| 9,000 |
| 9,000 |
| 36,000 |
|
| Weighted Average Price per Bbl | $ | 49.58 |
| $ | 49.85 |
| $ | 50.12 |
| $ | 50.45 |
| $ | 50.00 |
|
The fair value of our Oil and Gas segment’s derivative contracts is summarized below (in thousands) as of:
|
| | | | | | | | | | | |
| | June 30, 2017 | | December 31, 2016 | | June 30, 2016 |
| Net derivative (liabilities) assets | $ | 497 |
| | $ | (1,433 | ) | | $ | 2,520 |
|
| Cash collateral offset in Derivatives | 230 |
| | 2,733 |
| | (1,150 | ) |
| Cash Collateral included in Other current assets | — |
| | — |
| | — |
|
| Net asset (liability) position | $ | 727 |
| | $ | 1,300 |
| | $ | 1,370 |
|
Financing Activities
We engage in activities to manage risks associated with changes in interest rates. Historically, we have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated long-termdebt refinancings. Further details of theAt June 30, 2018, December 31, 2017 and June 30, 2017, we had no outstanding interest rate swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K and in Note 10 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.agreements.
The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
|
| | | | | | | | | | | | | | | | | |
| | June 30, 2017 | | December 31, 2016 | | June 30, 2016 |
| | Designated
Interest Rate
Swaps | | Designated
Interest Rate
Swap (a) | | Designated
Interest Rate
Swap (b) | Designated
Interest Rate
Swap (b) | Designated
Interest Rate
Swaps (a) |
| Notional | $ | — |
| | $ | 50,000 |
| | $ | 150,000 |
| $ | 250,000 |
| $ | 75,000 |
|
| Weighted average fixed interest rate | — | % | | 4.94 | % | | 2.09 | % | 2.29 | % | 4.97 | % |
| Maximum terms in months | 0 |
| | 1 |
| | 10 |
| 10 |
| 6 |
|
| Derivative assets, non-current | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
|
| Derivative liabilities, current | $ | — |
| | $ | 90 |
| | $ | 8,553 |
| $ | 18,500 |
| $ | 1,505 |
|
| Derivative liabilities, non-current | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
|
| Pre-tax accumulated other comprehensive income (loss) | $ | — |
| | $ | (90 | ) | | $ | (8,553 | ) | $ | (18,500 | ) | $ | (1,505 | ) |
__________
| |
(a) | The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. |
| |
(b) | These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt. |
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 June 30, 20172018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 2017.2018.
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 June 30, 2017,2018, 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 20162017 Annual Report on Form 10-K and Note 1617 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 1617 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 20162017 Annual Report on Form 10-K filed with the SEC.
| |
| ITEM 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
There were no unregistered securities sold during the six months ended June 30, 2017.2018.
| |
| 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.
|
| |
| Exhibit Number | Description |
| | |
Exhibit 2.1* | Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant's Form 8-K file on July 14, 2015). First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015). |
| |
Exhibit 2.2* | Option Agreement by and among Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant's Form 8-K file on July 14, 2015). |
| |
Exhibit 2.3* | Guaranty of Black Hills Corporation in favor of Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, dated as of July 12, 2015 (filed as Exhibit 2.3 to the Registrant's Form 8-K file on July 14, 2015). |
| |
Exhibit 3.1* | |
| | |
| Exhibit 3.2* | |
| | |
| Exhibit 4.1* | |
| |
| |
| |
| |
| |
| |
| |
| | |
| Exhibit 4.2* | |
| |
| |
| |
| | |
| Exhibit 4.3* | |
| |
| |
| | |
| Exhibit 4.4* | |
| |
| |
|
| |
| |
| Exhibit 4.5* | |
| | |
| Exhibit 4.6* | Indenture dated as of April 16, 2007 between SourceGas LLC and U.S. Bank National Association, as Trustee (relating to $325 million, 5.90% Senior Notes due 2017) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on March 18, 2016). |
| |
Exhibit 4.7* | |
| |
| Exhibit 10.1 |
|
| |
| Exhibit 10.2 |
|
| |
| Exhibit 12 | |
| | |
| Exhibit 31.1 | |
| | |
| Exhibit 31.2 | |
| | |
| Exhibit 32.1 | |
| | |
| Exhibit 32.2 | |
| | |
| Exhibit 95 | |
| | |
| Exhibit 101 | Financial Statements for XBRL Format. |
__________
| |
| * | Previously filed as part of the filing indicated and incorporated by reference herein. |
| |
† | Indicates a board of director or management compensatory plan. |
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
|
| | |
| | | /s/ David R. Emery |
| | | David R. Emery, Chairman and |
| | | Chief Executive Officer |
| | | |
| | | /s/ Richard W. Kinzley |
| | | Richard W. Kinzley, Senior Vice President and |
| | | Chief Financial Officer |
| | | |
| Dated: | August 4, 2017 | |
INDEX TO EXHIBITS
|
| |
Exhibit Number | Description |
| |
Exhibit 2.1* | Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant's Form 8-K file on July 14, 2015). First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015). |
| |
Exhibit 2.2* | Option Agreement by and among Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant's Form 8-K file on July 14, 2015). |
| |
Exhibit 2.3* | Guaranty of Black Hills Corporation in favor of Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, dated as of July 12, 2015 (filed as Exhibit 2.3 to the Registrant's Form 8-K file on July 14, 2015). |
| |
Exhibit 3.1* | Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004). |
| |
Exhibit 3.2* | Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017). |
| |
Exhibit 4.1* | Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrants’ Form 8-K filed on November 18, 2013). Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016). Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016). |
| |
Exhibit 4.2* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014). |
| |
Exhibit 4.3* | Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014). First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014). Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014). |
| 7, 2018 | |
|
| |
Exhibit 4.4* | Junior Subordinated Indenture dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on November 23, 2015). First Supplemental Indenture dated as of November 23, 2015 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on November 23, 2015). |
| |
Exhibit 4.5* | Purchase Contract and Pledge Agreement dated as of November 23, 2015 between Black Hills Corporation and U.S. Bank National Association, as purchase contract agent, collateral agent, custodial agent and securities intermediary (filed as Exhibit 4.4 to the Registrant’s Form 8-K filed on November 23, 2015). |
| |
Exhibit 4.6* | Indenture dated as of April 16, 2007 between SourceGas LLC and U.S. Bank National Association, as Trustee (relating to $325 million, 5.90% Senior Notes due 2017) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on March 18, 2016). |
| |
Exhibit 4.7* | Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000). |
| |
Exhibit 31.1 | Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
| |
Exhibit 31.2 | Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
| |
Exhibit 32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. |
| |
Exhibit 32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. |
| |
Exhibit 95 | Mine Safety and Health Administration Safety Data. |
| |
Exhibit 101 | Financial Statements for XBRL Format. |
__________
| |
* | Previously filed as part of the filing indicated and incorporated by reference herein. |
| |
† | Indicates a board of director or management compensatory plan. |