NORTHWEST NATURAL GAS CO - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - NORTHWEST NATURAL GAS CO	ex321q22018.htm
EX-31.2 - EXHIBIT 31.2 - NORTHWEST NATURAL GAS CO	ex312q22018.htm
EX-31.1 - EXHIBIT 31.1 - NORTHWEST NATURAL GAS CO	ex311q22018.htm
EX-12 - EXHIBIT 12 - NORTHWEST NATURAL GAS CO	ex12q22018.htm
EX-10 - EXHIBIT 10 - NORTHWEST NATURAL GAS CO	ex10-purchaseandsaleagreem.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to____________

Commission file number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)



Oregon	93-0256722
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

220 N.W. Second Avenue, Portland, Oregon 97209

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (503) 226-4211

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [ X ] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [ X ] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer [ X ] Accelerated Filer [ ]

Non-accelerated Filer [ ] Smaller Reporting Company [ ]

(Do not check if a Smaller Reporting Company) Emerging Growth Company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [ X ]

At July 27, 2018, 28,800,482 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended June 30, 2018

TABLE OF CONTENTS



PART 1.	FINANCIAL INFORMATION	Page

	Forward-Looking Statements	3

Item 1.	Unaudited Consolidated Financial Statements:
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017	5
	Consolidated Balance Sheets at June 30, 2018 and 2017 and December 31, 2017	6
	Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017	8
	Notes to Unaudited Consolidated Financial Statements	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	46

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	47

Item 1A.	Risk Factors	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 6.	Exhibits	47

	Signature	49

PART I. FINANCIAL INFORMATION

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, which are subject to the safe harbors created by such Act. Forward-looking statements can be identified by words such as anticipates, assumes, intends, plans, seeks, believes, estimates, expects, and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:


•	plans, projections and predictions;


•	objectives, goals or strategies;


•	assumptions, generalizations and estimates;


•	ongoing continuation of past practices or patterns;


•	future events or performance;


•	trends;


•	risks;


•	timing and cyclicality;


•	earnings and dividends;


•	capital expenditures and allocation;


•	capital or organizational structure, including restructuring as a holding company;


•	climate change and our role in a low-carbon future;


•	growth;


•	customer rates;


•	labor relations and workforce succession;


•	commodity costs;


•	gas reserves;


•	operational and financial performance and costs;


•	energy policy, infrastructure and preferences;


•	public policy approach and involvement;


•	efficacy of derivatives and hedges;


•	liquidity, financial positions, and planned securities issuances;


•	valuations;


•	project and program development, expansion, or investment;


•	business development efforts, including acquisitions and integration thereof;


•	asset dispositions and outcomes thereof;


•	pipeline capacity, demand, location, and reliability;


•	adequacy of property rights and headquarter development;


•	technology implementation and cybersecurity practices;


•	competition;


•	procurement and development of gas supplies;


•	estimated expenditures;


•	costs of compliance;


•	credit exposures;


•	rate or regulatory outcomes, recovery or refunds;


•	impacts or changes of laws, rules and regulations;


•	tax liabilities or refunds, including effects of tax reform;


•	levels and pricing of gas storage contracts and gas storage markets;


•	outcomes, timing and effects of potential claims, litigation, regulatory actions, and other administrative matters;


•	projected obligations, expectations and treatment with respect to retirement plans;


•	availability, adequacy, and shift in mix, of gas supplies;


•	effects of new or anticipated changes in critical accounting policies or estimates;


•	approval and adequacy of regulatory deferrals;


•	effects and efficacy of regulatory mechanisms; and


•	environmental, regulatory, litigation and insurance costs and recoveries, and timing thereof.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future operational or financial performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2017 Annual Report on Form 10-K, Part I, Item 1A “Risk Factors” and Part II, Item 7 and Item 7A, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk”, respectively of Part II of this report.

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Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

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ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
In thousands, except per share data	2018			2017			2018			2017

Operating revenues	$	124,567		$	134,476		$	388,202		$	430,200

Operating expenses:
Cost of gas	42,053			53,005			150,159			196,616
Operations and maintenance	38,028			34,997			77,551			72,443
Environmental remediation	1,882			2,611			6,506			9,565
General taxes	7,729			7,204			17,203			15,883
Revenue taxes	4,780			—			17,209			—
Depreciation and amortization	21,147			20,224			42,022			40,177
Other operating expenses	679			—			1,532			—
Total operating expenses	116,298			118,041			312,182			334,684
Income from operations	8,269			16,435			76,020			95,516
Other income (expense), net	7			(340		)	(827		)	(763		)
Interest expense, net	8,771			9,473			18,045			19,103
Income (loss) before income taxes	(495		)	6,622			57,148			75,650
Income tax (benefit) expense	(156		)	2,547			15,476			30,178
Net income (loss) from continuing operations	(339		)	4,075			41,672			45,472
Loss from discontinued operations, net of tax	(659		)	(1,346		)	(1,133		)	(2,433		)
Net income (loss)	(998		)	2,729			40,539			43,039
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $56 and $88 for the three months ended and $111 and $177 for the six months ended June 30, 2018 and 2017, respectively	153			137			307			273
Comprehensive income (loss)	$	(845	)	$	2,866		$	40,846		$	43,312
Average common shares outstanding:
Basic	28,791			28,648			28,772			28,641
Diluted	28,791			28,717			28,825			28,722
Earnings (loss) from continuing operations per share of common stock:
Basic	$	(0.01	)	$	0.14		$	1.45		$	1.58
Diluted	(0.01		)	0.14			1.45			1.58
Loss from discontinued operations per share of common stock:
Basic	$	(0.02	)	$	(0.04	)	$	(0.04	)	$	(0.08	)
Diluted	(0.02		)	(0.04		)	(0.04		)	(0.08		)
Earnings (loss) per share of common stock:
Basic	$	(0.03	)	$	0.10		$	1.41		$	1.50
Diluted	(0.03		)	0.10			1.41			1.50
Dividends declared per share of common stock	0.4725			0.4700			0.9450			0.9400

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30,			June 30,			December 31,
In thousands	2018			2017			2017

Assets:
Current assets:
Cash and cash equivalents	$	8,755		$	20,854		$	3,472
Accounts receivable	31,512			30,778			66,236
Accrued unbilled revenue	13,995			13,896			62,381
Allowance for uncollectible accounts	(657		)	(845		)	(956		)
Regulatory assets	41,092			37,504			45,781
Derivative instruments	2,044			1,530			1,735
Inventories	43,109			57,264			47,577
Gas reserves	16,579			16,072			15,704
Other current assets	11,672			13,028			24,949
Discontinued operations current assets (Note 15)	12,743			1,923			3,057
Total current assets	180,844			192,004			269,936
Non-current assets:
Property, plant, and equipment	3,298,856			3,098,112			3,204,635
Less: Accumulated depreciation	984,998			942,558			960,477
Total property, plant, and equipment, net	2,313,858			2,155,554			2,244,158
Gas reserves	75,362			92,020			84,053
Regulatory assets	339,177			348,284			356,608
Derivative instruments	1,077			162			1,306
Other investments	64,854			68,885			66,363
Other non-current assets	11,588			3,164			6,505
Discontinued operations non-current assets (Note 15)	—			205,081			10,817
Total non-current assets	2,805,916			2,873,150			2,769,810
Total assets	$	2,986,760		$	3,065,154		$	3,039,746

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30,			June 30,			December 31,
In thousands	2018			2017			2017

Liabilities and equity:
Current liabilities:
Short-term debt	$	47,100		$	—		$	54,200
Current maturities of long-term debt	74,785			61,991			96,703
Accounts payable	70,551			95,126			111,021
Taxes accrued	6,916			6,906			18,883
Interest accrued	6,652			5,966			6,773
Regulatory liabilities	34,275			28,041			34,013
Derivative instruments	11,744			4,734			18,722
Other current liabilities	32,935			31,015			39,942
Discontinued operations current liabilities (Note 15)	12,922			1,303			1,593
Total current liabilities	297,880			235,082			381,850
Long-term debt	683,895			658,118			683,184
Deferred credits and other non-current liabilities:
Deferred tax liabilities	281,028			577,176			270,526
Regulatory liabilities	602,294			359,205			586,093
Pension and other postretirement benefit liabilities	218,061			219,718			223,333
Derivative instruments	3,913			3,466			4,649
Other non-current liabilities	140,163			134,793			135,292
Discontinued operations - non-current liabilities (Note 15)	—			12,167			12,043
Total deferred credits and other non-current liabilities	1,245,459			1,306,525			1,231,936
Commitments and contingencies (Note 14)
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,800, 28,662, and 28,736 at June 30, 2018 and 2017, and December 31, 2017, respectively	452,195			444,058			448,865
Retained earnings	315,462			428,049			302,349
Accumulated other comprehensive loss	(8,131		)	(6,678		)	(8,438		)
Total equity	759,526			865,429			742,776
Total liabilities and equity	$	2,986,760		$	3,065,154		$	3,039,746

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
In thousands	2018			2017

Operating activities:
Net Income	$	40,539		$	43,039
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	42,022			40,177
Regulatory amortization of gas reserves	7,816			8,031
Deferred income taxes	11,227			22,170
Qualified defined benefit pension plan expense	2,876			2,615
Contributions to qualified defined benefit pension plans	(5,570		)	(7,250		)
Deferred environmental expenditures, net	(7,330		)	(6,817		)
Amortization of environmental remediation	6,506			9,565
Regulatory revenue deferral from the TCJA	9,212			—
Other	810			1,128
Changes in assets and liabilities:
Receivables, net	79,332			85,250
Inventories	4,803			(3,501		)
Income taxes	(11,967		)	(5,243		)
Accounts payable	(26,613		)	(21,849		)
Interest accrued	(121		)	—
Deferred gas costs	4,787			15,325
Other, net	3,623			8,243
Discontinued operations	700			3,348
Cash provided by operating activities	162,652			194,231
Investing activities:
Capital expenditures	(102,370		)	(94,333		)
Other	195			(404		)
Discontinued operations	(283		)	15
Cash used in investing activities	(102,458		)	(94,722		)
Financing activities:
Repurchases related to stock-based compensation	—			(2,034		)
Proceeds from stock options exercised	45			1,309
Long-term debt retired	(22,000		)	—
Change in short-term debt	(7,100		)	(53,300		)
Cash dividend payments on common stock	(25,577		)	(26,919		)
Other	(279		)	(1,232		)
Cash used in financing activities	(54,911		)	(82,176		)
Increase in cash and cash equivalents	5,283			17,333
Cash and cash equivalents, beginning of period	3,472			3,521
Cash and cash equivalents, end of period	$	8,755		$	20,854

Supplemental disclosure of cash flow information:
Interest paid, net of capitalization	$	17,117		$	18,011
Income taxes paid	13,347			9,081

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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. Our regulated local gas distribution business, referred to as the utility segment, is our core operating business and serves residential, commercial, and industrial customers in Oregon and southwest Washington. The other category primarily includes the non-utility portion of our Mist gas storage facility that provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon. In addition, we have investments and other non-utility activities reported 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), which is presented as a discontinued operation;


•	Northwest Energy Corporation (Energy Corp);


◦	NWN Gas Reserves LLC (NWN Gas Reserves);


•	NNG Financial Corporation (NNG Financial);


•	NW Natural Water Company, LLC (NWN Water);


◦	FWC Merger Sub, Inc.;


◦	Cascadia Water, LLC (Cascadia);


•	Northwest Natural Holding Company (NWN Holding); and


◦	NWN Merger Sub, Inc. (NWN Holdco Sub).

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 Energy's investment in Trail West Holdings, LLC (TWH), which is accounted for under the equity method, and NNG Financial's investment in Kelso-Beaver Pipeline. 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 the non-utility portion of our Mist gas storage facility and other non-utility investments and business activities.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for a fair statement of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2017 Annual Report on Form 10-K (2017 Form 10-K), taking into consideration the changes mentioned below in this Note 1 and in Notes 4 and 15. A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results.

During the second quarter of 2018, we moved forward with our long-term strategic plans, which include a shift away from our merchant gas storage business. In June 2018, NWN Gas Storage, our wholly-owned subsidiary, entered into a Purchase and Sale Agreement that provides for the sale of all of the membership interests in its wholly-owned subsidiary, Gill Ranch, subject to various regulatory approvals and closing conditions. We have concluded that the pending sale of Gill Ranch qualifies as assets and liabilities held for sale and discontinued operations. As such, for all periods presented, the results of Gill Ranch have been presented as a discontinued operation on the consolidated statements of comprehensive income and cash flows, and the assets and liabilities associated with Gill Ranch have been classified as discontinued operations assets and liabilities on the consolidated balance sheets. See Note 15 for additional information. Additionally, we reevaluated our reportable segments and concluded that the remaining gas storage activities no longer meet the requirements to be separately reported as a segment. The non-utility portion of our Mist gas storage facility is now reported as other, and all prior periods reflect this change. See Note 4, which provides segment information. These reclassifications had no effect on our prior year's consolidated results of operations, financial condition, or cash flows.

Our notes to the consolidated financial statements reflect the activity of our continuing operations for all periods presented, unless otherwise noted. Note 15 provides information regarding our discontinued operations.

2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are described in Note 2 of the 2017 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2018 other than those incorporated in Note 5 and Note 15 relating to revenue and discontinued operations, respectively. The following are current updates to certain critical accounting policy estimates and new accounting standards.

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Industry Regulation

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Oregon Public Utilities Commission (OPUC) or Washington Utilities and Transportation Commission (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.

Amounts deferred as regulatory assets and liabilities were as follows:



	Regulatory Assets
	June 30,				December 31,
In thousands	2018		2017		2017
Current:
Unrealized loss on derivatives⁽¹⁾	$	11,744	$	4,625	$	18,712
Gas costs	273		859		154
Environmental costs⁽²⁾	5,594		6,724		6,198
Decoupling⁽³⁾	10,232		12,136		11,227
Income taxes	2,217		4,378		2,218
Other⁽⁴⁾	11,032		8,782		7,272
Total current	$	41,092	$	37,504	$	45,781
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	3,913	$	3,466	$	4,649
Pension balancing⁽⁵⁾	67,527		55,358		60,383
Income taxes	19,267		36,591		19,991
Pension and other postretirement benefit liabilities	171,186		176,136		179,824
Environmental costs⁽²⁾	65,156		64,008		72,128
Gas costs	28		87		84
Decoupling⁽³⁾	1,636		1,993		3,970
Other⁽⁴⁾	10,464		10,645		15,579
Total non-current	$	339,177	$	348,284	$	356,608



	Regulatory Liabilities
	June 30,				December 31,
In thousands	2018		2017		2017
Current:
Gas costs	$	20,906	$	15,708	$	14,886
Unrealized gain on derivatives⁽¹⁾	1,938		1,459		1,674
Decoupling⁽³⁾	2,153		134		322
Other⁽⁴⁾	9,278		10,740		17,131
Total current	$	34,275	$	28,041	$	34,013
Non-current:
Gas costs	$	3,460	$	2,719	$	4,630
Unrealized gain on derivatives⁽¹⁾	1,077		162		1,306
Decoupling⁽³⁾	410		—		957
Income taxes⁽⁶⁾	222,734		—		213,306
Accrued asset removal costs⁽⁷⁾	370,245		350,828		360,929
Other⁽⁴⁾	4,368		5,496		4,965
Total non-current	$	602,294	$	359,205	$	586,093


⁽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 14 for a description of environmental costs.


⁽³⁾	This deferral represents the margin adjustment resulting from differences between actual and expected volumes.


⁽⁴⁾	Balances consist of deferrals and amortizations under approved regulatory mechanisms and typically earn a rate of return or carrying charge.


⁽⁵⁾	Refer to footnote (1) of the Net Periodic Benefit Cost table in Note 8 for information regarding the deferral of pension expenses.


⁽⁶⁾	This balance represents estimated amounts associated with the Tax Cuts and Jobs Act. See Note 9.


⁽⁷⁾	Estimated costs of removal on certain regulated properties are collected through rates.

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We believe all costs incurred and deferred at June 30, 2018 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, then we would be required to write-off the net unrecoverable balances in the period such determination is made.

New Accounting Standards

We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial Accounting Standards Board (FASB). ASUs 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 Adopted Accounting Pronouncements

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 Topic 718, related to a change to the terms or conditions of a share-based payment award. 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 were effective for us beginning January 1, 2018, and will be applied prospectively to any award modified on or after the adoption date. The adoption did not have a material impact to our financial statements or 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. Additionally, the other components of net periodic benefit costs are to be presented 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 were effective for us beginning January 1, 2018.

Upon adoption, the ASU required that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. As such, the interest cost, expected return on assets, amortization of prior service costs, and other costs have been reclassified from operations and maintenance expense to other income (expense), net on our consolidated statement of comprehensive income for the three and six months ended June 30, 2017. We did not elect the practical expedient which would have allowed us to reclassify amounts disclosed previously in the pension and other postretirement benefits footnote disclosure as the basis for applying retrospective presentation. As mentioned above, on a prospective basis, the other components of net periodic benefit cost will not be eligible for capitalization, however, they will continue to be included in our pension regulatory balancing mechanism.

The retrospective presentation requirement related to the other components of net periodic benefit cost affected the operations and maintenance expense and other income (expense), net lines on our consolidated statement of comprehensive income. For the three months and six months ended June 30, 2017, $1.3 million and $2.6 million of expense was reclassified from operations and maintenance expense and included in other income (expense), net, respectively.

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. The amendments in this standard were effective for us beginning January 1, 2018, and the adoption did not have a material impact to our financial statements or disclosures as our historical practices and presentation were consistent with the directives of this ASU.

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 was effective for us beginning January 1, 2018, and the adoption did not have a material impact to our financial statements or disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." 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 accounting standard and all related amendments were effective for us beginning January 1, 2018. We applied the accounting standard to all contracts using the modified retrospective method. The new standard is primarily reflected in our consolidated statement of comprehensive income and Note 5. The implementation of the new revenue standard did not result in

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changes to how we currently recognize revenue, and therefore, we did not have a cumulative effect or adjustment to the opening balance of retained earnings. The implementation did result in changes to our disclosures and presentation of revenue and expenses. The comparative information for prior years has not been restated. There is no material impact to our financial results and no significant changes to our control environment due to the adoption of the new revenue standard on an ongoing basis.

As previously discussed, the adoption of the new revenue standard did not impact our consolidated balance sheet or statement of cash flows but did result in changes to the presentation of our consolidated statements of comprehensive income. Had the adoption of the new revenue standard not occurred, our operating revenues for the three and six months ended June 30, 2018 would have been $119.8 million and $371.0 million, compared to the reported amounts of $124.6 million and $388.2 million under the new revenue standard, respectively. Similarly, absent the impact of the new revenue standard, our operating expenses would have been $111.5 million and $295.0 million, compared to the reported amounts of $116.3 million and $312.2 million under the new revenue standard for the three and six months ended June 30, 2018, respectively. The effect of the change was an increase in both operating revenues and operating expenses of $4.8 million and $17.2 million for the three and six months ended June 30, 2018, respectively, due to the change in presentation of revenue taxes. As part of the adoption of the new revenue standard, we evaluated the presentation of revenue taxes under the new guidance and across our peer group and concluded that the gross presentation of revenue taxes provides the greatest level of consistency and transparency. Prior to the adoption of the new revenue standard, a portion of revenue taxes was presented net in operating revenues and a portion was recorded directly on the balance sheet. During the three and six months ended June 30, 2018, we recognized $4.8 million and $17.2 million in revenue taxes in operating revenues and operating expenses, respectively. In comparison, for the three and six months ended June 30, 2017, we recognized $5.6 million and $19.3 million in revenue taxes, of which $3.2 million and $11.0 million were recorded in operating revenues and $2.4 million and $8.3 million were recorded on the balance sheet, respectively. The change in presentation of revenue taxes had no impact on utility margin, net income or earnings per share.

Recently Issued Accounting Pronouncements

ACCUMULATED OTHER COMPREHENSIVE INCOME. On February 14, 2018, the FASB issued ASU 2018-02, "Income Statement—Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income." This update was issued in response to concerns from certain stakeholders regarding the current requirements under U.S. GAAP that deferred tax assets and liabilities are adjusted for a change in tax laws or rates, and the effect is to be included in income from continuing operations in the period of the enactment date. This requirement is also applicable to items in accumulated other comprehensive income where the related tax effects were originally recognized in other comprehensive income. The adjustment of deferred taxes due to the new corporate income tax rate enacted through the Tax Cuts and Jobs Act (TCJA) on December 22, 2017 recognized in income from continuing operations causes the tax effects of items within accumulated other comprehensive income (referred to as stranded tax effects) to not reflect the appropriate tax rate. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and require certain disclosures about stranded tax effects. The amendments in this update are effective for us beginning January 1, 2019, and should be applied either in the period of adoption or retrospectively to each period in which the effect of the change in the federal corporate income tax rate in the TCJA is recognized. The reclassification allowed in this update is elective, and we are currently assessing whether we will make the reclassification. This update is not expected to have a material impact on our financial condition.

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.

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. 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. Additionally, 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. The standard and associated ASUs are effective for us beginning January 1, 2019. 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 of the 2017 Form 10-K for our current lease commitments.

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3. EARNINGS PER SHARE

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except using 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 per common share.

Diluted earnings (loss) from continuing operations per share are calculated as follows:



	Three Months Ended June 30,					Six Months Ended June 30,
In thousands, except per share data	2018			2017		2018		2017
Net income (loss) from continuing operations	$	(339	)	$	4,075	$	41,672	$	45,472
Average common shares outstanding - basic	28,791			28,648		28,772		28,641
Additional shares for stock-based compensation plans (See Note 6)	—			69		53		81
Average common shares outstanding - diluted	28,791			28,717		28,825		28,722
Earnings (loss) from continuing operations per share of common stock - basic	$	(0.01	)	$	0.14	$	1.45	$	1.58
Earnings (loss) from continuing operations per share of common stock - diluted	$	(0.01	)	$	0.14	$	1.45	$	1.58
Additional information:
Antidilutive shares	53			32		10		21

4. SEGMENT INFORMATION

We primarily operate in one reportable business segment, which is our local gas distribution business and which is referred to as the utility segment. During the second quarter of 2018, we moved forward with our long-term strategic plans, which include a shift away from our merchant gas storage business, by entering into a Purchase and Sale Agreement that provides for the sale of all of the membership interests in Gill Ranch, subject to various regulatory approvals and closing conditions. As such, we reevaluated our reportable segments and concluded that the gas storage activities no longer meet the requirements of a reportable segment. Our ongoing, non-utility gas storage activities, which include our interstate storage and optimization activities at our Mist gas storage facility, are now reported as other. We also have other investments and business activities not specifically related to our utility segment, which are aggregated and reported as other. We refer to our local gas distribution business as the utility and all other activities as non-utility.

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. As of December 31, 2017, 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.

In addition to our local gas distribution business, our utility segment also includes the utility portion of our Mist underground storage facility, our North Mist gas storage expansion in Oregon, and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp.

Other

We have non-utility investments and other business activities, which are aggregated and reported as other. Other includes NWN Gas Storage, a wholly-owned subsidiary of NWN Energy, and the non-utility portion of our Mist facility in Oregon and third-party

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asset management services. Earnings from non-utility assets at our Mist facility are primarily related to firm storage capacity revenues. Earnings from 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. Under the Oregon sharing mechanism, 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.

Other also 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 subsidiaries FWC Merger Sub, Inc. and Cascadia, NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project and NWN Holding, which is pursuing the holding company reorganization of NW Natural through its wholly-owned subsidiary NWN Holdco Sub.

All prior period amounts have been retrospectively adjusted to reflect the change in our reportable segments and the designation of Gill Ranch as a discontinued operation.

Inter-segment transactions were immaterial for the periods presented. The following table presents summary financial information concerning the reportable segments of our continuing operations. See Note 15 for information regarding our discontinued operation, Gill Ranch Storage.



	Three Months Ended June 30,
In thousands	Utility			Other		Total
2018
Operating revenues	$	118,515		$	6,052	$	124,567
Depreciation and amortization	20,766			381		21,147
Income from operations	4,545			3,724		8,269
Net income (loss) from continuing operations	(2,970		)	2,631		(339		)
Capital expenditures	43,801			1,239		45,040
2017
Operating revenues	$	130,095		$	4,381	$	134,476
Depreciation and amortization	19,894			330		20,224
Income from operations	13,158			3,277		16,435
Net income from continuing operations	2,137			1,938		4,075
Capital expenditures	54,265			1,142		55,407



	Six Months Ended June 30,
In thousands	Utility		Other		Total
2018
Operating revenues	$	376,448	$	11,754	$	388,202
Depreciation and amortization	41,309		713		42,022
Income from operations	69,301		6,719		76,020
Net income from continuing operations	36,913		4,759		41,672
Capital expenditures	100,695		1,675		102,370
Total assets at June 30, 2018⁽¹⁾	2,907,724		66,293		2,974,017
2017
Operating revenues	$	422,821	$	7,379	$	430,200
Depreciation and amortization	39,518		659		40,177
Income from operations	90,285		5,231		95,516
Net income from continuing operations	42,329		3,143		45,472
Capital expenditures	93,119		1,214		94,333
Total assets at June 30, 2017⁽¹⁾	2,792,011		66,139		2,858,150
Total assets at December 31, 2017⁽¹⁾	2,961,326		64,546		3,025,872


⁽¹⁾	Total assets exclude assets related to discontinued operations of $12.7 million, $207.0 million, and $13.9 million as of June 30, 2018, June 30, 2017, and December 31, 2017, respectively.

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Utility Margin

Utility margin is a financial measure used by our chief operating decision maker (CODM) consisting of utility operating revenues, reduced by the associated cost of gas, environmental recovery revenues, and revenue taxes. 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. Revenue taxes are collected from our utility customers and remitted to our taxing authorities. The collections from customers are offset by the expense recognition of the obligation to the taxing authority. By subtracting cost of gas, environmental remediation expense, and revenue taxes from utility operating revenues, utility margin provides a key metric used by our CODM in assessing the performance of the utility segment.

The following table presents additional segment information concerning utility margin:



	Three Months Ended June 30,				Six Months Ended June 30,
In thousands	2018		2017		2018		2017
Utility margin calculation:
Utility operating revenues	$	118,515	$	130,095	$	376,448	$	422,821
Less: Utility cost of gas	42,107		53,005		150,271		196,616
Environmental remediation expense	1,882		2,611		6,506		9,565
Revenue taxes⁽¹⁾	4,780		—		17,209		—
Utility margin	$	69,746	$	74,479	$	202,462	$	216,640


⁽¹⁾	The change in presentation of revenue taxes was a result of the adoption of ASU 2014-09 "Revenue From Contracts with Customers" and all related amendments on January 1, 2018. This change had no impact on utility margin results as revenue taxes were previously presented net in utility operating revenue. For additional information, see Note 2.

5. REVENUE

The following table presents our disaggregated revenue from continuing operations:



	Three months ended June 30, 2018
In thousands	Utility		Other		Total
Local gas distribution revenue	$	114,725	$	—	$	114,725
Gas storage revenue, net	—		2,736		2,736
Asset management revenue, net	—		2,140		2,140
Appliance retail center revenue	—		1,176		1,176
Revenue from contracts with customers	114,725		6,052		120,777

Alternative revenue	3,663		—		3,663
Leasing revenue	127		—		127
Total operating revenues	$	118,515	$	6,052	$	124,567



	Six months ended June 30, 2018
In thousands	Utility		Other		Total
Local gas distribution revenue	$	372,954	$	—	$	372,954
Gas storage revenue, net	—		5,314		5,314
Asset management revenue, net	—		3,719		3,719
Appliance retail center revenue	—		2,721		2,721
Revenue from contracts with customers	372,954		11,754		384,708

Alternative revenue	3,291		—		3,291
Leasing revenue	203		—		203
Total operating revenues	$	376,448	$	11,754	$	388,202

Revenue is recognized when our obligation to our customer is satisfied and in the amount we expect to receive in exchange for transferring goods or providing services. Our revenue from contracts with customers contain one performance obligation that is generally satisfied over time, using the output method based on time elapsed, due to the continuous nature of the service provided. The transaction price is determined per a set price agreed upon in the contract or dependent on regulatory tariffs.

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Customer accounts are settled on a monthly basis or paid at time of sale and based on historical experience. It is probable that we will collect substantially all of the consideration to which we are entitled to receive.

We do not have any material contract assets as our net accounts receivable and accrued unbilled revenue balances are unconditional and only involve the passage of time until such balances are billed and collected. We do not have any material contract liabilities.

Revenue-based taxes are primarily franchise taxes, which are collected from utility customers and remitted to taxing authorities. Beginning January 1, 2018, revenue taxes are included in operating revenues with an equal and offsetting expense recognized in operating expenses in the consolidated statement of comprehensive income.

Utility Segment

Local gas distribution revenue. Our primary source of revenue is providing natural gas to the customers in our service territory, which include residential, commercial, industrial and transportation customers. Gas distribution revenue is generally recognized over time upon delivery of the gas commodity or service to the customer, and the amount of consideration we receive and recognize as revenue is dependent on the Oregon and Washington tariffs. Customer accounts are to be paid in full each month, and there is no right of return or warranty for services provided. Revenues include firm and interruptible sales and transportation services, franchise taxes recovered from the customer, late payment fees, service fees, and accruals for gas delivered but not yet billed (accrued unbilled revenue). Our accrued unbilled revenue balance is based on estimates of deliveries during the period from the last meter reading and management judgment is required for a number of factors used in this calculation, including customer use and weather factors.

We applied the significant financing practical expedient and we have not adjusted the consideration we expect to receive from our utility customers for the effects of a significant financing component as all payment arrangements are settled annually. Due to the election of the right to invoice practical expedient, we do not disclose the value of unsatisfied performance obligations as of June 30, 2018.

Alternative revenue. Our weather normalization mechanism (WARM) and decoupling mechanism are considered to be alternative revenue programs. Alternative revenue programs are considered to be contracts between us and our regulator and are excluded from revenue from contracts with customers.

Leasing revenue. Leasing revenue primarily consists of rental revenue for small leases of our utility-owned property to third parties. The transactions are accounted for as operating leases and the revenue is recognized on a straight-line basis over the term of the lease agreement. Lease revenue is excluded from revenue from contracts with customers.

Other

Gas storage revenue. Our gas storage activity includes the non-utility portion of our Mist facility, which is used to store natural gas for customers. Gas storage revenue is generally recognized over time as the gas storage service is provided to the customer and the amount of consideration we receive and recognize as revenue is dependent on set rates defined per the storage agreements. Noncash consideration in the form of dekatherms of natural gas is received as consideration for providing gas injection services to our gas storage customers. This noncash consideration is measured at fair value using the average spot rate. Customer accounts are generally paid in full each month, and there is no right of return or warranty for services provided. Revenues include firm and interruptible storage services, net of the profit sharing amount refunded to our utility customers.

Asset management revenue. Asset management revenue is generally recognized over time using a straight-line approach over the term of each contract, and the amount of consideration we receive and recognize as revenue is dependent on a variable pricing model. Variable revenues earned above guaranteed amounts are estimated and recognized at the end of each period using the most likely amount approach. Revenues include the optimization of the storage assets and pipeline capacity provided, net of the profit sharing amount refunded to our utility customers. Asset management accounts are settled on a monthly basis.

As of June 30, 2018, unrecognized revenue for the fixed component of the transaction price related to our gas storage and asset management revenue was approximately $43.4 million. Of this amount, approximately $8.1 million will be recognized during the remainder of 2018, $10.2 million in 2019, $8.5 million in 2020, $7.5 million in 2021, $4.3 million in 2022 and $4.8 million thereafter.

Appliance retail center revenue. We own and operate an appliance store that is open to the public, where customers can purchase natural gas home appliances. Revenue from the sale of appliances is recognized at the point in time in which the appliance is transferred to the third party responsible for delivery and installation services and when the customer has legal title to the appliance. It is required that the sale be paid for in full prior to transfer of legal title. The amount of consideration we receive and recognize as revenue varies with changes in marketing incentives and discounts that we offer to our customers.

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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 Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the 2017 Form 10-K and the updates provided below.

Long Term Incentive Plan

Performance Shares

LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the six months ended June 30, 2018, no performance-based shares were granted under the LTIP for accounting purposes. In February 2018, the 2018 LTIP was awarded to participants; however, the agreement allows for one of the performance factors to remain variable until the first quarter of the third year of the award period. As the performance factor will not be approved until the first quarter of 2020, there is not a mutual understanding of the award’s key terms and conditions between the Company and the participants as of June 30, 2018 and therefore no expense was recognized for the 2018 award. We will calculate the grant date fair value and recognize expense once the final performance factor has been approved.

For the 2018 LTIP, award share payouts range from a threshold of 0% to a maximum of 200% based on achievement of pre-established goals. The performance criteria for the 2018 performance shares consists of a three-year Return on Invested Capital (ROIC) threshold that must be satisfied and a cumulative EPS factor, which can be modified by a total shareholder return factor (TSR modifier) relative to the performance of the Russell 2500 Utilities Index over the three-year performance period. If the target was achieved for the 2018 award, we would grant 34,702 shares in the first quarter of 2020.

As of June 30, 2018, there was $2.1 million of unrecognized compensation cost associated with the 2016 and 2017 LTIP grants, which is expected to be recognized through 2019.

Restricted Stock Units

During the six months ended June 30, 2018, 26,087 RSUs were granted under the LTIP with a weighted-average grant date fair value of $55.16 per share. 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. Generally, an RSU obligates us, upon vesting, to issue the RSU holder 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 our common stock on the grant date. As of June 30, 2018, there was $3.3 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2022.

7. DEBT

Short-Term Debt

At June 30, 2018, we had short-term debt of $47.1 million, which was comprised entirely of commercial paper. The carrying cost of our commercial paper approximates fair value using Level 2 inputs. See Note 2 in the 2017 Form 10-K for a description of the fair value hierarchy. At June 30, 2018, our commercial paper had a maximum remaining maturity of 12 days and average remaining maturity of 7 days.

Long-Term Debt

At June 30, 2018, we had long-term debt of $758.7 million, which included $6.0 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2018 through 2047, interest rates ranging from 1.545% to 9.05%, and a weighted average coupon rate of 4.728%. In March 2018, we retired $22.0 million of FMBs with a coupon rate of 6.60%.

Fair Value of Long-Term Debt

Our outstanding debt does not trade in active markets. We estimate the fair value of our long-term debt using utility companies with similar credit ratings, terms, and remaining maturities to our long-term 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 in the 2017 Form 10-K for a description of the fair value hierarchy.

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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:



	June 30,						December 31,
In thousands	2018			2017			2017
Gross long-term debt	$	764,700		$	726,700		$	786,700
Unamortized debt issuance costs	(6,020		)	(6,591		)	(6,813		)
Carrying amount	$	758,680		$	720,109		$	779,887
Estimated fair value⁽¹⁾	$	792,623		$	791,885		$	853,339

⁽¹⁾Estimated fair value does not include unamortized debt issuance costs.

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8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

We recognize the service cost component of net periodic benefit cost for our pension and other postretirement benefit plans in operations and maintenance expense in our consolidated statements of comprehensive income. The other non-service cost components are recognized in other income (expense), net in our consolidated statements of comprehensive income. The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans:



	Three Months Ended June 30,												Six Months Ended June 30,
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
In thousands	2018			2017			2018			2017			2018			2017			2018			2017
Service cost	$	1,807		$	1,870		$	79		$	99		$	3,614		$	3,740		$	159		$	197
Interest cost	4,183			4,472			241			274			8,366			8,944			482			548
Expected return on plan assets	(5,150		)	(5,112		)	—			—			(10,301		)	(10,225		)	—			—
Amortization of prior service costs	10			31			(117		)	(117		)	21			63			(234		)	(234		)
Amortization of net actuarial loss	4,524			3,622			112			139			9,047			7,243			222			277
Net periodic benefit cost	5,374			4,883			315			395			10,747			9,765			629			788
Amount allocated to construction	(685		)	(1,558		)	(28		)	(135		)	(1,367		)	(3,079		)	(55		)	(267		)
Amount deferred to regulatory balancing account⁽¹⁾	(2,747		)	(1,508		)	—			—			(5,503		)	(3,035		)	—			—
Net amount charged to expense	$	1,942		$	1,817		$	287		$	260		$	3,877		$	3,651		$	574		$	521

⁽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. See Note 2 in the 2017 Form 10-K.

The following table presents amounts recognized in accumulated other comprehensive loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plans:



	Three Months Ended June 30,						Six Months Ended June 30,
In thousands	2018			2017			2018			2017
Beginning balance	$	(8,284	)	$	(6,815	)	$	(8,438	)	$	(6,951	)
Amounts reclassified from AOCL:
Amortization of actuarial losses	209			225			418			450
Total reclassifications before tax	209			225			418			450
Tax (benefit) expense	(56		)	(88		)	(111		)	(177		)
Total reclassifications for the period	153			137			307			273
Ending balance	$	(8,131	)	$	(6,678	)	$	(8,131	)	$	(6,678	)

Employer Contributions to Company-Sponsored Defined Benefit Pension Plans

For the six months ended June 30, 2018, we made cash contributions totaling $5.6 million to our qualified defined benefit pension plans. We expect further plan contributions of $10.0 million during the remainder of 2018.

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 $3.5 million and $2.8 million for the six months ended June 30, 2018 and 2017, respectively.

See Note 8 in the 2017 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

9. INCOME TAX

An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.

The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:



	Three Months Ended June 30,						Six Months Ended June 30,
Dollars in thousands	2018			2017			2018			2017
Income taxes at statutory rates (federal and state)	$	(135	)	$	2,603		$	15,233		$	29,912
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(14		)	66			835			1,584
Other, net	(7		)	(122		)	(592		)	(1,318		)
Total provision for income taxes on continuing operations	$	(156	)	$	2,547		$	15,476		$	30,178
Effective tax rate for continuing operations	31.5		%	38.5		%	27.1		%	39.9		%

The effective income tax rate for the three and six months ended June 30, 2018 compared to the same periods in 2017 decreased primarily as a result of the TCJA and lower pre-tax income. See "U.S. Federal TCJA Matters" below and Note 9 in the 2017 Form 10-K for more detail on income taxes and effective tax rates.

The IRS Compliance Assurance Process (CAP) examination of the 2016 tax year was completed during the first quarter of 2018. There were no material changes to the return as filed. The 2017 tax year is subject to examination under CAP and the 2018 tax year CAP application has been accepted by the IRS.

U.S. Federal TCJA Matters

On December 22, 2017, the TCJA was enacted and permanently lowered the U.S. federal corporate income tax rate to 21% from the previous 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 and placed in service after September 27, 2017.

Under pre-TCJA law, business interest expense was 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 ongoing uncertainty with regards to the application of the new interest expense limitation to our non-regulated operations. See Note 9 in the 2017 Form 10-K.

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, ongoing uncertainty exists with respect to the application of full expensing to our non-regulated activities, and the availability of bonus depreciation for utility assets acquired before September 28, 2017 and placed in service after September 27, 2017. See Note 9 in the 2017 Form 10-K.

At June 30, 2018 and December 31, 2017, we had an estimated regulatory liability of $213.3 million for the change in regulated utility deferred taxes as a result of the TCJA, which included a gross-up for income taxes of $56.5 million. It is possible that this estimated balance may increase or decrease in the future as additional authoritative interpretation of the TCJA becomes available, or as a result of regulatory guidance from the OPUC or WUTC. We anticipate that until such time that customers receive the direct benefit of this regulatory liability, the balance, net of the additional gross-up for income taxes, will continue to provide an indirect benefit to customers by reducing the utility rate base which is a component of customer rates. It is not yet certain when the final resolution of these regulatory proceedings will occur, and as result, this regulatory liability is classified as long-term.

Utility rates in effect include an allowance to provide for the recovery of the anticipated provision for income taxes incurred as a result of providing regulated services. As a result of the newly enacted 21% federal corporate income tax rate, we are recording an additional regulatory liability in 2018 reflecting the estimated net reduction in our provision for income taxes. This revenue deferral is based on the estimated net benefit to customers using forecasted regulated utility earnings, considering average weather and associated volumes, and includes a gross-up for income taxes. As of June 30, 2018, a regulatory liability of $9.4 million has been recorded including accrued interest to reflect this estimated revenue deferral.

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10. PROPERTY, PLANT, AND EQUIPMENT

The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation of our continuing operations:



	June 30,				December 31,
In thousands	2018		2017		2017
Utility plant in service	$	3,035,089	$	2,901,791	$	2,975,217
Utility construction work in progress	192,496		127,383		159,924
Less: Accumulated depreciation	966,766		925,589		942,879
Utility plant, net	2,260,819		2,103,585		2,192,262
Non-utility plant in service	65,743		63,964		65,372
Non-utility construction work in progress	5,528		4,974		4,122
Less: Accumulated depreciation	18,232		16,969		17,598
Non-utility plant, net ⁽¹⁾	53,039		51,969		51,896
Total property, plant, and equipment	$	2,313,858	$	2,155,554	$	2,244,158

Capital expenditures in accrued liabilities ⁽²⁾	$	22,112	$	42,574	$	34,761


⁽¹⁾	Previously reported non-utility balances were restated due to the assets and liabilities associated with Gill Ranch now being classified as discontinued operations assets and liabilities on the consolidated balance sheets. See Note 15 for further discussion.

⁽²⁾

Previously reported capital expenditures in accrued liabilities were restated due to the assets and liabilities associated with Gill Ranch now being classified as discontinued operations assets and liabilities on the consolidated balance sheets. Capital expenditures in accrued liabilities related to Gill Ranch were approximately $0.3 million, $0.1 million, and $0.2 million as of June 30, 2018, June 30, 2017, and December 31, 2017, respectively.

Build-to-suit Assets

In October 2017, we entered into a 20-year operating lease agreement commencing in 2020 for our new headquarters location in Portland, Oregon. Our existing headquarters lease expires in 2020. Our search and evaluation process focused on seismic preparedness, safety, reliability, least cost to our customers, and a continued commitment to our employees and the communities we serve. 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 have recognized $7.6 million and $0.5 million in property, plant and equipment and an obligation in other non-current liabilities for the same amount in our consolidated balance sheet at June 30, 2018 and December 31, 2017, respectively. In 2019, pursuant to the new lease standard issued by the FASB, we expect to de-recognize the associated build-to-suit asset and liability. See Note 14 in our 2017 Form 10-K.

11. GAS RESERVES

We have invested approximately $188 million through our gas reserves program in the Jonah Field located in Wyoming as of June 30, 2018. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities in 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 approximately $178 million and the amended agreement with Jonah Energy LLC under which an approximate additional $10 million was invested.

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.

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.

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The following table outlines our net gas reserves investment:



	June 30,				December 31,
In thousands	2018		2017		2017
Gas reserves, current	$	16,579	$	16,072	$	15,704
Gas reserves, non-current	170,958		171,464		171,832
Less: Accumulated amortization	95,596		79,444		87,779
Total gas reserves⁽¹⁾	91,941		108,092		99,757
Less: Deferred taxes on gas reserves	20,381		31,074		22,712
Net investment in gas reserves	$	71,560	$	77,018	$	77,045


⁽¹⁾	Our net investment in additional wells included in total gas reserves was $5.5 million, $6.3 million and $5.8 million at June 30, 2018 and 2017 and December 31, 2017, respectively.

Our investment is included in our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.

12. INVESTMENTS

Investments in Gas Pipeline

Trail West Pipeline, LLC (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 in our balance sheet. If we do not develop this investment, 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 June 30, 2018 and 2017 and December 31, 2017. See Note 12 in our 2017 Form 10-K.

Other Investments

Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in our 2017 Form 10-K.

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, net of amounts shared with utility customers.

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Notional Amounts

The following table presents the absolute notional amounts related to open positions on our derivative instruments:



	June 30,				December 31,
In thousands	2018		2017		2017
Natural gas (in therms):
Financial	473,900		490,780		429,100
Physical	724,450		495,751		520,268
Foreign exchange	$	7,804	$	7,788	$	7,669

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:



	Three Months Ended June 30,
	2018						2017
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	2,658		$	(56	)	$	(5,172	)	$	216
Operating revenues	391			—			(109		)	—
Amounts deferred to regulatory accounts on balance sheet	(2,915		)	56			5,263			(216		)
Total gain (loss) in pre-tax earnings	$	134		$	—		$	(18	)	$	—



	Six Months Ended June 30,
	2018						2017
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(3,089	)	$	(210	)	$	(16,515	)	$	224
Operating revenues	164			—			(1,277		)	—
Amounts deferred to regulatory accounts on balance sheet	2,980			210			17,347			(224		)
Total gain (loss) in pre-tax earnings	$	55		$	—		$	(445	)	$	—

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 $4.7 million and $13.7 million for the three and six months ended June 30, 2018, respectively, from the settlement of natural gas financial derivative contracts. Whereas, we realized net gains of $0.3 million and remained flat for the three and six months ended June 30, 2017, respectively. 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 June 30, 2018 or 2017. 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 2018 or 2017. 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

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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 upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $14.3 million at June 30, 2018, 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

Speculative

With Adequate Assurance Calls

—

NORTHWEST NATURAL GAS CO - FORM 10-Q - August 7, 2018

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