Document and Entity Information
Document and Entity Information Document - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 05, 2016 | Jun. 30, 2015 | |
Entity Information [Line Items] | |||
Entity Registrant Name | NORTHWESTERN CORPORATION | ||
Entity Central Index Key | 73,088 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 48,178,591 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 2,294,283,000 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues | |||
Electric | $ 944,428 | $ 877,967 | $ 865,239 |
Gas | 269,871 | 326,896 | 287,605 |
Other | 0 | 0 | 1,675 |
Total Revenues | 1,214,299 | 1,204,863 | 1,154,519 |
Operating Expenses | |||
Cost of sales | 372,864 | 482,591 | 479,546 |
Operating, general and administrative | 297,475 | 305,886 | 285,569 |
Property and other taxes | 133,442 | 114,592 | 105,540 |
Depreciation and depletion | 144,702 | 123,776 | 112,831 |
Total Operating Expenses | 948,483 | 1,026,845 | 983,486 |
Operating Income | 265,816 | 178,018 | 171,033 |
Interest Expense, net | (92,153) | (77,802) | (70,486) |
Other Income, net | 7,583 | 10,198 | 7,737 |
Income Before Income Taxes | 181,246 | 110,414 | 108,284 |
Income Tax Benefit (Expense) | (30,037) | 10,272 | (14,301) |
Net Income | $ 151,209 | $ 120,686 | $ 93,983 |
Average Common Shares Outstanding | 47,298,350 | 40,156,177 | 38,144,852 |
Basic Earnings per Average Common Share | $ 3.20 | $ 3.01 | $ 2.46 |
Diluted Earnings per Average Common Share | $ 3.17 | $ 2.99 | $ 2.46 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Income | $ 151,209 | $ 120,686 | $ 93,983 |
Other comprehensive income (loss), net of tax: | |||
Reclassification of net gains on derivative instruments to net income | (698) | (684) | (730) |
Realized loss on cash flow hedging activities | 0 | (11,145) | 0 |
Pension and postretirement medical liability adjustment | 310 | 82 | 963 |
Foreign currency translation adjustment | 558 | 265 | 166 |
Total Other Comprehensive Income (Loss) | 170 | (11,482) | 399 |
Comprehensive Income | $ 151,379 | $ 109,204 | $ 94,382 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 11,980 | $ 20,362 |
Restricted cash | 6,634 | 29,662 |
Accounts receivable, net | 154,410 | 163,479 |
Inventories | 53,458 | 55,094 |
Regulatory assets | 51,348 | 47,374 |
Deferred income taxes | 0 | 20,843 |
Other | 8,830 | 14,071 |
Total current assets | 286,660 | 350,885 |
Property, plant, and equipment, net | 4,059,499 | 3,758,008 |
Goodwill | 357,586 | 355,128 |
Regulatory assets | 517,223 | 455,757 |
Other noncurrent assets | 57,672 | 54,165 |
Total assets | 5,278,640 | 4,973,943 |
Current Liabilities: | ||
Current maturities of capital leases | 1,837 | 1,730 |
Short-term borrowings | 229,874 | 267,840 |
Accounts payable | 74,511 | 81,961 |
Accrued expenses | 183,988 | 206,882 |
Regulatory liabilities | 80,990 | 56,169 |
Total current liabilities | 571,200 | 614,582 |
Long-term capital leases | 26,325 | 28,162 |
Long-term debt | 1,782,128 | 1,662,099 |
Deferred income taxes | 501,532 | 446,600 |
Noncurrent regulatory liabilities | 378,711 | 362,228 |
Other noncurrent liabilities | 418,570 | 382,489 |
Total liabilities | $ 3,678,466 | $ 3,496,160 |
Commitments and Contingencies (Note 19) | ||
Shareholders' Equity: | ||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,788,961 and 48,172,158 respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | $ 518 | $ 505 |
Treasury stock at cost | (93,948) | (92,558) |
Paid-in capital | 1,376,291 | 1,313,844 |
Retained earnings | 325,909 | 264,758 |
Accumulated other comprehensive income | (8,596) | (8,766) |
Total shareholders' equity | 1,600,174 | 1,477,783 |
Total liabilities and shareholders' equity | $ 5,278,640 | $ 4,973,943 |
CONSOLIDATED BALANCE SHEETS PAR
CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Common stock, par or stated value per share | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 200,000,000 | 200,000,000 |
Common Stock, shares issued | 51,788,961 | 50,522,280 |
Common Stock, shares outstanding | 48,172,158 | 46,914,811 |
Preferred stock, par or stated value per share | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred Stock, shares issued | 0 | 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
OPERATING ACTIVITIES: | |||
Net Income | $ 151,209 | $ 120,686 | $ 93,983 |
Items not affecting cash: | |||
Depreciation and depletion | 144,702 | 123,776 | 112,831 |
Amortization of debt issue costs, discount and deferred hedge gain | 2,258 | 5,033 | 2,039 |
Stock based compensation costs | 5,082 | 3,262 | 2,404 |
Equity portion of allowance for funds used during construction | (8,684) | (6,554) | (5,050) |
Gain on disposition of assets | (20) | (1,330) | (721) |
Deferred income taxes | 33,886 | (9,612) | 54,617 |
Changes in current assets and liabilities: | |||
Restricted cash | 6,920 | (6,408) | (196) |
Accounts receivable | 9,069 | 12,622 | (30,792) |
Inventories | 1,636 | 747 | 181 |
Other current assets | 5,514 | 4,201 | (2,940) |
Accounts payable | (11,169) | (9,565) | 6,235 |
Accrued expenses | (22,738) | 8,530 | 1,949 |
Regulatory assets | (3,974) | (8,952) | (2,846) |
Regulatory liabilities | 24,821 | 9,763 | (2,019) |
Other noncurrent assets | (5,584) | 2,853 | (43,714) |
Other noncurrent liabilities | 6,890 | 987 | 7,755 |
Cash provided by operating activities | 339,818 | 250,039 | 193,716 |
INVESTING ACTIVITIES: | |||
Property, plant, and equipment additions | (283,705) | (270,384) | (230,454) |
Acquisitions | (146,668) | (903,573) | (68,666) |
Proceeds from sale of assets | 30,209 | 1,535 | 3,766 |
Change in restricted cash | 16,108 | (16,358) | 0 |
Investment in New Market Tax Credit program | 0 | (18,169) | 0 |
Cash used in investing activities | (384,056) | (1,206,949) | (295,354) |
FINANCING ACTIVITIES: | |||
Dividends on common stock | (90,058) | (65,019) | (57,684) |
Proceeds from issuance of common stock, net | 56,651 | 399,207 | 56,825 |
Issuance of long-term debt | 270,000 | 505,789 | 100,000 |
Repayment of long-term debt | (150,025) | (90) | (149) |
(Repayments) issuances of short-term borrowings, net | (37,966) | 126,890 | 18,016 |
Treasury stock activity | (664) | (814) | (1,042) |
Financing costs | (12,082) | (5,248) | (7,593) |
Cash provided by financing activities | 35,856 | 960,715 | 108,373 |
(Decrease) Increase in Cash and Cash Equivalents | (8,382) | 3,805 | 6,735 |
Cash and Cash Equivalents, beginning of period | 20,362 | 16,557 | 9,822 |
Cash and Cash Equivalents, end of period | $ 11,980 | $ 20,362 | $ 16,557 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Paid-in Capital | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income |
Balance at Dec. 31, 2012 | $ 934,032 | $ 408 | $ 849,218 | $ (90,702) | $ 172,791 | $ 2,317 |
Shares, Balance at Dec. 31, 2012 | 40,792 | 3,571 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Net Income | 93,983 | $ 0 | 0 | $ 0 | 93,983 | 0 |
Other comprehensive income: | ||||||
Foreign currency translation adjustment | 166 | 0 | 0 | 0 | 0 | 166 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (730) | 0 | 0 | 0 | 0 | (730) |
Realized loss on cash flow hedging activities | 0 | |||||
Pension and postretirement medical liability adjustment, net of tax | 963 | 0 | 0 | 0 | 0 | 963 |
Stock based compensation, value | 2,663 | $ 1 | 3,987 | $ (1,325) | 0 | 0 |
Stock based compensation, shares | 167 | 35 | ||||
Issuance of shares, value | 57,276 | $ 14 | 56,979 | 0 | 0 | |
Issuance of shares, shares | 1,381 | |||||
Issuance of shares, value, treasury stock reissued | $ 283 | |||||
Issuance of shares, shares, treasury stock reissued | (11) | |||||
Dividends on common stock | $ (57,683) | $ 0 | 0 | $ 0 | (57,683) | 0 |
Dividends per share | $ 1.52 | |||||
Balance at Dec. 31, 2013 | $ 1,030,670 | $ 423 | 910,184 | $ (91,744) | 209,091 | 2,716 |
Shares, Balance at Dec. 31, 2013 | 42,340 | 3,595 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Net Income | 120,686 | $ 0 | 0 | $ 0 | 120,686 | 0 |
Other comprehensive income: | ||||||
Foreign currency translation adjustment | 265 | 0 | 0 | 0 | 0 | 265 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (684) | 0 | 0 | 0 | 0 | (684) |
Realized loss on cash flow hedging activities | (11,145) | 0 | 0 | 0 | 0 | (11,145) |
Pension and postretirement medical liability adjustment, net of tax | 82 | 0 | 0 | 0 | 0 | 82 |
Stock based compensation, value | 3,423 | $ 0 | 4,288 | $ (865) | 0 | 0 |
Stock based compensation, shares | 119 | 12 | ||||
Issuance of shares, value | 399,505 | $ 82 | 399,372 | 0 | 0 | |
Issuance of shares, shares | 8,063 | |||||
Issuance of shares, value, treasury stock reissued | $ 51 | |||||
Issuance of shares, shares, treasury stock reissued | 0 | |||||
Dividends on common stock | $ (65,019) | $ 0 | 0 | $ 0 | (65,019) | 0 |
Dividends per share | $ 1.60 | |||||
Balance at Dec. 31, 2014 | $ 1,477,783 | $ 505 | 1,313,844 | $ (92,558) | 264,758 | (8,766) |
Shares, Balance at Dec. 31, 2014 | 50,522 | 3,607 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Net Income | 151,209 | $ 0 | 0 | $ 0 | 151,209 | 0 |
Other comprehensive income: | ||||||
Foreign currency translation adjustment | 558 | 0 | 0 | 0 | 0 | 558 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (698) | 0 | 0 | 0 | 0 | (698) |
Realized loss on cash flow hedging activities | 0 | |||||
Pension and postretirement medical liability adjustment, net of tax | 310 | 0 | 0 | 0 | 0 | 310 |
Stock based compensation, value | 2,489 | $ 0 | 4,345 | $ (1,856) | 0 | 0 |
Stock based compensation, shares | 167 | 10 | ||||
Issuance of shares, value | 58,581 | $ 13 | 58,102 | 0 | 0 | |
Issuance of shares, shares | 1,100 | |||||
Issuance of shares, value, treasury stock reissued | $ 466 | |||||
Issuance of shares, shares, treasury stock reissued | 0 | |||||
Dividends on common stock | $ (90,058) | $ 0 | 0 | $ 0 | (90,058) | 0 |
Dividends per share | $ 1.92 | |||||
Balance at Dec. 31, 2015 | $ 1,600,174 | $ 518 | $ 1,376,291 | $ (93,948) | $ 325,909 | $ (8,596) |
Shares, Balance at Dec. 31, 2015 | 51,789 | 3,617 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 12 Months Ended |
Dec. 31, 2015 | |
Nature of Operations and Basis of Consolidation [Abstract] | |
Nature of Operations and Basis of Consolidation | (1) Nature of Operations and Basis of Consolidation NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 701,000 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002 . The Consolidated Financial Statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The accompanying Consolidated Financial Statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. All intercompany balances and transactions have been eliminated from the Consolidated Financial Statements. Events occurring subsequent to December 31, 2015 , have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. Our November 2014 acquisition of hydro generating assets is included in the results of operations for the years ended December 31, 2015 and 2014, and impacts the comparability of the current year financial statements to prior years. For a further discussion of this acquisition, see Note 3 - Acquisitions. Variable Interest Entities A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain QF plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 MW coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per MWH (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $273.1 million through 2024 . For further discussion of our gross QF liability, see Note 19 - Commitments and Contingencies. During the years ended December 31, 2015 , 2014 and 2013 purchases from this QF were approximately $24.3 million , $24.4 million , and $23.8 million , respectively. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | (2) Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, asset retirement obligations, uncollectible accounts, our QF liability, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. Revenue Recognition Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to customers, but not yet billed at month-end. Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $4.0 million and $4.3 million at December 31, 2015 and December 31, 2014 , respectively. Receivables include unbilled revenues of $74.5 million and $70.3 million at December 31, 2015 and December 31, 2014 , respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2015 2014 Materials and supplies $31,789 $30,672 Storage gas and fuel 21,669 24,422 Total Inventory $53,458 $55,094 Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Income Statements at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets. Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging . All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated other comprehensive income (AOCI) and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9, Risk Management and Hedging Activities for further discussion of our derivative activity. Property, Plant and Equipment Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 7.5% , 8.0% , and 8.1% , for Montana and South Dakota for 2015 , 2014 , and 2013 , respectively. AFUDC capitalized totaled $13.6 million for the year ended December 31, 2015 , $10.8 million for the year ended December 31, 2014 and $8.2 million for the year ended December 31, 2013 for Montana and South Dakota combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to 50 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.3% , 2.9% , and 3.2% for 2015 , 2014 , and 2013 , respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2015 2014 Pension and other employee benefits $131,887 $137,377 Future QF obligation, net 138,310 136,893 Environmental 30,226 28,060 Customer advances 36,046 30,001 Asset retirement obligations 35,532 21,435 Other 46,569 28,723 Total $418,570 $382,489 Income Taxes Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes. Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows. Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. Business Combination The acquisition of hydro generating assets and the Beethoven wind project was accounted for using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information see Note 3 - Acquisitions. Accounting Standards Issued In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The FASB delayed the effective date of this guidance to the first quarter of 2018, with early adoption permitted as of the original effective date of the first quarter of 2017. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. The new guidance will be effective for us in our first quarter of 2016. Early adoption is permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. In February 2015, the FASB issued consolidation guidance that eliminated two consolidation models and requires all legal entities to be evaluated under a voting interest entity model or a variable interest entity model. Both models require the reporting entity to identify whether it has a controlling financial interest in a legal entity and is therefore required to consolidate the entity. The new guidance will be effective for us in our first quarter of 2016. Early adoption is permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. Accounting Standards Adopted In November 2015, the FASB issued accounting guidance that changes the presentation of deferred taxes. Deferred tax assets and deferred tax liabilities will be presented as noncurrent in a classified balance sheet, as compared with previous guidance requiring separate presentation of deferred tax assets and deferred tax liabilities as current and noncurrent in a classified balance sheet. We early adopted this standard in the fourth quarter of 2015 with an impact to the presentation of the Consolidated Balance Sheet prospectively, and therefore no longer reflects current deferred tax assets. The prior reporting period was not retrospectively adjusted. In May 2015, the FASB issued accounting guidance that removed the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and certain disclosures related to those investments. We early adopted this standard in the fourth quarter of 2015. As a result, net asset value investments are no longer included in Level 2 and Level 3 within the fair value hierarchy. Supplemental Cash Flow Information Year Ended December 31, 2015 2014 2013 (in thousands) Cash (received) paid for: Income taxes $ (1,284 ) $ 35 $ 50 Interest 81,572 63,482 57,789 Significant non-cash transactions: Capital expenditures included in trade accounts payable 12,834 8,555 12,025 |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | (3) Acquisitions Hydro Transaction In November 2014, we completed the purchase of 11 hydroelectric generating facilities and associated assets located in Montana for an adjusted purchase price of approximately $904 million (Hydro Transaction). The addition of hydroelectric generation provides long-term supply diversity to our portfolio and reduces risks associated with variable fuel prices. The Hydro Transaction allows us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we are less exposed to market volatility and better positioned to control the cost of supplying electricity to our customers. We completed the purchase accounting in 2015 and, as a result, increased goodwill by approximately $2.5 million primarily due to our assessment of environmental matters. Kerr Project - The Hydro Transaction included the Kerr Project. Upon the close of the Hydro Transaction, we assumed temporary ownership of the Kerr Project until it was conveyed to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) on September 5, 2015, in accordance with the associated FERC license. Our purchase agreement for the Hydro Transaction included a $30 million reference price for the Kerr Project. In September 2015, the CSKT paid us $18.3 million , which was established through previous arbitration, and Talen Energy (formerly PPL Montana) paid the difference of $11.7 million to us. Upon receipt of the CSKT payment we conveyed the Kerr Project to the CSKT. The MPSC order approving the Hydro Transaction provided that customers would have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT. We sold any excess system generation, which was primarily due to our temporary ownership of the Kerr Project, in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. Therefore, during our temporary ownership a net benefit of approximately $2.7 million was provided to customers and there was no benefit to shareholders. For further discussion of the required compliance filing see Note 4 - Regulatory Matters. South Dakota Wind Generation In September 2015, we completed the purchase of the 80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million . The Beethoven project was not submitted in the South Dakota electric rate filing made in December 2014; however, we reached a stipulated settlement agreement in September 2015 that allowed us to include Beethoven in rate base and collect approximately $9.0 million annually. For further discussion of this settlement agreement see Note 4 - Regulatory Matters. The Beethoven purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition as follows: Purchase Price Allocation Assets Acquired Property Plant and Equipment $143.0 Other Prepayments $0.1 Total Assets Acquired $143.1 Liabilities Assumed Other Current Liabilities $0.3 Total Liabilities Assumed $0.3 Total Purchase Price $142.8 The purchase accounting was completed during the fourth quarter of 2015. The pro forma results as if the Beethoven acquisition occurred on January 1, 2015 would not be materially different from our financial results for the twelve months ended December 31, 2015. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2015 | |
Regulated Operations [Abstract] | |
Regulatory Matters | (4) Regulatory Matters South Dakota Electric Rate Filing In December 2014, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for an annual increase to electric rates totaling approximately $26.5 million . Our request was based on an overall rate of return of 7.67% and rate base of $447.4 million . In September 2015, we reached a settlement with the SDPUC Staff and intervenors providing for an increase in base rates of approximately $20.2 million , based on an overall rate of return of 7.24% . In addition, the settlement would allow us to collect approximately $9 million annually related to the Beethoven wind project as discussed above. The settlement was approved by the SDPUC in October 2015. We have been collecting interim rates since July 1, 2015, based on our original filing, with the new lower rate implemented January 1, 2016. As of December 31, 2015, we have deferred approximately $6.3 million that will be refunded to customers by April 2016. Hydro Compliance Filing In December 2015, we submitted the required hydro compliance filing to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts for the Hydro Transaction. Interim rates were approved in January 2016, and we expect the MPSC to issue a final order during the second quarter of 2016. Due to the timing of the rate adjustment, as of December 31, 2015, we have deferred revenue of approximately $6.7 million that will be refunded to customers in 2016. Montana Electric and Natural Gas Tracker Filings Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric supply procurement activities were prudent. During the second quarter of 2015, we filed our annual electric and natural gas supply tracker filings for the 2014/2015 tracker period and received orders from the MPSC approving those filings on an interim basis. Our electric and natural gas supply tracker filings for the 2013/2014 and 2012/2013 tracker periods are part of consolidated dockets. Electric Tracker - Our 2013/2014 electric tracker filing included market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. The MCC, Montana Environmental Information Center and Sierra Club have intervened in the consolidated docket to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A hearing was held in October 2015 related to the 2013/2014 and 2012/2013 consolidated tracker docket and we expect the MPSC to issue a final order in the first quarter of 2016. In November 2015, we filed a motion with the MPSC for an order approving a Stipulation and Settlement Agreement between us and the MCC on the 2014/2015 electric supply tracker which requires us to include a $0.7 million reduction for production tax credits, suspend the hedging of purchase power costs going forward without first obtaining approval from the MPSC, and to make a compliance filing which removes lost revenues from electric rates effective December 1, 2015. We expect the MPSC to issue a final order in the first quarter of 2016. Natural Gas Tracker - In October 2015, we received a final order in the natural gas consolidated 2013/2014 and 2012/2013 tracker docket. This consolidated docket included our request to continue collecting the cost of service for natural gas production interests acquired in December 2013 and in August 2012 in northern Montana's Bear Paw Basin (Bear Paw) on an interim basis. The MPSC final order requires that we revise the bridge rates currently used to reflect expected 2015 fixed cost revenue requirements. In addition, the order requires us to make a filing by September 2016 to address the cost-recovery of our gas production fields. As of December 31, 2015, we have deferred revenue of approximately $1.2 million consistent with the final order. In November 2015, we filed a motion with the MPSC for an order approving a Stipulation and Settlement Agreement between us and the MCC on the 2014/2015 natural gas supply tracker which requires us to refund our customers approximately $1.5 million as a result of revising the Bear Paw bridge rates to our expected 2015 fixed cost requirements through October 2015, adjust our lost revenues calculation for the 2014/2015 tracker period, and to make a compliance filing which removes lost revenues from natural gas rates effective December 1, 2015. We expect the MPSC to issue a final order in the first quarter of 2016. Electric and Natural Gas Lost Revenue Adjustment Mechanism - Demand-side management (DSM) lowers our sales to customers. Base rates, including impacts of past DSM activities, are reset in general rate filings. Between rate filings, the implementation of energy saving measures result in increased lost revenues related to DSM activities. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM through our supply tracker filings. In an order issued in October 2013, which was related to our 2011/2012 electric supply tracker, the MPSC required us to lower our LRAM revenue recovery and imposed a new burden of proof on us for future LRAM recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In June 2015, the MPSC held a hearing to address these issues. In October 2015, the MPSC issued an order to eliminate the LRAM prospectively effective December 1, 2015. Based on the October 2013 MPSC order, we have recognized $7.1 million of DSM lost revenues for each annual electric supply tracker period (cumulatively July 1, 2012 through November 30, 2015) and deferred the remaining portion. As of December 31, 2015 we have cumulative deferred revenue of approximately $13.4 million , which is recorded within current regulatory liabilities in the Consolidated Balance Sheets. Since the 2012/2013, 2013/2014, and 2014/2015 annual electric tracker filings are still subject to final approval, the MPSC may ultimately require us to refund more than we have deferred or approve recovery of more DSM lost revenues than we have recognized since July 2012. Dave Gates Generating Station at Mill Creek (DGGS) In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of December 31, 2015, we have cumulative deferred revenue of approximately $27.3 million , which is subject to refund and recorded within current regulatory liabilities in the Consolidated Balance Sheets. In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. There is no deadline by which FERC must act on our rehearing petition. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal would likely extend into 2017 or beyond. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. As of December 31, 2015, the DGGS net property, plant and equipment is approximately $156.2 million. We are evaluating options to use DGGS in combination with other generation resources, including our hydro facilities, to minimize portfolio costs, which may facilitate cost recovery. The cost recovery of any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | (5) Regulatory Assets and Liabilities We prepare our Consolidated Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to the customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Note Reference Remaining Amortization Period December 31, 2015 2014 (in thousands) Pension 15 Undetermined $ 135,057 $ 139,050 Employee related benefits 15 Undetermined 21,055 19,080 Distribution infrastructure projects 2 Years 6,272 9,407 Environmental clean-up 19 Various 14,237 13,741 Supply costs 1 Year 29,604 29,200 Income taxes 13 Plant Lives 319,973 263,764 Deferred financing costs Various 19,978 12,151 State & local taxes & fees Various 7,724 5,319 Other — Various 14,671 11,419 Total Regulatory Assets $ 568,571 $ 503,131 Removal cost 7 Various $ 368,467 $ 351,676 Gas storage sales 24 Years 9,990 10,410 Supply costs 1 Year 13,685 14,569 Deferred revenue 4 1 Year 58,868 36,592 Environmental clean-up Various 7,089 2,501 State & local taxes & fees 1 Year 1,566 511 Other Various 36 2,138 Total Regulatory Liabilities $ 459,701 $ 418,397 Pension and Employee Related Benefits We recognize the unfunded portion of plan benefit obligations in the Consolidated Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis. The MPSC allows recovery of other employee related benefits on a cash basis. Montana Distribution System Infrastructure Project (DSIP) We have an accounting order to defer certain incremental operating and maintenance expenses associated with DSIP. Pursuant to the order, we deferred expenses incurred during 2011 and 2012 as a regulatory asset associated with the phase-in portion of the DSIP. These costs are being amortized into expense over five years, which began in 2013. Environmental Clean-up Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 19 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. We record changes in the regulatory asset consistent with changes in our environmental liabilities. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period. Supply Costs The MPSC, SDPUC and NPSC have authorized the use of electric and natural gas supply cost trackers that enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, we have recorded a regulatory asset and liability to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on electric and natural gas supply costs under collected, or apply interest in an over collection, of 7.5% , in Montana; 7.2% and 7.8% , respectively, in South Dakota; and 8.5% for natural gas in Nebraska. Income Taxes Tax assets primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, removal costs, capitalized interest and contributions in aid of construction that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Deferred Financing Costs Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. These amounts are amortized over the life of the new debt. State & Local Taxes & Fees (Montana Property Tax Tracker) The MPSC has authorized recovery in the property tax tracker of approximately 60% of the estimated increase in property taxes as compared with the related amount included in rates during our last rate case. Removal Cost The anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. Therefore, consistent with this regulated treatment, we reflect this accrual of removal costs for our regulated assets by increasing our regulatory liability. See Note 7 - Asset Retirement Obligations, for further information regarding this item. Gas Storage Sales A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base. Deferred Revenue We have deferred revenue associated with DGGS, DSM, Hydro and Gas Production, which may be subject to refund as we have open regulatory proceedings. See Note 4 - Regulatory Matters, for further information regarding these items. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | (6) Property, Plant and Equipment The following table presents the major classifications of our property, plant and equipment (in thousands): Estimated Useful Life December 31, 2015 2014 (years) (in thousands) Land, land rights and easements 54 – 96 $ 135,930 $ 130,816 Building and improvements 27 – 64 219,907 168,041 Transmission, distribution, and storage 15 – 85 2,785,944 2,579,861 Generation 25 – 50 1,154,513 1,044,764 Plant acquisition adjustment 25 – 50 685,417 654,835 Other 2 – 45 445,679 326,211 Construction work in process –— 75,694 221,868 Total property, plant and equipment 5,503,084 5,126,396 Less accumulated depreciation (1,443,585 ) (1,368,388 ) Net property, plant and equipment $ 4,059,499 $ 3,758,008 In 2014, we acquired hydro generating assets which resulted in an increase of approximately $870 million in property, plant and equipment. In 2015, we acquired the Beethoven wind project, which resulted in an increase of approximately $143 million in property, plant and equipment. For both acquisitions, we recorded the plant assets at original cost, less accumulated depreciation with an acquisition adjustment in accordance with FERC rules. The plant acquisition adjustment balance above also includes an amount related to the inclusion of our interest in Colstrip Unit 4 in rate base in 2009. The acquisition adjustment is being amortized on a straight-line basis over the estimated remaining useful life in depreciation expense. Plant and equipment under capital lease were $21.3 million and $23.4 million as of December 31, 2015 and 2014 , respectively, which included $21.1 million and $23.1 million as of December 31, 2015 and 2014 , respectively, related to a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a capital lease. Jointly Owned Electric Generating Plant We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income. The participants each finance their own investment. Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone (SD) Neal #4 (IA) Coyote (ND) Colstrip Unit 4 (MT) December 31, 2015 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,740 $ 60,088 $ 46,387 $ 289,604 Accumulated depreciation 37,522 27,940 37,160 73,328 December 31, 2014 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 61,628 $ 59,579 $ 46,045 $ 292,806 Accumulated depreciation 46,741 27,742 36,649 72,976 |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | (7) Asset Retirement Obligations We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our property, plant and equipment and other noncurrent liabilities. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligation (ARO) is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, and our obligation to plug and abandon oil and gas wells at the end of their life. The following table presents the change in our gross conditional ARO (in thousands): December 31, 2015 2014 Liability at January 1, $ 21,435 $ 20,886 Accretion expense 1,437 1,073 Liabilities incurred 12,682 552 Liabilities settled (22 ) (85 ) Revisions to cash flows — (991 ) Liability at December 31, $ 35,532 $ 21,435 The EPA's rule regulating Coal Combustion Residuals (CCRs) became effective in October 2015. The rule imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plants and not closed. Based on our assessment of these requirements, we recorded an increase to our existing AROs of approximately $12.0 million during the second quarter of 2015. See Note 19 - Commitments and Contingencies for further discussion of these requirements. In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our Hydro Transaction; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements. We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. The recorded amounts of estimated future removal costs are considered regulatory liabilities and do not represent legal retirement obligations. See Note 5 - Regulatory Assets and Liabilities for removal costs recorded as regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2015 and 2014 . |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill [Abstract] | |
Goodwill | (8) Goodwill We completed our annual goodwill impairment test as of April 1, 2015 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections. Goodwill increased $2.5 million during the year ended December 31, 2015 , due to the finalization of our assessment of environmental matters as part of the Hydro Transaction. Goodwill by segment is as follows (in thousands): December 31, 2015 2014 Electric $ 243,558 $ 241,100 Natural gas 114,028 114,028 Total $ 357,586 $ 355,128 |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management and Hedging Activities | (9) Risk Management and Hedging Activities Nature of Our Business and Associated Risks We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Consolidated Financial Statements at December 31, 2015 and 2014 . Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivative activities by assessing the creditworthiness of potential counterparties before entering into transactions and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements - standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements - standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements - standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements - standardized power sales contracts in the electric industry. Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCI to Income Amount Reclassified from AOCI into Income during the Year Ended December 31, 2015 Interest rate contracts Interest Expense $ 1,125 A net pre-tax loss of approximately $14.9 million is remaining in AOCI as of December 31, 2015 , and we expect to reclassify approximately $0.3 million of net pre-tax gains from AOCI into interest expense during the next twelve months. These amounts relate to terminated swaps. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | (10) Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: • Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities; • Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and • Level 3 – Significant inputs that are generally not observable from market activity. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 December 31, 2014 Restricted cash $ 13,140 $ — $ — $ — $ 13,140 Rabbi trust investments 21,594 — — — 21,594 Total $ 34,734 $ — $ — $ — $ 34,734 Restricted cash represents amounts held in money market mutual funds. Rabbi trust assets represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,782,128 $ 1,844,974 $ 1,662,099 $ 1,817,642 Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy. |
Short-Term Borrowings and Credi
Short-Term Borrowings and Credit Arrangements | 12 Months Ended |
Dec. 31, 2015 | |
Short-term Debt [Abstract] | |
Short-Term Debt | (11) Short-Term Borrowings and Credit Arrangements Short-Term Borrowings Short-term borrowings and the corresponding weighted average interest rates as of December 31 were as follows (dollars in millions, except for percentages): 2015 2014 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 229.9 0.82 % $ 267.8 0.50 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2015 2014 Maximum short-term debt outstanding $ 267.8 $ 276.9 Average short-term debt outstanding $ 192.8 $ 132.5 Weighted-average interest rate 0.61 % 0.39 % Under our commercial paper program we may issue unsecured commercial paper notes on a private placement basis up to a maximum aggregate amount outstanding at any time of $340 million to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Commercial paper issuances are supported by available capacity under our unsecured revolving credit facility. Unsecured Revolving Line of Credit We have a $350 million unsecured revolving credit facility in place that does not amortize and is scheduled to expire on November 5, 2018 . The facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75% . A total of eight banks participate in the facility, with no one bank providing more than 21% of the total availability. There were no direct borrowings or letters of credit outstanding as of December 31, 2015 . Commitment fees for the unsecured revolving line of credit were $0.4 million for each of the years ended December 31, 2015 and 2014 . The credit facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65% . The facility also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the credit facility; however a default on the credit facility would not trigger a default on any other obligations. |
Long-Term Debt and Capital Leas
Long-Term Debt and Capital Leases | 12 Months Ended |
Dec. 31, 2015 | |
Long-term Debt and Capital Lease Obligations [Abstract] | |
Long-term Debt And Capital Leases | (12) Long-Term Debt and Capital Leases Long-term debt and capital leases consisted of the following (in thousands): December 31, Due 2015 2014 Unsecured Debt: Unsecured Revolving Line of Credit 2018 $ — $ — Secured Debt: Mortgage bonds— South Dakota—6.05% 2018 55,000 55,000 South Dakota—5.01% 2025 64,000 64,000 South Dakota—4.15% 2042 30,000 30,000 South Dakota—4.30% 2052 20,000 20,000 South Dakota—4.85% 2043 50,000 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 — Montana—6.04% — 150,000 Montana—6.34% 2019 250,000 250,000 Montana—5.71% 2039 55,000 55,000 Montana—5.01% 2025 161,000 161,000 Montana—4.15% 2042 60,000 60,000 Montana—4.30% 2052 40,000 40,000 Montana—4.85% 2043 15,000 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 — Montana—4.11% 2045 125,000 — Pollution control obligations— Montana—4.65% 2023 170,205 170,205 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds — (54 ) (83 ) $ 1,782,128 $ 1,662,099 Less current maturities — — $ 1,782,128 $ 1,662,099 Capital Leases: Total Capital Leases Various $ 28,162 $ 29,892 Less current maturities (1,837 ) (1,730 ) $ 26,325 $ 28,162 Secured Debt First Mortgage Bonds and Pollution Control Obligations The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. All of such bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets. The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets. During September 2015, we issued $70 million of South Dakota First Mortgage Bonds at a fixed interest rate of 4.26% maturing in 2040 to finance the Beethoven wind project. The bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. In June 2015, we issued $200 million aggregate principal amount of Montana First Mortgage Bonds, which includes $75 million at a fixed interest rate of 3.11% maturing in 2025 and $125 million at a fixed interest rate of 4.11% maturing in 2045 . The bonds are secured by our electric and natural gas assets in Montana. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.04% , $150 million of Montana First Mortgage Bonds due 2016 and finance incremental Montana capital expenditures. As of December 31, 2015, we are in compliance with our financial debt covenants. Other Long-Term Debt During 2014 we entered into a New Market Tax Credit (NMTC) financing agreement, pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, to take advantage of a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement was structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment. The loans have a term of thirty years with an interest rate of approximately 1.146% . In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years. If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021. If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in other noncurrent assets in the Consolidated Balance Sheets. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and capital leases, during the next five years are $1.8 million in 2016 , $2.0 million in 2017 , $57.1 million in 2018 , $252.3 million in 2019 and $2.5 million in 2020 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | (13) Income Taxes Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2015 2014 2013 Federal Current $ (3,527 ) $ (405 ) $ 108 Deferred 33,031 (5,658 ) 18,150 Investment tax credits (232 ) (273 ) (335 ) State Current (90 ) 18 83 Deferred 855 (3,954 ) (3,705 ) Income Tax Expense (Benefit) $ 30,037 $ (10,272 ) $ 14,301 The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions 0.1 (1.8 ) (2.8 ) Flow-through repairs deductions (13.3 ) (22.9 ) (16.4 ) Recognition of unrecognized tax benefit — (11.4 ) — Production tax credits (3.2 ) (2.8 ) (2.9 ) Plant and depreciation of flow through items (1.6 ) 0.1 (0.5 ) Prior year permanent return to accrual adjustments 0.1 (4.7 ) 0.5 Other, net (0.5 ) (0.8 ) 0.3 Effective tax rate 16.6 % (9.3 )% 13.2 % The following table summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2015 2014 2013 Income Before Income Taxes $ 181,246 $ 110,414 $ 108,284 Income tax calculated at 35% federal statutory rate 63,436 38,645 37,899 Permanent or flow through adjustments: State tax income, net of federal provisions 301 (1,969 ) (3,082 ) Flow-through repairs deductions (24,079 ) (25,268 ) (17,763 ) Recognition of unrecognized tax benefit — (12,607 ) — Production tax credits (5,721 ) (3,136 ) (3,171 ) Plant and depreciation of flow through items (2,893 ) 74 (584 ) Prior year permanent return to accrual adjustments 207 (5,172 ) 541 Other, net (1,214 ) (839 ) 461 $ (33,399 ) $ (48,917 ) $ (23,598 ) Income Tax Expense (Benefit) $ 30,037 $ (10,272 ) $ 14,301 Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. The income tax benefit for 2014 reflects the release of approximately $12.6 million of unrecognized tax benefits due to the lapse of statutes of limitation in the third quarter of 2014. In addition, in the third quarter of 2014, we elected the safe harbor method related to the deductibility of repair costs. This resulted in an income tax benefit of approximately $4.3 million for the cumulative adjustment for years prior to 2014, which is included in the prior year permanent return to accrual adjustments. Deferred income taxes relate primarily to the difference between book and tax methods of depreciating property, amortizing tax-deductible goodwill, the difference in the recognition of revenues and expenses for book and tax purposes, certain natural gas and electric costs which are deferred for book purposes but expensed currently for tax purposes, and NOL carry forwards. We have elected under Internal Revenue Code 46(f)(2) to defer investment tax credit benefits and amortize them against expense and customer billing rates over the book life of the underlying plant. The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands): December 31, 2015 2014 Pension / postretirement benefits $ 54,440 $ 51,817 Unbilled revenue 28,390 19,863 Property taxes 24,650 881 Compensation accruals 17,441 17,315 Customer advances 14,197 11,817 AMT credit carryforward 13,143 10,357 Environmental liability 9,410 8,968 Production tax credit 6,550 6,452 Interest rate hedges 6,483 6,251 NOL carryforward 3,677 42,787 Regulatory liabilities 2,862 975 QF obligations 2,636 2,162 Reserves and accruals — 1,772 Other, net 3,696 4,415 Deferred Tax Asset 187,575 185,832 Excess tax depreciation (392,113 ) (349,428 ) Goodwill amortization (152,065 ) (137,090 ) Flow through depreciation (125,441 ) (103,677 ) Regulatory assets (14,901 ) (21,394 ) Reserves and accruals (4,587 ) — Deferred Tax Liability (689,107 ) (611,589 ) Deferred Tax Liability, net $ (501,532 ) $ (425,757 ) At December 31, 2015 we estimate our total federal NOL carryforward to be approximately $215.7 million prior to consideration of unrecognized tax benefits. If unused, our federal NOL carryforwards will expire as follows: $1.6 million in 2029 ; $127.5 million in 2031 ; $13.3 million in 2033 and $73.3 million in 2034 . We estimate our state NOL carryforward as of December 31, 2015 is approximately $154.1 million . If unused, our state NOL carryforwards will expire as follows: $85.3 million in 2018 ; $10.5 million in 2020 and $58.3 million in 2021 . We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards. Uncertain Tax Positions We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands): 2015 2014 2013 Unrecognized Tax Benefits at January 1 $ 95,929 $ 113,466 $ 113,291 Gross increases - tax positions in prior period 44 — — Gross decreases - tax positions in prior period (2,903 ) — — Gross increases - tax positions in current period 494 909 518 Gross decreases - tax positions in current period (1,177 ) (5,597 ) (343 ) Lapse of statute of limitations — (12,849 ) — Unrecognized Tax Benefits at December 31 $ 92,387 $ 95,929 $ 113,466 Our unrecognized tax benefits include approximately $65.2 million and $62.4 million related to tax positions as of December 31, 2015 and 2014 , respectively, that if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the year ended December 31, 2015 , we did not recognize expense for interest and penalties in the Consolidated Statements of Income and did not have any amounts accrued in the Consolidated Balance Sheets. During the year ended December 31, 2014 , we released approximately $0.4 million of interest in the Consolidated Statements of Income. As of December 31, 2014 , we did not have any amounts accrued in the Consolidated Balance Sheets. Our federal tax returns from 2000 forward remain subject to examination by the IRS. |
Comprehensive Income (Loss)
Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |
Comprehensive Income (Loss) Note [Text Block] | (14) Other Comprehensive Income (Loss) The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): December 31, 2015 2014 2013 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 558 $ — $ 558 $ 265 — $ 265 $ 166 $ — $ 166 Reclassification of net gains on derivative instruments (1,125 ) 427 (698 ) (1,110 ) 426 (684 ) (1,188 ) 458 (730 ) Realized loss on cash flow hedging derivatives — — — (18,388 ) 7,243 (11,145 ) — — — Pension and postretirement medical liability adjustment 504 (194 ) 310 134 (52 ) 82 1,568 (605 ) 963 Other comprehensive income (loss) $ (63 ) $ 233 $ 170 $ (19,099 ) $ 7,617 $ (11,482 ) $ 546 $ (147 ) $ 399 Balances by classification included within AOCI on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2015 December 31, 2014 Foreign currency translation $ 1,355 $ 797 Derivative instruments designated as cash flow hedges (9,014 ) (8,316 ) Pension and postretirement medical plans (937 ) (1,247 ) Accumulated other comprehensive income (8,596 ) (8,766 ) The following table displays the changes in AOCI by component, net of tax (in thousands): December 31, 2015 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive (loss) income before reclassifications — — 558 $ 558 Amounts reclassified from accumulated other comprehensive income Interest Expense (698 ) — — $ (698 ) Amounts reclassified from accumulated other comprehensive income — 310 — $ 310 Net current-period other comprehensive (loss) income (698 ) 310 558 170 Ending Balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) December 31, 2014 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ 3,513 $ (1,329 ) $ 532 $ 2,716 Other comprehensive income before reclassifications (11,145 ) — 265 $ (10,880 ) Amounts reclassified from accumulated other comprehensive income Interest Expense (684 ) — — $ (684 ) Amounts reclassified from accumulated other comprehensive income — 82 — $ 82 Net current-period other comprehensive (loss) income (11,829 ) 82 265 (11,482 ) Ending Balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Employee Benefit Plans | (15) Employee Benefit Plans Pension and Other Postretirement Benefit Plans We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees, which includes two cash balance pension plans. The plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation pension plan, and the plan for our Montana employees is referred to as the NorthWestern Energy pension plan. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plan’s funded status is recognized as an asset or liability in our Consolidated Financial Statements. See Note 5 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers. Benefit Obligation and Funded Status Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2015 2014 Change in benefit obligation: Obligation at beginning of period $ 688,444 $ 567,866 $ 30,004 $ 30,084 Service cost 12,362 10,830 526 465 Interest cost 26,174 26,147 786 859 Plan amendments — — 1,045 — Actuarial (gain) loss (47,351 ) 107,023 (616 ) 958 Settlements — — 390 690 Benefits paid (50,746 ) (23,422 ) (3,483 ) (3,052 ) Benefit Obligation at End of Period $ 628,883 $ 688,444 $ 28,652 $ 30,004 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 556,051 $ 516,352 $ 18,040 $ 18,183 Return on plan assets (15,461 ) 52,921 — 1,391 Employer contributions 10,200 10,200 3,415 1,518 Benefits paid (50,746 ) (23,422 ) (3,483 ) (3,052 ) Fair value of plan assets at end of period $ 500,044 $ 556,051 $ 17,972 $ 18,040 Funded Status $ (128,839 ) $ (132,393 ) $ (10,680 ) $ (11,964 ) Amounts Recognized in the Balance Sheet Consist of: Current liability — — (2,584 ) (1,169 ) Noncurrent liability (128,839 ) (132,393 ) (8,096 ) (10,795 ) Net amount recognized $ (128,839 ) $ (132,393 ) $ (10,680 ) $ (11,964 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (255 ) (502 ) 14,021 17,098 Net actuarial loss (142,305 ) (153,268 ) (5,219 ) (4,945 ) Amounts recognized in AOCI consist of: Prior service cost — — (1,000 ) (1,151 ) Net actuarial gain — — (102 ) (409 ) Total $ (142,560 ) $ (153,770 ) $ 7,700 $ 10,593 The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions): Pension Benefits December 31, 2015 2014 Projected benefit obligation $ 628.9 $ 688.4 Accumulated benefit obligation 626.0 685.0 Fair value of plan assets 500.0 556.1 Net Periodic Cost (Credit) The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2013 2015 2014 2013 Components of Net Periodic Benefit Cost Service cost $ 12,362 $ 10,830 $ 13,465 $ 526 $ 465 $ 541 Interest cost 26,174 26,147 22,719 786 859 877 Expected return on plan assets (31,561 ) (29,506 ) (32,491 ) (969 ) (981 ) (1,019 ) Amortization of prior service cost (credit) 246 246 246 (1,882 ) (1,998 ) (1,998 ) Recognized actuarial loss 10,634 2,118 11,648 385 348 1,271 Settlement loss recognized — — — 390 690 — Net Periodic Benefit Cost (Credit) $ 17,855 $ 9,835 $ 15,587 $ (764 ) $ (617 ) $ (328 ) For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years. We estimate amortizations from regulatory assets into net periodic benefit cost during 2016 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (246 ) $ 1,882 Accumulated loss (9,864 ) (349 ) Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2015 and 2014 . The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. For 2015 and 2014 , we set the discount rate using a yield curve analysis, which is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The decrease in discount rate during 2014 increased our projected benefit obligation by approximately $73.6 million . In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we are keeping our long term rate of return on assets assumption at 5.80% for 2016. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.15-4.30 % 3.75-3.90 % 4.55-4.75 % 3.60-3.75 % 3.20-3.40 % 3.75-4.20 % Expected rate of return on assets 5.80 5.80 7.00 5.80 5.80 7.00 Long-term rate of increase in compensation levels (nonunion) 3.58 3.58 3.58 3.58 3.58 3.58 Long-term rate of increase in compensation levels (union) 3.50 3.50 3.50 3.50 3.50 3.50 The postretirement benefit obligation is calculated assuming that health care costs increase by 7.94% in 2016 and the rate of increase in the per capita cost of covered health care benefits thereafter was assumed to decrease to an ultimate trend of 4.5% by the year 2038 . The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation. Investment Strategy Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, and the Prudent Man Rule of the Employee Retirement Income Security Act of 1974 . Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following: • Each plan should be substantially fully invested as long-term cash holdings reduce long-term rates of return; • It is prudent to diversify each plan across the major asset classes; • Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility; • Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the overall funded status; • Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns; • Active management can reduce portfolio risk and potentially add value through security selection strategies; • A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and • It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5% , is as follows: Pension Benefits Other Benefits December 31, December 31, 2015 2014 2015 2014 Domestic debt securities 55.0 % 55.0 % 40.0 % 40.0 % International debt securities 5.0 5.0 — — Domestic equity securities 34.0 34.0 50.0 50.0 International equity securities 6.0 6.0 10.0 10.0 The actual allocation by plan is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2015 2014 2015 2014 2015 2014 Cash and cash equivalents 0.4 % — % — % 0.1 % 0.1 % 0.2 % Domestic debt securities 54.9 56.0 65.8 65.6 37.0 37.2 International debt securities 4.7 4.4 4.5 4.5 — — Domestic equity securities 33.9 34.1 24.9 25.1 54.2 53.9 International equity securities 6.1 5.5 4.8 4.7 8.7 8.7 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. Debt securities consist of U.S. and international instruments. Core domestic portfolios can be invested in government, corporate, asset-backed and mortgage-backed obligation securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks, which are diversified across investment styles such as growth and value. We also invest in international equities with exposure to developing and emerging markets. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. In addition, the NorthWestern Corporation pension plan assets also include a participating group annuity contract in the John Hancock General Investment Account, which consists primarily of fixed-income securities. The participating group annuity contract is valued based on discounted cash flows of current yields of similar contracts with comparable duration based on the underlying fixed income investments. Cash Flows In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Based on the assumptions allowed under the PPA, WRERA, Treasury guidance and IRS guidance, we estimate that our minimum annual required contribution for 2016 will be approximately $10.2 million . Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact these funding requirements. Due to the regulatory treatment of pension costs in Montana, pension expense for 2015, 2014 and 2013 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2015 2014 2013 NorthWestern Energy Pension Plan (MT) $ 9,000 $ 9,000 $ 10,500 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 10,200 $ 10,200 $ 11,700 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2016 $ 29,439 $ 3,623 2017 30,600 3,407 2018 32,173 3,265 2019 33,536 3,057 2020 34,738 2,943 2021-2025 192,419 10,785 Defined Contribution Plan Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the year ended December 31, 2015 , 2014 and 2013 were $9.5 million , $8.7 million , and $7.8 million . |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | (16) Stock-Based Compensation We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. In 2014, an additional 600,000 shares of common stock were authorized by the shareholders for issuance under the ECP. As of December 31, 2015 , there were 933,387 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control. We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. Performance Unit Awards Performance unit awards are granted annually under the ECP. These awards vest at the end of the three -year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. These awards contain both a market and performance based component. For our outstanding performance unit awards which were granted in 2013, the performance goals are independent of each other and equally weighted, and are based on two metrics: (i) cumulative net income and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group. For the awards granted in 2014 and 2015, our Board added an earnings per share metric and removed the net income metric, while retaining the average return on equity and TSR metrics. Fair value is determined for each component of the performance unit awards. The fair value of the net income / earnings per share component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted: 2015 2014 Risk-free interest rate 1.06 % 0.67 % Expected life, in years 3 3 Expected volatility 14.2% to 19.0% 15.5% to 23.3% Dividend yield 3.5 % 3.3 % The risk-free interest rate was based on the U.S. Treasury yield of a three -year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three -year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2015 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 180,572 $ 35.77 Granted 93,437 42.47 Vested (85,966 ) 32.97 Forfeited (471 ) 36.13 Remaining nonvested grants 187,572 $ 40.39 We recognized compensation expense of $4.4 million , $3.1 million , and $2.4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, and a related income tax (expense) benefit of $(1.8) million , $0.1 million , and $1.5 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , we had $4.5 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2.0 years. The total fair value of shares vested was $2.8 million , $2.1 million , and $2.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Retirement/Retention Restricted Share Awards In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. These awards are subject to a five -year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends. A summary of nonvested shares as of and changes during the year ended December 31, 2015 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 41,720 $ 35.14 Granted 15,593 44.77 Vested — — Forfeited — — Remaining nonvested grants 57,313 $ 37.76 Director's Deferred Compensation Nonemployee directors may elect to defer up to 100% of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years). During the years ended December 31, 2015 , 2014 and 2013 , DSUs issued to members of our Board totaled 35,030 , 26,460 and 33,837 , respectively. Total compensation expense attributable to the DSUs during the years ended December 31, 2015 , 2014 and 2013 was approximately $1.3 million , $2.3 million and $3.6 million , respectively. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2015 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |
Common Stock | (17) Common Stock We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of these shares, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 16 - Stock-Based Compensation. Beethoven Issuance - During October 2015, we issued 1,100,000 shares of our common stock at $51.81 per share, for aggregate net proceeds of $57 million to finance a portion of the Beethoven wind project. Repurchase of Common Stock Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 39,504 and 23,630 during the years ended December 31, 2015 and 2014 , respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | (18) Earnings Per Share Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: December 31, 2015 2014 Basic computation 47,298,350 40,156,177 Dilutive effect of Performance and restricted share awards (1) 344,451 275,774 Diluted computation 47,642,801 40,431,951 _____________________ (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | (19) Commitments and Contingencies Qualifying Facilities Liability Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. The QFs require us to purchase minimum amounts of energy at prices ranging from $74 to $136 per MWH through 2029 . Our estimated gross contractual obligation related to the QFs is approximately $955.3 million through 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $740.6 million through 2029 . The present value of the remaining QF liability is recorded in our Consolidated Balance Sheets as a regulatory disallowance liability pursuant to ASC 980. The following summarizes the change in the QF liability (in thousands): December 31, 2015 2014 Beginning QF liability $ 136,893 $ 136,448 Unrecovered amount (9,379 ) (10,128 ) Interest expense 10,796 10,573 Ending QF liability $ 138,310 $ 136,893 The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Obligation Recoverable Amounts Net 2016 72,629 57,188 15,441 2017 74,684 57,789 16,895 2018 76,782 58,401 18,381 2019 78,918 59,020 19,898 2020 81,068 59,647 21,421 Thereafter 571,212 448,547 122,665 Total $ 955,293 $ 740,592 $ 214,701 Long Term Supply and Capacity Purchase Obligations We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. Costs incurred under these contracts are included in Cost of Sales in the Consolidated Income Statement and were approximately $241.6 million , $402.3 million and $379.4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , our commitments under these contracts are $226.1 million in 2016 , $189.9 million in 2017 , $147.1 million in 2018 , $143.3 million in 2019 , $109.0 million in 2020 , and $1.1 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements. Hydroelectric License Commitments With the Hydro Transaction, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $24.1 million between 2016 and 2040. These commitments are not reflected in our Consolidated Financial Statements. Environmental Matters The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us and is estimated to range between $27 million to $32 million . As of December 31, 2015, we have a reserve of approximately $31.5 million , which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations. During the second quarter of 2015, we reached a settlement agreement with an insurance carrier for the former Montana Power Company for what were primarily generation related environmental remediation costs. As a result of this settlement, we recognized a net recovery of approximately $20.8 million , which is reflected as a reduction to operating expenses in our other segment. The environmental remediation costs were never reflected in customer rates and the litigation expenses have not been treated as utility expenses. In a 2002 order approving NorthWestern’s acquisition of the transmission and distribution assets of the Montana Power Company, the MPSC approved a stipulation in which NorthWestern agreed to release its customers from all environmental liabilities associated with the Montana Power Company’s generation assets. Manufactured Gas Plants - Approximately $23.4 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies and implementing remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $11.5 million , and we estimate that approximately $6.8 million of this amount will be incurred during the next five years. We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District, a draft risk assessment was prepared for the Missoula site and presented to the Missoula County Water Quality Board (MCWQB). The MCWQB deferred all decision making to the MDEQ, but suggested additional site delineation. Additional delineation work began in December 2015 and will be continued in 2016. The result of the additional delineation work may lead to amending the risk assessment and / or development of a remedial alternatives report followed by implementation of a remedy. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at these sites or if any additional actions beyond monitored natural attenuation will be required. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide (CO2). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions. On August 3, 2015, the EPA released for publication in the Federal Register, the final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed stationary combustion turbines. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit. In a separate action that also affects power plants, on August 3, 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d). EPA refers to this rule as the Clean Power Plan or CPP. The CPP specifically establishes CO 2 emission performance standards for existing electric utility steam generating units and stationary combustion turbines. States may develop implementation plans for affected units to meet the individual state targets established in the CPP or may adopt a federal plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour (MWH)) or mass-based tonnage limits for CO 2 . The 2030 rate-based requirement for all existing affected generating units in Montana and South Dakota is 1,305 and 1,167 pounds per MWH, respectively. The rate-based approach requires a 38.4 percent reduction in South Dakota and a 47.4 percent reduction in Montana from 2012 levels by 2030. The mass-based approach for existing units in South Dakota requires a 30.9 percent decrease by 2030, while in Montana the mass-based approach requires a 41.0 percent decrease by 2030. States are required to submit initial plans for achieving GHG emission standards to EPA by September 2016, but may seek additional time to finalize State plans by September 2018. The initial performance period for compliance would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program, which would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program, which would allow trading of allowances with an allowance equal to one short ton of CO 2 ; and a state measures program, that would allow intra-state trading to achieve the state-wide average emission rate. On August 3, 2015, EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one of the two options. Comments on the proposed federal plan and model trading rule were due January 21, 2016. The EPA has indicated that it intends to finalize both the federal plan and the model trading rules in the summer of 2016. The CPP reduction of 47 percent in carbon dioxide emissions in Montana by 2030 is the greatest reduction target among the lower 48 states, according to a nationwide analysis. Our Montana generation portfolio emits less carbon on average than the EPA's 2030 target due to investments we made prior to 2013 in carbon-free generation resources. However, the CPP's target reduction is applied on a statewide basis, and investments made prior to 2012 are not counted in the CPP's 2030 target. The State of Montana is required by the CPP to submit a satisfactory state plan to EPA by no later than September 2018. The state plan will determine whether we will have to meet rate-based or mass-based requirements and, if the state adopts a mass-based plan, the number and vintages of allowances that will be allocated to Colstrip. Until the plan is submitted, or a federal plan is imposed, we cannot predict the impact of the CPP on us. We asked the University of Montana’s Bureau of Business and Economic Research (BBER) to study the potential impacts of the CPP across Montana. The BBER study looked at the implications of closing the Colstrip generating facilities in southeast Montana as a scenario for complying with the federal rule. The study's conclusions describe the likely loss of jobs and population, the decline in the local and state tax base, the impact on businesses statewide, and the closure's impact on electric reliability and affordability. The electricity produced at Unit 4 represents approximately 25 percent of our customer needs. Closing Colstrip would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing Colstrip would also create significant issues with the transmission grid that serves Montana, and we would lose transmission revenues that are credited to and lower electric customer bills. On October 23, 2015, the same date the CPP was published in the Federal Register, we along with other utilities, trade groups, coal producers, labor and business organizations, filed Petitions for Review of the CPP with the United States Court of Appeals for the District of Columbia Circuit. Accompanying these Petitions for Review were Motions to Stay the implementation of the CPP. On January 21, 2016, the U.S. Court of Appeals for the District of Columbia denied the requests for stay but ordered expedited briefing on the merits, with oral argument scheduled for June 2, 2016. On January 26, 2016, 29 states and state agencies asked the U.S. Supreme Court to issue an immediate stay of the CPP. On January 27, 2016, 60 utilities and allied petitioners also requested the U.S. Supreme Court to immediately stay the CPP, and we are among the utilities seeking a stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the Clean Power Plan. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. The effect is to delay the CPP’s deadlines until challenges to the CPP has been fully litigated and the U.S. Supreme Court has ruled. We do not expect a final judicial decision on challenges to the CPP until mid-2017 at the earliest, and, more likely, early 2018. On December 22, 2015 we also filed an administrative Petition for Reconsideration with the EPA, requesting it reconsider the CPP, on the grounds that the CO 2 reductions in the CPP were substantially greater in Montana than in the proposed rule. We also requested EPA stay the CPP while it considered our Petition for Reconsideration. At this time no action has been taken on the Petition for Reconsideration or stay request. On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the prevention of significant deterioration program, which includes most electric generating units. Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Although there continues to be proposed legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as droughts, floods and tornadoes, in the locations where we operate or have interests. We are evaluating the implications of these rules and technology available to achieve the CO 2 emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters nor what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources. Coal Combustion Residuals - The EPA's final rule regulating CCRs became effective on October 14, 2015. The rule imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plants and not closed. Under the rule, the EPA regulates CCRs as non-hazardous under the Resource Conservation and Recovery Act Subtitle B and allows beneficial use of CCRs, with some restrictions. The rule's requirements for covered CCR impoundments and landfills include commencement or completion of closure activities generally between three and ten years from certain triggering events. Based on our assessment of these requirements, we recorded an increase to our existing AROs of approximately $12.0 million during the second quarter of 2015. AROs represent the anticipated costs of removing assets upon retirement and are provided for over the life of those assets as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. All costs of the rule are expected to be recovered from customers in future rates. Therefore, consistent with this regulated treatment, we reflect this increase to the accrual of removal costs by increasing our regulatory liability. Further, we do not have any assets that are legally restricted related to the settlement of CCR related asset retirement obligations. The actual asset retirement costs related to the CCR Rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. We will coordinate with the plant operators and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, we will update the ARO obligation for these changes in estimates, which could be material. Legislation has been introduced in Congress to permanently designate coal ash as non-hazardous and establish a national system to regulate coal ash disposal, but leave enforcement largely to states. We cannot predict at this time the final outcome of any such legislation and what impact, if any, it would have on us. Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the Court of Appeals. In November 2015, the EPA published final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. The rule became effective in January 2016. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations; however, it is too early to determine whether the impacts of these rules will be material. Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership. The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas. In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit Court in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit, and on July 31 the litigation was formally sent back to the D.C. Circuit, which will decide whether the standards will be vacated or will remain in place while the EPA addresses the Supreme Court decision. The EPA indicated that it will seek a remand without vacatur of the MATS rule, and in support of that request, the EPA will submit to the court a declaration establishing a plan to "complete the required consideration of costs" to support the "appropriate and necessary finding" by spring 2016. Installation or upgrading of relevant environmental controls at our affected plants is complete. Colstrip Unit 4 is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS. At this time, we cannot predict whether and when compliance with the MATS rule ultimately will be required. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required in certain states beginning in 2012. In April 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. In December, 2015 EPA published a proposed update to the CSAPR rule. Litigation of the remaining CSAPR lawsuits is pending. In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA , which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions. In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Units 3 and 4 do not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised Plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana, the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center, and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, the U.S. Court of Appeals for the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. South Dakota . The South Dakota DENR determined that the Big Stone plant, in which we have a 23.4% ownership, is subject to the BART requirements of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant installed a new BART compliant air quality control system (AQCS) to reduce SO 2 , NOx and particulate emissions. The project was substantially completed and placed in service in December 2015. We capitalized costs of approximately $98 million (including allowance for funds used during construction). North Dakota . The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10.0% ownership, to reduce its NOx emissions by July 2018. Coyote is in the process of installing control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, with the project expected to be operational by the third quarter of 2016. The cost of the control equipment is not significant. Iowa . The Neal #4 generating facility, in which we have an 8.7% ownership, completed the installation of a scrubber, baghouse, activated carbon injection and a selective non-catalytic reduction system in 2013 to comply with national ambient air quality standards and the MATS. Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's CCR Rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90.0 million (our share is 30% ) over the remaining life of the facility. See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation. Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment. We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties: • We may not know all sites for which we are alleged or will be found to be responsible for remediation; and • Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation. LEGAL PROCEEDINGS Colstrip Litigation On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station (Defendants). On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint dropped claims associated with projects completed before 2001, the Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects. In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO2, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits. On May 3, 2013, the C |
Segment and Related Information
Segment and Related Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment and Related Information | (20) Segment and Related Information Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs. We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments for the twelve months ended are as follows (in thousands): December 31, 2015 Electric Gas Other Eliminations Total Operating revenues $ 944,428 269,871 $ — $ — $ 1,214,299 Cost of sales 281,251 91,613 — — 372,864 Gross margin 663,177 178,258 — — 841,435 Operating, general and administrative 233,416 84,219 (20,160 ) — 297,475 Property and other taxes 104,264 29,168 10 — 133,442 Depreciation and depletion 115,701 28,968 33 — 144,702 Operating income 209,796 35,903 20,117 — 265,816 Interest expense, net (79,044 ) (11,433 ) (1,676 ) — (92,153 ) Other income (expense), net 6,300 1,821 (538 ) — 7,583 Income tax expense (19,950 ) (3,752 ) (6,335 ) — (30,037 ) Net income $ 117,102 $ 22,539 $ 11,568 $ — $ 151,209 Total assets $ 4,194,810 $ 1,076,414 $ 7,416 $ — $ 5,278,640 Capital expenditures $ 234,451 $ 49,254 $ — $ — $ 283,705 December 31, 2014 Electric Gas Other Eliminations Total Operating revenues $ 877,967 $ 326,896 $ — $ — $ 1,204,863 Cost of sales 348,640 133,951 — — 482,591 Gross margin 529,327 192,945 — — 722,272 Operating, general and administrative 200,186 91,437 14,263 — 305,886 Property and other taxes 84,759 29,821 12 — 114,592 Depreciation and depletion 94,813 28,930 33 — 123,776 Operating income (loss) 149,569 42,757 (14,308 ) — 178,018 Interest expense, net (60,424 ) (10,618 ) (6,760 ) — (77,802 ) Other income, net 4,758 1,324 4,116 — 10,198 Income tax (expense) benefit (1,490 ) (7,463 ) 19,225 — 10,272 Net income $ 92,413 $ 26,000 $ 2,273 $ — $ 120,686 Total assets $ 3,442,659 $ 1,522,902 $ 8,382 $ — $ 4,973,943 Capital expenditures $ 233,538 $ 36,846 $ — $ — $ 270,384 December 31, 2013 Electric Gas Other Eliminations Total Operating revenues $ 865,239 $ 287,605 $ 1,675 $ — $ 1,154,519 Cost of sales 358,688 120,858 — — 479,546 Gross margin 506,551 166,747 1,675 — 674,973 Operating, general and administrative 195,100 78,822 11,647 — 285,569 Property and other taxes 78,536 26,993 11 — 105,540 Depreciation and depletion 89,728 23,070 33 — 112,831 Operating income (loss) 143,187 37,862 (10,016 ) — 171,033 Interest expense, net (57,920 ) (9,993 ) (2,573 ) — (70,486 ) Other income, net 4,061 1,239 2,437 — 7,737 Income tax (expense) benefit (13,905 ) (4,134 ) 3,738 — (14,301 ) Net income (loss) $ 75,423 $ 24,974 $ (6,414 ) $ — $ 93,983 Total assets $ 2,583,554 $ 1,117,861 $ 13,845 $ — $ 3,715,260 Capital expenditures $ 198,032 $ 32,422 $ — $ — $ 230,454 |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data | (21) Quarterly Financial Data (Unaudited) Our quarterly financial information has not been audited, but, in management's opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. Amounts presented are in thousands, except per share data: 2015 First Second Third Fourth Operating revenues $ 346,011 $ 270,560 $ 272,739 $ 324,989 Operating income 83,891 61,132 48,461 72,332 Net income $ 51,425 $ 30,973 $ 23,798 $ 45,013 Average common shares outstanding 46,977 47,044 47,065 48,098 Income per average common share: Basic $ 1.09 $ 0.66 $ 0.51 $ 0.94 Diluted $ 1.09 $ 0.65 $ 0.51 $ 0.93 Dividends per share $ 0.48 $ 0.48 $ 0.48 $ 0.48 Stock price: High $ 59.71 $ 54.65 $ 56.68 $ 57.07 Low 50.75 48.44 48.47 51.27 Quarter-end close 53.79 48.75 53.83 54.25 2014 First Second Third Fourth Operating revenues $ 369,723 $ 270,281 $ 251,912 $ 312,947 Operating income 71,350 25,097 30,987 50,584 Net income $ 45,580 $ 7,746 $ 30,191 $ 37,169 Average common shares outstanding 38,856 39,137 39,141 43,451 Income per average common share: Basic $ 1.17 $ 0.20 $ 0.77 $ 0.87 Diluted $ 1.17 $ 0.20 $ 0.77 $ 0.85 Dividends per share $ 0.40 $ 0.40 $ 0.40 $ 0.40 Stock price: High $ 47.86 $ 52.49 $ 52.70 $ 58.70 Low 42.64 45.49 45.30 45.14 Quarter-end close 47.43 52.19 45.36 56.58 |
Nature of Operations and Basi29
Nature of Operations and Basis of Consolidation (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Nature of Operations and Basis of Consolidation [Abstract] | |
Variable Interest Entities | Variable Interest Entities A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain QF plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 MW coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per MWH (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $273.1 million through 2024 . For further discussion of our gross QF liability, see Note 19 - Commitments and Contingencies. During the years ended December 31, 2015 , 2014 and 2013 purchases from this QF were approximately $24.3 million , $24.4 million , and $23.8 million , respectively. |
Significant Accounting Polici30
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, asset retirement obligations, uncollectible accounts, our QF liability, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. |
Revenue Recognition | Revenue Recognition Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to customers, but not yet billed at month-end. |
Cash Equivalents | Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. |
Restricted cash | Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. |
Accounts Receivable, Net | Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $4.0 million and $4.3 million at December 31, 2015 and December 31, 2014 , respectively. Receivables include unbilled revenues of $74.5 million and $70.3 million at December 31, 2015 and December 31, 2014 , respectively. |
Regulation of Utility Operations | Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Income Statements at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets. |
Derivative Financial Instruments | Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging . All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated other comprehensive income (AOCI) and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9, Risk Management and Hedging Activities for further discussion of our derivative activity. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 7.5% , 8.0% , and 8.1% , for Montana and South Dakota for 2015 , 2014 , and 2013 , respectively. AFUDC capitalized totaled $13.6 million for the year ended December 31, 2015 , $10.8 million for the year ended December 31, 2014 and $8.2 million for the year ended December 31, 2013 for Montana and South Dakota combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to 50 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.3% , 2.9% , and 3.2% for 2015 , 2014 , and 2013 , respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. |
Income Taxes | Income Taxes Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes. |
Environmental Costs | Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows. Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. |
Business Combinations | Business Combination The acquisition of hydro generating assets and the Beethoven wind project was accounted for using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information see Note 3 - Acquisitions. |
Significant Accounting Polici31
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Inventories | Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2015 2014 Materials and supplies $31,789 $30,672 Storage gas and fuel 21,669 24,422 Total Inventory $53,458 $55,094 |
Other Noncurrent Liabilties | Other noncurrent liabilities consisted of the following (in thousands): December 31, 2015 2014 Pension and other employee benefits $131,887 $137,377 Future QF obligation, net 138,310 136,893 Environmental 30,226 28,060 Customer advances 36,046 30,001 Asset retirement obligations 35,532 21,435 Other 46,569 28,723 Total $418,570 $382,489 |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Year Ended December 31, 2015 2014 2013 (in thousands) Cash (received) paid for: Income taxes $ (1,284 ) $ 35 $ 50 Interest 81,572 63,482 57,789 Significant non-cash transactions: Capital expenditures included in trade accounts payable 12,834 8,555 12,025 |
Acquisitions Purchase Price All
Acquisitions Purchase Price Allocation Table (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | The Beethoven purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition as follows: Purchase Price Allocation Assets Acquired Property Plant and Equipment $143.0 Other Prepayments $0.1 Total Assets Acquired $143.1 Liabilities Assumed Other Current Liabilities $0.3 Total Liabilities Assumed $0.3 Total Purchase Price $142.8 |
Regulatory Assets and Liabili33
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets And Liabilities | Note Reference Remaining Amortization Period December 31, 2015 2014 (in thousands) Pension 15 Undetermined $ 135,057 $ 139,050 Employee related benefits 15 Undetermined 21,055 19,080 Distribution infrastructure projects 2 Years 6,272 9,407 Environmental clean-up 19 Various 14,237 13,741 Supply costs 1 Year 29,604 29,200 Income taxes 13 Plant Lives 319,973 263,764 Deferred financing costs Various 19,978 12,151 State & local taxes & fees Various 7,724 5,319 Other — Various 14,671 11,419 Total Regulatory Assets $ 568,571 $ 503,131 Removal cost 7 Various $ 368,467 $ 351,676 Gas storage sales 24 Years 9,990 10,410 Supply costs 1 Year 13,685 14,569 Deferred revenue 4 1 Year 58,868 36,592 Environmental clean-up Various 7,089 2,501 State & local taxes & fees 1 Year 1,566 511 Other Various 36 2,138 Total Regulatory Liabilities $ 459,701 $ 418,397 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Major classifications of property, plant and equipment | The following table presents the major classifications of our property, plant and equipment (in thousands): Estimated Useful Life December 31, 2015 2014 (years) (in thousands) Land, land rights and easements 54 – 96 $ 135,930 $ 130,816 Building and improvements 27 – 64 219,907 168,041 Transmission, distribution, and storage 15 – 85 2,785,944 2,579,861 Generation 25 – 50 1,154,513 1,044,764 Plant acquisition adjustment 25 – 50 685,417 654,835 Other 2 – 45 445,679 326,211 Construction work in process –— 75,694 221,868 Total property, plant and equipment 5,503,084 5,126,396 Less accumulated depreciation (1,443,585 ) (1,368,388 ) Net property, plant and equipment $ 4,059,499 $ 3,758,008 |
Schedule of jointly owned utility plants | Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone (SD) Neal #4 (IA) Coyote (ND) Colstrip Unit 4 (MT) December 31, 2015 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,740 $ 60,088 $ 46,387 $ 289,604 Accumulated depreciation 37,522 27,940 37,160 73,328 December 31, 2014 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 61,628 $ 59,579 $ 46,045 $ 292,806 Accumulated depreciation 46,741 27,742 36,649 72,976 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following table presents the change in our gross conditional ARO (in thousands): December 31, 2015 2014 Liability at January 1, $ 21,435 $ 20,886 Accretion expense 1,437 1,073 Liabilities incurred 12,682 552 Liabilities settled (22 ) (85 ) Revisions to cash flows — (991 ) Liability at December 31, $ 35,532 $ 21,435 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill [Abstract] | |
Schedule of Goodwill | Goodwill by segment is as follows (in thousands): December 31, 2015 2014 Electric $ 243,558 $ 241,100 Natural gas 114,028 114,028 Total $ 357,586 $ 355,128 |
Risk Management and Hedging A37
Risk Management and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) | Cash Flow Hedges Location of Amount Reclassified from AOCI to Income Amount Reclassified from AOCI into Income during the Year Ended December 31, 2015 Interest rate contracts Interest Expense $ 1,125 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 December 31, 2014 Restricted cash $ 13,140 $ — $ — $ — $ 13,140 Rabbi trust investments 21,594 — — — 21,594 Total $ 34,734 $ — $ — $ — $ 34,734 |
Schedule of Estimated Fair Value of Financial Instruments | The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,782,128 $ 1,844,974 $ 1,662,099 $ 1,817,642 |
Short-Term Borrowings and Cre39
Short-Term Borrowings and Credit Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Short-term Debt [Abstract] | |
Schedule of Short-term Debt | Short-term borrowings and the corresponding weighted average interest rates as of December 31 were as follows (dollars in millions, except for percentages): 2015 2014 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 229.9 0.82 % $ 267.8 0.50 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2015 2014 Maximum short-term debt outstanding $ 267.8 $ 276.9 Average short-term debt outstanding $ 192.8 $ 132.5 Weighted-average interest rate 0.61 % 0.39 % |
Long-Term Debt and Capital Le40
Long-Term Debt and Capital Leases (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Long-term Debt and Capital Lease Obligations [Abstract] | |
Schedule of Debt and Capital Leases | Long-term debt and capital leases consisted of the following (in thousands): December 31, Due 2015 2014 Unsecured Debt: Unsecured Revolving Line of Credit 2018 $ — $ — Secured Debt: Mortgage bonds— South Dakota—6.05% 2018 55,000 55,000 South Dakota—5.01% 2025 64,000 64,000 South Dakota—4.15% 2042 30,000 30,000 South Dakota—4.30% 2052 20,000 20,000 South Dakota—4.85% 2043 50,000 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 — Montana—6.04% — 150,000 Montana—6.34% 2019 250,000 250,000 Montana—5.71% 2039 55,000 55,000 Montana—5.01% 2025 161,000 161,000 Montana—4.15% 2042 60,000 60,000 Montana—4.30% 2052 40,000 40,000 Montana—4.85% 2043 15,000 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 — Montana—4.11% 2045 125,000 — Pollution control obligations— Montana—4.65% 2023 170,205 170,205 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds — (54 ) (83 ) $ 1,782,128 $ 1,662,099 Less current maturities — — $ 1,782,128 $ 1,662,099 Capital Leases: Total Capital Leases Various $ 28,162 $ 29,892 Less current maturities (1,837 ) (1,730 ) $ 26,325 $ 28,162 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Income Tax Expense Domestic | Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2015 2014 2013 Federal Current $ (3,527 ) $ (405 ) $ 108 Deferred 33,031 (5,658 ) 18,150 Investment tax credits (232 ) (273 ) (335 ) State Current (90 ) 18 83 Deferred 855 (3,954 ) (3,705 ) Income Tax Expense (Benefit) $ 30,037 $ (10,272 ) $ 14,301 |
Schedule of Effective Income Tax Rate Reconciliation | The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions 0.1 (1.8 ) (2.8 ) Flow-through repairs deductions (13.3 ) (22.9 ) (16.4 ) Recognition of unrecognized tax benefit — (11.4 ) — Production tax credits (3.2 ) (2.8 ) (2.9 ) Plant and depreciation of flow through items (1.6 ) 0.1 (0.5 ) Prior year permanent return to accrual adjustments 0.1 (4.7 ) 0.5 Other, net (0.5 ) (0.8 ) 0.3 Effective tax rate 16.6 % (9.3 )% 13.2 % The following table summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2015 2014 2013 Income Before Income Taxes $ 181,246 $ 110,414 $ 108,284 Income tax calculated at 35% federal statutory rate 63,436 38,645 37,899 Permanent or flow through adjustments: State tax income, net of federal provisions 301 (1,969 ) (3,082 ) Flow-through repairs deductions (24,079 ) (25,268 ) (17,763 ) Recognition of unrecognized tax benefit — (12,607 ) — Production tax credits (5,721 ) (3,136 ) (3,171 ) Plant and depreciation of flow through items (2,893 ) 74 (584 ) Prior year permanent return to accrual adjustments 207 (5,172 ) 541 Other, net (1,214 ) (839 ) 461 $ (33,399 ) $ (48,917 ) $ (23,598 ) Income Tax Expense (Benefit) $ 30,037 $ (10,272 ) $ 14,301 |
Schedule of Deferred Tax Assets and Liabilities | The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands): December 31, 2015 2014 Pension / postretirement benefits $ 54,440 $ 51,817 Unbilled revenue 28,390 19,863 Property taxes 24,650 881 Compensation accruals 17,441 17,315 Customer advances 14,197 11,817 AMT credit carryforward 13,143 10,357 Environmental liability 9,410 8,968 Production tax credit 6,550 6,452 Interest rate hedges 6,483 6,251 NOL carryforward 3,677 42,787 Regulatory liabilities 2,862 975 QF obligations 2,636 2,162 Reserves and accruals — 1,772 Other, net 3,696 4,415 Deferred Tax Asset 187,575 185,832 Excess tax depreciation (392,113 ) (349,428 ) Goodwill amortization (152,065 ) (137,090 ) Flow through depreciation (125,441 ) (103,677 ) Regulatory assets (14,901 ) (21,394 ) Reserves and accruals (4,587 ) — Deferred Tax Liability (689,107 ) (611,589 ) Deferred Tax Liability, net $ (501,532 ) $ (425,757 ) |
Summary of Income Tax Contingencies | The change in unrecognized tax benefits is as follows (in thousands): 2015 2014 2013 Unrecognized Tax Benefits at January 1 $ 95,929 $ 113,466 $ 113,291 Gross increases - tax positions in prior period 44 — — Gross decreases - tax positions in prior period (2,903 ) — — Gross increases - tax positions in current period 494 909 518 Gross decreases - tax positions in current period (1,177 ) (5,597 ) (343 ) Lapse of statute of limitations — (12,849 ) — Unrecognized Tax Benefits at December 31 $ 92,387 $ 95,929 $ 113,466 |
Comprehensive Income (Loss) (Ta
Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |
Schedule of Comprehensive Income (Loss) | The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): December 31, 2015 2014 2013 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 558 $ — $ 558 $ 265 — $ 265 $ 166 $ — $ 166 Reclassification of net gains on derivative instruments (1,125 ) 427 (698 ) (1,110 ) 426 (684 ) (1,188 ) 458 (730 ) Realized loss on cash flow hedging derivatives — — — (18,388 ) 7,243 (11,145 ) — — — Pension and postretirement medical liability adjustment 504 (194 ) 310 134 (52 ) 82 1,568 (605 ) 963 Other comprehensive income (loss) $ (63 ) $ 233 $ 170 $ (19,099 ) $ 7,617 $ (11,482 ) $ 546 $ (147 ) $ 399 |
Schedule of Accumulated Comprehensive Income (Loss) | Balances by classification included within AOCI on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2015 December 31, 2014 Foreign currency translation $ 1,355 $ 797 Derivative instruments designated as cash flow hedges (9,014 ) (8,316 ) Pension and postretirement medical plans (937 ) (1,247 ) Accumulated other comprehensive income (8,596 ) (8,766 ) |
Reclassification out of Accumulated Other Comprehensive Income | The following table displays the changes in AOCI by component, net of tax (in thousands): December 31, 2015 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive (loss) income before reclassifications — — 558 $ 558 Amounts reclassified from accumulated other comprehensive income Interest Expense (698 ) — — $ (698 ) Amounts reclassified from accumulated other comprehensive income — 310 — $ 310 Net current-period other comprehensive (loss) income (698 ) 310 558 170 Ending Balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) December 31, 2014 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ 3,513 $ (1,329 ) $ 532 $ 2,716 Other comprehensive income before reclassifications (11,145 ) — 265 $ (10,880 ) Amounts reclassified from accumulated other comprehensive income Interest Expense (684 ) — — $ (684 ) Amounts reclassified from accumulated other comprehensive income — 82 — $ 82 Net current-period other comprehensive (loss) income (11,829 ) 82 265 (11,482 ) Ending Balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of Changes in Projected Benefit Obligations | Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2015 2014 Change in benefit obligation: Obligation at beginning of period $ 688,444 $ 567,866 $ 30,004 $ 30,084 Service cost 12,362 10,830 526 465 Interest cost 26,174 26,147 786 859 Plan amendments — — 1,045 — Actuarial (gain) loss (47,351 ) 107,023 (616 ) 958 Settlements — — 390 690 Benefits paid (50,746 ) (23,422 ) (3,483 ) (3,052 ) Benefit Obligation at End of Period $ 628,883 $ 688,444 $ 28,652 $ 30,004 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 556,051 $ 516,352 $ 18,040 $ 18,183 Return on plan assets (15,461 ) 52,921 — 1,391 Employer contributions 10,200 10,200 3,415 1,518 Benefits paid (50,746 ) (23,422 ) (3,483 ) (3,052 ) Fair value of plan assets at end of period $ 500,044 $ 556,051 $ 17,972 $ 18,040 Funded Status $ (128,839 ) $ (132,393 ) $ (10,680 ) $ (11,964 ) Amounts Recognized in the Balance Sheet Consist of: Current liability — — (2,584 ) (1,169 ) Noncurrent liability (128,839 ) (132,393 ) (8,096 ) (10,795 ) Net amount recognized $ (128,839 ) $ (132,393 ) $ (10,680 ) $ (11,964 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (255 ) (502 ) 14,021 17,098 Net actuarial loss (142,305 ) (153,268 ) (5,219 ) (4,945 ) Amounts recognized in AOCI consist of: Prior service cost — — (1,000 ) (1,151 ) Net actuarial gain — — (102 ) (409 ) Total $ (142,560 ) $ (153,770 ) $ 7,700 $ 10,593 |
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets | The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions): Pension Benefits December 31, 2015 2014 Projected benefit obligation $ 628.9 $ 688.4 Accumulated benefit obligation 626.0 685.0 Fair value of plan assets 500.0 556.1 |
Schedule of Defined Benefit Plans Disclosures | The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2013 2015 2014 2013 Components of Net Periodic Benefit Cost Service cost $ 12,362 $ 10,830 $ 13,465 $ 526 $ 465 $ 541 Interest cost 26,174 26,147 22,719 786 859 877 Expected return on plan assets (31,561 ) (29,506 ) (32,491 ) (969 ) (981 ) (1,019 ) Amortization of prior service cost (credit) 246 246 246 (1,882 ) (1,998 ) (1,998 ) Recognized actuarial loss 10,634 2,118 11,648 385 348 1,271 Settlement loss recognized — — — 390 690 — Net Periodic Benefit Cost (Credit) $ 17,855 $ 9,835 $ 15,587 $ (764 ) $ (617 ) $ (328 ) |
Schedule of Estimated Amortization of Regulatory Assets Into Net Periodic Benefit Costs | We estimate amortizations from regulatory assets into net periodic benefit cost during 2016 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (246 ) $ 1,882 Accumulated loss (9,864 ) (349 ) |
Schedule of Assumptions Used | The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.15-4.30 % 3.75-3.90 % 4.55-4.75 % 3.60-3.75 % 3.20-3.40 % 3.75-4.20 % Expected rate of return on assets 5.80 5.80 7.00 5.80 5.80 7.00 Long-term rate of increase in compensation levels (nonunion) 3.58 3.58 3.58 3.58 3.58 3.58 Long-term rate of increase in compensation levels (union) 3.50 3.50 3.50 3.50 3.50 3.50 |
Schedule of Pension And Postretirement Benefits Investment Strategy | Based on this, the target asset allocation established, within an allowable range of plus or minus 5% , is as follows: Pension Benefits Other Benefits December 31, December 31, 2015 2014 2015 2014 Domestic debt securities 55.0 % 55.0 % 40.0 % 40.0 % International debt securities 5.0 5.0 — — Domestic equity securities 34.0 34.0 50.0 50.0 International equity securities 6.0 6.0 10.0 10.0 |
Schedule of Allocation of Plan Assets | The actual allocation by plan is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2015 2014 2015 2014 2015 2014 Cash and cash equivalents 0.4 % — % — % 0.1 % 0.1 % 0.2 % Domestic debt securities 54.9 56.0 65.8 65.6 37.0 37.2 International debt securities 4.7 4.4 4.5 4.5 — — Domestic equity securities 33.9 34.1 24.9 25.1 54.2 53.9 International equity securities 6.1 5.5 4.8 4.7 8.7 8.7 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % |
Schedule of Pension Contributions | Annual contributions to each of the pension plans are as follows (in thousands): 2015 2014 2013 NorthWestern Energy Pension Plan (MT) $ 9,000 $ 9,000 $ 10,500 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 10,200 $ 10,200 $ 11,700 |
Schedule of Expected Benefit Payments | We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2016 $ 29,439 $ 3,623 2017 30,600 3,407 2018 32,173 3,265 2019 33,536 3,057 2020 34,738 2,943 2021-2025 192,419 10,785 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions | The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted: 2015 2014 Risk-free interest rate 1.06 % 0.67 % Expected life, in years 3 3 Expected volatility 14.2% to 19.0% 15.5% to 23.3% Dividend yield 3.5 % 3.3 % |
Schedule of Nonvested Share Activity | A summary of nonvested shares as of and changes during the year ended December 31, 2015 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 180,572 $ 35.77 Granted 93,437 42.47 Vested (85,966 ) 32.97 Forfeited (471 ) 36.13 Remaining nonvested grants 187,572 $ 40.39 |
Share-based Compensation Arrangement by Share-based Payment Award | |
Schedule of Nonvested Restricted Stock Units Activity | A summary of nonvested shares as of and changes during the year ended December 31, 2015 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 41,720 $ 35.14 Granted 15,593 44.77 Vested — — Forfeited — — Remaining nonvested grants 57,313 $ 37.76 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Weighted Average Number of Shares | Average shares used in computing the basic and diluted earnings per share are as follows: December 31, 2015 2014 Basic computation 47,298,350 40,156,177 Dilutive effect of Performance and restricted share awards (1) 344,451 275,774 Diluted computation 47,642,801 40,431,951 _____________________ (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Changes In Qualifying Facility Liability | The following summarizes the change in the QF liability (in thousands): December 31, 2015 2014 Beginning QF liability $ 136,893 $ 136,448 Unrecovered amount (9,379 ) (10,128 ) Interest expense 10,796 10,573 Ending QF liability $ 138,310 $ 136,893 |
Schedule of Estimated Gross Contractual Obligation Less Amounts Recoverable Through Rates | The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Obligation Recoverable Amounts Net 2016 72,629 57,188 15,441 2017 74,684 57,789 16,895 2018 76,782 58,401 18,381 2019 78,918 59,020 19,898 2020 81,068 59,647 21,421 Thereafter 571,212 448,547 122,665 Total $ 955,293 $ 740,592 $ 214,701 |
Segment and Related Informati47
Segment and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | Financial data for the business segments for the twelve months ended are as follows (in thousands): December 31, 2015 Electric Gas Other Eliminations Total Operating revenues $ 944,428 269,871 $ — $ — $ 1,214,299 Cost of sales 281,251 91,613 — — 372,864 Gross margin 663,177 178,258 — — 841,435 Operating, general and administrative 233,416 84,219 (20,160 ) — 297,475 Property and other taxes 104,264 29,168 10 — 133,442 Depreciation and depletion 115,701 28,968 33 — 144,702 Operating income 209,796 35,903 20,117 — 265,816 Interest expense, net (79,044 ) (11,433 ) (1,676 ) — (92,153 ) Other income (expense), net 6,300 1,821 (538 ) — 7,583 Income tax expense (19,950 ) (3,752 ) (6,335 ) — (30,037 ) Net income $ 117,102 $ 22,539 $ 11,568 $ — $ 151,209 Total assets $ 4,194,810 $ 1,076,414 $ 7,416 $ — $ 5,278,640 Capital expenditures $ 234,451 $ 49,254 $ — $ — $ 283,705 December 31, 2014 Electric Gas Other Eliminations Total Operating revenues $ 877,967 $ 326,896 $ — $ — $ 1,204,863 Cost of sales 348,640 133,951 — — 482,591 Gross margin 529,327 192,945 — — 722,272 Operating, general and administrative 200,186 91,437 14,263 — 305,886 Property and other taxes 84,759 29,821 12 — 114,592 Depreciation and depletion 94,813 28,930 33 — 123,776 Operating income (loss) 149,569 42,757 (14,308 ) — 178,018 Interest expense, net (60,424 ) (10,618 ) (6,760 ) — (77,802 ) Other income, net 4,758 1,324 4,116 — 10,198 Income tax (expense) benefit (1,490 ) (7,463 ) 19,225 — 10,272 Net income $ 92,413 $ 26,000 $ 2,273 $ — $ 120,686 Total assets $ 3,442,659 $ 1,522,902 $ 8,382 $ — $ 4,973,943 Capital expenditures $ 233,538 $ 36,846 $ — $ — $ 270,384 December 31, 2013 Electric Gas Other Eliminations Total Operating revenues $ 865,239 $ 287,605 $ 1,675 $ — $ 1,154,519 Cost of sales 358,688 120,858 — — 479,546 Gross margin 506,551 166,747 1,675 — 674,973 Operating, general and administrative 195,100 78,822 11,647 — 285,569 Property and other taxes 78,536 26,993 11 — 105,540 Depreciation and depletion 89,728 23,070 33 — 112,831 Operating income (loss) 143,187 37,862 (10,016 ) — 171,033 Interest expense, net (57,920 ) (9,993 ) (2,573 ) — (70,486 ) Other income, net 4,061 1,239 2,437 — 7,737 Income tax (expense) benefit (13,905 ) (4,134 ) 3,738 — (14,301 ) Net income (loss) $ 75,423 $ 24,974 $ (6,414 ) $ — $ 93,983 Total assets $ 2,583,554 $ 1,117,861 $ 13,845 $ — $ 3,715,260 Capital expenditures $ 198,032 $ 32,422 $ — $ — $ 230,454 |
Quarterly Financial Data (Una48
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Amounts presented are in thousands, except per share data: 2015 First Second Third Fourth Operating revenues $ 346,011 $ 270,560 $ 272,739 $ 324,989 Operating income 83,891 61,132 48,461 72,332 Net income $ 51,425 $ 30,973 $ 23,798 $ 45,013 Average common shares outstanding 46,977 47,044 47,065 48,098 Income per average common share: Basic $ 1.09 $ 0.66 $ 0.51 $ 0.94 Diluted $ 1.09 $ 0.65 $ 0.51 $ 0.93 Dividends per share $ 0.48 $ 0.48 $ 0.48 $ 0.48 Stock price: High $ 59.71 $ 54.65 $ 56.68 $ 57.07 Low 50.75 48.44 48.47 51.27 Quarter-end close 53.79 48.75 53.83 54.25 2014 First Second Third Fourth Operating revenues $ 369,723 $ 270,281 $ 251,912 $ 312,947 Operating income 71,350 25,097 30,987 50,584 Net income $ 45,580 $ 7,746 $ 30,191 $ 37,169 Average common shares outstanding 38,856 39,137 39,141 43,451 Income per average common share: Basic $ 1.17 $ 0.20 $ 0.77 $ 0.87 Diluted $ 1.17 $ 0.20 $ 0.77 $ 0.85 Dividends per share $ 0.40 $ 0.40 $ 0.40 $ 0.40 Stock price: High $ 47.86 $ 52.49 $ 52.70 $ 58.70 Low 42.64 45.49 45.30 45.14 Quarter-end close 47.43 52.19 45.36 56.58 |
Nature of Operations and Basi49
Nature of Operations and Basis of Consolidation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)wattscustomers | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Number of customers | customers | 701,000 | ||
Number of megawatts of qualifying facility | watts | 35 | ||
Estimated aggregate gross contractual payments through 2024 | $ 273.1 | ||
Variable interest entity, measure of activity, purchases | $ 24.3 | $ 24.4 | $ 23.8 |
Significant Accounting Polici50
Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 31,789 | $ 30,672 |
Storage gas and fuel | 21,669 | 24,422 |
Total | $ 53,458 | $ 55,094 |
Significant Accounting Polici51
Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||
Allowance for funds used during construction, rate | 7.50% | 8.00% | 8.10% |
Interest costs, capitalized during period | $ 13.6 | $ 10.8 | $ 8.2 |
Property, plant and equipment, disclosure of composite depreciation rate for plants in service | 3.30% | 2.90% | 3.20% |
Significant Accounting Polici52
Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Accounting Policies [Abstract] | |||
Pension and other employee benefits | $ 131,887 | $ 137,377 | |
Future QF obligation, net | 138,310 | 136,893 | |
Environmental | 30,226 | 28,060 | |
Customer advances | 36,046 | 30,001 | |
Asset retirement obligation | 35,532 | 21,435 | $ 20,886 |
Other | 46,569 | 28,723 | |
Total | $ 418,570 | $ 382,489 |
Significant Accounting Polici53
Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accounting Policies [Abstract] | |||
Income taxes, cash paid (received) | $ (1,284) | $ 35 | $ 50 |
Interest, cash paid (received) | 81,572 | 63,482 | 57,789 |
Capital expenditures included in trade accounts payable | $ 12,834 | $ 8,555 | $ 12,025 |
Significant Accounting Polici54
Significant Accounting Policies Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2015USD ($)days | Dec. 31, 2014USD ($) | |
Allowance for doubtful accounts receivable, current | $ 4 | $ 4.3 |
Unbilled receivables,current | $ 74.5 | $ 70.3 |
Number of days or less of maturity to be considered cash equivalent | days | 90 |
Acquisitions Hydro Transaction
Acquisitions Hydro Transaction (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Nov. 30, 2014 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | ||
Goodwill increase | $ 2.5 | |
Kerr Project [Member] | ||
Business Acquisition [Line Items] | ||
Purchase price | $ 30 | |
Estimated conveyance price of hydroelectric facility | 18.3 | |
Estimated reference price less conveyance price | 11.7 | |
Hydro-electric Assets [Member] | ||
Business Acquisition [Line Items] | ||
Purchase price | $ 904 |
Acquisitions South Dakota Wind
Acquisitions South Dakota Wind Generation (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Assets Acquired | |
Property, Plant and Equipment | $ 143 |
Other Prepayments | 0.1 |
Total Assets Acquired | 143.1 |
Liabilities Assumed | |
Other Current Liabilities | 0.3 |
Total Liabilities Assumed | 0.3 |
Total Purchase Price | 142.8 |
South Dakota Wind Generation [Member] | |
Business Acquisition [Line Items] | |
Purchase price | 143 |
Annual collected amount based on stipulated rate base increase | $ 9 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | |
South Dakota Electric Rate Filing [Member] | |||
Regulatory Assets [Line Items] | |||
Requested rate increase | $ 26.5 | ||
Requested return on rate base | 7.67% | ||
Rate base | $ 447.4 | ||
Stipulated rate increase | $ 20.2 | ||
Overall rate of return | 7.24% | ||
Annual collected amount based on stipulated rate base increase | $ 9 | ||
Regulatory Reviews of Filings [Member] | |||
Regulatory Assets [Line Items] | |||
Stipulated rate increase | $ 0.7 | ||
Incremental market purchases | 11 | ||
Demand side management [Member] | |||
Regulatory Assets [Line Items] | |||
Demand side management revenue recognized | 7.1 | ||
Revenue Subject to Refund [Member] | South Dakota Electric Rate Filing [Member] | |||
Regulatory Assets [Line Items] | |||
Deferred revenue | 6.3 | ||
Revenue Subject to Refund [Member] | Hydro Transaction [Member] | |||
Regulatory Assets [Line Items] | |||
Deferred revenue | 6.7 | ||
Revenue Subject to Refund [Member] | Dave Gates Generating Station [Member] | |||
Regulatory Assets [Line Items] | |||
Deferred revenue | 27.3 | ||
Revenue Subject to Refund [Member] | Montana Natural Gas Production Assets [Member] | |||
Regulatory Assets [Line Items] | |||
Deferred revenue | 1.2 | ||
Customer Refund Liability, Current | 1.5 | ||
Revenue Subject to Refund [Member] | Demand side management [Member] | |||
Regulatory Assets [Line Items] | |||
Deferred revenue | $ 13.4 |
Regulatory Assets and Liabili58
Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Regulatory Assets [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 568,571 | $ 503,131 |
Regulatory Assets [Member] | Pension [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 135,057 | 139,050 |
Regulatory Assets [Member] | Employee related benefits [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 21,055 | 19,080 |
Regulatory Assets [Member] | Distribution infrastructure projects | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 6,272 | 9,407 |
Regulatory assets, remaining amortization period | 2 years | |
Regulatory Assets [Member] | Environmental clean-up [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 14,237 | 13,741 |
Regulatory Assets [Member] | Supply costs [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 29,604 | 29,200 |
Regulatory assets, remaining amortization period | 1 year | |
Regulatory Assets [Member] | Income taxes [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 319,973 | 263,764 |
Regulatory Assets [Member] | Deferred financing costs [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 19,978 | 12,151 |
Regulatory Assets [Member] | State And Local Taxes And Fees [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 7,724 | 5,319 |
Regulatory Assets [Member] | Other [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 14,671 | 11,419 |
Regulatory Liabilities [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 459,701 | 418,397 |
Regulatory Liabilities [Member] | Removal cost | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 368,467 | 351,676 |
Regulatory Liabilities [Member] | Gas storage sales | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 9,990 | 10,410 |
Regulatory liability, remaining amortization period | 24 years | |
Regulatory Liabilities [Member] | Supply costs [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 13,685 | 14,569 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | Deferred revenue [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 58,868 | 36,592 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | Environmental clean-up [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 7,089 | 2,501 |
Regulatory Liabilities [Member] | State And Local Taxes And Fees [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 1,566 | 511 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | Other [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 36 | $ 2,138 |
Regulatory Assets and Liabili59
Regulatory Assets and Liabilities Narrative (Details) | 12 Months Ended |
Dec. 31, 2015 | |
State And Local Taxes And Fees [Member] | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of estimated increase In local taxes and fees authorized for recovery by MPSC | 60.00% |
Electric Supply Costs [Member] | South Dakota | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of interest earned on electric and natural gas supply costs | 7.20% |
Natural Gas Supply Costs [Member] | South Dakota | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of interest earned on electric and natural gas supply costs | 7.80% |
Natural Gas Supply Costs [Member] | Nebraska | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of interest earned on electric and natural gas supply costs | 8.50% |
Supply costs [Member] | Montana | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of interest earned on electric and natural gas supply costs | 7.50% |
Property, Plant and Equipment60
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | ||
Land, land rights and easements | $ 135,930 | $ 130,816 |
Buildings and improvements | 219,907 | 168,041 |
Transmission, distribution and storage | 2,785,944 | 2,579,861 |
Generation | 1,154,513 | 1,044,764 |
Plant acquisition adjustment | 685,417 | 654,835 |
Other | 445,679 | 326,211 |
Construction work in progress | 75,694 | 221,868 |
Property, plant and equipment, gross | 5,503,084 | 5,126,396 |
Less accumulated depreciation | (1,443,585) | (1,368,388) |
Property, plant, and equipment, net | 4,059,499 | 3,758,008 |
Property, plant, and equipment under capiltal leases | 21,300 | 23,400 |
Increase in PP&E due to hydro acquisition | $ 143,000 | 870,000 |
Land and improvements [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 54 years | |
Land and improvements [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 96 years | |
Building and improvements [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 27 years | |
Building and improvements [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 64 years | |
Tranmission, distribution and storage[Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 15 years | |
Tranmission, distribution and storage[Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 85 years | |
Generation [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 25 years | |
Generation [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 50 years | |
Plant Acquisition adjustment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 25 years | |
Plant Acquisition adjustment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 50 years | |
Other [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 2 years | |
Other [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated Useful Life | 45 years | |
Basin Capital Lease [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment under capiltal leases | $ 21,100 | $ 23,100 |
Property, Plant and Equipment J
Property, Plant and Equipment Joint Ownership (Details) $ in Thousands | Dec. 31, 2015USD ($)plants | Dec. 31, 2014USD ($) |
Jointly Owned Utility Plant Interests [Line Items] | ||
Number of joint ownership interests in electric generating plants | plants | 4 | |
Big Stone Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 23.40% | 23.40% |
Plant in service | $ 153,740 | $ 61,628 |
Accumulated depreciation | $ 37,522 | $ 46,741 |
Neal 4 Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 8.70% | 8.70% |
Plant in service | $ 60,088 | $ 59,579 |
Accumulated depreciation | $ 27,940 | $ 27,742 |
Coyote Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 10.00% | 10.00% |
Plant in service | $ 46,387 | $ 46,045 |
Accumulated depreciation | $ 37,160 | $ 36,649 |
Colstrip Unit 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 30.00% | 30.00% |
Plant in service | $ 289,604 | $ 292,806 |
Accumulated depreciation | $ 73,328 | $ 72,976 |
Asset Retirement Obligation Rol
Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liability at January 1, | $ 21,435 | $ 20,886 |
Accretion expense | 1,437 | 1,073 |
Liabilities incurred | 12,682 | 552 |
Liabilities settled | (22) | (85) |
Revision to cash flows | 0 | (991) |
Liability at December 31, | $ 35,532 | $ 21,435 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Line Items] | ||
Goodwill | $ 357,586 | $ 355,128 |
Goodwill increase | 2,500 | |
Electric | ||
Goodwill [Line Items] | ||
Goodwill | 243,558 | 241,100 |
Natural gas | ||
Goodwill [Line Items] | ||
Goodwill | $ 114,028 | $ 114,028 |
Risk Management and Hedging A64
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative [Line Items] | ||
Physical purchase and sale of gas and electricity at fixed prices | $ 0 | $ 0 |
Pre-tax gain on cash flow hedge from AOCI to be reclassified during next 12 months | 300 | |
No swaps outstanding, interest rate fair value derivatives | 0 | $ 0 |
Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Pre-tax loss on cash flow hedges remaining in AOCI | 14,900 | |
Interest Rate Swap [Member] | Interest Expense [Member] | ||
Derivative [Line Items] | ||
Interest rate contracts, amount of gain reclassified from AOCI into income | $ 1,125 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Level 1 to level 2 asset transfers, amount | $ 0 | $ 0 |
Level 2 to level 1 assets, transfers, amount | 0 | 0 |
Level 1 to level 2 liabilities transfers, amount | 0 | 0 |
Level 2 to level 1 liabilities, transfers, amount | 0 | 0 |
Transfers into and out of Level 3 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Total Net Fair Value [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 6,240 | 13,140 |
Rabbi trust investments | 24,245 | 21,594 |
Total | 30,485 | 34,734 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices In Active Markets for Identical Assets or Liabilities, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 6,240 | 13,140 |
Rabbi trust investments | 24,245 | 21,594 |
Total | 30,485 | 34,734 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | $ 0 | $ 0 |
Fair Value Measurements Fair 66
Fair Value Measurements Fair Value Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying value | $ 1,782,128 | $ 1,662,099 |
Long-term debt, fair value | $ 1,844,974 | $ 1,817,642 |
Short-Term Borrowings and Cre67
Short-Term Borrowings and Credit Arrangements (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Short-term Debt [Line Items] | ||
Commercial Paper, Balance | $ 229,874 | $ 267,840 |
Borrowing capacity under commercial paper program | $ 340,000 | |
Short term borrowings maximum days outstanding | 270 days | |
Unsecured Revolving Line Of Credit [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Commitment Fee Amount | $ 400 | 400 |
Short-term Debt [Member] | ||
Short-term Debt [Line Items] | ||
Commercial Paper, Balance | $ 229,900 | $ 267,800 |
Commercial Paper, Interest Rate | 0.82% | 0.50% |
Maximum short-term debt outstanding | $ 267,800 | $ 276,900 |
Average short-term debt outstanding | $ 192,800 | $ 132,500 |
Weighted average interest rate | 0.61% | 0.39% |
Short-Term Borrowings and Cre68
Short-Term Borrowings and Credit Arrangements Unsecured Revolving Line of Credit (Details) - Unsecured Revolving Line Of Credit [Member] $ in Millions | 12 Months Ended | |
Dec. 31, 2015USD ($)numberofbanks | Dec. 31, 2014USD ($) | |
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 350 | |
Number of institutions participating in the credit facility | numberofbanks | 8 | |
Maximum number of institutions participating in the credit faciltiy pertaining to maximum contributory percentage | numberofbanks | 1 | |
Line of Credit Facility, maximum percentage of total availability provided by a single lender | 21.00% | |
Commitment fees | $ 0.4 | $ 0.4 |
Letters of credit outstanding, amount | $ 0 | |
Maximum ratio of indebtedness to net capital threshold percentage | 65.00% | |
Eurodollar [Member] | Minimum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.88% | |
Eurodollar [Member] | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% |
Long-Term Debt and Capital Le69
Long-Term Debt and Capital Leases Schedule of Debt (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||
Long-term debt | $ 1,782,128 | $ 1,662,099 |
Less current maturities | 0 | 0 |
Long-term debt, excluding current maturities | 1,782,128 | 1,662,099 |
Capital Lease | ||
Total Capital Leases | 28,162 | 29,892 |
Less current maturities | (1,837) | (1,730) |
Capital lease obligations, noncurrent | 26,325 | 28,162 |
Unsecured Debt | Unsecured Revolving Line Of Credit | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 0 | 0 |
Maturity date | Nov. 5, 2018 | |
Secured Debt | South Dakota, 6.05%, Due 2018 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 55,000 | 55,000 |
Interest rate, stated percentage | 6.05% | |
Maturity date | May 1, 2018 | |
Secured Debt | South Dakota, 5.01%, Due 2025 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 64,000 | 64,000 |
Interest rate, stated percentage | 5.01% | |
Maturity date | May 1, 2025 | |
Secured Debt | South Dakota, 4.15%, Due 2042 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 30,000 | 30,000 |
Interest rate, stated percentage | 4.15% | |
Maturity date | Aug. 10, 2042 | |
Secured Debt | South Dakota, 4.30%, Due 2052 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 20,000 | 20,000 |
Interest rate, stated percentage | 4.30% | |
Maturity date | Aug. 10, 2052 | |
Secured Debt | South Dakota, 4.85% Due 2043 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 50,000 | 50,000 |
Interest rate, stated percentage | 4.85% | |
Maturity date | Dec. 19, 2043 | |
Secured Debt | South Dakota, 4.22% Due 2044 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 30,000 | 30,000 |
Interest rate, stated percentage | 4.22% | |
Maturity date | Dec. 19, 2044 | |
Secured Debt | South Dakota, 4.26% Due 2040 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 70,000 | 0 |
Interest rate, stated percentage | 4.26% | |
Maturity date | Sep. 29, 2040 | |
Secured Debt | Montana, 6.04%, Due 2016 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 0 | 150,000 |
Interest rate, stated percentage | 6.04% | |
Maturity date | Sep. 1, 2016 | |
Secured Debt | Montana, 6.34%, Due 2019 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 250,000 | 250,000 |
Interest rate, stated percentage | 6.34% | |
Maturity date | Apr. 1, 2019 | |
Secured Debt | Montana, 5.71%, Due 2039 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 55,000 | 55,000 |
Interest rate, stated percentage | 5.71% | |
Maturity date | Oct. 15, 2039 | |
Secured Debt | Montana, 5.01%, Due 2025 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 161,000 | 161,000 |
Interest rate, stated percentage | 5.01% | |
Maturity date | May 1, 2025 | |
Secured Debt | Montana, 4.15%, Due 2042 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 60,000 | 60,000 |
Interest rate, stated percentage | 4.15% | |
Maturity date | Aug. 10, 2042 | |
Secured Debt | Montana, 4.30%, Due 2052 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 40,000 | 40,000 |
Interest rate, stated percentage | 4.30% | |
Maturity date | Aug. 10, 2052 | |
Secured Debt | Montana 4.85%, Due 2043 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 15,000 | 15,000 |
Interest rate, stated percentage | 4.85% | |
Maturity date | Dec. 19, 2043 | |
Secured Debt | Montana 3.99% Due 2028 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 35,000 | 35,000 |
Interest rate, stated percentage | 3.99% | |
Maturity date | Dec. 19, 2028 | |
Secured Debt | Montana 4.176% Due 2044 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 450,000 | 450,000 |
Interest rate, stated percentage | 4.176% | |
Maturity date | Nov. 15, 2044 | |
Secured Debt | Montana 3.11%, Due 2025 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 75,000 | 0 |
Interest rate, stated percentage | 3.11% | |
Maturity date | Jul. 1, 2025 | |
Secured Debt | Montana 4.11%, due 2045 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 125,000 | 0 |
Interest rate, stated percentage | 4.11% | |
Maturity date | Jul. 1, 2045 | |
Secured Debt | Montana, 4.65%, Due 2023 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 170,205 | 170,205 |
Interest rate, stated percentage | 4.65% | |
Maturity date | Aug. 1, 2023 | |
Secured Debt | New Market Tax Credit Financing [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 26,977 | 26,977 |
Interest rate, stated percentage | 1.146% | |
Maturity date | Jul. 1, 2046 | |
Discount on Notes and Bonds | Discount on Notes and Bonds | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ (54) | $ (83) |
Long-Term Debt and Capital Le70
Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) - Secured Debt $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
South Dakota, 4.26% Due 2040 | |
Debt Instrument [Line Items] | |
Debt instrument, face amount | $ 70 |
Interest rate, stated percentage | 4.26% |
Maturity date | Sep. 29, 2040 |
Montana 3.11%, Due 2025 | |
Debt Instrument [Line Items] | |
Debt instrument, face amount | $ 75 |
Interest rate, stated percentage | 3.11% |
Maturity date | Jul. 1, 2025 |
Montana 4.11%, due 2045 | |
Debt Instrument [Line Items] | |
Debt instrument, face amount | $ 125 |
Interest rate, stated percentage | 4.11% |
Maturity date | Jul. 1, 2045 |
Montana, 6.04%, Due 2016 | |
Debt Instrument [Line Items] | |
Interest rate, stated percentage | 6.04% |
Debt Instrument, Repurchase Amount | $ 150 |
Maturity date | Sep. 1, 2016 |
Secured Debt Montana Due 2025 and 2045 [Member] | |
Debt Instrument [Line Items] | |
Debt instrument, face amount | $ 200 |
Long-Term Debt and Capital Le71
Long-Term Debt and Capital Leases Other Long-term Debt (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jul. 31, 2021 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | ||||
Investment in New Market Tax Credit Program | $ 0 | $ 18,169 | $ 0 | |
New Market Tax Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Other Long-term Debt | 27,000 | |||
New Market Tax Credit Financing [Member] | ||||
Debt Instrument [Line Items] | ||||
Investments | $ 18,200 | |||
Debt Instrument, term | 30 years | |||
Interest rate, stated percentage | 1.146% | |||
Investment in New Market Tax Credit Program | $ 8,800 | |||
Scenario, Forecast [Member] | New Market Tax Credit Financing [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, forgiveness | $ 7,900 |
Long-Term Debt and Capital Le72
Long-Term Debt and Capital Leases (Details) $ in Millions | Dec. 31, 2015USD ($) |
Maturities of Long-term Debt [Abstract] | |
2,016 | $ 1.8 |
2,017 | 2 |
2,018 | 57.1 |
2,019 | 252.3 |
2,020 | $ 2.5 |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Internal Revenue Service (IRS) [Member] | |
Income Tax Contingency [Line Items] | |
Earliest year subject to examination | 2,000 |
Income Taxes Domestic Tax Compo
Income Taxes Domestic Tax Components (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Federal | |||
Current | $ (3,527) | $ (405) | $ 108 |
Deferred | 33,031 | (5,658) | 18,150 |
Investment tax credits | (232) | (273) | (335) |
State | |||
Current | (90) | 18 | 83 |
Deferred | 855 | (3,954) | (3,705) |
Income tax expense (benefit) | $ 30,037 | $ (10,272) | $ 14,301 |
Income Taxes Effective Rate Rec
Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income, net of federal provisions | 0.10% | (1.80%) | (2.80%) |
Flow-through repairs deductions | (13.30%) | (22.90%) | (16.40%) |
Recognition of unrecognized tax benefit | (0.00%) | (11.40%) | (0.00%) |
Prior year permanent return to accrual adjustments | 0.10% | (4.70%) | 0.50% |
Production tax credits | (3.20%) | (2.80%) | (2.90%) |
Plant and depreciation of flow through items | (1.60%) | 0.10% | (0.50%) |
Other, net | (0.50%) | (0.80%) | 0.30% |
Effective income tax rate | 16.60% | (9.30%) | 13.20% |
Income (Loss) Before Income Taxes | $ 181,246 | $ 110,414 | $ 108,284 |
Income tax calculated at 35% federal statutory rate | 63,436 | 38,645 | 37,899 |
State income, net of federal provisions | 301 | (1,969) | (3,082) |
Flow-through repairs deductions | (24,079) | (25,268) | (17,763) |
Recognition of unrecognized tax benefit | 0 | (12,607) | 0 |
Prior year permanent return to accrual adjustments | 207 | (5,172) | 541 |
Production tax credits | (5,721) | (3,136) | (3,171) |
Plant and depreciation of flow through items | (2,893) | 74 | (584) |
Other, net | (1,214) | (839) | 461 |
Total reconciling items | (33,399) | (48,917) | (23,598) |
Income tax expense (benefit) | 30,037 | $ (10,272) | $ 14,301 |
Income Tax Credits and Adjustments | $ 4,300 |
Income Taxes Deferred Tax Liabi
Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred Tax Assets, [Abstract] | ||
Pension / postretirement benefits | $ 54,440 | $ 51,817 |
NOL carryforward | 3,677 | 42,787 |
Unbilled revenue | 28,390 | 19,863 |
Compensation accruals | 17,441 | 17,315 |
Customer advances | 14,197 | 11,817 |
AMT credit carryforwards | 13,143 | 10,357 |
Environmental liability | 9,410 | 8,968 |
Production tax credits | 6,550 | 6,452 |
Interest rate hedges | 6,483 | 6,251 |
QF obligations | 2,636 | 2,162 |
Reserves and accruals | 0 | 1,772 |
Property taxes | 24,650 | 881 |
Regulatory liabilities | 2,862 | 975 |
Other, net | 3,696 | 4,415 |
Deferred Tax Asset | 187,575 | 185,832 |
Deferred Tax Liabilities, [Abstract] | ||
Excess tax depreciation | (392,113) | (349,428) |
Goodwill amortization | (152,065) | (137,090) |
Flow through depreciation | (125,441) | (103,677) |
Regulatory assets | (14,901) | (21,394) |
Reserves and Accruals | (4,587) | 0 |
Deferred Tax Liability | (689,107) | (611,589) |
Deferred Tax Liability, net | $ (501,532) | $ (425,757) |
Income Taxes Operating Loss (De
Income Taxes Operating Loss (Details) $ in Millions | Dec. 31, 2015USD ($) |
Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | $ 215.7 |
State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | 154.1 |
Year 2029 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 1.6 |
Year 2031 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 127.5 |
Year 2033 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 13.3 |
Year 2034 [Member] [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 73.3 |
Year 2018 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 85.3 |
Year 2020 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | 10.5 |
Year 2021 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 58.3 |
Income Taxes Uncertain Tax Posi
Income Taxes Uncertain Tax Positions (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Contingency [Line Items] | |||
Income tax penalties and interest expense | $ 0 | $ 0 | |
Unrecognized tax benefit more likely than not percentage threshold | 50.00% | ||
Unrecognized tax benefits that would impact effective tax rate | $ 65,200,000 | 62,400,000 | |
Interest release | 400,000 | ||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits at January 1 | 95,929,000 | 113,466,000 | $ 113,291,000 |
Gross increases - tax positions in prior period | 44,000 | 0 | 0 |
Gross decreases - tax positions in prior periods | (2,903,000) | 0 | 0 |
Gross increases - tax positions in current period | 494,000 | 909,000 | 518,000 |
Gross decreases - tax positions in current period | (1,177,000) | (5,597,000) | (343,000) |
Lapse of statute of limitations | 0 | (12,849,000) | 0 |
Unrecognized Tax Benefits at December 31 | 92,387,000 | 95,929,000 | $ 113,466,000 |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ 0 | $ 0 |
Comprehensive Income (Loss) (De
Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Comprehensive Income (Loss), Before Tax [Abstract] | |||
Foreign currency translation adjustment | $ 558 | $ 265 | $ 166 |
Reclassification of net gains on derivative instruments | (1,125) | (1,110) | (1,188) |
Realized loss on cash flow hedging derivatives | 0 | (18,388) | 0 |
Pension and postretirement medical liability adjustment | 504 | 134 | 1,568 |
Other comprehensive loss, before tax | (63) | (19,099) | 546 |
Other Comprehensive Income (Loss), Tax [Abstract] | |||
Foreign currency translation adjustment | 0 | 0 | 0 |
Reclassification of net gains on derivative instruments | 427 | 426 | 458 |
Realized loss on cash flow hedging derivatives | 0 | 7,243 | 0 |
Pension and postretirement medical liability adjustment | (194) | (52) | (605) |
Other comprehensive loss, tax | 233 | 7,617 | (147) |
Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||
Foreign currency translation adjustment | 558 | 265 | 166 |
Reclassification of net gains on derivative instruments to net income | (698) | (684) | (730) |
Realized loss on cash flow hedging activities | 0 | (11,145) | 0 |
Pension and postretirement medical liability adjustment | 310 | 82 | 963 |
Other comprehensive loss, net of tax | 170 | (11,482) | 399 |
Accumulated Other Comprehensive Income, Net of Tax [Abstract] | |||
Foreign currency translation | 1,355 | 797 | |
Derivative instruments designated as cash flow hedges | (9,014) | (8,316) | |
Pension and postretirement medical plans | (937) | (1,247) | |
Accumulated other comprehensive income | (8,596) | (8,766) | |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||
Other comprehensive loss, net of tax | (698) | (11,829) | |
Accumulated Other Comprehensive Income, Net of Tax [Abstract] | |||
Accumulated other comprehensive income | (9,014) | (8,316) | 3,513 |
Accumulated Defined Benefit Plans Adjustment [Member] | |||
Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||
Other comprehensive loss, net of tax | 310 | 82 | |
Accumulated Other Comprehensive Income, Net of Tax [Abstract] | |||
Accumulated other comprehensive income | $ (937) | $ (1,247) | $ (1,329) |
Comprehensive Income (Loss) Com
Comprehensive Income (Loss) Components of AOCI (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | $ (8,766) | ||
Net current-period other comprehensive (loss) income | 170 | $ (11,482) | $ 399 |
Ending balance | (8,596) | (8,766) | |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (8,316) | 3,513 | |
Other comprehensive income before reclassifications | 0 | (11,145) | |
Amounts reclassified from accumulated other comprehensive income | 0 | 0 | |
Net current-period other comprehensive (loss) income | (698) | (11,829) | |
Ending balance | (9,014) | (8,316) | 3,513 |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from accumulated other comprehensive income | (698) | (684) | |
Accumulated Defined Benefit Plans Adjustment [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (1,247) | (1,329) | |
Other comprehensive income before reclassifications | 0 | 0 | |
Amounts reclassified from accumulated other comprehensive income | 310 | 82 | |
Net current-period other comprehensive (loss) income | 310 | 82 | |
Ending balance | (937) | (1,247) | (1,329) |
Accumulated Defined Benefit Plans Adjustment [Member] | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from accumulated other comprehensive income | 0 | 0 | |
Foreign Currency Gain (Loss) [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | 797 | 532 | |
Other comprehensive income before reclassifications | 558 | 265 | |
Amounts reclassified from accumulated other comprehensive income | 0 | 0 | |
Net current-period other comprehensive (loss) income | 558 | 265 | |
Ending balance | 1,355 | 797 | 532 |
Foreign Currency Gain (Loss) [Member] | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from accumulated other comprehensive income | 0 | 0 | |
Other Comprehensive Income (Loss) [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (8,766) | 2,716 | |
Other comprehensive income before reclassifications | 558 | (10,880) | |
Amounts reclassified from accumulated other comprehensive income | 310 | 82 | |
Net current-period other comprehensive (loss) income | 170 | (11,482) | |
Ending balance | (8,596) | (8,766) | $ 2,716 |
Other Comprehensive Income (Loss) [Member] | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from accumulated other comprehensive income | $ (698) | $ (684) |
Employee Benefit Plans Benefit
Employee Benefit Plans Benefit Obligation And Funded Status (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation beginning of period | $ 688,444 | $ 567,866 | |
Service cost | 12,362 | 10,830 | |
Interest cost | 26,174 | 26,147 | |
Plan Amendments | 0 | 0 | |
Actuarial (gain) loss | (47,351) | 107,023 | |
Settlements | 0 | 0 | |
Benefits paid | (50,746) | (23,422) | |
Benefit obligation end of period | 628,883 | 688,444 | $ 567,866 |
Change in Fair Value of Plan Assets: | |||
Employer contributions | 9,500 | 8,700 | 7,800 |
Benefits paid | (50,746) | (23,422) | |
Amounts recognized in balance sheet consist of: | |||
Current liability | 0 | 0 | |
Noncurrent liability | (128,839) | (132,393) | |
Net amount recognized | (128,839) | (132,393) | |
Amounts recognized in AOCI consist of: | |||
Prior service cost | 0 | 0 | |
Net actuarial gain | 0 | 0 | |
Total | (142,560) | (153,770) | |
Plans with Benefit Obligations in Excess of Plan Assets [Abstract] | |||
Projected benefit obligation | 628,900 | 688,400 | |
Accumulated benefit obligation | 626,000 | 685,000 | |
Fair value of plan assets | 500,000 | 556,100 | |
Pension Plan [Member] | Pension Costs [Member] | |||
Amounts recognized in regulatory assets consist of: | |||
Prior service (cost) credit | (255) | (502) | |
Net actuarial loss | (142,305) | (153,268) | |
Pension Plan [Member] | Changes Measurement [Member] | |||
Change in Benefit Obligation: | |||
Benefits paid | (50,746) | (23,422) | |
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 556,051 | 516,352 | |
Return on plan assets | (15,461) | 52,921 | |
Employer contributions | 10,200 | 10,200 | |
Benefits paid | (50,746) | (23,422) | |
Fair value of plan assets at end of period | 500,044 | 556,051 | 516,352 |
Funded Status | (128,839) | (132,393) | |
Other Postretirement Benefit Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation beginning of period | 30,004 | 30,084 | |
Service cost | 526 | 465 | |
Interest cost | 786 | 859 | |
Plan Amendments | 1,045 | 0 | |
Actuarial (gain) loss | (616) | 958 | |
Settlements | 390 | 690 | |
Benefits paid | (3,483) | (3,052) | |
Benefit obligation end of period | 28,652 | 30,004 | 30,084 |
Change in Fair Value of Plan Assets: | |||
Benefits paid | (3,483) | (3,052) | |
Amounts recognized in balance sheet consist of: | |||
Current liability | (2,584) | (1,169) | |
Noncurrent liability | (8,096) | (10,795) | |
Net amount recognized | (10,680) | (11,964) | |
Amounts recognized in AOCI consist of: | |||
Prior service cost | (1,000) | (1,151) | |
Net actuarial gain | (102) | 409 | |
Total | 7,700 | 10,593 | |
Other Postretirement Benefit Plan [Member] | Pension Costs [Member] | |||
Amounts recognized in regulatory assets consist of: | |||
Prior service (cost) credit | 14,021 | 17,098 | |
Net actuarial loss | (5,219) | (4,945) | |
Other Postretirement Benefit Plan [Member] | Changes Measurement [Member] | |||
Change in Benefit Obligation: | |||
Benefits paid | (3,483) | (3,052) | |
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 18,040 | 18,183 | |
Return on plan assets | 0 | 1,391 | |
Employer contributions | 3,415 | 1,518 | |
Benefits paid | (3,483) | (3,052) | |
Fair value of plan assets at end of period | 17,972 | 18,040 | $ 18,183 |
Funded Status | $ (10,680) | $ (11,964) |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | $ 12,362 | $ 10,830 | ||
Interest cost | 26,174 | 26,147 | ||
Recognized actuarial loss | 47,351 | (107,023) | ||
Settlements | 0 | 0 | ||
Net Periodic Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 12,362 | 10,830 | $ 13,465 | |
Interest cost | 26,174 | 26,147 | 22,719 | |
Expected return on plan assets | (31,561) | (29,506) | (32,491) | |
Amortization of prior service cost (credit) | 246 | 246 | 246 | |
Recognized actuarial loss | 10,634 | 2,118 | 11,648 | |
Settlements | 0 | 0 | 0 | |
Net Periodic Benefit Cost (Credit) | 17,855 | 9,835 | 15,587 | |
Net Periodic Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 526 | 465 | 541 | |
Interest cost | 786 | 859 | 877 | |
Expected return on plan assets | (969) | (981) | (1,019) | |
Amortization of prior service cost (credit) | (1,882) | (1,998) | (1,998) | |
Recognized actuarial loss | 385 | 348 | 1,271 | |
Settlements | 390 | 690 | 0 | |
Net Periodic Benefit Cost (Credit) | $ (764) | $ (617) | $ (328) | |
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Amortization of prior service cost (credit) | $ (246) | |||
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Amortization of prior service cost (credit) | 1,882 | |||
Scenario, Forecast [Member] | Pension Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Accumulated gain | (9,864) | |||
Scenario, Forecast [Member] | Pension Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Accumulated gain | $ (349) |
Employee Benefit Plans Actuaria
Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum | 5.00% | |||
Discount rate change [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Actuarial Gain (Loss) | $ 73,600 | |||
Pension Plan [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Actuarial Gain (Loss) | $ (47,351) | $ 107,023 | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on plan assets | 5.80% | 5.80% | 7.00% | |
Pension Plan [Member] | Nonunion [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Long-term rate of increase in compensation levels | 3.58% | 3.58% | 3.58% | |
Pension Plan [Member] | Union [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Long-term rate of increase in compensation levels | 3.50% | 3.50% | 3.50% | |
Pension Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 4.15% | 3.75% | 4.55% | |
Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 4.30% | 3.90% | 4.75% | |
Other Postretirement Benefit Plan [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Actuarial Gain (Loss) | $ (616) | $ 958 | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on plan assets | 5.80% | 5.80% | 7.00% | |
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | ||||
Ultimate health care cost trend rate | 4.50% | |||
Year that rate reaches ultimate trend rate | 2,038 | |||
Other Postretirement Benefit Plan [Member] | Nonunion [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Long-term rate of increase in compensation levels | 3.58% | 3.58% | 3.58% | |
Other Postretirement Benefit Plan [Member] | Union [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Long-term rate of increase in compensation levels | 3.50% | 3.50% | 3.50% | |
Other Postretirement Benefit Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 3.60% | 3.20% | 3.75% | |
Other Postretirement Benefit Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 3.75% | 3.40% | 4.20% | |
Scenario, Forecast [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on plan assets | 5.80% | |||
Scenario, Forecast [Member] | Other Postretirement Benefit Plan [Member] | ||||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | ||||
Health care cost trend rate assumed for next year | 7.94% |
Employee Benefit Plans Investme
Employee Benefit Plans Investment Strategy (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Target asset allocation allowable range of plus or minus | 5.00% | |
Other Postretirement Benefit Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100.00% | 100.00% |
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0.10% | 0.20% |
Debt Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 55.00% | 55.00% |
Debt Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 5.00% | 5.00% |
Debt Securities [Member] | Other Postretirement Benefit Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 40.00% | 40.00% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 37.00% | 37.20% |
Debt Securities [Member] | Other Postretirement Benefit Plan [Member] | International [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 0.00% | 0.00% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0.00% | 0.00% |
Equity Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 34.00% | 34.00% |
Equity Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 6.00% | 6.00% |
Equity Securities [Member] | Other Postretirement Benefit Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 50.00% | 50.00% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 54.20% | 53.90% |
Equity Securities [Member] | Other Postretirement Benefit Plan [Member] | International [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation of investments by plan | 10.00% | 10.00% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 8.70% | 8.70% |
MONTANA | Pension Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100.00% | 100.00% |
MONTANA | Cash and Cash Equivalents [Member] | Pension Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0.40% | 0.00% |
MONTANA | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 54.90% | 56.00% |
MONTANA | Debt Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 4.70% | 4.40% |
MONTANA | Equity Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 33.90% | 34.10% |
MONTANA | Equity Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 6.10% | 5.50% |
SOUTH DAKOTA | Pension Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100.00% | 100.00% |
SOUTH DAKOTA | Cash and Cash Equivalents [Member] | Pension Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0.00% | 0.10% |
SOUTH DAKOTA | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 65.80% | 65.60% |
SOUTH DAKOTA | Debt Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 4.50% | 4.50% |
SOUTH DAKOTA | Equity Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 24.90% | 25.10% |
SOUTH DAKOTA | Equity Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 4.80% | 4.70% |
Employee Benefit Plans Cash Flo
Employee Benefit Plans Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Pension contributions | $ 10,200 | $ 10,200 | $ 11,700 | |
MONTANA | Pension Plan [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Pension contributions | 9,000 | 9,000 | 10,500 | |
SOUTH DAKOTA | Pension Plan [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Pension contributions | $ 1,200 | $ 1,200 | $ 1,200 | |
Scenario, Forecast [Member] | Pension Plan [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Expected contributions to pension plans | $ 10,200 |
Employee Benefit Plans Estimate
Employee Benefit Plans Estimated Payments (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Pension Plan [Member] | |
Estimated Future Benefit Payments | |
2,016 | $ 29,439 |
2,017 | 30,600 |
2,018 | 32,173 |
2,019 | 33,536 |
2,020 | 34,738 |
2021-2025 | 192,419 |
Other Pension Plan, Postretirement or Supplemental Plans [Member] | |
Estimated Future Benefit Payments | |
2,016 | 3,623 |
2,017 | 3,407 |
2,018 | 3,265 |
2,019 | 3,057 |
2,020 | 2,943 |
2021-2025 | $ 10,785 |
Employee Benefit Plans Narrativ
Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined benefit plan percentage threshold of differences between actuarial assumptions and actual plan results that are greater than projected benefit or market value | 10.00% | ||
Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Matching employer contributions | $ 9.5 | $ 8.7 | $ 7.8 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 4.4 | $ 3.1 | $ 2.4 |
Compensation expense tax (expense) benefit | (1.8) | 0.1 | 1.5 |
Compensation expense not yet recognized for nonvested awards | $ 4.5 | ||
Nonvested awards, total compensation cost not yet recognized, period for recognition | 2 years 4 days | ||
Shares vested in period, total fair value | $ 2.8 | $ 2.1 | $ 2.2 |
Share-based Compensation, Significant Assumptions | |||
Risk-free interest rate | 1.06% | 0.67% | |
Expected life, in years | 3 years | 3 years | |
Expected volatility, minimum | 14.20% | 15.50% | |
Expected volatility, maximum | 19.00% | 23.30% | |
Dividend yield | 3.50% | 3.30% | |
Performance Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 3 years | ||
Performance Shares [Member] | Minimum [Member] | |||
Share-based Compensation, Significant Assumptions | |||
Percent of shares issued based on company performance | 0.00% | ||
Performance Shares [Member] | Maximum [Member] | |||
Share-based Compensation, Significant Assumptions | |||
Percent of shares issued based on company performance | 200.00% | ||
Stock Compensation Plan [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 1 year | ||
Stock Compensation Plan [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 5 years | ||
Executive retirement/retention program [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 5 years | ||
Deferred Stock Unit [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum percentage of compensation to be deferred | 100.00% | ||
Maximum number of years for distribution payments | 10 | ||
Deferred stock units issued during period, shares | shares | 35,030 | 26,460 | 33,837 |
Deferred stock units total compensation expense | $ 1.3 | $ 2.3 | $ 3.6 |
Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized | shares | 600,000 | ||
Number of shares available for grant | shares | 933,387 |
Stock-Based Compensation Nonves
Stock-Based Compensation Nonvested (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Performance Shares [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward] | |
Beginning nonvested grants (shares) | shares | 180,572 |
Granted (shares) | shares | 93,437 |
Vested (shares) | shares | (85,966) |
Forfeited (shares) | shares | (471) |
Remaining nonvested grants (shares) | shares | 187,572 |
Beginning nonvested (weighted-average grant date fair value) | $ / shares | $ 35.77 |
Granted (weighted-average grant date fair value) | $ / shares | 42.47 |
Vested (weighted-average grant date fair value) | $ / shares | 32.97 |
Forfeited (weighted-average grant date fair value) | $ / shares | 36.13 |
Remaining nonvested (weighted-average grant date fair value) | $ / shares | $ 40.39 |
Performance and vesting period | 3 years |
Executive retirement/retention program [Member] | Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward] | |
Beginning nonvested grants (shares) | shares | 41,720 |
Granted (shares) | shares | 15,593 |
Vested (shares) | shares | 0 |
Forfeited (shares) | shares | 0 |
Remaining nonvested grants (shares) | shares | 57,313 |
Beginning nonvested (weighted-average grant date fair value) | $ / shares | $ 35.14 |
Granted (weighted-average grant date fair value) | $ / shares | 44.77 |
Vested (weighted-average grant date fair value) | $ / shares | 0 |
Forfeited (weighted-average grant date fair value) | $ / shares | 0 |
Remaining nonvested (weighted-average grant date fair value) | $ / shares | $ 37.76 |
Performance and vesting period | 5 years |
Common Stock Common Stock (Deta
Common Stock Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Class of Stock [Line Items] | ||||
Combined common and preferred stock, shares authorized | 250,000,000 | 250,000,000 | ||
Common stock, shares authorized | 200,000,000 | 200,000,000 | 200,000,000 | |
Common stock, par or stated value per share | $ 0.01 | $ 0.01 | $ 0.01 | |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 | 50,000,000 | |
Preferred stock, par or stated value per share | $ 0.01 | $ 0.01 | $ 0.01 | |
Common stock reserved for incentive plan awards | 2,865,957 | 2,865,957 | ||
Net proceeds from sale of stock | $ 58,581 | $ 399,505 | $ 57,276 | |
Shares paid for tax withholding | 39,504 | 23,630 | ||
Beethoven Acquisition [Member] | ||||
Class of Stock [Line Items] | ||||
Stock issued during period, shares | 1,100,000 | |||
Net proceeds from sale of stock | $ 57,000 | |||
Common stock average share price | $ 51.81 |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Basic computation | 48,098,000 | 47,065,000 | 47,044,000 | 46,977,000 | 43,451,000 | 39,141,000 | 39,137,000 | 38,856,000 | 47,298,350 | 40,156,177 | 38,144,852 | |
Performance share awards (1) | 344,451 | [1] | 275,774 | |||||||||
Diluted computation | 47,642,801 | 40,431,951 | ||||||||||
[1] | Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. |
Commitments and Contingencies Q
Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Beginning QF liability | $ 136,893,000 | ||
Ending QF liability | 138,310,000 | $ 136,893,000 | |
Qualifying Facility Contracts [Member] | |||
Beginning QF liability | 136,893,000 | 136,448,000 | |
Unrecovered amount | (9,379,000) | (10,128,000) | |
Interest expense | 10,796,000 | 10,573,000 | |
Ending QF liability | 138,310,000 | 136,893,000 | $ 136,448,000 |
Qualifying Facility Contracts [Member] | Gross Obligation [Member] | |||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,016 | 72,629,000 | ||
2,017 | 74,684,000 | ||
2,018 | 76,782,000 | ||
2,019 | 78,918,000 | ||
2,020 | 81,068,000 | ||
Thereafter | 571,212,000 | ||
Contractual obligation related to QF's | 955,293,000 | ||
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member] | |||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,016 | 57,188,000 | ||
2,017 | 57,789,000 | ||
2,018 | 58,401,000 | ||
2,019 | 59,020,000 | ||
2,020 | 59,647,000 | ||
Thereafter | 448,547,000 | ||
Contractual obligation related to QF's | 740,592,000 | ||
Qualifying Facility Contracts [Member] | Net Amount [Member] | |||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,016 | 15,441,000 | ||
2,017 | 16,895,000 | ||
2,018 | 18,381,000 | ||
2,019 | 19,898,000 | ||
2,020 | 21,421,000 | ||
Thereafter | 122,665,000 | ||
Contractual obligation related to QF's | 214,701,000 | ||
Qualifying Facility Contracts [Member] | Year 2029 [Member] | Gross Obligation [Member] | |||
Recorded unconditional purchase obligation portion recoverable through rates | 740,600,000 | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
Contractual obligation related to QF's | 955,300,000 | ||
Qualifying Facility Contracts [Member] | Minimum [Member] | Year 2029 [Member] | |||
Price per MWH of energy required to be purchased per QF agreement | 74 | ||
Qualifying Facility Contracts [Member] | Maximum [Member] | Year 2029 [Member] | |||
Price per MWH of energy required to be purchased per QF agreement | 136 | ||
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | |||
Long Term Purchase Committments Costs Incurred | 241,600,000 | $ 402,300,000 | $ 379,400,000 |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,016 | 226,100,000 | ||
2,017 | 189,900,000 | ||
2,018 | 147,100,000 | ||
2,019 | 143,300,000 | ||
2,020 | 109,000,000 | ||
Thereafter | $ 1,100,000,000 |
Commitments and Contingencies L
Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Long-term Purchase Commitment [Line Items] | |||
Long Term Purchase Committments Costs Incurred | $ 241.6 | $ 402.3 | $ 379.4 |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,016 | 226.1 | ||
2,017 | 189.9 | ||
2,018 | 147.1 | ||
2,019 | 143.3 | ||
2,020 | 109 | ||
Thereafter | $ 1,100 | ||
Minimum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long Term Purchase Commitments Term In Years | 1 year | ||
Maximum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long Term Purchase Commitments Term In Years | 26 |
Commitments and Contingencies E
Commitments and Contingencies Environmental Liabilities (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Jul. 01, 2018 | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Other Commitment | $ 24,100 | |||
Asset retirement obligation | 35,532 | $ 21,435 | $ 20,886 | |
Colstrip Unit 4 [Member] | ||||
Environmental obligation, estimated capital expenditures | $ 90,000 | |||
Jointly owned utility plant, proportionate ownership share | 30.00% | 30.00% | ||
Neal 4 Generating Facility [Member] | ||||
Jointly owned utility plant, proportionate ownership share | 8.70% | 8.70% | ||
Coyote Generating Facility [Member] | ||||
Jointly owned utility plant, proportionate ownership share | 10.00% | 10.00% | ||
Big Stone Generating Facility [Member] | ||||
Jointly owned utility plant, proportionate ownership share | 23.40% | 23.40% | ||
Capitalized costs, jointly owned utility plant | $ 98,000 | |||
Environmental remediation obligations [Member] | ||||
Environmental remediation obligation, minimum | 27,000 | |||
Environmental remediation obligation, maximum | 32,000 | |||
Accrual for environmental loss contingencies | 31,500 | |||
Insurance Recoveries | 20,800 | |||
Manufactured Gas Plants [Member] | Combined Manufacturing Sites [Member] | ||||
Accrual for environmental loss contingencies | 23,400 | |||
Manufactured Gas Plants [Member] | Aberdeen South Dakota Site [Member] | ||||
Accrual for environmental loss contingencies | 11,500 | |||
Environmental remediation obligation, to be incurred during next 5 years | $ 6,800 | |||
Number of years for environmental remediation obligation to be incurred | 5 years | |||
Coal Combustion Residuals (CCRs) [Member] | ||||
Asset retirement obligation | $ 12,000 | |||
Scenario, Forecast [Member] | Coyote Generating Facility [Member] | ||||
NOx emissions per million Btu | 0.5 |
Commitments and Contingencies95
Commitments and Contingencies Legal Proceedings (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | ||
Damages sought,value | $ 61.7 | $ 48.5 |
Retention amount | $ 2 |
Segment and Related Informati96
Segment and Related Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | $ 324,989 | $ 272,739 | $ 270,560 | $ 346,011 | $ 312,947 | $ 251,912 | $ 270,281 | $ 369,723 | $ 1,214,299 | $ 1,204,863 | $ 1,154,519 |
Cost of sales | 372,864 | 482,591 | 479,546 | ||||||||
Gross margin | 841,435 | 722,272 | 674,973 | ||||||||
Operating, general and administrative | 297,475 | 305,886 | 285,569 | ||||||||
Property and other taxes | 133,442 | 114,592 | 105,540 | ||||||||
Depreciation and depletion | 144,702 | 123,776 | 112,831 | ||||||||
Operating Income | 72,332 | 48,461 | 61,132 | 83,891 | 50,584 | 30,987 | 25,097 | 71,350 | 265,816 | 178,018 | 171,033 |
Interest expense, net | (92,153) | (77,802) | (70,486) | ||||||||
Other income, net | 7,583 | 10,198 | 7,737 | ||||||||
Income tax (expense) benefit | (30,037) | 10,272 | (14,301) | ||||||||
Net Income | 45,013 | $ 23,798 | $ 30,973 | $ 51,425 | 37,169 | $ 30,191 | $ 7,746 | $ 45,580 | 151,209 | 120,686 | 93,983 |
Total assets | 5,278,640 | 4,973,943 | 5,278,640 | 4,973,943 | 3,715,260 | ||||||
Capital expenditures | 283,705 | 270,384 | 230,454 | ||||||||
Electric | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 944,428 | 877,967 | 865,239 | ||||||||
Cost of sales | 281,251 | 348,640 | 358,688 | ||||||||
Gross margin | 663,177 | 529,327 | 506,551 | ||||||||
Operating, general and administrative | 233,416 | 200,186 | 195,100 | ||||||||
Property and other taxes | 104,264 | 84,759 | 78,536 | ||||||||
Depreciation and depletion | 115,701 | 94,813 | 89,728 | ||||||||
Operating Income | 209,796 | 149,569 | 143,187 | ||||||||
Interest expense, net | (79,044) | (60,424) | (57,920) | ||||||||
Other income, net | 6,300 | 4,758 | 4,061 | ||||||||
Income tax (expense) benefit | (19,950) | (1,490) | (13,905) | ||||||||
Net Income | 117,102 | 92,413 | 75,423 | ||||||||
Total assets | 4,194,810 | 3,442,659 | 4,194,810 | 3,442,659 | 2,583,554 | ||||||
Capital expenditures | 234,451 | 233,538 | 198,032 | ||||||||
Gas | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 269,871 | 326,896 | 287,605 | ||||||||
Cost of sales | 91,613 | 133,951 | 120,858 | ||||||||
Gross margin | 178,258 | 192,945 | 166,747 | ||||||||
Operating, general and administrative | 84,219 | 91,437 | 78,822 | ||||||||
Property and other taxes | 29,168 | 29,821 | 26,993 | ||||||||
Depreciation and depletion | 28,968 | 28,930 | 23,070 | ||||||||
Operating Income | 35,903 | 42,757 | 37,862 | ||||||||
Interest expense, net | (11,433) | (10,618) | (9,993) | ||||||||
Other income, net | 1,821 | 1,324 | 1,239 | ||||||||
Income tax (expense) benefit | (3,752) | (7,463) | (4,134) | ||||||||
Net Income | 22,539 | 26,000 | 24,974 | ||||||||
Total assets | 1,076,414 | 1,522,902 | 1,076,414 | 1,522,902 | 1,117,861 | ||||||
Capital expenditures | 49,254 | 36,846 | 32,422 | ||||||||
Other Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 0 | 0 | 1,675 | ||||||||
Cost of sales | 0 | 0 | 0 | ||||||||
Gross margin | 0 | 0 | 1,675 | ||||||||
Operating, general and administrative | (20,160) | 14,263 | 11,647 | ||||||||
Property and other taxes | 10 | 12 | 11 | ||||||||
Depreciation and depletion | 33 | 33 | 33 | ||||||||
Operating Income | 20,117 | (14,308) | (10,016) | ||||||||
Interest expense, net | (1,676) | (6,760) | (2,573) | ||||||||
Other income, net | (538) | 4,116 | 2,437 | ||||||||
Income tax (expense) benefit | (6,335) | 19,225 | 3,738 | ||||||||
Net Income | 11,568 | 2,273 | (6,414) | ||||||||
Total assets | 7,416 | 8,382 | 7,416 | 8,382 | 13,845 | ||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 0 | 0 | 0 | ||||||||
Cost of sales | 0 | 0 | 0 | ||||||||
Gross margin | 0 | 0 | 0 | ||||||||
Operating, general and administrative | 0 | 0 | 0 | ||||||||
Property and other taxes | 0 | 0 | 0 | ||||||||
Depreciation and depletion | 0 | 0 | 0 | ||||||||
Operating Income | 0 | 0 | 0 | ||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||
Other income, net | 0 | 0 | 0 | ||||||||
Income tax (expense) benefit | 0 | 0 | 0 | ||||||||
Net Income | 0 | 0 | 0 | ||||||||
Total assets | $ 0 | $ 0 | 0 | 0 | 0 | ||||||
Capital expenditures | $ 0 | $ 0 | $ 0 |
Quarterly Financial Data (Una97
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues | $ 324,989 | $ 272,739 | $ 270,560 | $ 346,011 | $ 312,947 | $ 251,912 | $ 270,281 | $ 369,723 | $ 1,214,299 | $ 1,204,863 | $ 1,154,519 |
Operating income | 72,332 | 48,461 | 61,132 | 83,891 | 50,584 | 30,987 | 25,097 | 71,350 | 265,816 | 178,018 | 171,033 |
Net Income | $ 45,013 | $ 23,798 | $ 30,973 | $ 51,425 | $ 37,169 | $ 30,191 | $ 7,746 | $ 45,580 | $ 151,209 | $ 120,686 | $ 93,983 |
Average Common Shares Outstanding | 48,098,000 | 47,065,000 | 47,044,000 | 46,977,000 | 43,451,000 | 39,141,000 | 39,137,000 | 38,856,000 | 47,298,350 | 40,156,177 | 38,144,852 |
Dividends per share | $ 0.48 | $ 0.48 | $ 0.48 | $ 0.48 | $ 0.40 | $ 0.40 | $ 0.40 | $ 0.40 | $ 1.92 | $ 1.60 | $ 1.52 |
Quarter-end close | 54.25 | 53.83 | 48.75 | 53.79 | 56.58 | 45.36 | 52.19 | 47.43 | 54.25 | 56.58 | |
Income per average common share | |||||||||||
Net income basic | 0.94 | 0.51 | 0.66 | 1.09 | 0.87 | 0.77 | 0.20 | 1.17 | 3.20 | 3.01 | 2.46 |
Net income diluted | 0.93 | 0.51 | 0.65 | 1.09 | 0.85 | 0.77 | 0.20 | 1.17 | $ 3.17 | $ 2.99 | $ 2.46 |
Maximum [Member] | |||||||||||
Stock price | 57.07 | 56.68 | 54.65 | 59.71 | 58.70 | 52.70 | 52.49 | 47.86 | |||
Minimum [Member] | |||||||||||
Stock price | $ 51.27 | $ 48.47 | $ 48.44 | $ 50.75 | $ 45.14 | $ 45.30 | $ 45.49 | $ 42.64 |