Northwest Natural Holding 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Document Information [Line Items]
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Central Index Key	73,020
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	Northwest Natural Gas Co.
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		28,751,528
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Public Float			$ 1,695,121,435

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues [Abstract]
Operating revenues	$ 762,173	$ 675,967	$ 723,791
Operating expenses: [Abstract]
Cost of gas	324,795	260,588	327,305
Operations and maintenance	165,246	149,974	157,521
Environmental remediation	15,291	13,298	3,513
General taxes	32,012	30,538	30,281
Depreciation and amortization	85,578	82,289	80,923
Impairment of Long-Lived Assets	192,478	0	0
Total operating expenses	815,400	536,687	599,543
Income (loss) from operations	(53,227)	139,280	124,248
Other income (expense), net	5,348	(543)	7,747
Interest expense, net	38,501	39,128	42,539
Income (loss) before income taxes	(86,380)	99,609	89,456
Income tax expense (benefit)	(30,757)	40,714	35,753
Net income (loss)	(55,623)	58,895	53,703
Other comprehensive income: [Abstract]
Change in employee benefit plan liability, net of taxes of $735 for 2017, $452 for 2016, and ($988) for 2015	(2,059)	(744)	1,561
Amortization of non-qualified employee benefit plan liability, net of taxes of $374 for 2017, ($624) for 2016, and ($883) for 2015	572	955	1,353
Comprehensive income (loss)	$ (57,110)	$ 59,106	$ 56,617
Average common shares outstanding: [Abstract]
Basic	28,669	27,647	27,347
Diluted	28,669	27,779	27,417
Earnings per share of common stock: [Abstract]
Basic	$ (1.94)	$ 2.13	$ 1.96
Diluted	(1.94)	2.12	1.96
Dividends declared per share of common stock	$ 1.88	$ 1.87	$ 1.8625

Consolidated Statements of Com3

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in employee benefit plan liability, tax	$ 735	$ 452	$ (988)
Amortization of non-qualified employee benefit plan liability, tax	$ (374)	$ (624)	$ (883)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets: [Abstract]
Cash and cash equivalents	$ 3,472	$ 3,521
Accounts receivable	68,362	66,700
Accrued unbilled revenue	62,381	64,946
Allowance for uncollectible accounts	(956)	(1,290)
Regulatory Assets, Current	45,781	42,362
Derivative instruments	1,735	17,031
Inventories	47,973	54,129
Deferred Gas Cost	15,704	15,926
Other current assets	25,484	24,728
Total current assets	269,936	288,053
Non-current assets: [Abstract]
Property, Plant and Equipment, Gross	3,215,451	3,208,816
Less: Accumulated depreciation	960,477	947,916
Total property, plant, and equipment, net	2,254,974	2,260,900
Inventory, Gas in Storage Underground, Noncurrent	84,053	100,184
Regulatory assets	356,608	357,530
Derivative instruments	1,306	3,265
Other investments	66,363	68,376
Other non-current assets	6,506	1,493
Total non-current assets	2,769,810	2,791,748
Total assets	3,039,746	3,079,801
Current liabilities: [Abstract]
Short-term Debt	54,200	53,300
Current maturities of long-term debt	96,703	39,989
Accounts payable	112,308	85,664
Taxes accrued	18,883	12,149
Interest accrued	6,773	5,966
Regulatory Liability, Current	34,013	40,290
Derivative instruments	18,722	1,315
Other current liabilities	40,248	35,844
Total current liabilities	381,850	274,517
Long-term debt	683,184	679,334
Deferred credits and other non-current liabilities: [Abstract]
Deferred tax liabilities	270,526	557,085
Regulatory Liability, Noncurrent	586,093	349,319
Pension and other postretirement benefit liabilities	223,333	225,725
Derivative instruments	4,649	913
Other Liabilities, Noncurrent	147,335	142,411
Total deferred credits and other non-current liabilities	1,231,936	1,275,453
Commitments and contingencies (see Note 14 and Note 15)	0	0
Equity: [Abstract]
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,630 and 27,427 at December 31, 2016 and 2015, respectively	448,865	445,187
Retained earnings	302,349	412,261
Accumulated other comprehensive loss	(8,438)	(6,951)
Total equity	742,776	850,497
Total liabilities and equity	$ 3,039,746	$ 3,079,801

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Common Stock Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Outstanding	28,630,000	28,630,000
Common Stock, Shares, Issued	28,630,000	28,630,000
Commitments and Contingencies	$ 0	$ 0

Consolidated Statement of Share

Consolidated Statement of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock Including APIC [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Balance at Dec. 31, 2014	$ 767,321	$ 375,117	$ 402,280	$ (10,076)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive income	56,617	0		2,914
Net income (loss)	53,703		53,703
Dividends on common stock	(50,993)	0	(50,993)	0
Tax expense from employee stock plans	(118)	(118)	0	0
Stock-based compensation	3,277	3,277	0	0
Shares issued pursuant to equity based plans	4,868	4,868	0	0
Balance at Dec. 31, 2015	780,972	383,144	404,990	(7,162)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive income	59,106	0		211
Net income (loss)	58,895		58,895
Dividends on common stock	(51,624)	0	(51,624)	0
Stock-based compensation	2,924	2,924	0	0
Shares issued pursuant to equity based plans	6,358	6,358	0	0
Issuance of common stock, net of issuance costs	52,761	52,761	0	0
Balance at Dec. 31, 2016	850,497	445,187	412,261	(6,951)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive income	(57,110)	0		(1,487)
Net income (loss)	(55,623)		(55,623)
Dividends on common stock	(54,289)	0	(54,289)	0
Stock-based compensation	2,882	2,882	0	0
Shares issued pursuant to equity based plans	796	796	0	0
Balance at Dec. 31, 2017	$ 742,776	$ 448,865	$ 302,349	$ (8,438)

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities: [Abstract]
Net income (loss)	$ (55,623)	$ 58,895	$ 53,703
Adjustments to reconcile net income to cash provided by operations: [Abstract]
Depreciation and amortization	85,578	82,289	80,923
Regulatory amortization of gas reserves	16,353	15,525	17,991
Deferred Tax Liabilities, net	(52,414)	32,056	26,972
Qualified defined benefit pension plan expense	5,364	5,274	5,697
Contributions to qualified defined benefit pension plans	(19,430)	(14,470)	(14,120)
Deferred environmental (expenditures) recoveries, net	(13,716)	(10,469)	(10,568)
Regulatory disallowance of prior environmental cost deferrals	0	3,287	15,000
Amortization of environmental remediation	15,291	13,298	3,513
Impairment of Long-Lived Assets	192,478	0	0
Other	2,127	3,225	(1,613)
Changes in assets and liabilities: [Abstract]
Receivables, net	3,099	(7,484)	2,373
Inventories	5,571	16,620	6,964
Taxes Accrued	6,734	9,467	(6,541)
Accounts payable	1,424	12,380	(17,175)
Interest accrued	807	93	(206)
Deferred gas costs	17,122	(10,204)	31,918
Other, net	(4,061)	12,365	(10,143)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	(206,704)	(222,147)	(184,688)
Payments to Acquire Property, Plant, and Equipment [Abstract]
Capital expenditures	(213,595)	(139,511)	(118,320)
Other	(577)	2,882	3,022
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(214,172)	(136,629)	(115,298)
Financing activities: [Abstract]
Payments for Repurchase of Common Stock	(2,034)	(1,042)	0
Proceeds from Stock Options Exercised	4,819	8,404	3,875
Common Stock Issued, net	0	52,760	0
Long-term debt issued	100,000	150,000	0
Long-term debt retired	(40,000)	(25,000)	(60,000)
Change in short-term debt	900	(216,735)	35,335
Cash dividend payments on common stock	(53,957)	(51,508)	(49,243)
Other	(2,309)	(3,087)	(4,680)
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	7,419	(86,208)	(74,713)
(Decrease) Increase in cash and cash equivalents	(49)	(690)	(5,323)
Cash and cash equivalents, beginning of period	3,521	4,211	9,534
Cash and cash equivalents, end of period	3,472	3,521	4,211
Supplemental disclosure of cash flow information: [Abstract]
Interest paid, net of capitalization	34,787	36,023	39,634
Income Taxes Paid, Net of refunds	$ 14,780	$ (7,157)	$ 17,306

Organization and Principles of

Organization and Principles of Consolidation	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other . Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), Northwest Natural Water Company (NWN Water), FWC Merger Sub, Inc., and NWN Gas Reserves LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, include NWN Financial's investment in Kelso-Beaver Pipeline and NWN Energy's investment in Trail West Holdings, LLC (TWH), which is accounted for under the equity method. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities. Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	2. SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes. Actual amounts could differ from those estimates, and changes would most likely be reported in future periods. Management believes the estimates and assumptions used are reasonable . Industry Regulation Our principal businesses are the distribution of natural gas, which is regulated by the OPUC and WUTC, and natural gas storage services, which are regulated by either the FERC or the CPUC, and to a certain extent by the OPUC and WUTC. Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP. Our businesses regulated by the OPUC, WUTC, and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates). In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases. At December 31, the amounts deferred as regulatory assets and liabilities were as follows: Regulatory Assets In thousands 2017 2016 Current: Unrealized loss on derivatives (1) $ 18,712 $ 1,315 Gas costs 154 6,830 Environmental costs (2) 6,198 9,989 Decoupling (3) 11,227 13,067 Income taxes 2,218 4,378 Other (4) 7,272 6,783 Total current $ 45,781 $ 42,362 Non-current: Unrealized loss on derivatives (1) $ 4,649 $ 913 Pension balancing (5) 60,383 50,863 Income taxes 19,991 38,670 Pension and other postretirement benefit liabilities 179,824 183,035 Environmental costs (2) 72,128 63,970 Gas costs 84 89 Decoupling (3) 3,970 5,860 Other (4) 15,579 14,130 Total non-current $ 356,608 $ 357,530 Regulatory Liabilities In thousands 2017 2016 Current: Gas costs $ 14,886 $ 8,054 Unrealized gain on derivatives (1) 1,674 16,624 Decoupling (3) 322 — Other (4) 17,131 15,612 Total current $ 34,013 $ 40,290 Non-current: Gas costs $ 4,630 $ 1,021 Unrealized gain on derivatives (1) 1,306 3,265 Decoupling (3) 957 — Income taxes 213,306 — Accrued asset removal costs (6) 360,929 341,107 Other (4) 4,965 3,926 Total non-current $ 586,093 $ 349,319 (1) Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. (2) Refer to footnote (3) per the Deferred Regulatory Asset table in Note 15 for a description of environmental costs. (3) This deferral represents the margin adjustment resulting from differences between actual and expected volumes. (4) These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. (5) Refer to footnote (1) of the Net Periodic Benefit Cost table per Note 8 for information regarding the deferral of pension expenses. (6) Estimated costs of removal on certain regulated properties are collected through rates. See "Accounting Policies— Plant, Property, and Accrued Asset Removal Costs " below. The amortization period for our regulatory assets and liabilities ranges from less than one year to an indeterminable period. Our regulatory deferrals for gas costs payable are generally amortized over 12 months beginning each November 1 following the gas contract year during which the deferred gas costs are recorded. Similarly, most of our other regulatory deferred accounts are amortized over 12 months . However, certain regulatory account balances, such as income taxes, environmental costs, pension liabilities, and accrued asset removal costs, are large and tend to be amortized over longer periods once we have agreed upon an amortization period with the respective regulatory agency. We believe all costs incurred and deferred at December 31, 2017 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, we would be required to write-off the net unrecoverable balances in the period such determination is made. Environmental Regulatory Accounting See Note 15 for information about our SRRM and OPUC orders regarding implementation. New Accounting Standards We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations. Recently Issued Accounting Pronouncements DERIVATIVES AND HEDGING. On August 28, 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities." The purpose of the amendment is to more closely align hedge accounting with companies’ risk management strategies. The ASU amends the accounting for risk component hedging, the hedged item in fair value hedges of interest rate risk, and amounts excluded from the assessment of hedge effectiveness. The guidance also amends the recognition and presentation of the effect of hedging instruments and includes other simplifications of hedge accounting. The amendments in this update are effective for us beginning January 1, 2019. Early adoption is permitted. The amended presentation and disclosure guidance is required prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures. STOCK COMPENSATION. On May 10, 2017, the FASB issued ASU 2017-09, "Stock Compensation - Scope of Modification Accounting." The purpose of the amendment is to provide clarity, reduce diversity in practice and reduce the cost and complexity when applying the guidance in ASC 718, related to a change to the terms or conditions of a share-based payment award. The ASU amends the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. Specifically, an entity would not apply modification accounting if the fair value, vesting conditions, and classification of the awards are the same immediately before and after the modification. The amendments in this update are effective for us beginning January 1, 2018. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. We do not expect this standard to materially affect our financial statements and disclosures. RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. Only the service cost component of the net periodic benefit cost is eligible for capitalization. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. On December 28, 2017, the FERC issued Docket AI18-1-000 stating that it will allow entities to change their capitalization policy for regulatory accounting and reporting purposes to be consistent with the new US GAAP requirements. This change will be allowed as a one-time policy election upon adoption of the guidance. We have elected to adopt the new ASU for FERC regulatory accounting and reporting purposes. We anticipate that this adoption will reduce amounts capitalized to plant. However, this reduction will be largely offset by deferrals to our pension regulatory balancing mechanism, and therefore, we do not expect this standard to materially affect our financial position. STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. We do not expect this standard to materially affect our financial statements and disclosures. LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. On November 29, 2017, the FASB proposed an additional practical expedient that would allow entities to apply the transition requirements on the effective date of the standard. On January 25, 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842", to address the costs and complexity of applying the transition provisions of the new lease standard to land easements. This ASU provides an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under the current lease guidance. We are evaluating additional amendments reached by the FASB, and we are currently assessing our lease population and material contracts to determine the effect of this standard on our financial statements and disclosures. Refer to Note 14 for our current lease commitments. FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Any impacts as a result of the implementation of this ASU will be made through a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. We do not expect this standard to have a material impact to our financial statements and disclosures. REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or modified retrospective adoption method. The new standard is effective for us beginning January 1, 2018, and we have elected to adopt the standard using the modified retrospective approach. We are in the process of updating our accounting policies, processes, systems, and internal controls as a result of implementing the new standard. We have analyzed our revenue streams, material contracts with customers, and the expanded disclosure requirements under the new standard and determined that the standard will not have a material impact on our financial position, net income, or cash flows. Accounting Policies Plant, Property, and Accrued Asset Removal Costs Plant and property are stated at cost, including capitalized labor, materials, and overhead. In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest. AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “ AFUDC ” below). When constructed assets are subject to market-based rates rather than cost-based rates, the financing costs incurred during construction are included in capitalized interest in accordance with U.S. GAAP, not as regulatory financing costs under AFUDC. In accordance with long-standing regulatory treatment, our depreciation rates consist of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset’s estimated cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation. These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs as non-current regulatory liabilities rather than as accumulated depreciation on our consolidated balance sheets. In the rate setting process, the liability for removal costs is treated as a reduction to the net rate base on which the regulated utility has the opportunity to earn its allowed rate of return. The costs of utility plant retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. Gains from the sale of regulated assets are generally deferred and refunded to customers. For non-utility assets, we record a gain or loss upon the disposal of the property, and the gain or loss is recorded in operating income or loss in the consolidated statements of comprehensive income or loss. Our provision for depreciation of utility property, plant, and equipment is recorded under the group method on a straight-line basis with rates computed in accordance with depreciation studies approved by regulatory authorities. The weighted-average depreciation rate for utility assets in service was approximately 2.8 % for 2017 , 2016 , and 2015 , reflecting the approximate weighted-average economic life of the property. This includes 2017 weighted-average depreciation rates for the following asset categories: 2.7 % for transmission and distribution plant, 2.3 % for gas storage facilities, 4.4 % for general plant, and 2.7 % for intangible and other fixed assets. AFUDC. Certain additions to utility plant include AFUDC, which represents the net cost of debt and equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for ROE, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and on ROE funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rate was 5.5 % in 2017 , 0.7 % in 2016 , and 0.4% in 2015 . IMPAIRMENT OF LONG-LIVED ASSETS. We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Factors that would necessitate an impairment assessment of long-lived assets include a significant adverse change in the extent or manner in which the asset is used, a significant adverse change in legal factors or business climate that could affect the value of the asset, or a significant decline in the observable market value or expected future cash flows of the asset, among others. When such factors are present, we assess the recoverability by determining whether the carrying value of the asset will be recovered through expected future cash flows. An asset is determined to be impaired when the carrying value of the asset exceeds the expected undiscounted future cash flows from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss for the difference between the carrying value and the fair value of the long-lived assets. Fair value is estimated using appropriate valuation methodologies, which may include an estimate of discounted cash flows. In the fourth quarter of 2017, we recognized a non-cash pre-tax impairment of long-lived assets at the Gill Ranch Facility of $192.5 million , which is included in our gas storage segment. We determined circumstances existed that indicated the carrying value of the assets may not be recoverable. Those circumstances included the completion of a comprehensive strategic review process that evaluated various alternatives including a potential sale, as well as contracting for available storage at lower than anticipated values for the coming storage year. Given these considerations, management was required to re-evaluate the estimated cash flows from our interests in the Gill Ranch Facility, and has determined that those estimated cash flows are no longer sufficient to cover the carrying value of the assets. We did not recognize any impairments in 2016 or 2015. We used the income approach to estimate fair value, using the estimated future net cash flows of the Gill Ranch Facility. We also compared the results of the income approach to our own recent sale process experience and recent market comparable transactions in order to estimate fair value. Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with original maturity dates of three months or less. At December 31, 2017 and 2016 , outstanding checks of approximately $ 4.8 million and $ 2.9 million , respectively, were included in accounts payable. Revenue Recognition and Accrued Unbilled Revenue Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of the gas commodity or service to customers. Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenue). Accrued unbilled revenue is dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer use by billing cycle, and weather factors. Accrued unbilled revenue is reversed the following month when actual billings occur. Our accrued unbilled revenue at December 31, 2017 and 2016 was $ 62.4 million and $64.9 million , respectively. Non-utility revenues are derived primarily from the gas storage segment. At our Mist underground storage facility, revenues are primarily firm service revenues in the form of fixed monthly reservation charges. At the Gill Ranch Facility, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. In addition, we also have asset management service revenue from an independent energy marketing company that optimizes commodity, storage, and pipeline capacity release transactions. Under this agreement, guaranteed asset management revenue is recognized using a straight-line, pro-rata methodology over the term of each contract. Revenues earned above the guaranteed amount are recognized as they are earned. Revenue Taxes Revenue-based taxes are primarily franchise taxes, which are collected from customers and remitted to taxing authorities. Revenue taxes are included in operating revenues in the statement of comprehensive income or loss. Revenue taxes were $19.1 million , $17.1 million , and $18.0 million for 2017 , 2016 , and 2015 , respectively. Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to utility customers, plus amounts due for gas storage services. We establish an allowance for uncollectible accounts (allowance) for trade receivables, including accrued unbilled revenue, based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues. A specific allowance is established and recorded for large individual customer receivables when amounts are identified as unlikely to be partially or fully recovered. Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed uncollectible. Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer creditworthiness, and natural gas prices. The allowance for uncollectible accounts is adjusted quarterly, as necessary, based on information currently available. Inventories Utility gas inventories, which consist of natural gas in storage for the utility, are stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates. Utility gas inventories injected into storage are priced in inventory based on actual purchase costs. Utility gas inventories withdrawn from storage are charged to cost of gas during the current period they are withdrawn at the weighted-average inventory cost. Gas storage inventories, which primarily represent inventories at the Gill Ranch Facility, mainly consist of natural gas received as fuel-in-kind from storage customers. Gas storage inventories are valued at the lower of average cost or net realizable value. Cushion gas is not included in our inventory balances, is recorded at original cost, and is classified as a long-term plant asset. Materials and supplies inventories consist of both utility and non-utility inventories and are stated at the lower of average cost or net realizable value. Our utility and gas storage inventories totaled $ 36.7 million and $ 42.7 million at December 31, 2017 and 2016 , respectively. At December 31, 2017 and 2016 , our materials and supplies inventories totaled $ 11.3 million and $ 11.4 million , respectively. Gas Reserves Gas reserves are payments to acquire and produce natural gas reserves. Gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. The current portion is calculated based on expected gas deliveries within the next fiscal year. We recognize regulatory amortization of this asset on a volumetric basis calculated using the estimated gas reserves and the estimated therms extracted and sold each month. The amortization of gas reserves is recorded to cost of gas along with gas production revenues and production costs. See Note 11 . Derivatives Derivatives are measured at fair value and recognized as either assets or liabilities on the balance sheet. Changes in the fair value of the derivatives are recognized currently in earnings unless specific regulatory or hedge accounting criteria are met. Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable. In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates. Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles. Our financial derivatives generally qualify for deferral under regulatory accounting. Our index-priced physical derivative contracts also qualify for regulatory deferral accounting treatment. Derivative contracts entered into for utility requirements after the annual PGA rate has been set and maturing during the PGA year are subject to the PGA incentive sharing mechanism. In Oregon we participate in a PGA sharing mechanism under which we are required to select either an 80% or 90% deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20% or 10% of gas cost differences compared to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2017 , 2016 , and 2015 , we selected the 90% , 90% , and 80% deferral of gas cost differences, respectively. In Washington, 100% of the differences between the PGA prices and actual gas costs are deferred. See Note 13 . Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters. Our objective for using derivatives is to decrease the volatility of gas prices, earnings, and cash flows without speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined not to exceed acceptable tolerance levels, and are determined necessary to support normal business activities. We do not enter into derivative instruments for trading purposes. Fair Value In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets, and our derivative fair value measurements: • Level 1: Valuation is based on quoted prices for identical instruments traded in active markets; • Level 2: Valuation is based on quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market; and • Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect our own estimates of assumptions market participants would use in valuing the asset or liability. When developing fair value measurements, it is our policy to use quoted market prices whenever available or to maximize the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available. Fair values are primarily developed using industry-standard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market interest rates and yield curves; (g) credit spreads; and (h) other relevant economic measures. The Company considers liquid points for its natural gas hedging to be those points for which there are regularly published prices in a nationally recognized publication or where the instruments are traded on an exchange. Income Taxes We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the enactment date period unless a regulatory Order specifies deferral of the effect of the change in tax rates over a longer period of time. Deferred income tax assets and liabilities are also recognized for temporary differences where the deferred income tax benefits or expenses have previously been flowed through in the ratemaking process of the regulated utility. Regulatory tax assets and liabilities are recorded on these deferred tax assets and liabilities to the extent we believe they will be recoverable from or refunded to customers in future rates. Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant. We recognize interest and penalties related to unrecognized tax benefits, if any, within income tax expense and accrued interest and penalties within the related tax liability line in the consolidated balance sheets. No accrued interest or penalties for uncertain tax benefits have been recorded. See Note 9 . Environmental Contingencies Loss contingencies are recorded as liabilities when it is probable a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. With respect to environmental liabilities and related costs, we develop estimates based on a review of information available from numerous sources, including completed studies and site specific negotiations. It is our policy to accrue the full amount of such liability when information is sufficient to reasonably estimate the amount of probable liability. When information is not available to reasonably estimate the probable liability, or when only the range of probable liabilities can be estimated and no amount within the range is more likely than another, it is our policy to accrue at the low end of the range. Accordingly, due to numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the potential loss and the fact that the high end of the range cannot be reasonably estimated. See Note 15. Subsequent Events We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. We do not have any subsequent events to report.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share [Text Block]	3. EARNINGS PER SHARE Basic earnings or loss per share are computed using net income or loss and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock awards are excluded from the calculation of diluted earnings or loss per common share. Diluted earnings or loss per share are calculated as follows: In thousands, except per share data 2017 2016 2015 Net income (loss) $ (55,623 ) $ 58,895 $ 53,703 Average common shares outstanding - basic 28,669 27,647 27,347 Additional shares for stock-based compensation plans (See Note 6) — 132 70 Average common shares outstanding - diluted 28,669 27,779 27,417 Earnings (loss) per share of common stock - basic $ (1.94 ) $ 2.13 $ 1.96 Earnings (loss) per share of common stock - diluted $ (1.94 ) $ 2.12 $ 1.96 Additional information: Antidilutive shares 97 5 12

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information [Text Block]	4. SEGMENT INFORMATION We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility and our North Mist gas storage expansion in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial, non-utility appliance retail center operations, NWN Water, which is pursuing investments in the water sector itself and through its wholly-owned subsidiary FWC Merger Sub, Inc., and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. No individual customer accounts for over 10% of our operating revenues. Local Gas Distribution Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale, and delivery of natural gas and related services to customers in Oregon and southwest Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from producers and marketers, contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms, and conditions approved by the OPUC or WUTC. Gas distribution also includes taking customer-owned gas and transporting it from interstate pipeline connections, or city gates, to the customers’ end-use facilities for a fee, which is approved by the OPUC or WUTC. Approximately 89 % of our customers are located in Oregon and 11 % in Washington. On an annual basis, residential and commercial customers typically account for around 60% of our utility’s total volumes delivered and 90% of our utility’s margin. Industrial customers largely account for the remaining volumes and utility margin. A small amount of utility margin is also derived from miscellaneous services, gains or losses from an incentive gas cost sharing mechanism, and other service fees. Industrial sectors we serve include: pulp, paper, and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery, and textiles; the manufacture of asphalt, concrete, and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. Gas Storage Our gas storage segment includes natural gas storage services provided to customers primarily from two underground natural gas storage facilities: the Gill Ranch Facility and the non-utility portion of our Mist gas storage facility. In addition to earning revenue from customer storage contracts, we also use an independent energy marketing company to provide asset management services for utility and non-utility capacity, the results of which are included in this business segment. Mist Gas Storage Facility Earnings from non-utility assets at our Mist facility in Oregon are primarily related to firm storage capacity revenues. Earnings for the Mist facility also include revenue, net of amounts shared with utility customers, from management of utility assets at Mist and upstream pipeline capacity when not needed to serve utility customers. We retain 80 % of the pre-tax income from these services when the costs of the capacity have not been included in utility rates, or 33 % of the pre-tax income when the costs have been included in utility rates. The remaining 20 % and 67 %, respectively, are recorded to a deferred regulatory account for crediting back to utility customers. Gill Ranch Gas Storage Facility Gill Ranch has a joint project agreement with Pacific Gas and Electric Company (PG&E) to own and operate the Gill Ranch Facility, an underground natural gas storage facility near Fresno, California. Gill Ranch has a 75 % undivided ownership interest in the facility and is also the operator of the facility, which offers storage services to the California market at market-based rates, subject to CPUC regulation including, but not limited to, service terms and conditions and tariff regulations. Although this is a jointly-owned property, each owner is independently responsible for financing its share of the Gill Ranch Facility. As such, the impairment of long-lived assets at the Gill Ranch Facility recognized in 2017 reflects our ownership interest. Revenues are primarily related to firm storage capacity as well as asset management revenues. Other We have non-utility investments and other business activities, which are aggregated and reported as other. Other primarily consists of an equity method investment in TWH, which was formed to build and operate an interstate gas transmission pipeline in Oregon (TWP), other pipeline assets in NNG Financial, and non-utility appliance retail center operations. For more information on TWP, see Note 12. Other also includes some corporate operating and non-operating revenues and expenses that cannot be allocated to utility operations. Upon closing agreements to purchase two water utilities, we expect them to be accounted for as other. NNG Financial's assets primarily consist of an active, wholly-owned subsidiary which owns a 10 % interest in an 18-mile interstate natural gas pipeline. NNG Financial’s total assets were $ 0.4 million and $ 0.5 million at December 31, 2017 and 2016 , respectively. Segment Information Summary Inter-segment transactions were immaterial for the periods presented. The following table presents summary financial information concerning the reportable segments: In thousands Utility Gas Storage Other Total 2017 Operating revenues $ 732,942 $ 23,620 $ 5,611 $ 762,173 Depreciation and amortization 79,734 5,844 — 85,578 Income (loss) from operations (1) 132,807 (185,074 ) (960 ) (53,227 ) Net income (loss) (2) 60,509 (116,209 ) 77 (55,623 ) Capital expenditures 211,672 1,923 — 213,595 Total assets at December 31, 2017 2,961,326 59,583 18,837 3,039,746 2016 Operating revenues $ 650,477 $ 25,266 $ 224 $ 675,967 Depreciation and amortization 76,289 6,000 — 82,289 Income (loss) from operations 130,570 9,136 (426 ) 139,280 Net income (loss) (3) 54,567 4,303 25 58,895 Capital expenditures 138,074 1,437 — 139,511 Total assets at December 31, 2016 2,806,627 256,333 16,841 3,079,801 2015 Operating revenues $ 702,210 $ 21,356 $ 225 $ 723,791 Depreciation and amortization 74,410 6,513 — 80,923 Income (loss) from operations 119,215 5,032 1 124,248 Net income (loss) (3) 53,391 174 138 53,703 Capital expenditures 115,272 3,048 — 118,320 Total assets at December 31, 2015 2,791,623 261,750 16,037 3,069,410 (1) Includes $192.5 million for an impairment of long-lived assets at the Gill Ranch Facility in Gas Storage. (2) Includes $21.9 million and $0.6 million of tax benefit in Gas Storage and Other, respectively, and $1.0 million of tax expense in Utility from the enactment of TCJA. Gas Storage also includes an after-tax impairment of long-lived assets at the Gill Ranch Facility of $141.5 million . The TCJA was enacted December 22, 2017 and resulted in the federal tax rate changing from 35% to 21%. The after-tax impairment charge is calculated using our new combined federal and state statutory rate of 26.5%. (3) Includes $2.0 million in 2016 and $9.1 million in 2015 of after-tax regulatory environmental disallowance charges in Utility. Utility Margin Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage segment and other emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance. The following table presents additional segment information concerning utility margin: In thousands 2017 2016 2015 Utility margin calculation: Utility operating revenues $ 732,942 $ 650,477 $ 702,210 Less: Utility cost of gas 325,019 260,588 327,305 Environmental remediation expense 15,291 13,298 3,513 Utility margin $ 392,632 $ 376,591 $ 371,392

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Common Stock [Text Block]	5. COMMON STOCK Common Stock As of December 31, 2017 and 2016 , we had 100 million shares of common stock authorized. As of December 31, 2017 , we had reserved 43,058 shares for issuance of common stock under the Employee Stock Purchase Plan (ESPP) and 155,086 shares under our Dividend Reinvestment and Direct Stock Purchase Plan (DRPP). At our election, shares sold through our DRPP may be purchased in the open market or through original issuance of shares reserved for issuance under the DRPP. The Restated Stock Option Plan (SOP) was terminated with respect to new grants in 2012; however, options granted before the Restated SOP was terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. There were 91,688 options outstanding at December 31, 2017 , which were granted prior to termination of the plan. During November 2016, we completed an equity issuance consisting of an offering of 880,000 shares of its common stock along with a 30 -day option for the underwriters to purchase an additional 132,000 shares. The offering closed on November 16, 2016 and resulted in a total issuance of 1,012,000 shares as both the initial offering and the underwriter option were fully executed. All shares were issued on November 16, 2016 at an offering price of $54.63 per share and resulted in total net proceeds of $52.8 million. Stock Repurchase Program We have a share repurchase program under which we may purchase our common shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 2018 to repurchase up to an aggregate of the greater of 2.8 million shares or $100 million . No shares of common stock were repurchased pursuant to this program during the year ended December 31, 2017 . Since the plan’s inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million . Summary of Changes in Common Stock The following table shows the changes in the number of shares of our common stock issued and outstanding: In thousands Shares Balance, December 31, 2014 27,284 Sales to employees under ESPP 19 Stock-based compensation 78 Sales to shareholders under DRPP 46 Balance, December 31, 2015 27,427 Sales to employees under ESPP 18 Stock-based compensation 173 Equity Issuance 1,012 Balance, December 31, 2016 28,630 Sales to employees under ESPP 18 Stock-based compensation 88 Balance, December 31, 2017 28,736

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Based Compensation [Text Block]	6. STOCK-BASED COMPENSATION Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long Term Incentive Plan (LTIP), an ESPP, and a Restated SOP. Long Term Incentive Plan The LTIP is intended to provide a flexible, competitive compensation program for eligible officers and key employees. Under the LTIP, shares of common stock are authorized for equity incentive grants in the form of stock, restricted stock, restricted stock units, stock options, or performance shares. An aggregate of 1,100,000 shares were authorized for issuance as of December 31, 2017 . Shares awarded under the LTIP may be purchased on the open market or issued as original shares. Of the 1,100,000 shares of common stock authorized for LTIP awards at December 31, 2017 , there were 626,960 shares available for issuance under any type of award. This assumes market, performance, and service-based grants currently outstanding are awarded at the target level. There were no outstanding grants of restricted stock or stock options under the LTIP at December 31, 2017 or 2016 . The LTIP stock awards are compensatory awards for which compensation expense is based on the fair value of stock awards, with expense being recognized over the performance and vesting period of the outstanding awards. Forfeitures are recognized as they occur. Performance Shares Since the LTIP’s inception in 2001, performance shares, which incorporate market, performance, and service-based factors, have been granted annually with three-year performance periods. The following table summarizes performance share expense information: Dollars in thousands Shares (1) Expense During Award Year (2) Total Expense for Award Estimated award: 2015-2017 grant (3) 18,300 $ (346 ) $ 1,169 Actual award: 2014-2016 grant 31,388 168 1,685 2013-2015 grant 8,914 312 1,240 (1) In addition to common stock shares, a participant also receives a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. (2) Amount represents the expense recognized in the third year of the vesting period noted above. For the 2015-2017 grant, we did not meet targets and reversed expense during 2017 that had been previously recognized. (3) This represents the estimated number of shares to be awarded as of December 31, 2017 as certain performance share measures had been achieved. Amounts are subject to change with final payout amounts authorized by the Board of Directors in February 2018. The aggregate number of performance shares granted and outstanding at the target and maximum levels were as follows: Dollars in thousands Performance Share Awards Outstanding 2017 Cumulative Expense Performance Period Target Maximum Expense/(Reversal) December 31, 2017 2015-17 29,967 59,934 $ (346 ) $ 1,169 2016-18 24,826 49,652 337 815 2017-19 32,680 65,360 942 942 Total 87,473 174,946 $ 933 For the 2015-2017 and 2016-2018 plan years, performance share awards are based on EPS and Return on Invested Capital (ROIC) factors and a total shareholder return (TSR factor) relative to the Dow Jones U.S. Gas Distribution peer group over the three-year performance period. Additionally, these plans are based on performance results achieved relative to specific core and non-core strategies (strategic factor). For the 2017-2019 plan year, performance share awards are based on the achievement of EPS and ROIC factors, which can be modified by a TSR factor relative to the performance of the Russell 2500 Utilities Index over the three-year performance period and a growth modifier based on accumulative EBITA measure. Compensation expense is recognized in accordance with accounting standards for stock-based compensation and calculated based on performance levels achieved and an estimated fair value using the Monte-Carlo method. The weighted-average grant date fair value of nonvested shares at December 31, 2017 and 2016 was $ 56.40 and $ 50.83 per share, respectively. The weighted-average grant date fair value of shares granted during the year was $ 57.05 per share and for shares vested during the year was $ 52.02 per share. As of December 31, 2017 , there was $ 2.8 million of unrecognized compensation expense related to the nonvested portion of performance awards expected to be recognized through 2019. Restricted Stock Units In 2012, we began granting RSUs under the LTIP instead of stock options under the Restated SOP. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. Upon vesting, the RSU holder is issued one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU. The fair value of an RSU is equal to the closing market price of the Company's common stock on the grant date. During 2017, total RSU expense was $ 1.6 million compared to $ 1.5 million in 2016 and $ 1.3 million in 2015. As of December 31, 2017 , there was $ 3.1 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2022 . Information regarding the RSU activity is summarized as follows: Number of RSUs Weighted - Average Price Per RSU Nonvested, December 31, 2014 70,794 $ 44.00 Granted 37,264 46.29 Vested (19,003 ) 44.81 Forfeited (468 ) 44.99 Nonvested, December 31, 2015 88,587 44.78 Granted 40,271 54.36 Vested (29,488 ) 45.56 Forfeited (9,397 ) 44.59 Nonvested, December 31, 2016 89,973 48.85 Granted 32,168 60.51 Vested (35,341 ) 47.07 Forfeited (2,278 ) 53.78 Nonvested, December 31, 2017 84,522 53.90 Restated Stock Option Plan The Restated SOP was terminated for new option grants in 2012; however, options granted before the plan terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. Any new grants of stock options would be made under the LTIP, however, no option grants have been awarded since 2012 and all stock options were vested as of December 31, 2015. Options under the Restated SOP were granted to officers and key employees designated by a committee of our Board of Directors. All options were granted at an option price equal to the closing market price on the date of grant and may be exercised for a period of up to 10 years and seven days from the date of grant. Option holders may exchange shares they have owned for at least six months , valued at the current market price, to purchase shares at the option price. Information regarding the Restated SOP activity is summarized as follows: Option Shares Weighted - Average Price Per Share Intrinsic Value (In millions) Balance outstanding, December 31, 2014 416,088 $ 43.40 $ 2.7 Exercised (62,900 ) 39.96 0.5 Forfeited (500 ) 45.74 n/a Balance outstanding, December 31, 2015 352,688 44.00 2.3 Exercised (172,525 ) 43.61 2.0 Forfeited — n/a n/a Balance outstanding, December 31, 2016 180,163 44.38 2.8 Exercised (88,275 ) 44.33 1.8 Forfeited (200 ) 41.15 n/a Balance outstanding and exercisable, December 31, 2017 91,688 44.43 1.4 During 2017 , cash of $ 3.9 million was received for stock options exercised and $0.5 million related tax expense was recognized. The weighted-average remaining life of options exercisable and outstanding at December 31, 2017 was 2.47 years . Employee Stock Purchase Plan The ESPP allows employees to purchase common stock at 85% of the closing price on the trading day immediately preceding the initial offering date, which is set annually. Each eligible employee may purchase up to $ 21,199 worth of stock through payroll deductions over a period defined by the Board of Directors, which is currently a 12-month period, with shares issued at the end of the 12-month subscription period. Stock-Based Compensation Expense Stock-based compensation expense is recognized as operations and maintenance expense or is capitalized as part of construction overhead. The following table summarizes the financial statement impact of stock-based compensation under our LTIP, Restated SOP and ESPP: In thousands 2017 2016 2015 Operations and maintenance expense, for stock-based compensation $ 2,354 $ 2,370 $ 2,673 Income tax benefit (930 ) (924 ) (1,012 ) Net stock-based compensation effect on net income (loss) $ 1,424 $ 1,446 $ 1,661 Amounts capitalized for stock-based compensation $ 528 $ 554 $ 661

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt [Text Block]	7. DEBT Short-Term Debt Our primary source of short-term funds is from the sale of commercial paper and bank loans. In addition to issuing commercial paper or bank loans to meet seasonal working capital requirements, short-term debt is used temporarily to fund capital requirements. Commercial paper and bank loans are periodically refinanced through the sale of long-term debt or equity securities. Our commercial paper program is supported by one or more committed credit facilities. At December 31, 2017 and 2016 , total short-term debt outstanding was $54.2 million and $53.3 million , respectively, which was comprised entirely of commercial paper. The weighted average interest rate at December 31, 2017 and 2016 was 1.9 % and 0.8% , respectively. The carrying cost of our commercial paper approximates fair value using Level 2 inputs, due to the short-term nature of the notes. See Note 2 for a description of the fair value hierarchy. At December 31, 2017 , our commercial paper had a maximum remaining maturity of 11 days and an average remaining maturity of 6 days. We have a $ 300.0 million credit agreement, with a feature that allows us to request increases in the total commitment amount up to a maximum amount of $ 450.0 million . The maturity of the agreement is December 20, 2019 . We have a letter of credit of $ 100.0 million . Any principal and unpaid interest owed on borrowings under the agreement is due and payable on or before the expiration date. There were no outstanding balances under the agreement and no letters of credit issued or outstanding at December 31, 2017 and 2016 . The credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings or senior secured debt ratings, as applicable, by such rating agencies. A change in our debt ratings is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to debt ratings, which would increase or decrease the cost of any loans under the credit facility when ratings are changed. The credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70 % or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2017 and 2016 . Long-Term Debt The issuance of FMBs, which includes our medium-term notes, under the Mortgage and Deed of Trust (Mortgage) is limited by eligible property, adjusted net earnings, and other provisions of the Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of our utility property. Maturities and Outstanding Long-Term Debt Retirement of long-term debt for each of the 12-month periods through December 31, 2022 and thereafter are as follows: In thousands Year 2018 $ 97,000 2019 30,000 2020 75,000 2021 60,000 2022 — Thereafter 524,700 The following table presents our debt outstanding as of December 31: In thousands 2017 2016 First Mortgage Bonds 7.000 % Series B due 2017 $ — $ 40,000 1.545 % Series B due 2018 75,000 75,000 6.600 % Series B due 2018 22,000 22,000 8.310 % Series B due 2019 10,000 10,000 7.630 % Series B due 2019 20,000 20,000 5.370 % Series B due 2020 75,000 75,000 9.050 % Series A due 2021 10,000 10,000 3.176 % Series B due 2021 50,000 50,000 3.542 % Series B due 2023 50,000 50,000 5.620 % Series B due 2023 40,000 40,000 7.720 % Series B due 2025 20,000 20,000 6.520 % Series B due 2025 10,000 10,000 7.050 % Series B due 2026 20,000 20,000 3.211 % Series B due 2026 35,000 35,000 7.000 % Series B due 2027 20,000 20,000 2.822 % Series B due 2027 25,000 — 6.650 % Series B due 2027 19,700 19,700 6.650 % Series B due 2028 10,000 10,000 7.740 % Series B due 2030 20,000 20,000 7.850 % Series B due 2030 10,000 10,000 5.820 % Series B due 2032 30,000 30,000 5.660 % Series B due 2033 40,000 40,000 5.250 % Series B due 2035 10,000 10,000 4.000 % Series B due 2042 50,000 50,000 4.136 % Series B due 2046 40,000 40,000 3.685 % Series B due 2047 75,000 — 786,700 726,700 Less: Current maturities 97,000 40,000 Total long-term debt $ 689,700 $ 686,700 First Mortgage Bonds We issued $ 100.0 million of FMBs in September 2017 consisting of $ 25.0 million with a coupon rate of 2.822% and maturity date in 2027 and $ 75 million with a coupon rate of 3.685% and maturity date in 2047. Retirements of Long-Term Debt We redeemed $ 40.0 million of FMBs with a coupon rate of 7.000% in August 2017. Fair Value of Long-Term Debt Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 . The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date : December 31, In thousands 2017 2016 Gross long-term debt $ 786,700 $ 726,700 Unamortized debt issuance costs (6,813 ) (7,377 ) Carrying amount $ 779,887 $ 719,323 Estimated fair value $ 853,339 $ 793,339

Pension and Other Postretiremen

Pension and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2017
Pension and Other Postretirement Benefit Expense [Abstract]
Pension and Other Postretirement Benefits [Text Block]	8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS We maintain a qualified non-contributory defined benefit pension plan, non-qualified supplemental pension plans for eligible executive officers and other key employees, and other postretirement employee benefit plans. We also have a qualified defined contribution plan (Retirement K Savings Plan) for all eligible employees. The qualified defined benefit pension plan and Retirement K Savings Plan have plan assets, which are held in qualified trusts to fund retirement benefits. Effective January 1, 2007 and 2010, the qualified defined benefit pension plans and postretirement benefits for non-union employees and union employees, respectively, were closed to new participants. These plans were not available to employees of our non-utility subsidiaries. Non-union and union employees hired or re-hired after December 31, 2006 and 2009, respectively, and employees of NW Natural subsidiaries are provided an enhanced Retirement K Savings Plan benefit. Effective December 31, 2012, the qualified defined benefit pension plans for non-union and union employees were merged into a single plan. The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for the pension and other postretirement benefit plans, excluding the Retirement K Savings Plan, and a summary of the funded status and amounts recognized in the consolidated balance sheets as of December 31: Postretirement Benefit Plans Pension Benefits Other Benefits In thousands 2017 2016 2017 2016 Reconciliation of change in benefit obligation: Obligation at January 1 $ 457,839 $ 445,628 $ 29,395 $ 31,049 Service cost 7,090 7,083 341 391 Interest cost 18,111 18,399 1,141 1,175 Net actuarial (gain) loss 34,829 7,688 (213 ) (1,488 ) Benefits paid (1) (31,580 ) (20,959 ) (1,737 ) (1,732 ) Obligation at December 31 $ 486,289 $ 457,839 $ 28,927 $ 29,395 Reconciliation of change in plan assets: Fair value of plan assets at January 1 $ 257,714 $ 249,338 $ — $ — Actual return on plan assets 40,308 12,593 — — Employer contributions 21,483 16,742 1,737 1,732 Benefits paid (1) (31,580 ) (20,959 ) (1,737 ) (1,732 ) Fair value of plan assets at December 31 $ 287,925 $ 257,714 $ — $ — Funded status at December 31 $ (198,364 ) $ (200,125 ) $ (28,927 ) $ (29,395 ) (1) In 2017, we completed a partial buy-out of our qualified defined benefit pension plan in which $9.3 million of plan assets and $8.7 million liabilities were transferred to an insurer to provide annuities for buy-out plan participants. Our qualified defined benefit pension plan has an aggregate benefit obligation of $ 449.7 million and $ 423.5 million at December 31, 2017 and 2016 , respectively, and fair values of plan assets of $ 287.9 million and $ 257.7 million , respectively. The following table presents amounts realized through regulatory assets or in other comprehensive loss (income) for the years ended December 31: Regulatory Assets Other Comprehensive Loss (Income) Pension Benefits Other Postretirement Benefits Pension Benefits In thousands 2017 2016 2015 2017 2016 2015 2017 2016 2015 Net actuarial loss (gain) $ 12,177 $ 14,005 $ 419 $ (214 ) $ (1,488 ) $ 2,724 $ 2,777 $ (1,196 ) $ (2,549 ) Settlement Loss — — — — — — — 193 — Amortization of: Prior service cost (127 ) (230 ) (230 ) 468 468 (197 ) — — — Actuarial loss (14,802 ) (13,238 ) (16,372 ) (696 ) (705 ) (554 ) (946 ) 1,386 (2,236 ) Total $ (2,752 ) $ 537 $ (16,183 ) $ (442 ) $ (1,725 ) $ 1,973 $ 1,831 $ 383 $ (4,785 ) The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at December 31: Regulatory Assets AOCL Pension Benefits Other Postretirement Benefits Pension Benefits In thousands 2017 2016 2017 2016 2017 2016 Prior service cost (credit) $ 49 $ 176 $ (2,206 ) $ (2,675 ) $ — $ 1 Net actuarial loss 175,035 177,660 6,964 7,874 13,266 11,434 Total $ 175,084 $ 177,836 $ 4,758 $ 5,199 $ 13,266 $ 11,435 The following table presents amounts recognized in AOCL and the changes in AOCL related to our non-qualified employee benefit plans: Year Ended December 31, In thousands 2017 2016 Beginning balance $ (6,951 ) $ (7,162 ) Amounts reclassified to AOCL (2,794 ) (1,196 ) Amounts reclassified from AOCL: Amortization of actuarial losses 946 1,386 Loss from plan settlement — 193 Total reclassifications before tax (1,848 ) 383 Tax expense (benefit) 361 (172 ) Total reclassifications for the period (1,487 ) 211 Ending balance $ (8,438 ) $ (6,951 ) In 2018 , an estimated $ 17.3 million will be amortized from regulatory assets to net periodic benefit costs, consisting of $ 17.7 million of actuarial losses, and $ 0.4 million of prior service credits. A total of $ 0.8 million will be amortized from AOCL to earnings related to actuarial losses in 2018 . Our assumed discount rate for the pension plan and other postretirement benefit plans was determined independently based on the Citigroup Above Median Curve (discount rate curve), which uses high quality corporate bonds rated AA- or higher by S&P or Aa3 or higher by Moody’s. The discount rate curve was applied to match the estimated cash flows in each of our plans to reflect the timing and amount of expected future benefit payments for these plans. Our assumed expected long-term rate of return on plan assets for the qualified pension plan was developed using a weighted-average of the expected returns for the target asset portfolio. In developing the expected long-term rate of return assumption, consideration was given to the historical performance of each asset class in which the plan’s assets are invested and the target asset allocation for plan assets. Our investment strategy and policies for qualified pension plan assets held in the retirement trust fund were approved by our Retirement Committee, which is composed of senior management with the assistance of an outside investment consultant. The policies set forth the guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate consideration for liquidity, portfolio risk, and return expectations. All investments are expected to satisfy the prudent investments rule under the Employee Retirement Income Security Act of 1974. The approved asset classes may include cash and short-term investments, fixed income, common stock and convertible securities, absolute and real return strategies, real estate, and investments in NW Natural securities. Plan assets may be invested in separately managed accounts or in commingled or mutual funds. Investment re-balancing takes place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target ranges. The retirement trust fund is not currently invested in NW Natural securities. The following table presents the pension plan asset target allocation at December 31, 2017 : Asset Category Target Allocation U.S. large cap equity 29.3 % U.S. small/mid cap equity 6.9 Non-U.S. equity 28.0 Emerging markets equity 11.8 Long government/credit 17.5 High yield bonds 2.0 Emerging market debt 3.5 Real estate funds 1.0 Our non-qualified supplemental defined benefit plan obligations were $ 36.6 million and $ 34.3 million at December 31, 2017 and 2016 , respectively. These plans are not subject to regulatory deferral, and the changes in actuarial gains and losses, prior service costs, and transition assets or obligations are recognized in AOCL, net of tax until they are amortized as a component of net periodic benefit cost. These are unfunded, non-qualified plans with no plan assets; however, we indirectly fund a significant portion of our obligations with company and trust-owned life insurance and other assets. Our other postretirement benefit plans are unfunded plans but are subject to regulatory deferral. The actuarial gains and losses, prior service costs, and transition assets or obligations for these plans are recognized as a regulatory asset. Net periodic benefit costs consist of service costs, interest costs, the amortization of actuarial gains and losses, and the expected returns on plan assets, which are based in part on a market-related valuation of assets. The market-related valuation reflects differences between expected returns and actual investment returns with the differences recognized over a three-year or less period from the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility. The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans for the years ended December 31: Pension Benefits Other Postretirement Benefits In thousands 2017 2016 2015 2017 2016 2015 Service cost $ 7,090 $ 7,083 $ 8,267 $ 341 $ 391 $ 527 Interest cost 18,111 18,399 18,360 1,141 1,175 1,179 Expected return on plan assets (20,433 ) (20,054 ) (20,676 ) — — — Amortization of prior service costs 127 231 231 (468 ) (468 ) 197 Amortization of net actuarial loss 15,748 14,624 18,609 696 705 554 Settlement expense — 193 — — — — Net periodic benefit cost 20,643 20,476 24,791 1,710 1,803 2,457 Amount allocated to construction (6,597 ) (5,746 ) (6,834 ) (587 ) (600 ) (808 ) Amount deferred to regulatory balancing account (1) (6,542 ) (6,252 ) (8,241 ) — — — Net amount charged to expense $ 7,504 $ 8,478 $ 9,716 $ 1,123 $ 1,203 $ 1,649 (1) The deferral of defined benefit pension plan expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. Net periodic benefit costs are reduced by amounts capitalized to utility plant based on approximately 25% to 35% payroll overhead charge. In addition, a certain amount of net periodic benefit costs are recorded to the regulatory balancing account for pensions. Net periodic pension cost less amounts charged to capital accounts and regulatory balancing accounts are expenses recognized in earnings. The following table provides the assumptions used in measuring periodic benefit costs and benefit obligations for the years ended December 31: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Assumptions for net periodic benefit cost: Weighted-average discount rate 3.99 % 4.17 % 3.82 % 3.85 % 4.00 % 3.74 % Rate of increase in compensation 3.25-4.5% 3.25-4.5% 3.25-5.0% n/a n/a n/a Expected long-term rate of return 7.50 % 7.50 % 7.50 % n/a n/a n/a Assumptions for year-end funded status: Weighted-average discount rate 3.52 % 4.00 % 4.21 % 3.44 % 3.85 % 4.00 % Rate of increase in compensation 3.25-4.5% 3.25-4.5% 3.25-4.5% n/a n/a n/a Expected long-term rate of return 7.50 % 7.50 % 7.50 % n/a n/a n/a The assumed annual increase in health care cost trend rates used in measuring other postretirement benefits as of December 31, 2017 was 7.50% . These trend rates apply to both medical and prescription drugs. Medical costs and prescription drugs are assumed to decrease gradually each year to a rate of 4.75% by 2026 . Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans; however, other postretirement benefit plans have a cap on the amount of costs reimbursable by us. A one percentage point change in assumed health care cost trend rates would have the following effects: In thousands 1% Increase 1% Decrease Effect on net periodic postretirement health care benefit cost $ 44 $ (39 ) Effect on the accumulated postretirement benefit obligation 478 (428 ) We review mortality assumptions annually and will update for material changes as necessar y. In 2017 , our mortality rate assumptions were updated from RP-2006 mortality tables for employees and healthy annuitants with a fully generational projection using scale MP-2016 to corresponding RP-2006 mortality tables using scale MP-2017, which partially offset increases of our projected benefit obligation. The following table provides information regarding employer contributions and benefit payments for the qualified pension plan, non-qualified pension plans, and other postretirement benefit plans for the years ended December 31, and estimated future contributions and payments: In thousands Pension Benefits Other Benefits Employer Contributions: 2016 $ 16,742 $ 1,732 2017 21,483 1,737 2018 (estimated) 17,710 1,835 Benefit Payments: 2015 35,923 2,018 2016 20,959 1,732 2017 31,580 1,737 Estimated Future Benefit Payments: 2018 22,679 1,835 2019 23,546 1,871 2020 24,542 1,861 2021 25,471 1,904 2022 26,095 1,886 2023-2027 145,065 9,261 Employer Contributions to Company-Sponsored Defined Benefit Pension Plans We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations, and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established funding requirements for defined benefit plans. The Act establishes a 100% funding target over seven years for plan years beginning after December 31, 2008. In 2012 the Moving Ahead for Progress in the 21st Century Act (MAP-21) legislation changed several provisions affecting pension plans, including temporary funding relief and Pension Benefit Guaranty Corporation (PBGC) premium increases, which reduces the level of minimum required contributions in the near-term but generally increases contributions in the long-run and increases the operational costs of running a pension plan. In 2014, the Highway and Transportation Funding Act (HATFA) was signed and extends certain aspects of MAP-21 as well as modifies the phase-out periods for the limitations. Our qualified defined benefit pension plan is currently underfunded by $ 161.7 million at December 31, 2017 . Including the impacts of MAP-21 and HATFA, we made cash contributions totaling $ 19.4 million to our qualified defined benefit pension plan for 2017 . During 2018 , we expect to make contributions of approximately $ 15.5 million to this plan. Multiemployer Pension Plan In addition to the Company-sponsored defined benefit plans presented above, prior to 2014 we contributed to a multiemployer pension plan for our utility's union employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). The plan's employer identification number is 94-6076144. Effective December 22, 2013, we withdrew from the plan, which was a noncash transaction. Vested participants will receive all benefits accrued through the date of withdrawal. As the plan was underfunded at the time of withdrawal, we were assessed a withdrawal liability of $8.3 million , plus interest, which requires NW Natural to pay $0.6 million each year to the plan for 20 years beginning in July 2014. The cost of the withdrawal liability was deferred to a regulatory account on the balance sheet. We made payments of $0.6 million for 2017 , and as of December 31, 2017 the liability balance was $7.1 million . For 2016 and 2015 , contributions to the plan were $0.6 million and $0.6 million , respectively, which was approximately 4% to 5% of the total contributions to the plan by all employer participants in those years. Defined Contribution Plan The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Sections 401(a) and 401(k). Employer contributions totaled $ 5.4 million , $4.6 million , and $3.7 million for 2017 , 2016 , and 2015 , respectively. The Retirement K Savings Plan includes an Employee Stock Ownership Plan. Deferred Compensation Plans The supplemental deferred compensation plans for eligible officers and senior managers are non-qualified plans. These plans are designed to enhance the retirement savings of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly. Fair Value Below is a description of the valuation methodologies used for assets measured at fair value. In cases where the pension plan is invested through a collective trust fund or mutual fund, the fund's market value is utilized. Market values for investments directly owned are also utilized. U.S. LARGE CAP EQUITY and U.S. SMALL/MID CAP EQUITY. These are Level 1 and non-published net asset value (NAV) assets. The Level 1 assets consist of directly held stocks and mutual funds with a readily determinable fair value, including a published NAV. The non-published NAV assets consist of commingled trusts where NAV is not published but the investment can be readily disposed of at NAV or market value. Directly held stocks are valued at the closing price reported in the active market on which the individual security is traded. Mutual funds and commingled trusts are valued at NAV and the unit price, respectively. This asset class includes investments primarily in U.S. common stocks. NON-U.S. EQUITY. These are Level 1 and non-published NAV assets. The Level 1 assets consist of directly held stocks, and the non-published NAV assets consist of commingled trusts where the NAV/unit price is not published but the investment can be readily disposed of at the NAV/unit price. Directly held stocks are valued at the closing price reported in the active market on which the individual security is traded, and the commingled trusts are valued at unit price. This asset class includes investments primarily in foreign equity common stocks. EMERGING MARKETS EQUITY. These are non-published NAV assets consisting of an open-end mutual fund where the NAV price is not published but the investment can be readily disposed of at the NAV, and a commingled trust where the investment can be readily disposed of at unit price. This asset class includes investments primarily in common stocks in emerging markets. FIXED INCOME. These are non-published NAV assets consisting of a commingled trust, valued at unit price, where unit price is not published, but the investment can be readily disposed of at the unit price. This asset class includes investments primarily in investment grade debt and fixed income securities. LONG GOVERNMENT/CREDIT. These are non-published NAV and Level 2 assets. The non-published NAV assets include commingled trusts, valued at unit price, where unit price is not published, but the investment can be readily disposed of at the unit price. The Level 2 assets consist of directly held fixed-income securities, with readily determinable fair values, whose values are determined by closing prices if available and by matrix prices for illiquid securities. This asset class includes long duration fixed income investments primarily in U.S. treasuries, U.S. government agencies, municipal securities, mortgage-backed securities, asset-backed securities, as well as U.S. and international investment-grade corporate bonds. HIGH YIELD BONDS. These are non-published NAV assets, consisting of a limited partnership and a commingled trust where the valuation is not published but the investment can be readily disposed of at market value, valued at NAV or unit price, respectively. This asset class includes investments primarily in high yield bonds. EMERGING MARKET DEBT. This is a non-published NAV asset consisting of a commingled trust with a readily determinable fair value, where unit price is not published, but the investment can be readily disposed of at the unit price. This asset class includes investments primarily in emerging market debt. REAL ESTATE. These are Level 1 and non-published NAV assets. The Level 1 asset is a mutual fund with a readily determinable fair value, including a published NAV. The non-published NAV asset is a commingled trust with a readily determinable fair value, where unit price is not published, but the investment can be readily disposed of at the unit price. This asset class includes investments primarily in real estate investment trust (REIT) equity securities globally. ABSOLUTE RETURN STRATEGY. This is a non-published NAV asset consisting of a hedge fund of funds where the valuation is not published. This hedge fund of funds is winding down. Based on recent dispositions, we believe the remaining investment is fairly valued. The hedge fund of funds is valued at the weighted average value of investments in various hedge funds, which in turn are valued at the closing price of the underlying securities. This asset class primarily includes investments in common stocks and fixed income securities. CASH AND CASH EQUIVALENTS. These are Level 1 and non-published NAV assets. The Level 1 assets consist of cash in U.S. dollars, which can be readily disposed of at face value. The non-published NAV assets represent mutual funds without published NAV's but the investment can be readily disposed of at the NAV. The mutual funds are valued at the NAV of the shares held by the plan at the valuation date. The preceding valuation methods may produce a fair value calculation that is not indicative of net realizable value or reflective of future fair values. Although we believe these valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain investments could result in a different fair value measurement at the reporting date. Investment securities are exposed to various financial risks including interest rate, market, and credit risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of our investment securities will occur in the near term and such changes could materially affect our investment account balances and the amounts reported as plan assets available for benefit payments. The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the retirement trust fund: In thousands December 31, 2017 Investments Level 1 Level 2 Level 3 Non-Published NAV (1) Total U.S. large cap equity $ — $ — $ — $ 102,851 $ 102,851 U.S. small/mid cap equity — — — 16,423 16,423 Non-U.S. equity 21,211 — — 56,075 77,286 Emerging markets equity — — — 28,743 28,743 Fixed income — — — 2,781 2,781 Long government/credit — — — 33,081 33,081 High yield bonds — — — 2,777 2,777 Emerging market debt — — — 12,605 12,605 Real estate — — — 5,544 5,544 Absolute return strategy — — — 189 189 Cash and cash equivalents 82 — — 5,533 5,615 Total investments $ 21,293 $ — $ — $ 266,602 $ 287,895 December 31, 2016 Investments Level 1 Level 2 Level 3 Non-Published NAV (1) Total U.S. large cap equity $ 49,841 $ — $ — $ 5,655 $ 55,496 U.S. small/mid cap equity 18,629 — — 10,232 28,861 Non-U.S. equity 22,404 — — 25,346 47,750 Emerging markets equity — — — 13,457 13,457 Fixed income — — — 6,719 6,719 Long government/credit — 34,955 — 17,960 52,915 High yield bonds — — — 14,072 14,072 Emerging market debt — — — 8,504 8,504 Real estate 17,857 — — 882 18,739 Absolute return strategy — — — 3,111 3,111 Cash and cash equivalents $ 9 $ — $ — $ 2,482 $ 2,491 Total investments $ 108,740 $ 34,955 $ — $ 108,420 $ 252,115 December 31, 2017 2016 Receivables: Accrued interest and dividend income $ 30 $ 451 Due from broker for securities sold — 5,170 Total receivables $ 30 $ 5,621 Liabilities: Due to broker for securities purchased $ — $ 22 Total investment in retirement trust $ 287,925 $ 257,714 (1) The fair value for these investments is determined using Net Asset Value per share (NAV) as of December 31, as a practical expedient, and therefore they are not classified within the fair value hierarchy. These investments primarily consist of institutional investment products, for which the NAV is generally not publicly available.

Income Tax

Income Tax	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax [Text Block]	9. INCOME TAX The following table provides a reconciliation between income taxes calculated at the statutory federal tax rate and the provision for income taxes reflected in the consolidated statements of comprehensive income or loss for December 31: Dollars in thousands 2017 2016 2015 Income taxes (benefits) at federal statutory rate $ (30,233 ) $ 34,863 $ 31,310 Increase (decrease): State income tax, net of federal (5,784 ) 4,582 4,195 Amortization of investment tax credits (4 ) (41 ) (118 ) Differences required to be flowed-through by regulatory commissions 2,357 2,357 2,357 Gains on company and trust-owned life insurance (872 ) (594 ) (766 ) Effect of TCJA (21,429 ) — — Deferred Tax Rate Differential Post-TCJA 26,947 — — Other, net (1,739 ) (453 ) (1,225 ) Total provision for income taxes (benefits) $ (30,757 ) $ 40,714 $ 35,753 Effective tax rate 35.6 % 40.9 % 40.0 % The effective income tax rate for 2017 compared to 2016 changed primarily as a result of the TCJA, the equity portion of AFUDC and excess tax benefits related to stock-based compensation. The effective income tax rate increase from 2016 compared to 2015 was primarily the result of lower depletion deductions from gas reserves activity in 2016. The provision for current and deferred income taxes consists of the following at December 31: In thousands 2017 2016 2015 Current Federal $ 16,403 $ 7,402 $ 10,558 State 4,892 2,042 61 21,295 9,444 10,619 Deferred Federal (41,134 ) 26,219 18,729 State (10,918 ) 5,051 6,405 (52,052 ) 31,270 25,134 Total provision for income taxes (loss benefits) $ (30,757 ) $ 40,714 $ 35,753 At December 31, 2017 and 2016 , regulatory income tax assets of $21.3 million and $43.0 million , respectively, were recorded, a portion of which is recorded in current assets. These regulatory income tax assets primarily represent future rate recovery of deferred tax liabilities, resulting from differences in utility plant financial statement and tax bases and utility plant removal costs, which were previously flowed through for rate making purposes and to take into account the additional future taxes, which will be generated by that recovery. These deferred tax liabilities, and the associated regulatory income tax assets, are currently being recovered through customer rates. At December 31, 2017 , we had a regulatory income tax asset of $ 0.9 million representing probable future rate recovery of deferred tax liabilities resulting from the equity portion of AFUDC. The following table summarizes the total provision (benefit) for income taxes for the utility and non-utility business segments for December 31: In thousands 2017 2016 2015 Utility: Current $ 21,453 $ 10,300 $ 15,890 Deferred 19,479 28,749 20,834 Deferred investment tax credits (4 ) (41 ) (118 ) 40,928 39,008 36,606 Non-utility business segments: Current (158 ) (856 ) (5,271 ) Deferred (71,527 ) 2,562 4,418 (71,685 ) 1,706 (853 ) Total provision for income taxes $ (30,757 ) $ 40,714 $ 35,753 The following table summarizes the tax effect of significant items comprising our deferred income tax accounts at December 31: In thousands 2017 2016 Deferred tax liabilities: Plant and property $ 296,114 $ 428,642 Regulatory income tax assets 22,209 43,048 Regulatory liabilities 29,114 48,291 Non-regulated deferred tax liabilities 933 51,446 Total $ 348,370 $ 571,427 Deferred tax assets: Regulatory income tax liabilities $ 56,470 $ — Non-regulated deferred tax assets 17,796 — Pension and postretirement obligations 3,512 4,493 Alternative minimum tax credit carryforward 66 9,853 Total $ 77,844 $ 14,346 Deferred income tax liabilities, net $ 270,526 $ 557,081 Deferred investment tax credits — 4 Deferred income taxes and investment tax credits $ 270,526 $ 557,085 Management assesses the available positive and negative evidence to estimate if sufficient taxable income will be generated to utilize the existing deferred tax assets. Based upon this assessment, we have determined we are more likely than not to realize all deferred tax assets recorded as of December 31, 2017 . As a result of certain realization requirements prescribed in the accounting guidance for income taxes, the tax benefit of statutory depletion is recognized no earlier than the year in which the depletion is deductible on our federal income tax return. Income tax expense decreased by $ 0.9 million in 2015 as a result of realizing deferred depletion benefit from 2013 and 2014. This benefit is included in Other, net in the statutory rate reconciliation table. Uncertain tax positions are accounted for in accordance with accounting standards that require management’s assessment of the anticipated settlement outcome of material uncertain tax positions taken in a prior year, or planned to be taken in the current year. Until such positions are sustained, we would not recognize the uncertain tax benefits resulting from such positions. No reserves for uncertain tax positions were recorded as of December 31, 2017 , 2016 , or 2015 . Our federal income tax returns for tax years 2013 and earlier are closed by statute. The IRS Compliance Assurance Process (CAP) examination of the 2013, 2014, and 2015 tax years have been completed. There were no material changes to these returns as filed. The 2016 and 2017 tax years are currently under IRS CAP examination. Our 2018 CAP application has been accepted by the IRS. Under the CAP program, we work with the IRS to identify and resolve material tax matters before the tax return is filed each year. As of December 31, 2017 , income tax years 2014 through 2016 remain open for state examination. U.S. Federal TCJA Matters On December 22, 2017, the TCJA was enacted and permanently lowers the U.S. federal corporate income tax rate to 21% from the existing maximum rate of 35% , effective for our tax year beginning January 1, 2018. The TCJA includes specific provisions related to regulated public utilities that provide for the continued deductibility of interest expense and the elimination of bonus depreciation for property acquired after September 27, 2017. As a result of the reduction of the U.S. corporate income tax rate to 21% , U.S. GAAP requires deferred tax assets and liabilities be revalued as of the date of enactment, with resulting tax effects accounted for in the reporting period of enactment. We recorded a net revaluation of deferred tax asset and liability balances of $196.4 million as of December 31, 2017 . This revaluation had no impact on our 2017 cash flows. The net change in our utility deferred taxes, that were determined to have previously been included in ratemaking activities by the OPUC and WUTC, was recorded as a net regulatory liability that is expected to accrue to the future benefit of customers. It is possible that this estimated regulatory liability balance of $213.3 million , which includes a gross up for income taxes of $56.5 million , may increase or decrease as a result of future regulatory guidance by the OPUC and WUTC or as additional authoritative interpretation of the TCJA becomes available. The change in our utility deferred taxes of $18.2 million , associated with tax benefits that have previously been flowed through to customers or for the equity portion of AFUDC, resulted in an identical reduction in the associated regulatory assets. This change had no impact on our income tax expense. The net change in our utility deferred taxes, that were determined to have been previously excluded from ratemaking activities by the OPUC and WUTC, and the change in deferred taxes associated with the gas storage segment and other non-regulated operations, was recorded as a net reduction of income tax expense of $21.4 million . Under pre-TCJA law, business interest is generally deductible in the determination of taxable income. The TCJA imposes a new limitation on the deductibility of net business interest expense in excess of approximately 30% of adjusted taxable income. Taxpayers operating in the trade or business of public regulated utilities are excluded from these new interest expense limitations. There is uncertainty whether the new interest expense limitation may apply to our non-regulated operations. The legislative history indicates that all members of a consolidated or affiliated group are treated as a single taxpayer with respect to applying business interest limitations. Future authoritative guidance may indicate that net interest expense must be allocated between regulated and non-regulated activities within the consolidated group. Until such time that additional guidance is available that eliminates this uncertainty, we are unable to estimate whether the new interest limitation rules will impact our future operating results. The new interest limitation rules are effective for taxable years beginning after December 31, 2017. There is no grandfathering for debt instruments outstanding prior to such date. Net business interest expense amounts disallowed may be carried forward indefinitely and treated as interest in succeeding taxable years. The TCJA generally provides for immediate full expensing for qualified property acquired and placed in service after September 27, 2017 and before January 1, 2023. This would generally provide for accelerated cost recovery for capital investments. However, the definition of qualified property excludes property used in the trade or business of a public regulated utility. The definition of utility trade or business is the same as that used by the TCJA with respect to the imposition of the net interest expense limitation discussed above. As a result, a similar uncertainty exists with respect to whether the exclusion from full expensing will apply to our full consolidated group, which primarily operates as a regulated public utility, or whether full expensing will be available to our non-regulated activities. An additional uncertainty exists with respect to whether 50% bonus depreciation, which was in effect prior to the TCJA, will apply to property for which a contract was entered into or significant construction had occurred prior to September 27, 2017, but that was not placed in service until after that date. We excluded all assets placed in service by the consolidated group after September 27, 2017 from bonus depreciation. If future authoritative guidance indicates that bonus depreciation is available to us for these capital expenditures, this would primarily result in a decrease to our current income taxes payable and an increase in regulatory liability. The SEC staff issued Staff Accounting Bulletin 118, which provides guidance on accounting for the tax effects of the TCJA. SAB 118 provides a measurement period that should not extend beyond one year from the TCJA enactment date for companies to complete the accounting under ASC 740. To the extent that a company’s accounting for certain income tax effects of the TCJA is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. Consistent with SAB 118, the determination to exclude all assets placed in service after September 27, 2017 from bonus depreciation is provisional. We primarily operate in the States of Oregon and Washington. The extent to which a particular state adopts the U.S. Internal Revenue Code directly affects the application of the enacted federal changes of the TCJA to its taxable income computation. To varying degrees, Oregon and Washington corporate business tax approaches rely on federal income tax law, including the Internal Revenue Code and the associated Treasury regulations. It is possible that the federal changes resulting from the TCJA will cause states to reassess their future conformity, however, we have evaluated the state impacts of the TCJA under current law. Oregon automatically adopts changes to the U.S. Internal Revenue Code related to the calculation of consolidated corporate taxable income. By both State statute and administrative rule, Oregon corporation excise tax law, as related to the definition of taxable income, is tied to federal tax law as applicable to our tax year. Changes enacted to the definition of federal taxable income by the TCJA are effective for Oregon tax purposes in the same manner as for federal tax purposes. As a result, the net interest limitation and full expensing exclusions, discussed above, apply to Oregon as well. Washington State does not have a corporate income tax, but rather imposes a tax on our gross receipts. The TCJA does not include a change to the definition of gross receipts, or the timing of their recognition, that is currently anticipated to impact us. As a result, no change to Washington State reporting is anticipated.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Public Utilities, Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Text Block]	10. PROPERTY, PLANT, AND EQUIPMENT The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation at December 31: In thousands 2017 2016 Utility plant in service $ 2,975,217 $ 2,843,243 Utility construction work in progress 159,924 62,264 Less: Accumulated depreciation 942,879 903,096 Utility plant, net 2,192,262 2,002,411 Non-utility plant in service 75,639 299,378 Non-utility construction work in progress 4,671 3,931 Less: Accumulated depreciation 17,598 44,820 Non-utility plant, net 62,712 258,489 Total property, plant, and equipment $ 2,254,974 $ 2,260,900 Capital expenditures in accrued liabilities $ 34,976 $ 9,547 The weighted average depreciation rate for utility assets was 2.8% for utility assets during 2017, 2016, and 2015. The weighted average depreciation rate for non-utility assets was 1.9% in 2017 , 2.0% in 2016 , and 2.2% in 2015 . Accumulated depreciation does not include the accumulated provision for asset removal costs of $360.9 million and $ 341.1 million at December 31, 2017 and 2016 , respectively. These accrued asset removal costs are reflected on the balance sheet as regulatory liabilities. See Note 2 . During 2017 and 2016, we did not acquire any equipment under capital leases.

Gas Reserves

Gas Reserves	12 Months Ended
	Dec. 31, 2017
Gas Reserves [Abstract]
Gas Reserves [Text Block]	11. GAS RESERVES We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of December 31, 2017. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the consolidated balance sheets. Our investment in gas reserves provides long-term price protection for utility customers through the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested. We entered into our original agreements with Encana in 2011 under which we hold working interests in certain sections of the Jonah Field. Gas produced in these sections is sold at prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to the utility's cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our investment under the original agreement, less accumulated amortization and deferred taxes, earns a rate of return. In March 2014, we amended the original gas reserves agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field. We also retained the right to invest in new wells with Jonah Energy. Under the amended agreement we still have the option to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, but have not had the opportunity to participate in additional wells since 2014. However, we may have the opportunity to participate in more wells in the future. Gas produced from the additional wells is included in our Oregon PGA at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment. Gas reserves acted to hedge the cost of gas for approximately 6% , 8% and 11% of our utility's gas supplies for the years ended December 31, 2017 , 2016 , and 2015 respectively. The following table outlines our net gas reserves investment at December 31: In thousands 2017 2016 Gas reserves, current $ 15,704 $ 15,926 Gas reserves, non-current 171,832 171,610 Less: Accumulated amortization 87,779 71,426 Total gas reserves (1) 99,757 116,110 Less: Deferred taxes on gas reserves 22,712 28,119 Net investment in gas reserves $ 77,045 $ 87,991 (1) Our net investment in additional wells included in total gas reserves was $ 5.8 million and $ 6.7 million at December 31, 2017 and 2016, respectively. Our investment is included in our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.

Investments

Investments	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
Investments [Text Block]	12. INVESTMENTS Investments include financial investments in life insurance policies, and equity method investments in certain partnerships and limited liability companies. The following table summarizes our other investments at December 31: In thousands 2017 2016 Investments in life insurance policies $ 50,792 $ 52,719 Investments in gas pipeline 13,669 13,767 Other 1,902 1,890 Total other investments $ 66,363 $ 68,376 Investment in Life Insurance Policies We have invested in key person life insurance contracts to provide an indirect funding vehicle for certain long-term employee and director benefit plan liabilities. The amount in the above table is reported at cash surrender value, net of policy loans. Investments in Gas Pipeline TWP, a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural, owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. Variable Interest Entity (VIE) Analysis TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity, and there are no stipulations that allow us a disproportionate influence over it. Our investments in TWH and TWP are included in other investments on our balance sheet. If we do not develop this investment, then our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at December 31, 2017 and 2016 . Impairment Analysis Our investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment at each reporting period and following updates to our corporate planning assumptions. If it is determined a loss in value is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value. Fair value is based on quoted market prices when available or on the present value of expected future cash flows. Differing assumptions could affect the timing and amount of a charge recorded in any period. In 2011, TWP withdrew its original application with the FERC for a proposed natural gas pipeline in Oregon and informed FERC that it intended to re-file an application to reflect changes in the project scope aligning the project with the region’s current and future gas infrastructure needs. TWP continues working with customers in the Pacific Northwest to further understand their gas transportation needs and determine the commercial support for a revised pipeline proposal. A new FERC certificate application is expected to be filed to reflect a revised scope based on these regional needs. Our equity investment was not impaired at December 31, 2017 as the fair value of expected cash flows from planned development exceeded our remaining equity investment of $ 13.4 million at December 31, 2017 . However, if we learn that the project is not viable or will not go forward, we could be required to recognize a maximum charge of up to approximately $ 13.4 million based on the current amount of our equity investment, net of cash and working capital at TWP. We will continue to monitor and update our impairment analysis as required.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments [Text Block]	13. DERIVATIVE INSTRUMENTS We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options, and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts. We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars. In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment. We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers. Notional Amounts The following table presents the absolute notional amounts related to open positions on our derivative instruments: At December 31, In thousands 2017 2016 Natural gas (in therms): Financial 429,100 477,430 Physical 520,268 535,450 Foreign exchange $ 7,669 $ 7,497 Purchased Gas Adjustment (PGA) Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. In general, our commodity hedging for the current gas year is completed prior to the start of the gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. Hedge contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. We entered the 2017 -18 and 2016-17 gas year with our forecasted sales volumes hedged at 49% and 48% in financial swap and option contracts, and 26% and 27% in physical gas supplies, respectively. Hedge contracts entered into prior to our PGA filing, in September 2017, were included in the PGA for the 2017 -18 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings and qualify for regulatory deferral. Unrealized and Realized Gain/Loss The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments: December 31, 2017 December 31, 2016 In thousands Natural gas commodity Foreign exchange Natural gas commodity Foreign exchange Benefit (expense) to cost of gas $ (26,000 ) $ 107 $ 22,746 $ (130 ) Operating revenues (1,021 ) — 995 — Amounts deferred to regulatory accounts on balance sheet 26,665 (107 ) (23,394 ) 130 Total gain (loss) in pre-tax earnings $ (356 ) $ — $ 347 $ — UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability. REALIZED GAIN/LOSS. We realized net losses of $ 7.8 million and $26.9 million for the years ended December 31, 2017 and 2016 , respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year. Credit Risk Management of Financial Derivatives Instruments No collateral was posted with or by our counterparties as of December 31, 2017 or 2016 . We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we were not subject to collateral calls in 2017 or 2016 . Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based on current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $ 22.3 million at December 31, 2017 , we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows: Credit Rating Downgrade Scenarios In thousands (Current Ratings) A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Specul-ative With Adequate Assurance Calls $ — $ — $ — $ (5,428 ) $ (15,422 ) Without Adequate Assurance Calls — — — (5,428 ) (11,594 ) Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. We and our counterparties have the ability to set-off obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event. If netted by counterparty, our derivative position would result in an asset of $2.9 million and a liability of $23.3 million as of December 31, 2017 . As of December 31, 2016 , our derivative position would have resulted in an asset of $ 18.8 million and a liability of $ 0.7 million . We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. We utilize master netting arrangements through International Swaps and Derivatives Association contracts to minimize this risk along with collateral support agreements with counterparties based on their credit ratings. In certain cases, we require guarantees or letters of credit from counterparties to meet our minimum credit requirement standards. Our financial derivatives policy requires counterparties to have a certain investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. We do not speculate with derivatives; instead, we use derivatives to hedge our exposure above risk tolerance limits. Any increase in market risk created by the use of derivatives should be offset by the exposures they modify. We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral, or guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial condition, government actions, and market news. We use a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices. The results of the model are used to establish earnings-at-risk trading limits. Our credit risk for all outstanding financial derivatives at December 31, 2017 extends to March 2020 . We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss; however, we would expect such a loss to be eligible for regulatory deferral and rate recovery, subject to a prudence review. All of our existing counterparties currently have investment-grade credit ratings. Fair Value In accordance with fair value accounting, we include non-performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads, and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at December 31, 2017 . As of December 31, 2017 and 2016 , the net fair value was a liability of $ 20.3 million and an asset of $ 18.1 million , respectively, using significant other observable, or Level 2, inputs. No Level 3 inputs were used in our derivative valuations, and there were no transfers between Level 1 or Level 2 during the years ended December 31, 2017 and 2016 .

Commitments and Contigencies

Commitments and Contigencies	12 Months Ended
	Dec. 31, 2017
Disclosure Commitments And Contingencies [Abstract]
Commitments and Contingencies [Text Block]	14. COMMITMENTS AND CONTINGENCIES Leases We lease land, buildings, and equipment under agreements that expire in various years, including a 99-year land lease that extends through 2108 . Rental costs were $ 7.5 million , $ 6.2 million , and $ 5.5 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, a portion of which is capitalized. The following table reflects the future minimum lease payments due under non-cancelable leases at December 31, 2017 . These commitments relate principally to the lease of our office headquarters, underground gas storage facilities, and computer equipment. In thousands Operating leases Capital leases Minimum lease payments 2018 $ 5,378 $ 3 $ 5,381 2019 5,379 — 5,379 2020 6,945 — 6,945 2021 7,482 — 7,482 2022 7,629 — 7,629 Thereafter 169,411 — 169,411 Total $ 202,224 $ 3 $ 202,227 In October 2017, we entered into a 20 -year operating lease agreement for a new headquarters in Portland, Oregon in anticipation of the expiration of our current lease in 2020 . Payments under the new lease are expected to commence in 2020 . Total estimated base rent payments over the life of the lease are approximately $160 million and have been included in the table above. We have the option to extend the term of the lease for two additional seven -year periods. Additionally, the lease was analyzed in consideration of build-to-suit lease accounting guidance, and we concluded that we are the accounting owner of the asset during construction. As a result, we recognized $0.5 million in Property, plant and equipment and an obligation in Other non-current liabilities for the same amount on our consolidated balance sheet at December 31, 2017. Gas Purchase and Pipeline Capacity Purchase and Release Commitments We have signed agreements providing for the reservation of firm pipeline capacity under which we are required to make fixed monthly payments for contracted capacity. The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies. In addition, we have entered into long-term sale agreements to release firm pipeline capacity. We also enter into short-term and long-term gas purchase agreements. The aggregate amounts of these agreements were as follows at December 31, 2017 : In thousands Gas Pipeline Pipeline 2018 $ 63,944 $ 79,891 $ 3,581 2019 2,729 82,129 — 2020 2,729 77,028 — 2021 2,273 65,630 — 2022 — 60,050 — Thereafter — 601,844 — Total 71,675 966,572 3,581 Less: Amount representing interest 601 174,542 24 Total at present value $ 71,074 $ 792,030 $ 3,557 Our total payments for fixed charges under capacity purchase agreements were $ 85.3 million for 2017 , $85.0 million for 2016 , and $ 85.2 million for 2015 . Included in the amounts were reductions for capacity release sales of $ 4.5 million for 2017 , $4.5 million for 2016 , and $ 4.4 million for 2015 . In addition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements. In certain take-or-pay purchase commitments, annual deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements. Environmental Matters Refer to Note 15 for a discussion of environmental commitments and contingencies.

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2017
Environmental Remediation Obligations [Abstract]
Environmental Matters [Text Block]	15. ENVIRONMENTAL MATTERS We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties (PRPs). When amounts are prudently expended related to site remediation of those sites described herein, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding. Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After a ROD is issued, we would seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We would have the ability to further refine estimates of remediation liabilities at that time. Remediation may include treatment of contaminated media such as sediment, soil and groundwater, removal and disposal of media, institutional controls such as legal restrictions on future property use, or natural recovery. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring, and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described below. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated where a range of potential loss is available. Unless there is an estimate within the range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations, and the determination by regulators of remediation alternatives. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims from third-party tribal entities. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. Refer to "Other Portland Harbor" below. Environmental Sites The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet at December 31: Current Liabilities Non-Current Liabilities In thousands 2017 2016 2017 2016 Portland Harbor site: Gasco/Siltronic Sediments $ 2,683 $ 869 $ 45,346 $ 43,972 Other Portland Harbor 1,949 1,970 4,163 4,148 Gasco/Siltronic Upland site 13,422 10,657 47,835 49,183 Central Service Center site 25 73 — — Front Street site 1,009 906 10,757 7,786 Oregon Steel Mills — — 179 179 Total $ 19,088 $ 14,475 $ 108,280 $ 105,268 PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands sites. We are one of over one hundred PRPs to the Superfund site. In January 2017, the EPA issued its Record of Decision, which selects the remedy fund for the clean-up of the Portland Harbor site (Portland Harbor ROD). The Portland Harbor ROD estimates the present value total cost at approximately $1.05 billion with an accuracy between -30% and +50% of actual costs. Our potential liability is a portion of the costs of the remedy for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. In addition, we are actively pursuing clarification and flexibility under the ROD in order to better understand our obligation under the clean-up. We are also participating in a non-binding allocation process with the other PRPs in an effort to resolve our potential liability. The Portland Harbor ROD does not provide any additional clarification around allocation of costs among PRPs and, as a result of issuance of the Portland Harbor ROD, we have not modified any of our recorded liabilities at this time. We manage our liability related to the Superfund site as two distinct remediation projects: the Gasco/Siltronic Sediments and Other Portland Harbor projects. Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA, for the additional studies and design work needed before the cleanup can occur, and for regulatory oversight throughout the clean-up range from $48.0 million to $350 million . We have recorded a liability of $ 48.0 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site discussed above. Other Portland Harbor. While we still believe liabilities associated with the Gasco/Siltronic sediments site represent our largest exposure, we do have other potential exposures associated with the Portland Harbor ROD, including NRD costs and harborwide clean-up costs (including downstream petroleum contamination), for which allocations among the PRPs have not yet been determined. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased NRD assessment to estimate liabilities to support an early restoration-based settlement of NRD claims. One member of this Trustee council, the Yakama Nation, withdrew from the council in 2009, and in 2017, filed suit against the Company and 29 other parties seeking remedial costs and NRD assessment costs associated with the Portland Harbor, set forth in the complaint. The complaint seeks recovery of alleged costs totaling $0.3 million in connection with the selection of a remedial action for the Portland Harbor as well as declaratory judgment for unspecified future remedial action costs and for costs to assess the injury, loss, or destruction of natural resources resulting from the release of hazardous substances at and from the Portland Harbor site. The Yakama Nation has filed two amended complaints addressing certain pleading defects and dismissing the State of Oregon. We have recorded a liability for NRD claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. The NRD liability is not included in the aforementioned range of costs provided in the Portland Harbor ROD. GASCO UPLANDS SITE. A predecessor of NW Natural, Portland Gas and Coke Company, owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program (VCP). It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts: the uplands portion and the groundwater source control action. We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time. In October 2016, ODEQ and NW Natural agreed to amend their VCP agreement to incorporate a portion of the Siltronic property adjacent to the Gasco site formerly owned by Portland Gas & Coke between 1939 and 1960 into the Gasco RA and FS, excluding the uplands for Siltronic. Previously, we were conducting an investigation of manufactured gas plant constituents on the entire Siltronic uplands for ODEQ. Siltronic will be working with ODEQ directly on environmental impacts to the remainder of its property. In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure. OTHER SITES. In addition to those sites above, we have environmental exposures at three other sites: Central Service Center, Front Street, and Oregon Steel Mills. We may have exposure at other sites that have not been identified at this time. Due to the uncertainty of the design of remediation, regulation, timing of the remediation, and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time. Central Service Center site. We are currently performing an environmental investigation of the property under ODEQ's Independent Cleanup Pathway. This site is on ODEQ's list of sites with confirmed releases of hazardous substances, and cleanup is necessary. Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. In July 2017, ODEQ issued the PGM ROD. The ROD specifies the selected remedy, which requires a combination of dredging, capping, treatment, and natural recovery. In addition, the selected remedy also requires institutional controls and long-term inspection and maintenance. We revised the liability in the second quarter of 2017 to incorporate the estimated undiscounted cost of approximately $10.5 million for the selected remedy. Further, we have recognized an additional liability of $1.3 million for additional studies and design costs as well as regulatory oversight throughout the clean-up. We plan to complete the remedial design in 2018 and expect to construct the remedy details during 2019. Oregon Steel Mills site. Refer to the “Legal Proceedings,” below. Site Remediation and Recovery Mechanism (SRRM) We have an SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test, for those sites identified therein. In the February 2015 Order establishing the SRRM (2015 Order), the OPUC addressed outstanding issues related to the SRRM, which required us to forego the collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs. As a follow-up to the 2015 Order, the OPUC issued an additional Order in January 2016 (2016 Order) regarding the SRRM implementation in which the OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we recognized a $3.3 million non-cash charge in the first quarter, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense. COLLECTIONS FROM OREGON CUSTOMERS. Under the SRRM collection process there are three types of deferred environmental remediation expense: • Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. • Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. • Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. In addition to the collection amount noted above, the Order also provides for the annual collection of $5.0 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize an equal and offsetting amount of our deferred regulatory asset balance through the environmental remediation operating expense line shown separately in the operating expense section of the income statement. We received total environmental insurance proceeds of approximately $150.0 million as a result of settlements from our litigation that was dismissed in July 2014. Under the 2015 OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012 with the remaining two-thirds applied to costs at a rate of $5.0 million per year plus interest over the following 20 years. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of December 31, 2017 , we have applied $68.2 million of insurance proceeds to prudently incurred remediation costs allocated to Oregon. The following table presents information regarding the total regulatory asset deferred as of December 31: In thousands 2017 2016 Deferred costs and interest (1) $ 45,546 $ 53,039 Accrued site liabilities (2) 126,950 119,443 Insurance proceeds and interest (94,170 ) (98,523 ) Total regulatory asset deferral (1) $ 78,326 $ 73,959 Current regulatory assets (3) 6,198 9,989 Long-term regulatory assets (3) 72,128 63,970 (1) Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers. (2) Excludes 3.32% of the Front Street site liability, or $0.4 million in 2017 and $0.3 million in 2016, as the OPUC only allows recovery of 96.68% of costs for those sites allocable to Oregon, including those that historically served only Oregon customers. (3) Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. ENVIRONMENTAL EARNINGS TEST. To the extent the utility earns at or below its authorized Return of Equity (ROE), remediation expenses and interest in excess of the $5.0 million tariff rider and $5.0 million insurance proceeds are recoverable through the SRRM. To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10.0 million with those earnings that exceed its authorized ROE. Under the 2015 Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if we gain greater certainty about our future remediation costs, to consider whether adjustments to the mechanism may be appropriate. WASHINGTON DEFERRAL. In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Legal Proceedings NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations, or cash flows. OREGON STEEL MILLS SITE. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. In August 2017, the case was stayed pending outcome of the Portland Harbor allocation process or other remediation. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations, or cash flows. For additional information regarding other commitments and contingencies, see Note 14.

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2017
Schedule Of Quarterly Financial Information [Abstract]
Quarterly Financial Information [Text Block]	NORTHWEST NATURAL GAS COMPANY QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2017 Operating revenues $ 297,323 $ 136,238 $ 88,190 $ 240,422 Net income (loss) 40,310 2,729 (8,495 ) (90,167 ) Basic earnings (loss) per share (1) 1.41 0.10 (0.30 ) (3.14 ) Diluted earnings (loss) per share (1) 1.40 0.10 (0.30 ) (3.14 ) 2016 Operating revenues $ 255,529 $ 99,183 $ 87,727 $ 233,528 Net income (loss) 36,641 2,019 (8,040 ) 28,275 Basic earnings (loss) per share (1) 1.33 0.07 (0.29 ) 1.01 Diluted earnings (loss) per share (1) 1.33 0.07 (0.29 ) 1.00 (1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

Valuation Allowances and Reserv

Valuation Allowances and Reserves	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule of Valuation and Qualifying Accounts [Text Block]	NORTHWEST NATURAL GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E Additions Deductions In thousands (year ended December 31) Balance at beginning of period Charged to costs and expenses Charged to other accounts Net write-offs Balance at end of period 2017 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 1,290 $ 865 $ — $ 1,199 $ 956 2016 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 870 $ 1,246 $ — $ 826 $ 1,290 2015 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 969 $ 760 $ — $ 859 $ 870

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), Northwest Natural Water Company (NWN Water), FWC Merger Sub, Inc., and NWN Gas Reserves LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, include NWN Financial's investment in Kelso-Beaver Pipeline and NWN Energy's investment in Trail West Holdings, LLC (TWH), which is accounted for under the equity method. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes. Actual amounts could differ from those estimates, and changes would most likely be reported in future periods. Management believes the estimates and assumptions used are reasonable .
Public Utilities, Policy [Policy Text Block]	Industry Regulation Our principal businesses are the distribution of natural gas, which is regulated by the OPUC and WUTC, and natural gas storage services, which are regulated by either the FERC or the CPUC, and to a certain extent by the OPUC and WUTC. Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP. Our businesses regulated by the OPUC, WUTC, and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates). In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Pronouncements DERIVATIVES AND HEDGING. On August 28, 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities." The purpose of the amendment is to more closely align hedge accounting with companies’ risk management strategies. The ASU amends the accounting for risk component hedging, the hedged item in fair value hedges of interest rate risk, and amounts excluded from the assessment of hedge effectiveness. The guidance also amends the recognition and presentation of the effect of hedging instruments and includes other simplifications of hedge accounting. The amendments in this update are effective for us beginning January 1, 2019. Early adoption is permitted. The amended presentation and disclosure guidance is required prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures. STOCK COMPENSATION. On May 10, 2017, the FASB issued ASU 2017-09, "Stock Compensation - Scope of Modification Accounting." The purpose of the amendment is to provide clarity, reduce diversity in practice and reduce the cost and complexity when applying the guidance in ASC 718, related to a change to the terms or conditions of a share-based payment award. The ASU amends the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. Specifically, an entity would not apply modification accounting if the fair value, vesting conditions, and classification of the awards are the same immediately before and after the modification. The amendments in this update are effective for us beginning January 1, 2018. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. We do not expect this standard to materially affect our financial statements and disclosures. RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. Only the service cost component of the net periodic benefit cost is eligible for capitalization. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. On December 28, 2017, the FERC issued Docket AI18-1-000 stating that it will allow entities to change their capitalization policy for regulatory accounting and reporting purposes to be consistent with the new US GAAP requirements. This change will be allowed as a one-time policy election upon adoption of the guidance. We have elected to adopt the new ASU for FERC regulatory accounting and reporting purposes. We anticipate that this adoption will reduce amounts capitalized to plant. However, this reduction will be largely offset by deferrals to our pension regulatory balancing mechanism, and therefore, we do not expect this standard to materially affect our financial position. STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. We do not expect this standard to materially affect our financial statements and disclosures. LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. On November 29, 2017, the FASB proposed an additional practical expedient that would allow entities to apply the transition requirements on the effective date of the standard. On January 25, 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842", to address the costs and complexity of applying the transition provisions of the new lease standard to land easements. This ASU provides an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under the current lease guidance. We are evaluating additional amendments reached by the FASB, and we are currently assessing our lease population and material contracts to determine the effect of this standard on our financial statements and disclosures. Refer to Note 14 for our current lease commitments. FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Any impacts as a result of the implementation of this ASU will be made through a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. We do not expect this standard to have a material impact to our financial statements and disclosures. REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or modified retrospective adoption method. The new standard is effective for us beginning January 1, 2018, and we have elected to adopt the standard using the modified retrospective approach. We are in the process of updating our accounting policies, processes, systems, and internal controls as a result of implementing the new standard. We have analyzed our revenue streams, material contracts with customers, and the expanded disclosure requirements under the new standard and determined that the standard will not have a material impact on our financial position, net income, or cash flows.
Property, Plant and Equipment, Policy [Policy Text Block]	Plant, Property, and Accrued Asset Removal Costs Plant and property are stated at cost, including capitalized labor, materials, and overhead. In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest. AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “ AFUDC ” below). When constructed assets are subject to market-based rates rather than cost-based rates, the financing costs incurred during construction are included in capitalized interest in accordance with U.S. GAAP, not as regulatory financing costs under AFUDC.
Asset Removal Costs [Policy Text Block]	In accordance with long-standing regulatory treatment, our depreciation rates consist of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset’s estimated cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation. These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs as non-current regulatory liabilities rather than as accumulated depreciation on our consolidated balance sheets. In the rate setting process, the liability for removal costs is treated as a reduction to the net rate base on which the regulated utility has the opportunity to earn its allowed rate of return. The costs of utility plant retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. Gains from the sale of regulated assets are generally deferred and refunded to customers. For non-utility assets, we record a gain or loss upon the disposal of the property, and the gain or loss is recorded in operating income or loss in the consolidated statements of comprehensive income or loss.
Depreciation, Depletion, and Amortization [Policy Text Block]	Our provision for depreciation of utility property, plant, and equipment is recorded under the group method on a straight-line basis with rates computed in accordance with depreciation studies approved by regulatory authorities. The weighted-average depreciation rate for utility assets in service was approximately 2.8 % for 2017 , 2016 , and 2015 , reflecting the approximate weighted-average economic life of the property. This includes 2017 weighted-average depreciation rates for the following asset categories: 2.7 % for transmission and distribution plant, 2.3 % for gas storage facilities, 4.4 % for general plant, and 2.7 % for intangible and other fixed assets.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	AFUDC. Certain additions to utility plant include AFUDC, which represents the net cost of debt and equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for ROE, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and on ROE funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rate was 5.5 % in 2017 , 0.7 % in 2016 , and 0.4% in 2015 .
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	IMPAIRMENT OF LONG-LIVED ASSETS. We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Factors that would necessitate an impairment assessment of long-lived assets include a significant adverse change in the extent or manner in which the asset is used, a significant adverse change in legal factors or business climate that could affect the value of the asset, or a significant decline in the observable market value or expected future cash flows of the asset, among others. When such factors are present, we assess the recoverability by determining whether the carrying value of the asset will be recovered through expected future cash flows. An asset is determined to be impaired when the carrying value of the asset exceeds the expected undiscounted future cash flows from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss for the difference between the carrying value and the fair value of the long-lived assets. Fair value is estimated using appropriate valuation methodologies, which may include an estimate of discounted cash flows. In the fourth quarter of 2017, we recognized a non-cash pre-tax impairment of long-lived assets at the Gill Ranch Facility of $192.5 million , which is included in our gas storage segment. We determined circumstances existed that indicated the carrying value of the assets may not be recoverable. Those circumstances included the completion of a comprehensive strategic review process that evaluated various alternatives including a potential sale, as well as contracting for available storage at lower than anticipated values for the coming storage year. Given these considerations, management was required to re-evaluate the estimated cash flows from our interests in the Gill Ranch Facility, and has determined that those estimated cash flows are no longer sufficient to cover the carrying value of the assets. We did not recognize any impairments in 2016 or 2015. We used the income approach to estimate fair value, using the estimated future net cash flows of the Gill Ranch Facility. We also compared the results of the income approach to our own recent sale process experience and recent market comparable transactions in order to estimate fair value.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with original maturity dates of three months or less. At December 31, 2017 and 2016 , outstanding checks of approximately $ 4.8 million and $ 2.9 million , respectively, were included in accounts payable.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition and Accrued Unbilled Revenue Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of the gas commodity or service to customers. Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenue). Accrued unbilled revenue is dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer use by billing cycle, and weather factors. Accrued unbilled revenue is reversed the following month when actual billings occur. Our accrued unbilled revenue at December 31, 2017 and 2016 was $ 62.4 million and $64.9 million , respectively. Non-utility revenues are derived primarily from the gas storage segment. At our Mist underground storage facility, revenues are primarily firm service revenues in the form of fixed monthly reservation charges. At the Gill Ranch Facility, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. In addition, we also have asset management service revenue from an independent energy marketing company that optimizes commodity, storage, and pipeline capacity release transactions. Under this agreement, guaranteed asset management revenue is recognized using a straight-line, pro-rata methodology over the term of each contract. Revenues earned above the guaranteed amount are recognized as they are earned.
Revenue Tax Policy [Text Block]	Revenue Taxes Revenue-based taxes are primarily franchise taxes, which are collected from customers and remitted to taxing authorities. Revenue taxes are included in operating revenues in the statement of comprehensive income or loss. Revenue taxes were $19.1 million , $17.1 million , and $18.0 million for 2017 , 2016 , and 2015 , respectively.
Receivables, Policy [Policy Text Block]	Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to utility customers, plus amounts due for gas storage services. We establish an allowance for uncollectible accounts (allowance) for trade receivables, including accrued unbilled revenue, based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues. A specific allowance is established and recorded for large individual customer receivables when amounts are identified as unlikely to be partially or fully recovered. Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed uncollectible. Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer creditworthiness, and natural gas prices. The allowance for uncollectible accounts is adjusted quarterly, as necessary, based on information currently available.
Inventory, Policy [Policy Text Block]	Inventories Utility gas inventories, which consist of natural gas in storage for the utility, are stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates. Utility gas inventories injected into storage are priced in inventory based on actual purchase costs. Utility gas inventories withdrawn from storage are charged to cost of gas during the current period they are withdrawn at the weighted-average inventory cost. Gas storage inventories, which primarily represent inventories at the Gill Ranch Facility, mainly consist of natural gas received as fuel-in-kind from storage customers. Gas storage inventories are valued at the lower of average cost or net realizable value. Cushion gas is not included in our inventory balances, is recorded at original cost, and is classified as a long-term plant asset. Materials and supplies inventories consist of both utility and non-utility inventories and are stated at the lower of average cost or net realizable value. Our utility and gas storage inventories totaled $ 36.7 million and $ 42.7 million at December 31, 2017 and 2016 , respectively. At December 31, 2017 and 2016 , our materials and supplies inventories totaled $ 11.3 million and $ 11.4 million , respectively.
Gas Reserves Policy [Text Block]	Gas Reserves Gas reserves are payments to acquire and produce natural gas reserves. Gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. The current portion is calculated based on expected gas deliveries within the next fiscal year. We recognize regulatory amortization of this asset on a volumetric basis calculated using the estimated gas reserves and the estimated therms extracted and sold each month. The amortization of gas reserves is recorded to cost of gas along with gas production revenues and production costs. See Note 11 .
Derivatives, Policy [Policy Text Block]	Derivatives Derivatives are measured at fair value and recognized as either assets or liabilities on the balance sheet. Changes in the fair value of the derivatives are recognized currently in earnings unless specific regulatory or hedge accounting criteria are met. Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable. In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates. Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles. Our financial derivatives generally qualify for deferral under regulatory accounting. Our index-priced physical derivative contracts also qualify for regulatory deferral accounting treatment. Derivative contracts entered into for utility requirements after the annual PGA rate has been set and maturing during the PGA year are subject to the PGA incentive sharing mechanism. In Oregon we participate in a PGA sharing mechanism under which we are required to select either an 80% or 90% deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20% or 10% of gas cost differences compared to PGA prices, respectively. For the PGA years in Oregon beginning November 1, 2017 , 2016 , and 2015 , we selected the 90% , 90% , and 80% deferral of gas cost differences, respectively. In Washington, 100% of the differences between the PGA prices and actual gas costs are deferred. See Note 13 . Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters. Our objective for using derivatives is to decrease the volatility of gas prices, earnings, and cash flows without speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined not to exceed acceptable tolerance levels, and are determined necessary to support normal business activities. We do not enter into derivative instruments for trading purposes
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets, and our derivative fair value measurements: • Level 1: Valuation is based on quoted prices for identical instruments traded in active markets; • Level 2: Valuation is based on quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market; and • Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect our own estimates of assumptions market participants would use in valuing the asset or liability. When developing fair value measurements, it is our policy to use quoted market prices whenever available or to maximize the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available. Fair values are primarily developed using industry-standard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market interest rates and yield curves; (g) credit spreads; and (h) other relevant economic measures. The Company considers liquid points for its natural gas hedging to be those points for which there are regularly published prices in a nationally recognized publication or where the instruments are traded on an exchange.
Income Tax, Policy [Policy Text Block]	Income Taxes We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the enactment date period unless a regulatory Order specifies deferral of the effect of the change in tax rates over a longer period of time. Deferred income tax assets and liabilities are also recognized for temporary differences where the deferred income tax benefits or expenses have previously been flowed through in the ratemaking process of the regulated utility. Regulatory tax assets and liabilities are recorded on these deferred tax assets and liabilities to the extent we believe they will be recoverable from or refunded to customers in future rates. Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant. We recognize interest and penalties related to unrecognized tax benefits, if any, within income tax expense and accrued interest and penalties within the related tax liability line in the consolidated balance sheets. No accrued interest or penalties for uncertain tax benefits have been recorded. See Note 9 .
Commitments and Contingencies, Policy [Policy Text Block]	Environmental Contingencies Loss contingencies are recorded as liabilities when it is probable a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. With respect to environmental liabilities and related costs, we develop estimates based on a review of information available from numerous sources, including completed studies and site specific negotiations. It is our policy to accrue the full amount of such liability when information is sufficient to reasonably estimate the amount of probable liability. When information is not available to reasonably estimate the probable liability, or when only the range of probable liabilities can be estimated and no amount within the range is more likely than another, it is our policy to accrue at the low end of the range. Accordingly, due to numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the potential loss and the fact that the high end of the range cannot be reasonably estimated. See Note 15.
Subsequent Events, Policy [Policy Text Block]	Subsequent Events We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. We do not have any subsequent events to report.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Regulatory Assets [Table Text Block]	Regulatory Assets In thousands 2017 2016 Current: Unrealized loss on derivatives (1) $ 18,712 $ 1,315 Gas costs 154 6,830 Environmental costs (2) 6,198 9,989 Decoupling (3) 11,227 13,067 Income taxes 2,218 4,378 Other (4) 7,272 6,783 Total current $ 45,781 $ 42,362 Non-current: Unrealized loss on derivatives (1) $ 4,649 $ 913 Pension balancing (5) 60,383 50,863 Income taxes 19,991 38,670 Pension and other postretirement benefit liabilities 179,824 183,035 Environmental costs (2) 72,128 63,970 Gas costs 84 89 Decoupling (3) 3,970 5,860 Other (4) 15,579 14,130 Total non-current $ 356,608 $ 357,530
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory Liabilities In thousands 2017 2016 Current: Gas costs $ 14,886 $ 8,054 Unrealized gain on derivatives (1) 1,674 16,624 Decoupling (3) 322 — Other (4) 17,131 15,612 Total current $ 34,013 $ 40,290 Non-current: Gas costs $ 4,630 $ 1,021 Unrealized gain on derivatives (1) 1,306 3,265 Decoupling (3) 957 — Income taxes 213,306 — Accrued asset removal costs (6) 360,929 341,107 Other (4) 4,965 3,926 Total non-current $ 586,093 $ 349,319

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
EPS Calculation [Table Text Block]	In thousands, except per share data 2017 2016 2015 Net income (loss) $ (55,623 ) $ 58,895 $ 53,703 Average common shares outstanding - basic 28,669 27,647 27,347 Additional shares for stock-based compensation plans (See Note 6) — 132 70 Average common shares outstanding - diluted 28,669 27,779 27,417 Earnings (loss) per share of common stock - basic $ (1.94 ) $ 2.13 $ 1.96 Earnings (loss) per share of common stock - diluted $ (1.94 ) $ 2.12 $ 1.96 Additional information: Antidilutive shares 97 5 12

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	In thousands Utility Gas Storage Other Total 2017 Operating revenues $ 732,942 $ 23,620 $ 5,611 $ 762,173 Depreciation and amortization 79,734 5,844 — 85,578 Income (loss) from operations (1) 132,807 (185,074 ) (960 ) (53,227 ) Net income (loss) (2) 60,509 (116,209 ) 77 (55,623 ) Capital expenditures 211,672 1,923 — 213,595 Total assets at December 31, 2017 2,961,326 59,583 18,837 3,039,746 2016 Operating revenues $ 650,477 $ 25,266 $ 224 $ 675,967 Depreciation and amortization 76,289 6,000 — 82,289 Income (loss) from operations 130,570 9,136 (426 ) 139,280 Net income (loss) (3) 54,567 4,303 25 58,895 Capital expenditures 138,074 1,437 — 139,511 Total assets at December 31, 2016 2,806,627 256,333 16,841 3,079,801 2015 Operating revenues $ 702,210 $ 21,356 $ 225 $ 723,791 Depreciation and amortization 74,410 6,513 — 80,923 Income (loss) from operations 119,215 5,032 1 124,248 Net income (loss) (3) 53,391 174 138 53,703 Capital expenditures 115,272 3,048 — 118,320 Total assets at December 31, 2015 2,791,623 261,750 16,037 3,069,410
Utility Margin [Table Text Block]	In thousands 2017 2016 2015 Utility margin calculation: Utility operating revenues $ 732,942 $ 650,477 $ 702,210 Less: Utility cost of gas 325,019 260,588 327,305 Environmental remediation expense 15,291 13,298 3,513 Utility margin $ 392,632 $ 376,591 $ 371,392

Common Stock Shares Outstanding

Common Stock Shares Outstanding (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Summary Of Common Stock Shares Issued And Outstanding Table [Table Text Block]	In thousands Shares Balance, December 31, 2014 27,284 Sales to employees under ESPP 19 Stock-based compensation 78 Sales to shareholders under DRPP 46 Balance, December 31, 2015 27,427 Sales to employees under ESPP 18 Stock-based compensation 173 Equity Issuance 1,012 Balance, December 31, 2016 28,630 Sales to employees under ESPP 18 Stock-based compensation 88 Balance, December 31, 2017 28,736

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Payment Awards [Table Text Block]	Dollars in thousands Shares (1) Expense During Award Year (2) Total Expense for Award Estimated award: 2015-2017 grant (3) 18,300 $ (346 ) $ 1,169 Actual award: 2014-2016 grant 31,388 168 1,685 2013-2015 grant 8,914 312 1,240
Schedule Of Performance Based Award [Table Text Block]	Dollars in thousands Performance Share Awards Outstanding 2017 Cumulative Expense Performance Period Target Maximum Expense/(Reversal) December 31, 2017 2015-17 29,967 59,934 $ (346 ) $ 1,169 2016-18 24,826 49,652 337 815 2017-19 32,680 65,360 942 942 Total 87,473 174,946 $ 933
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]	Number of RSUs Weighted - Average Price Per RSU Nonvested, December 31, 2014 70,794 $ 44.00 Granted 37,264 46.29 Vested (19,003 ) 44.81 Forfeited (468 ) 44.99 Nonvested, December 31, 2015 88,587 44.78 Granted 40,271 54.36 Vested (29,488 ) 45.56 Forfeited (9,397 ) 44.59 Nonvested, December 31, 2016 89,973 48.85 Granted 32,168 60.51 Vested (35,341 ) 47.07 Forfeited (2,278 ) 53.78 Nonvested, December 31, 2017 84,522 53.90
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	Option Shares Weighted - Average Price Per Share Intrinsic Value (In millions) Balance outstanding, December 31, 2014 416,088 $ 43.40 $ 2.7 Exercised (62,900 ) 39.96 0.5 Forfeited (500 ) 45.74 n/a Balance outstanding, December 31, 2015 352,688 44.00 2.3 Exercised (172,525 ) 43.61 2.0 Forfeited — n/a n/a Balance outstanding, December 31, 2016 180,163 44.38 2.8 Exercised (88,275 ) 44.33 1.8 Forfeited (200 ) 41.15 n/a Balance outstanding and exercisable, December 31, 2017 91,688 44.43 1.4
Schedule Of Stock Based Compensation Capitalized Under LTIP SOP and ESPP [Table Text Block]	In thousands 2017 2016 2015 Operations and maintenance expense, for stock-based compensation $ 2,354 $ 2,370 $ 2,673 Income tax benefit (930 ) (924 ) (1,012 ) Net stock-based compensation effect on net income (loss) $ 1,424 $ 1,446 $ 1,661 Amounts capitalized for stock-based compensation $ 528 $ 554 $ 661

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Current and Noncurrent [Abstract]
Schedule of Maturities of Long-term Debt [Table Text Block]	In thousands Year 2018 $ 97,000 2019 30,000 2020 75,000 2021 60,000 2022 — Thereafter 524,700
Schedule of Debt [Table Text Block]	In thousands 2017 2016 First Mortgage Bonds 7.000 % Series B due 2017 $ — $ 40,000 1.545 % Series B due 2018 75,000 75,000 6.600 % Series B due 2018 22,000 22,000 8.310 % Series B due 2019 10,000 10,000 7.630 % Series B due 2019 20,000 20,000 5.370 % Series B due 2020 75,000 75,000 9.050 % Series A due 2021 10,000 10,000 3.176 % Series B due 2021 50,000 50,000 3.542 % Series B due 2023 50,000 50,000 5.620 % Series B due 2023 40,000 40,000 7.720 % Series B due 2025 20,000 20,000 6.520 % Series B due 2025 10,000 10,000 7.050 % Series B due 2026 20,000 20,000 3.211 % Series B due 2026 35,000 35,000 7.000 % Series B due 2027 20,000 20,000 2.822 % Series B due 2027 25,000 — 6.650 % Series B due 2027 19,700 19,700 6.650 % Series B due 2028 10,000 10,000 7.740 % Series B due 2030 20,000 20,000 7.850 % Series B due 2030 10,000 10,000 5.820 % Series B due 2032 30,000 30,000 5.660 % Series B due 2033 40,000 40,000 5.250 % Series B due 2035 10,000 10,000 4.000 % Series B due 2042 50,000 50,000 4.136 % Series B due 2046 40,000 40,000 3.685 % Series B due 2047 75,000 — 786,700 726,700 Less: Current maturities 97,000 40,000 Total long-term debt $ 689,700 $ 686,700
Fair Value Of Long Term Debt Table [Text Block]	December 31, In thousands 2017 2016 Gross long-term debt $ 786,700 $ 726,700 Unamortized debt issuance costs (6,813 ) (7,377 ) Carrying amount $ 779,887 $ 719,323 Estimated fair value $ 853,339 $ 793,339

Pension and Other Postretirem32

Pension and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Pension and Other Postretirement Benefit Expense [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	Postretirement Benefit Plans Pension Benefits Other Benefits In thousands 2017 2016 2017 2016 Reconciliation of change in benefit obligation: Obligation at January 1 $ 457,839 $ 445,628 $ 29,395 $ 31,049 Service cost 7,090 7,083 341 391 Interest cost 18,111 18,399 1,141 1,175 Net actuarial (gain) loss 34,829 7,688 (213 ) (1,488 ) Benefits paid (1) (31,580 ) (20,959 ) (1,737 ) (1,732 ) Obligation at December 31 $ 486,289 $ 457,839 $ 28,927 $ 29,395 Reconciliation of change in plan assets: Fair value of plan assets at January 1 $ 257,714 $ 249,338 $ — $ — Actual return on plan assets 40,308 12,593 — — Employer contributions 21,483 16,742 1,737 1,732 Benefits paid (1) (31,580 ) (20,959 ) (1,737 ) (1,732 ) Fair value of plan assets at December 31 $ 287,925 $ 257,714 $ — $ — Funded status at December 31 $ (198,364 ) $ (200,125 ) $ (28,927 ) $ (29,395 )
Schedule Of Amounts Recognized In Regulatory Assets Or Other Comprehensive Income Loss [Table Text Block]	Regulatory Assets Other Comprehensive Loss (Income) Pension Benefits Other Postretirement Benefits Pension Benefits In thousands 2017 2016 2015 2017 2016 2015 2017 2016 2015 Net actuarial loss (gain) $ 12,177 $ 14,005 $ 419 $ (214 ) $ (1,488 ) $ 2,724 $ 2,777 $ (1,196 ) $ (2,549 ) Settlement Loss — — — — — — — 193 — Amortization of: Prior service cost (127 ) (230 ) (230 ) 468 468 (197 ) — — — Actuarial loss (14,802 ) (13,238 ) (16,372 ) (696 ) (705 ) (554 ) (946 ) 1,386 (2,236 ) Total $ (2,752 ) $ 537 $ (16,183 ) $ (442 ) $ (1,725 ) $ 1,973 $ 1,831 $ 383 $ (4,785 )
Schedule Of Defined Benefit Plan Amounts In AOCL And Regulatory Assets [Table Text Block]	Regulatory Assets AOCL Pension Benefits Other Postretirement Benefits Pension Benefits In thousands 2017 2016 2017 2016 2017 2016 Prior service cost (credit) $ 49 $ 176 $ (2,206 ) $ (2,675 ) $ — $ 1 Net actuarial loss 175,035 177,660 6,964 7,874 13,266 11,434 Total $ 175,084 $ 177,836 $ 4,758 $ 5,199 $ 13,266 $ 11,435
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Year Ended December 31, In thousands 2017 2016 Beginning balance $ (6,951 ) $ (7,162 ) Amounts reclassified to AOCL (2,794 ) (1,196 ) Amounts reclassified from AOCL: Amortization of actuarial losses 946 1,386 Loss from plan settlement — 193 Total reclassifications before tax (1,848 ) 383 Tax expense (benefit) 361 (172 ) Total reclassifications for the period (1,487 ) 211 Ending balance $ (8,438 ) $ (6,951 )
Schedule of Allocation of Plan Assets [Table Text Block]	In thousands December 31, 2017 Investments Level 1 Level 2 Level 3 Non-Published NAV (1) Total U.S. large cap equity $ — $ — $ — $ 102,851 $ 102,851 U.S. small/mid cap equity — — — 16,423 16,423 Non-U.S. equity 21,211 — — 56,075 77,286 Emerging markets equity — — — 28,743 28,743 Fixed income — — — 2,781 2,781 Long government/credit — — — 33,081 33,081 High yield bonds — — — 2,777 2,777 Emerging market debt — — — 12,605 12,605 Real estate — — — 5,544 5,544 Absolute return strategy — — — 189 189 Cash and cash equivalents 82 — — 5,533 5,615 Total investments $ 21,293 $ — $ — $ 266,602 $ 287,895 December 31, 2016 Investments Level 1 Level 2 Level 3 Non-Published NAV (1) Total U.S. large cap equity $ 49,841 $ — $ — $ 5,655 $ 55,496 U.S. small/mid cap equity 18,629 — — 10,232 28,861 Non-U.S. equity 22,404 — — 25,346 47,750 Emerging markets equity — — — 13,457 13,457 Fixed income — — — 6,719 6,719 Long government/credit — 34,955 — 17,960 52,915 High yield bonds — — — 14,072 14,072 Emerging market debt — — — 8,504 8,504 Real estate 17,857 — — 882 18,739 Absolute return strategy — — — 3,111 3,111 Cash and cash equivalents $ 9 $ — $ — $ 2,482 $ 2,491 Total investments $ 108,740 $ 34,955 $ — $ 108,420 $ 252,115 December 31, 2017 2016 Receivables: Accrued interest and dividend income $ 30 $ 451 Due from broker for securities sold — 5,170 Total receivables $ 30 $ 5,621 Liabilities: Due to broker for securities purchased $ — $ 22 Total investment in retirement trust $ 287,925 $ 257,714 Asset Category Target Allocation U.S. large cap equity 29.3 % U.S. small/mid cap equity 6.9 Non-U.S. equity 28.0 Emerging markets equity 11.8 Long government/credit 17.5 High yield bonds 2.0 Emerging market debt 3.5 Real estate funds 1.0
Schedule of Net Benefit Costs [Table Text Block]	Pension Benefits Other Postretirement Benefits In thousands 2017 2016 2015 2017 2016 2015 Service cost $ 7,090 $ 7,083 $ 8,267 $ 341 $ 391 $ 527 Interest cost 18,111 18,399 18,360 1,141 1,175 1,179 Expected return on plan assets (20,433 ) (20,054 ) (20,676 ) — — — Amortization of prior service costs 127 231 231 (468 ) (468 ) 197 Amortization of net actuarial loss 15,748 14,624 18,609 696 705 554 Settlement expense — 193 — — — — Net periodic benefit cost 20,643 20,476 24,791 1,710 1,803 2,457 Amount allocated to construction (6,597 ) (5,746 ) (6,834 ) (587 ) (600 ) (808 ) Amount deferred to regulatory balancing account (1) (6,542 ) (6,252 ) (8,241 ) — — — Net amount charged to expense $ 7,504 $ 8,478 $ 9,716 $ 1,123 $ 1,203 $ 1,649
Sensitivity Analysis Of Retirement Benefit Costs and Benefit Obligations [Table Text Block]	Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Assumptions for net periodic benefit cost: Weighted-average discount rate 3.99 % 4.17 % 3.82 % 3.85 % 4.00 % 3.74 % Rate of increase in compensation 3.25-4.5% 3.25-4.5% 3.25-5.0% n/a n/a n/a Expected long-term rate of return 7.50 % 7.50 % 7.50 % n/a n/a n/a Assumptions for year-end funded status: Weighted-average discount rate 3.52 % 4.00 % 4.21 % 3.44 % 3.85 % 4.00 % Rate of increase in compensation 3.25-4.5% 3.25-4.5% 3.25-4.5% n/a n/a n/a Expected long-term rate of return 7.50 % 7.50 % 7.50 % n/a n/a n/a
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	In thousands 1% Increase 1% Decrease Effect on net periodic postretirement health care benefit cost $ 44 $ (39 ) Effect on the accumulated postretirement benefit obligation 478 (428 )
Defined Benefit Plan Estimated Future Employer Contributions Benefit Payments and Estimated Future Payments [Table Text Block]	In thousands Pension Benefits Other Benefits Employer Contributions: 2016 $ 16,742 $ 1,732 2017 21,483 1,737 2018 (estimated) 17,710 1,835 Benefit Payments: 2015 35,923 2,018 2016 20,959 1,732 2017 31,580 1,737 Estimated Future Benefit Payments: 2018 22,679 1,835 2019 23,546 1,871 2020 24,542 1,861 2021 25,471 1,904 2022 26,095 1,886 2023-2027 145,065 9,261

Income Tax (Tables)

Income Tax (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Dollars in thousands 2017 2016 2015 Income taxes (benefits) at federal statutory rate $ (30,233 ) $ 34,863 $ 31,310 Increase (decrease): State income tax, net of federal (5,784 ) 4,582 4,195 Amortization of investment tax credits (4 ) (41 ) (118 ) Differences required to be flowed-through by regulatory commissions 2,357 2,357 2,357 Gains on company and trust-owned life insurance (872 ) (594 ) (766 ) Effect of TCJA (21,429 ) — — Deferred Tax Rate Differential Post-TCJA 26,947 — — Other, net (1,739 ) (453 ) (1,225 ) Total provision for income taxes (benefits) $ (30,757 ) $ 40,714 $ 35,753 Effective tax rate 35.6 % 40.9 % 40.0 %
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	In thousands 2017 2016 2015 Current Federal $ 16,403 $ 7,402 $ 10,558 State 4,892 2,042 61 21,295 9,444 10,619 Deferred Federal (41,134 ) 26,219 18,729 State (10,918 ) 5,051 6,405 (52,052 ) 31,270 25,134 Total provision for income taxes (loss benefits) $ (30,757 ) $ 40,714 $ 35,753
Schedule Of Regulated Utility And Non Utility Business Segments [Table Text Block]	In thousands 2017 2016 2015 Utility: Current $ 21,453 $ 10,300 $ 15,890 Deferred 19,479 28,749 20,834 Deferred investment tax credits (4 ) (41 ) (118 ) 40,928 39,008 36,606 Non-utility business segments: Current (158 ) (856 ) (5,271 ) Deferred (71,527 ) 2,562 4,418 (71,685 ) 1,706 (853 ) Total provision for income taxes $ (30,757 ) $ 40,714 $ 35,753
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	In thousands 2017 2016 Deferred tax liabilities: Plant and property $ 296,114 $ 428,642 Regulatory income tax assets 22,209 43,048 Regulatory liabilities 29,114 48,291 Non-regulated deferred tax liabilities 933 51,446 Total $ 348,370 $ 571,427 Deferred tax assets: Regulatory income tax liabilities $ 56,470 $ — Non-regulated deferred tax assets 17,796 — Pension and postretirement obligations 3,512 4,493 Alternative minimum tax credit carryforward 66 9,853 Total $ 77,844 $ 14,346 Deferred income tax liabilities, net $ 270,526 $ 557,081 Deferred investment tax credits — 4 Deferred income taxes and investment tax credits $ 270,526 $ 557,085

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Public Utilities, Property, Plant and Equipment [Abstract]
Major Classifications Of Property, Plant And Equipment And Accumulated Depreciation [Text Block]	In thousands 2017 2016 Utility plant in service $ 2,975,217 $ 2,843,243 Utility construction work in progress 159,924 62,264 Less: Accumulated depreciation 942,879 903,096 Utility plant, net 2,192,262 2,002,411 Non-utility plant in service 75,639 299,378 Non-utility construction work in progress 4,671 3,931 Less: Accumulated depreciation 17,598 44,820 Non-utility plant, net 62,712 258,489 Total property, plant, and equipment $ 2,254,974 $ 2,260,900 Capital expenditures in accrued liabilities $ 34,976 $ 9,547

Gas Reserves (Tables)

Gas Reserves (Tables)	12 Months Ended
	Dec. 31, 2017
Gas Reserves [Abstract]
Gas Reserves Table [Text Block]	In thousands 2017 2016 Gas reserves, current $ 15,704 $ 15,926 Gas reserves, non-current 171,832 171,610 Less: Accumulated amortization 87,779 71,426 Total gas reserves (1) 99,757 116,110 Less: Deferred taxes on gas reserves 22,712 28,119 Net investment in gas reserves $ 77,045 $ 87,991

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Investments [Abstract]
Schedule Of Long Term Investments [Table Text Block]	In thousands 2017 2016 Investments in life insurance policies $ 50,792 $ 52,719 Investments in gas pipeline 13,669 13,767 Other 1,902 1,890 Total other investments $ 66,363 $ 68,376

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of Derivative Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	At December 31, In thousands 2017 2016 Natural gas (in therms): Financial 429,100 477,430 Physical 520,268 535,450 Foreign exchange $ 7,669 $ 7,497
Income Statement Presentation of Derivative Instruments [Text Block]	December 31, 2017 December 31, 2016 In thousands Natural gas commodity Foreign exchange Natural gas commodity Foreign exchange Benefit (expense) to cost of gas $ (26,000 ) $ 107 $ 22,746 $ (130 ) Operating revenues (1,021 ) — 995 — Amounts deferred to regulatory accounts on balance sheet 26,665 (107 ) (23,394 ) 130 Total gain (loss) in pre-tax earnings $ (356 ) $ — $ 347 $ —
Table Of Estimated Collateral Calls Table [Table Text Block]	Credit Rating Downgrade Scenarios In thousands (Current Ratings) A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Specul-ative With Adequate Assurance Calls $ — $ — $ — $ (5,428 ) $ (15,422 ) Without Adequate Assurance Calls — — — (5,428 ) (11,594 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule Of Future Minimum Lease Payments For Operating And Capital Leases [Table Text Block]	In thousands Operating leases Capital leases Minimum lease payments 2018 $ 5,378 $ 3 $ 5,381 2019 5,379 — 5,379 2020 6,945 — 6,945 2021 7,482 — 7,482 2022 7,629 — 7,629 Thereafter 169,411 — 169,411 Total $ 202,224 $ 3 $ 202,227
Long-term Purchase Commitment [Table Text Block]	In thousands Gas Pipeline Pipeline 2018 $ 63,944 $ 79,891 $ 3,581 2019 2,729 82,129 — 2020 2,729 77,028 — 2021 2,273 65,630 — 2022 — 60,050 — Thereafter — 601,844 — Total 71,675 966,572 3,581 Less: Amount representing interest 601 174,542 24 Total at present value $ 71,074 $ 792,030 $ 3,557

Environmental Matters (Tables)

Environmental Matters (Tables)	12 Months Ended
	Dec. 31, 2017
Environmental Remediation Obligations [Abstract]
Schedule of Environmental Loss Contingencies by Site [Table Text Block]	Current Liabilities Non-Current Liabilities In thousands 2017 2016 2017 2016 Portland Harbor site: Gasco/Siltronic Sediments $ 2,683 $ 869 $ 45,346 $ 43,972 Other Portland Harbor 1,949 1,970 4,163 4,148 Gasco/Siltronic Upland site 13,422 10,657 47,835 49,183 Central Service Center site 25 73 — — Front Street site 1,009 906 10,757 7,786 Oregon Steel Mills — — 179 179 Total $ 19,088 $ 14,475 $ 108,280 $ 105,268
Environmental Regulatory Table [Table Text Block]	In thousands 2017 2016 Deferred costs and interest (1) $ 45,546 $ 53,039 Accrued site liabilities (2) 126,950 119,443 Insurance proceeds and interest (94,170 ) (98,523 ) Total regulatory asset deferral (1) $ 78,326 $ 73,959 Current regulatory assets (3) 6,198 9,989 Long-term regulatory assets (3) 72,128 63,970

Quarterly Financial Informati40

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule Of Quarterly Financial Information [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	NORTHWEST NATURAL GAS COMPANY QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2017 Operating revenues $ 297,323 $ 136,238 $ 88,190 $ 240,422 Net income (loss) 40,310 2,729 (8,495 ) (90,167 ) Basic earnings (loss) per share (1) 1.41 0.10 (0.30 ) (3.14 ) Diluted earnings (loss) per share (1) 1.40 0.10 (0.30 ) (3.14 ) 2016 Operating revenues $ 255,529 $ 99,183 $ 87,727 $ 233,528 Net income (loss) 36,641 2,019 (8,040 ) 28,275 Basic earnings (loss) per share (1) 1.33 0.07 (0.29 ) 1.01 Diluted earnings (loss) per share (1) 1.33 0.07 (0.29 ) 1.00 (1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

Valuation Allowances and Rese41

Valuation Allowances and Reserves (Tables)	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Summary of Valuation Allowance [Table Text Block]	NORTHWEST NATURAL GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E Additions Deductions In thousands (year ended December 31) Balance at beginning of period Charged to costs and expenses Charged to other accounts Net write-offs Balance at end of period 2017 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 1,290 $ 865 $ — $ 1,199 $ 956 2016 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 870 $ 1,246 $ — $ 826 $ 1,290 2015 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ 969 $ 760 $ — $ 859 $ 870

Organization and Principles o42

Organization and Principles of Consolidation Organization and Principles of Consolidation (Details)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Operating Segments	2

Summary of Significant Accoun43

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Accounting Policies [Abstract]
Public Utilities Property Plant And Equipment, Disclosure Of Composite Depreciation Rate Number Of Components	3
Weighted Average Depreciation Rates Transmission Distribution	2.70%
Weighted Average Depreciation Rates Gas Storage	2.30%
Weighted Average Depreciation Rates General Plant	4.40%
Weighted Average Depreciation Rates Intangible Other	2.70%
Public Utilities, Allowance for Funds Used During Construction, Rate	5.50%	0.70%	0.40%
Accrued unbilled revenue	$ 62,381	$ 64,946
Revenue Taxes	19,069	17,100	$ 18,000
Inventory - Gas	36,700	42,700
Inventory, Raw Materials and Supplies, Net of Reserves	11,300	11,400
Regulatory Assets, Current	45,781	42,362
Impairment of Long-Lived Assets	$ 192,478	0	$ 0
Regulatory Asset, Amortization Period, Low End of Range	less than one year
Regulatory Assets, Noncurrent	$ 356,608	357,530
Decoupling [Domain]
Regulatory Assets, Current	11,227	13,067
Regulatory Assets, Noncurrent	3,970	5,860
Deferred Income Tax Charge [Member]
Regulatory Assets, Current	2,218	4,378
Regulatory Assets, Noncurrent	$ 19,991	$ 38,670
Minimum [Member]
PGA deferral rate	80.00%
Impact on earnings from gas cost sharing	10.00%
Maximum [Member]
PGA deferral rate	90.00%
Impact on earnings from gas cost sharing	20.00%
OREGON
PGA deferral rate	90.00%	90.00%	80.00%
WASHINGTON
PGA deferral rate	100.00%	100.00%	100.00%
Accounts Payable Location Member [Member]
Bank Overdrafts	$ 4,800	$ 2,900
Utility Plant [Member]
Accounting Policies [Abstract]
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.80%	2.80%	2.80%

Summary of Significant Accoun44

Summary of Significant Accounting Policies Regulatory Asset Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Liability, Current	$ 34,013	$ 40,290
Regulatory Assets, Current	45,781	42,362
Regulatory Assets, Noncurrent	$ 356,608	357,530
Regulatory Asset, Amortization Period	12 months
Regulatory Asset, Amortization Period, Low End of Range	less than one year
Regulatory Liability, Noncurrent	$ 586,093	349,319
Unrealized Loss On Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	18,712	1,315
Regulatory Assets, Noncurrent	4,649	913
Asset Recoverable Gas Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	154	6,830
Regulatory Assets, Noncurrent	84	89
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	6,198	9,989
Regulatory Assets, Noncurrent	72,128	63,970
Decoupling [Domain]
Regulatory Assets [Line Items]
Regulatory Assets, Current	11,227	13,067
Regulatory Assets, Noncurrent	3,970	5,860
Other Regulatory [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	7,272	6,783
Regulatory Assets, Noncurrent	15,579	14,130
Pension Balancing [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	60,383	50,863
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	2,218	4,378
Regulatory Assets, Noncurrent	19,991	38,670
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	179,824	183,035
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Liability, Noncurrent	213,306	0
Decoupling [Domain]
Regulatory Assets [Line Items]
Regulatory Liability, Current	322	0
Regulatory Liability, Noncurrent	$ 957	$ 0

Summary of Significant Accoun45

Summary of Significant Accounting Policies Regulatory Liability Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 34,013	$ 40,290
Regulatory Liability, Noncurrent	$ 586,093	349,319
Regulatory Liability, Amortization Period	12 months
Regulatory Liability, Amortization Period, Low End Of Range	less than one year
Gas Costs Payable [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 14,886	8,054
Regulatory Liability, Noncurrent	$ 4,630	1,021
Regulatory Liability, Amortization Period	12 months
Unrealized Gain On Derivatives [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 1,674	16,624
Regulatory Liability, Noncurrent	1,306	3,265
Decoupling [Domain]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	322	0
Regulatory Liability, Noncurrent	957	0
Other Regulatory [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	17,131	15,612
Regulatory Liability, Noncurrent	4,965	3,926
Asset Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Noncurrent	$ 360,929	$ 341,107

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (90,167)	$ (8,495)	$ 2,729	$ 40,310	$ 28,275	$ (8,040)	$ 2,019	$ 36,641	$ (55,623)	$ 58,895	$ 53,703
Average common shares outstanding - basic									28,669	27,647	27,347
Additional shares for stock-based compensation plans									0	132	70
Average common shares outstanding - diluted									28,669	27,779	27,417
Earnings (loss) per share of common stock - basic	$ (3.14)	$ (0.30)	$ 0.10	$ 1.41	$ 1.01	$ (0.29)	$ 0.07	$ 1.33	$ (1.94)	$ 2.13	$ 1.96
Earnings (loss) per share of common stock - diluted	$ (3.14)	$ (0.30)	$ 0.10	$ 1.40	$ 1	$ (0.29)	$ 0.07	$ 1.33	$ (1.94)	$ 2.12	$ 1.96
Antidilutive shares									97	5	12

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Impairment of Long-Lived Assets									$ 192,478	$ 0	$ 0
Operating revenues	$ 240,422	$ 88,190	$ 136,238	$ 297,323	$ 233,528	$ 87,727	$ 99,183	$ 255,529	762,173	675,967	723,791
Cost of gas									324,795	260,588	327,305
Environmental remediation									15,291	13,298	3,513
Depreciation and amortization									85,578	82,289	80,923
Income (loss) from operations									(53,227)	139,280	124,248
Net income (loss)	(90,167)	$ (8,495)	$ 2,729	$ 40,310	28,275	$ (8,040)	$ 2,019	$ 36,641	(55,623)	58,895	53,703
Capital expenditures									213,595	139,511	118,320
Assets	3,039,746				3,079,801				$ 3,039,746	3,079,801	3,069,410
Operating Segments [Member]
Segment Reporting Information [Line Items]
Number of Reportable Segments									2
Segment Reporting, Disclosure of Major Customers									0
Operating Segments [Member] | Utility Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues									$ 732,942	650,477	702,210
Cost of gas									325,019	260,588	327,305
Environmental remediation									15,291	13,298	3,513
Gross Profit									392,632	376,591	371,392
Depreciation and amortization									79,734	76,289	74,410
Income (loss) from operations									132,807	130,570	119,215
Net income (loss)									60,509	54,567	53,391
Capital expenditures									211,672	138,074	115,272
Assets	2,961,326				2,806,627				2,961,326	2,806,627	2,791,623
Operating Segments [Member] | Gas Storage Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues									23,620	25,266	21,356
Depreciation and amortization									5,844	6,000	6,513
Income (loss) from operations									(185,074)	9,136	5,032
Net income (loss)									(116,209)	4,303	174
Capital expenditures									1,923	1,437	3,048
Assets	59,583				256,333				59,583	256,333	261,750
Corporate, Non-Segment [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									5,611	224	225
Depreciation and amortization									0	0	0
Income (loss) from operations									(960)	(426)	1
Net income (loss)									77	25	138
Capital expenditures									0	0	0
Assets	$ 18,837				16,841				$ 18,837	16,841	$ 16,037
Mist Gas Storage Facility Member [Member] | Gas Storage Segment [Member]
Segment Reporting Information [Line Items]
Percent Of Pre Tax Income From Gas Storage Retained When The Costs Of The Capacity Are Not In Utility Rates	80.00%								80.00%
Percent Of Pre Tax Income From Gas Storage Retained When The Costs Of The Capacity Are In Utility Rates	33.00%								33.00%
Percent Of Pre Tax Income From Gas Storage Credited To Deferred Regulatory Account	20.00%								20.00%
Percent Of Pre Tax Income From Gas Storage Credited To Deferred Regulatory Account When In Rates	67.00%								67.00%
Gill Ranch Gas Storage Facility Member [Member]
Segment Reporting Information [Line Items]
Percent Ownership In Joint Project	75.00%								75.00%
NNG Financial [Member]
Segment Reporting Information [Line Items]
Percent Interest In Pipeline	10.00%								10.00%
Assets	$ 400				$ 500				$ 400	$ 500
Customer Total [Member] | Geographic Concentration Risk [Member] | OREGON | Utility Segment [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage									89.00%
Customer Total [Member] | Geographic Concentration Risk [Member] | WASHINGTON | Utility Segment [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage									11.00%
Gross Profit Margin [Member] | Residential and Commerical Customers [Member] | Utility Segment [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage									90.00%
Volumes Delivered [Member] | Residential and Commerical Customers [Member] | Utility Segment [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage									60.00%

Common Stock (Details)

Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 16, 2016	Nov. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Common Stock Shares Authorized			100,000,000	100,000,000	100,000,000
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reserved Shares Dividend Reinvestment and Direct Stock Purchase Plan			155,086		155,086
Total shares issued in offering	1,012,000	880,000
Offering price (in usd per share)	$ 54.63
Net proceeds from shares issued in offering	$ 52,800			$ 52,761
Stock Repurchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchase Program Expiration Date			May 31, 2018
Stock Repurchase Program, Authorized Amount			$ 100,000		$ 100,000
Stock Repurchase Program, Number of Shares Authorized to be Repurchased			2,800,000		2,800,000
Treasury Stock, Shares, Acquired			0		2,100,000
Treasury Stock Program					$ 83,300
Underwriters [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option period to purchase additional shares		30 days
Total shares issued in offering		132,000
Employee Stock Purchase Plan Member [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reserved Shares Employee Stock Purchase Plan			43,058		43,058
Restated Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding			91,688	180,163	91,688	352,688	416,088

Common Stock Summary of Changes

Common Stock Summary of Changes in Common Stock (Details) - shares	Nov. 16, 2016	Nov. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, beginning of period			28,630,000
Equity Issuance	1,012,000	880,000
Balance, end of period			28,630,000	28,630,000
Common Stock [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, beginning of period			28,630,000	27,427,000	27,284,000
Sales to shareholders under DRPP					46,000
Sales to employees under ESPP			18,000	18,000	19,000
Stock-based compensation			88,000	173,000	78,000
Equity Issuance				1,012,000
Balance, end of period			28,736,000	28,630,000	27,427,000

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($)	12 Months Ended			24 Months Ended	36 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ (930,000)	$ (924,000)	$ (1,012,000)
Allocated Share-based Compensation Expense, Net of Tax	1,424,000	1,446,000	1,661,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 528,000	$ 554,000	661,000
Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,100,000			1,100,000	1,100,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant, Any Award Type	626,960			626,960	626,960
Number of RSUs [Roll Forward]
Nonvested, beginning of period	0
Nonvested, end of period	0	0		0	0	0
Long Term Incentive Plan [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement by Share Based Payment Award Performance Period	3 years
Share Based Compensation Award Target Share	87,473			87,473	87,473
Unrecognized compensation expense	$ 2,800,000			$ 2,800,000	$ 2,800,000
Unrecognized Compensation Cost, Period for Recognition	through 2,019
Allocated Share-based Compensation Expense	$ 933,000
Weighted Average Price Per LTIP
Nonvested, beginning of period	$ 50.83
Granted	57.05
Vested	52.02
Nonvested, end of period	$ 56.40	$ 50.83		$ 56.40	$ 56.40	$ 50.83
Long Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	174,946			174,946	174,946
Long Term Incentive Plan [Member] | Performance Shares [Member] | A 2014 Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense						$ 1,685,000
Long Term Incentive Plan [Member] | Performance Shares [Member] | 2015-2017 Grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	29,967			29,967	29,967
Allocated Share-based Compensation Expense	$ (346,000)				$ 1,169,000
Long Term Incentive Plan [Member] | Performance Shares [Member] | 2015-2017 Grant | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	59,934			59,934	59,934
Long Term Incentive Plan [Member] | Performance Shares [Member] | A 2016 Award [Member] [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	24,826			24,826	24,826
Allocated Share-based Compensation Expense	$ 337,000			$ 815,000
Long Term Incentive Plan [Member] | Performance Shares [Member] | A 2016 Award [Member] [Domain] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	49,652			49,652	49,652
Long Term Incentive Plan [Member] | Performance Shares [Member] | A 2017 Award [Member] [Domain] [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	32,680			32,680	32,680
Allocated Share-based Compensation Expense	$ 942,000
Long Term Incentive Plan [Member] | Performance Shares [Member] | A 2017 Award [Member] [Domain] [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Award Target Share	65,360			65,360	65,360
Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$ 3,100,000			$ 3,100,000	$ 3,100,000
Unrecognized Compensation Cost, Period for Recognition	through 2,022
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Allocated Share-based Compensation Expense	$ 1,600,000	$ 1,500,000	$ 1,300,000
Number of RSUs [Roll Forward]
Nonvested, beginning of period	89,973	88,587	70,794	88,587	70,794
Granted	32,168	40,271	37,264
Vested	(35,341)	(29,488)	(19,003)
Forfeit	(2,278)	(9,397)	(468)
Nonvested, end of period	84,522	89,973	88,587	84,522	84,522	89,973
Weighted Average Price Per LTIP
Nonvested, beginning of period	$ 48.85	$ 44.78	$ 44	$ 44.78	$ 44
Granted	60.51	54.36	46.29
Vested	47.07	45.56	44.81
Forfeited	53.78	44.59	44.99
Nonvested, end of period	$ 53.90	$ 48.85	$ 44.78	$ 53.90	$ 53.90	$ 48.85
Restated Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	$ 3,900,000
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years 7 days
Share Based Compensation Arrangement By Share Based Payment Award Exchange Period	6 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	2 years 5 months 18 days
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 486,000
Option Shares
Exercised	(88,275)	(172,525)	(62,900)
Forfeited	(200)	0	(500)
Balance outstanding, end of period	91,688	180,163	352,688	91,688	91,688	180,163
Weighted-Average Price Per Share
Balance outstanding, beginning of period	$ 44.38	$ 44	$ 43.40	$ 44	$ 43.40
Exercised	44.33	43.61	39.96
Balance outstanding, end of period	$ 44.43	$ 44.38	$ 44	$ 44.43	$ 44.43	$ 44.38
Intrinsic Value balance, beginning of period	$ 2,800,000	$ 2,300,000	$ 2,700,000	$ 2,300,000	$ 2,700,000
Intrinsic value, Exercised	1,800,000	2,000,000	500,000
Intrinsic Value balance, end of period	$ 1,400,000	2,800,000	$ 2,300,000	$ 1,400,000	$ 1,400,000	$ 2,800,000
Weighted Average Price Per LTIP
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 41.15		$ 45.74
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percent Of Offering Date Price Employees Are Allowed To Purchase Stock	85.00%
Maximum Value Of Stock Employees Are Allowed To Purchase	$ 21,199
Operations and Maintenance Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 2,354,000	$ 2,370,000	$ 2,673,000

Debt (Details)

Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Abstract]
Short-term Debt	$ 54,200	$ 53,300
Bank Loans	$ 0	$ 0
Short-term Debt, Weighted Average Interest Rate	1.90%	0.78%
Commercial Paper, Maximum Maturity	11 days
Commercial Paper, Average Maturity	6 days
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 100,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Year Two	30,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	75,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	60,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	524,700
Debt Outstanding
Long-term Debt	779,887	$ 719,323
Long-term Debt, Current Maturities	96,703	39,989
Long-term debt, noncurrent	683,184	679,334
Repayments of Long-term Debt [Abstract]
Long-term Debt, Gross	786,700	726,700
Unamortized Debt Issuance Expense	(6,813)	(7,377)
Long-Term Debt, Current Maturities, Gross	97,000	40,000
Long-term Debt, Excluding Maturities, Gross	689,700	686,700
Liabilities, Fair Value Disclosure [Abstract]
Debt Instrument, Fair Value Disclosure	853,339	793,339
Note 7000 Series B Due 2017 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 0	$ 40,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	0.00%	7.00%
Repayments of Long-term Debt [Abstract]
Extinguishment of Debt, Amount	$ 40,000
Note 1545 Series Due 2018 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 75,000	$ 75,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	1.55%	1.55%
Note 6600 Series B Due 2018 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 22,000	$ 22,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	6.60%	6.60%
Note 8310 Series B Due 2019 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	8.31%	8.31%
Note 7630 Series B Due 2019 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 20,000	$ 20,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.63%	7.63%
Note 5370 Series B Due 2020 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 75,000	$ 75,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	5.37%	5.37%
Note 9050 Series A Due 2021 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	9.05%	9.05%
Note 3176 Series B Due 2021 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 50,000	$ 50,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	3.18%	3.18%
Note 3542 Series B Due 2023 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 50,000	$ 50,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	3.542%	3.542%
Note 5620 Series B Due 2023 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 40,000	$ 40,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	5.62%	5.62%
Note 7720 Series B Due 2025 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 20,000	$ 20,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.72%	7.72%
Note 6520 Series B Due 2025 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	6.52%	6.52%
Note 7050 Series B Due 2026 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 20,000	$ 20,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.05%	7.05%
Note 3211 Series B Due 2026 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 35,000	$ 35,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	3.21%	3.21%
Note 7000 Series Due 2027 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 20,000	$ 20,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.00%	7.00%
Note 2822 Series Due 2027 [Member] [Domain]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 25,000
Secured Debt	$ 25,000	$ 0
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	2.822%	0.00%
Note 6650 Series Due 2027 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 19,700	$ 19,700
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	6.65%	6.65%
Note 6650 Series Due 2028 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	6.65%	6.65%
Note 7740 Series Due 2030 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 20,000	$ 20,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.74%	7.74%
Note 7850 Series Due 2030 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	7.85%	7.85%
Note 5820 Series Due 2032 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 30,000	$ 30,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	5.82%	5.82%
Note 5660 Series Due 2032 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 40,000	$ 40,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	5.66%	5.66%
Note 5250 Series Due 2035 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 10,000	$ 10,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	5.25%	5.25%
Note 4136 Series Due 2046 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 40,000	$ 40,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	4.136%	4.14%
Note 4000 Series Due 2042 [Member]
Debt Instrument [Line Items]
Secured Debt	$ 50,000	$ 50,000
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	4.00%	4.00%
Note 3685 Series Due 2047 [Member] [Domain]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 75,000
Secured Debt	$ 75,000	$ 0
Debt Outstanding
Debt Instrument, Interest Rate, Stated Percentage	3.685%	0.00%
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 300,000
Line of Credit Facility Contingent Increase To Maximum Borrowing Capacity	450,000
Line of Credit Facility, Amount Outstanding	$ 0	$ 0
Debt Instrument Covenant Consolidated Indebtedness To Capitalization Ratio	70.00%
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 100,000
Letters of Credit Outstanding, Amount	$ 0	$ 0

Pension and Other Postretirem52

Pension and Other Postretirement Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 22, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss In Next Fiscal Year Regulatory	$ 17,300
Defined Benefit Plan Amortization Of Net Gains Losses Regulatory	17,700
Defined Benefit Plan Amortization Of Net Prior Service Cost Credit Regulatory	$ 400
Defined Benefit Plan, Health Care Cost Trend Rate For Pre-65 Population Assumed for Next Fiscal Year	7.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate, Decrease	4.75%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate				2,026
Defined Contribution Plan, Cost Recognized	$ 5,400	$ 4,600	$ 3,700
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Accumulated Other Comprehensive loss, beginning of period	(6,951)
Accumulated Other Comprehensive loss, end of period	(8,438)	(6,951)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Amortization of loss	800
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	44
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(39)
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	478
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(428)
Pension and Other Postretirement Benefit Contributions [Abstract]
Qualified Defined Benefit Pension Plan Contributions	$ 19,400
Fixed Income Pension Assets				$ 2,781
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Net Periodic Benefit Costs Overhead Charge Percentage	25.00%
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Net Periodic Benefit Costs Overhead Charge Percentage	35.00%
Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	29.30%
Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	6.90%
Foreign Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	28.00%
Emerging Market Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	11.80%
Government Or Credit Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	17.50%
High Yield Bond Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	2.00%
Emerging Market Debt [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	3.50%
Real Estate Funds [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Defined Benefit Plan Target Plan Asset Allocations	1.00%
Pension Costs [Member]
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Regulatory Assets Prior Service Cost				49	$ 176
Regulatory Assets Actuarial Loss				175,035	177,660
Regulatory Assets				175,084	177,836
Postretirement Benefit Costs [Member]
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Regulatory Assets Prior Service Cost				(2,206)	(2,675)
Regulatory Assets Actuarial Loss				6,964	7,874
Regulatory Assets				4,758	5,199
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				287,895	252,115
Defined Benefit Plan, Benefit Obligation	$ 457,839	445,628	445,628	486,289	457,839	$ 445,628
Defined Benefit Plan, Fair Value of Plan Assets	257,714	249,338	249,338	287,925	257,714	$ 249,338
Defined Benefit Plan, Funded Status of Plan				$ (198,364)	$ (200,125)
Reconciliation of change in benefit obligation
Obligation at beginning of period	457,839	445,628
Defined Benefit Plan, Service Cost	7,090	7,083	8,267
Defined Benefit Plan, Interest Cost	18,111	18,399	18,360
Defined Benefit Plan, Actuarial Loss	34,829	7,688
Defined Benefit Plan, Benefits Paid	31,580	20,959	35,923
Obligation and end of period	486,289	457,839	445,628
Reconciliation of change in plan assets
Fair value of plan assets, beginning of period	257,714	249,338
Defined Benefit Plan, Actual Return on Plan Assets	40,308	12,593
Defined Benefit Plan, Contributions by Employer	21,483	16,742
Defined Benefit Plan, Benefits Paid	31,580	20,959	35,923
Fair value of plan assets, end of period	287,925	257,714	249,338
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Regulatory assets defined benefit pension actuarial (gain) loss	12,177	14,005	419
Regulatory assets, Adjustment for Defined Benefit Plan Prior Service Cost	(127)	(230)	(230)
Regulatory asset, Adjustment for Defined Benefit Plan Amortization of Actuarial Loss	(14,802)	(13,238)	(16,372)
Regulatory Asset Adjustment Defined Benefit Plan	(2,752)	537	(16,183)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Service Cost	7,090	7,083	8,267
Defined Benefit Plan, Interest Cost	18,111	18,399	18,360
Defined Benefit Plan, Expected Return on Plan Assets	(20,433)	(20,054)	(20,676)
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	127	231	231
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	15,748	14,624	18,609
Defined Benefit Plan, Amortization of loss	0	193	0
Defined Benefit Plan Net Periodic Benefit Cost	20,643	20,476	24,791
Defined Benefit Plan Amount Allocated To Construction	(6,597)	(5,746)	(6,834)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	(6,542)	(6,252)	(8,241)
Defined Benefit Plan Net Amount Charged To Expense	$ 7,504	$ 8,478	$ 9,716
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.99%	4.17%	3.82%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.50%	7.50%	7.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.52%	4.00%	4.21%
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Expected Long Term Return On Assets				7.50%	7.50%	7.50%
Pension and Other Postretirement Benefit Contributions [Abstract]
Qualified Defined Benefit Pension Plan Contributions	$ 21,483	$ 16,742
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	17,710
Defined Benefit Plan, Benefits Paid	31,580	20,959	$ 35,923
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months				$ 22,679
Defined Benefit Plan, Expected Future Benefit Payments, Year Two				23,546
Defined Benefit Plan, Expected Future Benefit Payments, Year Three				24,542
Defined Benefit Plan, Expected Future Benefit Payments, Year Four				25,471
Defined Benefit Plan, Expected Future Benefit Payments, Year Five				26,095
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter				$ 145,065
Defined Benefit Plan, Settlements, Benefit Obligation	$ 0	$ 0	$ 0
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Rate Of Compensation Increase	3.25%	3.25%	3.25%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Rate Of Compensation Increase				3.25%	3.25%	3.25%
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Rate Of Compensation Increase	4.50%	4.50%	5.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan Assumptions Used Calculating Benefit Obligation Rate Of Compensation Increase				4.50%	4.50%	4.50%
Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				$ 102,851	$ 55,496
Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				16,423	28,861
Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				77,286	47,750
Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				28,743	13,457
Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables					6,719
Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				33,081	52,915
Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				2,777	14,072
Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				12,605	8,504
Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				5,544	18,739
Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				189
Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Pension Asset Investments Net Of Receivables And Payables				5,615	2,491
Other Postretirement Benefit Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 29,395	$ 31,049	$ 31,049	28,927	29,395	$ 31,049
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0	0	0	$ 0
Defined Benefit Plan, Funded Status of Plan				$ (28,927)	$ (29,395)
Reconciliation of change in benefit obligation
Obligation at beginning of period	29,395	31,049
Defined Benefit Plan, Service Cost	341	391	527
Defined Benefit Plan, Interest Cost	1,141	1,175	1,179
Defined Benefit Plan, Actuarial Loss	(213)	(1,488)
Defined Benefit Plan, Benefits Paid	1,737	1,732	2,018
Obligation and end of period	28,927	29,395	31,049
Reconciliation of change in plan assets
Fair value of plan assets, beginning of period	0	0
Defined Benefit Plan, Actual Return on Plan Assets	0	0
Defined Benefit Plan, Contributions by Employer	1,737	1,732
Defined Benefit Plan, Benefits Paid	1,737	1,732	2,018
Fair value of plan assets, end of period	0	0	0
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Regulatory assets defined benefit pension actuarial (gain) loss	(214)	(1,488)	2,724
Regulatory assets, Adjustment for Defined Benefit Plan Prior Service Cost	468	468	(197)
Regulatory asset, Adjustment for Defined Benefit Plan Amortization of Actuarial Loss	(696)	(705)	(554)
Regulatory Asset Adjustment Defined Benefit Plan	(442)	(1,725)	1,973
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Service Cost	341	391	527
Defined Benefit Plan, Interest Cost	1,141	1,175	1,179
Defined Benefit Plan, Expected Return on Plan Assets	0	0	0
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	(468)	(468)	197
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	696	705	554
Defined Benefit Plan, Amortization of loss	0	0	0
Defined Benefit Plan Net Periodic Benefit Cost	1,710	1,803	2,457
Defined Benefit Plan Amount Allocated To Construction	(587)	(600)	(808)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	0	0	0
Defined Benefit Plan Net Amount Charged To Expense	$ 1,123	$ 1,203	$ 1,649
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.85%	4.00%	3.74%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.44%	3.85%	4.00%
Pension and Other Postretirement Benefit Contributions [Abstract]
Qualified Defined Benefit Pension Plan Contributions	$ 1,737	$ 1,732
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	1,835
Defined Benefit Plan, Benefits Paid	1,737	1,732	$ 2,018
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months				$ 1,835
Defined Benefit Plan, Expected Future Benefit Payments, Year Two				1,871
Defined Benefit Plan, Expected Future Benefit Payments, Year Three				1,861
Defined Benefit Plan, Expected Future Benefit Payments, Year Four				1,904
Defined Benefit Plan, Expected Future Benefit Payments, Year Five				1,886
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter				9,261
Defined Benefit Plan, Settlements, Benefit Obligation	0	0	0
Qualified Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation	423,500	423,500		449,700	$ 423,500
Defined Benefit Plan, Fair Value of Plan Assets	257,700	257,700		287,900	257,700
Defined Benefit Plan, Funded Status of Plan				(161,700)
Reconciliation of change in benefit obligation
Obligation at beginning of period	423,500
Obligation and end of period	449,700	423,500
Reconciliation of change in plan assets
Fair value of plan assets, beginning of period	257,700
Fair value of plan assets, end of period	287,900	257,700
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				0	1
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				13,266	11,434
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				13,266	11,435
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	2,777	(1,196)	(2,549)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	(946)	1,386	(2,236)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	1,831	383	(4,785)
Pension and Other Postretirement Benefit Contributions [Abstract]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	15,500
Defined Benefit Plan, Settlements, Benefit Obligation	0	193	0
Non-Qualified Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation	34,300	34,300		36,600	$ 34,300
Defined Benefit Plan, Fair Value of Plan Assets	0			0
Reconciliation of change in benefit obligation
Obligation at beginning of period	34,300
Obligation and end of period	36,600	34,300
Reconciliation of change in plan assets
Fair value of plan assets, end of period	0
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Accumulated Other Comprehensive loss, beginning of period	(6,951)	(7,162)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	(2,794)	(1,196)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	946	1,386
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	0	193
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(1,848)	383
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax, Portion Attributable to Parent	361	(172)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(1,487)	211
Accumulated Other Comprehensive loss, end of period	(8,438)	(6,951)	(7,162)
Western States Office and Professional Employees Union Pension Fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Multiemployer Plans, Withdrawal Obligation				$ 7,100			$ 8,300
Multiemployer Plans, Plan Contributions	600
Multiemployer Plan, Period Contributions	$ 600	$ 600	$ 600
Western States Office and Professional Employees Union Pension Fund [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Multiemployer Plans, Collective-Bargaining Arrangement, Percentage of Contributions				4.00%
Western States Office and Professional Employees Union Pension Fund [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Multiemployer Plans, Collective-Bargaining Arrangement, Percentage of Contributions				5.00%

Pension and Other Postretirem53

Pension and Other Postretirement Benefits Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Information about Plan Assets [Abstract]
Fixed Income Pension Assets	$ 2,781
Pension Plan [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	287,895	$ 252,115
Plan Asset Receivable Or Payable Accrued Interest And Dividend Income	30	451
Plan Asset Receivable Or Payable Due From Broker Securities Sold	0	5,170
Total Pension Plan Asset Receivables	30	5,621
Plan Asset Receivable Or Payable Due From Broker Securities Purchased	0	22
Defined Benefit Plan, Fair Value of Plan Assets	287,925	257,714	$ 249,338
Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	102,851	55,496
Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	16,423	28,861
Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	77,286	47,750
Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	28,743	13,457
Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables		6,719
Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	33,081	52,915
Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	2,777	14,072
Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	12,605	8,504
Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	5,544	18,739
Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	189
Pension Plan [Member] | Real Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables		3,111
Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	5,615	2,491
Non-published Net Asset Value [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Fixed Income Pension Assets	2,781
Non-published Net Asset Value [Member] | Pension Plan [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	266,602	108,420
Non-published Net Asset Value [Member] | Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	102,851	5,655
Non-published Net Asset Value [Member] | Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16,423	10,232
Non-published Net Asset Value [Member] | Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	56,075	25,346
Non-published Net Asset Value [Member] | Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	28,743	13,457
Non-published Net Asset Value [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		6,719
Non-published Net Asset Value [Member] | Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	33,081	17,960
Non-published Net Asset Value [Member] | Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,777	14,072
Non-published Net Asset Value [Member] | Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	12,605	8,504
Non-published Net Asset Value [Member] | Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	5,544	882
Non-published Net Asset Value [Member] | Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	189
Non-published Net Asset Value [Member] | Pension Plan [Member] | Real Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		3,111
Non-published Net Asset Value [Member] | Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	5,533	2,482
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Fixed Income Pension Assets	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	21,293	108,740
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	49,841
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	18,629
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	21,211	22,404
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	17,857
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Real Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	82	9
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Fixed Income Pension Assets	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	0	34,955
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	34,955
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Real Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Fixed Income Pension Assets	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Total Pension Asset Investments Net Of Receivables And Payables	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Domestic Large Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Domestic Small/Mid Cap Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Foreign Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Government Or Credit Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | High Yield Bond Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Emerging Market Debt [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Real Estate Funds [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Absolute Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Real Return Strategy Investment Securities [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Inputs, Level 3 [Member] | Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

Income Tax (Details)

Income Tax (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2017	Dec. 21, 2017	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Deferred Tax Liabilities, Regulatory Assets	$ 22,209,000	$ 22,209,000		$ 43,048,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	66,000	66,000		9,853,000
Deferred Tax Assets, Regulatory Assets and Liabilities	56,470,000	56,470,000		0
Effect of TCJA		(21,429,000)		0	$ 0
Income Tax expense decrease after deferred depletion is realized					900,000
Deferred Tax Liabilities, Property, Plant and Equipment	296,114,000	296,114,000		428,642,000
Deferred Tax Liabilities, Regulatory Assets and Liabilities	29,114,000	29,114,000		48,291,000
Deferred Tax Liabilities Non Regulated Liabilities	933,000	933,000		51,446,000
Deferred Tax Liabilities, Net	348,370,000	348,370,000		571,427,000
Deferred Tax Assets Non Regulated Assets	17,796,000	17,796,000		0
Deferred Tax Assets, Tax Deferred Expense, Pension and Postretirement Obligations	3,512,000	3,512,000		4,493,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	66,000	66,000		9,853,000
Deferred Tax Assets, Net	77,844,000	77,844,000		14,346,000
Deferred Tax Assets, Net	270,526,000	270,526,000		557,081,000
Accumulated Deferred Investment Tax Credit	0	0		4,000
Deferred Tax Liabilities, Other	$ 270,526,000	270,526,000		557,085,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%		35.00%
Regulatory Liability, Noncurrent	$ 586,093,000	586,093,000		349,319,000
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate		(30,233,000)		34,863,000	31,310,000
Income Tax Reconciliation, State and Local Income Taxes, net of federal tax benefit		(5,784,000)		4,582,000	4,195,000
Income Tax Reconciliation, Tax Credits, Investment		(4,000)		(41,000)	(118,000)
Income Tax Reconciliation, Differences Regulatory Commission		2,357,000		2,357,000	2,357,000
Income Tax Reconciliation, Gains on company and trust-owned life insurance		(872,000)		(594,000)	(766,000)
Deferred Tax Rate Differential, Post TCJA		26,947,000		0	0
Income Tax Reconciliation, Other Adjustments		(1,739,000)		(453,000)	(1,225,000)
Income Tax Expense (Benefit)		$ (30,757,000)		$ 40,714,000	$ 35,753,000
Effective Income Tax Rate		35.60%		40.90%	40.00%
Tax Provision Current And Deferred [Abstract]
Current Federal Tax Expense (Benefit)		$ 16,403,000		$ 7,402,000	$ 10,558,000
Current State and Local Tax Expense (Benefit)		4,892,000		2,042,000	61,000
Current Income Tax Expense (Benefit)		21,295,000		9,444,000	10,619,000
Deferred Federal Income Tax Expense (Benefit)		(41,134,000)		26,219,000	18,729,000
Deferred State and Local Income Tax Expense (Benefit)		(10,918,000)		5,051,000	6,405,000
Deferred Income Tax Expense (Benefit)		(52,052,000)		31,270,000	25,134,000
Income Tax Expense (Benefit)		(30,757,000)		40,714,000	35,753,000
Tax Provision Regulated And Nonutility [Abstract]
Regulated Current Tax Expense Benefit		21,453,000		10,300,000	15,890,000
Regulated Deferred And Local Tax Expense Benefit		19,479,000		28,749,000	20,834,000
Regulated Investments And Credits Tax Expense Benefit		(4,000)		(41,000)	(118,000)
Total Tax Provision Related To Regulated Utility		40,928,000		39,008,000	36,606,000
Non Utility Current Tax Expense Benefit		(158,000)		(856,000)	(5,271,000)
Non Utility Deferred And Local Tax Expense Benefit		(71,527,000)		2,562,000	4,418,000
Total Tax Provision Related To Non Utility		(71,685,000)		1,706,000	(853,000)
Income Tax Expense (Benefit)		(30,757,000)		40,714,000	$ 35,753,000
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Deferred Tax Liabilities, Regulatory Assets	21,300,000	21,300,000
Deferred Tax Liabilities AFUDC [Member]
Regulatory Assets [Line Items]
Deferred Tax Liabilities, Regulatory Assets	0.9	0.9
TCJA Revaluation [Member]
Regulatory Assets [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities	18,200,000	18,200,000
Effect of TCJA		196,400,000
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Liability, Noncurrent	$ 213,306,000	$ 213,306,000		$ 0

Property, Plant and Equipment55

Property, Plant and Equipment (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	$ 3,215,451,000	$ 3,208,816,000
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	960,477,000	947,916,000
Total property, plant, and equipment, net	2,254,974,000	2,260,900,000
Property, Plant, Equipment non-cash	34,976,000	9,547,000
Regulatory Liability, Noncurrent	586,093,000	349,319,000
Acquired Equipment Capital Leases	0	0
Asset Removal Costs [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Regulatory Liability, Noncurrent	360,929,000	341,107,000
Utility Plant [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	2,975,217,000	2,843,243,000
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	159,924,000	62,264,000
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	942,879,000	903,096,000
Total property, plant, and equipment, net	$ 2,192,262,000	$ 2,002,411,000
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.80%	2.80%	2.80%
Non Utility Plant [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	$ 75,639,000	$ 299,378,000
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	4,671,000	3,931,000
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	17,598,000	44,820,000
Total property, plant, and equipment, net	$ 62,712,000	$ 258,489,000
Weighted Average Depreciation Rates Non Utility	1.90%	2.00%	2.20%

Gas Reserves (Details)

Gas Reserves (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gas Reserves [Abstract]
Total Cumulative Gas Reserves Investment	$ 188,000,000
Gas Reserves Investment	178,000,000
Cumulative Gross Investment	10,000,000
Additional Rate Per Therm	$ 0.4725
Gas Reserves Percent Gas Supplies YTD	6.00%	8.00%	11.00%
Gas Reserves, Current	$ 15,704,000	$ 15,926,000
Gas Reserves Noncurrent Gross	171,832,000	171,610,000
Gas Reserves Amortization	87,779,000	71,426,000
Total Gas Reserves	99,757,000	116,110,000
Deferred Taxes Related To Gas Reserves	22,712,000	28,119,000
Net Gas Reserves Investment	$ 77,045,000	$ 87,991,000

Investments (Details)

Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Investments [Abstract]
Ownership percentage of TWH	50.00%
Equity Method Investment, Underlying Equity in Net Assets	$ 13,400	$ 13,400
Equity Method Investment Exposure	13,400
Other Investments [Abstract]
Life Insurance, Corporate or Bank Owned, Amount	50,792	52,719
Equity Method Investments	13,669	13,767
Other Investments	1,902	1,890
Total Other investments	$ 66,363	$ 68,376

Derivative Instruments Gain (Lo

Derivative Instruments Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Nov. 01, 2015
Derivative [Line Items]
Target Hedge 2015-2016 Gas Year			75.00%
Unrealized Gain/Loss [Abstract]
Derivative, Loss on Derivative	$ 7,800,000	$ 26,900,000
Unrealized loss On Derivatives	22,300,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	2,900,000	18,800,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 23,300,000	700,000
Maturity Of Credit Risk Derivatives	Mar. 31, 2020
Derivative Fair Value Of Derivative Net	$ 20,300,000	$ (18,100,000)
Notional Disclosures [Abstract]
Financial Derivative, Nonmonetary Notional Amount	429,100,000	477,430,000
Derivative, Nonmonetary Notional Amount	520,268,000	535,450,000
Notional Amount of Foreign Currency Derivatives	$ 7,669,000	$ 7,497,000
Foreign Exchange Contract [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Foreign Exchange Contract [Member] | Cost of Sales [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	107,000	(130,000)
Foreign Exchange Contract [Member] | Sales [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Natural Gas Commodity [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(356,000)	347,000
Natural Gas Commodity [Member] | Cost of Sales [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(26,000,000)	(22,746,000)
Natural Gas Commodity [Member] | Sales [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(1,021,000)	995,000
Deferred Derivative Gain (Loss) [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(107,000)	130,000
Deferred Derivative Gain (Loss) [Member] | Natural Gas Commodity [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	$ 26,665,000	$ (23,394,000)

Derivative Instruments Credit R

Derivative Instruments Credit Rating Downgrade Scenarios (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Description Of Credit Risk Related Contingent Features [Line Items]
Maturity of Credit Risk Derivatives	Mar. 31, 2020
Moody's, A3 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	$ 0
Without Adequate Assurance Calls	0
Moody's, Baa1 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moody's, Baa2 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moody's, Baa3 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	(5,428)
Without Adequate Assurance Calls	(5,428)
Speculative [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	(15,422)
Without Adequate Assurance Calls	$ (11,594)

Commitments and Contingencies60

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating And Capital Leases Table [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 5,378,000
Operating Leases, Future Minimum Payments, Due in Two Years	5,379,000
Operating Leases, Future Minimum Payments, Due in Three Years	6,945,000
Operating Leases, Future Minimum Payments, Due in Four Years	7,482,000
Operating Leases, Future Minimum Payments, Due in Five Years	7,629,000
Operating Leases, Future Minimum Payments, Due Thereafter	169,411,000
Capital Leases, Future Minimum Payments Due, Current	3,000
Capital Leases, Future Minimum Payments Due in Two Years	0
Capital Leases, Future Minimum Payments Due in Three Years	0
Capital Leases, Future Minimum Payments Due in Four Years	0
Capital Leases, Future Minimum Payments Due in Five Years	0
Capital Leases, Future Minimum Payments Due Thereafter	0
Capital Leases, Future Minimum Payments Due	3,000
Future Minimum Payments Due Current	5,381,000
Future Minimum Payments Due In Two Years	5,379,000
Future Minimum Payments Due In Three Years	6,945,000
Future Minimum Payments Due In Four Years	7,482,000
Future Minimum Payments Due In Five Years	7,629,000
Future Minimum Payments Due Thereafter	169,411,000
Future Minimum Payments Due Total	202,227,000
Unrecorded Unconditional Purchase Obligations [Abstract]
Unrecorded Unconditional Purchase Obligation, Purchases	85,300,000	$ 85,000,000	$ 85,200,000
Unrecorded Unconditional Purchase Obligation Offsetting Sales	4,500,000	4,500,000	4,400,000
Unrecorded Unconditional Purchase Obligation [Line Items]
Operating Leases, Future Minimum Payments Due	$ 202,224,000
Leases [Abstract]
Land Buildings And Equipment Expiration Date	through 2,108
Operating Leases, Rent Expense, Minimum Rentals	$ 7,500,000	$ 6,200,000	$ 5,500,000
Gas Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	63,944,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	2,729,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	2,729,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	2,273,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	71,675,000
Unrecorded Unconditional Purchase Obligation Amount Representing Interest	601,000
Unrecorded Unconditional Purchase Obligation Total At Present Value	71,074,000
Pipeline Capacity Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	79,891,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	82,129,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	77,028,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	65,630,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	60,050,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	601,844,000
Unrecorded Unconditional Purchase Obligation	966,572,000
Unrecorded Unconditional Purchase Obligation Amount Representing Interest	174,542,000
Unrecorded Unconditional Purchase Obligation Total At Present Value	792,030,000
Pipeline Capacity Release Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	3,581,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Unrecorded Unconditional Purchase Obligation	3,581,000
Unrecorded Unconditional Purchase Obligation Amount Representing Interest	24,000
Unrecorded Unconditional Purchase Obligation Total At Present Value	$ 3,557,000
New Headquarters Lease 1st Renewal Period [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Lessee Leasing Arrangements, Operating Leases, Renewal Term	7 years
New Headquarters Lease 2nd Renewal Period [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Lessee Leasing Arrangements, Operating Leases, Renewal Term	7 years
New Headquarters Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	20 years
Lease Expected Commencement Year	1/1/2020
Operating Leases, Future Minimum Payments Due	$ 160,000,000
Current Headquarters Lease [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Lease Expiration Date	Jan. 1, 2020

Commitments and Contingencies O

Commitments and Contingencies Operating Lease Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Property, Plant and Equipment, Gross	$ 3,215,451	$ 3,208,816
Other Liabilities, Noncurrent	147,335	$ 142,411
New Headquarters Lease [Member] | Build to Suit Lease [Member]
Operating Leased Assets [Line Items]
Property, Plant and Equipment, Gross	500
Other Liabilities, Noncurrent	$ 500

Environmental Matters (Details)

Environmental Matters (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2016	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Environmental Activity [Line Items]
Undiscounted Environmental Remediation Expense		$ 10,500,000
Remediation Recovery Percentage			96.68%
EPA Record Of Decision, Clean-Up Costs, Portland Harbor			$ 1,050,000,000
Number Of Potentially Responsible Parties			more than 100
Loss Contingency Range Of Possible Loss Gasco Siltronic			$48.0 million to $350 million
Environmental Project Liability			$ 48,000,000
NRD Liability Claim Yakama Nation			0.3
Liability For Studies And Design Costs			1,300,000
Pre-tax Regulatory Disallowance			15,000,000
Deferred Environmental Charges			95,000,000
Disallowance From Order, Interest Portion	$ 2,800,000
Environmental Costs to be Amortized	13,800,000
Disallowance From Order, Operations and Maintenance Portion	500,000
Total Disallowance From Order	$ 3,300,000
Annual Tariff Rider Collection			5,000,000
Environmental Settlement Insurance Proceeds Received To Date			150,000,000
Annual insurance proceeds to appy against remediation costs			5,000,000
Insurance Proceeds Applied To Prudently Incurred Remediation Costs			68,200,000
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			19,088,000	$ 14,475,000
Environmental Noncurrent Liabilities			108,280,000	105,268,000
Regulatory Assets, Current			45,781,000	42,362,000
Regulatory Assets, Noncurrent			356,608,000	357,530,000
Annual Insurance Proceeds to Apply Against Remediation Costs			5,000,000
Total Annual Remediation Expense and Interest			10,000,000
Minimum [Member]
Environmental Activity [Line Items]
EPA Record Of Decision, Clean-Up Costs, Portland Harbor			(0.30)
Maximum [Member]
Environmental Activity [Line Items]
EPA Record Of Decision, Clean-Up Costs, Portland Harbor			0.50
Gasco Siltronic Sediments [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			2,683,000	869,000
Environmental Noncurrent Liabilities			45,346,000	43,972,000
Portland Harbor Other [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			1,949,000	1,970,000
Environmental Noncurrent Liabilities			4,163,000	4,148,000
Gasco Upland [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			13,422,000	10,657,000
Environmental Noncurrent Liabilities			47,835,000	49,183,000
Central Service Center [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			25,000	73,000
Environmental Noncurrent Liabilities			0	0
Front Street [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			1,009,000	906,000
Environmental Noncurrent Liabilities			10,757,000	7,786,000
Oregon Steel Mills [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Environmental Current Liabilities			0	0
Environmental Noncurrent Liabilities			179,000	179,000
Environmental Restoration Costs [Member]
Environmental Activity [Line Items]
Environmental Regulatory Deferred Cost and Interest			45,546,000	53,039,000
Environmental Regulatory Accrued Site Liabilities			126,950,000	119,443,000
Environmental Regulatory Insurance Proceeds and Interest			(94,170,000)	(98,523,000)
Environmental Regulatory Table [Abstract]
Environmental Regulatory Assets Noncurrent			78,326,000	73,959,000
Accrual for Environmental Loss Contingencies [Abstract]
Regulatory Assets, Current			6,198,000	9,989,000
Regulatory Assets, Noncurrent			$ 72,128,000	$ 63,970,000

Quarterly Financial Informati63

Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Quarterly Financial Information [Abstract]
Operating revenues	$ 240,422	$ 88,190	$ 136,238	$ 297,323	$ 233,528	$ 87,727	$ 99,183	$ 255,529	$ 762,173	$ 675,967	$ 723,791
Net income (loss)	$ (90,167)	$ (8,495)	$ 2,729	$ 40,310	$ 28,275	$ (8,040)	$ 2,019	$ 36,641	$ (55,623)	$ 58,895	$ 53,703
Earnings (loss) per share of common stock - basic	$ (3.14)	$ (0.30)	$ 0.10	$ 1.41	$ 1.01	$ (0.29)	$ 0.07	$ 1.33	$ (1.94)	$ 2.13	$ 1.96
Earnings (loss) per share of common stock - diluted	$ (3.14)	$ (0.30)	$ 0.10	$ 1.40	$ 1	$ (0.29)	$ 0.07	$ 1.33	$ (1.94)	$ 2.12	$ 1.96

Valuation Allowances and Rese64

Valuation Allowances and Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation and Qualifying Accounts [Abstract]
Allowance for Doubtful Accounts Receivable, beginning of period	$ 1,290	$ 870	$ 969
Valuation Allowances and Reserves, Charged to Cost and Expense	865	1,246	760
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	1,199	826	859
Allowance for Doubtful Accounts Receivable, end of period	$ 956	$ 1,290	$ 870