Attached files

file filename
EX-32.1 - EXHIBIT 32.1 SOX CERTIFICATION - NORTHWEST NATURAL GAS COex-321x201710xk.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS COex-312x201710xk.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS COex-311x201710xk.htm
EX-23 - EXHIBIT 23 CONSENT OF AUDITORS - NORTHWEST NATURAL GAS COex-23x201710xk.htm
EX-21 - EXHIBIT 21 SUBSIDIARIES OF NW NATURAL GAS COMPANY - NORTHWEST NATURAL GAS COex-21x201710xk.htm
EX-12 - EXHIBIT 12 RATIO OF EARNINGS TO FIXED CHARGES - NORTHWEST NATURAL GAS COex-12x201710xk.htm
EX-10.SS - EXHIBIT 10.SS CASH RETENTION BONUS AGREEMENT - NORTHWEST NATURAL GAS COex-10ssx201710xk.htm
EX-10.RR - EXHIBIT 10.RR HIRE-ON BONUS AGREEMENT - NORTHWEST NATURAL GAS COex-10rrx201710xk.htm
EX-10.QQ - EXHIBIT 10.QQ SPECIAL RENTION RESTRICTED STOCK UNIT AWARD AGREEMENT - NORTHWEST NATURAL GAS COex-10qqx201710xk.htm
EX-10.BB - EXHIBIT 10.BB RESTRICTED STOCK UNIT AWARD AGREEMENT - NORTHWEST NATURAL GAS COex-10bbx201710xk.htm
EX-10.Y - EXHIBIT 10.Y PERFORMANCE SHARE LONG TERM INCENTIVE AGREEMENT - NORTHWEST NATURAL GAS COex-10yx201710xk.htm
EX-10.S - EXHIBIT 10.S LONG TERM INCENTIVE PLAN - NORTHWEST NATURAL GAS COex-10sx201710xk.htm
EX-10.P - EXHIBIT 10.P EXECUTIVE ANNUAL INCENTIVE PLAN - NORTHWEST NATURAL GAS COex-10px201710xk.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X]       ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
[  ]       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
logoform10qa34.jpg
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter) 
 Oregon 
93-0256722
(State or other jurisdiction of    
(I.R.S. Employer
incorporation or organization)  
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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class                                                                                   Name of each exchange on which registered
Common Stock                                                                                       New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  [ X ]    No  [    ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes  [   ]    No  [ X ]
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.[   ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth 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. (Check one):
Large Accelerated Filer [ X ]                                                                      Accelerated Filer [    ]
Non-accelerated Filer [    ]                                                                         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 ]
As of June 30, 2017, the aggregate market value of the shares of Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $1,695,121,435.
At February 16, 2018, 28,751,528 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of the registrant, to be filed in connection with the 2018 Annual Meeting of Shareholders, are incorporated by reference in Part III.



NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission on Form 10-K
For the Fiscal Year Ended December 31, 2017

TABLE OF CONTENTS

PART I
 
 
 
 
 
Page
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II
 
 
 
 
 
 
Item 5.
 
 
 
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
 

PART III
 
 
 
 
 

Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
 

PART IV
 
 
 
 
 

Item 15.
Item 16.


2





GLOSSARY OF TERMS AND ABBREVIATIONS

AFUDC
 
Allowance for Funds Used During Construction
AOCI / AOCL
 
Accumulated Other Comprehensive Income (Loss)
ASC
 
Accounting Standards Codification
ASU
 
Accounting Standards Update as issued by the FASB
Average Weather
 
The 25-year average of heating degree days based on temperatures established in our last Oregon general rate case
Bcf
 
Billion cubic feet, a volumetric measure of natural gas, where one Bcf is roughly equal to 10 million therms
CNG
 
Compressed Natural Gas
Core Utility Customers
 
Residential, commercial, and industrial customers receiving firm service from the utility
Cost of Gas
 
The delivered cost of natural gas sold to customers, including the cost of gas purchased or withdrawn/produced from storage inventory or reserves, gains and losses from gas commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and Company gas use
CPUC
 
California Public Utilities Commission, the entity that regulates our California gas storage business at our Gill Ranch facility with respect to rates and terms of service, among other matters
Decoupling
 
A billing rate mechanism, also referred to as our conservation tariff, which is designed to allow the utility to encourage industrial and small commercial customers to conserve energy while not adversely affecting its earnings due to reductions in sales volumes
Demand Cost
 
A component in core utility customer rates representing the cost of securing firm pipeline capacity, whether the capacity is used or not
EBITDA
 
Earnings before interest, taxes, depreciation and amortization, a non-GAAP financial measure
EE/CA
 
Engineering Evaluation / Cost Analysis
Encana
 
Encana Oil & Gas (USA) Inc.
Energy Corp
 
Northwest Energy Corporation, a wholly-owned subsidiary of NW Natural
EPA
 
Environmental Protection Agency
EPS
 
Earnings per share
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission; the entity regulating interstate storage services offered by our Mist gas storage facility as part of our gas storage segment
Firm Service
 
Natural gas service offered to customers under contracts or rate schedules that will not be disrupted to meet the needs of other customers
FMBs
 
First Mortgage Bonds
GAAP
 
Accounting principles generally accepted in the United States of America
General Rate Case
 
A periodic filing with state or federal regulators to establish billing rates for utility customers
GHG
 
Greenhouse gases
Gill Ranch
 
Gill Ranch Storage, LLC, a wholly-owned subsidiary of NWN Gas Storage
Gill Ranch Facility
 
Underground natural gas storage facility near Fresno, California, with 75% owned by Gill Ranch and 25% owned by PG&E
GTN
 
Gas Transmission Northwest, which owns a transmission pipeline serving California and the Pacific Northwest
Heating Degree Days
 
Units of measure reflecting temperature-sensitive consumption of natural gas, calculated by subtracting the average of a day’s high and low temperatures from 65 degrees Fahrenheit
HATFA
 
Highway and Transportation Funding Act of 2014
IBEW
 
International Brotherhood of Electrical Workers Local Union No. 1245, which is also referred to as the Union formerly representing NW Natural's bargaining unit employees at Gill Ranch
Interruptible Service
 
Natural gas service offered to customers (usually large commercial or industrial users) under contracts or rate schedules that allow for interruptions when necessary to meet the needs of firm service customers
IRP
 
Integrated Resource Plan
KB
 
Kelso-Beaver Pipeline, of which 10% is owned by KB Pipeline Company, a subsidiary of NNG Financial
LNG
 
Liquefied Natural Gas, the cryogenic liquid form of natural gas. To reach a liquid form at atmospheric pressure, natural gas must be cooled to approximately negative 260 degrees Fahrenheit


1





MAP-21
 
A federal pension plan funding law called the Moving Ahead for Progress in the 21st Century Act, July 2012
Moody's
 
Moody's Investors Service, Inc., credit rating agency
NAV
 
Net Asset Value
NNG Financial
 
NNG Financial Corporation, a wholly-owned subsidiary of NW Natural
NOL
 
Net Operating Loss
NRD
 
Natural Resource Damages
NWN Energy
 
NW Natural Energy, LLC, a wholly-owned subsidiary of NW Natural
NWN Gas Reserves
 
NWN Gas Reserves LLC, a wholly-owned subsidiary of Northwest Energy Corporation
NWN Gas Storage
 
NW Natural Gas Storage, LLC, a wholly-owned subsidiary of NWN Energy
ODEQ
 
Oregon Department of Environmental Quality
OPEIU
 
Office and Professional Employees International Union Local No. 11, AFL-CIO, which is also referred to as the Union representing NW Natural's bargaining unit employees
OPUC
 
Public Utility Commission of Oregon; the entity that regulates our Oregon utility business with respect to rates and terms of service, among other matters; the OPUC also regulates our Mist gas storage facility's intrastate storage services
PBGC
 
Pension Benefit Guaranty Corporation
PG&E
 
Pacific Gas & Electric Company; 25% owner of the Gill Ranch Facility
PGA
 
Purchased Gas Adjustment, a regulatory mechanism which adjusts customer rates to reflect changes in the forecasted cost of gas and differences between forecasted and actual gas costs from the prior year
PGE
 
Portland General Electric; primary customer of the North Mist gas storage expansion
PHMSA
 
U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration
PRP
 
Potentially Responsible Parties
RI/FS
 
Remedial Investigation / Feasibility Study
ROD
 
Record of Decision
ROE
 
Return on Equity, a measure of corporate profitability, calculated as net income or loss divided by average common stock equity. Authorized ROE refers to the equity rate approved by a regulatory agency for use in determining utility revenue requirements
ROR
 
Rate of Return, a measure of return on utility rate base. Authorized ROR refers to the rate of return approved by a regulatory agency and is generally discussed in the context of ROE and capital structure
S&P
 
Standard & Poor's, a credit rating agency and division of The McGraw-Hill Companies, Inc.
Sales Service
 
Service provided whereby a customer purchases both natural gas commodity supply and transportation from the utility
SEC
 
U.S. Securities and Exchange Commission
SRRM
 
Site Remediation and Recovery Mechanism, a billing rate mechanism for recovering prudently incurred environmental site remediation costs allocable to Oregon through customer billings, subject to an earnings test
TAIL
 
TransCanada American Investments, Ltd., a 50% owner of TWH
TCJA
 
H.R.1; An act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018, also known as the Tax Cuts and Jobs Act enacted on December 22, 2017
Therm
 
The basic unit of natural gas measurement, equal to one hundred thousand Btu’s
TWH
 
Trail West Holdings, LLC, 50% owned by NWN Energy
TWP
 
Trail West Pipeline, LLC, a subsidiary of TWH
TransCanada
 
TransCanada Pipelines Limited, owner of TAIL and GTN
Transportation Service
 
Service provided whereby a customer purchases natural gas directly from a supplier but pays the utility to transport the gas over its distribution system to the customer’s facility
Utility Margin
 
A financial measure consisting of utility operating revenues less the associated cost of gas, franchise taxes, and environmental recoveries
WARM
 
An Oregon billing rate mechanism applied to residential and commercial customers to adjust for temperature variances from average weather
WUTC
 
Washington Utilities and Transportation Commission, the entity that regulates our Washington utility business with respect to rates and terms of service, among other matters


2





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 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;
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 performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed at Item 1A., "Risk Factors" of Part I and 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", respectively, of Part II of this report.
 
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.


3





NORTHWEST NATURAL GAS COMPANY
PART I

ITEM 1. BUSINESS
OVERVIEW

Northwest Natural Gas Company (NW Natural or the Company) was incorporated under the laws of Oregon in 1910. Our Company and its predecessors have supplied gas service to the public since 1859, and we have been doing business as NW Natural since 1997. We maintain operations in Oregon, Washington, and California and conduct business through NW Natural and its subsidiaries. References in this discussion to "Notes" are to the Notes to the Consolidated Financial Statements in Item 8 of this report.
  
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 storage facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other. See Note 4 for further information.

The utility business is our largest segment, while our gas storage business accounts for the majority of our remaining net income or loss. The following table reflects the allocation between segments and other as of December 31, 2017:
 
 
 
 
Non-Utility(1)
 
 
In millions
 
Utility
 
Gas Storage(2)
 
Other
 
Total
Assets(3)
 
$
2,961.3

 
$
59.6

 
$
18.8

 
$
3,039.7

Net income (loss)(3)
 
60.5

 
(116.2
)
 
0.1

 
(55.6
)
(1) 
We refer to our gas storage segment and other as non-utility as they are not included in our regulated gas distribution business; however, certain aspects of the gas storage segment and other may be regulated by the OPUC, WUTC, CPUC, or FERC.
(2)  
Our gas storage segment includes asset management services for both the utility and non-utility portion of our Mist gas storage facility.
(3)  
Our assets and net loss include an impairment of long-lived assets at the Gill Ranch Facility of $192.5 million and $141.5 million, respectively. See Part II, Item 7, "Application of Critical Accounting Policies and Estimates—Impairment of Long-Lived Assets."

LOCAL GAS DISTRIBUTION "UTILITY"

The utility is principally engaged in the regulated distribution of natural gas in Oregon and southwest Washington to over 735,000 customers with approximately 89% of our customers located in Oregon and 11% located in Washington. In total, we provide natural gas service to over 100 cities in 18 counties with an estimated population of 3.7 million in our service territory.
 
We have been allocated an exclusive service territory by the OPUC and WUTC, which includes a major portion of western Oregon, including the Portland metropolitan area, most of the Willamette Valley, the Coastal area from Astoria to Coos Bay, and portions of Washington along the Columbia River. Portland serves as one of the largest international ports on the West Coast and is a key distribution center due to its comprehensive transportation system of ocean and river shipping, transcontinental railways and highways, and an international airport. Major businesses located in our service territory include retail, manufacturing, and high-technology industries.

Customers
We serve residential, commercial, and industrial customers with no individual customer or industry accounting for more than 10% of our utility revenues. On an annual basis, residential and commercial customers typically account for 55% to 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.

The following table presents summary customer information as of December 31, 2017:
 
 
Number of Customers
 
% of Volumes
 
% of Utility Margin (1)
Residential
 
668,803

 
38
%
 
63
%
Commercial
 
68,050

 
22
%
 
28
%
Industrial
 
1,021

 
40
%
 
8
%
Other
 
N/A

 
N/A

 
1
%
Total
 
737,874

 
100
%
 
100
%
(1)  
Utility margin is also affected by other items, including miscellaneous services, gains or losses from our gas cost incentive sharing mechanism, and other service fees.

Generally, residential and commercial customers purchase both their natural gas commodity (gas sales) and natural gas delivery services (transportation services) from the utility. Industrial customers also purchase transportation services from the utility, but may buy the gas commodity either from the utility or directly from a third-party gas marketer or supplier. Our gas commodity cost is primarily a pass-through cost to customers; therefore, our profit margins are not materially affected by an industrial customer's decision to purchase gas from us or from third parties. Industrial and large commercial customers may also select between firm and interruptible service levels, with firm services generally providing higher profit margins compared to interruptible services.

To help manage gas supplies, our industrial tariffs are designed to provide some certainty regarding industrial customers' volumes by requiring an annual service election, special charges for changes between elections, and in some cases, a minimum or maximum volume requirement before changing options. 

Customer growth rates for natural gas utilities in the Pacific Northwest historically have been among the highest in the nation due to lower market saturation as natural gas became widely available as a residential heating source after other fuel options. We estimate natural gas was in approximately 63% of single-family residential homes in


4





both 2017 and 2016 using our in-house system mapping technology. Customer growth in our region comes from the following main sources: single-family housing, both new construction and conversions; multifamily housing new construction; and commercial buildings, both new construction and conversions. Single-family new construction has consistently been our strongest performing source of growth. Continued customer growth is closely tied to the comparative price of natural gas to electricity and fuel oil and the health of the Portland, Oregon and Vancouver, Washington economies. We believe there is potential for continued growth as natural gas is a preferred energy source due to its affordable, reliable, and clean qualities.

Competitive Conditions
In our service areas, we have no direct competition from other natural gas distributors, but we compete with other forms of energy in each customer class. This competition among energy suppliers is based on price, efficiency, reliability, performance, preference, market conditions, technology, federal, state, and local energy policy, and environmental impacts.

For residential and small to mid-size commercial customers, we compete primarily with providers of electricity, fuel oil, and propane.

In the industrial and large commercial markets, we compete with all forms of energy, including competition from wholesale natural gas marketers. In addition, large industrial customers could bypass our local gas distribution system by installing their own direct pipeline connection to the interstate pipeline system. We have designed custom transportation service agreements with several of our largest industrial customers to provide transportation service rates that are competitive with the customer’s costs of installing their own pipeline; these agreements generally prohibit bypass. Due to the cost pressures confronting a number of our largest customers competing in global markets, bypass continues to be a competitive threat. Although we do not expect a significant number of our large customers to bypass our system in the foreseeable future, we could experience deterioration of utility margin if customers bypass or switch over to custom contracts with lower profit margins.

Seasonality of Business
Our utility business is seasonal in nature due to higher gas usage by residential and commercial customers during the cold winter heating months. Our other categories of customers experience seasonality in their usage but to a lesser extent.

Regulation and Rates
The utility is subject to regulation by the OPUC, WUTC, and FERC. These regulatory agencies authorize rates and allow recovery mechanisms to provide our utility the opportunity to recover prudently incurred capital and operating costs from customers, while also earning a reasonable return on investment for investors. In addition, the OPUC and WUTC also regulate the system of accounts and issuance of securities by our utility.

We file general rate cases and rate tariff requests periodically with the commissions to establish approved
 
rates, an authorized ROE, an overall rate of return on rate base (ROR), an authorized utility capital structure, and other revenue/cost deferral and recovery mechanisms.

In addition, under our Mist interstate storage certificate with FERC, the utility is required to file either a petition for rate approval or a cost and revenue study every five years to change or justify maintaining the existing rates for the interstate storage service.

For further discussion on our most recent general rate cases, see Part II, Item 7, "Results of Operations—Regulatory Matters—Regulation and Rates".

Gas Supply
The utility strives to secure sufficient, reliable supplies of natural gas to meet the needs of customers at the lowest reasonable cost, while maintaining price stability and managing gas purchase costs prudently. This is accomplished through a comprehensive strategy focused on the following items:
Reliability - ensuring gas resource portfolios are sufficient to satisfy customer requirements under extreme cold weather conditions;
Diverse Supply - providing diversity of supply sources;
Diverse Contracts - maintaining a variety of contract durations, types, and counterparties; and
Cost Management and Recovery - employing prudent gas cost management strategies.

Reliability
The effectiveness of our gas distribution system ultimately rests on whether we provide reliable service to our core utility customers. To ensure our effectiveness, we develop a composite design year, including a seven-day design peak event based on the most severe cold weather experienced during the last 30 years in our service territory. 

Our projected maximum design day firm utility customer sendout is approximately 9.7 million therms. Of this total, we are currently capable of meeting about 57% of our maximum design day requirements with gas from storage located within or adjacent to our service territory, while the remaining supply requirements would come from gas purchases under firm gas purchase contracts and recall agreements. 

To supplement near-term natural gas supplies, we can segment transportation capacity during the heating seasons, if needed. Pipeline segmentation is a natural gas transportation mechanism under which a shipper can leverage its firm pipeline transportation capacity by separating it into multiple segments with alternate delivery routes. The reliability of service on these alternate routes will vary depending on the constraints of the pipeline system. For those segments with acceptable reliability, segmentation provides a shipper with increased flexibility and potential cost savings compared to traditional pipeline service. During the 2016-2017 and 2017-2018 heating seasons, we segmented and relied on approximately 0.6 million therms per day of our firm pipeline transportation capacity that flowed from Stanfield, Oregon to various points south of Molalla, Oregon.



5





We believe our gas supplies would be sufficient to meet existing firm customer demand if we were to experience maximum design day weather conditions. We will continue to evaluate and update our forecasted requirements and incorporate changes in our IRP process.  

The following table shows the sources of supply projected to be used to satisfy the design day sendout for the 2017-2018 winter heating season:
 Therms in millions
 
Therms
 
Percent
Sources of utility supply:
 
 
 
 
Firm supply purchases
 
3.4

 
34
%
Mist underground storage (utility only)
 
3.1

 
32

Company-owned LNG storage
 
1.9

 
19

Off-system storage contract
 
0.5

 
5

Pipeline segmentation capacity
 
0.6

 
6

Recall agreements
 
0.4

 
4

Total
 
9.9

 
100
%

The OPUC and WUTC have IRP processes in which utilities define different growth scenarios and corresponding resource acquisition strategies in an effort to evaluate supply and demand resource requirements, consider uncertainties in the planning process and the need for flexibility to respond to changes, and establish a plan for providing reliable service at the least cost.

We file a full IRP biennially for Oregon and Washington with the OPUC and the WUTC, respectively, and file updates between filings. The OPUC acknowledges the Company's action plan; whereas the WUTC provides notice that our IRP has met the requirements of the Washington Administrative Code. OPUC acknowledgment of the IRP does not constitute ratemaking approval of any specific resource acquisition strategy or expenditure. However, the Commissioners generally indicate that they would give considerable weight in prudence reviews to utility actions consistent with acknowledged plans. The WUTC has indicated the IRP process is one factor it will consider in a prudence review.  For additional information see Part II, Item 7, "Results of Operations—Regulatory Matters".

Diversity of Supply Sources
We purchase our gas supplies primarily from the Alberta and British Columbia areas of Canada and multiple receipt points in the U.S. Rocky Mountains to protect against regional supply disruptions and to take advantage of price differentials. For 2017, 59% of our gas supply came from Canada, with the balance primarily coming from the U.S. Rocky Mountain region. We believe gas supplies available in the western United States and Canada are adequate to serve our core utility requirements for the foreseeable future. We continue to evaluate the long-term supply mix based on projections of gas production and pricing in the U.S. Rocky Mountain region as well as other regions in North America; however, we believe the cost of natural gas coming from western Canada and the U.S. Rocky Mountain region will continue to track with broader U.S. market pricing. Additionally, the extraction of shale gas has increased the availability of gas supplies throughout North America for the foreseeable future.

 
We supplement our firm gas supply purchases with gas withdrawals from gas storage facilities, including underground reservoirs and LNG storage facilities. Storage facilities are generally injected with natural gas during the off-peak months in the spring and summer and the gas is withdrawn for use during peak demand months in the winter.

The following table presents the storage facilities available for our utility supply:
 
 
Maximum Daily Deliverability (therms in millions)
 
Designed Storage
Capacity (Bcf)
Gas Storage Facilities
 
 
 
 
Owned Facility
 
 
 
 
Mist, Oregon(1)
 
3.1

 
10.6

Contracted Facilities
 
 
 
 
Jackson Prairie, Washington(2)
 
0.5

 
1.1

Alberta, Canada(3)
 
0.3

 
1.5

LNG Facilities
 
 
 
 
Owned Facilities
 
 
 
 
Newport, Oregon
 
0.6

 
1.0

Portland, Oregon
 
1.3

 
0.6

Total
 
5.8

 
14.8

(1)  
The Mist gas storage facility has a total maximum daily deliverability of 5.4 million therms and a total designed storage capacity of about 16 Bcf, of which 3.1 million therms of daily deliverability and 10.6 Bcf of storage capacity are reserved for core utility customers.
(2)  
The storage facility is located near Chehalis, Washington and is contracted from Northwest Pipeline, a subsidiary of The Williams Companies.
(3)
This resource does not add to our total peak day capacity, but mitigates price risks as it displaces equivalent volumes of heating season spot purchases

The Mist facility is used for both utility and non-utility purposes. Under our regulatory agreements with the OPUC and WUTC, non-utility gas storage at Mist can be developed in advance of core utility customer needs but is subject to recall by the utility when needed to serve utility customers as their demand increases. In 2017, the utility did not recall additional deliverability or associated storage capacity from the non-utility business to serve core utility customer needs.  

In addition, we have the ability to recall pipeline capacity and supply resources from certain customers if needed to meet high demand requirements.

Diverse Contract Durations and Types
We have a diverse portfolio of short-, medium-, and long-term firm gas supply contracts and a variety of contract types including firm and interruptible supplies as well as supplemental supplies from gas storage facilities.

Our portfolio of firm gas supply contracts typically includes the following gas purchase contracts: year-round and winter-only baseload supplies; seasonal supply with an option to call on additional daily supplies during the winter heating season; and daily or monthly spot purchases.



6





During 2017, we purchased a total of 857 million therms under contracts with durations outlined in the chart below:
Contract Duration (primary term)
Percent of Purchases
Long-term (one year or longer)
26
%
Short-term (more than one month, less than one year)
23

Spot (one month or less)
51

Total
100
%

We renew or replace gas supply contracts as they expire. During 2017, no individual supplier provided over 10% of our gas supply requirements.

Gas Cost Management
The cost of gas sold to utility customers primarily consists of the following items, which are included in annual PGA rates: gas purchases from suppliers; charges from pipeline companies to transport gas to our distribution system; gas storage costs; gas reserves contracts; and gas commodity derivative contracts.

We employ a number of strategies to mitigate the cost of gas sold to utility customers. Our primary strategies for managing gas commodity price risk include:
negotiating fixed prices directly with gas suppliers;
negotiating financial derivative contracts that: (1) effectively convert floating index prices in physical gas supply contracts to fixed prices (referred to as commodity price swaps); or (2) effectively set a ceiling or floor price, or both, on floating index priced physical supply contracts (referred to as commodity price options such as calls, puts, and collars). See Part II, Item 7A, "Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Credit Exposure to Financial Derivative Counterparties";
buying physical gas supplies at a set price and injecting the gas into storage for price stability and to minimize pipeline capacity demand costs; and
investing in gas reserves for longer term price stability. See Note 11 for additional information about our gas reserves.

We also contract with an independent energy marketing company to capture opportunities regarding our storage and pipeline capacity when those assets are not serving the needs of our core utility customers. Our asset management activities provide opportunities for cost of gas savings for our customers and incremental revenues for our shareholders through a regulatory incentive-sharing mechanism. These activities are included in our gas storage segment.

Gas Cost Recovery
Mechanisms for gas cost recovery are designed to be fair and reasonable, with an appropriate balance between the interests of our customers and shareholders. In general, utility rates are designed to recover the costs of, but not to earn a return on, the gas commodity sold. We minimize risks associated with gas cost recovery by resetting customer rates annually through the PGA and aligning customer and shareholder interests through the use of sharing, weather normalization, and conservation mechanisms in Oregon.
 
See Part II, Item 7, "Results of Operations—Regulatory Matters" and "Results of Operations—Business Segments—Local Gas Distribution Utility Operations—Cost of Gas."

Transportation of Gas Supplies
Our local gas distribution system is reliant on a single, bi-directional interstate transmission pipeline to bring gas supplies into our distribution system. Although we are dependent on a single pipeline, the pipelines gas flows into the Portland metropolitan market from two directions: (1) the north, which brings supplies from the British Columbia and Alberta supply basins; and (2) the east, which brings supplies from Alberta as well as the U.S. Rocky Mountain supply basins. 

We incur monthly demand charges related to our firm pipeline transportation contracts. These contracts are multi-year contracts with expirations ranging from 2018 to 2060. Our largest pipeline agreements are with Northwest Pipeline. We actively work with Northwest Pipeline and others to renew contracts in advance of expiration to ensure gas transportation capacity is sufficient to meet our utility needs.

Rates for interstate pipeline transportation services are established by FERC within the U.S. and by Canadian authorities for services on Canadian pipelines.

As mentioned above, our service territory is dependent on a single pipeline for its natural gas supply. Although supply has not been disrupted in the recent past, pipeline replacement projects and long-term projected natural gas demand in our region underscore the need for pipeline transportation diversity. In addition, there are potential industrial projects in the region, which could increase the demand for natural gas and the need for additional pipeline capacity and pipeline diversity.

Currently, there are various interstate pipeline projects proposed, including the Trail West pipeline in which we have an interest, that could meet the forecasted demand for us and the region. However, the location of any future pipeline project will likely depend on the location of committed industrial projects. We will continue to evaluate and closely monitor the currently prospected projects to determine the best option for our customers. We have an equity investment in Trail West Holdings, LLC (TWH) that is developing plans to build the Trail West pipeline. This pipeline would connect TransCanada Pipelines Limited’s (TransCanada) Gas Transmission Northwest (GTN) interstate transmission line to our local gas distribution system. If constructed, this pipeline would provide another transportation path for gas purchases from Alberta and the U.S. Rocky Mountains in addition to the one that currently moves gas through the Northwest Pipeline system.

Gas Distribution
The primary goals of our gas distribution operations are safety and reliability of our system, which entails building and maintaining a safe pipeline distribution system.

Safety and the protection of our employees, our customers, and the public at large are, and will remain, our top priorities. We construct, operate, and maintain our pipeline distribution system and storage operations with the goal of


7





ensuring natural gas is delivered and stored safely, reliably, and efficiently. 

NW Natural has one of the most modern distribution systems in the country with no identified cast iron pipe or bare steel main. We removed the final known bare steel from our system in 2015 and completed our cast iron pipe removal in 2000. Since the 1980s, we have taken a proactive approach to replacement programs and partnered with our Commissions on progressive regulation to further safety and reliability efforts for our distribution system. In the past, we had a cost recovery program in Oregon that encompassed our programs for bare steel replacement, transmission pipeline integrity management, and distribution pipeline integrity management. If we want to have future cost recovery programs, we would have to seek PUC approval. For discussion on current regulatory programs, see Part II, Item 7, "Results of Operations—Regulatory Matters".

Natural gas distribution businesses will continue to be subject to greater federal and state regulation in the future due to pipeline incidents involving other companies.
Additional operating and safety regulations from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) are currently under development. In 2016, PHMSA issued proposed regulations to update safety requirements for natural gas transmission pipelines. The final draft of these regulations is anticipated to be issued by the end of 2018, with final regulations anticipated to be issued in 2019. Current proposed regulations indicate a 15-year timeline for implementation of compliance requirements. We will continue to work diligently with industry associations as well as federal and state regulators to ensure the safety of our system and compliance with new laws and regulations. We expect the costs to our utility associated with compliance with federal, state, and local rules would be recoverable in rates.

North Mist Gas Storage Expansion Project
In Oregon, there is a need to integrate intermittent resources, such as wind and solar, into the power system with policymakers committing to the elimination of coal-fired electric generation and moving toward a 50% renewable electricity standard by 2040. New, flexible natural gas-fired electric generation facilities and associated gas storage are necessary to support the integration of renewable resources. In 2016, we began expanding our gas storage facility near Mist, Oregon to provide innovative long-term, no-notice underground gas storage service to support gas-fired electric generating facilities that are intended to facilitate the integration of more wind power into the region's electric generation mix. Natural gas storage enables generation to adjust quickly when renewable energy, such as wind and solar, rises and falls.

This expansion project will be dedicated solely to Portland General Electric (PGE), a local electric company, to support their gas-fired electric power generation facilities under an initial 30-year contract with options to extend, totaling up to an additional 50 years upon mutual agreement of the parties.

 
The expansion project includes a new reservoir providing up to 2.5 Bcf of available storage, an additional compressor station with design capacity of 120,000 decatherms of gas per day, no-notice service that can be drawn on rapidly, and a 13-mile pipeline to connect to PGE's gas plants at Port Westward. The expansion project is considered part of the utility segment and has an estimated cost of approximately $132 million, with a targeted in-service date of the winter of 2018-19. See additional discussion in Part II, Item 7 "Financial Condition—Cash Flows—Investing Activities".

When the expansion is placed into service, the investment will immediately be included in rate base under an established tariff schedule already approved by the OPUC, with revenues recognized consistent with the schedule. Billing rates will be updated annually to the current depreciable asset level and forecasted operating expenses.

GAS STORAGE
Our gas storage segment includes the following:
the non-utility portion of the Mist gas storage facility near Mist, Oregon;
the Gill Ranch Facility near Fresno, California; and
asset management services provided by an independent energy marketing company.

In general, the supply of natural gas remains relatively stable over the course of a year, while the demand for natural gas typically fluctuates seasonally. Storage facilities allow customers to purchase and inject natural gas supplies during periods of low demand and withdraw these supplies for use or resale during periods of higher demand. These facilities allow us to capitalize on the imbalance of supply and demand and price volatility for natural gas. 

For more information on gas storage assets and results of operations, see Note 4 and Part II, Item 7, "Financial Condition—Capital Structure—Liquidity and Capital Resources".

Gas Storage Facilities
The following table provides information concerning our non-utility gas storage facilities:
 
 
 
 
Maximum
 
 
Designed Storage
Capacity (Bcf)
 
Deliverability
(Therms in millions/day(3)
 
Injection
(Therms in millions/day)(3)
Mist Storage(1)
 
5.4

 
2.3

 
0.8

Gill Ranch Storage(2)
 
15.0

 
4.9

 
2.4

(1)
Approximately 5.4 Bcf of a total designed storage capacity of about 16 Bcf at Mist is currently available to our gas storage segment. The remaining 10.6 Bcf is used to provide gas storage for our local distribution business and its utility customers.
(2)  
Our gas storage segment share of the Gill Ranch Facility is currently 15 Bcf out of a total capacity of 20 Bcf.
(3)
Our gas storage segment share of the designed daily maximum injection and deliverability rates.

In addition to the designed storage capacity described above, capacity may incrementally increase based on variations in the heat content of the stored gas. All storage capacity and daily deliverability currently developed for the


8





gas storage segment at Mist is available for recall by the utility. In 2015, the utility recalled approximately 0.3 million therms per day of deliverabiility and 0.7 Bcf of capacity for core utility customer use. There were no recalls by the utility in 2016 and 2017.

Mist Storage Facility
The Mist storage facility began operations in 1989. It is a 16 Bcf facility with 5.4 Bcf available for use in our gas storage segment. The remaining 10.6 Bcf is used to provide gas storage for our local distribution business and its utility customers. Excluding the North Mist expansion, the facility consists of seven depleted natural gas reservoirs, 22 injection and withdrawal wells, a compressor station, dehydration and control equipment, gathering lines, and other related facilities.

SERVICES. Mist provides multi-cycle gas storage services to customers in the interstate and intrastate markets from the facility located in Columbia County, Oregon, near the town of Mist. The Mist field was initially converted to storage operations for our utility customers. Since 2001, gas storage capacity at Mist has also been made available to interstate customers by developing new incremental capacity in advance of core utility customer requirements to meet the demands for interstate storage service. These interstate storage services are offered under a limited jurisdiction blanket certificate issued by FERC. In addition, since 2005 we have offered intrastate firm storage services in Oregon under an OPUC-approved rate schedule as an optional service to eligible non-residential utility customers. 
 
CUSTOMERS. For Mist storage services, firm service agreements with customers are entered into with terms typically ranging from 1 to 10 years. Currently, our gas storage revenues from Mist are derived primarily from firm service customers who provide energy-related services, including natural gas distribution, electric generation, and energy marketing. Four storage customers currently account for all of our existing contracted non-utility gas storage capacity at Mist, with the largest customer accounting for about half of the total capacity. These four customers have contracts expiring at various dates through 2024.

COMPETITIVE CONDITIONS. Our Mist gas storage facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location. However, competition from other storage providers in Washington and Canada, as well as competition for interstate pipeline capacity, does exist. In the future, we could face increased competition from new or expanded gas storage facilities as well as from new natural gas pipelines, marketers, and alternative energy sources.

SEASONALITY. Mist gas storage revenues generally do not follow seasonal patterns similar to those experienced by the utility because most of the storage capacity is contracted with customers for firm service, which are primarily in the form of fixed monthly reservation charges and are not affected by customer usage. However, there is seasonal variation with Mist storage capacity and deliverability usage related to customers' lower demand during the spring and summer months, which can be optimized under regulatory sharing agreements with the OPUC and WUTC. For additional discussion, see "Asset Management" below.
 

REGULATION. Our Mist facility is subject to regulation by the OPUC and WUTC. In addition, FERC has approved maximum cost-based rates under our Mist interstate storage certificate. We are required to file either a petition for rate approval or a cost and revenue study with FERC at least every five years to change or justify maintaining the existing rates for the interstate storage service. For additional regulation and rates discussion, see Part II, Item 7, "Results of Operations—Regulatory Matters".

EXPANSION OPPORTUNITIES. We are currently expanding our Mist Storage facility to provide 2.5 Bcf of storage to a local electric company. For additional discussion, see "Local Gas Distribution CompanyNorth Mist Gas Storage Expansion Project" above. While there are additional expansion opportunities in the Mist storage field, further development is not contemplated at this time and expansion would be based on market demand, project execution, cost effectiveness, available financing, receipt of future permits, and other rights.

Gill Ranch Storage Facility
Gill Ranch Storage, LLC (Gill Ranch), our subsidiary, has a joint project agreement with Pacific Gas and Electric Company (PG&E) governing the development and ownership of the Gill Ranch Facility, an underground natural gas storage facility near Fresno, California. Currently, Gill Ranch is the sole operator of the facility. The facility began operations in 2010 and consists of three depleted natural gas reservoirs, 12 injection and withdrawal wells, a compressor station, dehydration and control equipment, gathering lines, an electric substation, a natural gas transmission pipeline extending 27 miles from the storage field to an interconnection with the PG&E transmission system, and other related facilities. Gill Ranch owns the rights to 75%, or 15.0 Bcf, of the designed gas storage capacity at the facility.

The California gas storage market is challenged by low market prices and low market price volatility resulting from the abundant supply of natural gas to, and natural gas storage in, the region. We have substantially completed contracting for this facility for the 2018-19 gas year at pricing that was lower than expected and low relative to the pricing in our original long-term contracts which ended primarily in the 2013-14 gas storage year.

We have believed and continue to believe that we may see storage price improvements or an increase in the demand for natural gas in the future driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, an increase in use of alternative fuels to meet carbon emission reduction targets, growth of the California economy, growth of domestic industrial manufacturing, potential exports of liquefied natural gas from the west coast, and other favorable storage market conditions in and around California. These factors, if they were to occur, may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values, but there can be no assurance that any of the foregoing will occur. To the contrary, we have not seen the rebound in storage pricing as we originally anticipated.



9





For the last few years, we have been diligently pursuing opportunities to increase revenues at the Gill Ranch Facility. Simultaneously, we have been conducting a strategic review of Gill Ranch and exploring all strategic alternatives.
In the fourth quarter of 2017, we completed our comprehensive strategic review process, which included a sale process for our portion of the Gill Ranch Facility, and made a determination that Gill Ranch is no longer considered core to our long-term growth plans.

We will continue to pursue all strategic options for this asset, including, but not limited to, a potential sale. In the meantime, we remain committed to operating the facility to the highest safety standards. See Note 2 and Part II, Item 7 "Application of Critical Accounting Policies and Estimates".

SERVICES. Gill Ranch provides intrastate, multi-cycle storage services in California at market-based rates under a CPUC-approved tariff that includes firm storage service, interruptible storage service, and park and loan storage services. The Gill Ranch Facility is not currently authorized to provide interstate gas storage services.

CUSTOMERS. Customer contracts for firm storage capacity at Gill Ranch have contract terms for as long as 27 years in duration; however, the majority of the contracted capacity is shorter term in nature due to market conditions. In the near-term, we expect Gill Ranch to contract for terms ranging from one to five years. For the 2017-18 gas storage year, Gill Ranch has several storage customers, with the largest single contract accounting for approximately 13% of our storage capacity. In the near-term, we continue to expect shorter contract lengths reflecting current market prices and trends.

The California market served by Gill Ranch is larger, and has a greater diversity of prospective customers, than the Pacific Northwest market served by Mist. Therefore, we expect less sensitivity to any single customer or group of customers at Gill Ranch. Current Gill Ranch customers provide energy related services, including natural gas production, marketing, and electric generation.

COMPETITIVE CONDITIONS. The Gill Ranch Facility currently competes with a number of other storage providers, including local integrated gas companies and other independent storage providers (ISPs) in the northern California market. There are currently four ISPs authorized by the CPUC to provide storage services in California, with the Gill Ranch Facility comprising approximately 12% of the storage capacity held by ISPs. An acquisition during 2016 consolidated approximately 80% of the storage capacity authorized by the CPUC to ISPs in California.

In late 2015, a significant natural gas leak occurred at an unaffiliated southern California gas storage facility. In response to the incident, both state and federal additional regulations were developed. The California Department of Oil, Gas and Geothermal Resources (DOGGR) developed and proposed new regulations for gas storage wells that focus on implementing additional well integrity requirements. Initial draft regulations suggested that individual well risk would be the basis for testing and implementation of subsurface modifications for all wells. This would potentially
 
allow for a multiple year timeframe to comply after the issuance of the regulations with any necessary capital expenditures completed over several years after completing the testing period. DOGGR released a new formulation of these rules on February 12, 2018. Although these rules are subject to a comment period and possible revision, these rules establish a timeframe for completion of compliance within seven years, a period much shorter than we originally anticipated. We anticipate the final version of these regulations will be finalized in 2018. In addition, PHMSA proposed new federal regulations for underground natural gas storage facilities that focus on implementing additional pipeline safety requirements of downhole facilities, including operations, maintenance, and emergency response activities regarding wells, wellbore tubing, and casing.

While the regulations are still under development, and their ultimate impact is unknown, it is likely the final PHMSA and DOGGR regulations will result in higher costs for all storage providers. As a result of the legislation and proposed regulation, the nature of, and demand for, future storage contracts, costs of operating, and market values in California could be impacted and remain uncertain at this time.

SEASONALITY. While the majority of our Gill Ranch revenues are not subject to seasonality, and although we expect much of the storage revenue at Gill Ranch to be in the form of fixed monthly demand charges, cash flows can fluctuate due to timing of asset management and other revenues. In addition, a significant portion of operating costs at Gill Ranch are subject to fluctuations based on periods when storage customers elect to inject or withdraw.

REGULATION. Gill Ranch has a tariff on file with the CPUC authorizing it to charge market-based rates for the storage services offered. For additional discussion, see Part II, Item 7, "Results of Operations–Regulatory Matters".

EXPANSION OPPORTUNITIES. Subject to market demand, project execution, available financing, receipt of future permits, and other rights, the Gill Ranch Facility can be expanded beyond the current combined ownership designed storage capacity of 20 Bcf without further expansion of the takeaway pipeline system. Taking these considerations into account and with certain infrastructure modifications, we currently estimate the Gill Ranch Facility could support an additional 25 Bcf of storage capacity, bringing the total storage capacity to approximately 45 Bcf, of which our current rights would give us up to an additional 7.5 Bcf or ownership of a total of approximately 22.5 Bcf. We have no plans to expand the facility.

Asset Management
We contract with an independent energy marketing company to provide asset management services, primarily through the use of commodity exchange agreements and pipeline capacity release transactions. The results are included in the gas storage segment, except for amounts allocated to our utility pursuant to regulatory sharing agreements involving the use of utility assets. Utility pre-tax income from third-party asset management services is subject to revenue sharing with core utility customers. For additional discussion, see Part II, Item 7, "Results of Operations—Business SegmentsGas Storage".



10





OTHER

We have non-utility investments and other business activities which are aggregated and reported as other. Other primarily consists of:
non-utility appliance retail center operations;
an equity method investment in TWH, a joint venture to build and operate a gas transmission pipeline in Oregon. TWH is owned 50% by NWN Energy, a wholly-owned subsidiary of NW Natural, and 50% by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation;
a minority interest in the Kelso-Beaver Pipeline held by our wholly-owned subsidiary NNG Financial Corporation (NNG Financial); and
other operating and non-operating income and expenses of the parent company that are not included in utility or gas storage operations.

The pipelines referred to above are regulated by FERC. Less than 1% of our consolidated assets and consolidated net loss are related to activities in other. For summary information for these assets and results of operations, see Note 4.

We have signed agreements to purchase two privately-owned water utilities in the Pacific Northwest. If completed, we do not expect these transactions or their continued operations to have a material impact on our financial position. We expect to include financial results from these businesses in other.

ENVIRONMENTAL MATTERS


Properties and Facilities  
We own, or previously owned, properties and facilities that are currently being investigated that may require environmental remediation and are subject to federal, state, and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to address certain environmental impacts. Estimates of liabilities for environmental costs are difficult to determine with precision because of the various factors that can affect their ultimate disposition. These factors include, but are not limited to, the following:
the complexity of the site;
changes in environmental laws and regulations at the federal, state, and local levels;
the number of regulatory agencies or other parties involved;
new technology that renders previous technology obsolete, or experience with existing technology that proves ineffective;
the ultimate selection of a particular technology;
the level of remediation required;
variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site; and
the application of environmental laws that impose joint and several liabilities on all potentially responsible parties.
 
 
We have received recovery of a portion of such environmental costs through insurance proceeds and seek the remainder of such costs through customer rates, and we believe recovery of these costs is probable. In Oregon, we have a mechanism to recover expenses, subject to an earnings test and allocation rules. See Part II, Item 7, "Results of Operations—Rate Matters—Rate Mechanisms—Environmental Costs", Note 2, and Note 15.

Greenhouse Gas Matters
We recognize our businesses are likely to be impacted by future requirements to address greenhouse gas emissions. Future federal and/or state requirements may seek to limit emissions of greenhouse gases, including both carbon dioxide (CO2) and methane. These potential laws and regulations may require certain activities to reduce emissions and/or increase the price paid for energy based on its carbon content.

Current federal rules require the reporting of greenhouse gas emissions. In September 2009, the Environmental Protection Agency (EPA) issued a final rule requiring the annual reporting of greenhouse gas emissions from certain industries, specified large greenhouse gas emission sources, and facilities that emit 25,000 metric tons or more of CO2 equivalents per year. We began reporting emission information in 2011. Under this reporting rule, local gas distribution companies like NW Natural are required to report system throughput to the EPA on an annual basis. The EPA also issued additional greenhouse gas reporting regulations requiring the annual reporting of fugitive emissions from our operations.

In addition, the state of Washington's DOE enacted the Clean Air Rule (CAR) in 2016, which capped the maximum greenhouse gas emissions allowed from stationary sources, such as natural gas utilities. For gas distribution utilities, the production of emissions from usage by their customers was considered to be production of emissions attributable to the utility. In December 2017, in a Washington State Court proceeding, the Judge ruled that the Department of Ecology lacked legislative authority to regulate non-emitting sources, such as local distribution companies. The DOE has not yet indicated whether it will appeal the ruling. Currently, the Washington state legislature is considering other similar legislation.

Additionally, the Oregon legislature is currently considering various greenhouse gas reduction proposals, including cap and trade. One such bill would create a declining cap, beginning 2021, on greenhouse gas emissions emitted by a wide variety of emission sources, including electric and natural gas utilities, and would require large utilities to hold permits, or allowances, to emit greenhouse gas emissions on a per ton basis. The Oregon legislature is currently reviewing these proposals, and we expect them to review similar proposals in the future. While there is uncertainty regarding potential compliance costs and revenue sharing impacts of these and other similar proposals, we currently expect to be able to recover compliance costs in rates, and as such, do not expect this legislation to materially affect our consolidated financial position and results of operations.

The outcome of these or any additional federal and state policy developments in the area of climate change cannot


11





be determined at this time, but these initiatives could produce a number of results including new regulations, legal actions, additional charges to fund energy efficiency activities, or other regulatory actions. The adoption and implementation of any regulations limiting emissions of greenhouse gases from our operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations, which could result in an increase in the prices we charge our customers or a decline in the demand for natural gas. On the other hand, because natural gas is a low-carbon fuel, it is also possible future carbon constraints could create additional demand for natural gas for electric generation, direct use of natural gas in homes and businesses, and as a reliable and relatively low-emission back-up fuel source for alternative energy sources. Requirements to reduce greenhouse gas emissions from the transportation sector, such as those in Oregon’s clean fuel standard, could also result in additional demand for natural gas fueled vehicles.

We continue to take proactive steps to collaboratively address future greenhouse gas emission matters, including actively participating in policy development in Oregon and, at the federal level, within the American Gas Association. We engage in policy development to help drive policies that result in real and meaningful greenhouse gas emission reductions that are affordable for our customers, and identify ways to reduce greenhouse gas emissions in our own operations. We have developed a voluntary carbon savings initiative consisting of activities that fall into three broad categories: (1) reducing the carbon intensity of our product, (2) helping customers use less energy, and (3) displacing higher carbon fuels, such as replacing diesel in heavy duty vehicles. Additionally, we help our customers reduce and offset their gas use through partnership with the Energy Trust of Oregon offering efficiency programs and the Smart Energy program, which allows customers to voluntarily contribute funds to projects such as biodigesters on dairy farms that offset the greenhouse gases produced from their natural gas use.

EMPLOYEES

At December 31, 2017, our utility workforce consisted of 1,146 employees, of which 629 were members of the Office and Professional Employees International Union (OPEIU) Local No. 11, AFL-CIO, and 517 were non-union employees. Our labor agreement with members of OPEIU covers wages, benefits, and working conditions. On May 22, 2014, our union employees ratified a new labor agreement (Joint Accord) that extends to November 30, 2019, and thereafter from year to year unless either party serves notice of its intent to negotiate modifications to the collective bargaining agreement.

At December 31, 2017, our non-utility subsidiaries had a combined workforce of 14 non-union employees, of which eight had unionized as part of IBEW Local Union No. 1245 (IBEW) and were in the process of negotiating a collective bargaining agreement. In January 2018, we were notified by the majority of those represented employees that they no longer wished to be represented by IBEW as their bargaining agent. Therefore, our gas storage segment is no
 
longer recognizing IBEW as the bargaining agent for these eight employees.

Our subsidiaries receive certain services from centralized operations at the utility, and the utility is reimbursed for those services pursuant to a Shared Services Agreement.

ADDITIONS TO INFRASTRUCTURE

We make capital expenditures in order to maintain and enhance the safety and integrity of our pipelines, gate stations, storage facilities, and related assets, to expand the reach or capacity of those assets, or improve the efficiency of our operations. We expect to make a significant level of capital expenditures for additions to utility and gas storage infrastructure over the next five years, reflecting continued investments in customer growth, distribution system improvements, technology, and an expansion at our North Mist gas storage facility.

For the five-year period from 2018 to 2022, capital expenditures are estimated to be between $750 and $850 million.

Included in the five year period, 2018 utility capital expenditures are estimated to be between $190 and $220 million, including $20 to $30 million to complete the construction of our North Mist gas storage facility expansion. We expect to invest less than $5 million in non-utility capital investments for gas storage and other activities in 2018. Additional investments in our infrastructure during and after 2018 will depend largely on additional regulations and expansion opportunities. See additional discussion in Part II, Item 7 "Financial Condition—Cash Flows—Investing Activities".

EXECUTIVE OFFICERS OF THE REGISTRANT

For information concerning our executive officers, see Part III, Item 10.

AVAILABLE INFORMATION

We file annual, quarterly and current reports and other information with the Securities and Exchange Commission (SEC). Reports, proxy statements, and other information filed by us can be read, copied, and requested through the SEC by mail at U.S. Securities and Exchange Commission, 100 F Street, N.E., Washington, D.C. 20549, or online at its website (http://www.sec.gov). You can obtain information about access to the Public Reference Room and how to access or request records by calling the SEC at 1-800-SEC-0330. The SEC website contains reports, proxy and information statements, and other information we file electronically. In addition, we make available on our website (http://www.nwnatural.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) and proxy materials filed under Section 14 of the Securities Exchange Act of 1934, as amended (Exchange Act), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We have included our website address as an inactive textual reference only. Information


12





contained on our website is not incorporated by reference into this annual report on Form 10-K.

We have adopted a Code of Ethics for all employees, officers, and directors that is available on our website. We intend to disclose revisions and amendments to, and any waivers from, the Code of Ethics for officers and directors on our website. Our Corporate Governance Standards, Director Independence Standards, charters of each of the committees of the Board of Directors, and additional information about the Company are also available at the website. Copies of these documents may be requested, at no cost, by writing or calling Shareholder Services, NW Natural, One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone 503-226-4211 ext. 2402.



13





ITEM 1A. RISK FACTORS

Our business and financial results are subject to a number of risks and uncertainties, many of which are not within our control, which could adversely affect our business, financial condition, and results of operations. Additional risks and uncertainties that are not currently known to the Company or that are not currently believed by the Company to be material may also harm the Company's business, financial condition, and results of operations. When considering any investment in our securities, investors should carefully consider the following information, as well as information contained in the caption "Forward-Looking Statements", Item 7A, and other documents we file with the SEC. This list is not exhaustive and the order of presentation does not reflect management’s determination of priority or likelihood. Additionally, our listing of risk factors that primarily affects one of our business segments does not mean that such risk factor is inapplicable to our other business segments.

Risks Related to our Business Generally
REGULATORY RISK. Regulation of our businesses, including changes in the regulatory environment, failure of regulatory authorities to approve rates which provide for timely recovery of our costs and an adequate return on invested capital, or an unfavorable outcome in regulatory proceedings may adversely impact our financial condition and results of operations.

The OPUC and WUTC have general regulatory authority over our utility business in Oregon and Washington, respectively, including the rates charged to customers, authorized rates of return on rate base, including ROE, the amounts and types of securities we may issue, services we provide and the manner in which we provide them, the nature of investments we make, actions investors may take with respect to our company, and deferral and recovery of various expenses, including, but not limited to, pipeline replacement, environmental remediation costs, commodity hedging expense, transactions with affiliated interests, weather adjustment mechanisms and other matters. Similarly, in our gas storage businesses FERC has regulatory authority over interstate storage services, the CPUC has regulatory authority over our Gill Ranch storage operations, and the WUTC and OPUC have regulatory authority over our Mist storage operations. Additionally, expansion of our business, including into water or other sectors, could result in regulation by other regulatory authorities.

The prices the OPUC and WUTC allow us to charge for retail service, and the maximum FERC-approved rates FERC authorizes us to charge for interstate storage and related transportation services, are the most significant factors affecting our financial position, results of operations and liquidity. The OPUC and WUTC have the authority to disallow recovery of costs they find imprudently incurred or otherwise disallowed. Additionally, the rates allowed by the FERC may be insufficient for recovery of costs incurred. We expect to continue to make expenditures to expand, improve and operate our utility distribution and gas storage systems. Regulators can find such expansions or improvements of expenditures were not prudently incurred, and deny recovery. Additionally, while the OPUC and WUTC have
 
established an authorized rate of return for our utility through the ratemaking process, the regulatory process does not provide assurance that we will be able to achieve the earnings level authorized. Moreover, in the normal course of business we may place assets in service or incur higher than expected levels of operating expense before rate cases can be filed to recover those costs—this is commonly referred to as regulatory lag. The failure of any regulatory commission to approve requested rate increases on a timely basis to recover increased costs or to allow an adequate return could adversely impact our financial condition and results of operations.

As a regulated utility, we frequently have dockets open with our regulators. The regulatory proceedings for these dockets typically involve multiple parties, including governmental agencies, consumer advocacy groups, and other third parties. Each party has differing concerns, but all generally have the common objective of limiting amounts included in rates. We cannot predict the timing or outcome of these deferred proceedings or the effects of those outcomes on our results of operations and financial condition.

ENVIRONMENTAL LIABILITY RISK. Certain of our properties and facilities may pose environmental risks requiring remediation, the costs of which are difficult to estimate and which could adversely affect our financial condition, results of operations, and cash flows.

We own, or previously owned, properties that require environmental remediation or other action. We accrue all material loss contingencies relating to these properties. A regulatory asset at the utility has been recorded for estimated costs pursuant to a Deferral Order from the OPUC and WUTC. In addition to maintaining regulatory deferrals, we settled with most of our historical liability insurers for only a portion of the costs we have incurred to date and expect to incur in the future. To the extent amounts we recovered from insurance are inadequate or we are unable to recover these deferred costs in utility customer rates, we would be required to reduce our regulatory assets which would result in a charge to current year earnings. In addition, in Oregon, the OPUC approved the SRRM, which limits recovery of our deferred amounts to those amounts which satisfy an annual prudence review and earnings test that requires the Company to contribute additional amounts toward environmental remediation costs above approximately $10 million in years in which the Company earns above its authorized Return on Equity (ROE). To the extent the Company earns more than its authorized ROE in a year, the Company would be required to cover environmental expenses greater than the $10 million with those earnings that exceed its authorized ROE. In addition, the OPUC ordered a review of the SRRM in 2018 or when we obtain greater certainty of environmental costs, whichever occurs first. These ongoing prudence reviews, the earnings test, or the three-year review could reduce the amounts we are allowed to recover, and could adversely affect our financial condition, results of operations and cash flows.

Moreover, we may have disputes with regulators and other parties as to the severity of particular environmental matters, what remediation efforts are appropriate, and the


14





portion of the costs we should bear. We cannot predict with certainty the amount or timing of future expenditures related to environmental investigation, remediation or other action, the portions of these costs allocable to us, or disputes or litigation arising in relation thereto.

Our liability estimates are based on current remediation technology, industry experience gained at similar sites, an assessment of our probable level of responsibility, and the financial condition of other potentially responsible parties. However, it is difficult to estimate such costs due to uncertainties surrounding the course of environmental remediation, the preliminary nature of certain of our site investigations, and the application of environmental laws that impose joint and several liabilities on all potentially responsible parties. These uncertainties and disputes arising therefrom could lead to further adversarial administrative proceedings or litigation, with associated costs and uncertain outcomes, all of which could adversely affect our financial condition, results of operations and cash flows. 

ENVIRONMENTAL REGULATION COMPLIANCE RISK. We are subject to environmental regulations for our ongoing operations, compliance with which could adversely affect our operations or financial results.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, groundwater quality and availability, plant and wildlife protection, and other aspects of environmental regulation. For example, we are subject to reporting requirements to the Environmental Protection Agency and the Oregon Department of Environmental Quality regarding greenhouse gas emissions. Similarly, there are current legislative efforts in Oregon and Washington to cap or otherwise restrict the maximum GHGs an entity may emit without reduction efforts or other undertakings. These and other current and future additional environmental regulations could result in increased compliance costs or additional operating restrictions, which may or may not be recoverable in customer rates or through insurance. If these costs are not recoverable, they could have an adverse effect on our financial condition and results of operations.

GLOBAL CLIMATE CHANGE RISK. Future legislation to address global climate change may expose us to regulatory and financial risk. Additionally, our business may be subject to physical risks associated with climate change, all of which could adversely affect our financial condition, results of operations and cash flows.

There are a number of international, federal and state legislative and regulatory initiatives being proposed and adopted in an attempt to measure, control or limit the effects of global warming and climate change, including greenhouse gas emissions such as carbon dioxide and methane. Such current or future legislation or regulation could impose on us operational requirements, additional charges to fund energy efficiency initiatives, or levy a tax based on carbon content. Such initiatives could result in us
 
incurring additional costs to comply with the imposed restrictions, provide a cost advantage to energy sources other than natural gas, reduce demand for natural gas, impose costs or restrictions on end users of natural gas, impact the prices we charge our customers, impose increased costs on us associated with the adoption of new infrastructure and technology to respond to such requirements, and may impact cultural perception of our service or products negatively, diminishing the value of our brand, all of which could adversely affect our business practices, financial condition and results of operations.

Climate change may cause physical risks, including an increase in sea level, intensified storms, water scarcity and changes in weather conditions, such as changes in precipitation, average temperatures and extreme wind or other climate conditions. A significant portion of the nation’s gas infrastructure is located in areas susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to gas supply interruptions and price spikes.

These and other physical changes could result in disruptions to natural gas production and transportation systems potentially increasing the cost of gas and affecting our ability to procure gas to meet our customer demand. These changes could also affect our distribution systems resulting in increased maintenance and capital costs, disruption of service, regulatory actions and lower customer satisfaction. Additionally, to the extent that climate change adversely impacts the economic health or weather conditions of our service territory directly, it could adversely impact customer demand or our customers' ability to pay. Such physical risks could have an adverse effect on our financial condition, results of operations, and cash flows.

STRATEGIC TRANSACTION RISK. Our ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, business development projects or other strategic transactions is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, we may be unable to achieve some or all of the benefits that we anticipate from such transactions which could adversely affect our financial condition, results of operations, and cash flows.
 
From time to time, we have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, business development projects or other strategic transactions. Any such transactions involve substantial risks, including the following:
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
acquired businesses or assets could have, or supply, environmental, permitting, or other problems for which contractual protections prove inadequate;
we may experience difficulties in integration or operation costs of new businesses;
we may assume liabilities which were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;


15





we may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to us, or we may be unable to achieve anticipated regulatory treatment of any such transaction, or such benefits may be delayed or not occur at all;
we may agree to sell assets for a price that is less than the book value of those assets.

One of more of these conditions could affect our financial condition, results of operations, and cash flows.

BUSINESS DEVELOPMENT RISK. Our business development projects may encounter unanticipated obstacles, costs, changes or delays that could result in a project becoming impaired, which could negatively impact our financial condition, results of operations and cash flows.
 
Business development projects involve many risks. We are currently engaged in several business development projects, including, but not limited to, the early planning and development stages for a regional pipeline in Oregon, and an expansion of our gas storage facility at Mist. We may also engage in other business development projects such as investment in additional long-term gas reserves, CNG refueling stations, or projects in the water sector. These projects may not be successful. Additionally, we may not be able to obtain required governmental permits and approvals to complete our projects in a cost-efficient or timely manner potentially resulting in delays or abandonment of the projects. We could also experience startup and construction delays, construction cost overruns, disputes with contractors, inability to negotiate acceptable agreements such as rights-of-way, easements, construction, gas supply or other material contracts, changes in customer demand or commitment, public opposition to projects, changes in market prices, and operating cost increases. Additionally, we may be unable to finance our business development projects at acceptable interest rates or within a scheduled time frame necessary for completing the project. One or more of these events could result in the project becoming impaired, and such impairment could have an adverse effect on our financial condition and results of operations.

JOINT PARTNER RISK. Investing in business development projects through partnerships, joint ventures or other business arrangements affects our ability to manage certain risks and could adversely impact our financial condition, results of operations and cash flows.

We use joint ventures and other business arrangements to manage and diversify the risks of certain utility and non-utility development projects, including our Trail West pipeline, Gill Ranch storage and our gas reserves agreements. We may acquire or develop part-ownership interests in other projects in the future, including but not limited to, in the water sector. Under these arrangements, we may not be able to fully direct the management and policies of the business relationships, and other participants in those relationships may take action contrary to our interests including making operational decisions that could affect our costs and liabilities. In addition, other participants may withdraw from the project, divest important assets, become financially distressed or bankrupt, or have
 
economic or other business interests or goals that are inconsistent with ours.

For example, our gas reserves arrangements, which operate as a hedge backed by physical gas supplies, involve a number of risks. These risks include gas production that is significantly less than the expected volumes, or no gas volumes; operating costs that are higher than expected; changes in our consolidated tax position or tax laws that could affect our ability to take, or timing of, certain tax benefits that impact the financial outcome of this transaction; inherent risks of gas production, including disruption to operations or complete shut-in of the field; and a participant in one of these business arrangements acting contrary to our interests. In addition, while the cost of the original gas reserves venture is currently included in customer rates and additional wells under that arrangement are recovered at a specific cost, the occurrence of one or more of these risks, could affect our ability to recover this hedge in rates. Further, any new gas reserves arrangements have not been approved for inclusion in rates, and our regulators may ultimately determine to not include all or a portion of future transactions in rates. The realization of any of these situations could adversely impact the project as well as our financial condition, results of operations and cash flows.

OPERATING RISK. Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs, some or all of which may not be fully covered by insurance, and which could adversely affect our financial condition, results of operations and cash flows.

Our operations are subject to all of the risks and hazards inherent in the businesses of local gas distribution and storage, including:
earthquakes, floods, storms, landslides and other adverse weather conditions and hazards;
leaks or other losses of natural gas or other chemicals or compounds as a result of the malfunction of equipment or facilities;
damages from third parties, including construction, farm and utility equipment or other surface users;
operator errors;
negative performance by our storage reservoirs that could cause us to fail to meet expected or forecasted operational levels or contractual commitments to our customers;
problems maintaining, or the malfunction of, pipelines, wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our gas distribution and storage facilities;
collapse of underground storage caverns;
operating costs that are substantially higher than expected;
migration of natural gas through faults in the rock or to some area of the reservoir where existing wells cannot drain the gas effectively resulting in loss of the gas;
blowouts (uncontrolled escapes of gas from a pipeline or well) or other accidents, fires and explosions; and
risks and hazards inherent in the drilling operations associated with the development of the gas storage facilities and/or wells.



16





These risks could result in personal injury or loss of human life, damage to and destruction of property and equipment, pollution or other environmental damage, breaches of our contractual commitments, and may result in curtailment or suspension of our operations, which in turn could lead to significant costs and lost revenues. Further, because our pipeline, storage and distribution facilities are in or near populated areas, including residential areas, commercial business centers, and industrial sites, any loss of human life or adverse financial outcomes resulting from such events could be significant. Additionally, we may not be able to maintain the level or types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not covered by insurance could adversely affect our financial condition, results of operations and cash flows.

BUSINESS CONTINUITY RISK. We may be adversely impacted by local or national disasters, pandemic illness, terrorist activities, including cyber-attacks or data breaches, and other extreme events to which we may not be able to promptly respond.

Local or national disasters, pandemic illness, terrorist activities, including cyber-attacks and data breaches, and other extreme events are a threat to our assets and operations. Companies in critical infrastructure industries may face a heightened risk due to exposure to acts of terrorism, including physical and security breaches of our information technology infrastructure in the form of cyber-attacks. These attacks could target or impact our technology or mechanical systems that operate our distribution, transmission or storage facilities and result in a disruption in our operations, damage to our system and inability to meet customer requirements. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas or other necessary commodities that could affect our operations. Threatened or actual national disasters or terrorist activities may also disrupt capital or bank markets and our ability to raise capital or obtain debt financing, or impact our suppliers or our customers directly. Local disaster or pandemic illness could result in part of our workforce being unable to operate or maintain our infrastructure or perform other tasks necessary to conduct our business. A slow or inadequate response to events may have an adverse impact on operations and earnings. We may not be able to maintain sufficient insurance to cover all risks associated with local and national disasters, pandemic illness, terrorist activities and other events. Additionally, large scale natural disasters or terrorist attacks could destabilize the insurance industry making insurance we do have unavailable, which could increase the risk that an event could adversely affect our operations or financial results.

HOLDING COMPANY DIVIDEND RISK. If we were to reorganize as a holding company, the holding company would depend on its operating subsidiaries to meet financial obligations and the ability of the holding company to pay dividends on its common stock would be dependent on the receipt of dividends and other payments from its subsidiaries.

 
If we were to implement a holding company structure, NW Natural common stock would be converted or exchanged into shares of a holding company with the only significant assets being the stock of its operating subsidiaries, including NW Natural. NW Natural and its current subsidiaries, which would become NW Holding’s direct and indirect subsidiaries, are separate and distinct legal entities, managed by their own boards of directors, and, as is currently the case, would have no obligation to pay any amounts to their respective shareholders, whether through dividends, loans or other payments. The ability of these companies to pay dividends or make other distributions on their common stock is now, and would continue to be, subject to, among other things: their results of operations, net income, cash flows and financial condition, as well as the success of their business strategies and general economic and competitive conditions; the prior rights of holders of existing and future debt securities and any future preferred stock issued by those companies; and any applicable legal restrictions.

In addition, the ability of the holding company’s subsidiaries to pay upstream dividends and make other distributions would be subject to applicable state law and regulatory restrictions. Under the OPUC and WUTC regulatory approvals for the holding company formation, if NW Natural ceases to comply with credit and capital structure requirements approved by the OPUC and WUTC, it will not, with limited exceptions, be permitted to pay dividends to the holding company. Under the OPUC and WUTC orders authorizing the Company to form a holding company, NW Natural may not pay dividends or make distributions to the holding company if NW Natural’s credit ratings and common equity levels fall below specified ratings and levels. If NW Natural’s long-term secured credit ratings are below A- for S&P and A3 for Moody’s, dividends may be issued so long as NW Natural’s common equity is 45% or above. If NW Natural’s long-term secured credit ratings are below BBB for S&P and Baa2 for Moody’s, dividends may be issued so long as NW Natural’s common equity is 46% or above. Dividends may not be issued if NW Natural’s long-term secured credit ratings fall to BB+ or below for S&P or Ba1 or below for Moody’s, or if NW Natural’s common equity is below 44%. In each case, with the common equity level to be determined on a preceding or projected 13-month basis.

HOLDING COMPANY PRIORITY RISK. If a holding company structure is completed, the holding company’s ability to pay dividends on its common stock would be subject to the prior rights of holders of its indebtedness and preferred stock, if any.

If we were to form a holding company, it may from time to time issue debt securities and preferred stock, as well as additional shares of holding company common stock, in order to make capital contributions to one or more of its subsidiaries or for other reasons, although NW Natural would likely continue to issue its own debt securities and may issue preferred stock. The holding company could also guarantee indebtedness of non-utility subsidiaries. The issuance or guaranty of securities by the holding company would not be subject to the prior approval of the state utility commissions. The consolidated enterprise could thus be more highly leveraged than NW Natural and its current subsidiaries. The holding company’s ability to pay dividends


17





on its common stock would be subject to the prior rights of holders of the holding company’s debt securities (including guarantees) and preferred stock, if any.

In addition, the right of the holding company, as a shareholder, to receive assets of any of its direct or indirect subsidiaries upon the subsidiary’s liquidation or reorganization would be subject to the prior rights of the holders of existing and future debt securities and preferred stock issued by such subsidiaries, and, as in the case of dividends, the rights of holders of the holding company common stock to receive any such assets would be subject to the prior rights of the holders of the holding company’s debt securities (including guarantees) and preferred stock.

HOLDING COMPANY DIVERSIFICATION RISK. The holding company may invest in unregulated activities that may prove to be riskier than the current activities of NW Natural, which could result in losses and adversely affect the holding company’s financial condition, results of operations and cash flows.

The holding company structure may allow us greater opportunities to invest in regulated and unregulated businesses. These investments may involve greater risk than an investment in NW Natural. If losses are incurred in unregulated businesses, they will likely not be recoverable through utility rates and they could adversely affect the holding company’s financial condition, results of operations and cash flows.

EMPLOYEE BENEFIT RISK. The cost of providing pension and postretirement healthcare benefits is subject to changes in pension assets and liabilities, changing employee demographics and changing actuarial assumptions, which may have an adverse effect on our financial condition, results of operations and cash flows.

Until we closed the pension plans to new hires, which for non-union employees was in 2006 and for union employees was in 2009, we provided pension plans and postretirement healthcare benefits to eligible full-time utility employees and retirees. Most of our current utility employees were hired prior to these dates, and therefore remain eligible for these plans. Our cost of providing such benefits is subject to changes in the market value of our pension assets, changes in employee demographics including longer life expectancies, increases in healthcare costs, current and future legislative changes, and various actuarial calculations and assumptions. The actuarial assumptions used to calculate our future pension and postretirement healthcare expense may differ materially from actual results due to significant market fluctuations and changing withdrawal rates, wage rates, interest rates and other factors. These differences may result in an adverse impact on the amount of pension contributions, pension expense or other postretirement benefit costs recorded in future periods. Sustained declines in equity markets and reductions in bond rates may have a material adverse effect on the value of our pension fund assets and liabilities. In these circumstances, we may be required to recognize increased contributions and pension expense earlier than we had planned to the extent that the value of pension assets is less than the total anticipated liability under the plans, which could have a
 
negative impact on our financial condition, results of operations and cash flows.

WORKFORCE RISK. Our business is heavily dependent on being able to attract and retain qualified employees and maintain a competitive cost structure with market-based salaries and employee benefits, and workforce disruptions could adversely affect our operations and results.

Our ability to implement our business strategy and serve our customers is dependent upon our continuing ability to attract and retain talented professionals and a technically skilled workforce, and being able to transfer the knowledge and expertise of our workforce to new employees as our largely older workforce retires. We expect that a significant portion of our workforce will retire within the current decade, which will require that we attract, train and retain skilled workers to prevent loss of institutional knowledge or skills gap. Without an appropriately skilled workforce, our ability to provide quality service and meet our regulatory requirements will be challenged and this could negatively impact our earnings. Additionally, within our utility segment, a majority of our workers are represented by the OPEIU Local No.11 AFL-CIO, and are covered by a collective bargaining agreement that extends to November 30, 2019. Disputes with the union representing our employees over terms and conditions of their agreement could result in instability in our labor relationship and work stoppages that could impact the timely delivery of gas and other services from our utility and storage facilities, which could strain relationships with customers and state regulators and cause a loss of revenues. Our collective bargaining agreements may also limit our flexibility in dealing with our workforce, and our ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect our financial condition and results of operations.

LEGISLATIVE, COMPLIANCE AND TAXING AUTHORITY RISK. We are subject to governmental regulation, and compliance with local, state and federal requirements, including taxing requirements, and unforeseen changes in or interpretations of such requirements could affect our financial condition and results of operations.

We are subject to regulation by federal, state and local governmental authorities. We are required to comply with a variety of laws and regulations and to obtain authorizations, permits, approvals and certificates from governmental agencies in various aspects of our business. Significant changes in federal, state, or local governmental leadership can accelerate or amplify changes in existing laws or regulations, or the manner in which they are interpreted or enforced. For example, the U.S. Presidential Administration has made numerous leadership changes at federal administrative agencies since the 2016 U.S. Presidential election. Moreover, the U.S. Congress and the U.S. Presidential Administration may make substantial changes to fiscal, tax, regulation and other federal policies. The U.S. Presidential Administration has called for significant changes to U.S. fiscal policies, U.S. trade, healthcare, immigration, foreign, and government regulatory policy. To the extent the U.S. Congress or U.S. Presidential Administration implements changes to U.S. policy, those


18





changes may impact, among other things, the U.S. and global economy, international trade and relations, unemployment, immigration, corporate taxes, healthcare, the U.S. regulatory environment, inflation and other areas. Although we cannot predict the impact, if any, of these changes to our business, they could adversely affect our financial condition and results of operations. Until we know what policy changes are made and how those changes impact our business and the business of our competitors over the long term, we will not know if, overall, we will benefit from them or be negatively affected by them.

Though we cannot predict the changes in laws, regulations, or enforcement that are likely as a result of these transitions, we expect there to be a number of significant changes. We cannot predict with certainty the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and regulations. Additionally, any failure to comply with existing or new laws and regulations could result in fines, penalties or injunctive measures that could affect operating assets. For example, under the Energy Policy Act of 2005, the FERC has civil authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance may also increase. Changes in regulations, the imposition of additional regulations, and the failure to comply with laws and regulations could negatively influence our operating environment and results of operations. 

Additionally, changes in federal, state or local tax laws and their related regulations, or differing interpretations or enforcement of applicable law by a federal, state or local taxing authority, could result in substantial cost to us and negatively affect our results of operations. Tax law and its related regulations and case law are inherently complex and dynamic. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation. Our judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by taxing authorities. Changes in laws, regulations or adverse judgments and the inherent difficulty in quantifying potential tax effects of business decisions may negatively affect our financial condition and results of operations.

In this regard, the Tax Cuts and Jobs Act of 2017 was approved by the U.S. Congress on December 20, 2017 and signed into law by the U.S. President on December 22, 2017. This legislation makes significant changes to the U.S. Internal Revenue Code. Such changes include a reduction in the corporate tax rate from 35% to 21% and limitations on certain corporate deductions and credits, among other changes. Certain of these changes may negatively affect our financial condition and results of operations.

We expect that the elimination of bonus depreciation may increase taxes in 2018 and 2019, which may have an adverse effect on cash flows during this period. In addition, there is uncertainty as to how our regulators will reflect the impact of the legislation in rates. The resulting ratemaking treatment may negatively affect our financial condition and results of operations.

 
SAFETY REGULATION RISK. We may experience increased federal, state and local regulation of the safety of our systems and operations, which could adversely affect our operating costs and financial results.

The safety and protection of the public, our customers and our employees is and will remain our top priority. We are committed to consistently monitoring and maintaining our distribution system and storage operations to ensure that natural gas is acquired, stored and delivered safely, reliably and efficiently. Given recent high-profile natural gas explosions, leaks and accidents in other parts of the country involving both distribution systems and storage facilities, we anticipate that the natural gas industry may be the subject of even greater federal, state and local regulatory oversight. For example, in 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES Act) was signed into law increasing regulations for natural gas storage pipelines and underground storage facilities. Similarly, in 2016, California passed legislation directing the Department of Oil, Gas and Geothermal Resources (DOGGR) to develop regulations affecting gas storage operations. DOGGR has issued proposed regulations which we expect to go into effect within the first half of 2018. As currently written, these regulations require mechanical integrity testing and implementation of gas flow limited to tubing only for all wells at Gill Ranch within the next 7 years.

We intend to work diligently with industry associations and federal and state regulators to seek to ensure compliance with these and other new laws. We expect there to be increased costs associated with compliance, and those costs could be significant. If these costs are not recoverable in our customer rates, they could have a negative impact on our operating costs and financial results.
 
HEDGING RISK. Our risk management policies and hedging activities cannot eliminate the risk of commodity price movements and other financial market risks, and our hedging activities may expose us to additional liabilities for which rate recovery may be disallowed, which could result in an adverse impact on our operating revenues, costs, derivative assets and liabilities and operating cash flows.

Our gas purchasing requirements expose us to risks of commodity price movements, while our use of debt and equity financing exposes us to interest rate, liquidity and other financial market risks. In our Utility segment, we attempt to manage these exposures with both financial and physical hedging mechanisms, including our gas reserves transactions which are hedges backed by physical gas supplies. While we have risk management procedures for hedging in place, they may not always work as planned and cannot entirely eliminate the risks associated with hedging. Additionally, our hedging activities may cause us to incur additional expenses to obtain the hedge. We do not hedge our entire interest rate or commodity cost exposure, and the unhedged exposure will vary over time. Gains or losses experienced through hedging activities, including carrying costs, generally flow through the PGA mechanism or are recovered in future general rate cases. However, the hedge transactions we enter into for the utility are subject to a prudence review by the OPUC and WUTC, and, if found imprudent, those expenses may be, and have been


19





previously, disallowed, which could have an adverse effect on our financial condition and results of operations.

In addition, our actual business requirements and available resources may vary from forecasts, which are used as the basis for our hedging decisions, and could cause our exposure to be more or less than we anticipated. Moreover, if our derivative instruments and hedging transactions do not qualify for regulatory deferral and we do not elect hedge accounting treatment under generally accepted accounting standards, our results of operations and financial condition could be adversely affected.

We also have credit-related exposure to derivative counterparties. Counterparties owing us money or physical natural gas commodities could breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements to meet our normal business requirements. In that event, our financial results could be adversely affected. Additionally, under most of our hedging arrangements, any downgrade of our senior unsecured long-term debt credit rating could allow our counterparties to require us to post cash, a letter of credit or other form of collateral, which would expose us to additional costs and may trigger significant increases in borrowing from our credit facilities if the credit rating downgrade is below investment grade. Further, based on current interpretations, we are not considered a "swap dealer" or "major swap participant" in 2017, so we are exempt from certain requirements under the Dodd-Frank Act. If we are unable to claim this exemption, we could be subject to higher costs for our derivatives activities.

INABILITY TO ACCESS CAPITAL MARKET RISK. Our inability to access capital, or significant increases in the cost of capital, could adversely affect our financial condition and results of operations.

Our ability to obtain adequate and cost effective short-term and long-term financing depends on maintaining investment grade credit ratings as well as the existence of liquid and stable financial markets. Our businesses rely on access to capital and bank markets, including commercial paper, bond and equity markets, to finance our operations, construction expenditures and other business requirements, and to refund maturing debt that cannot be funded entirely by internal cash flows. Disruptions in capital markets could adversely affect our ability to access short-term and long-term financing. Our access to funds under committed credit facilities, which are currently provided by a number of banks, is dependent on the ability of the participating banks to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity. Disruptions in the bank or capital financing markets as a result of economic uncertainty, changing or increased regulation of the financial sector, or failure of major financial institutions could adversely affect our access to capital and negatively impact our ability to run our business and make strategic investments.

A negative change in our current credit ratings, particularly below investment grade, could adversely affect our cost of borrowing and access to sources of liquidity and capital.
 
Such a downgrade could further limit our access to borrowing under available credit lines. Additionally, downgrades in our current credit ratings below investment grade could cause additional delays in accessing the capital markets by the utility while we seek supplemental state regulatory approval, which could hamper our ability to access credit markets on a timely basis. A credit downgrade could also require additional support in the form of letters of credit, cash or other forms of collateral and otherwise adversely affect our financial condition and results of operations.

REPUTATIONAL RISKS. Customers', legislators', and regulators' opinions of us are affected by many factors, including system reliability and safety, protection of customer information, rates, media coverage, and public sentiment. To the extent that customers, legislators, or regulators have or develop a negative opinion of us, our financial positions, results of operations and cash flows could be adversely affected.

A number of factors can affect customer satisfaction including: service interruptions or safety concerns due to failures of equipment or facilities or from other causes, and our ability to promptly respond to such failures; our ability to safeguard sensitive customer information; and the timing and magnitude of rate increases, and volatility of rates. Customers', legislators', and regulators' opinions of us can also be affected by media coverage, including the proliferation of social media, which may include information, whether factual or not, that damages our brand and reputation.

If customers, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased regulatory oversight and could affect the returns on common equity we are allowed to earn. Additionally, negative opinions about us could make it more difficult for us to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volumes reductions or increased use of other sources of energy. Any of these consequences could adversely affect our financial position, results of operations and cash flows.

Risks Related Primarily to Our Local Utility Business
REGULATORY ACCOUNTING RISK. In the future, we may no longer meet the criteria for continued application of regulatory accounting practices for all or a portion of our regulated operations.

If we could no longer apply regulatory accounting, we could be required to write off our regulatory assets and precluded from the future deferral of costs not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future.

GAS PRICE RISK. Higher natural gas commodity prices and volatility in the price of gas may adversely affect our results of operations and cash flows.

The cost of natural gas is affected by a variety of factors, including weather, changes in demand, the level of production and availability of natural gas supplies, transportation constraints, availability and cost of pipeline


20





capacity, federal and state energy and environmental regulation and legislation, natural disasters and other catastrophic events, national and worldwide economic and political conditions, and the price and availability of alternative fuels. In our utility segment, the cost we pay for natural gas is generally passed through to our customers through an annual PGA rate adjustment. If gas prices were to increase significantly, it would raise the cost of energy to our utility customers, potentially causing those customers to conserve or switch to alternate sources of energy. Significant price increases could also cause new home builders and commercial developers to select alternative energy sources. Decreases in the volume of gas we sell could reduce our earnings, and a decline in customers could slow growth in our future earnings. Additionally, because a portion of any (10% or 20%) difference between the estimated average PGA gas cost in rates and the actual average gas cost incurred is recognized as current income or expense, higher average gas costs than those assumed in setting rates can adversely affect our operating cash flows, liquidity and results of operations. Additionally, notwithstanding our current rate structure, higher gas costs could result in increased pressure on the OPUC or the WUTC to seek other means to reduce rates, which also could adversely affect our results of operations and cash flows.

Higher gas prices may also cause us to experience an increase in short-term debt and temporarily reduce liquidity because we pay suppliers for gas when it is purchased, which can be in advance of when these costs are recovered through rates. Significant increases in the price of gas can also slow our collection efforts as customers experience increased difficulty in paying their higher energy bills, leading to higher than normal delinquent accounts receivable resulting in greater expense associated with collection efforts and increased bad debt expense.

CUSTOMER GROWTH RISK. Our utility margin, earnings and cash flow may be negatively affected if we are unable to sustain customer growth rates in our local gas distribution segment.

Our utility margins and earnings growth have largely depended upon the sustained growth of our residential and commercial customer base due, in part, to the new construction housing market, conversions of customers to natural gas from other energy sources and growing commercial use of natural gas. The last recession slowed new construction. While construction has resumed and the multi-family composition has been higher than its pre-recession pace, overall construction has not returned to the pre-recession pace. Insufficient growth in these markets, for economic, political or other reasons could result in an adverse long-term impact on our utility margin, earnings and cash flows.

RISK OF COMPETITION. Our gas distribution business is subject to increased competition which could negatively affect our results of operations.

In the residential and commercial markets, our gas distribution business competes primarily with suppliers of electricity, fuel oil, and propane. In the industrial market, we compete with suppliers of all forms of energy. Competition
 
among these forms of energy is based on price, efficiency, reliability, performance, market conditions, technology, environmental impacts and public perception.

Technological improvements in other energy sources such as heat pumps, batteries or other alternative technologies could erode our competitive advantage. If natural gas prices rise relative to other energy sources, or if the cost, environmental impact or public perception of such other energy sources improves relative to natural gas, it may negatively affect our ability to attract new customers or retain our existing residential, commercial and industrial customers, which could have a negative impact on our customer growth rate and results of operations.

RELIANCE ON THIRD PARTIES TO SUPPLY NATURAL GAS RISK. We rely on third parties to supply the natural gas in our distribution segment, and limitations on our ability to obtain supplies, or failure to receive expected supplies for which we have contracted, could have an adverse impact on our financial results.

Our ability to secure natural gas for current and future sales depends upon our ability to purchase and receive delivery of supplies of natural gas from third parties. We, and in some cases, our suppliers of natural gas do not have control over the availability of natural gas supplies, competition for those supplies, disruptions in those supplies, priority allocations on transmission pipelines, or pricing of those supplies. Additionally, third parties on whom we rely may fail to deliver gas for which we have contracted. If we are unable or are limited in our ability to obtain natural gas from our current suppliers or new sources, we may not be able to meet our customers' gas requirements and would likely incur costs associated with actions necessary to mitigate services disruptions, both of which could significantly and negatively impact our results of operations.

SINGLE TRANSPORTATION PIPELINE RISK. We rely on a single pipeline company for the transportation of gas to our service territory, a disruption of which could adversely impact our ability to meet our customers’ gas requirements.

Our distribution system is directly connected to a single interstate pipeline, which is owned and operated by Northwest Pipeline. The pipeline’s gas flows are bi-directional, transporting gas into the Portland metropolitan market from two directions: (1) the north, which brings supplies from the British Columbia and Alberta supply basins; and (2) the east, which brings supplies from the Alberta and the U.S. Rocky Mountain supply basins. If there is a rupture or inadequate capacity in the pipeline, we may not be able to meet our customers’ gas requirements and we would likely incur costs associated with actions necessary to mitigate service disruptions, both of which could significantly and negatively impact our results of operations.

WEATHER RISK. Warmer than average weather may have a negative impact on our revenues and results of operations.

We are exposed to weather risk primarily in our utility segment. A majority of our volume is driven by gas sales to space heating residential and commercial customers during the winter heating season. Current utility rates are based on


21





an assumption of average weather. Warmer than average weather typically results in lower gas sales. Colder weather typically results in higher gas sales. Although the effects of warmer or colder weather on utility margin in Oregon are expected to be mitigated through the operation of our weather normalization mechanism, weather variations from normal could adversely affect utility margin because we may be required to purchase more or less gas at spot rates, which may be higher or lower than the rates assumed in our PGA. Also, a portion of our Oregon residential and commercial customers (usually less than 10%) have opted out of the weather normalization mechanism, and 11% of our customers are located in Washington where we do not have a weather normalization mechanism. These effects could have an adverse effect on our financial condition, results of operations and cash flows.

CUSTOMER CONSERVATION RISK. Customers’ conservation efforts may have a negative impact on our revenues.

An increasing national focus on energy conservation, including improved building practices and appliance efficiencies may result in increased energy conservation by customers. This can decrease our sales of natural gas and adversely affect our results of operations because revenues are collected mostly through volumetric rates, based on the amount of gas sold. In Oregon, we have a conservation tariff which is designed to recover lost utility margin due to declines in residential and small commercial customers’ consumption. However, we do not have a conservation tariff in Washington that provides us this margin protection on sales to customers in that state.

RELIANCE ON TECHNOLOGY RISK. Our efforts to integrate, consolidate and streamline our operations have resulted in increased reliance on technology, the failure or security breach of which could adversely affect our financial condition and results of operations.

Over the last several years we have undertaken a variety of initiatives to integrate, standardize, centralize and streamline our operations. These efforts have resulted in greater reliance on technological tools such as: an enterprise resource planning system, an automated dispatch system, an automated meter reading system, a customer information system, a web-based ordering and tracking system, and other similar technological tools and initiatives. The failure of any of these or other similarly important technologies, or our inability to have these technologies supported, updated, expanded or integrated into other technologies, could adversely impact our operations. We take precautions to protect our systems, but there is no guarantee that the procedures we have implemented to protect against unauthorized access to secured data and systems are adequate to safeguard against all security breaches. Our utility could experience breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the utility in the normal course of business, which could adversely affect the utility’s reputation, diminish customer confidence, disrupt operations, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation, any of which could adversely affect our financial condition and results of operations.
 

Furthermore, we rely on information technology systems in our operations of our distribution and storage operations. There are various risks associated with these systems, including, hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other inadvertent errors or deliberate human acts. In particular, cyber security attacks, terrorism or other malicious acts could damage, destroy or disrupt all of our business systems. Any failure of information technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. As these potential cyber security attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems or obtain specific insurance coverage against potential losses.

Risks Related Primarily to Our Gas Storage Businesses
LONG-TERM LOW OR STABILIZATION OF GAS PRICE RISK. Any significant stabilization of natural gas prices or long-term low gas prices could have a negative impact on the demand for our natural gas storage services, which could adversely affect our financial results.

Storage businesses benefit from price volatility, which impacts the level of demand for services and the rates that can be charged for storage services. Largely due to the abundant supply of natural gas made available by hydraulic fracturing techniques, natural gas prices have dropped significantly to levels that are near historic lows. If prices and volatility remain low or decline further, then the demand for storage services, and the prices that we will be able to charge for those services, may decline or be depressed for a prolonged period of time. Prices below the costs to operate the storage facility could result in a decision to shut-in all or a portion of the facility. A sustained decline in these prices or a shut-in of all or a portion of the facility could have an adverse impact on our financial condition, results of operations and cash flows.

NATURAL GAS STORAGE COMPETITION RISK. Increasing competition in the natural gas storage business could reduce the demand for our storage services and drive prices down for storage, which could adversely affect our financial condition, results of operations and cash flows.

Our natural gas storage segment competes primarily with other storage facilities and pipelines. Natural gas storage is an increasingly competitive business, with the ability to expand or build new storage capacity in California, the U.S. Rocky Mountains and elsewhere in the United States and Canada. Increased competition in the natural gas storage business could reduce the demand for our natural gas storage services, drive prices down for our storage business, and adversely affect our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows, which could adversely affect our financial condition, results of operations and cash flows.



22





IMPAIRMENT OF LONG-LIVED ASSETS RISK. Additional impairments of the value of long-lived assets could have a material effect on our financial condition, or results of operations.
 
We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets might not be recoverable. The determination of recoverability is based on the undiscounted net cash flows expected to result from the operation of such assets. Projected cash flows depend on the future operating costs and projected revenues associated with the asset, storage pricing, the ability to contract with higher value customers, and the future market and price for gas storage over the remaining life of the asset. We recognized a $192.5 million impairment of long-lived assets at the Gill Ranch Facility as of December 31, 2017. Further changes in revenues, operating costs, or a decision to sell the facility may result in an additional impairment of long-lived assets at the Gill Ranch Facility. Additionally, we review our other long-lived assets to determine if an impairment analysis is necessary. Any impairment charge taken with respect to our long-lived assets could be material and could have a material effect on our financial condition and results of operations.

THIRD-PARTY PIPELINE RISK. Our gas storage businesses depend on third-party pipelines that connect our storage facilities to interstate pipelines, the failure or unavailability of which could adversely affect our financial condition, results of operations and cash flows.

Our gas storage facilities are reliant on the continued operation of a third-party pipeline and other facilities that provide delivery options to and from our storage facilities. Because we do not own all of these pipelines, their operations are not within our control. If the third-party pipeline to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the infrastructure, lack of capacity or other reasons, our ability to operate efficiently and satisfy our customers’ needs could be compromised, thereby potentially having an adverse impact on our financial condition, results of operations and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
We have no unresolved comments.



23





ITEM 2. PROPERTIES
  
Utility Properties
Our natural gas pipeline system consists of approximately 20,000 miles of distribution and transmission mains located in our service territory in Oregon and Washington. In addition, the pipeline system includes service pipelines, meters and regulators, and gas regulating and metering stations. Pipeline mains are located in municipal streets or alleys pursuant to franchise or occupation ordinances, in county roads or state highways pursuant to agreements or permits granted pursuant to statute, or on lands of others pursuant to easements obtained from the owners of such lands. We also hold permits for the crossing of numerous navigable waterways and smaller tributaries throughout our entire service territory.

We own service building facilities in Portland, Oregon, as well as various satellite service centers, garages, warehouses, and other buildings necessary and useful in the conduct of our business. We also lease office space in Portland for our corporate headquarters, which expires on May 31, 2020. Resource centers are maintained on owned or leased premises at convenient points in the distribution system to provide service within our utility service territory. We also own LNG storage facilities in Portland and near Newport, Oregon.

In October 2017, we entered into a 20-year operating lease agreement for a new headquarters in Portland in anticipation of the expiration of our current lease in 2020. We executed an extensive search and evaluation process that focused on seismic preparedness, safety, reliability, the least cost to our customers, and a continued commitment to our employees and the communities we serve. Payments under the new lease are expected to commence in 2020.
 
Gas Storage Properties 
We hold leases and other property interests in approximately 12,000 net acres of underground natural gas storage in Oregon, approximately 5,000 net acres of underground natural gas storage in California, and easements and other property interests related to pipelines associated with those facilities. We own rights to depleted gas reservoirs near Mist, Oregon that are continuing to be developed and operated as underground gas storage facilities. We also hold all future storage rights in certain other areas of the Mist gas field in Oregon, as well as in California related to the Gill Ranch Facility.
 
We consider all of our properties currently used in our operations, both owned and leased, to be well maintained, in good operating condition, and, along with planned additions, adequate for our present and foreseeable future needs.
  
Our Mortgage and Deed of Trust (Mortgage) is a first mortgage lien on substantially all of the property constituting our utility plant.

 
ITEM 3. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 15, we have only nonmaterial litigation in the ordinary course of business.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.



24





PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed and trades on the New York Stock Exchange under the symbol NWN. The high and low trades for our common stock during the past two years were as follows:
 
 
2017
 
2016
Quarter Ended
 
High
 
Low
 
High
 
Low
March 31
 
$
61.70

 
$
56.53

 
$
54.51

 
$
48.90

June 30
 
63.40

 
57.65

 
64.84

 
49.46

September 30
 
68.60

 
59.15

 
66.17

 
57.96

December 31
 
69.50

 
58.55

 
61.85

 
53.50


The closing price for our common stock on the last trading day of 2017 and 2016 was $59.65 and $59.80, respectively.

As of February 16, 2018, there were 5,213 holders of record of our common stock.

Dividends per share paid during the past two years were as follows:
Payment Month
 
2017
 
2016
February
 
$
0.4700

 
$
0.4675

May
 
0.4700

 
0.4675

August
 
0.4700

 
0.4675

November
 
0.4725

 
0.4700

Total per share
 
$
1.8825

 
$
1.8725


The declaration and amount of future dividends depend upon our earnings, cash flows, financial condition, and other factors. The amount and timing of dividends payable on our common stock are within the sole discretion of our Board of Directors. Subject to Board approval, we expect to continue paying cash dividends on our common stock on a quarterly basis.

The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the quarter ended December 31, 2017:
Issuer Purchases of Equity Securities
Period
 
Total Number
of Shares Purchased
(1)
 
Average
Price Paid per Share
 
Total Number of Shares
Purchased as Part of
Publicly Announced Plans or Programs
(2)
 
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the Plans or Programs
(2)
Balance forward
 
 
 
 
 
2,124,528

 
$
16,732,648

10/01/17-10/31/17
 
657

 
$
66.33

 

 

11/01/17-11/30/17
 
14,239

 
67.89

 

 

12/01/17-12/31/17
 
650

 
64.98

 

 

Total
 
15,546

 
67.71

 
2,124,528

 
$
16,732,648


(1) 
During the quarter ended December 31, 2017, the following number of shares of our common stock were purchased on the open market: 13,539 shares to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan and 2,007 shares to meet the requirements of our share-based programs. No shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.
(2) 
During the quarter ended December 31, 2017, no shares of our common stock were repurchased pursuant to our Board-Approved share repurchase program. For more information on this program, see Note 6.



25





ITEM 6. SELECTED FINANCIAL DATA
 
 
For the year ended December 31,
In thousands, except per share data
 
2017
 
2016
 
2015
 
2014
 
2013
Operating revenues
 
$
762,173

 
$
675,967

 
$
723,791

 
$
754,037

 
$
758,518

Net income (loss)
 
(55,623
)
 
58,895

 
53,703

 
58,692

 
60,538

 
 
 
 
 
 
 
 
 
 
 
Earnings (Loss) per share of common stock:
 
 
 
 

 
 

 
 

 
 

Basic
 
$
(1.94
)
 
$
2.13

 
$
1.96

 
$
2.16

 
$
2.24

Diluted
 
(1.94
)
 
2.12

 
1.96

 
2.16

 
2.24

Dividends paid per share of common stock
 
1.88

 
1.87

 
1.86

 
1.85

 
1.83

 
 
 
 
 
 
 
 
 
 
 
Total assets, end of period
 
$
3,039,746

 
$
3,079,801

 
$
3,069,410

 
$
3,056,326

 
$
2,960,808

Total equity
 
742,776

 
850,497

 
780,972

 
767,321

 
751,872

Long-term debt
 
683,184

 
679,334

 
569,445

 
613,095

 
671,643





26





ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural or the Company) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated results for the years ended December 31, 2017, 2016, and 2015. References in this discussion to "Notes" are to the Notes to Consolidated Financial Statements in Item 8 of this report.
 
The consolidated financial statements include NW Natural and its direct and indirect wholly-owned subsidiaries including:
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);
NW Natural Water Company, LLC (NWN Water); and
NWN Gas Reserves LLC (NWN Gas Reserves).
We operate in two primary 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 we aggregate and report 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 includes our NW Natural local gas distribution business, NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). 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 asset management services. Other includes NWN Energy's equity investment in Trail West Holding, LLC (TWH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Trail West Pipeline, LLC (TWP), NNG Financial's investment in Kelso-Beaver Pipeline (KB Pipeline), and NWN Water, which pursuing investments in the water sector itself and through its wholly-owned subsidiary FWC Merger Sub, Inc. For a further discussion of our business segments and other, see Note 4.

NON-GAAP FINANCIAL MEASURES. In addition to presenting the results of operations and earnings amounts in total, certain financial measures are expressed in cents per share or exclude the effects of certain items, which are non-GAAP financial measures. We present net income or loss and earnings or loss per share adjusted for certain items along with the U.S. GAAP measures to illustrate their magnitude on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income or loss and earnings or loss per share under U.S. GAAP, we believe the amount and nature these items make period to period comparisons of operations difficult or potentially confusing. We use such non-GAAP financial measures to analyze our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations. Our non-GAAP financial measures should not be considered a substitute for, or superior to, measures calculated in accordance with U.S. GAAP. Reconciliations of the non-GAAP financial measures to their closest U.S. GAAP measure used in subsequent sections of Item 7 are provided below.


27





NON-GAAP RECONCILIATIONS
 
2017
 
2016
 
2015
In millions, except per share data
 
Amount
Per Share
 
Amount
Per Share
 
Amount
Per Share
Consolidated net income (loss)
 
$
(55.6
)
$
(1.94
)
 
$
58.9

$
2.12

 
$
53.7

$
1.96

Adjustments:
 
 
 
 
 
 
 
 
 
Regulatory environmental disallowance(1)
 


 
3.3

0.12

 
15.0

0.55

Impairment of long-lived assets(2)
 
192.5

6.71

 


 


Tax effects on TCJA(3)
 
(21.4
)
(0.75
)
 


 


Tax effects on non-GAAP adjustments
 
(51.0
)
(1.78
)
 
(1.3
)
(0.05
)
 
(5.9
)
(0.22
)
Adjusted consolidated net income
 
$
64.5

$
2.24

 
$
60.9

$
2.19

 
$
62.8

$
2.29

 
 
 
 
 
 
 
 
 
 
Utility net income (loss)
 
$
60.5

$
2.11

 
$
54.6

$
1.96

 
$
53.4

$
1.95

Adjustments:
 
 
 
 
 
 
 
 
 
Regulatory environmental disallowance(1)
 


 
3.3

0.12

 
15.0

0.55

Tax effects on TCJA(3)
 
1.0

0.03

 


 


Tax effects on non-GAAP adjustments
 


 
(1.3
)
(0.05
)
 
(5.9
)
(0.22
)
Adjusted utility net income
 
$
61.5

$
2.14

 
$
56.6

$
2.03

 
$
62.5

$
2.28

 
 
 
 
 
 
 
 
 
 
Gas storage net income (loss)
 
$
(116.2
)
$
(4.05
)
 
$
4.3

$
0.16

 
$
0.2

$
0.01

Adjustments:
 
 
 
 
 
 
 
 
 
Impairment of long-lived assets(2)
 
192.5

6.71

 


 


Tax effects on TCJA(3)
 
(21.9
)
(0.76
)
 


 


Tax effects on non-GAAP adjustments
 
(51.0
)
(1.78
)
 


 


Adjusted gas storage net income
 
$
3.4

$
0.12

 
$
4.3

$
0.16

 
$
0.2

$
0.01

 
 
 
 
 
 
 
 
 
 
Other net income (loss)
 
$
0.1

$

 
$

$

 
$
0.1

$

Adjustments:
 
 
 
 
 
 
 
 
 
Tax effects on TCJA(3)
 
(0.6
)
(0.02
)
 


 


Adjusted other net income (loss)
 
$
(0.5
)
$
(0.02
)
 
$

$

 
$
0.1

$

(1) Regulatory environmental disallowance of $3.3 million in 2016 includes $2.8 million recorded in utility other income (expense), net and $0.5 million recorded in utility operations and maintenance expense. Regulatory environmental disallowance of $15.0 million in 2015 is recorded in utility operations and maintenance expense. The tax effect of both years' adjustments are calculated using a combined federal and state statutory rate of 39.5%. EPS amounts for the 2016 and 2015 adjustments are calculated using diluted shares of 27.8 million and 27.4 million, respectively, as shown on our Consolidated Statements of Comprehensive Income (Loss).
(2) Non-cash impairment of long-lived assets at the Gill Ranch Facility of $192.5 million was recorded on December 31, 2017. The tax effect of this adjustment is calculated using our new combined federal and state statutory tax rate of 26.5%. EPS amounts are calculated using diluted shares of 28.7 million as shown on our Consolidated Statements of Comprehensive Income (Loss). See Part II, Item 7, "Application of Critical Accounting Policies and Estimates—Impairment of Long-Lived Assets" for additional information on the impairment analysis.
(3) Non-cash Tax Cuts and Jobs Act (TCJA) benefit (expense) of $21.4 million was recorded in income tax expense (benefit) in the fourth quarter of 2017 as a result of the federal tax rate changing from 35% to 21% effective December 22, 2017. EPS amounts are calculated using diluted shares of 28.7 million as shown on our Consolidated Statements of Comprehensive Income (Loss), and the TCJA impacts in the segments and other may not correlate exactly to the consolidated amount due to rounding. See Note 9 for additional information on TCJA.



28





EXECUTIVE SUMMARY
We manage our business and strategic initiatives with a long-term view of providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2018 Outlook" below for more information. Highlights for the year include:
added over 12,700 customers in 2017 for a growth rate of 1.8% at December 31, 2017;
invested $214 million in our distribution system and facilities for growth and reliability;
completed key components of the North Mist Gas Storage Expansion Project with $107 million capital
 
expenditures incurred as of December 31, 2017, with an additional $20 to $30 million expected in 2018;
ranked first in the West in the 2017 J.D. Powers' Gas Utility Residential Customer Satisfaction Study and Gas Utility Business Customer Satisfaction Study;
filed for a general rate increase in Oregon for first time in six years;
delivered increasing dividends for the 62nd consecutive year; and
announced our intent to expand into the regulated water utility sector by entering into agreements to acquire two small privately owned water utilities.

Key financial highlights include:
 
 
2017
 
2016
 
2015
In millions, except per share data
 
Amount
Per Share
 
Amount
Per Share
 
Amount
Per Share
Consolidated net income (loss)
 
$
(55.6
)
$
(1.94
)
 
$
58.9

$
2.12

 
$
53.7

$
1.96

Adjusted consolidated net income(1)
 
$
64.5

$
2.24

 
$
60.9

$
2.19

 
$
62.8

$
2.29

Utility margin
 
$
392.6

 
 
$
376.6

 
 
$
371.4

 
Gas storage operating revenues
 
$
23.6

 
 
$
25.3

 
 
$
21.4

 
(1) See the Non-GAAP Reconciliations table at the beginning of Item 7 for a reconciliation of this non-GAAP measure to its closest U.S.GAAP measure.
                    
2017 COMPARED TO 2016. Consolidated net loss was $55.6 million compared to consolidated net income of $58.9 million in 2016, including $192.5 million pre-tax for the impairment of long-lived assets at the Gill Ranch Facility and the $21.4 million benefit associated with TCJA in 2017, and the $3.3 million pre-tax regulatory environmental disallowance in 2016.

Excluding these items, adjusted consolidated net income increased $3.6 million. See the Non-GAAP reconciliations at the beginning of Item 7 for additional information. Adjusted consolidated net income increased $3.6 million primarily due to the following factors:
a $16.0 million increase in utility margin primarily due to customer growth and effects of colder than average weather in 2017 compared to warmer than average weather in 2016; and
a $3.1 million increase in other income (expense), net primarily due an increase of the equity portion of AFUDC; partially offset by
a $15.7 million increase in operations and maintenance expense driven by higher utility payroll and benefits increases, as well as increased safety equipment upgrade costs; and
a $1.6 million decrease in gas storage revenues driven by lower revenues from our asset management agreements for our Mist storage and transportation capacity.
 
2016 COMPARED TO 2015. Overall, consolidated net income increased $5.2 million. The increase was primarily due to the $9.1 million after-tax charge from 2015 and a $2.0 million after-tax charge in 2016 related to the regulatory disallowances associated with a February 2015 OPUC Order and subsequent Order in our SRRM docket.

Excluding the impact of the non-cash charges from the SRRM docket in 2015 and 2016, adjusted consolidated net income decreased $1.9 million primarily due to the following factors:
a $7.0 million increase in operations and maintenance expense primarily due to cost savings initiatives that were implemented in the second half of 2015 that did not recur in 2016; and
a $5.5 million decrease in other income (expense), net primarily related to the recognition of $5.3 million of equity earnings on deferred regulatory asset balances as a result of the 2015 OPUC Order; partially offset by
a $5.2 million increase in utility margin primarily due to customer growth and gains from gas cost incentive sharing; and
a $3.9 million increase in gas storage revenues largely due to higher revenues from our asset management agreements at both storage facilities and slightly higher contract values at the Gill Ranch Facility for the 2016-17 gas year.


29





2018 OUTLOOK

Our 2018 goals leverage our resources and history of innovation to continue meeting the evolving needs of customers, regulators, and shareholders. Our near-term outlook is centered on following six long-term strategic objectives:
Deliver Gas
 
Grow Our Businesses
 
Ensure Safe and Reliable Service
 
 
Enable Utility Growth
 
Provide a Superior Customer Experience
 
 
Lead in a Low-Carbon Future
 
Advance Constructive Policies and Regulation
 
 
Pursue Strategic Investments

SAFETY AND RELIABILITY. Delivering natural gas safely and reliably to customers is our first priority. During 2018, we will maintain our vigilant focus on safety and emergency response through our hands-on scenario-based training for our employees, third-party contractors, and local authorities. To ensure reliability, resiliency, and safety of our infrastructure, we intend to continue to invest in the maintenance and necessary upgrades of our pipeline system, including multi-year projects to replace end-of-life equipment at our Mist storage facility and renovate several resource centers. Safety also includes our vigilance in maintaining strong cybersecurity defenses and preparing for large-scale emergency events, such as seismic hazards in our region.

SUPERIOR CUSTOMER EXPERIENCE. NW Natural has a legacy of providing excellent customer service and a long-standing dedication to continuous improvement, which have resulted in consistently high rankings in the J.D. Power and Associates customer satisfaction studies. In 2018, we will continue to enhance our customers' experience to meet their evolving expectations by prioritizing improvements to technology which supports our customers' frequent interactions and highest value touchpoints.

POLICIES AND REGULATION. We remain committed to working constructively with policymakers and regulators to provide the best outcomes for both our customers and shareholders. We are working closely with the Oregon commission and other stakeholders on several significant dockets, including the best way to return TCJA benefits to our customers and process our Oregon general rate case, which we filed in December 2017. The rate case supports the continued investment and maintenance of our system for safety, reliability and resiliency. Additionally, we plan to file an updated IRP in 2018 to support the long-term investments needed for the growth and continued reliability of our utility infrastructure. Finally, we will continue working with the EPA and other stakeholders on an environmentally protective and cost effective clean-up for the Portland Harbor Superfund Site.

 
UTILITY GROWTH. Natural gas is the preferred energy choice in our service territory given its efficient, affordable, and clean-burning qualities. We are focused on leveraging these key attributes to capitalize on our region's strong economic growth. We continue to grow our market share in the single-family residential sector and capture new commercial customers. We have also focused on expanding our share of mixed-use developments, a growing segment of the multifamily housing market, through equipment incentives, streamlined gas infrastructure designs, promotional support, and a recently approved new tariff. We will continue to pursue growth in all sectors in 2018.

LOW-CARBON PATHWAY. The Pacific Northwest and NW Natural are deeply committed to a clean energy future. It's why we launched our low-carbon initiative to further emission savings for both the Company and our communities by leveraging our modern pipeline systems in new ways, working closely with customers, policymakers and regulators, and embracing cutting-edge technology. We have partnered with the City of Portland to bring renewable natural gas (RNG) onto our system. We expect the entire project to be operational in 2019. We will continue helping our customers reduce and offset their consumption as we support the development of renewable natural gas supply and explore other cutting edge solutions to lower the carbon intensity of our product, such as power to gas.

STRATEGIC INVESTMENTS. We remain focused on creating value in all our businesses. We are investing in the regulated utility expansion of our Mist gas storage facility, which will provide innovative no-notice gas storage service for a local electric company who will use the reliability of natural gas to integrate more intermittent renewable energy like solar and wind into the energy grid. In 2017, we announced our intent to expand into the regulated water utility sector and will continue pursuing this strategy in 2018 with a focus on water sector investments that fit our conservative risk profile and core competencies. Our pursuit of a holding company structure is important to this growth strategy. With the OPUC and WUTC approvals for a holding company reorganization received, we will be focused on seeking shareholder approval for conversion to a holding company structure at our 2018 annual shareholders' meeting and executing on the conversions in late 2018 or early 2019.


30





HOLDING COMPANY
Formation of a Holding Company 
Holding company structures are well-established corporate structures, and exist across all industries. In the utility industry, holding companies have become the norm, and are employed for the same purposes holding companies are used in other industries. NW Natural intends to pursue formation of a holding company to best position it to be able to respond to opportunities and risks in a manner that serves the best interests of its shareholders and customers. We have received regulatory approval from the OPUC and WUTC and expect regulatory approval from the CPUC to reorganize into a holding company structure. Our Board of Directors has determined to recommend a holding company structure to our shareholders for vote at our 2018 Annual Shareholders Meeting. If our shareholders approve, the Board and Management must take additional actions to implement the holding company structure, which we currently expect to happen in the latter half of 2018 or at the beginning of 2019. To implement a holding company structure, NW Natural common stock would be converted or exchanged into the same relative percentages of the holding company that they own of NW Natural immediately prior to the reorganization. The structure currently contemplated involves placing a non-operating corporate entity over the existing consolidated structure, and “ring-fencing” NW Natural as described below to insulate the gas utility from the operations of the holding company and its other direct and indirect subsidiaries. NW Natural management continuously looks for growth opportunities that would build on core competencies and match the risk profile that NW Natural and its shareholders seek. We believe a holding company structure is a more agile and efficient platform from which to pursue, finance and oversee new business growth opportunities, such as in the water sector. Following the formation of the holding company, NW Natural would continue to operate as a gas utility subject to the jurisdiction of the OPUC and the WUTC.

Holding Company Regulatory Restrictions and Conditions
The regulatory approvals for the formation of a holding company require NW Natural and its holding company to enter into and file an agreement with the OPUC and the WUTC, which includes a number of “ring-fencing” conditions. The ring-fencing provisions are designed to operate the gas utility business conservatively and insulate it from risks associated with other holding company businesses. The ring-fencing and other provisions of the approvals include the following:
NW Natural may not pay dividends or make distributions to the holding company if NW Natural’s credit ratings and common equity levels fall below specified ratings and levels. If NW Natural’s long-term secured credit ratings are below A- for S&P and A3 for Moody’s, dividends may be issued so long as NW Natural’s common equity is 45% or above. If NW Natural’s long-term secured credit ratings are below BBB for S&P and Baa2 for Moody’s, dividends may be issued so long as NW Natural’s common equity is 46% or above. Dividends may not be issued if NW Natural’s long-term secured credit ratings fall to BB+ or below for S&P or Ba1 or below for Moody’s, or if NW Natural’s common equity is below 44%. In each case, with the
 
common equity level to be determined on a preceding or projected 13-month basis.
Maintenance of separate credit ratings, long-term debt ratings, and preferred stock ratings, if any, by NW Natural and its holding company;
In the event NW Natural’s common equity, on a preceding or projected basis, falls below 46%, NW Natural is required to notify the OPUC, and if the level of common equity falls below 44%, file a plan with the OPUC to restore its equity to that level. Under the WUTC order, the average equity component must not exceed 56%;
NW Natural must have one director who is independent from NW Natural management and from the holding company;
NW Natural and its subsidiaries will not be permitted to hold holding company investments, except under NW Natural-sponsored employee benefit plans or employee compensation plans;
NW Natural must issue one share of preferred stock to an independent party and require that NW Natural may only file a voluntary petition for bankruptcy if approved unanimously by the Board of Directors of NW Natural, including the independent director, and by the holder of the preferred share;
As is the case currently, NW Natural will be prohibited from cross-subsidizing any business, including the holding company and its unregulated subsidiaries;
The costs of the holding company reorganization must be separately tracked and not charged or allocated to NW Natural, and those costs and all other costs related to future business endeavors of the holding company must be excluded from NW Natural rate cases. NW Natural and its holding company are required to guarantee that NW Natural customers will not be harmed by any increases in NW Natural costs that result from the holding company reorganization, including any higher costs of debt or equity, higher revenue requirement, tax costs, or rate of return, due to the reorganization; and
For three years, NW Natural will be required to provide an annual $500,000 credit to Oregon customers and a $55,000 credit to Washington customers. Cost-savings over $50,000 that are allocable to NW Natural as a result of holding company acquisition activity will be deferred and credited to Oregon and Washington customers until after NW Natural’s next general rate case following the Company’s 2017 general rate case.

DIVIDENDS

Dividend highlights include:  
Per common share
 
2017
 
2016
 
2015
Dividends paid
 
$
1.8825

 
$
1.8725

 
$
1.8625


In January 2018, the Board of Directors declared a quarterly dividend on our common stock of $0.4725 per share, payable on February 15, 2018, to shareholders of record on January 31, 2018, reflecting an indicated annual dividend rate of $1.89 per share.



31





RESULTS OF OPERATIONS
Regulatory Matters

Regulation and Rates 
UTILITY. Our utility business is subject to regulation by the OPUC, WUTC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and WUTC also regulate the system of accounts and issuance of securities by our utility. In 2017, approximately 89% of our utility gas customers were located in Oregon, with the remaining 11% in Washington. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other proceedings in Oregon and Washington. They are also affected by the local economies in Oregon and Washington, the pace of customer growth in the residential, commercial, and industrial markets, and our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs in utility plant and other regulatory assets. See "Most Recent General Rate Cases" below.

GAS STORAGE. Our gas storage business is subject to regulation by the OPUC, WUTC, CPUC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities, system of accounts, and regulate intrastate storage services. The FERC regulates interstate storage services. The FERC uses a maximum cost of service model which allows for gas storage prices to be set at or below the cost of service as approved by each agency in their last regulatory filing. The OPUC Schedule 80 rates are tied to the FERC rates, and are updated whenever we modify our FERC maximum rates. The CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. In 2017, approximately 70% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 30% from California operations.

Most Recent General Rate Cases  
OREGON. Effective November 1, 2012, the OPUC authorized rates to customers based on an ROE of 9.5%, an overall rate of return of 7.78%, and a capital structure of 50% common equity and 50% long-term debt.

WASHINGTON. Effective January 1, 2009, the WUTC authorized rates to customers based on an ROE of 10.1% and an overall rate of return of 8.4% with a capital structure of 51% common equity, 5% short-term debt, and 44% long-term debt.

FERC. We are required under our Mist interstate storage certificate authority and rate approval orders to file every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for our interstate storage services. In December 2013, we filed a rate petition, which was approved in 2014, and allows for the maximum cost-based rates for our interstate gas storage services. These rates were effective January 1, 2014, with the rate changes having no significant impact on our revenues. In January 2018, various state parties filed a request with the FERC to adjust the revenue requirements
 
of public utilities to reflect the recent reduction in the federal corporate income tax rate and other impacts resulting from the TCJA. We will monitor this request and work the FERC to evaluate the potential impact to these approved rates.

We continuously monitor the utility and evaluate the need for a rate case. In December 2017, we filed a rate case in Oregon with the OPUC. For additional information, see "Regulatory Proceeding Updates—Rate Case" below.

Regulatory Proceeding Updates
During 2017, we were involved in the regulatory activities discussed below.

HEDGING. In 2014, the OPUC opened a docket to discuss broader gas hedging practices across gas utilities in Oregon. In January 2018, the OPUC accepted the parties' proposal to follow a uniform process to address any future proposed long-term hedges and closed the docket.

The WUTC also conducted an investigation into the hedging practices of gas utilities operating in Washington and considered whether it should require gas utilities to implement certain hedging practices. The WUTC issued and outlined their policy in March 2017. The policy supports risk-responsive hedging strategies that are adaptable to variability in the market and required gas utilities to submit with their 2017 PGA a preliminary hedging plan that outlines the utilities' intended path to incorporate risk-responsive hedging strategies. Beginning with the 2018 PGA, gas utilities must submit an annual comprehensive hedging plan that supports integration of risk responsive strategies into their hedging framework. Beginning with the 2019 PGA filing, utilities must provide a full strategy implementation plan for year 2020 and beyond. As directed by the WUTC, we submitted our preliminary hedging plan with our 2017 PGA in September 2017, and plan to submit our annual comprehensive hedging plan with our 2018 PGA.

INTERSTATE STORAGE AND OPTIMIZATION SHARING. We received an Order from the OPUC in March 2015 on their review of the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. The Order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket. In 2017, a third-party consultant completed a cost study. We will continue to work with all stakeholders as we review this completed study, and expect resolution of this docket in 2018.

INTEGRATED RESOURCE PLAN (IRP). We file a full IRP with Oregon and Washington bi-annually and file updates between filings. Our last full IRPs were filed in 2016, and we received a letter of compliance from the WUTC in December of 2016 and acknowledgment by the OPUC in February of 2017. The IRP included analysis of different growth scenarios and corresponding resource acquisition strategies. The analysis is needed to develop supply and demand resource requirements, consider uncertainties in the planning process, and establish a plan for providing reliable and low cost natural gas service. We anticipate filing our next full IRP in 2018.



32





DEPRECIATION STUDY. Under OPUC regulations, the utility is required to file a depreciation study every five years to update or justify maintaining the existing depreciation rates. In December 2016, we filed the required depreciation study with the Commission. In September 2017, the parties to the docket filed a settlement with the Commission requesting approval of updated depreciation rates negotiated with the parties. In January 2018, OPUC issued an order adopting the stipulation. The depreciation rates included in the stipulation do not materially change our current depreciation rates.

HOLDING COMPANY APPLICATION. In February 2017, we filed applications with the OPUC, WUTC, and CPUC for approval to reorganize under a holding company structure. In 2017, the OPUC and WUTC approved our applications subject to certain restrictions or "ring-fencing" provisions applicable to NW Natural, the entity that currently, and would continue to, house our utility operations, and the holding company. We continue to work with the CPUC, and expect resolutions by the end of the first quarter of 2018.

MULTI-FAMILY TARIFF. In June 2017, we filed a request with the OPUC to create a multi-family tariff to establish an optional program to serve the mixed-use, multi-family residential market. Under the tariff, NW Natural will provide upfront incentives for builders to offset the initial cost of installing natural gas piping to individual units, and then recover the costs of the incentives through a fixed charge on the customer's monthly bills. In July 2017, the OPUC approved the tariff allowing us to further serve the multi-family customer sector.

TAX REFORM DEFERRAL. In December 2017, we filed applications with the OPUC and WUTC to defer the overall net benefit associated with the TCJA that was enacted on December 22, 2017 with a January 1, 2018 effective date. We anticipate the impacts from the TCJA will accrue to our customers in a manner approved by the Commissions. We will continue to work with the OPUC and WUTC on this throughout 2018. See Note 9 for more information on TCJA.

REGULATED WATER UTILITY. In December 2017, we entered into agreements to acquire two privately-owned water utilities: Salmon Valley Water Company, based in Welches, Oregon, and Falls Water Company, based in Idaho Falls, Idaho. These transactions are subject to certain conditions, including approvals from the OPUC and the Idaho Public Utilities Commission (IPUC), respectively. In January 2018, we filed our application with the OPUC to acquire Salmon Valley Water Company and filed with the IPUC in February 2018 to acquire Falls Water Company. We do not expect these transactions or their continuing operations to have a material financial impact. We continue to work with the OPUC and IPUC and anticipate receiving approvals and completing these acquisitions in 2018.

GENERAL RATE CASE. On December 29, 2017, we filed an Oregon general rate case requesting a 6% revenue increase, after an adjustment for the conservation tariff deferral, to continue operating and maintaining our distribution system and continue providing safe, reliable service to our customers. Our December general rate case filing was based on the following:
 
forward test year from November 1, 2018 through October 31, 2019;
capital structure of 50% debt and 50% equity;
return on equity of 10.0%;
cost of capital of 7.62%; and
rate base of $1.19 billion, an increase of $304 million since the last Oregon rate case in 2012.

The general rate case filing in December 2017 does not include the benefit to customers’ rates of the newly passed federal tax legislation. In the coming months, we will be working with the OPUC to determine how to return these benefits to customers, and we expect to amend or refile our rate case to incorporate the benefit of the TCJA, which would likely lower the original revenue requirement requested. It is possible through this rate case proceeding or another proceeding that the OPUC will also determine how to treat historical deferred tax liabilities, which may result in additional changes to our rate case request as well. The general rate case review and approval process could take up to 10 months with new rates anticipated to be effective November 1, 2018.

Rate Mechanisms
During 2017, our approved rates and recovery mechanisms for each service area included:
 
Oregon
Washington
Authorized Rate Structure:
 
 
ROE
9.5%
10.1%
ROR
7.8%
8.4%
Debt/Equity Ratio
50%/50%
49%/51%
 
 
 
Key Regulatory Mechanisms:
 
 
PGA
X
X
Gas Cost Incentive Sharing
X
 
Decoupling
X
 
WARM
X
 
Environmental Cost Deferral
X
X
SRRM
X
 
Pension Balancing
X
 
Interstate Storage Sharing
X
X

PURCHASED GAS ADJUSTMENT. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas costs under spot purchases as well as contract supplies, gas costs hedged with financial derivatives, gas costs from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

In September 2017, we filed our PGA and received OPUC and WUTC approval in October 2017. PGA rate changes were effective November 1, 2017. The rate changes decreased the average monthly bills of residential customers by approximately 6.4% and 3.1% in Oregon and Washington, respectively. The decrease in Oregon reflected


33





customers' portion of adjustments mainly for the effect of changes in wholesale natural gas costs and for a portion of WARM amounts that exceeded the maximum monthly allowable amount to be returned to customers during the 2016-17 gas year. Oregon rates were offset by adjustments related to our energy efficiency programs and additional annual adjustments based on ongoing orders with the OPUC. Washington rates reflected the effect of changes in wholesale natural gas costs.

Each year, we typically hedge gas prices on a portion of our utility's annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2017-18 gas year with our forecasted sales volumes hedged at 49% in financial swap and option contracts and 26% in physical gas supplies. For additional hedging matters from the WUTC and OPUC, see "Regulatory Proceeding Updates—Hedging" above.

As of December 31, 2017, we have also hedged future gas years with approximately 24% for the 2018-19 gas year and between 4% and 11% over the subsequent five gas years for utility's annual sales requirements based on normal weather. Our hedge levels are subject to change based on actual load volumes, which depend, to a certain extent, on weather, economic conditions, and estimated gas reserve production. Also, our gas storage inventory levels may increase or decrease with storage expansion, changes in storage contracts with third parties, variations in the heat content of the gas, and/or storage recall by the utility.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year an 80% deferral or a 90% deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20% or 10% of the difference between actual and estimated gas costs, respectively. For the 2016-17 and 2017-18 gas years, we selected the 90% deferral option. Under the Washington PGA mechanism, we defer 100% of the higher or lower actual gas costs, and those gas cost differences are passed on to customers through the annual PGA rate adjustment.

EARNINGS TEST REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE threshold. If utility earnings exceed a specific ROE level, then 33% of the amount above that level is required to be deferred or refunded to customers. Under this provision, if we select the 80% deferral gas cost option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. For the 2015-16 gas year, we selected the 80% deferral option. For the 2016-17 and 2017-18 gas years, we selected the 90% deferral option. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2015, 2016, and 2017, the ROE threshold was 10.60%, 11.06%, and 10.66%, respectively. There were no refunds required for 2015 and 2016. We do not expect a refund for 2017 based on our results and anticipate filing the 2017 earnings test in May 2018.

 
GAS RESERVES. In 2011, the OPUC approved the Encana gas reserves transaction to provide long-term gas price protection for our utility customers and determined our costs under the agreement would be recovered on an ongoing basis through our annual PGA mechanism. Gas produced from our interests is sold at then prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are included in our cost of gas. The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return.

In 2014, we amended the original gas reserves agreement in response to Encana's sale of its interest in the Jonah field located in Wyoming to Jonah Energy. Under our amended agreement with Jonah Energy, we 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. Volumes produced from the additional wells drilled after our amended agreement are included in our Oregon PGA at a fixed rate of $0.4725. We did not have the opportunity to participate in additional wells in 2015, 2016, or 2017.

DECOUPLING. In Oregon, we have a decoupling mechanism. Decoupling is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy.
The Oregon decoupling mechanism was reauthorized and the baseline expected usage per customer was set in the 2012 Oregon general rate case. This mechanism employs a use-per-customer decoupling calculation, which adjusts margin revenues to account for the difference between actual and expected customer volumes. The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the annual PGA filing. In Washington, customer use is not covered by such a tariff.

WARM. In Oregon, we have an approved weather normalization mechanism, which is applied to residential and commercial customer bills. This mechanism is designed to help stabilize the collection of fixed costs by adjusting residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average. The mechanism is applied to bills from December through May of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers. The collections of any unbilled WARM amounts due to tariff caps and floors are deferred and earn a carrying charge until collected in the PGA the following year. This weather normalization mechanism was reauthorized in the


34





2012 Oregon general rate case without an expiration date. Residential and commercial customers in Oregon are allowed to opt out of the weather normalization mechanism, and as of December 31, 2017, 9% of total customers had opted out. We do not have a weather normalization mechanism approved for residential and commercial Washington customers, which account for about 11% of total customers. See "Business Segments—Local Gas Distribution Utility Operations" below.
 
INDUSTRIAL TARIFFS. The OPUC and WUTC have approved tariffs covering utility service to our major industrial customers, which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group. The approved terms include, among other things, an annual election period, special pricing provisions for out-of-cycle changes, and a requirement that industrial customers complete the term of their service election under our annual PGA tariff.
  
ENVIRONMENTAL COST DEFERRAL AND SRRM. We have a 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.

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. We anticipate 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. We included $7.4 million and $10.0 million of deferred remediation expense approved by the OPUC for collection during the 2017-18 and 2016-17 PGA years, respectively.

In addition, the SRRM 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 our Consolidated Statement of Comprehensive Income (Loss). See Note 15 for more information on our environmental matters.

 
The SRRM earnings test is an annual review of our adjusted utility ROE compared to our authorized utility ROE, which is currently 9.5%. To apply the earnings test first we must determine what if any costs are subject to the test through the following calculation:
Annual spend
Less: $5.0 million base rate rider(1)
          Prior year carry-over(2)
          $5.0 million insurance + interest on insurance
Total deferred annual spend subject to earnings test
Less: over-earnings adjustment, if any
Add: deferred interest on annual spend(3)
Total amount transferred to post-review
(1)  
Base rate rider went into Oregon customer rates beginning
November 1, 2015.
(2)
Prior year carry-over results when the prior year amount transferred to post-review is negative. The negative amount is carried over to offset annual spend in the following year.
(3)
Deferred interest is added to annual spend to the extent the spend is recoverable.

To the extent the utility earns at or below its authorized ROE, the total amount transferred to post-review is recoverable through the SRRM. To the extent the utility earns more than its authorized ROE in a year, the amount transferred to post-review would be reduced by those earnings that exceed its authorized ROE.
 
For 2017, we have performed this test, which we anticipate submitting to the OPUC in May 2018, and we do not expect an earnings test adjustment for 2017.

The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This Order was effective in January 2011 with cost recovery and carrying charges on amount deferred for costs associated with services provided to Washington customers to be determined in a future proceeding. Annually, or more often if circumstances warrant, we review all regulatory assets for recoverability. If we should determine all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances against earnings in the period such a determination was made.
 
PENSION COST DEFERRAL AND PENSION BALANCING ACCOUNT. The OPUC permits us to defer annual pension expenses above the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years. Our recovery of these deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities based on a number of key assumptions and our pension contributions. Pension expense deferrals, excluding interest, were $6.5 million, $6.3 million, and $8.2 million in 2017, 2016 and 2015, respectively.



35





INTERSTATE STORAGE AND OPTIMIZATION SHARING. On an annual basis, we credit amounts to Oregon and Washington customers as part of our regulatory incentive sharing mechanism related to net revenues earned from Mist gas storage and asset management activities. Generally, amounts are credited to Oregon customers in June, while credits are given to customers in Washington through reductions in rates through the annual PGA filing in November.
The following table presents the credits to customers:
In millions
 
2017
 
2016
 
2015
Oregon utility
customer credit
 
$
11.7

 
$
9.4

 
$
9.6

Washington utility customer credit
 
1.0

 
1.0

 
0.8


Business Segments - Local Gas Distribution Utility Operations
Utility margin results are primarily affected by customer growth, revenues from rate-base additions, and, to a certain extent, by changes in delivered volumes due to weather and customers’ gas usage patterns because a significant portion of our utility margin is derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff (also called the decoupling mechanism), which adjusts utility margin up or down each month through a deferred regulatory accounting adjustment designed to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, WARM, which adjusts customer bills up or down to offset changes in utility margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce, but not eliminate, the volatility of customer bills and our utility’s earnings. See "Regulatory Matters—Rate Mechanisms" above.

Utility segment highlights include:  
Dollars and therms in millions, except EPS data
 
2017
 
2016
 
2015
Utility net income
 
$
60.5

 
$
54.6

 
$
53.4

Adjusted utility net income(1)
 
61.5

 
56.6

 
62.5

EPS - utility segment
 
2.11

 
1.96

 
1.95

Adjusted EPS - utility segment(1)
 
2.14

 
2.03

 
2.28

Gas sold and delivered (in therms)
 
1,240

 
1,085

 
1,029

Utility margin(2)
 
$
392.6


$
376.6

 
$
371.4

(1) See the Non-GAAP Reconciliations table at the beginning of Item 7 for a reconciliation of this non-GAAP measure to its closest U.S.GAAP measure.
(2) See Utility Margin Table below for a reconciliation and additional detail.

2017 COMPARED TO 2016. Utility net income was $60.5 million in 2017 compared to $54.6 million in 2016, which includes the $1.0 million loss associated with the TCJA in 2017 and the after-tax $2.0 million regulatory environmental disallowance in 2016. See the Non-GAAP reconciliations at the beginning of Item 7 for additional information.
 

Excluding these items, adjusted utility net income increased $5.0 million, or $0.11 per share. The primary factors contributing to this increase in adjusted utility net income were as follows:
a $16.0 million increase in utility margin primarily due to:
a $6.8 million increase from customer growth; partially offset by
a $2.7 million decrease in gains in gas cost incentive sharing due to actual gas prices being lower than those estimated in the 2016-17 PGA, but not by the same magnitude as in the prior period.
a portion of the remaining increase was due to the effects of colder than average weather in 2017 compared to warmer than average weather in 2016.
a $3.1 million increase in other income (expense), net, primarily due to an increase in the equity portion of AFUDC in 2017; partially offset by
a $9.5 million increase in operations and maintenance expense driven largely from payroll and benefits due to increased headcount, general salary increases, and increased safety equipment update costs; and
a $3.4 million increase in depreciation expense primarily due to additional capital expenditures.

Total utility volumes sold and delivered in 2017 increased 14% over 2016 primarily due to the impact of weather that was 28% colder than the prior period and 7% colder than average.

2016 COMPARED TO 2015. The primary factors contributing to the $1.2 million, or $0.01 per share, increase in utility net income were as follows:
a $5.2 million increase in utility margin primarily due to:
a $5.7 million increase from customer growth;
a $0.8 million increase from gains in gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; partially offset by
a $1.3 million decrease due to lower contributions from our gas reserve investments, which decreased due to amortization.
an $8.3 million decrease in operations and maintenance expense primarily due to the environmental disallowance recognized in 2015, offset in part by increases in payroll costs due to additional headcount and general pay increases along with increased non-payroll costs for professional services and contract work; partially offset by
an $8.7 million, decrease in other income (expense), net, primarily due to the environmental interest disallowance recognized in 2016 and the recognition of $5.3 million of equity earnings on deferred regulatory asset balances in 2015; and
a $1.9 million, increase in depreciation expense primarily due to additional capital expenditures.

Total utility volumes sold and delivered in 2016 increased 5% over 2015 primarily due to comparatively colder weather in the first quarter during our peak heating season and colder weather in December 2016. 


36





UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales:
 
 
 
 
 
 
Favorable/(Unfavorable)
In thousands, except degree day and customer data
 
2017
 
2016
 
2015
 
2017 vs. 2016
 
2016 vs. 2015
Utility volumes (therms):
 
 
 
 
 
 
 
 
 
 
Residential and commercial sales
 
740,369

 
609,222

 
570,728

 
131,147

 
38,494

Industrial sales and transportation
 
499,924

 
475,774

 
457,884

 
24,150

 
17,890

Total utility volumes sold and delivered
 
1,240,293

 
1,084,996

 
1,028,612

 
155,297

 
56,384

Utility operating revenues:
 
 
 
 
 
 
 
 
 
 
Residential and commercial sales
 
$
684,214

 
$
604,390

 
$
644,835

 
$
79,824

 
$
(40,445
)
Industrial sales and transportation
 
63,925

 
59,386

 
71,495

 
4,539

 
(12,109
)
Other revenues
 
3,872

 
3,812

 
3,914

 
60

 
(102
)
Less: Revenue taxes
 
19,069

 
17,111

 
18,034

 
1,958

 
(923
)
Total utility operating revenues
 
732,942

 
650,477

 
702,210

 
82,465

 
(51,733
)
Less: Cost of gas
 
325,019

 
260,588

 
327,305

 
(64,431
)
 
66,717

Less: Environmental remediation expense
 
15,291

 
13,298

 
3,513

 
(1,993
)
 
(9,785
)
Utility margin
 
$
392,632

 
$
376,591

 
$
371,392

 
$
16,041

 
$
5,199

Utility margin:(1)
 
 
 
 
 
 
 
 
 
 
Residential and commercial sales
 
$
355,736

 
$
338,060

 
$
334,134

 
$
17,676

 
$
3,926

Industrial sales and transportation
 
31,847

 
30,989

 
30,081

 
858

 
908

Miscellaneous revenues
 
3,865

 
3,796

 
3,913

 
69

 
(117
)
Gain from gas cost incentive sharing
 
1,237

 
3,960

 
3,182

 
(2,723
)
 
778

Other margin adjustments
 
(53
)
 
(214
)
 
82

 
161

 
(296
)
Utility margin
 
$
392,632

 
$
376,591

 
$
371,392

 
$
16,041

 
$
5,199

Degree days
 
 
 
 
 
 
 
 
 
 
Average(2)
 
4,240

 
4,256

 
4,240

 
(16
)
 
16

Actual
 
4,553

 
3,551

 
3,458

 
28
%

3
%
Percent colder (warmer) than average weather(2)
 
7
%
 
(17
)%
 
(18
)%
 
 
 
 
Customers - end of period:
 
 
 
 
 
 
 
 
 
 
Residential customers
 
668,803

 
656,855

 
646,841

 
11,948

 
10,014

Commercial customers
 
68,050

 
67,278

 
66,584

 
772

 
694

Industrial customers
 
1,021

 
1,013

 
1,003

 
8

 
10

Total number of customers
 
737,874

 
725,146

 
714,428

 
12,728

 
10,718

Customer growth:
 


 


 
 
 
 
 
 
Residential customers
 
1.8
%
 
1.5
 %
 
 
 
 
 
 
Commercial customers
 
1.1
%
 
1.0
 %
 
 
 
 
 
 
Industrial customers
 
0.8
%
 
1.0
 %
 
 
 
 
 
 
Total customer growth
 
1.8
%
 
1.5
 %
 
 
 
 
 
 
(1) 
Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas and environmental remediation expense.
(2) 
Average weather represents the 25-year average of heating degree days, as determined in our 2012 Oregon general rate case.




37





Residential and Commercial Sales
The primary factors that impact results of operations in the residential and commercial markets are customer growth, seasonal weather patterns, energy prices, competition from other energy sources, and economic conditions in our service areas. The impact of weather on margin is significantly reduced through our weather normalization mechanism in Oregon; approximately 80% of our total customers are covered under this mechanism. The remaining customers either opt out of the mechanism or are located in Washington, which does not have a similar mechanism in place. For more information on our weather mechanism, see "Regulatory Matters—Rate Mechanisms—Weather Normalization Mechanism" above.

Residential and commercial sales highlights include:
In millions
 
2017
 
2016
 
2015
Volumes (therms):
 
 
 
 
 
 
Residential sales
 
465.2

 
379.2

 
350.9

Commercial sales
 
275.2

 
230.0

 
219.8

Total volumes
 
740.4

 
609.2

 
570.7

Operating revenues:
 
 
 
 
 
 
Residential sales
 
$
455.9

 
$
404.3

 
$
424.6