Document and Document Entity In
Document and Document Entity Information - USD ($) | 9 Months Ended | |
Sep. 30, 2015 | Oct. 16, 2015 | |
Entity Information [Line Items] | ||
Entity Registrant Name | NORTHWESTERN CORPORATION | |
Entity Central Index Key | 73,088 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 48,167,964 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Public Float | $ 2,042,683,000 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues | ||||
Electric | $ 238,513 | $ 212,430 | $ 695,921 | $ 652,951 |
Gas | 34,226 | 39,482 | 193,389 | 238,965 |
Total Revenues | 272,739 | 251,912 | 889,310 | 891,916 |
Operating Expenses | ||||
Cost of sales | 73,577 | 94,592 | 265,495 | 374,494 |
Operating, general and administrative | 79,296 | 68,108 | 222,139 | 214,557 |
Property and other taxes | 35,712 | 27,773 | 100,953 | 84,292 |
Depreciation and depletion | 35,693 | 30,452 | 107,239 | 91,139 |
Total Operating Expenses | 224,278 | 220,925 | 695,826 | 764,482 |
Operating Income | 48,461 | 30,987 | 193,484 | 127,434 |
Interest Expense, net | (22,043) | (18,794) | (68,101) | (57,887) |
Other Income (Expense) | 3,769 | (439) | 5,429 | 4,730 |
Income Before Income Taxes | 30,187 | 11,754 | 130,812 | 74,277 |
Income Tax (Expense) Benefit | (6,389) | 18,437 | (24,616) | 9,240 |
Net Income | $ 23,798 | $ 30,191 | $ 106,196 | $ 83,517 |
Average Common Shares Outstanding | 47,065,082 | 39,141,148 | 47,028,924 | 39,045,790 |
Basic Earnings per Average Common Share | $ 0.51 | $ 0.77 | $ 2.26 | $ 2.14 |
Diluted Earnings per Average Common Share | 0.51 | 0.77 | 2.25 | 2.13 |
Dividends Declared per Common Share | $ 0.48 | $ 0.40 | $ 1.44 | $ 1.20 |
CONDENSED CONSOLIDATED STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Comprehensive Income (Loss) | ||||
Net Income | $ 23,798 | $ 30,191 | $ 106,196 | $ 83,517 |
Unrealized loss on cash flow hedging derivatives | 0 | (1,011) | 0 | (1,011) |
Other comprehensive income (loss), net of tax: | ||||
Foreign currency translation | 233 | 134 | 445 | 155 |
Cash flow hedges: | ||||
Reclassification of net gains on derivative instruments | (555) | (183) | (735) | (549) |
Net current-period other comprehensive (loss) income | (322) | (1,060) | (290) | (1,405) |
Comprehensive Income | $ 23,476 | $ 29,131 | $ 105,906 | $ 82,112 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 10,135 | $ 20,362 |
Restricted cash | 18,639 | 29,662 |
Accounts receivable, net | 117,454 | 163,479 |
Inventories | 58,692 | 55,094 |
Regulatory assets | 38,389 | 47,374 |
Deferred income taxes | 62,370 | 20,843 |
Other | 10,157 | 14,071 |
Total current assets | 315,836 | 350,885 |
Property, plant, and equipment, net | 4,004,516 | 3,758,008 |
Goodwill | 355,128 | 355,128 |
Regulatory assets | 502,201 | 455,757 |
Other noncurrent assets | 57,397 | 54,165 |
Total assets | 5,235,078 | 4,973,943 |
Current Liabilities: | ||
Current maturities of capital leases | 1,803 | 1,730 |
Short-term borrowings | 217,943 | 267,840 |
Accounts payable | 60,235 | 81,961 |
Accrued expenses | 226,024 | 206,882 |
Regulatory liabilities | 68,908 | 56,169 |
Total current liabilities | 574,913 | 614,582 |
Long-term capital leases | 26,802 | 28,162 |
Long-term debt | 1,782,123 | 1,662,099 |
Deferred income taxes | 550,234 | 446,600 |
Noncurrent regulatory liabilities | 374,460 | 362,228 |
Other noncurrent liabilities | 407,700 | 382,489 |
Total liabilities | $ 3,716,232 | $ 3,496,160 |
Commitments and Contingencies (Note 14) | ||
Shareholders' Equity: | ||
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 50,687,962 and 47,067,963 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued | $ 507 | $ 505 |
Treasury stock at cost | (94,031) | (92,558) |
Paid-in capital | 1,317,617 | 1,313,844 |
Retained earnings | 303,809 | 264,758 |
Accumulated other comprehensive loss | (9,056) | (8,766) |
Total shareholders' equity | 1,518,846 | 1,477,783 |
Total liabilities and shareholders' equity | $ 5,235,078 | $ 4,973,943 |
CONDENSED CONSOLIDATED BALANCE5
CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL | Sep. 30, 2015$ / sharesshares |
Common Stock, Par or Stated Value Per Share | $ / shares | $ 0.01 |
Common Stock, Shares Authorized | 200,000,000 |
Common Stock, Shares, Issued | 50,687,962 |
Common Stock, Shares, Outstanding | 47,067,963 |
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 | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
OPERATING ACTIVITIES: | ||
Net Income | $ 106,196 | $ 83,517 |
Items not affecting cash: | ||
Depreciation and depletion | 107,239 | 91,139 |
Amortization of debt issue costs, discount and deferred hedge gain | 1,301 | 4,856 |
Stock-based compensation costs | 3,275 | 2,238 |
Equity portion of allowance for funds used during construction | (6,568) | (4,393) |
Gain on disposition of assets | (28) | (347) |
Deferred income taxes | 27,019 | 29,537 |
Changes in current assets and liabilities: | ||
Restricted cash | (735) | (10,286) |
Accounts receivable | 46,025 | 55,388 |
Inventories | (3,598) | (7,357) |
Other current assets | 4,006 | 5,086 |
Accounts payable | (21,655) | (30,298) |
Accrued expenses | 19,307 | 26,257 |
Regulatory assets | 8,985 | (8,448) |
Regulatory liabilities | 12,739 | 6,207 |
Other noncurrent assets | (2,240) | (34,650) |
Other noncurrent liabilities | 3,209 | (3,480) |
Cash provided by operating activities | 304,477 | 204,966 |
INVESTING ACTIVITIES: | ||
Property, plant, and equipment additions | (203,324) | (186,085) |
Acquisitions | (143,328) | 1,367 |
Proceeds from sale of assets | 30,209 | 390 |
Change in restricted cash | 11,758 | (21,180) |
Investment in New Market Tax Credit program | 0 | (18,169) |
Cash used in investing activities | (304,685) | (223,677) |
FINANCING ACTIVITIES: | ||
Treasury stock activity | (829) | (881) |
Proceeds from issuance of common stock, net | 0 | 13,320 |
Dividends on common stock | (67,145) | (46,426) |
Issuance of long-term debt | 270,000 | 25,789 |
Repayments on long-term debt | (150,024) | (80) |
(Repayments) issuances of short-term borrowings, net | (49,897) | 28,995 |
Financing costs | (12,124) | (832) |
Cash (used in) provided by financing activities | (10,019) | 19,885 |
(Decrease) Increase in Cash and Cash Equivalents | (10,227) | 1,174 |
Cash and Cash Equivalents, beginning of period | 20,362 | 16,557 |
Cash and Cash Equivalents, end of period | 10,135 | 17,731 |
Cash paid during the period for: | ||
Income taxes | 27 | 28 |
Interest | 52,106 | 44,170 |
Significant non-cash transactions: | ||
Capital expenditures included in accounts payable and accrued expenses | $ 8,932 | $ 7,989 |
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 Income (Loss) [Member] | Shareholders' Equity [Member] |
Balance, shares at Dec. 31, 2013 | 42,340 | 3,595 | |||||
Balance, beginning of period at Dec. 31, 2013 | $ 423 | $ 910,184 | $ (91,744) | $ 209,091 | $ 2,716 | $ 1,030,670 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | $ 83,517 | 0 | 0 | 0 | 83,517 | 0 | 83,517 |
Foreign currency translation adjustment | 155 | 0 | 0 | 0 | 0 | 155 | 155 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (549) | 0 | 0 | 0 | 0 | (549) | (549) |
Unrealized loss on cash flow hedging activities, net of tax | $ (1,011) | $ 0 | 0 | $ 0 | 0 | (1,011) | (1,011) |
Stock based compensation, shares | 118 | 0 | |||||
Stock based compensation, value | $ 0 | 2,727 | $ (922) | 0 | 0 | 1,805 | |
Issuance of shares | 296 | ||||||
Issuance of shares, value | $ 5 | 13,479 | 0 | 0 | 13,525 | ||
Issuance of shares, treasury stock | 15 | ||||||
Issuance of shares, treasury stock, value | $ 41 | ||||||
Dividends on common stock | 0 | 0 | 0 | (46,426) | 0 | (46,426) | |
Dividends per share | $ 1.20 | ||||||
Balance, end of period at Sep. 30, 2014 | $ 428 | 926,390 | $ (92,625) | 246,182 | 1,311 | 1,081,686 | |
Balance, shares at Sep. 30, 2014 | 42,754 | 3,610 | |||||
Balance, shares at Dec. 31, 2014 | 50,522 | 3,607 | |||||
Balance, beginning of period at Dec. 31, 2014 | $ 1,477,783 | $ 505 | 1,313,844 | $ (92,558) | 264,758 | (8,766) | 1,477,783 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | 106,196 | 0 | 0 | 0 | 106,196 | 0 | 106,196 |
Foreign currency translation adjustment | 445 | 0 | 0 | 0 | 0 | 445 | 445 |
Reclassification of net gains on derivative instruments from OCI to net income, net of tax | (735) | $ 0 | 0 | $ 0 | 0 | (735) | (735) |
Unrealized loss on cash flow hedging activities, net of tax | $ 0 | ||||||
Stock based compensation, shares | 166 | 0 | |||||
Stock based compensation, value | $ 0 | 3,304 | $ (1,926) | 0 | 0 | 1,378 | |
Issuance of shares | 0 | ||||||
Issuance of shares, value | $ 2 | 469 | 0 | 0 | 924 | ||
Issuance of shares, treasury stock | 13 | ||||||
Issuance of shares, treasury stock, value | $ 453 | ||||||
Dividends on common stock | 0 | 0 | 0 | (67,145) | 0 | (67,145) | |
Dividends per share | $ 1.44 | ||||||
Balance, end of period at Sep. 30, 2015 | $ 1,518,846 | $ 507 | $ 1,317,617 | $ (94,031) | $ 303,809 | $ (9,056) | $ 1,518,846 |
Balance, shares at Sep. 30, 2015 | 50,688 | 3,620 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 9 Months Ended |
Sep. 30, 2015 | |
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 692,600 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 September 30, 2015 , 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 SEC. 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, 2014 . 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 Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a 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 $279.5 million through 2024 . |
New Accounting Standards
New Accounting Standards | 9 Months Ended |
Sep. 30, 2015 | |
New Accounting Pronouncement or Change in Accounting Principle, Current Period Disclosures [Abstract] | |
New Accounting Pronouncements [Text Block] | New Accounting Standards Accounting Standards Issued In April 2015, the Financial Accounting Standards Board (FASB) issued accounting guidance that changes the presentation of debt issuance costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. The new guidance will be effective for us in our first quarter of 2016. Early adoption is permitted. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. In May 2014, the FASB issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The FASB delayed the effective date of this guidance to the first quarter of 2018, with early adoption permitted as of the original effective date of the first quarter of 2017. We are currently evaluating the impact of adoption of this new guidance on our Financial Statements and disclosures. In January 2015, the FASB issued guidance which eliminates from GAAP the concept of an extraordinary item. As a result, an entity will no longer (1) segregate an extraordinary item from the results of ordinary operations; (2) separately present an extraordinary item on its income statement, net of tax, after income from continuing operations; and (3) disclose income taxes and earnings-per-share data applicable to an extraordinary item. The new guidance will be effective for us in our first quarter of 2016 and early adoption is permitted. We do not expect the adoption of this standard to have a material effect on our reporting and disclosure. Accounting Standards Adopted There have been no new accounting pronouncements or changes in accounting pronouncements adopted during the nine months ended September 30, 2015 that are of significance, or potential significance, to us. |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Business Combination Disclosure (Text Block) | Hydro Transaction In November 2014, we completed the purchase of 11 hydroelectric generating facilities and associated assets located in Montana for an adjusted purchase price of approximately $904 million (Hydro Transaction). The addition of hydroelectric generation provides long-term supply diversity to our portfolio and reduces risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. We expect to finalize the purchase price allocation, including analysis of environmental matters and potential removal obligations, during the fourth quarter of 2015. Kerr Project - The Hydro Transaction included the Kerr Project. Upon the close of the Hydro Transaction, we assumed temporary ownership of the Kerr Project until it was conveyed to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) on September 5, 2015, in accordance with the associated FERC license. Our purchase agreement for the Hydro Transaction included a $30 million reference price for the Kerr Project. In September 2015, the CSKT paid us $18.3 million , which was established through previous arbitration, and Talen Energy (formerly PPL Montana) paid the difference of $11.7 million to us. Upon receipt of the CSKT payment we conveyed the Kerr Project to the CSKT. The Montana Public Service Commission (MPSC) order approving the Hydro Transaction provided that customers would have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT. We sold any excess system generation during our temporary ownership of the Kerr Project in the market and provided revenue credits to our Montana retail customers until the transfer to the CSKT. We believe the benefits of our temporary ownership of the Kerr Project exceeded any costs to customers. We expect to make the required compliance filing during the fourth quarter of 2015 that will remove the Kerr Project from cost of service, adjust for actual revenue credits and increase property taxes to actual amounts for the Hydro Transaction with revised rates effective January 1, 2016. South Dakota Wind Generation In September 2015, we completed the purchase of the 80 MW Beethoven wind project near Tripp, South Dakota, for approximately $143 million (subject to customary post closing adjustments). The Beethoven project was not submitted in the South Dakota electric rate filing made in December 2014; however, we reached a stipulated settlement agreement in September 2015 that will allow us to include Beethoven in rate base and collect approximately $9.0 million annually. For further discussion of this settlement agreement see Note 4 - Regulatory Matters. The purchase price was allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition as follows: Purchase Price Allocation (in millions) Assets Acquired Property Plant and Equipment $ 143.0 Other Prepayments 0.1 Total Assets Acquired $ 143.1 Liabilities Assumed Other Current Liabilities $ 0.3 Total Liabilities Assumed $ 0.3 Total Purchase Price $ 142.8 We expect to finalize the purchase price allocation during the fourth quarter of 2015. The pro forma results as if the Beethoven acquisition occurred on January 1, 2015 would not be materially different from our financial results for the nine months ended September 30, 2015. |
Regulatory Matters
Regulatory Matters | 9 Months Ended |
Sep. 30, 2015 | |
Regulated Operations [Abstract] | |
Public Utilities Disclosure [Text Block] | Regulatory Matters South Dakota Electric Rate Filing In December 2014, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for an annual increase to electric rates totaling approximately $26.5 million . Our request was based on an overall rate of return of 7.67% and rate base of $447.4 million . In September 2015, we reached a settlement with the SDPUC Staff and intervenors providing for an increase in base rates of approximately $20.2 million , based on an overall rate of return of 7.24% . In addition, the settlement would allow us to collect approximately $9 million annually related to the Beethoven wind project as discussed above. The settlement is subject to approval of the SDPUC, and a hearing is scheduled for October 2015. The SDPUC is expected to make a final determination in the case by the end of 2015. We have been collecting interim rates since July 1, 2015, based on our original filing. We are recognizing revenue consistent with the settlement and we will refund any amounts overcollected by March 31, 2016. Montana Electric and Natural Gas Tracker Filings Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric supply procurement activities were prudent. During the second quarter of 2015, we filed our annual electric and natural gas supply tracker filings for the 2014/2015 tracker period and received orders from the MPSC approving those filings on an interim basis. Our electric and natural gas supply tracker filings for the 2013/2014 and 2012/2013 tracker periods are part of consolidated dockets. Electric Tracker - Our 2013/2014 electric tracker filing included market purchases made between July 2013 and January 2014 for replacement power during an outage at Colstrip Unit 4. Inclusion of these costs in the tracker filing is consistent with the treatment of replacement power during previous outages. During a June 2014 MPSC work session, approximately $11 million of these incremental market purchases related to the Colstrip Unit 4 outage were identified by the MPSC for additional prudency review. The Montana Consumer Counsel, Montana Environmental Information Center and Sierra Club have intervened in the consolidated docket to challenge our recovery of costs associated with Colstrip Unit 4, particularly the costs incurred as a result of the outage, as imprudent. A hearing was held in October 2015 related to the 2013/2014 and 2012/2013 consolidated tracker docket and we expect the MPSC to issue a final order by the first quarter of 2016. Natural Gas Tracker - In October 2015, we received a final order in the natural gas consolidated 2013/2014 and 2012/2013 tracker docket. This consolidated docket included our request to continue collecting the cost of service for natural gas production interests acquired in December 2013 and in August 2012 in northern Montana's Bear Paw Basin (Bear Paw) on an interim basis. The MPSC final order requires that we revise the bridge rates currently used to reflect our actual fixed cost requirements since acquisition of these interests. In addition, the order requires us to make a filing within the next 12 months to address the cost-recovery of our gas production fields. As of September 30, 2015, we have deferred revenue of approximately $1.6 million consistent with the final order. Electric and Natural Gas Lost Revenue Adjustment Mechanism - Demand-side management (DSM) lowers our sales to customers. Base rates, including impacts of past DSM activities, are reset in general rate filings. Between rate filings, the implementation of energy saving measures result in increased lost revenues related to DSM activities. In 2005, the MPSC created a Lost Revenue Adjustment Mechanism (LRAM) by which we collect revenue that we would have collected without any DSM through our supply tracker filings. In an order issued in October 2013, which was related to our 2011/2012 electric supply tracker, the MPSC required us to lower our LRAM revenue recovery and imposed a new burden of proof on us for future LRAM recovery. We appealed the October 2013 order to Montana District Court, which led to a docket being initiated in June 2014 by the MPSC to review lost revenue policy issues. In June 2015, the MPSC held a hearing to address these issues. In October 2015, the MPSC issued an order to eliminate the LRAM prospectively effective December 1, 2015. Based on the October 2013 MPSC order, we have recognized $7.1 million of DSM lost revenues for each annual electric supply tracker period (cumulatively July 1, 2012 through September 30, 2015) and deferred the remaining portion. As of September 30, 2015 we have cumulative deferred revenue of approximately $11.8 million , which is recorded within current regulatory liabilities in the Consolidated Balance Sheet. Since the 2012/2013 and 2013/2014 annual electric tracker filings are still subject to final approval, the MPSC may ultimately require us to refund more than we have deferred or approve recovery of more DSM lost revenues than we have recognized since July 2012. Dave Gates Generating Station at Mill Creek (DGGS) In April 2014, the FERC issued an order affirming a FERC Administrative Law Judge's (ALJ) initial decision in September 2012, regarding cost allocation at DGGS between retail and wholesale customers. This decision concluded we should allocate only a fraction of the costs we believe, based on facts and the law, should be allocated to FERC jurisdictional customers. We have been recognizing revenue consistent with the ALJ's initial decision. As of September 30, 2015 , we have cumulative deferred revenue of approximately $27.3 million , which is subject to refund and recorded within current regulatory liabilities in the Consolidated Balance Sheets. In May 2014, we filed a request for rehearing, which remains pending. In our request for rehearing, we have argued that no refunds are due even if the cost allocation method is modified prospectively. There is no deadline by which FERC must act on our rehearing petition, but it could occur during 2015. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal would likely extend into 2016 or beyond. The FERC order was assessed as a triggering event as to whether an impairment charge should be recorded with respect to DGGS. We are evaluating options to use DGGS in combination with other generation resources, including our newly acquired hydro facilities, to facilitate cost recovery. Any alternative use of DGGS would be subject to regulatory approval and we cannot provide assurance of such approval. We do not believe an impairment loss is probable at this time; however, we will continue to evaluate recovery of this asset in the future as facts and circumstances change. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | Income Taxes The following table summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended September 30, 2015 2014 Income Before Income Taxes $ 30,187 $ 11,754 Income tax calculated at 35% federal statutory rate 10,565 35.0 % 4,114 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (857 ) (2.8 ) (108 ) (0.9 ) Release of unrecognized tax benefit — — (12,607 ) (107.3 ) Flow-through repairs deductions (2,779 ) (9.2 ) (3,413 ) (29.0 ) Production tax credits (733 ) (2.4 ) (300 ) (2.6 ) Plant and depreciation of flow through items (374 ) (1.2 ) (685 ) (5.8 ) Prior year permanent return to accrual adjustments 1,025 3.4 (5,172 ) (44.0 ) Other, net (458 ) (1.6 ) (266 ) (2.3 ) (4,176 ) (13.8 ) (22,551 ) (191.9 ) Income tax expense (benefit) $ 6,389 21.2 % $ (18,437 ) (156.9 )% Nine Months Ended September 30, 2015 2014 Income Before Income Taxes $ 130,812 $ 74,277 Income tax calculated at 35% federal statutory rate 45,784 35.0 % 25,997 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (329 ) (0.3 ) 257 0.3 Flow-through repairs deductions (17,240 ) (13.2 ) (14,885 ) (20.0 ) Release of unrecognized tax benefit — — (12,607 ) (17.0 ) Production tax credits (2,645 ) (2.0 ) (2,054 ) (2.8 ) Plant and depreciation of flow through items (1,000 ) (0.8 ) (182 ) (0.2 ) Prior year permanent return to accrual adjustments 1,025 0.8 (5,172 ) (7.0 ) Other, net (979 ) (0.7 ) (594 ) (0.7 ) (21,168 ) (16.2 ) (35,237 ) (47.4 ) Income tax expense (benefit) $ 24,616 18.8 % $ (9,240 ) (12.4 )% 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. 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 $96.4 million as of September 30, 2015 , including approximately $65.3 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 nine months ended September 30, 2015 , we did not recognize expense for interest and penalties in the Condensed Consolidated Statements of Income and did not have any amounts accrued at September 30, 2015 and December 31, 2014 , respectively, for the payment of interest and penalties. Our federal tax returns from 2000 forward remain subject to examination by the IRS. |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2015 | |
Goodwill [Abstract] | |
Goodwill Disclosure [Text Block] | Goodwill We completed our annual goodwill impairment test as of April 1, 2015, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections. There were no changes in our goodwill during the nine months ended September 30, 2015 . Goodwill by segment is as follows for both September 30, 2015 and December 31, 2014 (in thousands): Electric $ 241,100 Natural gas 114,028 $ 355,128 |
Comprehensive Income (Loss)
Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2015 | |
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) (in thousands): Three Months Ended September 30, 2015 September 30, 2014 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 233 $ — $ 233 $ 134 $ — $ 134 Reclassification of net gains on derivative instruments (901 ) 346 (555 ) (297 ) 114 (183 ) Unrealized loss on cash flow hedging derivatives — — — (1,644 ) 633 (1,011 ) Other comprehensive (loss) income $ (668 ) $ 346 $ (322 ) $ (1,807 ) $ 747 $ (1,060 ) Nine Months Ended September 30, 2015 September 30, 2014 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 445 $ — $ 445 $ 155 $ — $ 155 Reclassification of net gains on derivative instruments (1,187 ) 452 (735 ) (891 ) 342 (549 ) Unrealized loss on cash flow hedging derivatives — — — (1,644 ) 633 (1,011 ) Other comprehensive (loss) income $ (742 ) $ 452 $ (290 ) $ (2,380 ) $ 975 $ (1,405 ) Balances by classification included within accumulated other comprehensive income (loss) (AOCI) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): September 30, 2015 December 31, 2014 Foreign currency translation $ 1,242 $ 797 Derivative instruments designated as cash flow hedges (9,051 ) (8,316 ) Pension and postretirement medical plans (1,247 ) (1,247 ) Accumulated other comprehensive loss $ (9,056 ) $ (8,766 ) The following tables display the changes in AOCI by component, net of tax (in thousands): September 30, 2015 Three Months Ended 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 $ (8,496 ) $ (1,247 ) $ 1,009 $ (8,734 ) Other comprehensive income before reclassifications — — 233 233 Amounts reclassified from AOCI Interest Expense (555 ) — — (555 ) Net current-period other comprehensive (loss) income (555 ) — 233 (322 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) September 30, 2014 Three Months Ended 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 $ 3,147 $ (1,329 ) $ 553 $ 2,371 Other comprehensive income before reclassifications (1,011 ) — 134 (877 ) Amounts reclassified from AOCI Interest Expense (183 ) — — (183 ) Net current-period other comprehensive (loss) income (1,194 ) — 134 (1,060 ) Ending balance $ 1,953 $ (1,329 ) $ 687 $ 1,311 September 30, 2015 Nine Months Ended 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 $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive income before reclassifications — — 445 445 Amounts reclassified from AOCI Interest Expense (735 ) — — (735 ) Net current-period other comprehensive (loss) income (735 ) — 445 (290 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) September 30, 2014 Nine Months Ended 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 $ 3,513 $ (1,329 ) $ 532 $ 2,716 Other comprehensive income before reclassifications (1,011 ) — 155 (856 ) Amounts reclassified from AOCI Interest Expense (549 ) — — (549 ) Net current-period other comprehensive (loss) income (1,560 ) — 155 (1,405 ) Ending balance $ 1,953 $ (1,329 ) $ 687 $ 1,311 |
Risk Management and Hedging Act
Risk Management and Hedging Activities | 9 Months Ended |
Sep. 30, 2015 | |
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 within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the normal purchase and normal sale scope exception (NPNS) to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Financial Statements at September 30, 2015 and December 31, 2014 . Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate 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 AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Financial Statements (in thousands): Location of amount reclassified from AOCI to Income Amount Reclassified from AOCI into Income during the Nine Months Ended September 30, 2015 Interest rate contracts Interest Expense $ 1,187 A net pre-tax loss of approximately $15.0 million is remaining in AOCI as of September 30, 2015 , and we expect to reclassify approximately $0.3 million of net pre-tax gains from AOCI into interest expense during the next twelve months. These amounts relate to terminated swaps. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2015 | |
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 8 - 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) September 30, 2015 Restricted cash $ 13,892 $ — $ — $ — $ 13,892 Rabbi trust investments 23,760 — — — 23,760 Total $ 37,652 $ — $ — $ — $ 37,652 December 31, 2014 Restricted cash $ 13,140 $ — $ — $ — $ 13,140 Rabbi trust investments 21,594 — — — 21,594 Total $ 34,734 $ — $ — $ — $ 34,734 Restricted cash represents amounts held in money market mutual funds. Rabbi trust 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): September 30, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,782,123 $ 1,862,952 $ 1,662,099 $ 1,817,642 Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy. |
Financing Activities
Financing Activities | 9 Months Ended |
Sep. 30, 2015 | |
Financing Activities [Abstract] | |
Debt Disclosure [Text Block] | Financing Activities We financed the Beethoven wind project acquisition with a combination of $70 million of South Dakota first mortgage bonds, approximately $57 million of equity and the remainder with short-term borrowings. The $70 million of South Dakota first mortgage bonds were issued in September 2015 at a fixed interest rate of 4.26% maturing in 2040 . The bonds are secured by our electric and natural gas assets in South Dakota and were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. The equity transaction was completed in October 2015 through the issuance of 1,100,000 shares of our common stock at $51.81 per share. In June 2015, we issued $200 million aggregate principal amount of Montana First Mortgage Bonds, which includes $75 million at a fixed interest rate of 3.11% maturing in 2025 and $125 million at a fixed interest rate of 4.11% maturing in 2045 . The bonds are secured by our electric and natural gas assets in Montana. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.04% , $150 million of Montana First Mortgage Bonds due 2016 and finance incremental Montana capital expenditures. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2015 | |
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 September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 238,513 $ 34,226 $ — $ — $ 272,739 Cost of sales 66,197 7,380 — — 73,577 Gross margin 172,316 26,846 — — 199,162 Operating, general and administrative 58,298 19,843 1,155 — 79,296 Property and other taxes 28,648 7,062 2 — 35,712 Depreciation and depletion 28,476 7,209 8 — 35,693 Operating income (loss) 56,894 (7,268 ) (1,165 ) — 48,461 Interest expense (19,078 ) (2,562 ) (403 ) — (22,043 ) Other income 1,832 507 1,430 — 3,769 Income tax (expense) benefit (6,553 ) 1,883 (1,719 ) — (6,389 ) Net income (loss) $ 33,095 $ (7,440 ) $ (1,857 ) $ — $ 23,798 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 57,813 $ 14,341 $ — $ — $ 72,154 Three Months Ended September 30, 2014 Electric Gas Other Eliminations Total Operating revenues $ 212,430 $ 39,482 $ — $ — $ 251,912 Cost of sales 84,720 9,872 — — 94,592 Gross margin 127,710 29,610 — — 157,320 Operating, general and administrative 48,528 21,005 (1,425 ) — 68,108 Property and other taxes 20,413 7,357 3 — 27,773 Depreciation and depletion 23,174 7,270 8 — 30,452 Operating income (loss) 35,595 (6,022 ) 1,414 — 30,987 Interest expense (14,025 ) (2,627 ) (2,142 ) — (18,794 ) Other income (expense) 1,337 336 (2,112 ) — (439 ) Income tax benefit 5,235 926 12,276 — 18,437 Net income (loss) $ 28,142 $ (7,387 ) $ 9,436 $ — $ 30,191 Total assets $ 2,694,883 $ 1,170,843 $ 8,572 $ — $ 3,874,298 Capital expenditures $ 62,054 $ 12,011 $ — $ — $ 74,065 Nine Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 695,921 $ 193,389 $ — $ — $ 889,310 Cost of sales 196,034 69,461 — — 265,495 Gross margin 499,887 123,928 — — 623,815 Operating, general and administrative 179,191 63,554 (20,606 ) — 222,139 Property and other taxes 78,987 21,958 8 — 100,953 Depreciation and depletion 85,523 21,691 25 — 107,239 Operating income 156,186 16,725 20,573 — 193,484 Interest expense (58,524 ) (8,304 ) (1,273 ) — (68,101 ) Other income (expense) 4,773 1,349 (693 ) — 5,429 Income tax expense (16,364 ) (1,621 ) (6,631 ) — (24,616 ) Net income $ 86,071 $ 8,149 $ 11,976 $ — $ 106,196 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 171,800 $ 31,524 $ — $ — $ 203,324 Nine Months Ended September 30, 2014 Electric Gas Other Eliminations Total Operating revenues $ 652,951 $ 238,965 $ — $ — $ 891,916 Cost of sales 273,754 100,740 — — 374,494 Gross margin 379,197 138,225 — — 517,422 Operating, general and administrative 144,933 66,254 3,370 — 214,557 Property and other taxes 61,322 22,961 9 — 84,292 Depreciation and depletion 69,398 21,716 25 — 91,139 Operating income (loss) 103,544 27,294 (3,404 ) — 127,434 Interest expense (43,663 ) (7,979 ) (6,245 ) — (57,887 ) Other income 3,204 876 650 — 4,730 Income tax (expense) benefit (575 ) (3,334 ) 13,149 — 9,240 Net income $ 62,510 $ 16,857 $ 4,150 $ — $ 83,517 Total assets $ 2,694,883 $ 1,170,843 $ 8,572 $ — $ 3,874,298 Capital expenditures $ 161,718 $ 24,367 $ — $ — $ 186,085 |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2015 | |
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 September 30, 2015 September 30, 2014 Basic computation 47,065,082 39,141,148 Dilutive effect of Performance share awards (1) 245,463 139,655 Diluted computation 47,310,545 39,280,803 Nine Months Ended September 30, 2015 September 30, 2014 Basic computation 47,028,924 39,045,790 Dilutive effect of Performance share awards (1) 245,460 141,560 Diluted computation 47,274,384 39,187,350 ______________ (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
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [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 September 30, Three Months Ended September 30, 2015 2014 2015 2014 Components of Net Periodic Benefit Cost (Income) Service cost $ 3,091 $ 2,708 $ 132 $ 116 Interest cost 6,544 6,536 197 214 Expected return on plan assets (7,890 ) (7,377 ) (242 ) (245 ) Amortization of prior service cost 62 62 (471 ) (500 ) Recognized actuarial loss 2,659 530 96 87 Net Periodic Benefit Cost (Income) $ 4,466 $ 2,459 $ (288 ) $ (328 ) Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Components of Net Periodic Benefit Cost (Income) Service cost $ 9,272 $ 8,123 $ 395 $ 349 Interest cost 19,631 19,610 590 644 Expected return on plan assets (23,671 ) (22,130 ) (727 ) (736 ) Amortization of prior service cost 185 185 (1,412 ) (1,499 ) Recognized actuarial loss 7,976 1,589 289 261 Net Periodic Benefit Cost (Income) $ 13,393 $ 7,377 $ (865 ) $ (981 ) |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
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 $26.4 million to $35.0 million . As of September 30, 2015 , we have a reserve of approximately $28.3 million , which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations. During the second quarter of 2015, we reached a settlement agreement with an insurance carrier for the former Montana Power Company for what were primarily generation related environmental remediation costs. As a result of this settlement, we recognized a net recovery of approximately $20.8 million , which is reflected as a reduction to operating expenses in our other segment. The environmental remediation costs were never reflected in customer rates and the litigation expenses have not been treated as utility expenses. In a 2002 order approving NorthWestern’s acquisition of the transmission and distribution assets of the Montana Power Company, the MPSC approved a stipulation in which NorthWestern agreed to release its customers from all environmental liabilities associated with the Montana Power Company’s generation assets. While we believe the recovery we recognized as a reduction to operating expenses is not subject to refund to customers, the MPSC could disagree with us and could ultimately require us to refund all or a portion of the net recovery to customers. Manufactured Gas Plants - Approximately $23.4 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies and implementing remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $10.4 million , and we estimate that approximately $7.5 million of this amount will be incurred during the next five years. We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District, a draft risk assessment was prepared for the Missoula site and presented to the Missoula County Water Quality Board (MCWQB). The MCWQB deferred all decision making to the MDEQ, but suggested additional site delineation. A work plan is being prepared to address further delineation and proposed work is anticipated for the fourth quarter of 2015. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at these sites or if any additional actions beyond monitored natural attenuation will be required. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. 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 electric generating plants, all of which are coal fired and operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating new and existing sources of GHG emissions. On August 3, 2015, the EPA released for publication in the Federal Register, the final standards of performance to limit GHG emissions from new, modified and reconstructed fossil fuel generating units and from newly constructed and reconstructed stationary combustion turbines. The standards reflect the degree of emission limitations achievable through the application of the best system of emission reduction that the EPA determined has been demonstrated for each type of unit. In a separate action that also affects power plants, on August 3, 2015, the EPA released its final rule establishing GHG performance standards for existing power plants under Clean Air Act Section 111(d). EPA refers to this rule as the Clean Power Plan or CPP. The CPP specifically establishes CO2 emission performance standards for existing electric utility steam generating units and stationary combustion turbines. States may develop implementation plans for affected units to meet the individual state targets established in the CPP or may adopt a federal plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour (MWH)) or mass-based tonnage limits for CO2. The 2030 rate-based requirement for all existing affected generating units in Montana and South Dakota is 1,305 and 1,167 pounds per MWH, respectively. The mass-based approach for existing affected generating units calls for a 37 percent reduction from 2012 levels by 2030 in Montana. The mass-based approach for existing units in South Dakota permits an 11 percent increase by 2030. States are required to submit initial plans for achieving GHG emission standards to EPA by September 2016, but may seek additional time to finalize State plans by September 2018. The initial performance period for compliance would commence in 2022, with full implementation by 2030. The EPA also indicated that states may establish emission trading programs to facilitate compliance with the CPP and provides three options: an emission rate trading program, which would allow the trading of emission reduction credits equal to one MWH of emission free generation; a mass-based program, which would allow trading of allowances with an allowance equal to one short ton of CO2; and a state measures program, that would allow intra-state trading to achieve the state-wide average emission rate. On August 3, 2015, EPA also proposed a federal plan that would be imposed if a state fails to submit a satisfactory plan under the CPP. The federal plan proposal includes a "model trading rule" that describes how the EPA would establish an emission trading program as part of the federal plan to allow affected units to comply with the emission rate requirements. EPA proposed both an emission rate trading plan and a mass-based trading plan and indicated that the final federal rule will elect one of the two options. Comments on the proposed federal plan and model trading rule will be due ninety days after it is published in the Federal Register. On June 23, 2014, the U.S. Supreme Court struck down the EPA's Tailoring Rule, which limited the sources subject to GHG permitting requirements to the largest fossil-fueled power plants, indicating that EPA had exceeded its authority under the Clean Air Act by "rewriting unambiguous statutory terms." However, the decision affirmed EPA's ability to regulate GHG emissions from sources already subject to regulation under the prevention of significant deterioration program, which includes most electric generating units. Requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Although there continues to be proposed legislation and regulations that affect GHG emissions from power plants, technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. In addition, physical impacts of climate change may present potential risks for severe weather, such as droughts, floods and tornadoes, in the locations where we operate or have interests. We are evaluating the implications of these rules and technology available to achieve the CO2 emission performance standards. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the final rules that, in our view, disproportionately impact customers in our region, and to seek relief from the final compliance requirements. We cannot predict the ultimate outcome of these matters nor what our obligations might be under the state compliance plans with any degree of certainty until they are finalized; however, complying with the carbon emission standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources. Coal Combustion Residuals (CCRs) - In April 2015, the EPA published its final rule regulating CCRs, imposing extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located on active power plants and not closed. Under the rule, the EPA will regulate CCRs as non-hazardous under the Resource Conservation and Recovery Act Subtitle B and allow beneficial use of CCRs, with some restrictions. The CCR rule will become effective on October 14, 2015. The rule's requirements for covered CCR impoundments and landfills include commencement or completion of closure activities generally between three and ten years from certain triggering events. Based on our initial assessment of these requirements, during the second quarter of 2015 we recorded an increase to our existing asset retirement obligations (AROs) of approximately $12 million . AROs represent the anticipated costs of removing assets upon retirement and are provided for over the life of those assets as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. All costs of the rule are expected to be recovered from customers in future rates. Therefore, consistent with this regulated treatment, we reflect this increase to the accrual of removal costs by increasing our regulatory liability. Further, we do not have any assets that are legally restricted related to the settlement of CCR related asset retirement obligations. The actual asset retirement costs related to the CCR Rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. We will coordinate with the plant operators and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, we will update the ARO obligation for these changes in estimates, which could be material. Legislation has been introduced in Congress to permanently designate coal ash as non-hazardous and establish a national system to regulate coal ash disposal, but leave enforcement largely to states. We cannot predict at this time the final outcome of any such legislation and what impact, if any, it would have on us. Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best technology available (BTA)” for minimizing environmental impacts. In May, 2014, the EPA issued a final rule applicable to facilities that withdraw at least 2 million gallons per day of cooling water from waters of the US and use at least 25 percent of the water exclusively for cooling purposes. The final rule, which became effective in October 2014, gives options for meeting BTA, and provides a flexible compliance approach. Under the rule, permits required for existing facilities will be developed by the individual states and additional capital and/or increased operating costs may be required to comply with future water permit requirements. Challenges to the final cooling water intake rule filed by industry and environmental groups are under review in the Court of Appeals. On September 30, 2015, the EPA issued final regulations on effluent limitations for power plant wastewater discharges, including mercury, arsenic, lead and selenium. Some of the new requirements for existing power plants would be phased in starting in 2018 with full implementation of the rule by 2023. The EPA rule estimates that 12 percent of the steam electric power plants in the U.S. will have to make new investments to meet the requirements of the new effluent limitation regulations; however, it is too early to determine whether the impacts of these rules will be material. Clean Air Act Rules and Associated Emission Control Equipment Expenditures - The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants in which we have joint ownership. The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas. In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. The rule was challenged by industry groups and states, and was upheld by the D.C. Circuit Court in April 2014. The decision was appealed to the Supreme Court and in June 2015, the Supreme Court issued an opinion that the EPA did not properly consider the costs to industry when making the requisite “appropriate and necessary” determination as part of its analysis in connection with the issuance of the MATS rule. The Supreme Court remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit, and on July 31 the litigation was formally sent back to the D.C. Circuit, which will decide whether the standards will be vacated or will remain in place while the EPA addresses the Supreme Court decision. The EPA indicated that it will seek a remand without vacatur of the MATS rule, and in support of that request, the EPA will submit to the court a declaration establishing a plan to "complete the required consideration of costs" to support the "appropriate and necessary finding" by spring 2016. Installation or upgrading of relevant environmental controls at our affected plants is complete or they have received compliance extensions, as applicable. At this time, we cannot predict whether and when compliance with the MATS rule ultimately will be required. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required in certain states beginning in 2012. In April 2014 the Supreme Court reversed and remanded the 2012 decision of the U.S. Court of Appeals for the D.C. Circuit that had vacated the CSAPR. Litigation of the remaining CSAPR lawsuits continues, with a decision expected by the end of 2015. In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA , which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions. In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Units 3 and 4 do not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised Plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, PPL Montana, the operator of Colstrip, as well as environmental groups (National Parks Conservation Association, Montana Environmental Information Center, and Sierra Club) jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center and Sierra Club challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. In June 2015, the U.S. Court of Appeals for the Ninth Circuit rejected the challengers’ contention that the EPA should have required additional pollution-reduction technologies on Unit 4 beyond those in the regulations and the matter is back in EPA Region 8 for action. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. South Dakota . The South Dakota DENR determined that the Big Stone plant, in which we have a 23.4% ownership, is subject to the BART requirements of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant must install and operate a new BART compliant air quality control system (AQCS) to reduce SO 2 , NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of the SIP. The estimated total project cost for the AQCS at the Big Stone plant is approximately $384 million (our share is 23.4%). As of September 30, 2015 , we have capitalized costs of approximately $95.1 million (including allowance for funds used during construction) related to this project, which is expected to be operational in the first quarter of 2016. Based on the final MATS rule, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. The South Dakota DENR granted Big Stone an extension to comply with MATS, such that the new compliance deadline is April 16, 2016. New mercury emissions monitoring equipment will be required. North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, in which we have 10% ownership, to reduce its NOx emissions. Coyote must install control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30 -day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $9.0 million (our share is 10.0%). Based on the final MATS rule, Coyote will meet the requirements by using activated carbon injection for mercury control. Initial compliance was demonstrated during the third quarter of 2015. Iowa . The Neal #4 generating facility, in which we have an 8.7% ownership, completed the installation of a scrubber, baghouse, activated carbon injection and a selective non-catalytic reduction system in 2013 to comply with national ambient air quality standards and the MATS. Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is subject to EPA's CCR Rule. A compliance plan has been developed and is in the initial stages of implementation. The current estimate of the total project cost is approximately $90 million (our share is 30.0%) over the remaining life of the facility. In addition, Unit 4 is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS and therefore in compliance with the Federal MATS. See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation. Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment. We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties: • We may not know all sites for which we are alleged or will be found to be responsible for remediation; and • Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation. LEGAL PROCEEDINGS Colstrip Litigation On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana (Court) against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station (Defendants). On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint dropped claims associated with projects completed before 2001, the Title V claims and the opacity claims. The Amended Complaint alleged a total of 23 claims covering 64 projects. In the Amended Complaint, Plaintiffs identified physical changes made at Colstrip between 2001 and 2012, that Plaintiffs allege (a) have increased emissions of SO2, NOx and particulate matter and (b) were “major modifications” subject to permitting requirements under the Clean Air Act. They also alleged violations of the requirements related to Part 70 Operating Permits. On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims asserted in the original complaint. The motion was not ruled upon, and the Colstrip owners filed a second motion to dismiss the Amended Complaint on October 11, 2013, incorporating parts of the first motion and supplementing it with new authorities and with regard to new claims contained in the Amended Complaint. On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications. The parties filed a joint notice (Notice) on April 21, 2014, that advised the Court of Plaintiffs’ intent to file a Second Amended Complaint which dropped claims relating to 52 projects, and added one additional project. On May 6, 2014, the Court held oral argument on Defendants' motion to dismiss and on Plaintiffs’ motion for summary judgment on the applicable legal standard. On May 22, 2014, the Magistrate issued findings and recommendations, which denied Plaintiffs’ motion for summary judgment and denied most of the Colstrip owners’ motion to dismiss, but dismissed seven of Plaintiffs’ “best available control technology” claims and dismissed two of Plaintiffs' claims for injunctive relief. The Plaintiffs filed an objection to the Magistrate's findings and recommendations with the U.S. Federal District Court Judge, and on August 13, 2014, the Court adopted the Magistrate's findings and conclusions. On August 27, 2014, the Plaintiffs filed their Second Amended Complaint, which alleges a total of 13 claims covering eight projects and seeks injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees. Defendants filed their Answer to the Second Amended Complaint on September 26, 2014. Since filing the Second Amended Complaint, Plaintiffs have indicated that they are no longer pursuing a number of claims and projects thereby reducing their total claims to eight relating to four projects. The parties have filed motions for summary judgment with regard to issues affecting the remaining claims, and the motions for summary judgment are fully briefed. Oral argument on all pending motions for summary judgment is scheduled for December 1, 2015, and a bench trial is scheduled for May 31, 2016. We intend to vigorously defend this lawsuit. At this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision. Billings Refinery Outage Claim In August 2014, we received a demand letter from a refinery in Billings claiming that it had sustained damages of approximately $48.5 million as a result of a January 2014 electrical outage. We dispute the claim and intend to vigorously defend against it. We reported the refinery's claim to our insurance carrier under our primary insurance policy, which has a $2.0 million retention. This matter is in the initial stages and we cannot predict an outcome or estimate the amount or range of loss, if any, that would be associated with an adverse result. 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 Basi22
Nature of Operations and Basis of Consolidation (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
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 Facility (QF) plants. We identified one QF contract that may constitute a VIE. We entered into a 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 $279.5 million through 2024 . |
Acquisitions (Tables)
Acquisitions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | Purchase Price Allocation (in millions) Assets Acquired Property Plant and Equipment $ 143.0 Other Prepayments 0.1 Total Assets Acquired $ 143.1 Liabilities Assumed Other Current Liabilities $ 0.3 Total Liabilities Assumed $ 0.3 Total Purchase Price $ 142.8 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended September 30, 2015 2014 Income Before Income Taxes $ 30,187 $ 11,754 Income tax calculated at 35% federal statutory rate 10,565 35.0 % 4,114 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (857 ) (2.8 ) (108 ) (0.9 ) Release of unrecognized tax benefit — — (12,607 ) (107.3 ) Flow-through repairs deductions (2,779 ) (9.2 ) (3,413 ) (29.0 ) Production tax credits (733 ) (2.4 ) (300 ) (2.6 ) Plant and depreciation of flow through items (374 ) (1.2 ) (685 ) (5.8 ) Prior year permanent return to accrual adjustments 1,025 3.4 (5,172 ) (44.0 ) Other, net (458 ) (1.6 ) (266 ) (2.3 ) (4,176 ) (13.8 ) (22,551 ) (191.9 ) Income tax expense (benefit) $ 6,389 21.2 % $ (18,437 ) (156.9 )% Nine Months Ended September 30, 2015 2014 Income Before Income Taxes $ 130,812 $ 74,277 Income tax calculated at 35% federal statutory rate 45,784 35.0 % 25,997 35.0 % Permanent or flow through adjustments: State income, net of federal provisions (329 ) (0.3 ) 257 0.3 Flow-through repairs deductions (17,240 ) (13.2 ) (14,885 ) (20.0 ) Release of unrecognized tax benefit — — (12,607 ) (17.0 ) Production tax credits (2,645 ) (2.0 ) (2,054 ) (2.8 ) Plant and depreciation of flow through items (1,000 ) (0.8 ) (182 ) (0.2 ) Prior year permanent return to accrual adjustments 1,025 0.8 (5,172 ) (7.0 ) Other, net (979 ) (0.7 ) (594 ) (0.7 ) (21,168 ) (16.2 ) (35,237 ) (47.4 ) Income tax expense (benefit) $ 24,616 18.8 % $ (9,240 ) (12.4 )% |
Goodwill (Tables)
Goodwill (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Goodwill [Abstract] | |
Schedule of Goodwill [Table Text Block] | Goodwill by segment is as follows for both September 30, 2015 and December 31, 2014 (in thousands): Electric $ 241,100 Natural gas 114,028 $ 355,128 |
Comprehensive Income (Loss) (Ta
Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | |
Schedule of Comprehensive Income (Loss) [Table Text Block] | The following tables display the components of Other Comprehensive Income (Loss) (in thousands): Three Months Ended September 30, 2015 September 30, 2014 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 233 $ — $ 233 $ 134 $ — $ 134 Reclassification of net gains on derivative instruments (901 ) 346 (555 ) (297 ) 114 (183 ) Unrealized loss on cash flow hedging derivatives — — — (1,644 ) 633 (1,011 ) Other comprehensive (loss) income $ (668 ) $ 346 $ (322 ) $ (1,807 ) $ 747 $ (1,060 ) Nine Months Ended September 30, 2015 September 30, 2014 Before-Tax Amount Tax Benefit Net-of-Tax Amount Before-Tax Amount Tax Benefit Net-of-Tax Amount Foreign currency translation adjustment $ 445 $ — $ 445 $ 155 $ — $ 155 Reclassification of net gains on derivative instruments (1,187 ) 452 (735 ) (891 ) 342 (549 ) Unrealized loss on cash flow hedging derivatives — — — (1,644 ) 633 (1,011 ) Other comprehensive (loss) income $ (742 ) $ 452 $ (290 ) $ (2,380 ) $ 975 $ (1,405 ) |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Balances by classification included within accumulated other comprehensive income (loss) (AOCI) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): September 30, 2015 December 31, 2014 Foreign currency translation $ 1,242 $ 797 Derivative instruments designated as cash flow hedges (9,051 ) (8,316 ) Pension and postretirement medical plans (1,247 ) (1,247 ) Accumulated other comprehensive loss $ (9,056 ) $ (8,766 ) |
Accumulated Other Comprehensive Income [Table Text Block] | The following tables display the changes in AOCI by component, net of tax (in thousands): September 30, 2015 Three Months Ended 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 $ (8,496 ) $ (1,247 ) $ 1,009 $ (8,734 ) Other comprehensive income before reclassifications — — 233 233 Amounts reclassified from AOCI Interest Expense (555 ) — — (555 ) Net current-period other comprehensive (loss) income (555 ) — 233 (322 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) September 30, 2014 Three Months Ended 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 $ 3,147 $ (1,329 ) $ 553 $ 2,371 Other comprehensive income before reclassifications (1,011 ) — 134 (877 ) Amounts reclassified from AOCI Interest Expense (183 ) — — (183 ) Net current-period other comprehensive (loss) income (1,194 ) — 134 (1,060 ) Ending balance $ 1,953 $ (1,329 ) $ 687 $ 1,311 September 30, 2015 Nine Months Ended 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 $ (8,316 ) $ (1,247 ) $ 797 $ (8,766 ) Other comprehensive income before reclassifications — — 445 445 Amounts reclassified from AOCI Interest Expense (735 ) — — (735 ) Net current-period other comprehensive (loss) income (735 ) — 445 (290 ) Ending balance $ (9,051 ) $ (1,247 ) $ 1,242 $ (9,056 ) September 30, 2014 Nine Months Ended 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 $ 3,513 $ (1,329 ) $ 532 $ 2,716 Other comprehensive income before reclassifications (1,011 ) — 155 (856 ) Amounts reclassified from AOCI Interest Expense (549 ) — — (549 ) Net current-period other comprehensive (loss) income (1,560 ) — 155 (1,405 ) Ending balance $ 1,953 $ (1,329 ) $ 687 $ 1,311 |
Risk Management and Hedging A27
Risk Management and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 AOCI to Income Amount Reclassified from AOCI into Income during the Nine Months Ended September 30, 2015 Interest rate contracts Interest Expense $ 1,187 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 8 - 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) September 30, 2015 Restricted cash $ 13,892 $ — $ — $ — $ 13,892 Rabbi trust investments 23,760 — — — 23,760 Total $ 37,652 $ — $ — $ — $ 37,652 December 31, 2014 Restricted cash $ 13,140 $ — $ — $ — $ 13,140 Rabbi trust investments 21,594 — — — 21,594 Total $ 34,734 $ — $ — $ — $ 34,734 |
Fair Value Financial Instruments [Table Text Block] | The estimated fair value of financial instruments is summarized as follows (in thousands): September 30, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,782,123 $ 1,862,952 $ 1,662,099 $ 1,817,642 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 238,513 $ 34,226 $ — $ — $ 272,739 Cost of sales 66,197 7,380 — — 73,577 Gross margin 172,316 26,846 — — 199,162 Operating, general and administrative 58,298 19,843 1,155 — 79,296 Property and other taxes 28,648 7,062 2 — 35,712 Depreciation and depletion 28,476 7,209 8 — 35,693 Operating income (loss) 56,894 (7,268 ) (1,165 ) — 48,461 Interest expense (19,078 ) (2,562 ) (403 ) — (22,043 ) Other income 1,832 507 1,430 — 3,769 Income tax (expense) benefit (6,553 ) 1,883 (1,719 ) — (6,389 ) Net income (loss) $ 33,095 $ (7,440 ) $ (1,857 ) $ — $ 23,798 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 57,813 $ 14,341 $ — $ — $ 72,154 Three Months Ended September 30, 2014 Electric Gas Other Eliminations Total Operating revenues $ 212,430 $ 39,482 $ — $ — $ 251,912 Cost of sales 84,720 9,872 — — 94,592 Gross margin 127,710 29,610 — — 157,320 Operating, general and administrative 48,528 21,005 (1,425 ) — 68,108 Property and other taxes 20,413 7,357 3 — 27,773 Depreciation and depletion 23,174 7,270 8 — 30,452 Operating income (loss) 35,595 (6,022 ) 1,414 — 30,987 Interest expense (14,025 ) (2,627 ) (2,142 ) — (18,794 ) Other income (expense) 1,337 336 (2,112 ) — (439 ) Income tax benefit 5,235 926 12,276 — 18,437 Net income (loss) $ 28,142 $ (7,387 ) $ 9,436 $ — $ 30,191 Total assets $ 2,694,883 $ 1,170,843 $ 8,572 $ — $ 3,874,298 Capital expenditures $ 62,054 $ 12,011 $ — $ — $ 74,065 Nine Months Ended September 30, 2015 Electric Gas Other Eliminations Total Operating revenues $ 695,921 $ 193,389 $ — $ — $ 889,310 Cost of sales 196,034 69,461 — — 265,495 Gross margin 499,887 123,928 — — 623,815 Operating, general and administrative 179,191 63,554 (20,606 ) — 222,139 Property and other taxes 78,987 21,958 8 — 100,953 Depreciation and depletion 85,523 21,691 25 — 107,239 Operating income 156,186 16,725 20,573 — 193,484 Interest expense (58,524 ) (8,304 ) (1,273 ) — (68,101 ) Other income (expense) 4,773 1,349 (693 ) — 5,429 Income tax expense (16,364 ) (1,621 ) (6,631 ) — (24,616 ) Net income $ 86,071 $ 8,149 $ 11,976 $ — $ 106,196 Total assets $ 4,169,423 $ 1,057,919 $ 7,736 $ — $ 5,235,078 Capital expenditures $ 171,800 $ 31,524 $ — $ — $ 203,324 Nine Months Ended September 30, 2014 Electric Gas Other Eliminations Total Operating revenues $ 652,951 $ 238,965 $ — $ — $ 891,916 Cost of sales 273,754 100,740 — — 374,494 Gross margin 379,197 138,225 — — 517,422 Operating, general and administrative 144,933 66,254 3,370 — 214,557 Property and other taxes 61,322 22,961 9 — 84,292 Depreciation and depletion 69,398 21,716 25 — 91,139 Operating income (loss) 103,544 27,294 (3,404 ) — 127,434 Interest expense (43,663 ) (7,979 ) (6,245 ) — (57,887 ) Other income 3,204 876 650 — 4,730 Income tax (expense) benefit (575 ) (3,334 ) 13,149 — 9,240 Net income $ 62,510 $ 16,857 $ 4,150 $ — $ 83,517 Total assets $ 2,694,883 $ 1,170,843 $ 8,572 $ — $ 3,874,298 Capital expenditures $ 161,718 $ 24,367 $ — $ — $ 186,085 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
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 September 30, 2015 September 30, 2014 Basic computation 47,065,082 39,141,148 Dilutive effect of Performance share awards (1) 245,463 139,655 Diluted computation 47,310,545 39,280,803 Nine Months Ended September 30, 2015 September 30, 2014 Basic computation 47,028,924 39,045,790 Dilutive effect of Performance share awards (1) 245,460 141,560 Diluted computation 47,274,384 39,187,350 ______________ (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) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [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 September 30, Three Months Ended September 30, 2015 2014 2015 2014 Components of Net Periodic Benefit Cost (Income) Service cost $ 3,091 $ 2,708 $ 132 $ 116 Interest cost 6,544 6,536 197 214 Expected return on plan assets (7,890 ) (7,377 ) (242 ) (245 ) Amortization of prior service cost 62 62 (471 ) (500 ) Recognized actuarial loss 2,659 530 96 87 Net Periodic Benefit Cost (Income) $ 4,466 $ 2,459 $ (288 ) $ (328 ) Pension Benefits Other Postretirement Benefits Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Components of Net Periodic Benefit Cost (Income) Service cost $ 9,272 $ 8,123 $ 395 $ 349 Interest cost 19,631 19,610 590 644 Expected return on plan assets (23,671 ) (22,130 ) (727 ) (736 ) Amortization of prior service cost 185 185 (1,412 ) (1,499 ) Recognized actuarial loss 7,976 1,589 289 261 Net Periodic Benefit Cost (Income) $ 13,393 $ 7,377 $ (865 ) $ (981 ) |
Nature of Operations and Basi32
Nature of Operations and Basis of Consolidation (Details) $ in Millions | Sep. 30, 2015USD ($)watts | Dec. 31, 2014customers |
Number of customers | 692,600 | |
Number of megawatts of qualifying facility | watts | 35 | |
Estimated aggregate gross contractual payments for qualifying facilities through 2024 | $ | $ 279.5 |
Acquisitions (Details)
Acquisitions (Details) - USD ($) $ in Millions | 1 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2015 | Nov. 30, 2014 | |
Business Acquisition [Line Items] | |||
Purchase price | $ 904 | ||
Kerr Project [Member] | |||
Business Acquisition [Line Items] | |||
Purchase price | 30 | ||
Estimated conveyance price of hydroelectric facility | 18.3 | ||
Estimated reference price less conveyance price | $ 11.7 | ||
South Dakota Wind Generation [Member] | |||
Business Acquisition [Line Items] | |||
Purchase price | $ 143 | ||
Annual collected amount through rates | $ 9 |
Acquisitions Purchase Price All
Acquisitions Purchase Price Allocation Table (Details) $ in Millions | Sep. 30, 2015USD ($) |
Assets Acquired | |
Property Plant and Equipment | $ 143 |
Other Prepayments | 0.1 |
Total Assets Acquired | 143.1 |
Liabilities Assumed | |
Other Current Liabilities | 0.3 |
Total Liabilities Assumed | 0.3 |
Total Purchase Price | $ 142.8 |
Regulatory Matters (Details)
Regulatory Matters (Details) $ in Millions | 1 Months Ended | 9 Months Ended |
Sep. 30, 2015USD ($) | Sep. 30, 2015USD ($) | |
South Dakota Electric Rate Filing [Member] | ||
Requested rate increase (decrease) | $ 26.5 | |
Requested return on rate base | 7.67% | 7.67% |
Rate base | $ 447.4 | $ 447.4 |
Increase in base rates | $ 20.2 | |
Authorized rate of return | 7.24% | 7.24% |
Annual collected amount through rates | $ 9 | |
Montana Natural Gas Production Assets [Member] | Revenue Subject to Refund [Member] | ||
Deferred revenue | 1.6 | $ 1.6 |
Demand side management [Member] | ||
Demand side management lost revenue recognized | 7.1 | 7.1 |
Demand side management [Member] | Revenue Subject to Refund [Member] | ||
Deferred revenue | 11.8 | 11.8 |
Dave Gates Generating Station [Member] | Revenue Subject to Refund [Member] | ||
Deferred revenue | $ 27.3 | 27.3 |
Regulatory Reviews of Filings [Member] | ||
CU4 incremental market purchases identified for further review | $ 11 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Income Tax Contingency [Line Items] | ||
Unrecognized tax benefit more likely than not percentage threshold | 50.00% | |
Unrecognized tax benefits | $ 96.4 | |
Unrecognized tax benefits that would impact effective tax rate | 65.3 | |
Interest expense or penalties, uncertain tax positions | 0 | |
Accrued interest, uncertain tax positions | $ 0 | $ 0 |
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 | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Effective tax rate reconciliation | ||||
Income Before Income Taxes | $ 30,187 | $ 11,754 | $ 130,812 | $ 74,277 |
Income tax calculated at 35% federal statutory rate | $ 10,565 | $ 4,114 | $ 45,784 | $ 25,997 |
Income tax calculated at 35% federal statutory rate | 35.00% | 35.00% | 35.00% | 35.00% |
State income, net of federal provisions | $ (857) | $ (108) | $ (329) | $ 257 |
State income, net of federal provisions | (2.80%) | (0.90%) | (0.30%) | 0.30% |
Release of unrecognized tax benefit | $ 0 | $ (12,607) | $ 0 | $ (12,607) |
Release of unrecognized tax benefit | 0.00% | (107.30%) | 0.00% | (17.00%) |
Flow-through repairs deductions | $ (2,779) | $ (3,413) | $ (17,240) | $ (14,885) |
Flow-through repairs deductions | (9.20%) | (29.00%) | (13.20%) | (20.00%) |
Production tax credits | $ (733) | $ (300) | $ (2,645) | $ (2,054) |
Production tax credits | (2.40%) | (2.60%) | (2.00%) | (2.80%) |
Plant and depreciation of flow through items | $ (374) | $ (685) | $ (1,000) | $ (182) |
Plant and depreciation of flow through items | (1.20%) | (5.80%) | (0.80%) | (0.20%) |
Prior year permanent return to accrual adjustments | $ 1,025 | $ (5,172) | $ 1,025 | $ (5,172) |
Prior year permanent return to accrual adjustments | 3.40% | (44.00%) | 0.80% | (7.00%) |
Other, net | $ (458) | $ (266) | $ (979) | $ (594) |
Other, net | (1.60%) | (2.30%) | (0.70%) | (0.70%) |
Total Other Reconciling Items | $ (4,176) | $ (22,551) | $ (21,168) | $ (35,237) |
Total Other Reconciling Items | (13.80%) | (191.90%) | (16.20%) | (47.40%) |
Income tax expense (benefit) | $ 6,389 | $ (18,437) | $ 24,616 | $ (9,240) |
Income tax expense (benefit) | 21.20% | (156.90%) | 18.80% | (12.40%) |
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 | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Goodwill [Line Items] | ||
Change in goodwill | $ 0 | |
Goodwill | 355,128 | $ 355,128 |
Electric [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 241,100 | 241,100 |
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 | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Other Comprehensive Income (Loss), before Tax [Abstract] | |||||
Foreign currency translation adjustment | $ 233 | $ 134 | $ 445 | $ 155 | |
Reclassification of net gains on derivative instruments | (901) | (297) | (1,187) | (891) | |
Unrealized loss on cash flow hedging derivatives | 0 | (1,644) | 0 | (1,644) | |
Other comprehensive (loss) income | (668) | (1,807) | (742) | (2,380) | |
Other Comprehensive Income (Loss), Tax [Abstract] | |||||
Foreign currency translation adjustment | 0 | 0 | 0 | 0 | |
Reclassification of net gains on derivative instruments | 346 | 114 | 452 | 342 | |
Unrealized loss on cash flow hedging derivatives | 0 | 633 | 0 | 633 | |
Other comprehensive loss | 346 | 747 | 452 | 975 | |
Other comprehensive income (loss), net of tax: | |||||
Foreign currency translation adjustment | 233 | 134 | 445 | 155 | |
Reclassification of net gains on derivative instruments | (555) | (183) | (735) | (549) | |
Unrealized loss on cash flow hedging derivatives | 0 | (1,011) | 0 | (1,011) | |
Net current-period other comprehensive (loss) income | (322) | $ (1,060) | (290) | $ (1,405) | |
Accumulated Other Comprehensive Income [Abstract] | |||||
Foreign currency translation | 1,242 | 1,242 | $ 797 | ||
Derivative instruments designated as cash flow hedges | (9,051) | (9,051) | (8,316) | ||
Pension and postretirement medical plans | (1,247) | (1,247) | (1,247) | ||
Accumulated other comprehensive loss | $ (9,056) | $ (9,056) | $ (8,766) |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income by Component (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Accumulated Other Comprehensive Income [Line Items] | ||||
Beginning balance | $ (8,766) | |||
Net current-period other comprehensive (loss) income | $ (322) | $ (1,060) | (290) | $ (1,405) |
Ending balance | (9,056) | (9,056) | ||
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Beginning balance | (8,496) | 3,147 | (8,316) | 3,513 |
Other comprehensive income before reclassifications | 0 | (1,011) | 0 | (1,011) |
Net current-period other comprehensive (loss) income | (555) | (1,194) | (735) | (1,560) |
Ending balance | (9,051) | 1,953 | (9,051) | 1,953 |
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Interest Expense [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Amounts reclassified from AOCI | (555) | (183) | (735) | (549) |
Pension and Postretirement Medical Plans | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Beginning balance | (1,247) | (1,329) | (1,247) | (1,329) |
Other comprehensive income before reclassifications | 0 | 0 | 0 | 0 |
Net current-period other comprehensive (loss) income | 0 | 0 | 0 | 0 |
Ending balance | (1,247) | (1,329) | (1,247) | (1,329) |
Pension and Postretirement Medical Plans | Interest Expense [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Amounts reclassified from AOCI | 0 | 0 | 0 | 0 |
Accumulated Translation Adjustment [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Beginning balance | 1,009 | 553 | 797 | 532 |
Other comprehensive income before reclassifications | 233 | 134 | 445 | 155 |
Net current-period other comprehensive (loss) income | 233 | 134 | 445 | 155 |
Ending balance | 1,242 | 687 | 1,242 | 687 |
Accumulated Translation Adjustment [Member] | Interest Expense [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Amounts reclassified from AOCI | 0 | 0 | 0 | 0 |
Other Comprehensive Income (Loss) [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Beginning balance | (8,734) | 2,371 | (8,766) | 2,716 |
Other comprehensive income before reclassifications | 233 | (877) | 445 | (856) |
Net current-period other comprehensive (loss) income | (322) | (1,060) | (290) | (1,405) |
Ending balance | (9,056) | 1,311 | (9,056) | 1,311 |
Other Comprehensive Income (Loss) [Member] | Interest Expense [Member] | ||||
Accumulated Other Comprehensive Income [Line Items] | ||||
Amounts reclassified from AOCI | $ (555) | $ (183) | $ (735) | $ (549) |
Risk Management and Hedging A41
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Derivative [Line Items] | ||
Interest rate swaps outstanding | $ 0 | |
Physical purchase and sale of gas and electricity at fixed prices | 0 | $ 0 |
Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Pre-tax gain on cash flow hedges remaining in AOCI | 15,000 | |
Pre-tax gain on cash flow hedge to be reclassified within twelve months from AOCI to interest expense | 300 | |
Interest Rate Swap [Member] | Interest Expense [Member] | ||
Derivative [Line Items] | ||
Amount of gain reclassified from AOCI | $ 1,187 |
Fair Value Recurring Basis (Det
Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
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] | ||
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] | 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 | 13,892 | 13,140 |
Rabbi trust investments | 23,760 | 21,594 |
Total | 37,652 | 34,734 |
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 |
Fair Value, Measurements, Recurring [Member] | Total Net Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Restricted cash | 13,892 | 13,140 |
Rabbi trust investments | 23,760 | 21,594 |
Total | $ 37,652 | $ 34,734 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Finanical Insruments (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying value | $ 1,782,123 | $ 1,662,099 |
Long-term debt, fair value | $ 1,862,952 | $ 1,817,642 |
Financing Activities (Details)
Financing Activities (Details) - Secured Debt [Member] $ in Millions | 9 Months Ended |
Sep. 30, 2015USD ($) | |
Secured Debt South Dakota Due 2040 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 70 |
Debt Instrument, Interest Rate, Stated Percentage | 4.26% |
Debt Instrument, Maturity Date | Sep. 29, 2040 |
Secured Debt Montana Due 2025 and 2045 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 200 |
Secured Debt Montana Due 2025 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 75 |
Debt Instrument, Interest Rate, Stated Percentage | 3.11% |
Debt Instrument, Maturity Date | Jul. 1, 2025 |
Secured Debt Montana Due 2045 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 125 |
Debt Instrument, Interest Rate, Stated Percentage | 4.11% |
Debt Instrument, Maturity Date | Jul. 1, 2045 |
Secured Debt Montana Due 2016 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 6.04% |
Debt Instrument, Maturity Date | Sep. 1, 2016 |
Debt Instrument, Repurchase Amount | $ 150 |
Financing Activities Equity Ins
Financing Activities Equity Instrument (Details) - Beethoven Acquisition [Member] - Scenario, Forecast [Member] $ / shares in Units, $ in Millions | 3 Months Ended |
Dec. 31, 2015USD ($)$ / sharesshares | |
Business Acquisition, Equity Interests Issued or Issuable [Line Items] | |
Issuance of shares, value | $ | $ 57 |
Issuance of shares | 1,100,000 |
Common stock average share price | $ / shares | $ 51.81 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | |||||
Operating revenues | $ 272,739 | $ 251,912 | $ 889,310 | $ 891,916 | |
Cost of sales | 73,577 | 94,592 | 265,495 | 374,494 | |
Gross margin | 199,162 | 157,320 | 623,815 | 517,422 | |
Operating, general and administrative | 79,296 | 68,108 | 222,139 | 214,557 | |
Property and other taxes | 35,712 | 27,773 | 100,953 | 84,292 | |
Depreciation and depletion | 35,693 | 30,452 | 107,239 | 91,139 | |
Operating income (loss) | 48,461 | 30,987 | 193,484 | 127,434 | |
Interest expense | (22,043) | (18,794) | (68,101) | (57,887) | |
Other income | 3,769 | (439) | 5,429 | 4,730 | |
Income tax (expense) benefit | (6,389) | 18,437 | (24,616) | 9,240 | |
Net Income | 23,798 | 30,191 | 106,196 | 83,517 | |
Total assets | 5,235,078 | 3,874,298 | 5,235,078 | 3,874,298 | $ 4,973,943 |
Capital expenditures | 72,154 | 74,065 | 203,324 | 186,085 | |
Electric [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 238,513 | 212,430 | 695,921 | 652,951 | |
Cost of sales | 66,197 | 84,720 | 196,034 | 273,754 | |
Gross margin | 172,316 | 127,710 | 499,887 | 379,197 | |
Operating, general and administrative | 58,298 | 48,528 | 179,191 | 144,933 | |
Property and other taxes | 28,648 | 20,413 | 78,987 | 61,322 | |
Depreciation and depletion | 28,476 | 23,174 | 85,523 | 69,398 | |
Operating income (loss) | 56,894 | 35,595 | 156,186 | 103,544 | |
Interest expense | (19,078) | (14,025) | (58,524) | (43,663) | |
Other income | 1,832 | 1,337 | 4,773 | 3,204 | |
Income tax (expense) benefit | (6,553) | 5,235 | (16,364) | (575) | |
Net Income | 33,095 | 28,142 | 86,071 | 62,510 | |
Total assets | 4,169,423 | 2,694,883 | 4,169,423 | 2,694,883 | |
Capital expenditures | 57,813 | 62,054 | 171,800 | 161,718 | |
Natural Gas [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Operating revenues | 34,226 | 39,482 | 193,389 | 238,965 | |
Cost of sales | 7,380 | 9,872 | 69,461 | 100,740 | |
Gross margin | 26,846 | 29,610 | 123,928 | 138,225 | |
Operating, general and administrative | 19,843 | 21,005 | 63,554 | 66,254 | |
Property and other taxes | 7,062 | 7,357 | 21,958 | 22,961 | |
Depreciation and depletion | 7,209 | 7,270 | 21,691 | 21,716 | |
Operating income (loss) | (7,268) | (6,022) | 16,725 | 27,294 | |
Interest expense | (2,562) | (2,627) | (8,304) | (7,979) | |
Other income | 507 | 336 | 1,349 | 876 | |
Income tax (expense) benefit | 1,883 | 926 | (1,621) | (3,334) | |
Net Income | (7,440) | (7,387) | 8,149 | 16,857 | |
Total assets | 1,057,919 | 1,170,843 | 1,057,919 | 1,170,843 | |
Capital expenditures | 14,341 | 12,011 | 31,524 | 24,367 | |
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 | 1,155 | (1,425) | (20,606) | 3,370 | |
Property and other taxes | 2 | 3 | 8 | 9 | |
Depreciation and depletion | 8 | 8 | 25 | 25 | |
Operating income (loss) | (1,165) | 1,414 | 20,573 | (3,404) | |
Interest expense | (403) | (2,142) | (1,273) | (6,245) | |
Other income | 1,430 | (2,112) | (693) | 650 | |
Income tax (expense) benefit | (1,719) | 12,276 | (6,631) | 13,149 | |
Net Income | (1,857) | 9,436 | 11,976 | 4,150 | |
Total assets | 7,736 | 8,572 | 7,736 | 8,572 | |
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 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Basic computation | 47,065,082 | 39,141,148 | 47,028,924 | 39,045,790 |
Dilutive effect of performance share awards (1) | 245,463 | 139,655 | 245,460 | 141,560 |
Diluted computation | 47,310,545 | 39,280,803 | 47,274,384 | 39,187,350 |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | $ 3,091 | $ 2,708 | $ 9,272 | $ 8,123 |
Interest cost | 6,544 | 6,536 | 19,631 | 19,610 |
Expected return on plan assets | (7,890) | (7,377) | (23,671) | (22,130) |
Amortization of prior service cost | 62 | 62 | 185 | 185 |
Recognized actuarial loss | 2,659 | 530 | 7,976 | 1,589 |
Net Periodic Benefit Cost (Income) | 4,466 | 2,459 | 13,393 | 7,377 |
Other Postretirement Benefits [Member] | ||||
Components of Net Periodic Benefit Cost (Income) [Abstract] | ||||
Service cost | 132 | 116 | 395 | 349 |
Interest cost | 197 | 214 | 590 | 644 |
Expected return on plan assets | (242) | (245) | (727) | (736) |
Amortization of prior service cost | (471) | (500) | (1,412) | (1,499) |
Recognized actuarial loss | 96 | 87 | 289 | 261 |
Net Periodic Benefit Cost (Income) | $ (288) | $ (328) | $ (865) | $ (981) |
Commitments and Contingencies E
Commitments and Contingencies Environmental (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2015USD ($) | Sep. 30, 2015USD ($) | Jul. 01, 2018 | |
Colstrip Unit 4 [Member] | |||
Jointly owned utility plant ownership percentage | 30.00% | 30.00% | |
Environmental Obligation, Estimated Capital Expenditures | $ 90 | $ 90 | |
Neal 4 Generating Facility [Member] | |||
Jointly owned utility plant ownership percentage | 8.70% | 8.70% | |
Coyote Generating Facility [Member] | |||
Jointly owned utility plant ownership percentage | 10.00% | 10.00% | |
Environmental Obligation, Estimated Capital Expenditures | $ 9 | $ 9 | |
Big Stone Generating Facility [Member] | |||
Jointly owned utility plant ownership percentage | 23.40% | 23.40% | |
Environmental Obligation, Estimated Capital Expenditures | $ 384 | $ 384 | |
Joint ownership share of capitalized project costs | 95.1 | 95.1 | |
Environmental remediation obligations [Member] | |||
Environmental remediation obligation, minimum | 26.4 | 26.4 | |
Environmental remediation obligation, maximum | 35 | 35 | |
Accrual for environmental loss contingencies | 28.3 | 28.3 | |
Net recovery | 20.8 | ||
Coal Combustion Residuals (CCRs) [Member] | |||
Asset retirement obligation | 12 | $ 12 | |
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | |||
Number of years for environmental remediation obligation to be incurred | 5 years | ||
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member] | |||
Accrual for environmental loss contingencies | 23.4 | $ 23.4 | |
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | |||
Accrual for environmental loss contingencies | 10.4 | 10.4 | |
Environmental remediation obligation next 5 years | $ 7.5 | $ 7.5 | |
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) - Loss from Catastrophes [Member] $ in Millions | 1 Months Ended |
Aug. 31, 2014USD ($) | |
Loss Contingencies [Line Items] | |
Damages sought | $ 48.5 |
Retention amount | $ 2 |