x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
EXCHANGE ACT OF 1934 | |
For the quarterly period ended March 31, 2015 | |
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 Street | |
Rapid City, South Dakota 57701 | |
Registrant’s telephone number (605) 721-1700 | |
Former name, former address, and former fiscal year if changed since last report | |
NONE | |
Yes x | No o | |||
Yes x | No o | |||
Large accelerated filer x | Accelerated filer o | |||
Non-accelerated filer o | Smaller reporting company o | |||
Yes o | No x | |||
Class | Outstanding at April 30, 2015 | ||
Common stock, $1.00 par value | 44,821,847 | shares | |
TABLE OF CONTENTS | |||
Page | |||
Glossary of Terms and Abbreviations | |||
PART I. | FINANCIAL INFORMATION | ||
Item 1. | Financial Statements | ||
Condensed Consolidated Statements of Income (Loss) - unaudited | |||
Three Months Ended March 31, 2015 and 2014 | |||
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited | |||
Three Months Ended March 31, 2015 and 2014 | |||
Condensed Consolidated Balance Sheets - unaudited | |||
March 31, 2015, December 31, 2014 and March 31, 2014 | |||
Condensed Consolidated Statements of Cash Flows - unaudited | |||
Three Months Ended March 31, 2015 and 2014 | |||
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 | |||
AFUDC | Allowance for Funds Used During Construction |
AOCI | Accumulated Other Comprehensive Income (Loss) |
ASU | Accounting Standards Update issued by the FASB |
Bbl | Barrel |
BHC | Black Hills Corporation; the Company |
Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Black Hills Energy | The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries |
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 |
Black Hills Utility Holdings | Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation |
Black Hills Wyoming | Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation |
Btu | British thermal unit |
Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation |
Cheyenne Prairie | Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014. |
Colorado Electric | Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings |
Colorado IPP | Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation |
CPCN | Certificate of Public Convenience and Necessity |
CPUC | Colorado Public Utilities Commission |
CVA | Credit Valuation Adjustment |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
Dth | Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu) |
Energy West | Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc. |
FASB | Financial Accounting Standards Board |
Fitch | Fitch Ratings |
GAAP | Accounting principles generally accepted in the United States of America |
GHG | Greenhouse Gases |
GCA | Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of natural gas and certain services through to customers. |
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. |
Heating Degree Day | 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. |
IFRS | International Financial Reporting Standards |
Iowa Gas | Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings |
IPP | Independent power producer |
IRS | United States Internal Revenue Service |
IUB | Iowa Utilities Board |
Kansas Gas | Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings |
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. |
MW | Megawatts |
MWh | Megawatt-hours |
NGL | Natural Gas Liquids (1 barrel equals 6 Mcfe) |
NPSC | Nebraska Public Service Commission |
PPA | Power Purchase Agreement |
Revolving Credit Facility | Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019. |
SDPUC | South Dakota Public Utilities Commission |
SEC | U. S. Securities and Exchange Commission |
S&P | Standard and Poor’s, a division of The McGraw-Hill Companies, Inc. |
WPSC | Wyoming Public Service Commission |
WRDC | Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
(unaudited) | Three Months Ended March 31, | |||||
2015 | 2014 | |||||
(in thousands, except per share amounts) | ||||||
Revenue | $ | 441,987 | $ | 460,169 | ||
Operating expenses: | ||||||
Utilities - | ||||||
Fuel, purchased power and cost of natural gas sold | 205,327 | 230,468 | ||||
Operations and maintenance | 71,084 | 71,227 | ||||
Non-regulated energy operations and maintenance | 22,050 | 22,332 | ||||
Depreciation, depletion and amortization | 39,586 | 36,083 | ||||
Taxes - property, production and severance | 11,936 | 10,336 | ||||
Other operating expenses | 52 | 125 | ||||
Total operating expenses | 350,035 | 370,571 | ||||
Operating income | 91,952 | 89,598 | ||||
Other income (expense): | ||||||
Interest charges - | ||||||
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps) | (19,910 | ) | (17,860 | ) | ||
Allowance for funds used during construction - borrowed | 158 | 270 | ||||
Capitalized interest | 276 | 257 | ||||
Interest income | 448 | 390 | ||||
Allowance for funds used during construction - equity | 56 | 238 | ||||
Other income (expense), net | 331 | 592 | ||||
Total other income (expense), net | (18,641 | ) | (16,113 | ) | ||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 73,311 | 73,485 | ||||
Equity in earnings (loss) of unconsolidated subsidiaries | (297 | ) | (1 | ) | ||
Income tax benefit (expense) | (25,120 | ) | (25,366 | ) | ||
Net income (loss) available for common stock | $ | 47,894 | $ | 48,118 | ||
Earnings (loss) per share of common stock: | ||||||
Earnings (loss) per share, Basic | $ | 1.08 | $ | 1.09 | ||
Earnings (loss) per share, Diluted | $ | 1.07 | $ | 1.08 | ||
Weighted average common shares outstanding: | ||||||
Basic | 44,541 | 44,330 | ||||
Diluted | 44,660 | 44,554 | ||||
Dividends declared per share of common stock | $ | 0.405 | $ | 0.390 | ||
(unaudited) | Three Months Ended March 31, | |||||
2015 | 2014 | |||||
(in thousands) | ||||||
Net income (loss) available for common stock | $ | 47,894 | $ | 48,118 | ||
Other comprehensive income (loss), net of tax: | ||||||
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(1,042) and $1,307 for the three months ended 2015 and 2014, respectively) | 1,836 | (2,257 | ) | |||
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $1,254 and $(425) for the three months ended 2015 and 2014, respectively) | (1,241 | ) | 780 | |||
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $15 and $2 for the three months ended 2015 and 2014, respectively) | (27 | ) | (2 | ) | ||
Benefit plan liability adjustments - prior service cost (net of tax (expense) benefit of $(90) for the three months ended 2014 | — | 164 | ||||
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $4 for the three months ended 2015 and 2014, respectively) | (36 | ) | (9 | ) | ||
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(247) and $(85) for the three months ended 2015 and 2014, respectively) | 458 | 157 | ||||
Other comprehensive income (loss), net of tax | 990 | (1,167 | ) | |||
Comprehensive income (loss) available for common stock | $ | 48,884 | $ | 46,951 | ||
(unaudited) | As of | ||||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
(in thousands) | |||||||||||
ASSETS | |||||||||||
Current assets: | |||||||||||
Cash and cash equivalents | $ | 63,385 | $ | 21,218 | $ | 17,641 | |||||
Restricted cash and equivalents | 2,191 | 2,056 | 2 | ||||||||
Accounts receivable, net | 178,421 | 189,992 | 203,625 | ||||||||
Materials, supplies and fuel | 66,626 | 91,191 | 66,187 | ||||||||
Derivative assets, current | — | — | 1,846 | ||||||||
Income tax receivable, net | 159 | 2,053 | 1,826 | ||||||||
Deferred income tax assets, net, current | 23,913 | 48,288 | 25,780 | ||||||||
Regulatory assets, current | 56,542 | 74,396 | 62,946 | ||||||||
Other current assets | 47,448 | 24,842 | 24,563 | ||||||||
Total current assets | 438,685 | 454,036 | 404,416 | ||||||||
Investments | 17,210 | 17,294 | 16,916 | ||||||||
Property, plant and equipment | 4,652,058 | 4,563,400 | 4,318,194 | ||||||||
Less: accumulated depreciation and depletion | (1,351,857 | ) | (1,324,025 | ) | (1,298,398 | ) | |||||
Total property, plant and equipment, net | 3,300,201 | 3,239,375 | 3,019,796 | ||||||||
Other assets: | |||||||||||
Goodwill | 353,396 | 353,396 | 353,396 | ||||||||
Intangible assets, net | 3,121 | 3,176 | 3,342 | ||||||||
Regulatory assets, non-current | 178,935 | 183,443 | 138,173 | ||||||||
Other assets, non-current | 28,280 | 29,086 | 28,925 | ||||||||
Total other assets, non-current | 563,732 | 569,101 | 523,836 | ||||||||
TOTAL ASSETS | $ | 4,319,828 | $ | 4,279,806 | $ | 3,964,964 | |||||
(unaudited) | As of | ||||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
(in thousands, except share amounts) | |||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
Current liabilities: | |||||||||||
Accounts payable | $ | 88,770 | $ | 124,139 | $ | 149,681 | |||||
Accrued liabilities | 166,781 | 170,115 | 145,973 | ||||||||
Derivative liabilities, current | 3,342 | 3,340 | 3,498 | ||||||||
Regulatory liabilities, current | 17,621 | 3,687 | 583 | ||||||||
Notes payable | 102,600 | 75,000 | 100,000 | ||||||||
Current maturities of long-term debt | — | 275,000 | — | ||||||||
Total current liabilities | 379,114 | 651,281 | 399,735 | ||||||||
Long-term debt, net of current maturities | 1,542,658 | 1,267,589 | 1,396,949 | ||||||||
Deferred credits and other liabilities: | |||||||||||
Deferred income tax liabilities, net, non-current | 522,290 | 523,716 | 466,856 | ||||||||
Derivative liabilities, non-current | 2,143 | 2,680 | 4,805 | ||||||||
Regulatory liabilities, non-current | 148,918 | 145,144 | 116,793 | ||||||||
Benefit plan liabilities | 162,334 | 158,966 | 113,324 | ||||||||
Other deferred credits and other liabilities | 154,604 | 154,406 | 129,083 | ||||||||
Total deferred credits and other liabilities | 990,289 | 984,912 | 830,861 | ||||||||
Commitments and contingencies (See Notes 7, 8, 13, 14) | |||||||||||
Stockholders’ equity: | |||||||||||
Common stock equity — | |||||||||||
Common stock $1 par value; 100,000,000 shares authorized; issued 44,856,790; 44,714,072; and 44,666,953 shares, respectively | 44,857 | 44,714 | 44,667 | ||||||||
Additional paid-in capital | 749,517 | 748,840 | 742,016 | ||||||||
Retained earnings | 629,135 | 599,389 | 570,963 | ||||||||
Treasury stock, at cost – 33,755; 42,226; and 37,038 shares, respectively | (1,688 | ) | (1,875 | ) | (1,638 | ) | |||||
Accumulated other comprehensive income (loss) | (14,054 | ) | (15,044 | ) | (18,589 | ) | |||||
Total stockholders’ equity | 1,407,767 | 1,376,024 | 1,337,419 | ||||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 4,319,828 | $ | 4,279,806 | $ | 3,964,964 | |||||
(unaudited) | Three Months Ended March 31, | |||||
2015 | 2014 | |||||
Operating activities: | (in thousands) | |||||
Net income (loss) available for common stock | $ | 47,894 | $ | 48,118 | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 39,586 | 36,083 | ||||
Deferred financing cost amortization | 519 | 568 | ||||
Stock compensation | 2,083 | 3,716 | ||||
Deferred income taxes | 22,048 | 25,953 | ||||
Employee benefit plans | 5,283 | 3,703 | ||||
Other adjustments, net | 6,748 | 5,190 | ||||
Changes in certain operating assets and liabilities: | ||||||
Materials, supplies and fuel | 25,689 | 22,291 | ||||
Accounts receivable, unbilled revenues and other operating assets | 47,947 | (78,576 | ) | |||
Accounts payable and other operating liabilities | (44,652 | ) | 29,074 | |||
Other operating activities, net | (1,658 | ) | 1,978 | |||
Net cash provided by (used in) operating activities | 151,487 | 98,098 | ||||
Investing activities: | ||||||
Property, plant and equipment additions | (117,523 | ) | (83,609 | ) | ||
Other investing activities | (348 | ) | (3,220 | ) | ||
Net cash provided by (used in) investing activities | (117,871 | ) | (86,829 | ) | ||
Financing activities: | ||||||
Dividends paid on common stock | (18,148 | ) | (17,399 | ) | ||
Common stock issued | 999 | 881 | ||||
Short-term borrowings - issuances | 77,700 | 86,800 | ||||
Short-term borrowings - repayments | (50,100 | ) | (69,300 | ) | ||
Other financing activities | (1,900 | ) | (2,451 | ) | ||
Net cash provided by (used in) financing activities | 8,551 | (1,469 | ) | |||
Net change in cash and cash equivalents | 42,167 | 9,800 | ||||
Cash and cash equivalents, beginning of period | 21,218 | 7,841 | ||||
Cash and cash equivalents, end of period | $ | 63,385 | $ | 17,641 | ||
Three Months Ended March 31, 2015 | External Operating Revenue | Inter-company Operating Revenue | Net Income (Loss) | |||||||||
Utilities: | ||||||||||||
Electric | $ | 182,974 | $ | 3,424 | $ | 18,929 | ||||||
Gas | 237,651 | — | 22,212 | |||||||||
Non-regulated Energy: | ||||||||||||
Power Generation | 1,953 | 20,721 | 8,145 | |||||||||
Coal Mining | 8,142 | 7,792 | 3,010 | |||||||||
Oil and Gas | 11,267 | — | (5,071 | ) | ||||||||
Corporate activities | — | — | 669 | |||||||||
Inter-company eliminations | — | (31,937 | ) | — | ||||||||
Total | $ | 441,987 | $ | — | $ | 47,894 | ||||||
Three Months Ended March 31, 2014 | External Operating Revenue | Inter-company Operating Revenue | Net Income (Loss) | |||||||||
Utilities: | ||||||||||||
Electric | $ | 178,095 | $ | 4,007 | $ | 14,575 | ||||||
Gas | 259,337 | — | 24,698 | |||||||||
Non-regulated Energy: | ||||||||||||
Power Generation | 1,269 | 21,079 | 8,073 | |||||||||
Coal Mining | 6,618 | 8,880 | 2,464 | |||||||||
Oil and Gas | 14,850 | — | (2,022 | ) | ||||||||
Corporate activities | — | — | 330 | |||||||||
Inter-company eliminations | — | (33,966 | ) | — | ||||||||
Total | $ | 460,169 | $ | — | $ | 48,118 | ||||||
Total Assets (net of inter-company eliminations) as of: | March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||||
Utilities: | |||||||||||
Electric (a) | $ | 2,817,423 | $ | 2,748,680 | $ | 2,572,616 | |||||
Gas | 839,802 | 906,922 | 842,660 | ||||||||
Non-regulated Energy: | |||||||||||
Power Generation (a) | 75,945 | 76,945 | 90,643 | ||||||||
Coal Mining | 77,399 | 74,407 | 74,523 | ||||||||
Oil and Gas | 403,657 | 366,247 | 295,083 | ||||||||
Corporate activities | 105,602 | 106,605 | 89,439 | ||||||||
Total assets | $ | 4,319,828 | $ | 4,279,806 | $ | 3,964,964 | |||||
(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. |
Accounts | Unbilled | Less Allowance for | Accounts | |||||||||
March 31, 2015 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | ||||||||
Electric Utilities | $ | 53,862 | $ | 24,540 | $ | (834 | ) | $ | 77,568 | |||
Gas Utilities | 63,252 | 28,785 | (1,588 | ) | 90,449 | |||||||
Power Generation | 1,152 | — | — | 1,152 | ||||||||
Coal Mining | 3,638 | — | — | 3,638 | ||||||||
Oil and Gas | 4,646 | — | (13 | ) | 4,633 | |||||||
Corporate | 981 | — | — | 981 | ||||||||
Total | $ | 127,531 | $ | 53,325 | $ | (2,435 | ) | $ | 178,421 | |||
Accounts | Unbilled | Less Allowance for | Accounts | |||||||||
December 31, 2014 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | ||||||||
Electric Utilities | $ | 59,714 | $ | 26,474 | $ | (722 | ) | $ | 85,466 | |||
Gas Utilities | 47,394 | 45,546 | (781 | ) | 92,159 | |||||||
Power Generation | 1,369 | — | — | 1,369 | ||||||||
Coal Mining | 3,151 | — | — | 3,151 | ||||||||
Oil and Gas | 5,305 | — | (13 | ) | 5,292 | |||||||
Corporate | 2,555 | — | — | 2,555 | ||||||||
Total | $ | 119,488 | $ | 72,020 | $ | (1,516 | ) | $ | 189,992 | |||
Accounts | Unbilled | Less Allowance for | Accounts | |||||||||
March 31, 2014 | Receivable, Trade | Revenue | Doubtful Accounts | Receivable, net | ||||||||
Electric Utilities | $ | 53,733 | $ | 20,063 | $ | (690 | ) | $ | 73,106 | |||
Gas Utilities | 77,982 | 35,791 | (814 | ) | 112,959 | |||||||
Power Generation | 1,340 | — | — | 1,340 | ||||||||
Coal Mining | 2,616 | — | — | 2,616 | ||||||||
Oil and Gas | 10,920 | — | (13 | ) | 10,907 | |||||||
Corporate | 2,697 | — | — | 2,697 | ||||||||
Total | $ | 149,288 | $ | 55,854 | $ | (1,517 | ) | $ | 203,625 | |||
Maximum | As of | As of | As of | |||||||
Amortization (in years) | March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Regulatory assets | ||||||||||
Deferred energy and fuel cost adjustments - current (a) (d) | 1 | $ | 30,833 | $ | 23,820 | $ | 23,935 | |||
Deferred gas cost adjustments (a)(d) | 2 | 6,138 | 37,471 | 38,505 | ||||||
Gas price derivatives (a) | 7 | 21,606 | 18,740 | 4,420 | ||||||
AFUDC (b) | 45 | 12,114 | 12,358 | 12,349 | ||||||
Employee benefit plans (c) (e) | 12 | 97,700 | 97,126 | 65,833 | ||||||
Environmental (a) | subject to approval | 1,240 | 1,314 | 1,317 | ||||||
Asset retirement obligations (a) | 44 | 3,237 | 3,287 | 3,271 | ||||||
Bond issue cost (a) | 23 | 3,240 | 3,276 | 3,383 | ||||||
Renewable energy standard adjustment (a) | 5 | 5,590 | 9,622 | 16,088 | ||||||
Flow through accounting (c) | 35 | 26,835 | 25,887 | 21,837 | ||||||
Decommissioning costs | 10 | 13,702 | 12,484 | — | ||||||
Other regulatory assets (a) | 15 | 13,242 | 12,454 | 10,181 | ||||||
$ | 235,477 | $ | 257,839 | $ | 201,119 | |||||
Regulatory liabilities | ||||||||||
Deferred energy and gas costs (a) (d) | 1 | $ | 18,094 | $ | 6,496 | $ | 6,485 | |||
Employee benefit plans (c) (e) | 12 | 53,151 | 53,139 | 34,355 | ||||||
Cost of removal (a) | 44 | 81,449 | 78,249 | 67,640 | ||||||
Other regulatory liabilities (c) | 25 | 13,845 | 10,947 | 8,896 | ||||||
$ | 166,539 | $ | 148,831 | $ | 117,376 | |||||
(a) | Recovery of costs, but we are not allowed a rate of return. |
(b) | In addition to recovery of costs, we are allowed a rate of return. |
(c) | In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively. |
(d) | Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Fluctuations in deferred gas cost adjustments compared to the same period in the prior year are primarily due to higher natural gas prices driven by demand and market conditions from the peak winter heating season in the first part of 2014. 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. |
(e) | Increase compared to March 31, 2014 is due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates. |
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
Materials and supplies | $ | 52,429 | $ | 49,555 | $ | 50,727 | |||||
Fuel - Electric Utilities | 6,780 | 6,637 | 7,218 | ||||||||
Natural gas in storage held for distribution | 7,417 | 34,999 | 8,242 | ||||||||
Total materials, supplies and fuel | $ | 66,626 | $ | 91,191 | $ | 66,187 | |||||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Net income (loss) available for common stock | $ | 47,894 | $ | 48,118 | ||
Weighted average shares - basic | 44,541 | 44,330 | ||||
Dilutive effect of: | ||||||
Equity compensation | 119 | 224 | ||||
Weighted average shares - diluted | 44,660 | 44,554 | ||||
Three Months Ended March 31, | ||||
2015 | 2014 | |||
Equity compensation | 107 | 46 | ||
Anti-dilutive shares | 107 | 46 | ||
March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||||||||||||
Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | |||||||||||||
Revolving Credit Facility | $ | 102,600 | $ | 22,300 | $ | 75,000 | $ | 35,000 | $ | 100,000 | $ | 27,700 | ||||||
As of March 31, 2015 | Covenant Requirement | |||
Recourse Leverage Ratio | 55% | Less than | 65% | |
• | Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production; and our fuel procurement for certain of our gas-fired generation assets; and |
• | Interest rate risk associated with our variable-rate debt. |
March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||||||||||||||
Crude Oil Futures, Swaps and Options | Natural Gas Futures and Swaps | Crude Oil Futures, Swaps and Options | Natural Gas Futures and Swaps | Crude Oil Futures, Swaps and Options | Natural Gas Futures and Swaps | |||||||||||||||
Notional (a) | 305,000 | 5,367,500 | 334,500 | 6,582,500 | 442,500 | 8,296,250 | ||||||||||||||
Maximum terms in months (b) | 1 | 1 | 1 | 1 | 1 | 1 | ||||||||||||||
Derivative assets, current | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||
Derivative assets, non-current | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||
Derivative liabilities, current | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||
Derivative liabilities, non-current | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||
(a) | Crude oil in Bbls, natural gas in MMBtus. |
(b) | Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument. |
March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||||||||
Notional (MMBtus) | Maximum Term (months) (a) | Notional (MMBtus) | Maximum Term (months) (a) | Notional (MMBtus) | Maximum Term (months) (a) | |||||||||
Natural gas futures purchased | 17,280,000 | 69 | 19,370,000 | 72 | 16,140,000 | 80 | ||||||||
Natural gas options purchased | 1,320,000 | 12 | 4,020,000 | 8 | 1,320,000 | 12 | ||||||||
Natural gas basis swaps purchased | 15,735,000 | 57 | 12,005,000 | 60 | 14,575,000 | 69 | ||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Derivative assets, current | $ | — | $ | — | $ | 1,846 | |||
Derivative assets, non-current | $ | — | $ | — | $ | — | |||
Derivative liabilities, non-current | $ | — | $ | — | $ | — | |||
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities | $ | 21,606 | $ | 18,740 | $ | 4,420 | |||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
Interest Rate Swaps (a) | Interest Rate Swaps (a) | Interest Rate Swaps (a) | |||||||||
Notional | $ | 75,000 | $ | 75,000 | $ | 75,000 | |||||
Weighted average fixed interest rate | 4.97 | % | 4.97 | % | 4.97 | % | |||||
Maximum terms in years | 1.75 | 2.00 | 2.75 | ||||||||
Derivative liabilities, current | $ | 3,342 | $ | 3,340 | $ | 3,498 | |||||
Derivative liabilities, non-current | $ | 2,143 | $ | 2,680 | $ | 4,805 | |||||
(a) | These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related borrowings. |
Three Months Ended March 31, 2015 | ||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | 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 | $ | (886 | ) | Interest expense | $ | 1,437 | $ | — | ||||||||
Commodity derivatives | 3,764 | Revenue | (3,932 | ) | — | |||||||||||
Total | $ | 2,878 | $ | (2,495 | ) | $ | — | |||||||||
Three Months Ended March 31, 2014 | ||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | 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 | $ | (91 | ) | Interest expense | $ | (894 | ) | $ | — | |||||||
Commodity derivatives | (3,473 | ) | Revenue | (311 | ) | — | ||||||||||
Total | $ | (3,564 | ) | $ | (1,205 | ) | $ | — | ||||||||
• | The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure. |
• | The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. |
• | The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then 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 includes a CVA component. The CVA considers 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 utilize observable inputs supporting a Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. |
As of March 31, 2015 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Cash Collateral and Counterparty Netting | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | 8,096 | — | (8,096 | ) | — | ||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 6,526 | — | (6,526 | ) | — | ||||||||||
Commodity derivatives — Utilities | — | 1,184 | — | (1,184 | ) | — | ||||||||||
Total | $ | — | $ | 15,806 | $ | — | $ | (15,806 | ) | $ | — | |||||
Liabilities: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | 2 | — | (2 | ) | — | ||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 256 | — | (256 | ) | — | ||||||||||
Commodity derivatives — Utilities | — | 22,002 | — | (22,002 | ) | — | ||||||||||
Interest rate swaps | — | 5,485 | — | — | 5,485 | |||||||||||
Total | $ | — | $ | 27,745 | $ | — | $ | (22,260 | ) | $ | 5,485 | |||||
As of December 31, 2014 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Cash Collateral and Counterparty Netting | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | 8,599 | — | (8,599 | ) | — | ||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 6,558 | — | (6,558 | ) | — | ||||||||||
Commodity derivatives —Utilities | — | 2,389 | — | (2,389 | ) | — | ||||||||||
Total | $ | — | $ | 17,546 | $ | — | $ | (17,546 | ) | $ | — | |||||
Liabilities: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | — | — | — | — | |||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 473 | — | (473 | ) | — | ||||||||||
Commodity derivatives — Utilities | — | 19,303 | — | (19,303 | ) | — | ||||||||||
Interest rate swaps | — | 6,020 | — | — | 6,020 | |||||||||||
Total | $ | — | $ | 25,796 | $ | — | $ | (19,776 | ) | $ | 6,020 | |||||
As of March 31, 2014 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Cash Collateral and Counterparty Netting | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | 7 | — | (7 | ) | — | ||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 490 | — | (490 | ) | — | ||||||||||
Commodity derivatives — Utilities | — | 3,226 | — | (1,380 | ) | 1,846 | ||||||||||
Total | $ | — | $ | 3,723 | $ | — | $ | (1,877 | ) | $ | 1,846 | |||||
Liabilities: | ||||||||||||||||
Commodity derivatives — Oil and Gas | ||||||||||||||||
Options -- Oil | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||
Basis Swaps -- Oil | — | 1,983 | — | (1,983 | ) | — | ||||||||||
Options -- Gas | — | — | — | — | — | |||||||||||
Basis Swaps -- Gas | — | 2,114 | — | (2,114 | ) | — | ||||||||||
Commodity derivatives — Utilities | — | 6,919 | — | (6,919 | ) | — | ||||||||||
Interest rate swaps | — | 8,303 | — | — | 8,303 | |||||||||||
Total | $ | — | $ | 19,319 | $ | — | $ | (11,016 | ) | $ | 8,303 | |||||
As of March 31, 2015 | ||||||||
Balance Sheet Location | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | ||||||
Derivatives designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | 9,989 | $ | — | |||
Commodity derivatives | Derivative assets — non-current | 4,633 | — | |||||
Commodity derivatives | Derivative liabilities — current | — | 126 | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 132 | |||||
Interest rate swaps | Derivative liabilities — current | — | 3,342 | |||||
Interest rate swaps | Derivative liabilities — non-current | — | 2,143 | |||||
Total derivatives designated as hedges | $ | 14,622 | $ | 5,743 | ||||
Derivatives not designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | — | $ | — | |||
Commodity derivatives | Derivative assets — non-current | — | — | |||||
Commodity derivatives | Derivative liabilities — current | — | 7,530 | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 13,288 | |||||
Total derivatives not designated as hedges | $ | — | $ | 20,818 | ||||
As of December 31, 2014 | ||||||||
Balance Sheet Location | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | ||||||
Derivatives designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | 10,391 | $ | — | |||
Commodity derivatives | Derivative assets — non-current | 4,766 | — | |||||
Commodity derivatives | Derivative liabilities — current | — | 185 | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 288 | |||||
Interest rate swaps | Derivative liabilities — current | — | 3,340 | |||||
Interest rate swaps | Derivative liabilities — non-current | — | 2,680 | |||||
Total derivatives designated as hedges | $ | 15,157 | $ | 6,493 | ||||
Derivatives not designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | — | $ | — | |||
Commodity derivatives | Derivative assets — non-current | — | — | |||||
Commodity derivatives | Derivative liabilities — current | — | 8,032 | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 8,882 | |||||
Total derivatives not designated as hedges | $ | — | $ | 16,914 | ||||
As of March 31, 2014 | ||||||||
Balance Sheet Location | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | ||||||
Derivatives designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | 30 | $ | — | |||
Commodity derivatives | Derivative assets — non-current | 466 | — | |||||
Commodity derivatives | Derivative liabilities — current | — | 3,187 | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 910 | |||||
Interest rate swaps | Derivative liabilities — current | — | 3,498 | |||||
Interest rate swaps | Derivative liabilities — non-current | — | 4,805 | |||||
Total derivatives designated as hedges | $ | 496 | $ | 12,400 | ||||
Derivatives not designated as hedges: | ||||||||
Commodity derivatives | Derivative assets — current | $ | 1,846 | $ | — | |||
Commodity derivatives | Derivative assets — non-current | — | — | |||||
Commodity derivatives | Derivative liabilities — current | — | — | |||||
Commodity derivatives | Derivative liabilities — non-current | — | 5,539 | |||||
Interest rate swaps | Derivative liabilities — current | — | — | |||||
Interest rate swaps | Derivative liabilities — non-current | — | — | |||||
Total derivatives not designated as hedges | $ | 1,846 | $ | 5,539 | ||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||
Cash and cash equivalents (a) | $ | 63,385 | $ | 63,385 | $ | 21,218 | $ | 21,218 | $ | 17,641 | $ | 17,641 | ||||||||
Restricted cash and equivalents (a) | $ | 2,191 | $ | 2,191 | $ | 2,056 | $ | 2,056 | $ | 2 | $ | 2 | ||||||||
Notes payable (a) | $ | 102,600 | $ | 102,600 | $ | 75,000 | $ | 75,000 | $ | 100,000 | $ | 100,000 | ||||||||
Long-term debt, including current maturities (b) | $ | 1,542,658 | $ | 1,767,113 | $ | 1,542,589 | $ | 1,734,555 | $ | 1,396,949 | $ | 1,541,727 | ||||||||
(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) | 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. |
(11) | OTHER COMPREHENSIVE INCOME (LOSS) |
Location on the Condensed Consolidated Statements of Income (Loss) | Amount Reclassified from AOCI | ||||||
Three Months Ended | |||||||
March 31, 2015 | March 31, 2014 | ||||||
Gains (losses) on cash flow hedges: | |||||||
Interest rate swaps | Interest expense | $ | 1,437 | $ | 894 | ||
Commodity contracts | Revenue | (3,932 | ) | 311 | |||
(2,495 | ) | 1,205 | |||||
Income tax | Income tax benefit (expense) | 1,254 | (425 | ) | |||
Reclassification adjustments related to cash flow hedges, net of tax | $ | (1,241 | ) | $ | 780 | ||
Amortization of defined benefit plans: | |||||||
Prior service cost | Utilities - Operations and maintenance | $ | (27 | ) | $ | (25 | ) |
Non-regulated energy operations and maintenance | (28 | ) | 12 | ||||
Actuarial gain (loss) | Utilities - Operations and maintenance | 454 | 157 | ||||
Non-regulated energy operations and maintenance | 251 | 85 | |||||
650 | 229 | ||||||
Income tax | Income tax benefit (expense) | (228 | ) | (81 | ) | ||
Reclassification adjustments related to defined benefit plans, net of tax | $ | 422 | $ | 148 | |||
Derivatives Designated as Cash Flow Hedges | Employee Benefit Plans | Total | |||||||
Balance as of December 31, 2013 | $ | (7,133 | ) | $ | (10,289 | ) | $ | (17,422 | ) |
Other comprehensive income (loss), net of tax | (1,478 | ) | 311 | (1,167 | ) | ||||
Balance as of March 31, 2014 | $ | (8,611 | ) | $ | (9,978 | ) | $ | (18,589 | ) |
Balance as of December 31, 2014 | $ | 5,093 | $ | (20,137 | ) | $ | (15,044 | ) | |
Other comprehensive income (loss), net of tax | 595 | 395 | 990 | ||||||
Balance as of March 31, 2015 | $ | 5,688 | $ | (19,742 | ) | $ | (14,054 | ) | |
Three months ended | March 31, 2015 | March 31, 2014 | |||||
(in thousands) | |||||||
Non-cash investing and financing activities from continuing operations— | |||||||
Property, plant and equipment acquired with accrued liabilities | $ | 33,534 | $ | 40,939 | |||
Increase (decrease) in capitalized assets associated with asset retirement obligations | $ | — | $ | (2,785 | ) | ||
Cash (paid) refunded during the period for continuing operations— | |||||||
Interest (net of amounts capitalized) | $ | (10,909 | ) | $ | (11,452 | ) | |
Income taxes, net | $ | (2 | ) | $ | 4 | ||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Service cost | $ | 1,494 | $ | 1,362 | ||
Interest cost | 3,880 | 3,963 | ||||
Expected return on plan assets | (4,867 | ) | (4,516 | ) | ||
Prior service cost | 15 | 16 | ||||
Net loss (gain) | 2,759 | 1,201 | ||||
Net periodic benefit cost | $ | 3,281 | $ | 2,026 | ||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Service cost | $ | 464 | $ | 425 | ||
Interest cost | 450 | 479 | ||||
Expected return on plan assets | (33 | ) | (21 | ) | ||
Prior service cost (benefit) | (107 | ) | (107 | ) | ||
Net loss (gain) | 102 | 40 | ||||
Net periodic benefit cost | $ | 876 | $ | 816 | ||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Service cost | $ | 491 | $ | 374 | ||
Interest cost | 364 | 362 | ||||
Prior service cost | 1 | 1 | ||||
Net loss (gain) | 270 | 124 | ||||
Net periodic benefit cost | $ | 1,126 | $ | 861 | ||
Contributions Made | Additional Contributions | Contributions | |||||||
Three Months Ended March 31, 2015 | Anticipated for 2015 | Anticipated for 2016 | |||||||
Defined Benefit Pension Plans | $ | — | $ | 10,200 | $ | 10,200 | |||
Non-pension Defined Benefit Postretirement Healthcare Plans | $ | 939 | $ | 2,816 | $ | 4,026 | |||
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | $ | 372 | $ | 1,115 | $ | 1,544 | |||
• | 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. As of March 31, 2015, the restricted net assets at our Utilities Group were approximately $338 million. |
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Business Group | Financial Segment |
Utilities | Electric Utilities |
Gas Utilities | |
Non-regulated Energy | Power Generation |
Coal Mining | |
Oil and Gas | |
See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 53. |
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
Revenue | |||||||||
Utilities | $ | 424,049 | $ | 441,439 | $ | (17,390 | ) | ||
Non-regulated Energy | 49,875 | 52,696 | (2,821 | ) | |||||
Inter-company eliminations | (31,937 | ) | (33,966 | ) | 2,029 | ||||
$ | 441,987 | $ | 460,169 | $ | (18,182 | ) | |||
Net income (loss) | |||||||||
Electric Utilities | $ | 18,929 | $ | 14,575 | $ | 4,354 | |||
Gas Utilities | 22,212 | 24,698 | (2,486 | ) | |||||
Utilities | 41,141 | 39,273 | 1,868 | ||||||
Power Generation | 8,145 | 8,073 | 72 | ||||||
Coal Mining | 3,010 | 2,464 | 546 | ||||||
Oil and Gas | (5,071 | ) | (2,022 | ) | (3,049 | ) | |||
Non-regulated Energy | 6,084 | 8,515 | (2,431 | ) | |||||
Corporate activities and eliminations | 669 | 330 | 339 | ||||||
Net income (loss) | $ | 47,894 | $ | 48,118 | $ | (224 | ) | ||
• | Gas Utilities experienced milder weather during the three months ended March 31, 2015 compared to the three months ended March 31, 2014. Heating degree days were 9% lower for the three months ended March 31, 2015, compared to the same period in 2014. Heating degree days for the three months ended March 31, 2015 were 4% higher than normal, compared to 14% higher than normal for the same period in 2014. |
• | On April 15, 2015, we filed a request for approval with the WPSC of our $17 million purchase agreement to acquire Energy West, Wyoming, a deal previously announced on October 14, 2014. Energy West is a gas utility serving approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The purchase also includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory. A hearing is scheduled with the WPSC on May 14, 2015. We have requested approval from the WPSC to close on the acquisition on June 1, 2015. |
• | On March 16, 2015, we announced plans to build a new corporate headquarters in Rapid City that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses of our five facilities throughout Rapid City. Construction will begin in the second quarter of 2015 with completion expected in 2017. |
• | On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for Black Hills Power of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas fired facility. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014. |
• | In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider also allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant. |
• | In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs. |
• | On July 22, 2014, Black Hills Power filed a CPCN with the WPSC to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. We are awaiting approval of the CPCN from the WPSC. Black Hills Power received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Assuming timely receipt of remaining approvals, Black Hills Power plans to commence construction in the third quarter of 2015. |
• | On May 5, 2014, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. An independent evaluator submitted a report to the CPUC confirming the ranking of the bids. On February 27, 2015 the Commission determined that none of the renewable bids were cost effective. Colorado Electric submitted a request for reconsideration on March 19, 2015. On April 16, 2015, the Commission deliberated these requests filed by the company and various parties to the initial decision. The Commission declined to change its decision. In their written order, the commission noted precedent allowing utilities to secure new bid pricing. Colorado Electric, at it’s discretion, has sixty days to renegotiate bids and submit a revised contract or contacts for approval. Colorado Electric is currently reviewing its options. |
• | Our Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the three months ended March 31, 2015 compared to the same period in 2014. The average hedged price received for natural gas decreased by 34% for the three months ended March 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 26% for the three months ended March 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 23% for the three months ended March 31, 2015 compared to the same period in 2014. |
• | We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We did not record a ceiling test impairment for the three months ended March 31, 2015. However, using our current reserves information, a ceiling impairment charge could occur in 2015 if commodity prices for crude oil and natural gas remain at current low levels. |
• | Our southern Piceance Basin drilling program continued with three Mancos Shale wells placed on production (one in January 2015 and two in February 2015). Production results to date from these wells have been favorable, and exceeded our expectations. |
• | Our Oil and Gas segment contracted for two additional drilling rigs to support drilling operations in the southern Piceance Basin. Drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 planned Mancos and other drilling capital to 2015, and the addition of one more Mancos well to the 2015 drilling plan, we have increased our planned 2015 capital expenditures to $167 million from $123 million. |
• | On April 13, 2015, we entered into a new $300 million unsecured term loan. The loan has a two-year term with a maturity date of April 12, 2017. Proceeds of the term note were used to repay the existing $275 million term note due June 19, 2015. |
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
(in thousands) | |||||||||
Revenue — electric | $ | 169,917 | $ | 168,365 | $ | 1,552 | |||
Revenue — gas | 16,481 | 13,737 | 2,744 | ||||||
Total revenue | 186,398 | 182,102 | 4,296 | ||||||
Fuel, purchased power and cost of gas — electric | 67,690 | 78,418 | (10,728 | ) | |||||
Purchased gas — gas | 10,098 | 8,274 | 1,824 | ||||||
Total fuel, purchased power and cost of gas | 77,788 | 86,692 | (8,904 | ) | |||||
Gross margin — electric | 102,227 | 89,947 | 12,280 | ||||||
Gross margin — gas | 6,383 | 5,463 | 920 | ||||||
Total gross margin | 108,610 | 95,410 | 13,200 | ||||||
Operations and maintenance | 43,984 | 42,601 | 1,383 | ||||||
Depreciation and amortization | 21,044 | 19,086 | 1,958 | ||||||
Total operating expenses | 65,028 | 61,687 | 3,341 | ||||||
Operating income | 43,582 | 33,723 | 9,859 | ||||||
Interest expense, net | (13,833 | ) | (12,013 | ) | (1,820 | ) | |||
Other income (expense), net | 69 | 256 | (187 | ) | |||||
Income tax benefit (expense) | (10,889 | ) | (7,391 | ) | (3,498 | ) | |||
Net income (loss) | $ | 18,929 | $ | 14,575 | $ | 4,354 | |||
Three Months Ended March 31, | |||||||
Revenue - Electric (in thousands) | 2015 | 2014 | |||||
Residential: | |||||||
Black Hills Power | $ | 20,140 | $ | 20,061 | |||
Cheyenne Light | 10,265 | 9,673 | |||||
Colorado Electric | 24,570 | 24,679 | |||||
Total Residential | 54,975 | 54,413 | |||||
Commercial: | |||||||
Black Hills Power | 24,741 | 21,528 | |||||
Cheyenne Light | 15,820 | 14,394 | |||||
Colorado Electric | 22,164 | 21,890 | |||||
Total Commercial | 62,725 | 57,812 | |||||
Industrial: | |||||||
Black Hills Power | 8,299 | 7,335 | |||||
Cheyenne Light | 8,626 | 7,224 | |||||
Colorado Electric | 10,756 | 9,038 | |||||
Total Industrial | 27,681 | 23,597 | |||||
Municipal: | |||||||
Black Hills Power | 858 | 792 | |||||
Cheyenne Light | 516 | 454 | |||||
Colorado Electric | 3,062 | 3,307 | |||||
Total Municipal | 4,436 | 4,553 | |||||
Total Retail Revenue - Electric | 149,817 | 140,375 | |||||
Contract Wholesale: | |||||||
Total Contract Wholesale - Black Hills Power | 5,420 | 5,598 | |||||
Off-system Wholesale: | |||||||
Black Hills Power | 6,635 | 9,075 | |||||
Cheyenne Light | 1,961 | 2,387 | |||||
Colorado Electric | 84 | 2,082 | |||||
Total Off-system Wholesale | 8,680 | 13,544 | |||||
Other Revenue: | |||||||
Black Hills Power | 4,190 | 6,878 | |||||
Cheyenne Light | 475 | 753 | |||||
Colorado Electric | 1,335 | 1,217 | |||||
Total Other Revenue | 6,000 | 8,848 | |||||
Total Revenue - Electric | $ | 169,917 | $ | 168,365 | |||
Three Months Ended March 31, | |||||
Quantities Generated and Purchased (in MWh) | 2015 | 2014 | |||
Generated — | |||||
Coal-fired: | |||||
Black Hills Power (a) | 376,834 | 417,248 | |||
Cheyenne Light (b) | 194,716 | 169,789 | |||
Total Coal-fired | 571,550 | 587,037 | |||
Natural Gas and Oil: | |||||
Black Hills Power | 2,878 | 2,308 | |||
Cheyenne Light | 2,839 | — | |||
Colorado Electric (c) | 3,492 | 18,068 | |||
Total Natural Gas and Oil | 9,209 | 20,376 | |||
Wind: | |||||
Colorado Electric | 9,091 | 14,329 | |||
Total Wind | 9,091 | 14,329 | |||
Total Generated: | |||||
Black Hills Power | 379,712 | 419,556 | |||
Cheyenne Light | 197,555 | 169,789 | |||
Colorado Electric | 12,583 | 32,397 | |||
Total Generated | 589,850 | 621,742 | |||
Purchased — | |||||
Black Hills Power | 438,443 | 430,801 | |||
Cheyenne Light | 187,779 | 207,318 | |||
Colorado Electric | 472,187 | 470,101 | |||
Total Purchased | 1,098,409 | 1,108,220 | |||
Total Generated and Purchased: | |||||
Black Hills Power | 818,155 | 850,357 | |||
Cheyenne Light | 385,334 | 377,107 | |||
Colorado Electric | 484,770 | 502,498 | |||
Total Generated and Purchased | 1,688,259 | 1,729,962 | |||
(a) | Decrease reflects the retirement of Neil Simpson I on March 21, 2014. |
(b) | Increase is due to purchasing spinning reserve in the current year compared to carrying spinning reserve in the prior year. |
(c) | Decrease in 2015 generation is primarily driven by commodity prices that impacted power marketing sales. |
Three Months Ended March 31, | ||||
Quantity (in MWh) | 2015 | 2014 | ||
Residential: | ||||
Black Hills Power | 146,963 | 171,311 | ||
Cheyenne Light | 67,499 | 70,656 | ||
Colorado Electric | 157,214 | 153,632 | ||
Total Residential | 371,676 | 395,599 | ||
Commercial: | ||||
Black Hills Power | 195,078 | 184,448 | ||
Cheyenne Light | 131,103 | 126,412 | ||
Colorado Electric | 165,081 | 158,179 | ||
Total Commercial | 491,262 | 469,039 | ||
Industrial: | ||||
Black Hills Power | 111,859 | 100,851 | ||
Cheyenne Light | 111,096 | 90,724 | ||
Colorado Electric | 118,107 | 90,116 | ||
Total Industrial | 341,062 | 281,691 | ||
Municipal: | ||||
Black Hills Power | 7,700 | 7,686 | ||
Cheyenne Light | 2,550 | 2,493 | ||
Colorado Electric | 28,113 | 26,687 | ||
Total Municipal | 38,363 | 36,866 | ||
Total Retail Quantity Sold | 1,242,363 | 1,183,195 | ||
Contract Wholesale: | ||||
Total Contract Wholesale - Black Hills Power (a) | 84,271 | 95,228 | ||
Off-system Wholesale: | ||||
Black Hills Power | 245,638 | 254,796 | ||
Cheyenne Light | 48,872 | 52,356 | ||
Colorado Electric (b) | 2,469 | 30,746 | ||
Total Off-system Wholesale | 296,979 | 337,898 | ||
Total Quantity Sold: | ||||
Black Hills Power | 791,509 | 814,320 | ||
Cheyenne Light | 361,120 | 342,641 | ||
Colorado Electric | 470,984 | 459,360 | ||
Total Quantity Sold | 1,623,613 | 1,616,321 | ||
Other Uses, Losses or Generation, net (c): | ||||
Black Hills Power | 26,646 | 36,037 | ||
Cheyenne Light | 24,214 | 34,466 | ||
Colorado Electric | 13,786 | 43,138 | ||
Total Other Uses, Losses and Generation, net | 64,646 | 113,641 | ||
Total Energy | 1,688,259 | 1,729,962 | ||
(a) | Decrease is driven by load requirements related to a Wygen III unit-contingent PPA. |
(b) | Decrease in 2015 generation is primarily driven by commodity prices that impacted power marketing sales. |
(c) | Includes company uses, line losses, and excess exchange production. |
Three Months Ended March 31, | |||||||||
Degree Days | 2015 | 2014 | |||||||
Actual | Variance from 30-Year Average | Actual Variance to Prior Year | Actual | Variance from 30-Year Average | |||||
Heating Degree Days: | |||||||||
Black Hills Power | 2,873 | (11)% | (16)% | 3,410 | 6% | ||||
Cheyenne Light | 2,651 | (12)% | (17)% | 3,206 | 6% | ||||
Colorado Electric | 2,398 | (8)% | (10)% | 2,670 | 2% | ||||
Combined (a) | 2,610 | (10)% | (14)% | 3,028 | 5% | ||||
(a) | Combined actuals are calculated based on the weighted average number of total customers by state. |
Electric Utilities Power Plant Availability | Three Months Ended March 31, | |||||
2015 | 2014 | |||||
Coal-fired plants | 91.3 | % | 95.5 | % | ||
Other plants (a) | 95.7 | % | 78.1 | % | ||
Total availability | 94.1 | % | 86.6 | % | ||
(a) | The three months ended March 31, 2014, reflects an unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station. |
Three Months Ended March 31, | |||||||
2015 | 2014 | ||||||
Revenue - Natural Gas (in thousands): | |||||||
Residential | $ | 8,712 | $ | 8,224 | |||
Commercial | 4,954 | 3,977 | |||||
Industrial | 1,900 | 1,285 | |||||
Other Sales Revenue | 915 | 251 | |||||
Total Revenue - Natural Gas | $ | 16,481 | $ | 13,737 | |||
Gross Margin (in thousands): | |||||||
Residential | $ | 3,778 | $ | 3,605 | |||
Commercial | 1,428 | 1,332 | |||||
Industrial | 262 | 275 | |||||
Other Gross Margin | 915 | 251 | |||||
Total Gross Margin | $ | 6,383 | $ | 5,463 | |||
Volumes Sold (Dth): | |||||||
Residential | 940,407 | 1,035,177 | |||||
Commercial | 670,589 | 564,394 | |||||
Industrial | 301,277 | 255,927 | |||||
Total Volumes Sold | 1,912,273 | 1,855,498 | |||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
(in thousands) | |||||||||
Revenue: | |||||||||
Natural gas — regulated | $ | 229,148 | $ | 251,232 | $ | (22,084 | ) | ||
Other — non-regulated services | 8,503 | 8,105 | 398 | ||||||
Total revenue | 237,651 | 259,337 | (21,686 | ) | |||||
Cost of sales | |||||||||
Natural gas — regulated | 152,285 | 170,774 | (18,489 | ) | |||||
Other — non-regulated services | 3,913 | 3,722 | 191 | ||||||
Total cost of sales | 156,198 | 174,496 | (18,298 | ) | |||||
Gross margin | 81,453 | 84,841 | (3,388 | ) | |||||
Operations and maintenance | 35,432 | 35,378 | 54 | ||||||
Depreciation and amortization | 7,046 | 6,521 | 525 | ||||||
Total operating expenses | 42,478 | 41,899 | 579 | ||||||
Operating income (loss) | 38,975 | 42,942 | (3,967 | ) | |||||
Interest expense, net | (3,809 | ) | (3,853 | ) | 44 | ||||
Other income (expense), net | (11 | ) | (17 | ) | 6 | ||||
Income tax benefit (expense) | (12,943 | ) | (14,374 | ) | 1,431 | ||||
Net income (loss) | $ | 22,212 | $ | 24,698 | $ | (2,486 | ) | ||
Three Months Ended March 31, | |||||||
Revenue (in thousands) | 2015 | 2014 | |||||
Residential: | |||||||
Colorado | $ | 25,736 | $ | 23,687 | |||
Nebraska | 56,444 | 62,892 | |||||
Iowa | 46,366 | 54,764 | |||||
Kansas | 29,328 | 33,277 | |||||
Total Residential | 157,874 | 174,620 | |||||
Commercial: | |||||||
Colorado | 5,097 | 4,697 | |||||
Nebraska | 18,212 | 20,066 | |||||
Iowa | 21,629 | 25,914 | |||||
Kansas | 11,066 | 11,671 | |||||
Total Commercial | 56,004 | 62,348 | |||||
Industrial: | |||||||
Colorado | 29 | 77 | |||||
Nebraska | 317 | 208 | |||||
Iowa | 1,255 | 1,172 | |||||
Kansas | 1,741 | 1,086 | |||||
Total Industrial | 3,342 | 2,543 | |||||
Transportation: | |||||||
Colorado | 365 | 325 | |||||
Nebraska | 5,396 | 5,730 | |||||
Iowa | 1,662 | 1,761 | |||||
Kansas | 2,501 | 2,493 | |||||
Total Transportation | 9,924 | 10,309 | |||||
Other Sales Revenue: | |||||||
Colorado | 43 | 31 | |||||
Nebraska | 657 | 703 | |||||
Iowa | 139 | 152 | |||||
Kansas | 1,165 | 526 | |||||
Total Other Sales Revenue | 2,004 | 1,412 | |||||
Total Regulated Revenue | 229,148 | 251,232 | |||||
Non-regulated Services | 8,503 | 8,105 | |||||
Total Revenue | $ | 237,651 | $ | 259,337 | |||
Three Months Ended March 31, | |||||||
Gross Margin (in thousands) | 2015 | 2014 | |||||
Residential: | |||||||
Colorado | $ | 6,337 | $ | 6,372 | |||
Nebraska | 18,990 | 20,889 | |||||
Iowa | 13,898 | 15,210 | |||||
Kansas | 11,478 | 11,584 | |||||
Total Residential | 50,703 | 54,055 | |||||
Commercial: | |||||||
Colorado | 1,040 | 1,060 | |||||
Nebraska | 4,669 | 5,163 | |||||
Iowa | 4,636 | 5,225 | |||||
Kansas | 3,387 | 3,183 | |||||
Total Commercial | 13,732 | 14,631 | |||||
Industrial: | |||||||
Colorado | 21 | 30 | |||||
Nebraska | 81 | 68 | |||||
Iowa | 81 | 85 | |||||
Kansas | 393 | 236 | |||||
Total Industrial | 576 | 419 | |||||
Transportation: | |||||||
Colorado | 365 | 326 | |||||
Nebraska | 5,396 | 5,731 | |||||
Iowa | 1,662 | 1,761 | |||||
Kansas | 2,501 | 2,493 | |||||
Total Transportation | 9,924 | 10,311 | |||||
Other Sales Margins: | |||||||
Colorado | 43 | 31 | |||||
Nebraska | 657 | 702 | |||||
Iowa | 139 | 152 | |||||
Kansas | 1,089 | 157 | |||||
Total Other Sales Margins | 1,928 | 1,042 | |||||
Total Regulated Gross Margin | 76,863 | 80,458 | |||||
Non-regulated Services | 4,590 | 4,383 | |||||
Total Gross Margin | $ | 81,453 | $ | 84,841 | |||
Three Months Ended March 31, | ||||
Distribution Quantities Sold and Transportation (in Dth) | 2015 | 2014 | ||
Residential: | ||||
Colorado | 2,946,805 | 3,021,434 | ||
Nebraska | 5,958,956 | 6,986,293 | ||
Iowa | 5,516,037 | 6,643,044 | ||
Kansas | 3,353,814 | 3,881,555 | ||
Total Residential | 17,775,612 | 20,532,326 | ||
Commercial: | ||||
Colorado | 617,198 | 635,690 | ||
Nebraska | 2,180,694 | 2,475,156 | ||
Iowa | 2,880,091 | 3,485,692 | ||
Kansas | 1,435,504 | 1,541,967 | ||
Total Commercial | 7,113,487 | 8,138,505 | ||
Industrial: | ||||
Colorado | 2,402 | 10,325 | ||
Nebraska | 45,700 | 26,965 | ||
Iowa | 191,005 | 193,863 | ||
Kansas (a) (b) | 324,779 | 180,087 | ||
Total Industrial | 563,886 | 411,240 | ||
Wholesale and Other: | ||||
Kansas (b) | 13,975 | 68,633 | ||
Total Wholesale and Other | 13,975 | 68,633 | ||
Total Distribution Quantities Sold | 25,466,960 | 29,150,704 | ||
Transportation: | ||||
Colorado | 380,049 | 330,344 | ||
Nebraska | 9,049,775 | 9,963,219 | ||
Iowa | 6,088,049 | 6,157,366 | ||
Kansas | 4,297,352 | 4,827,137 | ||
Total Transportation | 19,815,225 | 21,278,066 | ||
Total Distribution Quantities Sold and Transportation | 45,282,185 | 50,428,770 | ||
(a) | Increase is primarily due to a large customer’s sales volumes compared to the prior year and from a classification change in customer class. |
(b) | Decrease from prior year is primarily due a change in customer class. |
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
Heating Degree Days: | Actual | Variance from 30-Year Average | Actual Variance to Prior Year | Actual | Variance from 30-Year Average | ||||
Colorado | 2,535 | (9)% | (11)% | 2,859 | 2% | ||||
Nebraska | 3,014 | —% | (8)% | 3,272 | 7% | ||||
Iowa | 3,834 | 13% | (8)% | 4,174 | 19% | ||||
Kansas (a) | 2,322 | (6)% | (14)% | 2,689 | 8% | ||||
Combined (b) | 3,222 | 4% | (9)% | 3,524 | 14% | ||||
(a) | Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins. |
(b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. |
Type of Service | Date Requested | Effective Date | Revenue Amount Requested | Revenue Amount Approved | |||||
Black Hills Power (a) | Electric | 3/2014 | 10/2014 | $ | 14.6 | $ | 6.9 | ||
Kansas Gas (b) | Gas | 4/2014 | 1/2015 | $ | 7.3 | $ | 5.2 | ||
Colorado Electric (c) | Electric | 4/2014 | 1/2015 | $ | 4.0 | $ | 3.1 | ||
(a) | On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an increase for Black Hills Power of $6.9 million in annual electric revenue. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas fired facility. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014. |
(b) | On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million, effective January 2015. This increase in base rates allows Kansas Gas to recover a return on investments in infrastructure and recovery of increased operating costs. |
(c) | On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and a return on infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant. |
Type of Service | Date Requested | Effective Date | Capital Surcharge Requested | Capital Surcharge Approved | |||||
Nebraska Gas (a) | Gas | 4/2015 | 8/2015 | $ | 1.5 | $ | — | ||
Iowa Gas (b) | Gas | 3/2015 | 6/2015 | $ | 0.9 | $ | — | ||
(a) | On April 6, 2015, Nebraska Gas filed with the NPSC for a capital investment recovery surcharge increase of $1.5 million. Approval is expected in July, 2015. |
(b) | On March 17, 2015, Iowa Gas filed with the IUB for a capital investment recovery surcharge increase of $0.9 million. Approval is expected in June 2015. |
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
(in thousands) | |||||||||
Revenue | $ | 22,674 | $ | 22,348 | $ | 326 | |||
Operations and maintenance | 7,828 | 7,677 | 151 | ||||||
Depreciation and amortization | 1,134 | 1,209 | (75 | ) | |||||
Total operating expense | 8,962 | 8,886 | 76 | ||||||
Operating income | 13,712 | 13,462 | 250 | ||||||
Interest expense, net | (886 | ) | (928 | ) | 42 | ||||
Other (expense) income, net | (2 | ) | (9 | ) | 7 | ||||
Income tax (expense) benefit | (4,679 | ) | (4,452 | ) | (227 | ) | |||
Net income (loss) | $ | 8,145 | $ | 8,073 | $ | 72 | |||
Three Months Ended March 31, | ||||
2015 | 2014 | |||
Quantities Sold, Generated and Purchased (MWh) (a) | ||||
Sold | ||||
Black Hills Colorado IPP | 284,491 | 285,956 | ||
Black Hills Wyoming (b) | 159,558 | 140,608 | ||
Total Sold | 444,049 | 426,564 | ||
Generated | ||||
Black Hills Colorado IPP | 284,491 | 285,956 | ||
Black Hills Wyoming | 137,973 | 140,678 | ||
Total Generated | 422,464 | 426,634 | ||
Purchased | ||||
Black Hills Wyoming (b) | 24,392 | 989 | ||
Total Purchased | 24,392 | 989 | ||
Three Months Ended March 31, | ||||
2015 | 2014 | |||
Contracted power plant fleet availability: | ||||
Coal-fired plant | 98.2 | % | 99.3 | % |
Natural gas-fired plants | 98.9 | % | 97.9 | % |
Total availability | 98.7 | % | 98.2 | % |
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
(in thousands) | |||||||||
Revenue | $ | 15,934 | $ | 15,498 | $ | 436 | |||
Operations and maintenance | 9,904 | 10,131 | (227 | ) | |||||
Depreciation, depletion and amortization | 2,503 | 2,690 | (187 | ) | |||||
Total operating expenses | 12,407 | 12,821 | (414 | ) | |||||
Operating income (loss) | 3,527 | 2,677 | 850 | ||||||
Interest (expense) income, net | (89 | ) | (103 | ) | 14 | ||||
Other income, net | 585 | 603 | (18 | ) | |||||
Income tax benefit (expense) | (1,013 | ) | (713 | ) | (300 | ) | |||
Net income (loss) | $ | 3,010 | $ | 2,464 | $ | 546 | |||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Tons of coal sold | 1,019 | 1,087 | ||||
Cubic yards of overburden moved | 1,413 | 910 | ||||
Revenue per ton | $ | 15.64 | $ | 14.26 | ||
Three Months Ended March 31, | |||||||||
2015 | 2014 | Variance | |||||||
(in thousands) | |||||||||
Revenue | $ | 11,267 | $ | 14,850 | $ | (3,583 | ) | ||
Operations and maintenance | 10,917 | 11,139 | (222 | ) | |||||
Depreciation, depletion and amortization | 8,095 | 6,633 | 1,462 | ||||||
Total operating expenses | 19,012 | 17,772 | 1,240 | ||||||
Operating income (loss) | (7,745 | ) | (2,922 | ) | (4,823 | ) | |||
Interest income (expense), net | (384 | ) | (455 | ) | 71 | ||||
Other income (expense), net | (223 | ) | 38 | (261 | ) | ||||
Income tax benefit (expense) | 3,281 | 1,317 | 1,964 | ||||||
Net income (loss) | $ | (5,071 | ) | $ | (2,022 | ) | $ | (3,049 | ) |
Three Months Ended March 31, | ||||
2015 | 2014 | |||
Production: | ||||
Bbls of oil sold | 80,730 | 74,262 | ||
Mcf of natural gas sold | 2,254,042 | 1,759,964 | ||
Bbls of NGL sold | 28,770 | 27,041 | ||
Mcf equivalent sales | 2,911,043 | 2,367,782 | ||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Average price received: (a) (b) | ||||||
Oil/Bbl | $ | 66.86 | $ | 90.75 | ||
Gas/Mcf | $ | 2.20 | $ | 3.35 | ||
NGL/Bbl | $ | 13.74 | $ | 49.02 | ||
Depletion expense/Mcfe | $ | 2.40 | $ | 2.25 | ||
(a) | Net of hedge settlement gains and losses. |
(b) | Based on our quarterly ceiling test under the full cost accounting rules of the SEC, no impairment charge was necessary as of March 31, 2015. If crude oil and natural gas prices remain at or near the current low levels, a ceiling test impairment charge could occur in 2015. |
Three Months Ended March 31, 2015 | Three Months Ended March 31, 2014 | ||||||||||||||||||||||||
Producing Basin | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | LOE | Gathering, Compression, Processing and Transportation (a) | Production Taxes | Total | |||||||||||||||||
San Juan | $ | 1.58 | $ | 1.30 | $ | 0.37 | $ | 3.25 | $ | 1.54 | $ | 1.20 | $ | 0.63 | $ | 3.37 | |||||||||
Piceance | 0.33 | 2.48 | 0.20 | 3.01 | (0.06 | ) | 1.28 | 0.57 | 1.79 | ||||||||||||||||
Powder River | 2.89 | — | 0.56 | 3.45 | 2.36 | — | 1.34 | 3.70 | |||||||||||||||||
Williston | 0.24 | — | 0.09 | 0.33 | 0.67 | — | 1.90 | 2.57 | |||||||||||||||||
All other properties | 1.24 | — | 0.34 | 1.58 | 1.61 | — | 0.02 | 1.63 | |||||||||||||||||
Total weighted average | $ | 1.19 | $ | 1.35 | $ | 0.31 | $ | 2.85 | $ | 1.19 | $ | 0.81 | $ | 0.74 | $ | 2.74 | |||||||||
(a) | These costs include both third-party costs and operations costs. |
• | The income for the three months ended March 31, 2015, included lower interest expense compared to the three months ended March 31, 2014, primarily driven by favorable margins on base rate borrowings on our Revolving Credit Facility. Our Revolving Credit Facility agreement was amended and extended on May 29, 2014 with improved margins on base rate borrowings of 0.25% compared to the agreement it replaced. |
Cash provided by (used in): | 2015 | 2014 | Increase (Decrease) | ||||||
Operating activities | $ | 151,487 | $ | 98,098 | $ | 53,389 | |||
Investing activities | $ | (117,871 | ) | $ | (86,829 | ) | $ | (31,042 | ) |
Financing activities | $ | 8,551 | $ | (1,469 | ) | $ | 10,020 | ||
• | Cash earnings (net income plus non-cash adjustments) were comparable for the three months ended March 31, 2015 to the same period in the prior year. |
• | Net inflows from operating assets and liabilities were $29 million for the three months ended March 31, 2015, compared to net cash outflows of $27 million in the same period in the prior year. This $56 million variance was primarily due to: |
• | Cash inflows increased as a result of lower working capital requirements for the three months ended March 31, 2015 compared to the same period in the prior year. Colder weather and higher natural gas prices during the first quarter 2014 peak winter heating season drove a significant increase in natural gas volumes sold, and in natural gas volumes purchased and fuel cost adjustments recorded in regulatory assets. These fuel cost adjustments deferred in the prior year are recovered through their respective cost mechanisms as allowed by the state utility commissions; and |
• | Accrued expenditures decreased primarily at our Oil and Gas segment related to drilling activity for the three months ended March 31, 2015 compared to the same period in the prior year. |
• | Capital expenditures of approximately $118 million for the three months ended March 31, 2015, compared to $84 million for the three months ended March 31, 2014. The increase is related primarily to higher capital expenditures at our Oil and Gas segment driven by drilling activity in the Southern Piceance in the current year. The prior year Oil and Gas segment capital expenditures were affected by weather delays. Offsetting the oil and gas capital expenditure increase is the construction of Cheyenne Prairie at our Electric Utilities segment occurring in the prior year. |
• | Net short-term borrowings under the revolving credit facility for the three months ended March 31, 2015 increased primarily to fund the increase in overall capital expenditures. |
Current | Borrowings at | Letters of Credit at | Available Capacity at | ||||||||||
Credit Facility | Expiration | Capacity | March 31, 2015 | March 31, 2015 | March 31, 2015 | ||||||||
Revolving Credit Facility | May 29, 2019 | $ | 500 | $ | 103 | $ | 22 | $ | 375 | ||||
• | Evaluate amending and extending our Revolving Credit Facility for an additional year. |
• | Evaluate the conversion of our $300 million variable-rate Corporate term loan to fixed rate debt. |
Rating Agency | Senior Unsecured Rating | Outlook |
S&P | BBB | Stable |
Moody’s | Baa1 | Stable |
Fitch | BBB+ | Stable |
Rating Agency | Senior Secured Rating |
S&P | A- |
Moody’s | A1 |
Fitch | A |
Expenditures for the | Total | Total | Total | ||||||||||||
Three Months Ended March 31, 2015 (a) | 2015 Planned Expenditures (b) | 2016 Planned Expenditures | 2017 Planned Expenditures | ||||||||||||
Utilities: | |||||||||||||||
Electric Utilities | $ | 29,376 | $ | 229,300 | $ | 225,400 | $ | 135,600 | |||||||
Gas Utilities | 12,006 | 83,600 | 60,100 | 71,800 | |||||||||||
Cost of Service Gas | — | — | 40,000 | 50,000 | |||||||||||
Non-regulated Energy: | |||||||||||||||
Power Generation | 3,465 | 8,000 | 2,000 | 2,600 | |||||||||||
Coal Mining | 4,287 | 7,000 | 6,000 | 6,600 | |||||||||||
Oil and Gas (c) | 47,912 | 167,000 | 122,000 | 120,000 | |||||||||||
Corporate | 1,433 | 6,100 | 1,500 | 3,600 | |||||||||||
$ | 98,479 | $ | 501,000 | $ | 457,000 | $ | 390,200 | ||||||||
(c) | Our Oil and Gas segment contracted for two additional drilling rigs to support drilling operations in the southern Piceance Basin. Drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads. Due to the partial carryover of 2014 planned Mancos and other drilling capital to 2015, and the addition of one more Mancos well to the 2015 drilling plan, we have increased our planned 2015 capital expenditures to $167 million from $123 million. |
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
Net derivative (liabilities) assets | $ | (20,818 | ) | $ | (16,914 | ) | $ | (3,693 | ) | ||
Cash collateral offset in Derivatives | 20,818 | 16,914 | 5,539 | ||||||||
Cash Collateral included in Other current assets | 3,818 | 3,093 | 1,917 | ||||||||
Net asset (liability) position | $ | 3,818 | $ | 3,093 | $ | 3,763 | |||||
March 31, | June 30, | September 30, | December 31, | Total Year | |||||||||||
2015 | |||||||||||||||
Swaps - MMBtu | — | 1,180,000 | 955,000 | 1,000,000 | 3,135,000 | ||||||||||
Weighted Average Price per MMBtu | $ | — | $ | 4.03 | $ | 4.00 | $ | 4.04 | $ | 4.03 | |||||
2016 | |||||||||||||||
Swaps - MMBtu | 585,000 | 557,500 | 545,000 | 545,000 | 2,232,500 | ||||||||||
Weighted Average Price per MMBtu | $ | 3.87 | $ | 3.87 | $ | 3.91 | $ | 3.90 | $ | 3.89 | |||||
March 31, | June 30, | September 30, | December 31, | Total Year | |||||||||||
2015 | |||||||||||||||
Swaps - Bbls | — | 53,000 | 54,000 | 48,000 | 155,000 | ||||||||||
Weighted Average Price per Bbl | $ | — | $ | 86.56 | $ | 80.70 | $ | 79.56 | $ | 82.35 | |||||
2016 | |||||||||||||||
Swaps - Bbls | 39,000 | 39,000 | 36,000 | 36,000 | 150,000 | ||||||||||
Weighted Average Price per Bbl | $ | 84.55 | $ | 84.55 | $ | 84.55 | $ | 84.55 | $ | 84.55 | |||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
Net derivative (liabilities) assets | $ | 14,364 | $ | 14,684 | $ | (3,601 | ) | ||||
Cash collateral offset in Derivatives | (14,364 | ) | (14,684 | ) | 3,601 | ||||||
Cash Collateral included in Other current assets | 3,286 | 4,392 | 4,067 | ||||||||
Net asset (liability) position | $ | 3,286 | $ | 4,392 | $ | 4,067 | |||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||||
Designated Interest Rate Swaps (a) | Designated Interest Rate Swaps (a) | Designated Interest Rate Swaps (a) | |||||||||
Notional | $ | 75,000 | $ | 75,000 | $ | 75,000 | |||||
Weighted average fixed interest rate | 4.97 | % | 4.97 | % | 4.97 | % | |||||
Maximum terms in years | 1.75 | 2.00 | 2.75 | ||||||||
Derivative liabilities, current | $ | 3,342 | $ | 3,340 | $ | 3,498 | |||||
Derivative liabilities, non-current | $ | 2,143 | $ | 2,680 | $ | 4,805 | |||||
Pre-tax accumulated other comprehensive income (loss) | $ | (5,485 | ) | $ | (6,020 | ) | $ | (8,303 | ) | ||
(a) | These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related borrowings. |
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 |
Exhibit Number | Description |
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 January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010). |
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 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 Registrant’s Form 8-K filed on November 18, 2013). |
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). |
Exhibit 4.4* | 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 10.1* | Credit Agreement dated April 13, 2015 among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on April 14, 2015). |
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. |
/s/ David R. Emery | ||
David R. Emery, Chairman, President and | ||
Chief Executive Officer | ||
/s/ Richard W. Kinzley | ||
Richard W. Kinzley, Senior Vice President and | ||
Chief Financial Officer | ||
Dated: | May 5, 2015 | |
Exhibit Number | Description |
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 January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010). |
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). |
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). |
Exhibit 4.4* | 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 10.1* | Credit Agreement dated April 13, 2015 among Black Hills Corporation, as Borrower, JPMorgan Chase Bank, N. A., in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed on April 14, 2015). |
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. |