Document and Entity Information
Document and Entity Information Document - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 10, 2017 | Jun. 30, 2016 | |
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, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 48,354,198 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 3,046,979,753 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | |||
Electric | $ 1,011,595 | $ 944,428 | $ 877,967 |
Gas | 245,652 | 269,871 | 326,896 |
Total Revenues | 1,257,247 | 1,214,299 | 1,204,863 |
Operating Expenses | |||
Cost of sales | 400,973 | 372,864 | 482,591 |
Operating, general and administrative | 302,893 | 297,475 | 305,886 |
Property and other taxes | 148,098 | 133,442 | 114,592 |
Depreciation and depletion | 159,336 | 144,702 | 123,776 |
Total Operating Expenses | 1,011,300 | 948,483 | 1,026,845 |
Operating Income | 245,947 | 265,816 | 178,018 |
Interest Expense, net | (94,970) | (92,153) | (77,802) |
Other Income, net | 5,548 | 7,583 | 10,198 |
Income Before Income Taxes | 156,525 | 181,246 | 110,414 |
Income Tax Benefit (Expense) | 7,647 | (30,037) | 10,272 |
Net Income | $ 164,172 | $ 151,209 | $ 120,686 |
Average Common Shares Outstanding | 48,298,896 | 47,298,350 | 40,156,177 |
Basic Earnings per Average Common Share | $ 3.40 | $ 3.20 | $ 3.01 |
Diluted Earnings per Average Common Share | $ 3.39 | $ 3.17 | $ 2.99 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net Income | $ 164,172 | $ 151,209 | $ 120,686 |
Other comprehensive income (loss), net of tax: | |||
Reclassification of net gains on derivative instruments | (1,338) | (698) | (684) |
Realized loss on cash flow hedging derivatives | 0 | 0 | (11,145) |
Postretirement medical liability adjustment | 195 | 310 | 82 |
Foreign currency translation adjustment | 25 | 558 | 265 |
Total Other Comprehensive (Loss) Income | (1,118) | 170 | (11,482) |
Comprehensive Income | $ 163,054 | $ 151,379 | $ 109,204 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets: | ||
Cash and cash equivalents | $ 5,079 | $ 11,980 |
Restricted cash | 4,426 | 6,634 |
Accounts receivable, net | 159,556 | 154,410 |
Inventories | 49,206 | 53,458 |
Regulatory assets | 50,041 | 51,348 |
Other | 11,887 | 8,830 |
Total current assets | 280,195 | 286,660 |
Property, plant, and equipment, net | 4,214,892 | 4,059,499 |
Goodwill | 357,586 | 357,586 |
Regulatory assets | 602,943 | 517,223 |
Other noncurrent assets | 43,705 | 43,727 |
Total Assets | 5,499,321 | 5,264,695 |
Current Liabilities: | ||
Current maturities of capital leases | 1,979 | 1,837 |
Short-term borrowings | 300,811 | 229,874 |
Accounts payable | 79,311 | 74,511 |
Accrued expenses | 205,370 | 183,988 |
Regulatory liabilities | 26,361 | 80,990 |
Total current liabilities | 613,832 | 571,200 |
Long-term capital leases | 24,346 | 26,325 |
Long-term debt | 1,793,338 | 1,768,183 |
Deferred income taxes | 575,582 | 501,532 |
Noncurrent regulatory liabilities | 396,225 | 378,711 |
Other noncurrent liabilities | 419,771 | 418,570 |
Total Liabilities | 3,823,094 | 3,664,521 |
Commitments and Contingencies (Note 19) | ||
Shareholders' Equity: | ||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 51,957,840 and 48,331,675, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | 520 | 518 |
Treasury stock at cost | (95,769) | (93,948) |
Paid-in capital | 1,384,271 | 1,376,291 |
Retained earnings | 396,919 | 325,909 |
Accumulated other comprehensive loss | (9,714) | (8,596) |
Total Shareholders' Equity | 1,676,227 | 1,600,174 |
Total Liabilities and Shareholders' Equity | $ 5,499,321 | $ 5,264,695 |
CONSOLIDATED BALANCE SHEETS PAR
CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
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 | 51,957,840 | 51,788,961 |
Common Stock, shares outstanding | 48,331,675 | 48,172,158 |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
OPERATING ACTIVITIES: | |||
Net Income | $ 164,172 | $ 151,209 | $ 120,686 |
Items not affecting cash: | |||
Depreciation and depletion | 159,336 | 144,702 | 123,776 |
Amortization of debt issue costs, discount and deferred hedge gain | 2,117 | 2,258 | 5,033 |
Stock-based compensation costs | 6,731 | 5,082 | 3,262 |
Equity portion of allowance for funds used during construction | (4,589) | (8,684) | (6,554) |
Gain on disposition of assets | (15) | (20) | (1,330) |
Deferred income taxes | (8,184) | 33,886 | (9,612) |
Changes in current assets and liabilities: | |||
Restricted cash | 2,208 | 6,920 | (6,408) |
Accounts receivable | (5,146) | 9,069 | 12,622 |
Inventories | 4,252 | 1,636 | 747 |
Other current assets | (2,384) | 5,514 | 4,201 |
Accounts payable | 3,639 | (11,169) | (9,565) |
Accrued expenses | 25,124 | (22,738) | 8,530 |
Regulatory assets | 1,871 | (3,974) | (8,952) |
Regulatory liabilities | (54,629) | 24,821 | 9,763 |
Other noncurrent assets | (7,311) | (5,584) | 2,853 |
Other noncurrent liabilities | 1,820 | 6,890 | 987 |
Cash Provided by Operating Activities | 289,012 | 339,818 | 250,039 |
INVESTING ACTIVITIES: | |||
Property, plant, and equipment additions | (287,901) | (283,705) | (270,384) |
Acquisitions | 0 | (146,668) | (903,573) |
Proceeds from sale of assets | 1,354 | 30,209 | 1,535 |
Change in restricted cash | 0 | 16,108 | (16,358) |
Investment in New Market Tax Credit program | 0 | 0 | (18,169) |
Cash Used in Investing Activities | (286,547) | (384,056) | (1,206,949) |
FINANCING ACTIVITIES: | |||
Dividends on common stock | (95,765) | (90,058) | (65,019) |
Proceeds from issuance of common stock, net | 0 | 56,651 | 399,207 |
Issuance of long-term debt | 249,660 | 270,000 | 505,789 |
Repayment of long-term debt | (225,205) | (150,025) | (90) |
Issuances (repayments) of short-term borrowings, net | 70,937 | (37,966) | 126,890 |
Treasury stock activity | (561) | (664) | (814) |
Financing costs | (8,432) | (12,082) | (5,248) |
Cash (Used In) Provided by Financing Activities | (9,366) | 35,856 | 960,715 |
Net (Decrease) Increase in Cash and Cash Equivalents | (6,901) | (8,382) | 3,805 |
Cash and Cash Equivalents, beginning of period | 11,980 | 20,362 | 16,557 |
Cash and Cash Equivalents, end of period | $ 5,079 | $ 11,980 | $ 20,362 |
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, 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 |
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 derivatives | (11,145) | 0 | 0 | 0 | 0 | (11,145) |
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 |
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 derivatives | 0 | |||||
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 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Net Income | 164,172 | $ 0 | 0 | $ 0 | 164,172 | 0 |
Foreign currency translation adjustment | 25 | 0 | 0 | 0 | 0 | 25 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (1,338) | 0 | 0 | 0 | 0 | (1,338) |
Realized loss on cash flow hedging derivatives | 0 | |||||
Postretirement medical liability adjustment, net of tax | 195 | 0 | 0 | 0 | 0 | 195 |
Stock based compensation, value | 3,816 | $ 0 | 6,690 | $ (2,874) | 0 | 0 |
Stock based compensation, shares | 169 | 9 | ||||
Issuance of shares, value | 2,345 | $ 2 | 1,290 | 0 | 0 | |
Issuance of shares, shares | 0 | |||||
Issuance of shares, value, treasury stock reissued | $ 1,053 | |||||
Issuance of shares, shares, treasury stock reissued | 0 | |||||
Dividends on common stock | $ (95,765) | $ 0 | 0 | $ 0 | (95,765) | 0 |
Dividends per share | $ 2 | |||||
Balance at Dec. 31, 2016 | $ 1,676,227 | $ 520 | 1,384,271 | $ (95,769) | 396,919 | (9,714) |
Shares, Balance at Dec. 31, 2016 | 51,958 | 3,626 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Accounting standard adoption (1) | $ 2,603 | $ 0 | $ 0 | $ 0 | $ 2,603 | $ 0 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 12 Months Ended |
Dec. 31, 2016 | |
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 709,600 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, 2016 , have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. 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 $246.3 million through 2024 . For further discussion of our gross QF liability, see Note 19 - Commitments and Contingencies. During the years ended December 31, 2016 , 2015 and 2014 purchases from this QF were approximately $25.5 million , $24.3 million , and $24.4 million , respectively. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
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 $2.9 million and $4.0 million at December 31, 2016 and December 31, 2015 , respectively. Receivables include unbilled revenues of $80.4 million and $74.5 million at December 31, 2016 and December 31, 2015 , respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2016 2015 Materials and supplies $31,602 $31,789 Storage gas and fuel 17,604 21,669 Total Inventory $49,206 $53,458 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 Statements of Income 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 7.2% , 7.5% , and 8.0% , for Montana and South Dakota for 2016 , 2015 , and 2014 , respectively. AFUDC capitalized totaled $7.0 million for the year ended December 31, 2016 , $13.6 million for the year ended December 31, 2015 and $10.8 million for the year ended December 31, 2014 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 3.0% , 3.3% , and 2.9% for 2016 , 2015 , and 2014 , 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, 2016 2015 Future QF obligation, net $134,324 $138,310 Pension and other employee benefits 120,122 131,887 Environmental 30,501 30,226 Customer advances 40,209 36,046 Asset retirement obligations 39,402 35,532 Other 55,213 46,569 Total $419,771 $418,570 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. 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 in the process of evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. Our revenues are primarily from tariff based sales, which are in the scope of the standard. We provide gas or electricity to customers under these tariffs without a defined contractual term (‘at-will’). We expect that the revenue from these arrangements will be equivalent to the electricity or gas supplied and billed in that period (including estimated billings). As such, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. We are also selecting the transition method, either full or modified retrospective, and developing an approach to complying with the disclosure requirements. In addition, there are open industry related transition issues being considered that may change whether the guidance has significant impact on us. We will continue to assess the guidance and expect to conclude our analysis of expected impact during the first half of 2017. In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us in our first quarter of 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of adoption of this guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our initial analysis we do not expect this guidance to have a significant impact on our Financial Statements and disclosures other than an expected increase in assets and liabilities. In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows. In November 2016, the FASB issued guidance that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows. Accounting Standards Adopted In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, but adjustments to the carrying cost of debt. During the first quarter of 2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million in the Consolidated Balance Sheet as of December 31, 2015. In March 2016, the FASB issued Financial Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. The new standard is intended to simplify several aspects of the accounting for share-based payment award transactions including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. We elected to early adopt in the fourth quarter of 2016 as of January 1, 2016. For each share award, we determine whether the difference between the deduction for tax purposes and the compensation cost recognized in the Consolidated Financial Statements results in either an excess tax benefit or an excess tax deficit. Previously, excess tax benefits were recognized in Paid-in capital on our Consolidated Balance Sheet. The new guidance increases income statement volatility by requiring all excess tax benefits and deficits to be recognized in income taxes and treated as discrete items in the period in which they occur. During the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense in the Consolidated Statement of Income. These provisions were adopted prospectively. We applied the modified-retrospective approach to excess tax benefits from prior periods, and recorded a cumulative-effect adjustment to retained earnings as of the date of adoption of $2.6 million in the Consolidated Balance Sheets. Additionally, the cash flow presentation guidance is consistent with our historical presentation, and therefore did not have an impact. Finally, we did not change our accounting policy with regard to estimating forfeitures at the date of grant. Supplemental Cash Flow Information Year Ended December 31, 2016 2015 2014 (in thousands) Cash (received) paid for: Income taxes $ (2,922 ) $ (1,284 ) $ 35 Interest 84,953 81,572 63,482 Significant non-cash transactions: Capital expenditures included in trade accounts payable 13,783 12,834 8,555 |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Business Combination Disclosure [Text Block] | (3) Acquisitions 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 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 . |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2016 | |
Regulated Operations [Abstract] | |
Regulatory Matters | (4) Regulatory Matters Montana Natural Gas Delivery and Production Rate Filing In September 2016, we filed a natural gas rate case with the Montana Public Service Commission (MPSC) requesting an annual increase to natural gas rates of approximately $10.9 million , which includes approximately $7.4 million for delivery service and approximately $3.5 million for natural gas production. Our request was based on a return on equity of 10.35% , rate base of $432.1 million , and a capital structure of 53% debt and 47% equity. This filing includes a request for cost-recovery of two natural gas production fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin, which are recovered in customer rates on an interim basis, and a request that these fields be placed in permanent rates based on the actual cost of production. Finally, we requested that approximately $5.6 million of the rate increase for delivery service be approved on an interim basis to allow recovery of costs prior to the conclusion of the full rate case. We expect to receive a decision on our interim request by the end of the first quarter of 2017. The MPSC has nine months from the filing date in which to issue a final decision in this docket. A hearing is scheduled for May 2017. 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 supply procurement activities were prudent. During the second quarter of 2016, we filed our 2016 annual electric and natural gas tracker filings for the 2015/2016 tracker period. The MPSC issued orders in July 2016 approving the filings on an interim basis. In November 2016, the MPSC issued a final order approving the natural gas interim rates. Electric Trackers - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - The MPSC held a work session in March 2016 and directed staff to draft a final order in our Consolidated Docket that reflects a disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs in each of the periods. On the same day, in a separate work session, the MPSC directed staff to draft a final order in the 2015 Tracker that approved a stipulation between us and the Montana Consumer Counsel, but disallowed portfolio modeling costs. Based on the March 2016 work sessions, we recorded a disallowance during the first quarter of 2016 totaling approximately $10.3 million , which included $8.2 million of replacement power costs and $2.1 million of modeling costs. In April 2016, we received the final written order in the 2015 Tracker, which was consistent with the work session. In May 2016, we received the final written order in the Consolidated Docket. The written order upheld the March 2016 decision to disallow Colstrip Unit 4 replacement power costs and clarified the disallowance of modeling costs, resulting in a reduction of the disallowance of $0.8 million , which was reflected as a reduction in cost of sales in the second quarter of 2016. Based on the final orders, the impact of the disallowance totals $12.4 million , which includes $9.5 million of replacement power and modeling costs, and $2.9 million of interest and is recorded in the Consolidated Statement of Income for the twelve months ended December 31, 2016 . In June 2016, we filed an appeal of the 2015 Tracker decision regarding the disallowance of portfolio modeling costs in Montana District Court (Lewis & Clark County). Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket regarding the disallowance of Colstrip Unit 4 replacement power costs and the modeling/planning costs, arguing that these decisions were arbitrary and capricious, and violated Montana law. We brought this action in Montana District Court, as well (Yellowstone County). The briefing in this case is scheduled to conclude by the end of the second quarter of 2017. While the courts are not obligated to rule on these appeals within a certain period of time, based on our experience, we believe we are likely to receive orders from the courts in these matters within 9-20 months of filing. Electric and Natural Gas Lost Revenue Adjustment Mechanism - In 2005, the MPSC approved an energy efficiency program, by which we recovered on an after-the-fact basis a portion of our fixed costs that would otherwise have been collected in kilowatt hour sales lost due to the implementation of energy saving measures. In an order issued in October 2013 related to our 2011/2012 electric supply tracker, the MPSC required us to lower the calculated lost revenue recovery and imposed a new burden of proof on us for future 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 October 2015, the MPSC issued an order to eliminate the lost revenue adjustment mechanism prospectively effective December 1, 2015. Based on the October 2013 MPSC order, for the period July 1, 2012 through November 30, 2015, we recognized $7.1 million of lost revenues for each annual electric supply tracker period and deferred the remaining $14.2 million of efficiency efforts collected through the trackers pending final approval of the open tracker filings discussed above. During the second quarter of 2016, we received final written orders resolving our prior period open tracker dockets. These orders allowed the recovery of lost revenues included in each tracker period. As a result, we recognized revenue deferred during the July 2012 - November 2015 periods of $14.2 million in the Consolidated Statement of Income in the second quarter of 2016. Hydro Compliance Filing In December 2015, we submitted the required compliance filing associated with our purchase of Montana hydro generation assets in 2014, to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In January 2016, the MPSC approved an interim adjustment to our hydro rates based on the compliance filing, and opened a separate contested docket requesting additional detail on the adjustment to rates due to the conveyance of the Kerr Project. The MPSC identified additional issues and requested information. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative and general expenses that should be deducted from the approved revenue requirement due to the transfer of the Kerr Project. In December 2016, the MPSC issued a final order in this compliance filing reducing the annual amount we are allowed to recover in hydro generation rates by approximately $1.2 million . As a result, in the fourth quarter of 2016 we reduced revenue by $1.5 million in the Consolidated Statement of Income. As of December 31, 2016 , we have cumulative deferred revenue of approximately $2.6 million related to the change in rates from the Kerr conveyance that we expect to refund to customers by the end of the first quarter 2017. In addition, the order requires us to indicate by April 30, 2017, whether we intend to file a Montana electric rate case based on a 2016 test year. The Commission indicated that if we do not intend to file a rate case in 2017, it may require us to make an additional financial filing that would facilitate the Commission assessing whether additional action would be required to fulfill its obligation to authorize just and reasonable rates. FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS) In May 2016, we received an order from the Federal Energy Regulatory Commission (FERC) denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision 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 had cumulative deferred revenue of approximately $27.3 million , consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order. In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit. A briefing schedule has been established, with final briefs due by the end of the first quarter of 2017. We do not expect a decision in this matter until the last quarter of 2017, at the earliest. 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, 2016 , the DGGS net property, plant and equipment is approximately $158 million . DGGS previously provided only regulation service, which is the basis for the cost allocation in our previous MPSC and FERC filings. With the addition of owned hydro generation in November 2014, the utilization of DGGS has shifted to additional alternative uses, optimizing our generation portfolio. In support of our biennial electricity supply resource procurement plan that we filed with the MPSC in March 2016, we conducted a portfolio optimization analysis to evaluate options to use DGGS in combination with other generation resources. This analysis indicates DGGS provides cost-effective products necessary to operate our Montana electricity portfolio, including regulation, load following, peaking services and other ancillary products such as contingency reserves, which should guide future 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, 2016 | |
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, 2016 2015 (in thousands) Income taxes 13 Plant Lives $ 411,546 $ 319,973 Pension 15 Undetermined 127,133 135,057 Deferred financing costs Various 24,810 19,978 Employee related benefits 15 Undetermined 20,256 21,055 State & local taxes & fees Various 17,838 7,724 Supply costs 1 Year 16,809 29,604 Environmental clean-up 19 Various 13,601 14,237 Distribution infrastructure projects 1 Year 3,136 6,272 Other — Various 17,855 14,671 Total Regulatory Assets $ 652,984 $ 568,571 Removal cost 7 Various $ 386,373 $ 368,467 Supply costs 1 Year 14,041 13,685 Gas storage sales 23 Years 9,569 9,990 Environmental clean-up Various 6,383 7,089 Deferred revenue 4 1 Year 5,066 58,868 State & local taxes & fees 1 Year 1,154 1,566 Other Various — 36 Total Regulatory Liabilities $ 422,586 $ 459,701 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. 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. 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. 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. 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. 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. 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, 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, 2016 | |
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, 2016 2015 (years) (in thousands) Land, land rights and easements 54 – 96 $ 138,963 $ 135,930 Building and improvements 27 – 64 225,003 219,907 Transmission, distribution, and storage 15 – 85 2,933,788 2,785,944 Generation 25 – 50 1,167,525 1,154,513 Plant acquisition adjustment 25 – 50 685,417 685,417 Other 2 – 45 472,264 445,679 Construction work in process –— 116,995 75,694 Total property, plant and equipment 5,739,955 5,503,084 Less accumulated depreciation (1,525,063 ) (1,443,585 ) Net property, plant and equipment $ 4,214,892 $ 4,059,499 In 2015, we acquired the Beethoven wind project, which resulted in an increase of approximately $143 million in property, plant and equipment. 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 our hydro generating assets acquired in 2014 and 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 of each related asset in depreciation expense. Plant and equipment under capital lease were $19.3 million and $21.3 million as of December 31, 2016 and 2015 , respectively, which included $19.1 million and $21.1 million as of December 31, 2016 and 2015 , 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, 2016 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,623 $ 60,491 $ 50,802 $ 297,289 Accumulated depreciation 38,894 29,235 37,099 77,513 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 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 Liability at January 1, $ 35,532 $ 21,435 Accretion expense 1,885 1,437 Liabilities incurred 164 12,682 Liabilities settled — (22 ) Revisions to cash flows 1,821 — Liability at December 31, $ 39,402 $ 35,532 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 2015, and an additional $1.9 million during the fourth quarter 2016 based on further information. 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, 2016 and 2015 . |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill [Abstract] | |
Goodwill | (8) Goodwill We completed our annual goodwill impairment test as of April 1, 2016 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 by segment is as follows (in thousands): December 31, 2016 2015 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total $ 357,586 $ 357,586 |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
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. 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, 2016 and 2015 . 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 derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them 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 AOCL. We reclassify these gains from AOCL 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 AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2016 Interest rate contracts Interest Expense $ 2,169 A net pre-tax loss of approximately $17.1 million is remaining in AOCL as of December 31, 2016 , and we expect to reclassify approximately $0.6 million of net pre-tax losses from AOCL 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, 2016 | |
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. NPNS 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, 2016 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 $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228 December 31, 2015 Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 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, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,793,338 $ 1,852,052 $ 1,768,183 $ 1,844,974 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, 2016 | |
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): 2016 2015 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 300.8 1.07 % $ 229.9 0.82 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2016 2015 Maximum short-term debt outstanding $ 300.8 $ 267.8 Average short-term debt outstanding $ 210.7 $ 192.8 Weighted-average interest rate 0.86 % 0.61 % 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 On December 12, 2016, we amended and restated our existing revolving credit facility to, among other things, increase the size of the facility to $400 million (from $350 million ) and extend the maturity date to December 12, 2021 (from November 5, 2018). We retained an accordion feature that allows us to increase the size up to $450 million with the consent of the lenders. The facility does not amortize and is unsecured. The facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.875% to 1.75% . A total of eight banks participate in the facility, with no one bank providing more than 16% of the total availability. There were no direct borrowings or letters of credit outstanding as of December 31, 2016 . Commitment fees for the unsecured revolving line of credit were $0.4 million for each of the years ended December 31, 2016 and 2015 . 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, 2016 | |
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 2016 2015 Unsecured Debt: Unsecured Revolving Line of Credit 2021 $ — $ — Secured Debt: Mortgage bonds— South Dakota—6.05% 2018 — 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 70,000 South Dakota—2.80% 2026 60,000 — South Dakota—2.66% 2026 45,000 — 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 75,000 Montana—4.11% 2045 125,000 125,000 Pollution control obligations— Montana—4.65% 2023 — 170,205 Montana—2.00% 2023 144,660 — Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,299 ) (13,999 ) $ 1,793,338 $ 1,768,183 Less current maturities — — $ 1,793,338 $ 1,768,183 Capital Leases: Total Capital Leases Various $ 26,325 $ 28,162 Less current maturities (1,979 ) (1,837 ) $ 24,346 $ 26,325 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. In August 2016 , the City of Forsyth, Rosebud County, Montana issued $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds on our behalf. The bonds were issued at a fixed interest rate of 2.00% maturing in 2023 . The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and have been used to partially fund the redemption of the 4.65% , $170.2 million City of Forsyth Pollution Control Revenue Refunding Bonds due 2023 (Prior Bonds) issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. In June 2016 , we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026 . Proceeds were used to redeem our 6.05% , $55 million South Dakota First Mortgage Bonds due 2018 . In addition, in September 2016 , we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026 . Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. 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, 2016 , we are in compliance with our financial debt covenants. Other Long-Term Debt The New Market Tax Credit (NMTC) financing is pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, which was issued in association with a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement is 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 in 2014, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment. 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 $2.0 million in 2017 , $2.1 million in 2018 , $252.3 million in 2019 , $2.5 million in 2020 and $2.7 million in 2021 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | (13) Income Taxes Income tax (benefit) expense is comprised of the following (in thousands): Year Ended December 31, 2016 2015 2014 Federal Current $ 723 $ (3,527 ) $ (405 ) Deferred (2,054 ) 33,031 (5,658 ) Investment tax credits (196 ) (232 ) (273 ) State Current 10 (90 ) 18 Deferred (6,130 ) 855 (3,954 ) Income Tax (Benefit) Expense $ (7,647 ) $ 30,037 $ (10,272 ) The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions (2.4 ) 0.1 (1.8 ) Flow-through repairs deductions (26.3 ) (13.3 ) (22.9 ) Production tax credits (7.0 ) (3.2 ) (2.8 ) Plant and depreciation of flow through items (2.9 ) (1.6 ) 0.1 Share-based compensation (1.1 ) — — Prior year permanent return to accrual adjustments (0.1 ) 0.1 (4.7 ) Recognition of unrecognized tax benefit — — (11.4 ) Other, net (0.1 ) (0.5 ) (0.8 ) Effective tax rate (4.9 )% 16.6 % (9.3 )% The following table summarizes the significant differences in income tax (benefit) expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2016 2015 2014 Income Before Income Taxes $ 156,525 $ 181,246 $ 110,414 Income tax calculated at 35% federal statutory rate 54,784 63,436 38,645 Permanent or flow through adjustments: State tax income, net of federal provisions (3,714 ) 301 (1,969 ) Flow-through repairs deductions (41,111 ) (24,079 ) (25,268 ) Production tax credits (10,941 ) (5,721 ) (3,136 ) Plant and depreciation of flow through items (4,604 ) (2,893 ) 74 Share-based compensation (1,646 ) — — Prior year permanent return to accrual adjustments (128 ) 207 (5,172 ) Recognition of unrecognized tax benefit — — (12,607 ) Other, net (287 ) (1,214 ) (839 ) $ (62,431 ) $ (33,399 ) $ (48,917 ) Income Tax (Benefit) Expense $ (7,647 ) $ 30,037 $ (10,272 ) Our effective tax rate typically differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through the federal and state tax benefit 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. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. The excess tax benefit of vested share awards is treated as a discrete item in the current quarter. See Note 2 - Significant Accounting Policies, for further discussion of the impacts of this standard. In 2013, the IRS issued guidance related to the repair and maintenance of utility generation assets. During the third quarter of 2016, we filed a tax accounting method change with the IRS consistent with the guidance for generation property. This enabled us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. As discussed above, we flow this current tax deduction through to our customers in rate cases. Consistent with this regulatory treatment, we recorded an income tax benefit of approximately $17.0 million during the twelve months ended December 31, 2016 , of which approximately $12.5 million related to 2015 and prior tax years and is reflected in the flow-through repairs deductions line above. 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 Section 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, 2016 2015 NOL carryforward $ 72,964 $ 3,677 Pension / postretirement benefits 45,847 54,440 Compensation accruals 18,715 17,441 Production tax credit 17,034 6,550 Customer advances 15,837 14,197 AMT credit carryforward 13,599 13,143 Unbilled revenue 12,743 28,390 Environmental liability 9,698 9,410 Interest rate hedges 7,192 6,483 Property taxes 3,767 24,650 Regulatory liabilities 2,290 2,862 Reserves and accruals 1,121 — QF obligations 1,025 2,636 Other, net 3,173 3,696 Deferred Tax Asset 225,005 187,575 Excess tax depreciation (459,588 ) (392,113 ) Goodwill amortization (168,165 ) (152,065 ) Flow through depreciation (160,604 ) (125,441 ) Regulatory assets (12,230 ) (14,901 ) Reserves and accruals — (4,587 ) Deferred Tax Liability (800,587 ) (689,107 ) Deferred Tax Liability, net $ (575,582 ) $ (501,532 ) At December 31, 2016 we estimate our total federal NOL carryforward to be approximately $365.1 million prior to consideration of unrecognized tax benefits. If unused, our federal NOL carryforwards will expire as follows: $105.2 million in 2031 ; $13.3 million in 2033 ; $73.4 million in 2034 and $173.2 million in 2036 . We estimate our state NOL carryforward as of December 31, 2016 is approximately $276.0 million . If unused, our state NOL carryforwards will expire as follows: $67.0 million in 2018 ; $10.5 million in 2020 ; $58.3 million in 2021 and $140.2 million in 2023 . 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): 2016 2015 2014 Unrecognized Tax Benefits at January 1 $ 92,387 $ 95,929 $ 113,466 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 Gross decreases - tax positions in current period (3,958 ) (1,177 ) (5,597 ) Lapse of statute of limitations — — (12,849 ) Unrecognized Tax Benefits at December 31 $ 88,429 $ 92,387 $ 95,929 Our unrecognized tax benefits include approximately $66.5 million and $65.2 million related to tax positions as of December 31, 2016 and 2015 , 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, 2016 , we recognized $0.7 million of expense for interest and penalties in the Consolidated Statements of Income. As of December 31, 2016, we had $0.7 million of interest accrued in the Consolidated Balance Sheets. 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. Our federal tax returns from 2000 forward remain subject to examination by the IRS. |
Comprehensive Loss
Comprehensive Loss | 12 Months Ended |
Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Comprehensive Income (Loss) Note [Text Block] | (14) Comprehensive Loss The following tables display the components of Other Comprehensive (Loss) Income, after-tax, and the related tax effects (in thousands): December 31, 2016 2015 2014 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 $ 25 $ — $ 25 $ 558 — $ 558 $ 265 $ — $ 265 Reclassification of net gains on derivative instruments (2,169 ) 831 (1,338 ) (1,125 ) 427 (698 ) (1,110 ) 426 (684 ) Realized loss on cash flow hedging derivatives — — — — — — (18,388 ) 7,243 (11,145 ) Postretirement medical liability adjustment 317 (122 ) 195 504 (194 ) 310 134 (52 ) 82 Other comprehensive (loss) income $ (1,827 ) $ 709 $ (1,118 ) $ (63 ) $ 233 $ 170 $ (19,099 ) $ 7,617 $ (11,482 ) Balances by classification included within accumulated other comprehensive loss (AOCL) on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2016 December 31, 2015 Foreign currency translation $ 1,380 $ 1,355 Derivative instruments designated as cash flow hedges (10,352 ) (9,014 ) Postretirement medical plans (742 ) (937 ) Accumulated other comprehensive loss $ (9,714 ) $ (8,596 ) The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2016 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) Other comprehensive income before reclassifications — — 25 25 Amounts reclassified from AOCL Interest Expense (1,338 ) — — (1,338 ) Amounts reclassified from AOCL — 195 — 195 Net current-period other comprehensive (loss) income (1,338 ) 195 25 (1,118 ) Ending Balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 ) December 31, 2015 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive income before reclassifications — — 558 558 Amounts reclassified from AOCL Interest Expense (698 ) — — (698 ) Amounts reclassified from AOCL — 310 — 310 Net current-period other comprehensive (loss) income (698 ) 310 558 170 Ending Balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 2016 2015 Change in benefit obligation: Obligation at beginning of period $ 628,883 $ 688,444 $ 28,652 $ 30,004 Service cost 11,759 12,362 492 526 Interest cost 26,210 26,174 795 786 Plan amendments — — — 1,045 Actuarial loss (gain) 7,006 (47,351 ) (71 ) (616 ) Settlements — — 390 390 Benefits paid (27,826 ) (50,746 ) (4,041 ) (3,483 ) Benefit Obligation at End of Period $ 646,032 $ 628,883 $ 26,217 $ 28,652 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 500,044 $ 556,051 $ 17,972 $ 18,040 Return on plan assets 39,719 (15,461 ) 1,277 — Employer contributions 12,700 10,200 3,397 3,415 Benefits paid (27,826 ) (50,746 ) (4,041 ) (3,483 ) Fair value of plan assets at end of period $ 524,637 $ 500,044 $ 18,605 $ 17,972 Funded Status $ (121,395 ) $ (128,839 ) $ (7,612 ) $ (10,680 ) Amounts Recognized in the Balance Sheet Consist of: Current liability — — (1,789 ) (2,584 ) Noncurrent liability (121,395 ) (128,839 ) (5,823 ) (8,096 ) Net amount recognized $ (121,395 ) $ (128,839 ) $ (7,612 ) $ (10,680 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (9 ) (255 ) 11,988 14,021 Net actuarial loss (127,953 ) (142,305 ) (4,739 ) (5,219 ) Amounts recognized in AOCL consist of: Prior service cost — — (849 ) (1,000 ) Net actuarial gain — — 38 (102 ) Total $ (127,962 ) $ (142,560 ) $ 6,438 $ 7,700 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, 2016 2015 Projected benefit obligation $ 646.0 $ 628.9 Accumulated benefit obligation 643.6 626.0 Fair value of plan assets 524.6 500.0 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, 2016 2015 2014 2016 2015 2014 Components of Net Periodic Benefit Cost Service cost $ 11,759 $ 12,362 $ 10,830 $ 492 $ 526 $ 465 Interest cost 26,210 26,174 26,147 795 786 859 Expected return on plan assets (28,248 ) (31,561 ) (29,506 ) (1,042 ) (969 ) (981 ) Amortization of prior service cost (credit) 246 246 246 (1,882 ) (1,882 ) (1,998 ) Recognized actuarial loss 9,888 10,634 2,118 315 385 348 Settlement loss recognized — — — 390 390 690 Net Periodic Benefit Cost (Credit) $ 19,855 $ 17,855 $ 9,835 $ (932 ) $ (764 ) $ (617 ) 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 2017 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (9 ) $ 1,882 Accumulated loss (7,901 ) (313 ) Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2016 and 2015 . 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. We set the discount rate using a yield curve analysis. This analysis includes 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 2016 increased our projected benefit obligation by approximately $16.1 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 lowering our long term rate of return on assets assumption to 4.70% for 2017. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2016 2015 2014 2016 2015 2014 Discount rate 3.95-4.10 % 4.15-4.30 % 3.75-3.90 % 3.40-3.55 % 3.60-3.75 % 3.20-3.40 % Expected rate of return on assets 5.80 5.80 5.80 5.80 5.80 5.80 Long-term rate of increase in compensation levels (nonunion) 3.28 3.58 3.58 3.28 3.58 3.58 Long-term rate of increase in compensation levels (union) 3.20 3.50 3.50 3.20 3.50 3.50 The postretirement benefit obligation is calculated assuming that health care costs increase by 7.59% in 2017 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, 2016 2015 2016 2015 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, 2016 2015 2016 2015 2016 2015 Cash and cash equivalents — % 0.4 % 0.1 % — % 1.0 % 0.1 % Domestic debt securities 53.4 54.9 64.4 65.8 37.0 37.0 International debt securities 4.6 4.7 4.4 4.5 — — Domestic equity securities 36.0 33.9 26.0 24.9 52.6 54.2 International equity securities 6.0 6.1 5.1 4.8 9.4 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. We expect to continue to make contributions to the pension plans in 2017 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements. Due to the regulatory treatment of pension costs in Montana, pension expense for 2016, 2015 and 2014 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2016 2015 2014 NorthWestern Energy Pension Plan (MT) $ 11,500 $ 9,000 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 12,700 $ 10,200 $ 10,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2017 $ 30,637 $ 3,513 2018 32,346 3,464 2019 33,574 3,218 2020 34,847 2,844 2021 35,906 2,634 2022-2026 198,236 9,195 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, 2016 , 2015 and 2014 were $9.8 million , $9.5 million , and $8.7 million . |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , there were 870,186 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 market- and performance-based components. The performance goals are independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group. Fair value is determined for each component of the performance unit awards. The fair value of the 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: 2016 2015 Risk-free interest rate 0.85 % 1.06 % Expected life, in years 3 3 Expected volatility 17.1% to 22.1% 14.2% to 19.0% Dividend yield 3.4 % 3.5 % 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, 2016 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 187,572 $ 40.39 Granted 88,107 50.32 Vested (90,417 ) 38.33 Forfeited (10,005 ) 42.12 Remaining nonvested grants 175,257 $ 46.35 We recognized compensation expense of $5.3 million , $4.4 million , and $3.1 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively, and a related income tax (expense) benefit of $(1.8) million , $(1.8) million , and $0.1 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. As of December 31, 2016 , we had $5.1 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 $3.5 million , $2.8 million , and $2.1 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 57,313 $ 37.76 Granted 15,708 45.78 Vested (8,112 ) 28.00 Forfeited (2,318 ) 35.11 Remaining nonvested grants 62,591 $ 41.14 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, 2016 , 2015 and 2014 , DSUs issued to members of our Board totaled 28,338 , 35,030 and 26,460 , respectively. Total compensation expense attributable to the DSUs during the years ended December 31, 2016 , 2015 and 2014 was approximately $2.4 million , $1.3 million and $2.3 million , respectively. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2016 | |
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 49,514 and 39,504 during the years ended December 31, 2016 and 2015 , 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, 2016 | |
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, 2016 2015 Basic computation 48,298,896 47,298,350 Dilutive effect of — Performance and restricted share awards (1) 176,166 344,451 Diluted computation 48,475,062 47,642,801 _____________________ (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. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 22,044 shares for the year ended December 31, 2016. See Note 2 - Significant Accounting Policies, for further discussion of the impacts of this standard. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
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 $882.0 million through 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $683.4 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, 2016 2015 Beginning QF liability $ 138,310 $ 136,893 Unrecovered amount (14,829 ) (9,379 ) Interest expense 10,843 10,796 Ending QF liability $ 134,324 $ 138,310 The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Obligation Recoverable Amounts Net 2017 74,607 57,789 16,818 2018 76,703 58,401 18,302 2019 78,836 59,020 19,816 2020 80,984 59,647 21,337 2021 82,941 60,136 22,805 Thereafter 487,957 388,411 99,546 Total $ 882,028 $ 683,404 $ 198,624 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 27 years. Costs incurred under these contracts are included in Cost of Sales in the Consolidated Statements of Income and were approximately $216.8 million , $241.6 million and $402.3 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. As of December 31, 2016 , our commitments under these contracts are $206.1 million in 2017 , $155.9 million in 2018 , $156.2 million in 2019 , $122.8 million in 2020 , $107.0 million in 2021 , and $1.3 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 $22.0 million between 2017 and 2040 . These commitments are not reflected in our Consolidated Financial Statements. ENVIRONMENTAL LIABILITIES AND REGULATION 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 $27.9 million to $32.6 million . As of December 31, 2016 , 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. Manufactured Gas Plants - Approximately $24.7 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, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2016 , the reserve for remediation costs at this site is approximately $10.8 million , and we estimate that approximately $6.2 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, both listed as high priority sites on Montana's state superfund list, 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. In August 2016, the MDEQ sent us a letter of Notice of Potential Liability and Request for Remedial Action regarding the Helena site. An initial scoping meeting with MDEQ regarding this letter has not yet been scheduled. At MDEQ's direction, a Soil Vapor Analysis Plan for the two buildings located on the Helena site was submitted to confirm whether vapors are present in the soil that could seep into the two buildings. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte and Helena 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 (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. The additional investigation work began in December 2015 and has continued in 2016. Analytical results from an October 2016 sampling exceeded the Montana Maximum Contaminant Level (MCL) for benzene and/or total cyanide in certain monitoring wells. These results were forwarded to MVWQD which shared the same with the MDEQ. In a December 21, 2016 letter to MVWQD, MDEQ requested that MVWQD file a formal complaint with MDEQ's Enforcement Division regarding groundwater contamination of the site. If MVWQD files a formal complaint, we expect it will prompt MDEQ to reevaluate its position concerning listing the Missoula site on the State's superfund list. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. 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 (CO 2 ). These actions include legislative proposals, Executive and 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. There is uncertainty associated with the new EPA Administration and the timeframe for actions that may be taken with regard to the existing and pending GHG-related regulations. 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 natural gas combined cycle (NGCC) units. 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) (the Clean Power Plan, or CPP). The CPP establishes CO 2 emission performance standards for existing electric utility steam generating units and NGCC units. 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 South Dakota and Montana is 1,167 and 1,305 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 percent decrease by 2030. States were required to submit initial plans for achieving GHG emission standards to EPA by September 2016, and could seek additional time to finalize State plans by September 2018. Due to the stay of the rule, discussed below, South Dakota and Montana have not submitted implementation plans. The initial performance period for compliance under the CPP 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 that would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program that 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, the 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 included a "model trading rule" that described 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. On December 19, 2016, the EPA withdrew the final model emissions trading rule and posted a draft model rule and supporting documents to “guide” states that elect to move forward in complying with the CPP. The CPP reduction of 47.4 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, under the CPP, investments made in renewable energy prior to 2012 are not counted for compliance with the CPP's requirements. 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 all four of the generating units that comprise the Colstrip facility 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 Colstrip Unit 4 represents approximately 25 percent of our customer needs. Closing all four Colstrip units would lead to higher utility rates in order to replace the base-load generation that currently is provided by Colstrip. Closing all four Colstrip units 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, and 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. 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 were among the utilities seeking a stay. On February 9, 2016, the U.S. Supreme Court entered an order staying the CPP. 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. On May 16, 2016, the U.S. Court of Appeals for the District of Columbia entered an order declaring the challenge to the CPP would be reviewed en banc, and on September 27, 2016, the Court held oral argument in the matter. We expect a ruling this year from the U.S. Court of Appeals, and that ruling will likely be followed by a U.S. Supreme Court decision on challenges to the CPP, unless the new EPA administration withdraws, or significantly changes, the rule. On December 22, 2015 we also filed an administrative Petition for Reconsideration with the EPA, requesting that it reconsider the CPP, on the grounds that the CO2 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. On January 11, 2017, the Petition for Reconsideration was denied. We have 60 days in which to file a Petition for Review in the U.S. Court of Appeals for the District of Columbia. 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 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 or 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. Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act 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 Second Circuit 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. Challenges to the final rule have been filed in the Fifth Circuit Court of Appeals, indicating that the EPA underestimated compliance costs. 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. 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 the D.C. Circuit remanded, without vacatur, the MATS rule to the EPA, leaving the rule in place. In April 2016, the EPA published its final supplemental finding that it is "appropriate and necessary" to regulate coal and oil-fired units under Section 112 of the Clean Air Act. Although industry and trade associations have filed a lawsuit in the D.C. Circuit challenging the EPA's supplemental finding, installation or upgrading of relevant environmental controls at our affected plants is complete and we are controlling emissions of mercury under the state and Federal MATS rules. 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 (SO 2 ) 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. EPA has published proposed updates to the CSAPR rule and 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. 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 'Class I' areas. 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. On January 10, 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility, extending the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. Thus, by 2021, 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 (now Talen Montana), the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center (MEIC), 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. MEIC 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. Regarding the CPP, as discussed above, we cannot predict the impact of the CPP on NorthWestern until there is a definitive judicial decision on the issue or other action is taken to withdraw or significantly change the CPP. Compliance with the final rule on Water Intakes and Discharges discussed above, which became effective in January 2016, did not have a significant impact at any of our jointly owned facilities. North Dakota . The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx emissions by July 2018. In 2016, Coyote completed installation of control equipment to maintain compliance with the lower NOx emissions of 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown. The cost of the control equipment was not significant. Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's coal combustion residual 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 the Colstrip Generating Station (Colstrip), including us, as well as Talen Montana (Talen), the operator or managing agent of the station. Colstrip consists of four coal fired generating units. Colstrip Units 1 and 2 are older than Units 3 and 4. We do not have an ownership interest in Units 1 and 2. We have a 30 percent joint interest in Unit 4 and a reciprocal sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output of the units and is responsible for 15 percent of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or Unit 4. On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief that dropped claims associated with projects completed before 2001, 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 SO 2 , 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. In 2013, the Colstrip owners and operator filed partial motions to dismiss. On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications. The parties filed a joint notice (Notice) on April 21, 2014, that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the United States Magistrate Judge (Magistrate) issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motions to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the Court, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions. On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleged a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014. After filing the Second Amended Complaint, Plaintiffs indicated that they were no longer pursuing a number of claims and projects thereby reducing their total to eight claims relating to four projects. The parties filed motions for summary judgment and briefs in support with regard to issues affecting the remaining claims. On December 1, 2015, the Court held oral argument on all pending motions for summary judgment, and on December 31, 2015, the Magistrate issued findings and recommendations which (a) denied Plaintiffs’ motion for partial summary judgment regarding routine maintenance, repair and replacement; (b) denied Plaintiffs’ motion for partial summary judgment that the redesign projects for the Unit 1 and 4 turbines and the Unit 1 economizer were not “like kind replacements”; (c) granted Defendants’ motion for partial summary judgment regarding Plaintiffs’ use of the “actual-to-potential” emissions tes |
Segment and Related Information
Segment and Related Information | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 Electric Gas Other Eliminations Total Operating revenues $ 1,011,595 $ 245,652 $ — $ — $ 1,257,247 Cost of sales 332,817 68,156 — — 400,973 Gross margin 678,778 177,496 — — 856,274 Operating, general and administrative 216,736 86,713 (556 ) — 302,893 Property and other taxes 115,583 32,505 10 — 148,098 Depreciation and depletion 130,236 29,067 33 — 159,336 Operating income 216,223 29,211 513 — 245,947 Interest expense, net (86,038 ) (6,589 ) (2,343 ) — (94,970 ) Other income, net 3,246 1,329 973 — 5,548 Income tax benefit (expense) 7,392 (1,687 ) 1,942 — 7,647 Net income $ 140,823 $ 22,264 $ 1,085 $ — $ 164,172 Total assets $ 4,363,848 $ 1,129,355 $ 6,118 $ — $ 5,499,321 Capital expenditures $ 236,014 $ 51,887 $ — $ — $ 287,901 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, 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 $ 4,185,192 $ 1,072,613 $ 6,890 $ — $ 5,264,695 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 $ 3,434,035 $ 1,519,196 $ 7,671 $ — $ 4,960,902 Capital expenditures $ 233,538 $ 36,846 $ — $ — $ 270,384 |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
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: 2016 First Second Third Fourth Operating revenues $ 332,539 $ 293,120 $ 300,998 $ 330,590 Operating income 61,933 63,742 56,116 64,156 Net income (1) $ 39,867 $ 35,569 $ 44,605 $ 44,131 Average common shares outstanding 48,242 48,309 48,315 48,329 Income per average common share: Basic $ 0.83 $ 0.74 $ 0.92 $ 0.91 Diluted $ 0.82 $ 0.73 $ 0.92 $ 0.92 Dividends per share $ 0.50 $ 0.50 $ 0.50 $ 0.50 Stock price: High $ 62.22 $ 63.30 $ 63.75 $ 59.13 Low 52.16 55.34 56.18 53.85 Quarter-end close 61.75 63.07 57.53 56.87 _____________________ (1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which resulted in an increase in net income and earnings per share for the three months ended March 31, 2016 above. 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 $ 0.92 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 |
Nature of Operations and Basi29
Nature of Operations and Basis of Consolidation (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
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 $246.3 million through 2024 . For further discussion of our gross QF liability, see Note 19 - Commitments and Contingencies. During the years ended December 31, 2016 , 2015 and 2014 purchases from this QF were approximately $25.5 million , $24.3 million , and $24.4 million , respectively. |
Significant Accounting Polici30
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
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 $2.9 million and $4.0 million at December 31, 2016 and December 31, 2015 , respectively. Receivables include unbilled revenues of $80.4 million and $74.5 million at December 31, 2016 and December 31, 2015 , 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 Statements of Income 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 7.2% , 7.5% , and 8.0% , for Montana and South Dakota for 2016 , 2015 , and 2014 , respectively. AFUDC capitalized totaled $7.0 million for the year ended December 31, 2016 , $13.6 million for the year ended December 31, 2015 and $10.8 million for the year ended December 31, 2014 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 3.0% , 3.3% , and 2.9% for 2016 , 2015 , and 2014 , 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. |
Accounting Standards Issued | 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 in the process of evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. Our revenues are primarily from tariff based sales, which are in the scope of the standard. We provide gas or electricity to customers under these tariffs without a defined contractual term (‘at-will’). We expect that the revenue from these arrangements will be equivalent to the electricity or gas supplied and billed in that period (including estimated billings). As such, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. The evaluation of other revenue streams is ongoing, including those tied to longer term contractual commitments. We are also selecting the transition method, either full or modified retrospective, and developing an approach to complying with the disclosure requirements. In addition, there are open industry related transition issues being considered that may change whether the guidance has significant impact on us. We will continue to assess the guidance and expect to conclude our analysis of expected impact during the first half of 2017. In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months. Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us in our first quarter of 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the impact of adoption of this guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our initial analysis we do not expect this guidance to have a significant impact on our Financial Statements and disclosures other than an expected increase in assets and liabilities. In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows. In November 2016, the FASB issued guidance that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new guidance will be effective for us in our first quarter of 2018, with early adoption permitted. We are currently evaluating the impact of adoption of this guidance on our Statement of Cash Flows. |
Significant Accounting Polici31
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Inventories | Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2016 2015 Materials and supplies $31,602 $31,789 Storage gas and fuel 17,604 21,669 Total Inventory $49,206 $53,458 |
Other Noncurrent Liabilties | Other noncurrent liabilities consisted of the following (in thousands): December 31, 2016 2015 Future QF obligation, net $134,324 $138,310 Pension and other employee benefits 120,122 131,887 Environmental 30,501 30,226 Customer advances 40,209 36,046 Asset retirement obligations 39,402 35,532 Other 55,213 46,569 Total $419,771 $418,570 |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Year Ended December 31, 2016 2015 2014 (in thousands) Cash (received) paid for: Income taxes $ (2,922 ) $ (1,284 ) $ 35 Interest 84,953 81,572 63,482 Significant non-cash transactions: Capital expenditures included in trade accounts payable 13,783 12,834 8,555 |
Significant Accounting Polici32
Significant Accounting Policies Adoption of New Accounting Pronouncements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Statement of Financial Position [Abstract] | |
New Accounting Pronouncement, Early Adoption [Table Text Block] | Accounting Standards Adopted In April 2015, the FASB issued accounting guidance that changes the presentation of debt issuance costs. The core principle of this revised accounting guidance is that debt issuance costs are not assets, but adjustments to the carrying cost of debt. During the first quarter of 2016, we retrospectively adopted this guidance. The implementation of this accounting standard resulted in a reduction of other noncurrent assets and long-term debt of $13.9 million in the Consolidated Balance Sheet as of December 31, 2015. In March 2016, the FASB issued Financial Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. The new standard is intended to simplify several aspects of the accounting for share-based payment award transactions including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. We elected to early adopt in the fourth quarter of 2016 as of January 1, 2016. For each share award, we determine whether the difference between the deduction for tax purposes and the compensation cost recognized in the Consolidated Financial Statements results in either an excess tax benefit or an excess tax deficit. Previously, excess tax benefits were recognized in Paid-in capital on our Consolidated Balance Sheet. The new guidance increases income statement volatility by requiring all excess tax benefits and deficits to be recognized in income taxes and treated as discrete items in the period in which they occur. During the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense in the Consolidated Statement of Income. These provisions were adopted prospectively. We applied the modified-retrospective approach to excess tax benefits from prior periods, and recorded a cumulative-effect adjustment to retained earnings as of the date of adoption of $2.6 million in the Consolidated Balance Sheets. Additionally, the cash flow presentation guidance is consistent with our historical presentation, and therefore did not have an impact. Finally, we did not change our accounting policy with regard to estimating forfeitures at the date of grant. |
Acquisitions Purchase Price All
Acquisitions Purchase Price Allocation Table (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | 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 Liabili34
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets And Liabilities | Note Reference Remaining Amortization Period December 31, 2016 2015 (in thousands) Income taxes 13 Plant Lives $ 411,546 $ 319,973 Pension 15 Undetermined 127,133 135,057 Deferred financing costs Various 24,810 19,978 Employee related benefits 15 Undetermined 20,256 21,055 State & local taxes & fees Various 17,838 7,724 Supply costs 1 Year 16,809 29,604 Environmental clean-up 19 Various 13,601 14,237 Distribution infrastructure projects 1 Year 3,136 6,272 Other — Various 17,855 14,671 Total Regulatory Assets $ 652,984 $ 568,571 Removal cost 7 Various $ 386,373 $ 368,467 Supply costs 1 Year 14,041 13,685 Gas storage sales 23 Years 9,569 9,990 Environmental clean-up Various 6,383 7,089 Deferred revenue 4 1 Year 5,066 58,868 State & local taxes & fees 1 Year 1,154 1,566 Other Various — 36 Total Regulatory Liabilities $ 422,586 $ 459,701 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 (years) (in thousands) Land, land rights and easements 54 – 96 $ 138,963 $ 135,930 Building and improvements 27 – 64 225,003 219,907 Transmission, distribution, and storage 15 – 85 2,933,788 2,785,944 Generation 25 – 50 1,167,525 1,154,513 Plant acquisition adjustment 25 – 50 685,417 685,417 Other 2 – 45 472,264 445,679 Construction work in process –— 116,995 75,694 Total property, plant and equipment 5,739,955 5,503,084 Less accumulated depreciation (1,525,063 ) (1,443,585 ) Net property, plant and equipment $ 4,214,892 $ 4,059,499 |
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, 2016 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,623 $ 60,491 $ 50,802 $ 297,289 Accumulated depreciation 38,894 29,235 37,099 77,513 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 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 Liability at January 1, $ 35,532 $ 21,435 Accretion expense 1,885 1,437 Liabilities incurred 164 12,682 Liabilities settled — (22 ) Revisions to cash flows 1,821 — Liability at December 31, $ 39,402 $ 35,532 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill [Abstract] | |
Schedule of Goodwill | Goodwill by segment is as follows (in thousands): December 31, 2016 2015 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total $ 357,586 $ 357,586 |
Risk Management and Hedging A38
Risk Management and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2016 Interest rate contracts Interest Expense $ 2,169 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | December 31, 2016 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 $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228 December 31, 2015 Restricted cash $ 6,240 $ — $ — $ — $ 6,240 Rabbi trust investments 24,245 — — — 24,245 Total $ 30,485 $ — $ — $ — $ 30,485 |
Schedule of Estimated Fair Value of Financial Instruments | The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,793,338 $ 1,852,052 $ 1,768,183 $ 1,844,974 |
Short-Term Borrowings and Cre40
Short-Term Borrowings and Credit Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Line of Credit Facility [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | On December 12, 2016, we amended and restated our existing revolving credit facility to, among other things, increase the size of the facility to $400 million (from $350 million ) and extend the maturity date to December 12, 2021 (from November 5, 2018). We retained an accordion feature that allows us to increase the size up to $450 million with the consent of the lenders. The facility does not amortize and is unsecured. The facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.875% to 1.75% . A total of eight banks participate in the facility, with no one bank providing more than 16% of the total availability. There were no direct borrowings or letters of credit outstanding as of December 31, 2016 . Commitment fees for the unsecured revolving line of credit were $0.4 million for each of the years ended December 31, 2016 and 2015 . 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 |
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): 2016 2015 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 300.8 1.07 % $ 229.9 0.82 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2016 2015 Maximum short-term debt outstanding $ 300.8 $ 267.8 Average short-term debt outstanding $ 210.7 $ 192.8 Weighted-average interest rate 0.86 % 0.61 % |
Long-Term Debt and Capital Le41
Long-Term Debt and Capital Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 Unsecured Debt: Unsecured Revolving Line of Credit 2021 $ — $ — Secured Debt: Mortgage bonds— South Dakota—6.05% 2018 — 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 70,000 South Dakota—2.80% 2026 60,000 — South Dakota—2.66% 2026 45,000 — 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 75,000 Montana—4.11% 2045 125,000 125,000 Pollution control obligations— Montana—4.65% 2023 — 170,205 Montana—2.00% 2023 144,660 — Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,299 ) (13,999 ) $ 1,793,338 $ 1,768,183 Less current maturities — — $ 1,793,338 $ 1,768,183 Capital Leases: Total Capital Leases Various $ 26,325 $ 28,162 Less current maturities (1,979 ) (1,837 ) $ 24,346 $ 26,325 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Income Tax Expense Domestic | Income tax (benefit) expense is comprised of the following (in thousands): Year Ended December 31, 2016 2015 2014 Federal Current $ 723 $ (3,527 ) $ (405 ) Deferred (2,054 ) 33,031 (5,658 ) Investment tax credits (196 ) (232 ) (273 ) State Current 10 (90 ) 18 Deferred (6,130 ) 855 (3,954 ) Income Tax (Benefit) Expense $ (7,647 ) $ 30,037 $ (10,272 ) |
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, 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions (2.4 ) 0.1 (1.8 ) Flow-through repairs deductions (26.3 ) (13.3 ) (22.9 ) Production tax credits (7.0 ) (3.2 ) (2.8 ) Plant and depreciation of flow through items (2.9 ) (1.6 ) 0.1 Share-based compensation (1.1 ) — — Prior year permanent return to accrual adjustments (0.1 ) 0.1 (4.7 ) Recognition of unrecognized tax benefit — — (11.4 ) Other, net (0.1 ) (0.5 ) (0.8 ) Effective tax rate (4.9 )% 16.6 % (9.3 )% The following table summarizes the significant differences in income tax (benefit) expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2016 2015 2014 Income Before Income Taxes $ 156,525 $ 181,246 $ 110,414 Income tax calculated at 35% federal statutory rate 54,784 63,436 38,645 Permanent or flow through adjustments: State tax income, net of federal provisions (3,714 ) 301 (1,969 ) Flow-through repairs deductions (41,111 ) (24,079 ) (25,268 ) Production tax credits (10,941 ) (5,721 ) (3,136 ) Plant and depreciation of flow through items (4,604 ) (2,893 ) 74 Share-based compensation (1,646 ) — — Prior year permanent return to accrual adjustments (128 ) 207 (5,172 ) Recognition of unrecognized tax benefit — — (12,607 ) Other, net (287 ) (1,214 ) (839 ) $ (62,431 ) $ (33,399 ) $ (48,917 ) Income Tax (Benefit) Expense $ (7,647 ) $ 30,037 $ (10,272 ) |
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, 2016 2015 NOL carryforward $ 72,964 $ 3,677 Pension / postretirement benefits 45,847 54,440 Compensation accruals 18,715 17,441 Production tax credit 17,034 6,550 Customer advances 15,837 14,197 AMT credit carryforward 13,599 13,143 Unbilled revenue 12,743 28,390 Environmental liability 9,698 9,410 Interest rate hedges 7,192 6,483 Property taxes 3,767 24,650 Regulatory liabilities 2,290 2,862 Reserves and accruals 1,121 — QF obligations 1,025 2,636 Other, net 3,173 3,696 Deferred Tax Asset 225,005 187,575 Excess tax depreciation (459,588 ) (392,113 ) Goodwill amortization (168,165 ) (152,065 ) Flow through depreciation (160,604 ) (125,441 ) Regulatory assets (12,230 ) (14,901 ) Reserves and accruals — (4,587 ) Deferred Tax Liability (800,587 ) (689,107 ) Deferred Tax Liability, net $ (575,582 ) $ (501,532 ) |
Summary of Income Tax Contingencies | The change in unrecognized tax benefits is as follows (in thousands): 2016 2015 2014 Unrecognized Tax Benefits at January 1 $ 92,387 $ 95,929 $ 113,466 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 Gross decreases - tax positions in current period (3,958 ) (1,177 ) (5,597 ) Lapse of statute of limitations — — (12,849 ) Unrecognized Tax Benefits at December 31 $ 88,429 $ 92,387 $ 95,929 |
Comprehensive Loss (Tables)
Comprehensive Loss (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Schedule of Comprehensive Income (Loss) | The following tables display the components of Other Comprehensive (Loss) Income, after-tax, and the related tax effects (in thousands): December 31, 2016 2015 2014 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 $ 25 $ — $ 25 $ 558 — $ 558 $ 265 $ — $ 265 Reclassification of net gains on derivative instruments (2,169 ) 831 (1,338 ) (1,125 ) 427 (698 ) (1,110 ) 426 (684 ) Realized loss on cash flow hedging derivatives — — — — — — (18,388 ) 7,243 (11,145 ) Postretirement medical liability adjustment 317 (122 ) 195 504 (194 ) 310 134 (52 ) 82 Other comprehensive (loss) income $ (1,827 ) $ 709 $ (1,118 ) $ (63 ) $ 233 $ 170 $ (19,099 ) $ 7,617 $ (11,482 ) |
Accumulated Other Comprehensive Income [Table Text Block] | Balances by classification included within accumulated other comprehensive loss (AOCL) on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2016 December 31, 2015 Foreign currency translation $ 1,380 $ 1,355 Derivative instruments designated as cash flow hedges (10,352 ) (9,014 ) Postretirement medical plans (742 ) (937 ) Accumulated other comprehensive loss $ (9,714 ) $ (8,596 ) |
Schedule of Accumulated Comprehensive Income (Loss) | The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2016 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) Other comprehensive income before reclassifications — — 25 25 Amounts reclassified from AOCL Interest Expense (1,338 ) — — (1,338 ) Amounts reclassified from AOCL — 195 — 195 Net current-period other comprehensive (loss) income (1,338 ) 195 25 (1,118 ) Ending Balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 ) December 31, 2015 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive income before reclassifications — — 558 558 Amounts reclassified from AOCL Interest Expense (698 ) — — (698 ) Amounts reclassified from AOCL — 310 — 310 Net current-period other comprehensive (loss) income (698 ) 310 558 170 Ending Balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 2016 2015 Change in benefit obligation: Obligation at beginning of period $ 628,883 $ 688,444 $ 28,652 $ 30,004 Service cost 11,759 12,362 492 526 Interest cost 26,210 26,174 795 786 Plan amendments — — — 1,045 Actuarial loss (gain) 7,006 (47,351 ) (71 ) (616 ) Settlements — — 390 390 Benefits paid (27,826 ) (50,746 ) (4,041 ) (3,483 ) Benefit Obligation at End of Period $ 646,032 $ 628,883 $ 26,217 $ 28,652 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 500,044 $ 556,051 $ 17,972 $ 18,040 Return on plan assets 39,719 (15,461 ) 1,277 — Employer contributions 12,700 10,200 3,397 3,415 Benefits paid (27,826 ) (50,746 ) (4,041 ) (3,483 ) Fair value of plan assets at end of period $ 524,637 $ 500,044 $ 18,605 $ 17,972 Funded Status $ (121,395 ) $ (128,839 ) $ (7,612 ) $ (10,680 ) Amounts Recognized in the Balance Sheet Consist of: Current liability — — (1,789 ) (2,584 ) Noncurrent liability (121,395 ) (128,839 ) (5,823 ) (8,096 ) Net amount recognized $ (121,395 ) $ (128,839 ) $ (7,612 ) $ (10,680 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (9 ) (255 ) 11,988 14,021 Net actuarial loss (127,953 ) (142,305 ) (4,739 ) (5,219 ) Amounts recognized in AOCL consist of: Prior service cost — — (849 ) (1,000 ) Net actuarial gain — — 38 (102 ) Total $ (127,962 ) $ (142,560 ) $ 6,438 $ 7,700 |
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, 2016 2015 Projected benefit obligation $ 646.0 $ 628.9 Accumulated benefit obligation 643.6 626.0 Fair value of plan assets 524.6 500.0 |
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, 2016 2015 2014 2016 2015 2014 Components of Net Periodic Benefit Cost Service cost $ 11,759 $ 12,362 $ 10,830 $ 492 $ 526 $ 465 Interest cost 26,210 26,174 26,147 795 786 859 Expected return on plan assets (28,248 ) (31,561 ) (29,506 ) (1,042 ) (969 ) (981 ) Amortization of prior service cost (credit) 246 246 246 (1,882 ) (1,882 ) (1,998 ) Recognized actuarial loss 9,888 10,634 2,118 315 385 348 Settlement loss recognized — — — 390 390 690 Net Periodic Benefit Cost (Credit) $ 19,855 $ 17,855 $ 9,835 $ (932 ) $ (764 ) $ (617 ) |
Schedule of Estimated Amortization of Regulatory Assets Into Net Periodic Benefit Costs | We estimate amortizations from regulatory assets into net periodic benefit cost during 2017 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (9 ) $ 1,882 Accumulated loss (7,901 ) (313 ) |
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, 2016 2015 2014 2016 2015 2014 Discount rate 3.95-4.10 % 4.15-4.30 % 3.75-3.90 % 3.40-3.55 % 3.60-3.75 % 3.20-3.40 % Expected rate of return on assets 5.80 5.80 5.80 5.80 5.80 5.80 Long-term rate of increase in compensation levels (nonunion) 3.28 3.58 3.58 3.28 3.58 3.58 Long-term rate of increase in compensation levels (union) 3.20 3.50 3.50 3.20 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, 2016 2015 2016 2015 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, 2016 2015 2016 2015 2016 2015 Cash and cash equivalents — % 0.4 % 0.1 % — % 1.0 % 0.1 % Domestic debt securities 53.4 54.9 64.4 65.8 37.0 37.0 International debt securities 4.6 4.7 4.4 4.5 — — Domestic equity securities 36.0 33.9 26.0 24.9 52.6 54.2 International equity securities 6.0 6.1 5.1 4.8 9.4 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): 2016 2015 2014 NorthWestern Energy Pension Plan (MT) $ 11,500 $ 9,000 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 12,700 $ 10,200 $ 10,200 |
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 2017 $ 30,637 $ 3,513 2018 32,346 3,464 2019 33,574 3,218 2020 34,847 2,844 2021 35,906 2,634 2022-2026 198,236 9,195 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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: 2016 2015 Risk-free interest rate 0.85 % 1.06 % Expected life, in years 3 3 Expected volatility 17.1% to 22.1% 14.2% to 19.0% Dividend yield 3.4 % 3.5 % |
Schedule of Nonvested Share Activity | A summary of nonvested shares as of and changes during the year ended December 31, 2016 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 187,572 $ 40.39 Granted 88,107 50.32 Vested (90,417 ) 38.33 Forfeited (10,005 ) 42.12 Remaining nonvested grants 175,257 $ 46.35 |
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, 2016 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 57,313 $ 37.76 Granted 15,708 45.78 Vested (8,112 ) 28.00 Forfeited (2,318 ) 35.11 Remaining nonvested grants 62,591 $ 41.14 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 Basic computation 48,298,896 47,298,350 Dilutive effect of — Performance and restricted share awards (1) 176,166 344,451 Diluted computation 48,475,062 47,642,801 _____________________ (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, 2016 | |
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, 2016 2015 Beginning QF liability $ 138,310 $ 136,893 Unrecovered amount (14,829 ) (9,379 ) Interest expense 10,843 10,796 Ending QF liability $ 134,324 $ 138,310 |
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 2017 74,607 57,789 16,818 2018 76,703 58,401 18,302 2019 78,836 59,020 19,816 2020 80,984 59,647 21,337 2021 82,941 60,136 22,805 Thereafter 487,957 388,411 99,546 Total $ 882,028 $ 683,404 $ 198,624 |
Segment and Related Informati48
Segment and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 Electric Gas Other Eliminations Total Operating revenues $ 1,011,595 $ 245,652 $ — $ — $ 1,257,247 Cost of sales 332,817 68,156 — — 400,973 Gross margin 678,778 177,496 — — 856,274 Operating, general and administrative 216,736 86,713 (556 ) — 302,893 Property and other taxes 115,583 32,505 10 — 148,098 Depreciation and depletion 130,236 29,067 33 — 159,336 Operating income 216,223 29,211 513 — 245,947 Interest expense, net (86,038 ) (6,589 ) (2,343 ) — (94,970 ) Other income, net 3,246 1,329 973 — 5,548 Income tax benefit (expense) 7,392 (1,687 ) 1,942 — 7,647 Net income $ 140,823 $ 22,264 $ 1,085 $ — $ 164,172 Total assets $ 4,363,848 $ 1,129,355 $ 6,118 $ — $ 5,499,321 Capital expenditures $ 236,014 $ 51,887 $ — $ — $ 287,901 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, 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 $ 4,185,192 $ 1,072,613 $ 6,890 $ — $ 5,264,695 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 $ 3,434,035 $ 1,519,196 $ 7,671 $ — $ 4,960,902 Capital expenditures $ 233,538 $ 36,846 $ — $ — $ 270,384 |
Quarterly Financial Data (Una49
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Amounts presented are in thousands, except per share data: 2016 First Second Third Fourth Operating revenues $ 332,539 $ 293,120 $ 300,998 $ 330,590 Operating income 61,933 63,742 56,116 64,156 Net income (1) $ 39,867 $ 35,569 $ 44,605 $ 44,131 Average common shares outstanding 48,242 48,309 48,315 48,329 Income per average common share: Basic $ 0.83 $ 0.74 $ 0.92 $ 0.91 Diluted $ 0.82 $ 0.73 $ 0.92 $ 0.92 Dividends per share $ 0.50 $ 0.50 $ 0.50 $ 0.50 Stock price: High $ 62.22 $ 63.30 $ 63.75 $ 59.13 Low 52.16 55.34 56.18 53.85 Quarter-end close 61.75 63.07 57.53 56.87 _____________________ (1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which resulted in an increase in net income and earnings per share for the three months ended March 31, 2016 above. 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 $ 0.92 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 |
Nature of Operations and Basi50
Nature of Operations and Basis of Consolidation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)wattscustomers | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Number of customers | customers | 709,600 | ||
Number of megawatts of qualifying facility | watts | 35 | ||
Estimated aggregate gross contractual payments through 2024 | $ 246.3 | ||
Variable interest entity, measure of activity, purchases | $ 25.5 | $ 24.3 | $ 24.4 |
Significant Accounting Polici51
Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 31,602 | $ 31,789 |
Storage gas and fuel | 17,604 | 21,669 |
Total Inventory | $ 49,206 | $ 53,458 |
Significant Accounting Polici52
Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||
Allowance for funds used during construction, rate | 7.20% | 7.50% | 8.00% |
Interest costs, capitalized during period | $ 7 | $ 13.6 | $ 10.8 |
Property, plant and equipment, disclosure of composite depreciation rate for plant in service | 3.00% | 3.30% | 2.90% |
Significant Accounting Polici53
Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | |||
Future QF obligation, net | $ 134,324 | $ 138,310 | |
Pension and other employee benefits | 120,122 | 131,887 | |
Environmental | 30,501 | 30,226 | |
Customer advances | 40,209 | 36,046 | |
Asset retirement obligations | 39,402 | 35,532 | $ 21,435 |
Other | 55,213 | 46,569 | |
Total | $ 419,771 | $ 418,570 |
Significant Accounting Polici54
Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accounting Policies [Abstract] | |||
Income taxes, cash paid (received) | $ (2,922) | $ (1,284) | $ 35 |
Interest, cash paid | 84,953 | 81,572 | 63,482 |
Capital expenditures included in trade accounts payable | $ 13,783 | $ 12,834 | $ 8,555 |
Significant Accounting Polici55
Significant Accounting Policies Narrative (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)days | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Accounting Policies [Abstract] | |||
Debt issuance costs reclassified as adjustments to carrying cost of debt | $ 13,900 | ||
Allowance for doubtful accounts receivable, current | $ 2,900 | 4,000 | |
Unbilled receivables,current | $ 80,400 | 74,500 | |
Number of days or less of maturity to be considered cash equivalent | days | 90 | ||
Excess tax benefits, share-based compensation cost | $ 1,800 | $ 1,800 | $ (100) |
Cumulative effect of new accounting principle in period of adoption | 2,603 | ||
Retained Earnings | |||
Cumulative effect of new accounting principle in period of adoption | $ 2,603 |
Acquisitions South Dakota Wind
Acquisitions South Dakota Wind Generation (Details) - USD ($) $ in Millions | 3 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2015 | |
Property Plant and Equipment | ||
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] | ||
Acquisition date | Sep. 29, 2015 | |
Purchase price | $ 143 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | 41 Months Ended | ||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Nov. 30, 2015 | Dec. 31, 2015 | |
Regulatory Assets [Line Items] | |||||||
Property, plant, and equipment, net | $ 4,214,892 | $ 4,214,892 | $ 4,059,499 | ||||
Hydro Transaction [Member] | Revenue Subject to Refund [Member] | |||||||
Regulatory Assets [Line Items] | |||||||
Reduction of recoverable amount | 1,200 | ||||||
Cumulative deferred revenue | 2,600 | 2,600 | |||||
Deferred revenue decrease | 1,500 | ||||||
Demand side management [Member] | |||||||
Regulatory Assets [Line Items] | |||||||
Demand side management revenue recognized | $ 7,100 | ||||||
Deferred revenue, noncurrent | $ 14,200 | ||||||
Deferred revenue recognized | $ 14,200 | ||||||
Dave Gates Generating Station [Member] | |||||||
Regulatory Assets [Line Items] | |||||||
Deferred revenue, refund payments | 27,300 | ||||||
Property, plant, and equipment, net | 158,000 | 158,000 | |||||
Montana Natural Gas Rate Filing [Member] | |||||||
Regulatory Assets [Line Items] | |||||||
Requested return on equity, percentage | 10.35% | ||||||
Requested rate increase | $ 10,900 | ||||||
Rate base | 432,100 | ||||||
Requested rate increase for delivery service | 7,400 | ||||||
Requested rate increase for production | $ 3,500 | ||||||
Requested debt capital structure, percentage | 53.00% | ||||||
Requested equity capital structure, percentage | 47.00% | ||||||
Interim rate increase, amount | $ 5,600 | ||||||
Disallowed expenses [Member] | |||||||
Regulatory Assets [Line Items] | |||||||
Disallowed modeling costs | $ 2,100 | ||||||
Cost disallowance | 10,300 | ||||||
Disallowed modeling cost reduction | $ 800 | ||||||
Disallowed costs total | $ 12,400 | 12,400 | |||||
Disallowed replacement power and modeling costs | 9,500 | ||||||
Disallowed interest costs | $ 2,900 | ||||||
Disallowed replacement power costs | $ 8,200 |
Regulatory Assets and Liabili58
Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory Assets [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 652,984 | $ 568,571 |
Regulatory Assets [Member] | Income taxes | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 411,546 | 319,973 |
Regulatory Assets [Member] | Pension | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 127,133 | 135,057 |
Regulatory Assets [Member] | Deferred financing costs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 24,810 | 19,978 |
Regulatory Assets [Member] | Employee related benefits | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 20,256 | 21,055 |
Regulatory Assets [Member] | State And Local Taxes And Fees | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 17,838 | 7,724 |
Regulatory Assets [Member] | Supply costs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 16,809 | 29,604 |
Regulatory assets, remaining amortization period | 1 year | |
Regulatory Assets [Member] | Environmental clean-up | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 13,601 | 14,237 |
Regulatory Assets [Member] | Distribution infrastructure projects | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 3,136 | 6,272 |
Regulatory assets, remaining amortization period | 1 year | |
Regulatory Assets [Member] | Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 17,855 | 14,671 |
Regulatory Liabilities [Member] | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 422,586 | 459,701 |
Regulatory Liabilities [Member] | Removal cost | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 386,373 | 368,467 |
Regulatory Liabilities [Member] | Supply costs | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 14,041 | 13,685 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | Gas storage sales | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 9,569 | 9,990 |
Regulatory liability, remaining amortization period | 23 years | |
Regulatory Liabilities [Member] | Environmental clean-up | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 6,383 | 7,089 |
Regulatory Liabilities [Member] | Deferred Revenue | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 5,066 | 58,868 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | State And Local Taxes And Fees | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 1,154 | 1,566 |
Regulatory liability, remaining amortization period | 1 year | |
Regulatory Liabilities [Member] | Other | ||
Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | $ 0 | $ 36 |
Regulatory Assets and Liabili59
Regulatory Assets and Liabilities Narrative (Details) | 12 Months Ended |
Dec. 31, 2016 | |
State And Local Taxes And Fees | |
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 | 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 | 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 | Nebraska | |
Regulatory Assets And Liabilities [Line Items] | |
Percentage of interest earned on electric and natural gas supply costs | 8.50% |
Supply costs | 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, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||
Land, land rights and easements | $ 138,963 | $ 135,930 |
Buildings and improvements | 225,003 | 219,907 |
Transmission, distribution and storage | 2,933,788 | 2,785,944 |
Generation | 1,167,525 | 1,154,513 |
Plant acquisition adjustment | 685,417 | 685,417 |
Other | 472,264 | 445,679 |
Construction work in progress | 116,995 | 75,694 |
Total property, plant and equipment | 5,739,955 | 5,503,084 |
Less accumulated depreciation | (1,525,063) | (1,443,585) |
Net property, plant, and equipment | 4,214,892 | 4,059,499 |
Property, plant, and equipment under capital leases | $ 19,300 | 21,300 |
Increase in PP&E due to Beethoven wind acquisition | 143,000 | |
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 capital leases | $ 19,100 | $ 21,100 |
Property, Plant and Equipment J
Property, Plant and Equipment Joint Ownership (Details) $ in Thousands | Dec. 31, 2016USD ($)plants | Dec. 31, 2015USD ($) |
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 | $ 153,623 | $ 153,740 |
Accumulated depreciation | $ 38,894 | $ 37,522 |
Neal 4 Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 8.70% | 8.70% |
Plant in service | $ 60,491 | $ 60,088 |
Accumulated depreciation | $ 29,235 | $ 27,940 |
Coyote Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 10.00% | 10.00% |
Plant in service | $ 50,802 | $ 46,387 |
Accumulated depreciation | $ 37,099 | $ 37,160 |
Colstrip Unit 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 30.00% | 30.00% |
Plant in service | $ 297,289 | $ 289,604 |
Accumulated depreciation | $ 77,513 | $ 73,328 |
Asset Retirement Obligations Ro
Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liability at January 1, | $ 35,532 | $ 21,435 |
Accretion expense | 1,885 | 1,437 |
Liabilities incurred | 164 | 12,682 |
Liabilities settled | 0 | (22) |
Revision to cash flows | 1,821 | 0 |
Liability at December 31, | $ 39,402 | $ 35,532 |
Asset Retirement Obligations Na
Asset Retirement Obligations Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset retirement obligation increase | $ 1.9 | $ 12 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Goodwill [Line Items] | ||
Goodwill | $ 357,586 | $ 357,586 |
Electric | ||
Goodwill [Line Items] | ||
Goodwill | 243,558 | 243,558 |
Natural gas | ||
Goodwill [Line Items] | ||
Goodwill | $ 114,028 | $ 114,028 |
Risk Management and Hedging A65
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | ||
Physical purchase and sale of gas and electricity at fixed prices | $ 0 | $ 0 |
Pre-tax gain on cash flow hedge from AOCL to be reclassified during next 12 months | 600 | |
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 AOCL | 17,100 | |
Interest Rate Swap [Member] | Interest Expense [Member] | ||
Derivative [Line Items] | ||
Interest rate contracts, amount of gain reclassified from AOCL into income | $ 2,169 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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] | Total Net Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 4,164 | 6,240 |
Rabbi trust investments | 25,064 | 24,245 |
Total | 29,228 | 30,485 |
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 | 4,164 | 6,240 |
Rabbi trust investments | 25,064 | 24,245 |
Total | 29,228 | 30,485 |
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 |
Margin Cash Collateral Offset | 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 Fair 67
Fair Value Measurements Fair Value Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying value | $ 1,793,338 | $ 1,768,183 |
Long-term debt, fair value | $ 1,852,052 | $ 1,844,974 |
Short-Term Borrowings and Cre68
Short-Term Borrowings and Credit Arrangements (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Short-term Debt [Line Items] | ||
Commercial Paper, Balance | $ 300,811 | $ 229,874 |
Maximum aggregate amount issuable at any time under commercial paper program | $ 340,000 | |
Short term borrowings maximum days outstanding | 270 | |
Short-term Debt [Member] | ||
Short-term Debt [Line Items] | ||
Commercial Paper, Balance | $ 300,800 | $ 229,900 |
Commercial Paper, Interest Rate | 1.07% | 0.82% |
Maximum short-term debt outstanding | $ 300,800 | $ 267,800 |
Average short-term debt outstanding | $ 210,700 | $ 192,800 |
Weighted average interest rate | 0.86% | 0.61% |
Unsecured Revolving Line of Cre
Unsecured Revolving Line of Credit (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($)numberofbanks | Dec. 31, 2015USD ($) | |
Line of Credit Facility [Line Items] | ||
Line of credit facility, expiration date | Dec. 12, 2021 | |
Unsecured Revolving Line Of Credit [Member] | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 400 | |
Number of institutions participating in the credit facility | numberofbanks | 8 | |
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 | 16.00% | |
Commitment fees | $ 0.4 | $ 0.4 |
Letters of credit outstanding, amount | $ 0 | |
Maximum ratio of indebtedness to net capital threshold percentage | 65.00% | |
Unsecured Revolving Line Of Credit, Maximun Outstanding Under Accordian Feature [Member] | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 450 | |
Eurodollar [Member] | Minimum [Member] | Unsecured Revolving Line Of Credit [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.875% | |
Eurodollar [Member] | Maximum [Member] | Unsecured Revolving Line Of Credit [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% |
Long-Term Debt and Capital Le70
Long-Term Debt and Capital Leases Schedule of Debt (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Sep. 30, 2016 | Jun. 30, 2016 | Sep. 30, 2015 | Jun. 30, 2015 | Sep. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 1,793,338 | $ 1,768,183 | |||||
Less current maturities | 0 | 0 | |||||
Long-term debt, excluding current maturities | 1,793,338 | 1,768,183 | |||||
Capital Lease | |||||||
Total Capital Leases | 26,325 | 28,162 | |||||
Less current maturities | (1,979) | (1,837) | |||||
Capital lease obligations, noncurrent | 24,346 | 26,325 | |||||
Unsecured Debt | Unsecured Revolving Line Of Credit | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 0 | 0 | |||||
Maturity date | Dec. 12, 2021 | ||||||
Secured Debt | South Dakota, 6.05%, Due 2018 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 0 | 55,000 | |||||
Interest rate, stated percentage | 6.05% | 6.05% | |||||
Maturity date | May 1, 2018 | 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 | 70,000 | |||||
Interest rate, stated percentage | 4.26% | 4.26% | |||||
Maturity date | Sep. 29, 2040 | Sep. 29, 2040 | |||||
Secured Debt | South Dakota, 2.80%, Due 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 60,000 | 0 | |||||
Interest rate, stated percentage | 2.80% | 2.80% | |||||
Maturity date | Jun. 15, 2026 | Jun. 15, 2026 | |||||
Secured Debt | South Dakota, 2.66%, Due 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 45,000 | 0 | |||||
Interest rate, stated percentage | 2.66% | 2.66% | 2.66% | ||||
Maturity date | Sep. 30, 2026 | Sep. 30, 2026 | |||||
Secured Debt | Secured Debt Montana Due 2016 | |||||||
Debt Instrument [Line Items] | |||||||
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 | 75,000 | |||||
Interest rate, stated percentage | 3.11% | 3.11% | |||||
Maturity date | Jul. 1, 2025 | Jul. 1, 2025 | |||||
Secured Debt | Montana 4.11%, due 2045 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 125,000 | 125,000 | |||||
Interest rate, stated percentage | 4.11% | 4.11% | |||||
Maturity date | Jul. 1, 2045 | Jul. 1, 2045 | |||||
Secured Debt | Montana 4.65%, Due 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 0 | 170,205 | |||||
Interest rate, stated percentage | 4.65% | 4.65% | 4.65% | ||||
Maturity date | Aug. 1, 2023 | Aug. 1, 2023 | |||||
Secured Debt | Montana 2.00% Due 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt | $ 144,660 | 0 | |||||
Interest rate, stated percentage | 2.00% | 2.00% | 2.00% | ||||
Maturity date | Aug. 1, 2023 | Aug. 1, 2023 | |||||
Secured Debt | New Market Tax Credit Financing-1.146%, Due 2046 | |||||||
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 and Debt Issuance Costs, Net | |||||||
Debt Instrument [Line Items] | |||||||
Discount on notes and bonds and debt issuance costs, net | $ (13,299) | $ (13,999) |
Long-Term Debt and Capital Le71
Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) - Secured Debt - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Jun. 30, 2016 | Sep. 30, 2015 | Jun. 30, 2015 | Sep. 30, 2016 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||||||
Debt issued by third party | $ 144.7 | $ 144.7 | ||||
Montana 2.00% Due 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Debt Instrument, issuance date | Aug. 11, 2016 | |||||
Interest rate, stated percentage | 2.00% | 2.00% | 2.00% | |||
Maturity date | Aug. 1, 2023 | Aug. 1, 2023 | ||||
Montana 4.65%, Due 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 144.7 | $ 144.7 | ||||
Interest rate, stated percentage | 4.65% | 4.65% | 4.65% | |||
Maturity date | Aug. 1, 2023 | Aug. 1, 2023 | ||||
Repurchased face amount, debt instrument | $ 170.2 | $ 170.2 | ||||
South Dakota, 2.80%, Due 2026 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 60 | |||||
Debt Instrument, issuance date | Jun. 15, 2016 | |||||
Interest rate, stated percentage | 2.80% | 2.80% | ||||
Maturity date | Jun. 15, 2026 | Jun. 15, 2026 | ||||
South Dakota, 6.05%, Due 2018 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate, stated percentage | 6.05% | 6.05% | ||||
Maturity date | May 1, 2018 | May 1, 2018 | ||||
Repurchased face amount, debt instrument | $ 55 | |||||
South Dakota, 2.66%, Due 2026 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 45 | $ 45 | ||||
Interest rate, stated percentage | 2.66% | 2.66% | 2.66% | |||
Maturity date | Sep. 30, 2026 | Sep. 30, 2026 | ||||
South Dakota, 4.26% Due 2040 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 70 | |||||
Debt Instrument, issuance date | Sep. 1, 2015 | |||||
Interest rate, stated percentage | 4.26% | 4.26% | ||||
Maturity date | Sep. 29, 2040 | Sep. 29, 2040 | ||||
Secured Debt Montana Due 2025 and 2045 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 200 | |||||
Debt Instrument, issuance date | Jun. 1, 2015 | |||||
Montana 3.11%, Due 2025 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 75 | |||||
Interest rate, stated percentage | 3.11% | 3.11% | ||||
Maturity date | Jul. 1, 2025 | Jul. 1, 2025 | ||||
Montana 4.11%, due 2045 | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument, face amount | $ 125 | |||||
Interest rate, stated percentage | 4.11% | 4.11% | ||||
Maturity date | Jul. 1, 2045 | Jul. 1, 2045 | ||||
Montana, 6.04%, Due 2016 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate, stated percentage | 6.04% | |||||
Maturity date | Sep. 1, 2016 | |||||
Repurchased face amount, debt instrument | $ 150 |
Long-Term Debt and Capital Le72
Long-Term Debt and Capital Leases Other Long-term Debt (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jul. 31, 2021 | Sep. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||||
Investment in New Market Tax Credit Program | $ 0 | $ 0 | $ 18,169 | ||
New Market Tax Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
New Market Tax Credit (NMTC) financing | $ 27,000 | ||||
New Market Tax Credit Financing | |||||
Debt Instrument [Line Items] | |||||
Investments | 18,200 | ||||
Investment in New Market Tax Credit Program | $ 8,800 | ||||
Scenario, Forecast [Member] | New Market Tax Credit Financing | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument, decrease, forgiveness | $ 7,900 |
Long-Term Debt and Capital Le73
Long-Term Debt and Capital Leases (Details) $ in Millions | Dec. 31, 2016USD ($) |
Maturities of Long-term Debt [Abstract] | |
2,017 | $ 2 |
2,018 | 2.1 |
2,019 | 252.3 |
2,020 | 2.5 |
2,021 | $ 2.7 |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Contingency [Line Items] | ||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |
Other income tax benefit | $ 17,000 | |||
Tax benefit related to prior years | $ 4,300 | 12,500 | ||
Recognition of unrecognized tax benefit | $ 0 | $ 0 | $ 12,607 | |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Federal | |||
Current | $ 723 | $ (3,527) | $ (405) |
Deferred | (2,054) | 33,031 | (5,658) |
Investment tax credits | (196) | (232) | (273) |
State | |||
Current | 10 | (90) | 18 |
Deferred | (6,130) | 855 | (3,954) |
Income Tax (Benefit) Expense | $ (7,647) | $ 30,037 | $ (10,272) |
Income Taxes Effective Rate Rec
Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal provisions | (2.40%) | 0.10% | (1.80%) |
Flow-through repairs deductions | (26.30%) | (13.30%) | (22.90%) |
Production tax credits | (7.00%) | (3.20%) | (2.80%) |
Plant and depreciation of flow through items | (2.90%) | (1.60%) | 0.10% |
Share-based compensation | (1.10%) | (0.00%) | (0.00%) |
Prior year permanent return to accrual adjustments | (0.10%) | 0.10% | (4.70%) |
Recognition of unrecognized tax benefit | (0.00%) | (0.00%) | (11.40%) |
Other, net | (0.10%) | (0.50%) | (0.80%) |
Effective income tax rate | (4.90%) | 16.60% | (9.30%) |
Income Before Income Taxes | $ 156,525 | $ 181,246 | $ 110,414 |
Income tax calculated at 35% federal statutory rate | 54,784 | 63,436 | 38,645 |
State tax income, net of federal provisions | (3,714) | 301 | (1,969) |
Flow-through repairs deductions | (41,111) | (24,079) | (25,268) |
Production tax credits | (10,941) | (5,721) | (3,136) |
Plant and depreciation of flow through items | (4,604) | (2,893) | 74 |
Share-based compensation | (1,646) | 0 | 0 |
Prior year permanent return to accrual adjustments | (128) | 207 | (5,172) |
Recognition of unrecognized tax benefit | 0 | 0 | (12,607) |
Other, net | (287) | (1,214) | (839) |
Total reconciling items | (62,431) | (33,399) | (48,917) |
Income Tax (Benefit) Expense | $ (7,647) | $ 30,037 | $ (10,272) |
Income Taxes Deferred Tax Liabi
Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred Tax Assets, [Abstract] | ||
NOL carryforward | $ 72,964 | $ 3,677 |
Pension / postretirement benefits | 45,847 | 54,440 |
Compensation accruals | 18,715 | 17,441 |
Production tax credit | 17,034 | 6,550 |
Customer advances | 15,837 | 14,197 |
AMT credit carryforward | 13,599 | 13,143 |
Unbilled revenue | 12,743 | 28,390 |
Environmental liability | 9,698 | 9,410 |
Interest rate hedges | 7,192 | 6,483 |
Property taxes | 3,767 | 24,650 |
Regulatory liabilities | 2,290 | 2,862 |
Reserves and accruals | 1,121 | 0 |
QF obligations | 1,025 | 2,636 |
Other, net | 3,173 | 3,696 |
Deferred Tax Asset | 225,005 | 187,575 |
Deferred Tax Liabilities, [Abstract] | ||
Excess tax depreciation | (459,588) | (392,113) |
Goodwill amortization | (168,165) | (152,065) |
Flow through depreciation | (160,604) | (125,441) |
Regulatory assets | (12,230) | (14,901) |
Reserves and accruals | 0 | (4,587) |
Deferred Tax Liability | (800,587) | (689,107) |
Deferred Tax Liability, net | $ (575,582) | $ (501,532) |
Income Taxes Operating Loss (De
Income Taxes Operating Loss (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | $ 365.1 |
State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | 276 |
Year 2031 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 105.2 |
NOL carryforwards, expiration date | Dec. 31, 2031 |
Year 2033 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 13.3 |
NOL carryforwards, expiration date | Dec. 31, 2033 |
Year 2034 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 73.4 |
NOL carryforwards, expiration date | Dec. 31, 2034 |
Year 2036 [Member] | Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 173.2 |
NOL carryforwards, expiration date | Dec. 31, 2036 |
Year 2018 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 67 |
NOL carryforwards, expiration date | Dec. 31, 2018 |
Year 2020 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 10.5 |
NOL carryforwards, expiration date | Dec. 31, 2020 |
Year 2021 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 58.3 |
NOL carryforwards, expiration date | Dec. 31, 2021 |
Year 2023 [Member] | State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 140.2 |
NOL carryforwards, expiration date | Dec. 31, 2023 |
Income Taxes Uncertain Tax Posi
Income Taxes Uncertain Tax Positions (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Contingency [Line Items] | |||
Income tax penalties and interest expense | $ 700,000 | $ 0 | |
Accrual for interest and penalties | $ 700,000 | 0 | |
Unrecognized tax benefit more likely than not percentage threshold | 50.00% | ||
Unrecognized tax benefits that would impact effective tax rate | $ 66,500,000 | 65,200,000 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits at January 1 | 92,387,000 | 95,929,000 | $ 113,466,000 |
Gross increases - tax positions in prior period | 0 | 44,000 | 0 |
Gross decreases - tax positions in prior period | 0 | (2,903,000) | 0 |
Gross increases - tax positions in current period | 0 | 494,000 | 909,000 |
Gross decreases - tax positions in current period | (3,958,000) | (1,177,000) | (5,597,000) |
Lapse of statute of limitations | 0 | 0 | (12,849,000) |
Unrecognized Tax Benefits at December 31 | $ 88,429,000 | $ 92,387,000 | $ 95,929,000 |
Comprehensive Loss (Details)
Comprehensive Loss (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Comprehensive Income (Loss), Before Tax [Abstract] | |||
Foreign currency translation adjustment | $ 25 | $ 558 | $ 265 |
Reclassification of net gains on derivative instruments | (2,169) | (1,125) | (1,110) |
Realized loss on cash flow hedging derivatives | 0 | 0 | (18,388) |
Postretirement medical liability adjustment | 317 | 504 | 134 |
Other comprehensive (loss) income | (1,827) | (63) | (19,099) |
Other Comprehensive Income (Loss), Tax [Abstract] | |||
Foreign currency translation adjustment | 0 | 0 | 0 |
Reclassification of net gains on derivative instruments | 831 | 427 | 426 |
Realized loss on cash flow hedging derivatives | 0 | 0 | 7,243 |
Postretirement medical liability adjustment | (122) | (194) | (52) |
Other comprehensive (loss) income | 709 | 233 | 7,617 |
Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||
Foreign currency translation adjustment | 25 | 558 | 265 |
Reclassification of net gains on derivative instruments | (1,338) | (698) | (684) |
Realized loss on cash flow hedging derivatives | 0 | 0 | (11,145) |
Postretirement medical liability adjustment | 195 | 310 | 82 |
Other comprehensive (loss) income | (1,118) | 170 | $ (11,482) |
Accumulated Other Comprehensive Income, Net of Tax [Abstract] | |||
Foreign currency translation | 1,380 | 1,355 | |
Derivative instruments designated as cash flow hedges | (10,352) | (9,014) | |
Pension and postretirement medical plans | (742) | (937) | |
Accumulated other comprehensive loss | $ (9,714) | $ (8,596) |
Comprehensive Loss Components o
Comprehensive Loss Components of AOCI (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | $ (8,596) | ||
Net current-period other comprehensive (loss) income | (1,118) | $ 170 | $ (11,482) |
Ending Balance | (9,714) | (8,596) | |
Total | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (8,596) | (8,766) | |
Other comprehensive income before reclassifications | 25 | 558 | |
Amounts reclassified from AOCL | 195 | 310 | |
Net current-period other comprehensive (loss) income | (1,118) | 170 | |
Ending Balance | (9,714) | (8,596) | (8,766) |
Total | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from AOCL | (1,338) | (698) | |
Foreign Currency Translation | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | 1,355 | 797 | |
Other comprehensive income before reclassifications | 25 | 558 | |
Amounts reclassified from AOCL | 0 | 0 | |
Net current-period other comprehensive (loss) income | 25 | 558 | |
Ending Balance | 1,380 | 1,355 | 797 |
Foreign Currency Translation | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from AOCL | 0 | 0 | |
Pension and Postretirement Medical Plans | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (937) | (1,247) | |
Other comprehensive income before reclassifications | 0 | 0 | |
Amounts reclassified from AOCL | 195 | 310 | |
Net current-period other comprehensive (loss) income | 195 | 310 | |
Ending Balance | (742) | (937) | (1,247) |
Pension and Postretirement Medical Plans | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from AOCL | 0 | 0 | |
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (9,014) | (8,316) | |
Other comprehensive income before reclassifications | 0 | 0 | |
Amounts reclassified from AOCL | 0 | 0 | |
Net current-period other comprehensive (loss) income | (1,338) | (698) | |
Ending Balance | (10,352) | (9,014) | $ (8,316) |
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Interest Expense [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Amounts reclassified from AOCL | $ (1,338) | $ (698) |
Employee Benefit Plans Benefit
Employee Benefit Plans Benefit Obligation And Funded Status (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation at beginning of period | $ 628,883 | $ 688,444 | |
Service cost | 11,759 | 12,362 | |
Interest cost | 26,210 | 26,174 | |
Plan amendments | 0 | 0 | |
Actuarial loss (gain) | 7,006 | (47,351) | |
Settlements | 0 | 0 | |
Benefits paid | (27,826) | (50,746) | |
Benefit Obligation at End of Period | 646,032 | 628,883 | $ 688,444 |
Change in Fair Value of Plan Assets: | |||
Employer contributions | 9,800 | 9,500 | 8,700 |
Benefits paid | (27,826) | (50,746) | |
Amounts Recognized in the Balance Sheet Consist of: | |||
Current liability | 0 | 0 | |
Noncurrent liability | (121,395) | (128,839) | |
Net amount recognized | (121,395) | (128,839) | |
Amounts recognized in AOCL consist of: | |||
Prior service cost | 0 | 0 | |
Net actuarial gain | 0 | 0 | |
Total | (127,962) | (142,560) | |
Plans with Benefit Obligations in Excess of Plan Assets [Abstract] | |||
Projected benefit obligation | 646,000 | 628,900 | |
Accumulated benefit obligation | 643,600 | 626,000 | |
Fair value of plan assets | 524,600 | 500,000 | |
Pension Plan [Member] | Pension Costs [Member] | |||
Amounts Recognized in Regulatory Assets Consist of: | |||
Prior service (cost) credit | (9) | (255) | |
Net actuarial loss | (127,953) | (142,305) | |
Pension Plan [Member] | Changes Measurement [Member] | |||
Change in Benefit Obligation: | |||
Benefits paid | (27,826) | (50,746) | |
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 500,044 | 556,051 | |
Return on plan assets | 39,719 | (15,461) | |
Employer contributions | 12,700 | 10,200 | |
Benefits paid | (27,826) | (50,746) | |
Fair value of plan assets at end of period | 524,637 | 500,044 | 556,051 |
Funded Status | (121,395) | (128,839) | |
Other Postretirement Benefit Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation at beginning of period | 28,652 | 30,004 | |
Service cost | 492 | 526 | |
Interest cost | 795 | 786 | |
Plan amendments | 0 | 1,045 | |
Actuarial loss (gain) | (71) | (616) | |
Settlements | 390 | 390 | |
Benefits paid | (4,041) | (3,483) | |
Benefit Obligation at End of Period | 26,217 | 28,652 | 30,004 |
Change in Fair Value of Plan Assets: | |||
Benefits paid | (4,041) | (3,483) | |
Amounts Recognized in the Balance Sheet Consist of: | |||
Current liability | (1,789) | (2,584) | |
Noncurrent liability | (5,823) | (8,096) | |
Net amount recognized | (7,612) | (10,680) | |
Amounts recognized in AOCL consist of: | |||
Prior service cost | (849) | (1,000) | |
Net actuarial gain | 38 | (102) | |
Total | 6,438 | 7,700 | |
Other Postretirement Benefit Plan [Member] | Pension Costs [Member] | |||
Amounts Recognized in Regulatory Assets Consist of: | |||
Prior service (cost) credit | 11,988 | 14,021 | |
Net actuarial loss | (4,739) | (5,219) | |
Other Postretirement Benefit Plan [Member] | Changes Measurement [Member] | |||
Change in Benefit Obligation: | |||
Benefits paid | (4,041) | (3,483) | |
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 17,972 | 18,040 | |
Return on plan assets | 1,277 | 0 | |
Employer contributions | 3,397 | 3,415 | |
Benefits paid | (4,041) | (3,483) | |
Fair value of plan assets at end of period | 18,605 | 17,972 | $ 18,040 |
Funded Status | $ (7,612) | $ (10,680) |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | $ 11,759 | $ 12,362 | ||
Interest cost | 26,210 | 26,174 | ||
Recognized actuarial loss | (7,006) | 47,351 | ||
Settlements | 0 | 0 | ||
Net Periodic Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 11,759 | 12,362 | $ 10,830 | |
Interest cost | 26,210 | 26,174 | 26,147 | |
Expected return on plan assets | (28,248) | (31,561) | (29,506) | |
Amortization of prior service cost (credit) | 246 | 246 | 246 | |
Recognized actuarial loss | 9,888 | 10,634 | 2,118 | |
Settlements | 0 | 0 | 0 | |
Net Periodic Benefit Cost (Credit) | 19,855 | 17,855 | 9,835 | |
Net Periodic Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 492 | 526 | 465 | |
Interest cost | 795 | 786 | 859 | |
Expected return on plan assets | (1,042) | (969) | (981) | |
Amortization of prior service cost (credit) | (1,882) | (1,882) | (1,998) | |
Recognized actuarial loss | 315 | 385 | 348 | |
Settlements | 390 | 390 | 690 | |
Net Periodic Benefit Cost (Credit) | $ (932) | $ (764) | $ (617) | |
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Prior service credit (cost) | $ (9) | |||
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Prior service credit (cost) | 1,882 | |||
Scenario, Forecast [Member] | Pension Costs [Member] | Pension Plan [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Accumulated loss | (7,901) | |||
Scenario, Forecast [Member] | Pension Costs [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Accumulated loss | $ (313) |
Employee Benefit Plans Actuaria
Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Increase in projected benefit obligation due to change in discount rate | $ 16.1 | |||
Pension Plan [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on assets | 5.80% | 5.80% | 5.80% | |
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 | 3.28% | 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 | 3.20% | 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 | 3.95% | 4.15% | 3.75% | |
Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 4.10% | 4.30% | 3.90% | |
Other Postretirement Benefit Plan [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on assets | 5.80% | 5.80% | 5.80% | |
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | ||||
Health care cost trend rate assumed for next year | 7.59% | |||
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 | 3.28% | 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 | 3.20% | 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 | 3.40% | 3.60% | 3.20% | |
Other Postretirement Benefit Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 3.55% | 3.75% | 3.40% | |
Scenario, Forecast [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Expected rate of return on assets | 4.70% |
Employee Benefit Plans Investme
Employee Benefit Plans Investment Strategy (Details) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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 | 1.00% | 0.10% |
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% | 37.00% |
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 | 52.60% | 54.20% |
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 | 9.40% | 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 | 0.00% | 0.40% |
Montana | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 53.40% | 54.90% |
Montana | Debt Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 4.60% | 4.70% |
Montana | Equity Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 36.00% | 33.90% |
Montana | Equity Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 6.00% | 6.10% |
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 | 0.10% | 0.00% |
South Dakota | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 64.40% | 65.80% |
South Dakota | Debt Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 4.40% | 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 | 26.00% | 24.90% |
South Dakota | Equity Securities [Member] | Pension Plan [Member] | International [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 5.10% | 4.80% |
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 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension contributions | $ 12,700 | $ 10,200 | $ 10,200 |
Montana | Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension contributions | 11,500 | 9,000 | 9,000 |
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 |
Employee Benefit Plans Estimate
Employee Benefit Plans Estimated Payments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Employer contributions | $ 9,800 | $ 9,500 | $ 8,700 |
Estimated Future Benefit Payments | |||
2,017 | 30,637 | ||
2,018 | 32,346 | ||
2,019 | 33,574 | ||
2,020 | 34,847 | ||
2,021 | 35,906 | ||
2022-2026 | 198,236 | ||
Other Pension Plan, Postretirement or Supplemental Plans [Member] | |||
Estimated Future Benefit Payments | |||
2,017 | 3,513 | ||
2,018 | 3,464 | ||
2,019 | 3,218 | ||
2,020 | 2,844 | ||
2,021 | 2,634 | ||
2022-2026 | $ 9,195 |
Employee Benefit Plans Narrativ
Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
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 | $ 9.8 | $ 9.5 | $ 8.7 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 5.3 | $ 4.4 | $ 3.1 |
Compensation expense tax (expense) benefit | (1.8) | (1.8) | 0.1 |
Compensation expense not yet recognized for nonvested awards | $ 5.1 | ||
Nonvested awards, total compensation cost not yet recognized, period for recognition | 2 years | ||
Shares vested in period, total fair value | $ 3.5 | $ 2.8 | $ 2.1 |
Share-based Compensation, Significant Assumptions | |||
Risk-free interest rate | 0.85% | 1.06% | |
Expected life, in years | 3 years | 3 years | |
Expected volatility, minimum | 17.10% | 14.20% | |
Expected volatility, maximum | 22.10% | 19.00% | |
Dividend yield | 3.40% | 3.50% | |
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 | 28,338 | 35,030 | 26,460 |
Deferred stock units total compensation expense | $ 2.4 | $ 1.3 | $ 2.3 |
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 | 870,186 |
Stock-Based Compensation Nonves
Stock-Based Compensation Nonvested (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2016$ / 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 | 187,572 |
Granted (shares) | shares | 88,107 |
Vested (shares) | shares | (90,417) |
Forfeited (shares) | shares | (10,005) |
Remaining nonvested grants (shares) | shares | 175,257 |
Beginning nonvested (weighted-average grant date fair value) | $ / shares | $ 40.39 |
Granted (weighted-average grant date fair value) | $ / shares | 50.32 |
Vested (weighted-average grant date fair value) | $ / shares | 38.33 |
Forfeited (weighted-average grant date fair value) | $ / shares | 42.12 |
Remaining nonvested (weighted-average grant date fair value) | $ / shares | $ 46.35 |
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 | 57,313 |
Granted (shares) | shares | 15,708 |
Vested (shares) | shares | (8,112) |
Forfeited (shares) | shares | (2,318) |
Remaining nonvested grants (shares) | shares | 62,591 |
Beginning nonvested (weighted-average grant date fair value) | $ / shares | $ 37.76 |
Granted (weighted-average grant date fair value) | $ / shares | 45.78 |
Vested (weighted-average grant date fair value) | $ / shares | 28 |
Forfeited (weighted-average grant date fair value) | $ / shares | 35.11 |
Remaining nonvested (weighted-average grant date fair value) | $ / shares | $ 41.14 |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Class of Stock [Line Items] | ||||
Combined common and preferred stock, shares authorized | 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 | |||
Net proceeds from sale of stock | $ 2,345 | $ 58,581 | $ 399,505 | |
Shares paid for tax withholding | 49,514 | 39,504 | ||
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, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Basic computation | 48,329,000 | 48,315,000 | 48,309,000 | 48,242,000 | 48,098,000 | 47,065,000 | 47,044,000 | 46,977,000 | 48,298,896 | 47,298,350 | 40,156,177 | ||
Performance share awards (1) | 22,044 | [1] | 176,166 | [1] | 344,451 | ||||||||
Diluted computation | 48,475,062 | 47,642,801 | |||||||||||
[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. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 22,044 shares for the year ended December 31, 2016. See Note 2 - Significant Accounting Policies, for further discussion of the impacts of this standard. |
Commitments and Contingencies Q
Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Beginning QF liability | $ 138,310,000 | |
Ending QF liability | $ 134,324,000 | $ 138,310,000 |
Qualifying Facility Contracts [Member] | ||
Long-term purchase commitment through year 2029 | 2029 years | |
Beginning QF liability | $ 138,310,000 | 136,893,000 |
Unrecovered amount | (14,829,000) | (9,379,000) |
Interest expense | 10,843,000 | 10,796,000 |
Ending QF liability | 134,324,000 | $ 138,310,000 |
Qualifying Facility Contracts [Member] | Minimum [Member] | ||
Price per MWH of energy required to be purchased per QF agreement | 74 | |
Qualifying Facility Contracts [Member] | Maximum [Member] | ||
Price per MWH of energy required to be purchased per QF agreement | 136 | |
Qualifying Facility Contracts [Member] | Gross Obligation [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,017 | 74,607,000 | |
2,018 | 76,703,000 | |
2,019 | 78,836,000 | |
2,020 | 80,984,000 | |
2,021 | 82,941,000 | |
Thereafter | 487,957,000 | |
Contractual obligation related to QF's | 882,028,000 | |
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,017 | 57,789,000 | |
2,018 | 58,401,000 | |
2,019 | 59,020,000 | |
2,020 | 59,647,000 | |
2,021 | 60,136,000 | |
Thereafter | 388,411,000 | |
Contractual obligation related to QF's | 683,404,000 | |
Qualifying Facility Contracts [Member] | Net Amount [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,017 | 16,818,000 | |
2,018 | 18,302,000 | |
2,019 | 19,816,000 | |
2,020 | 21,337,000 | |
2,021 | 22,805,000 | |
Thereafter | 99,546,000 | |
Contractual obligation related to QF's | 198,624,000 | |
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2,017 | 206,100,000 | |
2,018 | 155,900,000 | |
2,019 | 156,200,000 | |
2,020 | 122,800,000 | |
2,021 | 107,000,000 | |
Thereafter | $ 1,300,000,000 |
Commitments and Contingencies L
Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long term purchase committments costs incurred | $ 216.8 | $ 241.6 | $ 402.3 |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
2,017 | 206.1 | ||
2,018 | 155.9 | ||
2,019 | 156.2 | ||
2,020 | 122.8 | ||
2,021 | 107 | ||
Thereafter | $ 1,300 | ||
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | Minimum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long term purchase commitments term | 1 year | ||
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | Maximum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long term purchase commitments term | 27 | ||
Hydroelectric License Commitments [Member] | Minimum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long term purchase commitments term | 2,017 | ||
Hydroelectric License Commitments [Member] | Maximum [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Long term purchase commitments term | 2,040 |
Commitments and Contingencies E
Commitments and Contingencies Environmental Liabilities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Jul. 01, 2018 | Dec. 31, 2015 | |
Other Commitment | $ 22 | ||
Colstrip Unit 4 [Member] | |||
Environmental obligation, estimated capital expenditures | $ 90 | ||
Jointly owned utility plant, proportionate ownership share | 30.00% | 30.00% | |
Coyote Generating Facility [Member] | |||
Jointly owned utility plant, proportionate ownership share | 10.00% | 10.00% | |
Environmental remediation obligations [Member] | |||
Environmental remediation obligation, minimum | $ 27.9 | ||
Environmental remediation obligation, maximum | 32.6 | ||
Accrual for environmental loss contingencies | 31.5 | ||
Scenario, Forecast [Member] | Coyote Generating Facility [Member] | |||
NOx emissions per million Btu | 0.5 | ||
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | |||
Accrual for environmental loss contingencies | 10.8 | ||
Environmental remediation obligation, to be incurred during next 5 years | $ 6.2 | ||
Number of years for environmental remediation obligation to be incurred | 5 years | ||
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member] | |||
Accrual for environmental loss contingencies | $ 24.7 |
Commitments and Contingencies96
Commitments and Contingencies Legal Proceedings (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |
Aug. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | |
Loss Contingencies [Line Items] | |||
Liability insurance coverage, retention amount | $ 2 | ||
Refinery outage [Member] | |||
Loss Contingencies [Line Items] | |||
Damages sought | $ 48.5 | $ 108 | $ 61.7 |
Segment and Related Informati97
Segment and Related Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | $ 330,590 | $ 300,998 | $ 293,120 | $ 332,539 | $ 324,989 | $ 272,739 | $ 270,560 | $ 346,011 | $ 1,257,247 | $ 1,214,299 | $ 1,204,863 |
Cost of sales | 400,973 | 372,864 | 482,591 | ||||||||
Gross margin | 856,274 | 841,435 | 722,272 | ||||||||
Operating, general and administrative | 302,893 | 297,475 | 305,886 | ||||||||
Property and other taxes | 148,098 | 133,442 | 114,592 | ||||||||
Depreciation and depletion | 159,336 | 144,702 | 123,776 | ||||||||
Operating Income | 64,156 | 56,116 | 63,742 | 61,933 | 72,332 | 48,461 | 61,132 | 83,891 | 245,947 | 265,816 | 178,018 |
Interest expense, net | (94,970) | (92,153) | (77,802) | ||||||||
Other income, net | 5,548 | 7,583 | 10,198 | ||||||||
Income tax (expense) benefit | 7,647 | (30,037) | 10,272 | ||||||||
Net Income | 44,131 | $ 44,605 | $ 35,569 | $ 39,867 | 45,013 | $ 23,798 | $ 30,973 | $ 51,425 | 164,172 | 151,209 | 120,686 |
Total assets | 5,499,321 | 5,264,695 | 5,499,321 | 5,264,695 | 4,960,902 | ||||||
Capital expenditures | 287,901 | 283,705 | 270,384 | ||||||||
Electric | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 1,011,595 | 944,428 | 877,967 | ||||||||
Cost of sales | 332,817 | 281,251 | 348,640 | ||||||||
Gross margin | 678,778 | 663,177 | 529,327 | ||||||||
Operating, general and administrative | 216,736 | 233,416 | 200,186 | ||||||||
Property and other taxes | 115,583 | 104,264 | 84,759 | ||||||||
Depreciation and depletion | 130,236 | 115,701 | 94,813 | ||||||||
Operating Income | 216,223 | 209,796 | 149,569 | ||||||||
Interest expense, net | (86,038) | (79,044) | (60,424) | ||||||||
Other income, net | 3,246 | 6,300 | 4,758 | ||||||||
Income tax (expense) benefit | 7,392 | (19,950) | (1,490) | ||||||||
Net Income | 140,823 | 117,102 | 92,413 | ||||||||
Total assets | 4,363,848 | 4,185,192 | 4,363,848 | 4,185,192 | 3,434,035 | ||||||
Capital expenditures | 236,014 | 234,451 | 233,538 | ||||||||
Gas | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Operating revenues | 245,652 | 269,871 | 326,896 | ||||||||
Cost of sales | 68,156 | 91,613 | 133,951 | ||||||||
Gross margin | 177,496 | 178,258 | 192,945 | ||||||||
Operating, general and administrative | 86,713 | 84,219 | 91,437 | ||||||||
Property and other taxes | 32,505 | 29,168 | 29,821 | ||||||||
Depreciation and depletion | 29,067 | 28,968 | 28,930 | ||||||||
Operating Income | 29,211 | 35,903 | 42,757 | ||||||||
Interest expense, net | (6,589) | (11,433) | (10,618) | ||||||||
Other income, net | 1,329 | 1,821 | 1,324 | ||||||||
Income tax (expense) benefit | (1,687) | (3,752) | (7,463) | ||||||||
Net Income | 22,264 | 22,539 | 26,000 | ||||||||
Total assets | 1,129,355 | 1,072,613 | 1,129,355 | 1,072,613 | 1,519,196 | ||||||
Capital expenditures | 51,887 | 49,254 | 36,846 | ||||||||
Other Segments [Member] | |||||||||||
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 | (556) | (20,160) | 14,263 | ||||||||
Property and other taxes | 10 | 10 | 12 | ||||||||
Depreciation and depletion | 33 | 33 | 33 | ||||||||
Operating Income | 513 | 20,117 | (14,308) | ||||||||
Interest expense, net | (2,343) | (1,676) | (6,760) | ||||||||
Other income, net | 973 | (538) | 4,116 | ||||||||
Income tax (expense) benefit | 1,942 | (6,335) | 19,225 | ||||||||
Net Income | 1,085 | 11,568 | 2,273 | ||||||||
Total assets | 6,118 | 6,890 | 6,118 | 6,890 | 7,671 | ||||||
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 (Una98
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating revenues | $ 330,590 | $ 300,998 | $ 293,120 | $ 332,539 | $ 324,989 | $ 272,739 | $ 270,560 | $ 346,011 | $ 1,257,247 | $ 1,214,299 | $ 1,204,863 |
Operating income | 64,156 | 56,116 | 63,742 | 61,933 | 72,332 | 48,461 | 61,132 | 83,891 | 245,947 | 265,816 | 178,018 |
Net Income | $ 44,131 | $ 44,605 | $ 35,569 | $ 39,867 | $ 45,013 | $ 23,798 | $ 30,973 | $ 51,425 | $ 164,172 | $ 151,209 | $ 120,686 |
Average Common Shares Outstanding | 48,329,000 | 48,315,000 | 48,309,000 | 48,242,000 | 48,098,000 | 47,065,000 | 47,044,000 | 46,977,000 | 48,298,896 | 47,298,350 | 40,156,177 |
Dividends per share | $ 0.50 | $ 0.50 | $ 0.50 | $ 0.50 | $ 0.48 | $ 0.48 | $ 0.48 | $ 0.48 | $ 2 | $ 1.92 | $ 1.60 |
Quarter-end close | 56.87 | 57.53 | 63.07 | 61.75 | 54.25 | 53.83 | 48.75 | 53.79 | 56.87 | 54.25 | |
Income per average common share | |||||||||||
Net income basic | 0.91 | 0.92 | 0.74 | 0.83 | 0.94 | 0.51 | 0.66 | 1.09 | 3.40 | 3.20 | 3.01 |
Net income diluted | 0.92 | 0.92 | 0.73 | 0.82 | 0.92 | 0.51 | 0.65 | 1.09 | $ 3.39 | $ 3.17 | $ 2.99 |
Maximum [Member] | |||||||||||
Stock price | 59.13 | 63.75 | 63.30 | 62.22 | 57.07 | 56.68 | 54.65 | 59.71 | |||
Minimum [Member] | |||||||||||
Stock price | $ 53.85 | $ 56.18 | $ 55.34 | $ 52.16 | $ 51.27 | $ 48.47 | $ 48.44 | $ 50.75 |
Quarterly Financial Data (Una99
Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Effect of Fourth Quarter Events [Line Items] | |||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 1.8 | $ 1.8 | $ (0.1) |