Document and Document Entity In
Document and Document Entity Information - USD ($) | 6 Months Ended | |
Jun. 30, 2017 | Jul. 21, 2017 | |
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-Q | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 48,471,447 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Public Float | $ 2,957,686,000 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Revenues | ||||
Electric | $ 233,866 | $ 248,403 | $ 500,105 | $ 489,745 |
Gas | 49,993 | 44,717 | 151,066 | 135,914 |
Total Revenues | 283,859 | 293,120 | 651,171 | 625,659 |
Operating Expenses | ||||
Cost of sales | 84,000 | 81,693 | 203,817 | 197,127 |
Operating, general and administrative | 75,188 | 72,579 | 156,150 | 152,440 |
Property and other taxes | 39,481 | 35,208 | 79,409 | 70,629 |
Depreciation and depletion | 41,495 | 39,898 | 82,956 | 79,788 |
Total Operating Expenses | 240,164 | 229,378 | 522,332 | 499,984 |
Operating Income | 43,695 | 63,742 | 128,839 | 125,675 |
Interest Expense, net | (23,408) | (26,421) | (46,808) | (50,930) |
Other Income | 2,123 | 1,195 | 3,623 | 4,297 |
Income Before Income Taxes | 22,410 | 38,516 | 85,654 | 79,042 |
Income Tax Expense | (580) | (2,947) | (7,257) | (3,606) |
Net Income | $ 21,830 | $ 35,569 | $ 78,397 | $ 75,436 |
Average Common Shares Outstanding | 48,450,639 | 48,308,656 | 48,418,368 | 48,275,482 |
Basic Earnings per Average Common Share | $ 0.45 | $ 0.74 | $ 1.62 | $ 1.57 |
Diluted Earnings per Average Common Share | 0.44 | 0.73 | 1.61 | 1.55 |
Dividends Declared per Common Share | $ 0.525 | $ 0.50 | $ 1.05 | $ 1 |
CONDENSED CONSOLIDATED STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Comprehensive Income (Loss) | ||||
Net Income | $ 21,830 | $ 35,569 | $ 78,397 | $ 75,436 |
Other comprehensive income (loss), net of tax: | ||||
Foreign currency translation | (104) | 8 | (53) | (110) |
Reclassification of net losses on derivative instruments | 93 | 37 | 186 | 74 |
Other comprehensive income (loss) | (11) | 45 | 133 | (36) |
Comprehensive Income | $ 21,819 | $ 35,614 | $ 78,530 | $ 75,400 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Current Assets: | ||
Cash and cash equivalents | $ 16,859 | $ 5,079 |
Restricted cash | 5,608 | 4,426 |
Accounts receivable, net | 123,925 | 159,556 |
Inventories | 50,599 | 49,206 |
Regulatory assets | 35,898 | 50,041 |
Other | 15,128 | 11,887 |
Total current assets | 248,017 | 280,195 |
Property, plant, and equipment, net | 4,261,983 | 4,214,892 |
Goodwill | 357,586 | 357,586 |
Regulatory assets | 641,720 | 602,943 |
Other noncurrent assets | 47,626 | 43,705 |
Total Assets | 5,556,932 | 5,499,321 |
Current Liabilities: | ||
Current maturities of capital leases | 2,053 | 1,979 |
Short-term borrowings | 303,658 | 300,811 |
Accounts payable | 55,530 | 79,311 |
Accrued expenses | 200,517 | 205,370 |
Regulatory liabilities | 16,670 | 26,361 |
Total current liabilities | 578,428 | 613,832 |
Long-term capital leases | 23,320 | 24,346 |
Long-term debt | 1,793,797 | 1,793,338 |
Deferred income taxes | 615,510 | 575,582 |
Noncurrent regulatory liabilities | 406,305 | 396,225 |
Other noncurrent liabilities | 430,975 | 419,771 |
Total Liabilities | 3,848,335 | 3,823,094 |
Commitments and Contingencies (Note 12) | ||
Shareholders' Equity: | ||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 52,091,239 and 48,470,756 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | 521 | 520 |
Treasury stock at cost | (96,689) | (95,769) |
Paid-in capital | 1,389,426 | 1,384,271 |
Retained earnings | 424,920 | 396,919 |
Accumulated other comprehensive loss | (9,581) | (9,714) |
Total Shareholders' Equity | 1,708,597 | 1,676,227 |
Total Liabilities and Shareholders' Equity | $ 5,556,932 | $ 5,499,321 |
CONDENSED CONSOLIDATED BALANCE5
CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL | Jun. 30, 2017$ / sharesshares |
Common Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 |
Common Stock, Shares Authorized | 200,000,000 |
Common Stock, Shares, Issued | 52,091,239 |
Common Stock, Shares, Outstanding | 48,470,756 |
Preferred Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 |
Preferred Stock, Shares Authorized | 50,000,000 |
Preferred Stock, Shares Issued | 0 |
Preferred Stock, Shares Outstanding | 0 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
OPERATING ACTIVITIES: | ||
Net Income | $ 78,397 | $ 75,436 |
Items not affecting cash: | ||
Depreciation and depletion | 82,956 | 79,788 |
Amortization of debt issue costs, discount and deferred hedge gain | 2,392 | 1,987 |
Stock-based compensation costs | 3,826 | 3,361 |
Equity portion of allowance for funds used during construction | (2,298) | (1,608) |
(Gain) loss on disposition of assets | (401) | 1,054 |
Deferred income taxes | 6,320 | 3,722 |
Changes in current assets and liabilities: | ||
Restricted cash | (1,182) | 46 |
Accounts receivable | 35,631 | 38,577 |
Inventories | (1,393) | 3,535 |
Other current assets | (3,241) | (7,365) |
Accounts payable | (19,788) | (17,595) |
Accrued expenses | (4,853) | 786 |
Regulatory assets | 14,143 | 10,865 |
Regulatory liabilities | (9,691) | (55,614) |
Other noncurrent assets | (6,781) | (3,099) |
Other noncurrent liabilities | 3,767 | 7,118 |
Cash Provided by Operating Activities | 177,804 | 140,994 |
INVESTING ACTIVITIES: | ||
Property, plant, and equipment additions | (119,123) | (121,246) |
Proceeds from sale of assets | 379 | 137 |
Cash Used in Investing Activities | (118,744) | (121,109) |
FINANCING ACTIVITIES: | ||
Treasury stock activity | 411 | (1,614) |
Dividends on common stock | (50,396) | (47,865) |
Issuance of long-term debt | 0 | 60,000 |
Repayments on long-term debt | 0 | (55,000) |
Issuances of short-term borrowings, net | 2,847 | 26,932 |
Financing costs | (142) | (5,349) |
Cash Used in Financing Activities | (47,280) | (22,896) |
Increase (Decrease) in Cash and Cash Equivalents | 11,780 | (3,011) |
Cash and Cash Equivalents, beginning of period | 5,079 | 11,980 |
Cash and Cash Equivalents, end of period | 16,859 | 8,969 |
Cash paid (received) during the period for: | ||
Income taxes | 61 | (2,922) |
Interest | 40,280 | 42,861 |
Significant non-cash transactions: | ||
Capital expenditures included in accounts payable | $ 9,776 | $ 11,054 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Statement - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Treasury Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] |
Balance, shares at Dec. 31, 2015 | 51,789 | 3,617 | ||||
Balance, beginning of period at Dec. 31, 2015 | $ 1,600,174 | $ 518 | $ 1,376,291 | $ (93,948) | $ 325,909 | $ (8,596) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 75,436 | 0 | 0 | 0 | 75,436 | 0 |
Foreign currency translation adjustment | (110) | 0 | 0 | 0 | 0 | (110) |
Reclassification of net losses on derivative instruments from OCI to net income, net of tax | 74 | $ 0 | 0 | $ 0 | 0 | 74 |
Stock based compensation, shares | 167 | 28 | ||||
Stock based compensation, value | 1,748 | $ 0 | 4,065 | $ (2,317) | 0 | 0 |
Issuance of shares | 0 | |||||
Issuance of shares, value | $ 2 | 0 | 0 | |||
Adjustments to additional paid in capital, stock issued, issuance costs | (11) | |||||
Stock issued, value, net of fees | (9) | |||||
Issuance of shares, treasury stock | 0 | |||||
Issuance of shares, treasury stock, value | $ 0 | |||||
Dividends on common stock | $ (47,865) | 0 | 0 | 0 | (47,865) | 0 |
Dividends per share | $ 1 | |||||
Balance, end of period at Jun. 30, 2016 | $ 1,632,051 | $ 520 | 1,380,345 | $ (96,265) | 356,083 | (8,632) |
Balance, shares at Jun. 30, 2016 | 51,956 | 3,645 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Cumulative-effect adjustment to retained earnings | 2,603 | $ 0 | 0 | $ 0 | 2,603 | 0 |
Balance, shares at Dec. 31, 2016 | 51,958 | 3,626 | ||||
Balance, beginning of period at Dec. 31, 2016 | 1,676,227 | $ 520 | 1,384,271 | $ (95,769) | 396,919 | (9,714) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 78,397 | 0 | 0 | 0 | 78,397 | 0 |
Foreign currency translation adjustment | (53) | 0 | 0 | 0 | 0 | (53) |
Reclassification of net losses on derivative instruments from OCI to net income, net of tax | 186 | $ 0 | 0 | $ 0 | 0 | 186 |
Stock based compensation, shares | 133 | (6) | ||||
Stock based compensation, value | 4,236 | $ 1 | 5,155 | $ (920) | 0 | 0 |
Dividends on common stock | $ (50,396) | 0 | 0 | 0 | (50,396) | 0 |
Dividends per share | $ 1.05 | |||||
Balance, end of period at Jun. 30, 2017 | $ 1,708,597 | $ 521 | $ 1,389,426 | $ (96,689) | $ 424,920 | $ (9,581) |
Balance, shares at Jun. 30, 2017 | 52,091 | 3,620 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] | 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. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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 unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to June 30, 2017 , have been evaluated as to their potential impact to the Financial Statements through the date of issuance. The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2016 . 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 qualifying co-generation facilities and qualifying small power production facilities (QF). We identified one QF contract that may constitute a VIE. We entered into a 40-year power purchase contract in 1984 with this 35 Megawatt (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 Megawatt Hour (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 $233.1 million through 2024 . |
New Accounting Standards
New Accounting Standards | 6 Months Ended |
Jun. 30, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements [Text Block] | New Accounting Standards Accounting Standards Adopted Stock Compensation - During the fourth quarter of 2016, we early adopted the provisions of 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. As a result of this adoption, 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 and a $ 0.04 increase in our earnings per share in the Condensed Consolidated Statement of Income. In addition, we recorded a cumulative-effect adjustment to retained earnings as of the date of adoption of $2.6 million in the Condensed Consolidated Balance Sheets. The guidance also requires that in future filings that include the previously issued interim financial information, the interim financial information is presented on a recast basis to reflect the adoption of ASU 2016-09 as of January 1, 2016. The Condensed Consolidated Financial Statements for the six months ended June 30, 2016, have been recast to reflect this adoption, resulting in an increase in net income and earnings per share. Accounting Standards Issued Revenue Recognition - 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. We expect to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, if applicable, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. Our revenues are primarily from tariff based sales, which are in the scope of the guidance. We provide gas and/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. In our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the guidance on our ability to recognize revenue for certain contracts where collectability is uncertain. The final resolution of these issues and completion of our assessment could impact our current accounting policies and revenue recognition. Retirement Benefits - In March 2017, the FASB issued new guidance on the presentation of net periodic costs related to benefit plans. The new guidance requires the service cost component of net periodic benefit cost to be included within operating income within the same line as other compensation expenses. All other components of net periodic costs must be outside of operating income. In addition, the updated guidance permits only the service cost component of net periodic costs to be capitalized to inventory or property, plant and equipment. This represents a change from current accounting and financial reporting, with presentation of the aggregate net periodic benefit costs on the income statement within operating income, and which permits all components of net periodic costs to be capitalized. This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be applied retrospectively for the presentation of the various components of net periodic costs and prospectively for the change in eligible costs to be capitalized. We have not yet fully determined the impacts of adoption of the standard, but expect that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment. Leases - 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 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. Statement of Cash Flows - 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. |
Regulatory Matters
Regulatory Matters | 6 Months Ended |
Jun. 30, 2017 | |
Regulated Operations [Abstract] | |
Public Utilities Disclosure [Text Block] | Regulatory Matters Montana Natural Gas General Rate Filing In June 2017, we reached a settlement agreement with intervenors in our natural gas rate case. This settlement included an overall increase in delivery services and production charges of approximately $5.7 million , based upon a 6.96 percent rate of return ( 9.55 percent return on equity, 4.67 percent cost of debt and 53.2 percent debt to rate base). In our initial filing in September 2016, we requested an annual increase to natural gas rates of approximately $10.9 million , with rebuttal testimony filed in April 2017 supporting a revised requested annual increase to rates of approximately $9.4 million . The natural gas production part of this filing includes a request for cost-recovery and permanent inclusion in base rates of fields acquired in August 2012 and December 2013 in northern Montana's Bear Paw Basin. Actual production costs are currently recovered in customer rates on an interim basis through our supply tracker. The MPSC held a work session on July 20, 2017, and voted to draft an order accepting the settlement with modifications. We estimate that these modifications lower the increase in delivery services and production charges to approximately $5.1 million . Due to the MPSC's modification of the settlement, any of the parties may elect to withdraw and request a new hearing. We will evaluate the impact of these modifications upon receipt of a final order, which we expect in August 2017. QF Decision Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. The MPSC held a work session in June 2017 to discuss our application for approval of a revised tariff for standard rates for small QFs. In July 2017, the MPSC issued an order establishing a maximum 10-year contract length with a rate adjustment after the first five years, and approving rates that do not include costs associated with the risk of future carbon dioxide emissions regulations. We expect this will result in substantially lower rates for these contracts. In this same order, the MPSC indicated they will apply the 10-year contract term to us for future electric supply resource transactions. We have significant generation capacity deficits and negative reserve margins. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. Our 2016 resource plan identified price and reliability risks to our customers of solely relying upon market purchases to address these needs. We are evaluating the impact of this decision and have suspended our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. Montana House Bill 193 / Electric and Natural Gas Tracker Filings House Bill 193 - In April 2017, the Montana legislature passed House Bill 193 (HB 193), repealing the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. In May 2017, the MPSC issued a Notice of Commission Action (NCA) initiating a process to develop a replacement electric tracker mechanism. We filed a motion for reconsideration of the May 2017 NCA. On July 7, 2017, the MPSC issued an additional NCA addressing the arguments in our motion for reconsideration and identifying three replacement mechanism alternatives for consideration. Two of the replacement mechanism alternatives identified include updating the fixed rate portion of the recovery of our electric supply assets in addition to the variable costs that were recovered through the prior electric tracker. This would be accomplished through an electric supply revenue requirements filing to be made by us by September 30, 2017. The July 2017 NCA also raises questions regarding our earnings as compared with our authorized rate of return for 2016 for electric supply. As noted below in the hydro compliance filing discussion, our 2016 MPSC annual report indicates we earned less than our authorized rate of return with electric delivery service and supply combined. The NCA established a timeline for the parties to provide comments in July 2017, on the issue of whether the MPSC should require a September 2017 filing, and we are awaiting a further decision. On July 14, 2017, we filed a proposed electric Power Cost and Credit Adjustment Mechanism (PCCAM) with the MPSC. We believe the PCCAM filing is consistent with the MPSC's advocacy for HB 193, the MPSC's May and July 2017 NCAs, and the Montana-Dakota Utilities (MDU) Montana adjustment mechanism that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. We expect application of the new mechanism to variable costs to be retroactive to the effective date of HB 193. Electric Tracker Open Dockets - 2015/2016 - 2016/2017 - Under the previous statutory tracker mechanism, each year we submitted an electric 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, which were subject to a prudency review. In June 2017, the MPSC consolidated the dockets for the 2015/2016 and 2016/2017 tracker periods, which are approved on an interim basis. The MPSC has not established a schedule regarding these remaining open dockets under the prior statutory tracker. Natural Gas Tracker - 2016/2017 - In May 2017, we filed our annual natural gas tracker filing for the 2016/2017 tracker period, which the MPSC approved on an interim basis. HB 193 does not impact our natural gas recovery mechanism. Electric Tracker Litigation - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - In 2016, we received final electric tracker orders from the MPSC in the Consolidated Docket and 2015 Tracker, resulting in a $12.4 million disallowance of costs, including interest. In June 2016, we filed an appeal in Montana District Court (Lewis & Clark County) of the MPSC decision in our 2015 Tracker docket to disallow certain portfolio modeling costs. Also, in September 2016, we appealed the MPSC’s decisions in the Consolidated Docket regarding the disallowance of replacement power costs from a 2013 outage at Colstrip Unit 4 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). In the Consolidated Docket appeal, we abandoned our appeal of the modeling costs (approximately $0.3 million ) reserving the issue for our 2015 Tracker appeal. The briefing in the Consolidated Docket appeal concluded in May 2017, and we expect a decision within the next 12 months. We expect a decision in the 2015 Tracker appeal in the next 12 to 18 months. Hydro Compliance Filing In December 2015, we submitted the required compliance filing associated with our 2014 purchase of Montana hydroelectric (hydro) generation assets, to remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts. In December 2016, the MPSC issued a final order in this filing reducing the annual amount we are allowed to recover in hydro generation rates by approximately $1.2 million . In addition, in the final order, the MPSC included language requiring us to indicate by April 30, 2017, whether we intend to file a Montana electric rate case based on a 2016 test year. On April 26, 2017, we filed our required annual report with the MPSC regarding 2016 results, which indicates we earned less than our authorized rate of return. At the same time, we also submitted a filing to the MPSC responsive to the hydro compliance order, indicating we do not expect to file an electric rate case in 2017 based on a 2016 test year. However, we indicated we expect to file a general electric rate case in 2018 based on a 2017 test year. In the hydro compliance order, the MPSC indicated that if we do not intend to file a rate case in 2017, the MPSC may require us to make an additional financial filing that would facilitate an assessment of whether the MPSC believes 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 (D.C. Circuit). The matter is fully briefed, and we are waiting for the Court to set a date for oral argument. We do not expect a decision in this matter until the fourth quarter of 2017, at the earliest. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | Income Taxes We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. 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. The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended June 30, 2017 2016 Income Before Income Taxes $ 22,410 $ 38,516 Income tax calculated at 35% federal statutory rate 7,844 35.0 % 13,481 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (492 ) (2.2 ) (1,025 ) (2.7 ) Flow-through repairs deductions (4,753 ) (21.2 ) (6,971 ) (18.1 ) Production tax credits (1,459 ) (6.5 ) (2,324 ) (6.0 ) Plant and depreciation of flow through items (686 ) (3.1 ) (246 ) (0.6 ) Prior year permanent return to accrual adjustments — — (128 ) (0.3 ) Other, net 126 0.6 160 0.4 (7,264 ) (32.4 ) (10,534 ) (27.3 ) Income Tax Expense $ 580 2.6 % $ 2,947 7.7 % Six Months Ended June 30, 2017 2016 Income Before Income Taxes $ 85,654 $ 79,042 Income tax calculated at 35% federal statutory rate 29,979 35.0 % 27,665 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (1) (1,326 ) (1.5 ) (2,292 ) (2.9 ) Flow-through repairs deductions (13,550 ) (15.8 ) (13,645 ) (17.3 ) Production tax credits (5,290 ) (6.2 ) (5,099 ) (6.5 ) Plant and depreciation of flow through items (2,126 ) (2.5 ) (1,184 ) (1.5 ) Share-based compensation (1) (399 ) (0.5 ) (1,646 ) (2.1 ) Prior year permanent return to accrual adjustments — — (128 ) (0.1 ) Other, net (31 ) — (65 ) — (22,722 ) (26.5 ) (24,059 ) (30.4 ) Income Tax Expense $ 7,257 8.5 % $ 3,606 4.6 % (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 impact of this adoption is reflected as of January 1, 2016, and included in the state income, net of federal provisions, and share-based compensation lines, resulting in a reduction in tax expense for the six months ended June 30, 2016. 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. We have unrecognized tax benefits of approximately $84.4 million as of June 30, 2017 , including approximately $66.7 million that, if recognized, would impact our 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 six months ended June 30, 2017 we recognized $0.3 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2016 , we recognized $0.3 million of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of June 30, 2017 and December 31, 2016 , we had $1.0 million and $0.7 million , respectively, of interest accrued in the Condensed Consolidated Balance Sheets. Our federal tax returns from 2000 forward remain subject to examination by the Internal Revenue Service. |
Goodwill
Goodwill | 6 Months Ended |
Jun. 30, 2017 | |
Goodwill [Abstract] | |
Goodwill Disclosure [Text Block] | Goodwill We completed our annual goodwill impairment test as of April 1, 2017, 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. There were no changes in our goodwill during the six months ended June 30, 2017 . Goodwill by segment is as follows for both June 30, 2017 and December 31, 2016 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586 |
Comprehensive Income (Loss)
Comprehensive Income (Loss) | 6 Months Ended |
Jun. 30, 2017 | |
Statement of Comprehensive Income [Abstract] | |
Comprehensive Income (Loss) Note [Text Block] | Comprehensive Income (Loss) The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): Three Months Ended June 30, 2017 June 30, 2016 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ (104 ) $ — $ (104 ) $ 8 $ — $ 8 Reclassification of net losses on derivative instruments 153 (60 ) 93 62 (25 ) 37 Other comprehensive income (loss) $ 49 $ (60 ) $ (11 ) $ 70 $ (25 ) $ 45 Six Months Ended June 30, 2017 June 30, 2016 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ (53 ) $ — $ (53 ) $ (110 ) $ — $ (110 ) Reclassification of net losses on derivative instruments 306 (120 ) 186 124 (50 ) 74 Other comprehensive income (loss) $ 253 $ (120 ) $ 133 $ 14 $ (50 ) $ (36 ) Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): June 30, 2017 December 31, 2016 Foreign currency translation $ 1,327 $ 1,380 Derivative instruments designated as cash flow hedges (10,166 ) (10,352 ) Postretirement medical plans (742 ) (742 ) Accumulated other comprehensive loss $ (9,581 ) $ (9,714 ) The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended June 30, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,259 ) $ (742 ) $ 1,431 (9,570 ) Other comprehensive loss before reclassifications — — (104 ) (104 ) Amounts reclassified from AOCL Interest Expense 93 — — 93 Net current-period other comprehensive income (loss) 93 — (104 ) (11 ) Ending balance $ (10,166 ) $ (742 ) $ 1,327 $ (9,581 ) Three Months Ended June 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,977 ) $ (937 ) $ 1,237 (8,677 ) Other comprehensive income before reclassifications — — 8 8 Amounts reclassified from AOCL Interest Expense 37 — — 37 Net current-period other comprehensive income 37 — 8 45 Ending balance $ (8,940 ) $ (937 ) $ 1,245 $ (8,632 ) Six Months Ended June 30, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) (742 ) $ 1,380 (9,714 ) Other comprehensive loss before reclassifications — — (53 ) (53 ) Amounts reclassified from AOCL Interest Expense 186 — — 186 Net current-period other comprehensive income (loss) 186 — (53 ) 133 Ending balance $ (10,166 ) $ (742 ) $ 1,327 $ (9,581 ) Six Months Ended June 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) (937 ) $ 1,355 (8,596 ) Other comprehensive loss before reclassifications — — (110 ) (110 ) Amounts reclassified from AOCL Interest Expense 74 — — 74 Net current-period other comprehensive income (loss) 74 — (110 ) (36 ) Ending balance $ (8,940 ) $ (937 ) $ 1,245 $ (8,632 ) |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 6 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | 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. 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 Financial Statements at June 30, 2017 and December 31, 2016 . 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 Financial Statements (in thousands): Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2017 Interest rate contracts Interest Expense $ 307 A pre-tax loss of approximately $16.8 million is remaining in AOCL as of June 30, 2017 , and we expect to reclassify approximately $0.6 million of 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 | 6 Months Ended |
Jun. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures [Text Block] | 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 7 - 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. 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) June 30, 2017 Restricted cash $ 5,354 $ — $ — $ — $ 5,354 Rabbi trust investments 29,012 — — — 29,012 Total $ 34,366 $ — $ — $ — $ 34,366 December 31, 2016 Restricted cash $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228 Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments 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): June 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt 1,793,797 $ 1,898,482 $ 1,793,338 $ 1,852,052 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. |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2017 | |
Segment Reporting Information [Line Items] | |
Segment Reporting Disclosure [Text Block] | Segment 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 are as follows (in thousands): Three Months Ended June 30, 2017 Electric Gas Other Eliminations Total Operating revenues 233,866 $ 49,993 $ — $ — $ 283,859 Cost of sales 70,146 13,854 — — 84,000 Gross margin 163,720 36,139 — — 199,859 Operating, general and administrative 54,086 20,206 896 — 75,188 Property and other taxes 30,909 8,569 3 — 39,481 Depreciation and depletion 34,105 7,382 8 — 41,495 Operating income (loss) 44,620 (18 ) (907 ) — 43,695 Interest expense (21,064 ) (1,500 ) (844 ) — (23,408 ) Other income 917 489 717 — 2,123 Income tax (expense) benefit (523 ) 817 (874 ) — (580 ) Net income (loss) $ 23,950 $ (212 ) $ (1,908 ) $ — $ 21,830 Total assets $ 4,439,694 $ 1,114,426 $ 2,812 — $ 5,556,932 Capital expenditures $ 55,995 $ 11,609 $ — — $ 67,604 Three Months Ended June 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 248,403 $ 44,717 $ — $ — $ 293,120 Cost of sales 72,165 9,528 — — 81,693 Gross margin 176,238 35,189 — — 211,427 Operating, general and administrative 51,568 20,585 426 — 72,579 Property and other taxes 27,322 7,883 3 — 35,208 Depreciation and depletion 32,544 7,346 8 — 39,898 Operating income (loss) 64,804 (625 ) (437 ) — 63,742 Interest expense (24,119 ) (1,814 ) (488 ) — (26,421 ) Other income 687 271 237 — 1,195 Income tax (expense) benefit (3,331 ) 1,278 (894 ) — (2,947 ) Net income (loss) $ 38,041 $ (890 ) $ (1,582 ) $ — $ 35,569 Total assets $ 4,221,293 $ 1,080,065 $ 6,248 $ — $ 5,307,606 Capital expenditures $ 57,938 $ 11,990 $ — $ — $ 69,928 Six Months Ended June 30, 2017 Electric Gas Other Eliminations Total Operating revenues 500,105 $ 151,066 $ — $ — $ 651,171 Cost of sales 155,531 48,286 — — 203,817 Gross margin 344,574 102,780 — — 447,354 Operating, general and administrative 112,705 41,835 1,610 — 156,150 Property and other taxes 62,070 17,333 6 — 79,409 Depreciation and depletion 68,175 14,765 16 — 82,956 Operating income (loss) 101,624 28,847 (1,632 ) — 128,839 Interest expense (42,101 ) (3,046 ) (1,661 ) — (46,808 ) Other income 1,623 717 1,283 — 3,623 Income tax (expense) benefit (3,410 ) (6,134 ) 2,287 — (7,257 ) Net income $ 57,736 $ 20,384 $ 277 $ — $ 78,397 Total assets $ 4,439,694 $ 1,114,426 $ 2,812 — $ 5,556,932 Capital expenditures $ 97,036 $ 22,087 $ — — $ 119,123 _ Six Months Ended June 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 489,745 $ 135,914 $ — $ — $ 625,659 Cost of sales 155,789 41,338 — — 197,127 Gross margin 333,956 94,576 — — 428,532 Operating, general and administrative 107,011 42,497 2,932 — 152,440 Property and other taxes 54,751 15,872 6 — 70,629 Depreciation and depletion 65,065 14,707 16 — 79,788 Operating income (loss) 107,129 21,500 (2,954 ) — 125,675 Interest expense (46,174 ) (3,769 ) (987 ) — (50,930 ) Other income 1,154 580 2,563 — 4,297 Income tax (expense) benefit (1) (4,346 ) (1,743 ) 2,483 — (3,606 ) Net income (1) $ 57,763 $ 16,568 $ 1,105 $ — $ 75,436 Total assets $ 4,221,293 $ 1,080,065 $ 6,248 $ — $ 5,307,606 Capital expenditures $ 99,563 $ 21,683 $ — $ — $ 121,246 ______________ (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 for the six months ended June 30, 2016 above. |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share [Text Block] | Earnings Per Share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all 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 performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended June 30, 2017 June 30, 2016 Basic computation 48,450,639 48,308,656 Dilutive effect of: Performance share awards (1) 130,772 76,877 Diluted computation 48,581,411 48,385,533 Six Months Ended June 30, 2017 June 30, 2016 Basic computation 48,418,368 48,275,482 Dilutive effect of: Performance share awards (1) 129,383 76,737 Diluted computation 48,547,751 48,352,219 _______ (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 10,090 and 10,116 for the three and six months ended June 30, 2016. |
Employee Benefit Plans
Employee Benefit Plans | 6 Months Ended |
Jun. 30, 2017 | |
Retirement Benefits [Abstract] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Employee Benefit Plans Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 Components of Net Periodic Benefit Cost (Income) Service cost $ 2,367 $ 2,941 $ 100 $ 116 Interest cost 6,388 6,539 178 196 Expected return on plan assets (5,974 ) (7,043 ) (211 ) (260 ) Amortization of prior service cost — 61 (470 ) (470 ) Recognized actuarial loss 1,944 2,478 81 71 Net Periodic Benefit Cost (Income) $ 4,725 $ 4,976 $ (322 ) $ (347 ) Pension Benefits Other Postretirement Benefits Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 Components of Net Periodic Benefit Cost (Income) Service cost $ 5,497 $ 5,880 $ 228 $ 246 Interest cost 12,817 13,105 358 398 Expected return on plan assets (11,982 ) (14,124 ) (424 ) (521 ) Amortization of prior service cost 2 123 (941 ) (941 ) Recognized actuarial loss 3,919 4,944 159 158 Net Periodic Benefit Cost (Income) $ 10,253 $ 9,928 $ (620 ) $ (660 ) |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | Commitments and Contingencies 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 June 30, 2017 , we have a reserve of approximately $30.6 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 $23.8 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 June 30, 2017 , the reserve for remediation costs at this site is approximately $10.4 million , and we estimate that approximately $5.9 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 Notice of Potential Liability and Request for Remedial Action regarding the Helena site. At MDEQ's direction, a soil vapor analysis plan for the two buildings located on the Helena site was submitted in January 2017. MDEQ reviewed the results of the analysis and indicated that work should be postponed until the winter of 2017-2018 to be integrated in an overall remediation plan for the Helena site. We expect to continue soil and groundwater sampling at the Helena site. 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 site. 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. Analytical results from an October 2016 sampling exceeded the Montana Maximum Contaminant Level for benzene and/or total cyanide in certain monitoring wells. These results were forwarded to MVWQD which shared the same with the MDEQ. MDEQ requested that MVWQD file a formal complaint with MDEQ's Enforcement Division, which MVWQD filed in July 2017. This is expected to prompt MDEQ to reevaluate its position concerning listing the Missoula site on the State of Montana's superfund list. New landowners purchased a portion of the Missoula site using funding provided by a third party. The terms of the funding require the new landowners to address environmental issues. The new landowners contacted us and have requested a meeting to address concerns. After researching historical ownership we have identified another potentially responsible party with whom we have initiated communications regarding the site. 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 Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions through regulations. EPA is currently reviewing its existing regulations as a result of an Executive Order issued by President Trump on March 28, 2017 (the Executive Order) instructing all federal agencies to review all regulations and other policies (specifically including the Clean Power Plan , which is discussed in further detail below) that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest. One of the regulations that the EPA was instructed to review under the Executive Order is the final standards of performance issued by EPA on August 3, 2015 which 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. Another regulation that the EPA was instructed to review pursuant to the Executive Order is its final regulation establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d), which was published in October, 2015, and is referred to as the Clean Power Plan (CPP). The CPP establishes CO2 emission performance standards for existing electric utility steam generating units and NGCC units. Under the CPP, states may develop implementation plans for affected units to meet the individual state GHG emission reduction targets established in the CPP or may adopt a federal plan. The CPP may require reductions in CO 2 emissions from 2012 emission levels of up to 38.4 percent in South Dakota and 47.4 percent in Montana by 2030. Neither South Dakota nor Montana has submitted implementation plans to date. Following the issuance of the CPP, judicial appeals were filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), including an appeal by us filed on October 23, 2015. The United States Supreme Court (Supreme Court) issued a stay of the CPP on February 9, 2016 pending resolution of the appeals by the D.C. Circuit and possibly the Supreme Court. Oral argument on the case was held in September 2016. In April 2017, the D.C. Circuit granted the EPA's request to hold the case in abeyance pursuant to the Executive Order, but only for a period of sixty days. In addition, administrative requests for reconsideration of the CPP were filed with the EPA, including one filed by us in December 2015. We requested the EPA reconsider the CPP, in part, on the grounds that the CO 2 reductions in the CPP applicable to Montana were substantially greater than the reductions the EPA had originally proposed. The EPA denied the petition for reconsideration on January 11, 2017, and we appealed that denial to the D.C. Circuit on March 13, 2017. The EPA has also requested that this case be held in abeyance. No action has been taken by the D.C. Circuit in this case. There is no certainty as to what, if any, action the D.C. Circuit may take in either of these two cases before the EPA takes action to address the CPP. If the CPP survives the Executive Order, the legal challenges described above, and is implemented as written, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are not recovered through regulated rates. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the CPP that, in our view, disproportionately impacts customers in our region. 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 CO 2 emission performance standards in the CPP, 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. In addition, future additional 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. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities. 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 United States Court of Appeals for the Second Circuit. 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 United States Court of Appeals for the Fifth Circuit, asserting 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 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 D.C. 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 and the D.C. Circuit recently delayed oral argument in the case at the request of the Trump administration, 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 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. The plan does not require Colstrip Units 3 and 4 to improve removal efficiency for pollutants that contribute to regional haze. In November 2012, PPL Montana (now Talen Montana, LLC) (Talen), 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 United States Court of Appeals for the Ninth Circuit (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 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. On January 10, 2017, the EPA published amendments to the requirements under the Clean Air Act for state plans for protection of visibility. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. Therefore, 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. On March 13, 2017, we filed a Petition for Review of these amendments with the D.C. Circuit. On March 15, 2017, our petition was consolidated with other petitions challenging the final rule. 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 or administrative action by the EPA 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 state implementation plan requires the Coyote generating facility, in which we have 10% ownership, to reduce its nitrogen oxide (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. 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 Billings, Montana Refinery Outage Claim In August 2014, we received a letter from the ExxonMobil refinery in Billings, Montana claiming that it had sustained approximately $48.5 million in damages as a result of a January 2014 electrical outage. In December 2015, ExxonMobil increased the estimated losses related to that incident to approximately $61.7 million . On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil currently claims property damages and economic losses of at least $108.0 million . We dispute ExxonMobil’s claims and intend to vigorously defend this lawsuit. We have reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also have brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they are responsible in whole or in part for the outages. We are not currently able to predict an outcome or estimate the amount or range of loss that would be associated with an adverse result. Pacific Northwest Solar Litigation Pacific Northwest Solar, LLC (PNWS) is an Oregon solar QF developer with which we began negotiating in early 2016 to purchase capacity and energy at our avoided cost under the QF-1 option 1(a) tariff standard rates in accordance with PURPA as implemented by the FERC and the MPSC. On June 16, 2016, however, the MPSC entered a Notice of Commission Action (MPSC Notice) suspending the availability of QF-1 option 1(a) standard rates for solar projects greater than 100 kW, which included the various projects proposed by PNWS. The MPSC exempted from the suspension any contracts with solar QFs greater than 100 kW, but no larger than 3 MW, at the standard tariff rate, if prior to the date of the MPSC Notice, the QF had submitted a signed power purchase agreement and had executed an interconnection agreement. PNWS had not obtained interconnection agreements for any of its projects as of June 16, 2016 and, based on the MPSC Notice and subsequent July 25, 2016 Order 7500 of like effect from the MPSC, we discontinued further negotiations with PNWS. On August 30, 2016, PNWS sent us a letter demanding that we enter into power purchase agreements for 21 solar projects and threatening to sue us for $106 million if we did not accede to its demand. We declined to do so, and on November 16, 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and other relief, including a judicial declaration that some or all of the proposed power purchase agreements were in effect. We removed the state lawsuit to the United States District Court for the District of Montana, which then stayed the case until September 29, 2017, so that the MPSC could consider related issues that might bear on the issues raised in PNWS's lawsuit. On July 19, 2017, we and PNWS entered into a partial settlement agreement that resolved some but not all of PNWS' litigation claims. In return for our support of PNWS' application to the MPSC for approval of its first four solar projects, PNWS agreed to drop its damage claims related to the other 17 projects. If the MPSC approves the four projects, PNWS will also drop its damage claims related to those four projects. If the MPSC does not approve the four projects, PNWS will be able to pursue all of its claims related to those four projects. PNWS can continue to seek (and we can continue to oppose) regulatory approval of the remaining projects, but PNWS will not pursue monetary damage claims related to those projects. We dispute all of the claims that PNWS has made in its lawsuit and intend to vigorously defend those that have not been resolved by the partial settlement. This matter is in the initial stages, and we cannot predict an outcome or estimate the am ount or range of loss that would be associated with an adverse result on the remaining claims. State of Montana - Riverbed Rents On April 1, 2016, the State of Montana filed a complaint on remand with the Montana First Judicial District Court (State District Court), naming us, along with Talen, as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan and Morony facilities on the Missouri-Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014. Prior to our acquisition of the facilities, Talen litigated this issue against the State in State District Court, the Montana Supreme Court and in the United States Supreme Court. In August 2007, the State District Court determined that the 10 hydroelectric facilities were located on rivers which were navigable and that the State held title to the riverbeds. Subsequently, in June 2008, the State District Court awarded the State compensation with respect to all 10 facilities of approximately $34 million for the 2000-2006 period and approximately $6 million for 2007. The District Court deferred the determination of compensation for 2008 and future years to the Montana State Land Board. Talen appealed the issue of navigability to the Montana Supreme Court, which in March 2010 affirmed the State District Court decision. In June 2011, the United States Supreme Court granted Talen's petition to review the Montana Supreme Court decision. The United States Supreme Court issued an opinion in February 2012, overturning the Montana Supreme Court and holding that the Montana courts erred first by not considering the navigability of the rivers on a segment-by-segment basis and second in relying on present day recreational use of the rivers. The United States Supreme Court also considered the navigability of what it referred to as the Great Falls Reach and concluded, at least from the head of the first waterfall to the foot of the last, that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State filed its complaint on remand with the State District Court. The complaint on remand renews all of the State’s claims that the rivers on which the 10 hydroelectric facilities are located are navigable (including the Great Falls Reach), that because they were navigable the riverbeds became State lands upon Montana’s statehood in 1889 and that the State is entitled to rent for their use. The State’s complaint on remand does not claim any specific rental amount. Pursuant to the terms of our acquisition of the hydroelectric facilities, Talen and NorthWestern will share jointly the expense of this litigation, and Talen is responsible for any rents applicable to the periods of time prior to the acquisition (i.e., before November 18, 2014), while we are responsible for periods thereafter. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court), and Talen consented to our removal. On April 27, 2016, we and Talen filed motions with the Federal District Court seeking to dismiss the portion of the litigation dealing with the Great Falls Reach in light of the United States Supreme Court’s decision that the Great Falls Reach was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. On May 19, 2016, the State asked the Federal District Court to remand the case back to the State District Court and to dismiss Talen’s consent to removal. The parties briefed the remand issue and oral argument was held before the Magistrate on January 17, 2017. On January 23, 2017 the Magistrate issued his Findings and Recommendation. The Magistrate recommended the Federal District Court remand the case to State District Court. On February 20, 2017, we filed objections to the Magistrate’s Findings and Recommendation, arguing that the Federal District Court should retain jurisdiction. The following day Talen filed its objections to the Federal Magistrate’s Findings and Recommendation, which we joined in on February 23, 2017. On March 21, 2017, the State filed its response to the objections. On March 24, 2017, in separate motions, both we and Talen filed motions asking the Federal District Court to hear oral argument on our respective objections. On July 10, 2017, the Federal District Court granted the motions for oral argument. Oral argument will be held before the U.S. District Judge on August 16, 2017. Our objections to the Magistrate's Findings and Recommendation along with Talen's and our motions to dismiss the State's claim regarding the Great Falls Reach remain pending. The Federal District Court will not address the motions to dismiss unless it retains jurisdiction. If the case is remanded to State District Court, we will file new motions to dismiss regarding the Great Falls Reach. We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If the Federal District Court (or the State District Court if the case is remanded to it) determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $7.0 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery. Other Legal Proceedings We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows. |
Nature of Operations and Basi20
Nature of Operations and Basis of Consolidation (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Consolidation, Variable Interest Entity [Policy Text Block] | 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 qualifying co-generation facilities and qualifying small power production facilities (QF). We identified one QF contract that may constitute a VIE. We entered into a 40-year power purchase contract in 1984 with this 35 Megawatt (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 Megawatt Hour (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 $233.1 million through 2024 . |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended June 30, 2017 2016 Income Before Income Taxes $ 22,410 $ 38,516 Income tax calculated at 35% federal statutory rate 7,844 35.0 % 13,481 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (492 ) (2.2 ) (1,025 ) (2.7 ) Flow-through repairs deductions (4,753 ) (21.2 ) (6,971 ) (18.1 ) Production tax credits (1,459 ) (6.5 ) (2,324 ) (6.0 ) Plant and depreciation of flow through items (686 ) (3.1 ) (246 ) (0.6 ) Prior year permanent return to accrual adjustments — — (128 ) (0.3 ) Other, net 126 0.6 160 0.4 (7,264 ) (32.4 ) (10,534 ) (27.3 ) Income Tax Expense $ 580 2.6 % $ 2,947 7.7 % Six Months Ended June 30, 2017 2016 Income Before Income Taxes $ 85,654 $ 79,042 Income tax calculated at 35% federal statutory rate 29,979 35.0 % 27,665 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (1) (1,326 ) (1.5 ) (2,292 ) (2.9 ) Flow-through repairs deductions (13,550 ) (15.8 ) (13,645 ) (17.3 ) Production tax credits (5,290 ) (6.2 ) (5,099 ) (6.5 ) Plant and depreciation of flow through items (2,126 ) (2.5 ) (1,184 ) (1.5 ) Share-based compensation (1) (399 ) (0.5 ) (1,646 ) (2.1 ) Prior year permanent return to accrual adjustments — — (128 ) (0.1 ) Other, net (31 ) — (65 ) — (22,722 ) (26.5 ) (24,059 ) (30.4 ) Income Tax Expense $ 7,257 8.5 % $ 3,606 4.6 % (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 impact of this adoption is reflected as of January 1, 2016, and included in the state income, net of federal provisions, and share-based compensation lines, resulting in a reduction in tax expense for the six months ended June 30, 2016. |
Goodwill (Tables)
Goodwill (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Goodwill [Abstract] | |
Schedule of Goodwill [Table Text Block] | Goodwill by segment is as follows for both June 30, 2017 and December 31, 2016 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586 |
Comprehensive Income Loss (Tabl
Comprehensive Income Loss (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
Comprehensive Income (Loss) [Table Text Block] | The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): Three Months Ended June 30, 2017 June 30, 2016 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ (104 ) $ — $ (104 ) $ 8 $ — $ 8 Reclassification of net losses on derivative instruments 153 (60 ) 93 62 (25 ) 37 Other comprehensive income (loss) $ 49 $ (60 ) $ (11 ) $ 70 $ (25 ) $ 45 Six Months Ended June 30, 2017 June 30, 2016 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ (53 ) $ — $ (53 ) $ (110 ) $ — $ (110 ) Reclassification of net losses on derivative instruments 306 (120 ) 186 124 (50 ) 74 Other comprehensive income (loss) $ 253 $ (120 ) $ 133 $ 14 $ (50 ) $ (36 ) |
Accumulated Other Comprehensive
Accumulated Other Comprehensive (Income) Loss (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Statement of Financial Position [Abstract] | |
Accumulated Other Comprehensive Income [Table Text Block] | Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): June 30, 2017 December 31, 2016 Foreign currency translation $ 1,327 $ 1,380 Derivative instruments designated as cash flow hedges (10,166 ) (10,352 ) Postretirement medical plans (742 ) (742 ) Accumulated other comprehensive loss $ (9,581 ) $ (9,714 ) |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended June 30, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,259 ) $ (742 ) $ 1,431 (9,570 ) Other comprehensive loss before reclassifications — — (104 ) (104 ) Amounts reclassified from AOCL Interest Expense 93 — — 93 Net current-period other comprehensive income (loss) 93 — (104 ) (11 ) Ending balance $ (10,166 ) $ (742 ) $ 1,327 $ (9,581 ) Three Months Ended June 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (8,977 ) $ (937 ) $ 1,237 (8,677 ) Other comprehensive income before reclassifications — — 8 8 Amounts reclassified from AOCL Interest Expense 37 — — 37 Net current-period other comprehensive income 37 — 8 45 Ending balance $ (8,940 ) $ (937 ) $ 1,245 $ (8,632 ) Six Months Ended June 30, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) (742 ) $ 1,380 (9,714 ) Other comprehensive loss before reclassifications — — (53 ) (53 ) Amounts reclassified from AOCL Interest Expense 186 — — 186 Net current-period other comprehensive income (loss) 186 — (53 ) 133 Ending balance $ (10,166 ) $ (742 ) $ 1,327 $ (9,581 ) Six Months Ended June 30, 2016 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) (937 ) $ 1,355 (8,596 ) Other comprehensive loss before reclassifications — — (110 ) (110 ) Amounts reclassified from AOCL Interest Expense 74 — — 74 Net current-period other comprehensive income (loss) 74 — (110 ) (36 ) Ending balance $ (8,940 ) $ (937 ) $ 1,245 $ (8,632 ) |
Risk Management and Hedging A25
Risk Management and Hedging Activities (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands): Location of amount reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Six Months Ended June 30, 2017 Interest rate contracts Interest Expense $ 307 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | 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 7 - 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. 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) June 30, 2017 Restricted cash $ 5,354 $ — $ — $ — $ 5,354 Rabbi trust investments 29,012 — — — 29,012 Total $ 34,366 $ — $ — $ — $ 34,366 December 31, 2016 Restricted cash $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228 |
Fair Value Financial Instruments [Table Text Block] | The estimated fair value of financial instruments is summarized as follows (in thousands): June 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt 1,793,797 $ 1,898,482 $ 1,793,338 $ 1,852,052 |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Financial data for the business segments are as follows (in thousands): Three Months Ended June 30, 2017 Electric Gas Other Eliminations Total Operating revenues 233,866 $ 49,993 $ — $ — $ 283,859 Cost of sales 70,146 13,854 — — 84,000 Gross margin 163,720 36,139 — — 199,859 Operating, general and administrative 54,086 20,206 896 — 75,188 Property and other taxes 30,909 8,569 3 — 39,481 Depreciation and depletion 34,105 7,382 8 — 41,495 Operating income (loss) 44,620 (18 ) (907 ) — 43,695 Interest expense (21,064 ) (1,500 ) (844 ) — (23,408 ) Other income 917 489 717 — 2,123 Income tax (expense) benefit (523 ) 817 (874 ) — (580 ) Net income (loss) $ 23,950 $ (212 ) $ (1,908 ) $ — $ 21,830 Total assets $ 4,439,694 $ 1,114,426 $ 2,812 — $ 5,556,932 Capital expenditures $ 55,995 $ 11,609 $ — — $ 67,604 Three Months Ended June 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 248,403 $ 44,717 $ — $ — $ 293,120 Cost of sales 72,165 9,528 — — 81,693 Gross margin 176,238 35,189 — — 211,427 Operating, general and administrative 51,568 20,585 426 — 72,579 Property and other taxes 27,322 7,883 3 — 35,208 Depreciation and depletion 32,544 7,346 8 — 39,898 Operating income (loss) 64,804 (625 ) (437 ) — 63,742 Interest expense (24,119 ) (1,814 ) (488 ) — (26,421 ) Other income 687 271 237 — 1,195 Income tax (expense) benefit (3,331 ) 1,278 (894 ) — (2,947 ) Net income (loss) $ 38,041 $ (890 ) $ (1,582 ) $ — $ 35,569 Total assets $ 4,221,293 $ 1,080,065 $ 6,248 $ — $ 5,307,606 Capital expenditures $ 57,938 $ 11,990 $ — $ — $ 69,928 Six Months Ended June 30, 2017 Electric Gas Other Eliminations Total Operating revenues 500,105 $ 151,066 $ — $ — $ 651,171 Cost of sales 155,531 48,286 — — 203,817 Gross margin 344,574 102,780 — — 447,354 Operating, general and administrative 112,705 41,835 1,610 — 156,150 Property and other taxes 62,070 17,333 6 — 79,409 Depreciation and depletion 68,175 14,765 16 — 82,956 Operating income (loss) 101,624 28,847 (1,632 ) — 128,839 Interest expense (42,101 ) (3,046 ) (1,661 ) — (46,808 ) Other income 1,623 717 1,283 — 3,623 Income tax (expense) benefit (3,410 ) (6,134 ) 2,287 — (7,257 ) Net income $ 57,736 $ 20,384 $ 277 $ — $ 78,397 Total assets $ 4,439,694 $ 1,114,426 $ 2,812 — $ 5,556,932 Capital expenditures $ 97,036 $ 22,087 $ — — $ 119,123 _ Six Months Ended June 30, 2016 Electric Gas Other Eliminations Total Operating revenues $ 489,745 $ 135,914 $ — $ — $ 625,659 Cost of sales 155,789 41,338 — — 197,127 Gross margin 333,956 94,576 — — 428,532 Operating, general and administrative 107,011 42,497 2,932 — 152,440 Property and other taxes 54,751 15,872 6 — 70,629 Depreciation and depletion 65,065 14,707 16 — 79,788 Operating income (loss) 107,129 21,500 (2,954 ) — 125,675 Interest expense (46,174 ) (3,769 ) (987 ) — (50,930 ) Other income 1,154 580 2,563 — 4,297 Income tax (expense) benefit (1) (4,346 ) (1,743 ) 2,483 — (3,606 ) Net income (1) $ 57,763 $ 16,568 $ 1,105 $ — $ 75,436 Total assets $ 4,221,293 $ 1,080,065 $ 6,248 $ — $ 5,307,606 Capital expenditures $ 99,563 $ 21,683 $ — $ — $ 121,246 ______________ (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 for the six months ended June 30, 2016 above. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Weighted Average Number of Shares [Table Text Block] | Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended June 30, 2017 June 30, 2016 Basic computation 48,450,639 48,308,656 Dilutive effect of: Performance share awards (1) 130,772 76,877 Diluted computation 48,581,411 48,385,533 Six Months Ended June 30, 2017 June 30, 2016 Basic computation 48,418,368 48,275,482 Dilutive effect of: Performance share awards (1) 129,383 76,737 Diluted computation 48,547,751 48,352,219 _______ (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. |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Retirement Benefits [Abstract] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 Components of Net Periodic Benefit Cost (Income) Service cost $ 2,367 $ 2,941 $ 100 $ 116 Interest cost 6,388 6,539 178 196 Expected return on plan assets (5,974 ) (7,043 ) (211 ) (260 ) Amortization of prior service cost — 61 (470 ) (470 ) Recognized actuarial loss 1,944 2,478 81 71 Net Periodic Benefit Cost (Income) $ 4,725 $ 4,976 $ (322 ) $ (347 ) Pension Benefits Other Postretirement Benefits Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 Components of Net Periodic Benefit Cost (Income) Service cost $ 5,497 $ 5,880 $ 228 $ 246 Interest cost 12,817 13,105 358 398 Expected return on plan assets (11,982 ) (14,124 ) (424 ) (521 ) Amortization of prior service cost 2 123 (941 ) (941 ) Recognized actuarial loss 3,919 4,944 159 158 Net Periodic Benefit Cost (Income) $ 10,253 $ 9,928 $ (620 ) $ (660 ) |
Nature of Operations and Basi30
Nature of Operations and Basis of Consolidation (Details) $ in Millions | Jun. 30, 2017USD ($)watts | Dec. 31, 2016customers |
Number of customers | customers | 709,600 | |
Number of megawatts of qualifying facility | watts | 35 | |
Estimated aggregate gross contractual payments for qualifying facilities through 2024 | $ | $ 233.1 |
New Accounting Standards Accoun
New Accounting Standards Accounting Standards Adopted (Details) $ / shares in Units, $ in Thousands | 6 Months Ended |
Jun. 30, 2016USD ($)$ / shares | |
New Accounting Pronouncement, Early Adoption [Line Items] | |
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 1,800 |
Change on basic earnings per share from early adoption of new accounting pronouncement | $ / shares | $ 0.04 |
Cumulative-effect adjustment to retained earnings | $ 2,603 |
Retained Earnings [Member] | |
New Accounting Pronouncement, Early Adoption [Line Items] | |
Cumulative-effect adjustment to retained earnings | $ 2,603 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Jun. 30, 2017 | Dec. 31, 2016 | |
Public Utilities, General Disclosures [Line Items] | |||||||
Recoverable percentage of energy costs | 90.00% | ||||||
Montana Natural Gas Rate Filing [Member] | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Requested rate increase | $ 9.4 | $ 10.9 | $ 5.7 | ||||
Approved rate of return | 6.96% | ||||||
Approved return on equity, percentage | 9.55% | ||||||
Approved cost of debt | 4.67% | ||||||
Approved debt capital structure, percentage | 53.20% | ||||||
Hydro Transaction [Member] | Revenue Subject to Refund [Member] | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved rate increase, amount | $ 1.2 | ||||||
Dave Gates Generating Station [Member] | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Deferred revenue, refund payments | $ 27.3 | ||||||
Disallowed Expenses [Member] | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Disallowed electric tracker costs | $ 12.4 | ||||||
Disallowed modeling costs | $ 0.3 | ||||||
Subsequent Event [Member] | Montana Natural Gas Rate Filing [Member] | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved rate increase, amount | $ 5.1 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Income Tax Contingency [Line Items] | |||
Employee service share-based compensation, recognition of excess tax benefits | $ 1.8 | ||
Unrecognized tax benefit more likely than not percentage threshold | 50.00% | ||
Unrecognized tax benefits | $ 84.4 | ||
Unrecognized tax benefits that would impact effective tax rate | 66.7 | ||
Interest expense or penalties, uncertain tax positions | 0.3 | $ 0.3 | |
Accrued interest, uncertain tax positions | $ 1 | $ 0.7 | |
Internal Revenue Service (IRS) [Member] | |||
Income Tax Contingency [Line Items] | |||
Earliest year subject to examination | 2,000 |
Income Taxes Effective Tax Rate
Income Taxes Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Effective tax rate reconciliation | ||||
Income Before Income Taxes | $ 22,410 | $ 38,516 | $ 85,654 | $ 79,042 |
Income tax calculated at 35% federal statutory rate | $ 7,844 | $ 13,481 | $ 29,979 | $ 27,665 |
Income tax calculated at 35% federal statutory rate | 35.00% | 35.00% | 35.00% | 35.00% |
State income, net of federal provisions | $ (492) | $ (1,025) | $ (1,326) | $ (2,292) |
State income, net of federal provisions | (2.20%) | (2.70%) | (1.50%) | (2.90%) |
Flow-through repairs deductions | $ (4,753) | $ (6,971) | $ (13,550) | $ (13,645) |
Flow-through repairs deductions | (21.20%) | (18.10%) | (15.80%) | (17.30%) |
Production tax credits | $ (1,459) | $ (2,324) | $ (5,290) | $ (5,099) |
Production tax credits | (6.50%) | (6.00%) | (6.20%) | (6.50%) |
Plant and depreciation of flow through items | $ (686) | $ (246) | $ (2,126) | $ (1,184) |
Plant and depreciation of flow through items | (3.10%) | (0.60%) | (2.50%) | (1.50%) |
Share-based compensation (1) | $ (399) | $ (1,646) | ||
Share-based compensation (1) | (0.50%) | (2.10%) | ||
Prior year permanent return to accrual adjustments | $ 0 | $ (128) | $ 0 | $ (128) |
Prior year permanent return to accrual adjustments | (0.00%) | (0.30%) | (0.00%) | (0.10%) |
Other, net | $ 126 | $ 160 | $ (31) | $ (65) |
Other, net | 0.60% | 0.40% | 0.00% | 0.00% |
Total Other Reconciling Items | $ (7,264) | $ (10,534) | $ (22,722) | $ (24,059) |
Total Other Reconciling Items | (32.40%) | (27.30%) | (26.50%) | (30.40%) |
Income Tax Expense | $ 580 | $ 2,947 | $ 7,257 | $ 3,606 |
Income Tax Expense | 2.60% | 7.70% | 8.50% | 4.60% |
Internal Revenue Service (IRS) [Member] | ||||
Effective tax rate reconciliation | ||||
Income tax calculated at 35% federal statutory rate | 35.00% |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Goodwill [Line Items] | ||
Change in goodwill | $ 0 | |
Goodwill | 357,586 | $ 357,586 |
Electric [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 243,558 | 243,558 |
Natural gas [Member] | ||
Goodwill [Line Items] | ||
Goodwill | $ 114,028 | $ 114,028 |
Comprehensive Income (Loss) (De
Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Other Comprehensive Income (Loss), before Tax [Abstract] | ||||
Foreign currency translation adjustment | $ (104) | $ 8 | $ (53) | $ (110) |
Reclassification of net losses on derivative instruments | 153 | 62 | 306 | 124 |
Other comprehensive income (loss) | 49 | 70 | 253 | 14 |
Other Comprehensive Income (Loss), Tax [Abstract] | ||||
Foreign currency translation adjustment | 0 | 0 | 0 | 0 |
Reclassification of net losses on derivative instruments | (60) | (25) | (120) | (50) |
Other comprehensive income (loss) | (60) | (25) | (120) | (50) |
Other comprehensive income (loss), net of tax: | ||||
Foreign currency translation adjustment | (104) | 8 | (53) | (110) |
Reclassification of net losses on derivative instruments | 93 | 37 | 186 | 74 |
Other comprehensive income (loss) | $ (11) | $ 45 | $ 133 | $ (36) |
Balance sheet classification (D
Balance sheet classification (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Foreign currency translation | $ 1,327 | $ 1,380 |
Derivative instruments designated as cash flow hedges | (10,166) | (10,352) |
Postretirement medical plans | (742) | (742) |
Accumulated other comprehensive loss | $ (9,581) | $ (9,714) |
Changes in AOCI by Component (D
Changes in AOCI by Component (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | $ (9,714) | |||
Other comprehensive income (loss) | $ (11) | $ 45 | 133 | $ (36) |
Ending balance | (9,581) | (9,581) | ||
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (10,259) | (8,977) | (10,352) | (9,014) |
Other comprehensive loss before reclassifications | 0 | 0 | 0 | 0 |
Amounts reclassified from AOCL | 93 | 37 | 186 | 74 |
Other comprehensive income (loss) | 93 | 37 | 186 | 74 |
Ending balance | (10,166) | (8,940) | (10,166) | (8,940) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (742) | (937) | (742) | (937) |
Other comprehensive loss before reclassifications | 0 | 0 | 0 | 0 |
Amounts reclassified from AOCL | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | 0 | 0 | 0 | 0 |
Ending balance | (742) | (937) | (742) | (937) |
Accumulated Foreign Currency Adjustment Attributable to Parent [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | 1,431 | 1,237 | 1,380 | 1,355 |
Other comprehensive loss before reclassifications | (104) | 8 | (53) | (110) |
Amounts reclassified from AOCL | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | (104) | 8 | (53) | (110) |
Ending balance | 1,327 | 1,245 | 1,327 | 1,245 |
Comprehensive Income (Loss) [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Beginning balance | (9,570) | (8,677) | (9,714) | (8,596) |
Other comprehensive loss before reclassifications | (104) | 8 | (53) | (110) |
Amounts reclassified from AOCL | 93 | 37 | 186 | 74 |
Other comprehensive income (loss) | (11) | 45 | 133 | (36) |
Ending balance | $ (9,581) | $ (8,632) | $ (9,581) | $ (8,632) |
Risk Management and Hedging A39
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Derivative [Line Items] | ||
Pre-tax loss on cash flow hedges remaining in AOCL | $ 16,800 | |
Pre-tax loss on cash flow hedge to be reclassified within twelve months from AOCL to interest expense | 600 | |
Physical purchase and sale of gas and electricity at fixed prices | $ 0 | $ 0 |
Number of interest rate swaps outstanding | 0 | |
Interest Expense [Member] | ||
Derivative [Line Items] | ||
Amount of gain reclassified from AOCL | $ 307 |
Fair Value Recurring Basis (Det
Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2017 | Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Fair value, assets, level 1 to level 2 transfers, amount | $ 0 | $ 0 |
Fair value, assets, level 2 to level 1 transfers, amount | 0 | 0 |
Fair value, liabilities, level 1 to level 2 transfers, amount | 0 | 0 |
Fair value, liabilities, level 2 to level 1 transfers, amount | 0 | 0 |
Fair Value, transfers into (out of) level 3 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 5,354 | 4,164 |
Rabbi trust investments | 29,012 | 25,064 |
Total | 34,366 | 29,228 |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs(Level 2) | ||
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) | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 0 | 0 |
Rabbi trust investments | 0 | 0 |
Total | 0 | 0 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 5,354 | 4,164 |
Rabbi trust investments | 29,012 | 25,064 |
Total | 34,366 | 29,228 |
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 Va
Fair Value Measurements Fair Value Finanical Insruments (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Dec. 31, 2016 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying amount | $ 1,793,797 | $ 1,793,338 |
Long-term debt, fair value | $ 1,898,482 | $ 1,852,052 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||||
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense | $ 1,800 | ||||
Operating revenues | $ 283,859 | $ 293,120 | $ 651,171 | 625,659 | |
Cost of sales | 84,000 | 81,693 | 203,817 | 197,127 | |
Gross margin | 199,859 | 211,427 | 447,354 | 428,532 | |
Operating, general and administrative | 75,188 | 72,579 | 156,150 | 152,440 | |
Property and other taxes | 39,481 | 35,208 | 79,409 | 70,629 | |
Depreciation and depletion | 41,495 | 39,898 | 82,956 | 79,788 | |
Operating income (loss) | 43,695 | 63,742 | 128,839 | 125,675 | |
Interest expense | (23,408) | (26,421) | (46,808) | (50,930) | |
Other income | 2,123 | 1,195 | 3,623 | 4,297 | |
Income Tax (Expense) Benefit | (580) | (2,947) | (7,257) | (3,606) | |
Net Income | 21,830 | 35,569 | 78,397 | 75,436 | |
Total assets | 5,556,932 | 5,307,606 | 5,556,932 | 5,307,606 | $ 5,499,321 |
Capital expenditures | 67,604 | 69,928 | 119,123 | 121,246 | |
Electric [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 233,866 | 248,403 | 500,105 | 489,745 | |
Cost of sales | 70,146 | 72,165 | 155,531 | 155,789 | |
Gross margin | 163,720 | 176,238 | 344,574 | 333,956 | |
Operating, general and administrative | 54,086 | 51,568 | 112,705 | 107,011 | |
Property and other taxes | 30,909 | 27,322 | 62,070 | 54,751 | |
Depreciation and depletion | 34,105 | 32,544 | 68,175 | 65,065 | |
Operating income (loss) | 44,620 | 64,804 | 101,624 | 107,129 | |
Interest expense | (21,064) | (24,119) | (42,101) | (46,174) | |
Other income | 917 | 687 | 1,623 | 1,154 | |
Income Tax (Expense) Benefit | (523) | (3,331) | (3,410) | (4,346) | |
Net Income | 23,950 | 38,041 | 57,736 | 57,763 | |
Total assets | 4,439,694 | 4,221,293 | 4,439,694 | 4,221,293 | |
Capital expenditures | 55,995 | 57,938 | 97,036 | 99,563 | |
Natural Gas [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 49,993 | 44,717 | 151,066 | 135,914 | |
Cost of sales | 13,854 | 9,528 | 48,286 | 41,338 | |
Gross margin | 36,139 | 35,189 | 102,780 | 94,576 | |
Operating, general and administrative | 20,206 | 20,585 | 41,835 | 42,497 | |
Property and other taxes | 8,569 | 7,883 | 17,333 | 15,872 | |
Depreciation and depletion | 7,382 | 7,346 | 14,765 | 14,707 | |
Operating income (loss) | (18) | (625) | 28,847 | 21,500 | |
Interest expense | (1,500) | (1,814) | (3,046) | (3,769) | |
Other income | 489 | 271 | 717 | 580 | |
Income Tax (Expense) Benefit | 817 | 1,278 | (6,134) | (1,743) | |
Net Income | (212) | (890) | 20,384 | 16,568 | |
Total assets | 1,114,426 | 1,080,065 | 1,114,426 | 1,080,065 | |
Capital expenditures | 11,609 | 11,990 | 22,087 | 21,683 | |
All Other Segments [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 0 | 0 | 0 | |
Cost of sales | 0 | 0 | 0 | 0 | |
Gross margin | 0 | 0 | 0 | 0 | |
Operating, general and administrative | 896 | 426 | 1,610 | 2,932 | |
Property and other taxes | 3 | 3 | 6 | 6 | |
Depreciation and depletion | 8 | 8 | 16 | 16 | |
Operating income (loss) | (907) | (437) | (1,632) | (2,954) | |
Interest expense | (844) | (488) | (1,661) | (987) | |
Other income | 717 | 237 | 1,283 | 2,563 | |
Income Tax (Expense) Benefit | (874) | (894) | 2,287 | 2,483 | |
Net Income | (1,908) | (1,582) | 277 | 1,105 | |
Total assets | 2,812 | 6,248 | 2,812 | 6,248 | |
Capital expenditures | 0 | 0 | 0 | 0 | |
Intersegment Elimination [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 0 | 0 | 0 | 0 | |
Cost of sales | 0 | 0 | 0 | 0 | |
Gross margin | 0 | 0 | 0 | 0 | |
Operating, general and administrative | 0 | 0 | 0 | 0 | |
Property and other taxes | 0 | 0 | 0 | 0 | |
Depreciation and depletion | 0 | 0 | 0 | 0 | |
Operating income (loss) | 0 | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Other income | 0 | 0 | 0 | 0 | |
Income Tax (Expense) Benefit | 0 | 0 | 0 | 0 | |
Net Income | 0 | 0 | 0 | 0 | |
Total assets | 0 | $ 0 | 0 | 0 | |
Capital expenditures | $ 0 | $ 0 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Basic computation | 48,450,639 | 48,308,656 | 48,418,368 | 48,275,482 |
Dilutive effect of performance share awards (1) | 130,772 | 76,877 | 129,383 | 76,737 |
Diluted computation | 48,581,411 | 48,385,533 | 48,547,751 | 48,352,219 |
Adjustments for New Accounting Principle, Early Adoption [Member] | ||||
Dilutive effect of performance share awards (1) | 10,116 | 10,090 |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Pension Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | $ 2,367 | $ 2,941 | $ 5,497 | $ 5,880 |
Interest cost | 6,388 | 6,539 | 12,817 | 13,105 |
Expected return on plan assets | (5,974) | (7,043) | (11,982) | (14,124) |
Amortization of prior service cost | 0 | 61 | 2 | 123 |
Recognized actuarial loss | 1,944 | 2,478 | 3,919 | 4,944 |
Net Periodic Benefit Cost (Income) | 4,725 | 4,976 | 10,253 | 9,928 |
Other Postretirement Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | 100 | 116 | 228 | 246 |
Interest cost | 178 | 196 | 358 | 398 |
Expected return on plan assets | (211) | (260) | (424) | (521) |
Amortization of prior service cost | (470) | (470) | (941) | (941) |
Recognized actuarial loss | 81 | 71 | 159 | 158 |
Net Periodic Benefit Cost (Income) | $ (322) | $ (347) | $ (620) | $ (660) |
Commitments and Contingencies E
Commitments and Contingencies Environmental (Details) $ in Millions | 6 Months Ended | |
Jun. 30, 2017USD ($) | Jul. 01, 2018 | |
Colstrip Unit 4 [Member] | ||
Jointly owned utility plant ownership percentage | 30.00% | |
Environmental obligation, estimated capital Expenditures | $ 90 | |
Coyote Generating Facility [Member] | ||
Jointly owned utility plant ownership percentage | 10.00% | |
Environmental remediation obligations [Member] | ||
Environmental remediation obligation, minimum | $ 27.9 | |
Environmental remediation obligation, maximum | 32.6 | |
Accrual for environmental loss contingencies | 30.6 | |
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member] | ||
Accrual for environmental loss contingencies | 23.8 | |
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | ||
Accrual for environmental loss contingencies | 10.4 | |
Environmental remediation obligation next 5 years | $ 5.9 | |
Number of years for environmental remediation obligation to be incurred | 5 years | |
Scenario, Forecast [Member] | Coyote Generating Facility [Member] | ||
NOx emissions per million Btu as calculated on a 30 day rolling average basis | 0.5 |
Commitments and Contingencies L
Commitments and Contingencies Litigation (Details) - Refinery outage [Member] - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended |
Aug. 31, 2014 | Dec. 31, 2015 | Jun. 30, 2017 | Dec. 31, 2016 | |
Loss Contingencies [Line Items] | ||||
Damages sought | $ 48.5 | $ 61.7 | $ 108 | |
Retention amount | $ 2 |