NORTHWEST NATURAL GAS CO - FORM 10-K

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EXCEL - IDEA: XBRL DOCUMENT - NORTHWEST NATURAL GAS CO	Financial_Report.xls
EX-21 - EXHIBIT 21 SUBSIDIARIES OF NW NATURAL GAS COMPANY - NORTHWEST NATURAL GAS CO	ex212014.htm
EX-4.N - EXHIBIT 4.N FIRST AMENDMENT TO CREDIT AGREEMENT - NORTHWEST NATURAL GAS CO	ex4n2014.htm
EX-23 - EXHIBIT 23 CONSENT OF AUDITORS - NORTHWEST NATURAL GAS CO	ex232014.htm
EX-10.W - EXHIBIT 10.W LTIP AWARD AGREEMENT 2015-2017 - NORTHWEST NATURAL GAS CO	ex102014.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex3122014.htm
EX-32.1 - EXHIBIT 32.1 SOX CERTIFICATION - NORTHWEST NATURAL GAS CO	ex3212014.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex3112014.htm
EX-4.M - EXHIBIT 4.M FORM OF LETTER AGREEMENT - NORTHWEST NATURAL GAS CO	ex4m2014.htm
EX-12 - EXHIBIT 12 RATIO OF EARNINGS TO FIXED CHARGES - NORTHWEST NATURAL GAS CO	ex122014.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, 2014

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

For the transition period from ___________ to____________

Commission file number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)



Oregon	93-0256722
(State or other jurisdiction of	(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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer [ X ] Accelerated Filer [ ]

Non-accelerated Filer [ ] Smaller Reporting Company [ ]

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, 2014, the registrant had 27,171,581 shares of its Common Stock outstanding, of which 26,805,283 shares were held by non-affiliates. 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 $1,263,869,093.

At February 20, 2015, 27,304,169 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 2015 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, 2014

TABLE OF CONTENTS



PART I				Page
	Glossary of Terms			1
	Forward-Looking Statements			4
Item 1.	Business			5
		Overview		5
		Business Model		5
			Local Gas Distribution	5
			Gas Storage	10
			Other	12
		Environmental Issues		12
		Employees		13
		Additions to Infrastructure		13
		Executive Officers of the Registrant		13
		Available Information		13
Item 1A.	Risk Factors			14
Item 1B.	Unresolved Staff Comments			21
Item 2.	Properties			21
Item 3.	Legal Proceedings			21
Item 4.	Mine Safety Disclosures			21

PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
		Purchases of Equity Securities		22
Item 6.	Selected Financial Data			23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk			47
Item 8.	Financial Statements and Supplementary Data			49
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			86
Item 9A.	Controls and Procedures			86
Item 9B.	Other Information			86

PART III
Item 10.	Directors, Executive Officers and Corporate Governance			87
Item 11.	Executive Compensation			88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			88
Item 13.	Certain Relationships and Related Transactions, and Director Independence			89
Item 14.	Principal Accountant Fees and Services			89

PART IV
Item 15.	Exhibits and Financial Statement Schedules			90
SIGNATURES				91

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GLOSSARY OF TERMS AND ABBREVIATIONS



AFUDC		Allowance for Funds Used During Construction
AM Best		A.M. Best Co. is a global independent credit rating agency
AOCI / AOCL		Accumulated Other Comprehensive Income (Loss)
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
ASU		Accounting Standards Update as issued by the FASB
Average Weather		The 25-year average 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.
Btu		British thermal unit, a basic unit of thermal energy measurement. One Btu equals the energy required to raise one pound of water one degree Fahrenheit at an atmospheric pressure of one and 60 degrees Fahrenheit. One hundred thousand Btus equal one therm.
CAP		Compliance Assurance Process with the Internal Revenue Service
CNG		Compressed Natural Gas
CO₂		Carbon Dioxide
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 break the link between utility earnings and the quantity of natural gas sold to customers. The design is intended 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.
Dth		Dekatherm (also decatherm) is equal to 10 therms or one million British thermal units (Btu).
EBITDA		Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement.
EE/CA		Engineering Evaluation / Cost Analysis
Encana		Encana Oil & Gas 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.
FMB		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

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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
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
IRS		United States Internal Revenue Service
KB		Kelso-Beaver Pipeline, of which 10% is owned by K-B Pipeline Company, a subsidiary of NNG Financial
LIBOR		London Interbank Offered Rate
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.
LWG		Lower Willamette Group
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. is a credit rating agency.
NAV		Net Asset Value
NNG Financial		NNG Financial Corporation, a wholly-owned subsidiary of NW Natural
NOL		Net Operating Loss
NWN Energy		NW Natural Energy, LLC, a wholly-owned subsidiary of NW Natural
NWN Gas Reserves		NW Natural 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
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 is a 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
PHMSA		U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration
RI/FS		Portland Harbor Remedial Investigation / Feasibility Study
ROE		Return on Equity. A measure of corporate profitability, calculated as net income 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
S&P		Standard & Poor's, a division of The McGraw-Hill Companies, Inc., is a credit rating agency.
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

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SIP		System Integrity Program. An Oregon billing rate mechanism that provides cost recovery of pipeline system integrity programs, which are required under various safety standards prescribed by both state and federal regulators.
SRRM		Site Remediation and Recovery Mechanism. An Oregon billing rate mechanism for recovering prudently incurred environmental site remediation costs through customer billings, subject to an earnings test.
TAIL		TransCanada American Investments, Ltd., a 50% owner of TWH
Therm		The basic unit of natural gas measurement, equal to one hundred thousand Btu’s.
TWH		Trail West Holdings, LLC (formerly Palomar Gas Holdings, LLC), which is 50% owned by NWN Energy
TWP		Trail West Pipeline, LLC, a subsidiary of TWH (formerly Palomar Gas Transmissions, LLC)
TransCanada		TransCanada Pipelines Limited, owner of TAIL and GTN
Transportation Service		Service provided whereby a customer purchases natural gas commodity 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 and franchise tax.
VIE		Variable Interest Entity
Weather Normalization		An Oregon billing rate mechanism applied to residential and commercial customers to adjust for temperature variances from average weather. Rates decrease when the weather is colder than average, and rates increase when the weather is warmer than average. The mechanism is applied to customer bills from December through May of each heating season.
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.

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FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as anticipates, 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;


•	objectives;


•	goals;


•	strategies;


•	assumptions and estimates;


•	future events or performance;


•	trends;


•	risks;


•	timing and cyclicality;


•	earnings and dividends;


•	capital structure;


•	growth;


•	customer rates;


•	commodity costs;


•	gas reserves;


•	operational performance and costs;


•	energy policy and preferences;


•	efficacy of derivatives and hedges;


•	liquidity and financial positions;


•	project and program development, expansion, or investment;


•	competition;


•	procurement and development of gas supplies;


•	estimated expenditures;


•	costs of compliance;


•	credit exposures;


•	potential efficiencies;


•	rate or regulatory recovery or refunds;


•	impacts of laws, rules and regulations;


•	tax liabilities or refunds;


•	levels and pricing of gas storage contracts;


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


•	projected obligations under retirement plans;


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


•	approval and adequacy of regulatory deferrals;


•	effects 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.

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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. However, 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 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 that we aggregate and report as other.

The utility business is our largest segment, while our gas storage businesses account for the majority of our remaining net income. The following table reflects the percentage allocation between segments and other as of December 31, 2014:



			Non-Utility⁽¹⁾
	Utility		Gas Storage⁽²⁾		Other		Total
Assets	90.5	%	9.0	%	0.5	%	100.0	%
Net Income	99.8	%	(0.6	)%	0.8	%	100.0	%


⁽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⁾	Gas Storage segment includes asset management services for both the utility and non-utility portion of our Mist gas storage facility.

LOCAL GAS DISTRIBUTION "UTILITY"

The utility is principally engaged in the regulated distribution of natural gas in Oregon and southwest Washington to over 700,000 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 3.5 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 in the retail, manufacturing, and high-technology industries are located in our service territory.

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 around 60% of our utility’s total volumes delivered and 90% of our utility’s margin. Industrial customers largely account for the remaining volumes and utility margin. The following table presents summary customer information as of December 31, 2014:



	Number of Customers	% of Volumes		% of Utility Margin ⁽¹⁾
Residential	637,411	35	%	64	%
Commercial	66,304	22	%	28	%
Industrial	929	43	%	8	%
Total	704,644	100	%	100	%


⁽¹⁾	Utility margin is also derived from other items, including miscellaneous services, gains or losses from our incentive gas cost 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 is in less than 60% of residential single-family dwellings in our service territory. Therefore, growth in the region comes from both new single and multi-family housing construction and existing homes converting to natural gas. Prior to the most recent recession, our customer growth rate averaged over 3% for many years. From 2009 to 2012, growth dipped below 1%, but in 2013 and 2014, the 12-month growth rate

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increased to 1.3% and 1.4%, respectively. Natural gas is a preferred energy resource in our service territory, as it is a low-cost, reliable, clean energy choice, and as such, we believe there is potential for continued growth. See Note 4 for information on the utility's assets and results of operations.

Competitive Conditions

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

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

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 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.

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. We filed a rate petition in 2013

and received approval in 2014 for new maximum cost-based rates effective January 1, 2014.

The utility's most recent general rate case in Oregon was effective November 1, 2012, and the latest Washington rate case was effective January 1, 2009. Our current approved rates and recovery mechanisms for each service area include:



	Oregon	Washington⁽¹⁾
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
Incentive Sharing	X
Weather Normalization Tariff	X
Decoupling	X
SIP	X
Pension Balancing	X
Environmental Cost Deferral	X	X
SRRM	X

⁽¹⁾Although we do not have the same specific regulatory mechanisms in Washington, we do have approved regulatory deferral orders that allow us to defer certain costs for future recovery through the PGA or future general rate cases, such as our environmental cost deferral order.

In general, these rates and regulatory mechanisms do not allow the utility to earn a profit or incur a loss on our gas commodity purchases. This means gas commodity purchase costs are primarily a pass-through cost in customer rates, with the exception of our original gas reserves investment and incentive cost sharing mechanism in Oregon. Under this mechanism, we can either increase or decrease margin revenues based on higher or lower actual gas purchase costs compared to gas purchase costs embedded in the PGA. Except for as described below, we can earn an authorized return on the equivalent rate base investment on our gas reserves.

For a complete discussion of regulatory matters, open dockets, current regulatory activities, and additional details on each rate mechanism, see Part II, Item 7, "Results of Operations—Regulatory Matters" and "Gas Storage" below.

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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:


•	Diverse Supply - providing diversity of supply sources;


•	Diverse Contracts - maintaining a variety of contract durations and types; and


•	Cost Management - employing prudent gas cost management strategies.

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 optimize price differentials. For 2014, 66% 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 off-peak months during 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)	Capacity (Bcf)
Gas Storage Facilities:
Owned Facility:
Mist, Oregon⁽¹⁾	2.7	10.0
Contracted Facilities:
Jackson Prairie, Washington⁽²⁾	0.5	1.1
Alberta, Canada⁽³⁾	0.5	4.0
LNG Facilities:
Owned Facilities:
Newport, Oregon	0.6	0.9
Portland, Oregon	1.2	0.6
Total	5.5	16.6


⁽¹⁾	The Mist gas storage facility has a total maximum daily deliverability of 5.2 million therms and a total working gas capacity of about 16 Bcf, of which 2.7 million therms of daily deliverability and 10 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. A portion of the related pipeline transportation service from this facility is subject to curtailment and considered secondary firm capacity. As a result, NW Natural is evaluating the reliability of the capacity as part of the IRP process.

⁽³⁾ This resource does not add to our total peak day capacity, but helps to manage 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 May 2015, the utility plans to recall 0.3 million therms per day of deliverability and 0.7 Bcf of 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.

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 plus 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.

During 2014, we purchased a total of 761 million therms under contracts with durations outlined in the chart below:



Contract Duration (primary term)	Percent of Purchases
Long-term (one year or longer)	30	%
Short-term (more than one month, less than one year)	25
Spot (one month or less)	45
Total	100	%

We renew or replace gas supply contracts as they expire. Aside from the gas supplies provided by an independent energy marketing company as part of asset management services, no individual supplier provided over 10% of our gas supply requirements in 2014.

Gas Cost Management Strategy

The cost of gas sold to utility customers primarily consists of the following items, which are included in annual PGA rates: purchase price paid to suppliers; charges paid to pipeline companies to store and transport gas to our distribution system; our gas reserves contract; and gains or losses related to 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;

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•

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.

We also contract with an independent energy marketing company to capture opportunities regarding our unused storage and pipeline capacity when those assets are not serving the needs of our core utility customers. Our asset management activities provide cost savings that reduce our utility customer's cost of gas and opportunities to generate incremental revenues for NW Natural's shareholders from a regulatory incentive-sharing mechanism, which are included in our gas storage segment.

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 pipeline’s 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. Our largest pipeline agreements are with Northwest Pipeline. These contracts are multi-year contracts with expirations ranging from 2016 to 2044. We actively work with Northwest Pipeline and others to renew contracts in advance of expiration and 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, NW Natural's 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 several potential industrial projects in the region, which could increase the demand for natural gas and the need for additional pipeline capacity and pipeline diversity.

Several interstate pipeline projects currently proposed could meet the region's and NW Natural's projected demand. Though only one of these projects will likely be completed with the pipeline location dependent on the location of the

successful project. NW Natural will evaluate and closely monitor the currently prospected projects to determine the best option for ratepayers. The Company also has an equity investment in Trail West Holdings, LLC (TWH) that is developing plans to build the Trail West pipeline, formerly known as Palomar or the cross-Cascades pipeline project. 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. See Part II, Item 7, "2015 Outlook".

Gas Distribution

The goals of our gas distribution operations are:


•	Safety - Building and maintaining a safe pipeline distribution system;


•	Reliability - Ensuring gas resource portfolios are sufficient to satisfy customer requirements under extreme cold weather conditions;


•	Lowest Reasonable Cost - Acquiring gas supplies at the lowest reasonable cost for utility customers;


•	Price Stability - Managing commodity price volatility by making the best use of physical assets and financial instruments; and


•	Cost Recovery - Managing gas purchase costs prudently to minimize risks associated with regulatory reviews and cost recovery.

These goals are discussed more fully in the following sections.

Safety

Safety and the protection of our employees, our customers and the public at large are, and will remain, our top priorities. We monitor and maintain our pipeline distribution system and storage operations with the goal of ensuring natural gas is stored and delivered safely, reliably and efficiently. Since 2004, we have partnered with the OPUC and WUTC on various efforts to improve the safety and reliability of our distribution system. In Oregon, we have a cost recovery program that integrated the Company’s programs for bare steel replacement, transmission pipeline integrity management, and distribution pipeline integrity management into a single program. Currently, we are seeking renewal of the System Integrity Program (SIP); however, our bare steel replacement program continues in 2015. See Part II, Item 7, "Results of Operations—Regulatory Matters—System Integrity Program".

Natural gas distribution businesses are likely to be subject to even greater federal and state regulation in the future due to recent pipeline incidents involving other companies. Most recently, additional regulations from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) were drafted in 2013 with final regulations expected in 2015 and an effective date in 2016. 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 associated with compliance to federal, state, and local rules would be recoverable in rates.

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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 totals approximately 9.3 million therms. Of this total, we are currently capable of meeting over 50% of our maximum design day requirements with gas from storage located within or adjacent to our service territory, while the remaining supply requirements would be met by gas purchases under firm gas purchase contracts and recall agreements.

On February 6, 2014, we experienced our current record customer sendout of 9.0 million therms, which included 7.4 million firm therms. This record day was approximately 9 degrees Fahrenheit warmer than the design day temperature.

To supplement near-term natural gas supplies, the Company planned to segment transportation capacity during the 2014-2015 heating season for approximately 0.4 million therms per day 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.

Specifically, the Company could segment pipeline capacity that flows from Stanfield, Oregon with additional gas expected from the Sumas, Washington trading hub. This segmented capacity is considered reliable as the pipeline has not experienced constraints from Sumas in recent years.

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 integrated resource plan (IRP) process.

The following table shows the sources of supply projected to be used to satisfy the design day sendout for the 2014-2015 winter heating season:



Therms in millions	Therms	Percent
Sources of utility supply:
Firm supply purchases	3.3	36	%
Mist underground storage (utility only)	2.7	29
Company-owned LNG storage	1.8	20
Off-system storage contract⁽¹⁾	0.5	5
Pipeline segmentation capacity	0.4	4
Recall agreements	0.4	4
Peak day citygate deliveries⁽²⁾	0.2	2
Total	9.3	100	%


⁽¹⁾	A portion of the related pipeline transportation service from this facility is subject to curtailment and considered secondary firm capacity. As a result, NW Natural is evaluating the reliability of the capacity as part of the IRP process.


⁽²⁾	These citygate deliveries are contracted from December 2014 to February 2015 with this resource being evaluated for future heating seasons after the current winter.

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.

In general, the IRP is filed biannually with both the OPUC and the WUTC. An update is filed in Oregon in the off year. The OPUC acknowledges receipt of the IRP; whereas the WUTC provides notice our IRP 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 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. We filed our 2014 IRP in both Oregon and Washington in August 2014 and received acknowledgment from the OPUC in February 2014. We are currently awaiting notice from the WUTC.

Lowest Reasonable Cost

We apply cost management strategies, including fixed-price contracts, financial derivative instruments, storage supplies, acquisition of gas reserves, and asset management to acquire gas supplies at the lowest reasonable cost for utility customers. See "Gas Supply—Gas Cost Management Strategy" above.

Price Stability

We use physical assets and financial instruments to manage commodity price volatility. We purchase gas for our storage facilities generally during the summer months when demand and gas prices are typically lower. In addition, our gas reserves provide long-term gas price stability for our utility customers. We also mitigate year-to-year commodity price volatility through financial hedge contracts such as commodity price swaps and options.

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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, 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—Rate Mechanisms" and "Results of Operations—Business Segments—Local Gas Distribution Utility Operations—Cost of Gas."

GAS STORAGE

The gas storage segment includes the following:


•	the non-utility portion of the Mist gas storage facility near Mist, Oregon;


•	our 75% share of the Gill Ranch gas storage 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.

In recent years, as a result of the abundant supply of natural gas in North America, we have seen lower, more stable natural gas prices, which have created a challenging gas storage environment particularly in California. The spot price and front end of the forward curve for natural gas temporarily increased in late 2013 and early 2014 due to extreme cold weather. The effect during 2014 was a significant decline in storage levels, which resulted in spring and summer natural gas prices equal to projected gas prices for the winter of 2014-15. Thus, the purchase of spring and summer gas for injection into storage was less desirable and storage values decreased. While we are seeing some improvement in storage values coming out of this year's warmer than normal winter, overall prices remain lower than our long-term contracts that expired during the 2013-14 gas storage year. Despite current market conditions, we continue to believe in the long-term need for gas storage, particularly in California, due to various regulations including renewable portfolio standards and signs of economic recovery and industrial growth in the region. Increased demand for natural gas and/or decreased drilling activity could change the current supply/demand imbalance and result in higher gas prices or increased market volatility, which could position this segment for growth.

See Note 4 for more information on gas storage assets and results of operations and "Financial Condition—Liquidity and Capital Resources".

Gas Storage Facilities

The following table provides information concerning the Company’s 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⁾	6	2.4	1.0
Gill Ranch Storage⁽²⁾	15	4.9	2.4

⁽¹⁾

Approximately 6 Bcf of a total 16 Bcf at Mist is currently available to our gas storage segment. The remaining 10 Bcf is used to provide gas storage for our local distribution business and its utility customers. All storage capacity and daily deliverability currently developed for the gas storage segment at Mist is available for recall by the utility. In May 2015, the utility plans to recall approximately 0.3 million therms per day of deliverability or 0.7 Bcf of capacity for core utility customer use.


⁽²⁾	Our share of the Gill Ranch facility is currently 15 Bcf out of a total capacity of 20 Bcf.


⁽³⁾	Our share of the expected daily maximum injection and deliverability rates.

Mist Storage Facility

The Mist storage facility began operations in 1989 and currently 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 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 interstate 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 production or distribution, electric generation, and energy marketing. Three storage customers currently account for over 90% of our existing non-utility gas storage capacity at Mist, with the largest customer accounting for about half of the total capacity. These three customers have contracts that expire at various dates through 2018.

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

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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 related to utility customers' lower demand during the spring and summer months. This surplus storage capacity and related transportation capacity can be optimized under regulatory sharing agreements with the OPUC and WUTC. 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. See Part II, Item 7, "Results of Operations—Regulatory Matters".

EXPANSION OPPORTUNITIES. The need for new, flexible gas-fired generation has been identified in the Pacific Northwest region to integrate intermittent wind resources into the power system, thereby increasing the associated need for gas storage. To address this need, we are planning a potential expansion of our Mist storage facility. If completed, this expansion would be supported by a contract with Portland General Electric (PGE) to serve gas-fired electric power generation facilities at Port Westward, Oregon, which is located approximately 15 miles from Mist.

The project would include a new reservoir providing up to 2.5 Bcf of available storage, an additional compressor station with design capacity of 120,000 dekatherms of gas per day, and a 13-mile pipeline to connect to PGE’s gas plants at Port Westward. The current estimated cost of the expansion is approximately $125 million with a potential in-service date in 2018 or 2019, depending on the permitting process and construction schedule.

In early 2015, we received authorization from PGE to begin permitting and land acquisition work, and in October 2014 a new rate schedule was approved under which we will provide no-notice gas storage service associated with the expansion. This expansion project is subject to PGE's final approval of project costs and a notice to proceed, as well as the receipt of permits, certain land rights, and other conditions.

Gill Ranch Facility

Gill Ranch Storage, LLC (Gill Ranch), our subsidiary, has a joint project agreement with Pacific Gas and Electric Company (PG&E) to develop and own the Gill Ranch 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% of the available storage capacity at the facility. Gill Ranch’s share of the facility currently provides 15 Bcf of working gas capacity.

California has been impacted by challenging market conditions for gas storage, with contract prices in the region at historic lows for the past two years and a greater number of competitors in the area compared to the Pacific Northwest region. More recently, we have seen improvement in pricing for the upcoming 2015-2016 gas storage year, however prices are still lower than our long-term contracts that expired during the 2013-2014 gas storage year. We are committed to using a variety of contracting tools to maximize the value of the Gill Ranch facility. In the longer term, we anticipate a rebound in gas storage values driven by a variety of factors including changes in energy generation triggered by California's renewable portfolio standards and carbon reduction targets, recovery of the California economy, and other favorable market conditions in and around California. We believe these factors could increase demand for natural gas storage and increase price volatility.

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. Our Gill Ranch facility is not currently authorized to provide interstate gas storage services.

CUSTOMERS. Customer contracts for firm storage capacity at Gill Ranch are as long as 28 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 mostly ranging from one to five years. For the 2014-15 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 storage facility competes with a number of other storage providers, including local integrated gas companies and other independent storage operators in the northern California market. As storage markets recover, there could also be expansions and proposed new construction of storage capacity in northern California that may create increased competition.

SEASONALITY. 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

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asset management and other revenues. In addition, a significant portion of operating costs at Gill Ranch are subject to seasonality 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. 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 storage facility can be expanded beyond the current combined permitted 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 storage 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.

Asset Management

We contract with an independent energy marketing company to provide asset management services, primarily through the use of commodity 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. See Part II, Item 7, "Results of Operations—Business Segments—Gas Storage".

OTHER

We have non-utility investments and other business activities which are aggregated and reported as other. Other primarily consists of:


•	an equity method investment in a joint venture to build and operate a gas transmission pipeline in Oregon. Trail West Holdings, LLC (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. See Part II, Item 7, "2015 Outlook";


•	a minority interest in 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 income are related to activities in other. See Note 4 for summary information for these assets and results of operations.

ENVIRONMENTAL ISSUES

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 timeframe 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; and


•	variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

We seek recovery of environmental costs through insurance and customer rates, and we believe recovery of these costs is probable. At December 31, 2014, we had an open proceeding with the OPUC to address implementation issues for the SRRM, which allows for regulatory cost recovery of our environmental expenditures. In February 2015, the OPUC issued an order addressing outstanding items related to the SRRM, including prudence of past costs, an earnings test, and a regulatory disallowance of $15 million pre-tax to be recorded in the first quarter of 2015 in accordance with accounting guidance and our regulatory accounting policy. See "Results of Operations—Rate Matters—Rate Mechanisms—Environmental Costs" below, Note 2, Note 15, and Note 16.

Greenhouse Gas Issues

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 future emissions of greenhouse gases, including both carbon dioxide (CO₂) and methane. These future 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 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

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greenhouse gas reporting regulations requiring the annual reporting of fugitive emissions from our operations.

The outcome of federal and state policy development in the area of climate change cannot 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 gas 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 fossil fuel with relatively low carbon content, 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 for use in vehicles.

We continue to take steps to address future greenhouse gas emission issues, including actively participating in policy development through participation on various Oregon taskforces and, at the federal level, within the American Gas Association. We engage in policy development and in identifying ways to reduce greenhouse gas emissions associated with our operations and our customers’ gas use, including offering 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, 2014, the utility workforce consisted of 612 members of the Office and Professional Employees International Union (OPEIU) Local No. 11, AFL-CIO, and 472 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, 2014, our subsidiaries had a combined workforce of 19 non-union 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, technology, and distribution system improvements. For the five-year period ending in 2019, capital expenditures for the utility are estimated to be between $850 and $950 million, including the Company's proposed investment in an expansion of our Mist gas storage facility.

In 2015, utility capital expenditures are estimated to be between $140 and $150 million, and non-utility capital investments are estimated to be less than $10 million. Additional spend for gas storage and other investments during and after 2015 will depend largely on future decisions about potential expansion opportunities in gas storage projects.

EXECUTIVE OFFICERS OF THE REGISTRANT

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

AVAILABLE INFORMATION

We file annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC). Reports, proxy statements and other information filed by us can be read and requested through the SEC by mail at U.S. Securities and Exchange Commission, Office of FOIA/PA Operations, 100 F Street, N.E., Washington, D.C. 20549, by facsimile at (202) 772-9337, 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 (202) 551-8090. 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 adopted a Code of Ethics for all employees and officers that is available on our website. We intend to disclose amendments to, and any waivers from the Code of Ethics 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.

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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. 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 indicate 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, pension expense, transactions with affiliated interests, 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 over our Mist storage operations.

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 disallow. For example, in the most recent OPUC order issued to the Company regarding implementation of our SRRM, the OPUC disallowed from rate recovery approximately $15 million of approximately $95 million of our total environmental expenditures made from 2003 to 2012, due to the OPUC's application of a recently formulated earnings test. 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.

In our latest general rate case with the OPUC, various items were deferred for future resolution in separate proceedings, including recovery of prepaid pension costs, and our revenue-sharing arrangement on the utility's interstate storage activities. The regulatory proceedings in which these issues will be resolved 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 already 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 asset which would result in a charge to current year earnings. In addition, in our most recent Oregon general rate case, the OPUC approved the SRRM, which limits recovery of our deferred amounts to those amounts which satisfy an annual prudence review and a recently adopted 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. These ongoing prudence reviews and the earnings test could reduce the amounts we are allowed to recover, and could adversely affect our financial condition, results of operations and cash flows.

In addition, we may have disputes with regulators and other parties as to the severity of particular environmental matters and what remediation efforts are appropriate. We cannot predict with certainty the amount or timing of future

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expenditures related to environmental investigation, remediation or other action, 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 the probable level of involvement, and 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. Current and additional environmental regulations could result in increased compliance costs or additional operating restrictions and could have an adverse effect on our financial condition and results of operations, particularly if those costs are not fully recoverable from insurance or through utility customer rates.

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 overall 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 beyond that assumed in our PGA 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.

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 a potential 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 or CNG refueling stations. 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, 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-

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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 similar projects in the future. 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 law 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, the occurrence of one or more of these risks, could affect our ability to recover this hedge in rates. Further, our amended gas reserves arrangement has not been approved for inclusion in rates, and our regulators may ultimately determine to not include all or a portion of that transaction 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 hydrocarbons 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;


•	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.

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 outcome resulting from such events could be significant. Additionally, we may not be able to obtain 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, and other extreme events to which we may not able to promptly respond.

Local or national disasters, pandemic illness, terrorist activities, including cyber attacks, and other extreme events are a threat to our assets and operations. Companies in our industry 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 natural gas 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 that could affect our operations. Threatened or actual national disasters or terrorist activities may also disrupt capital markets and our ability to raise capital, 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 obtain 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.

EMPLOYEE BENEFIT RISK. The cost of providing pension and postretirement healthcare benefits is subject to changes

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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 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 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 required 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 (the Union), and are covered by a collective bargaining agreement that extends to November 30, 2019. Disputes with the Union over terms and conditions of the 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 Mist gas storage, which could strain relationships with customers and state regulators and cause a loss of revenues. Our collective bargaining agreement 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. 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 applicable to them. 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 interpretation 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 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 and accidents in other parts of the country, we anticipate that the natural gas industry may be the subject of even greater federal, state and local regulatory oversight. We intend to work diligently with industry associations and federal and state regulators to ensure compliance with the new laws. We expect there to be increased costs associated with compliance, and those costs could be

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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 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 hedge accounting under generally accepted accounting standards, our hedges may not be effective and our results of operations and financial condition could be adversely affected.

We also have credit-related exposure to derivative counterparties. In general, we require our counterparties to have an investment-grade credit rating at the time the derivative instrument is entered into, and we specify limits on the contract amount and duration based on each counterparty’s credit rating. Nevertheless, 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 2014, 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 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 short-term 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.

Risks Related Primarily to Our Local Utility Business

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 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

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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 fuel 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 fuel sources and growing commercial use of natural gas. 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, propane, and renewable energy. 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 could also 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 to obtain, 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 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

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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. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. 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 operation 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.

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.

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Because we do not own all of these pipelines, their operation is 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 reason, our ability to operate efficiently and satisfy our customers’ needs could be compromised, thereby potentially could have an adverse impact on our financial condition, results of operations and cash flows.

OPERATIONS AT STORAGE FACILITY RISK. Operations at our Mist and Gill Ranch storage facilities involve numerous operational risks that may result in a failure to meet expectations or contractual obligations, additional or unexpected costs and other business risks that could adversely impact our financial condition, results of operations and cash flows.

Operations at a storage facility involve many risks. If we fail to inject or withdraw natural gas at the levels we expect or at contracted rates, or cannot deliver natural gas consistent with our expectations or contractual specifications, or otherwise operate as expected, or if operating costs are substantially higher than we expect or if we fail to control those costs, we may not be able to contract for storage at the levels and on the terms we expect, and we could incur higher than expected costs to satisfy our contractual obligations under contracts we obtain, and this could adversely impact our financial condition, results of operations and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have no unresolved comments.

ITEM 2. PROPERTIES

Utility Properties

Our natural gas pipeline system consists of approximately 14,000 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, 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 order to reduce risks associated with gas leakage in older parts of our system, we undertook accelerated pipe

replacement programs under which we removed and replaced 100% of our cast iron mains by the end of 2000, and under which we expect to eliminate all remaining bare steel mains and services by the end of 2015.

Gas Storage Properties

We hold leases and other property interests in approximately 12,000 net acres of underground natural gas storage in Oregon and 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 an option to purchase future storage rights in certain other areas of the Mist gas field in Oregon, as well as in California related to the Gill Ranch storage project.

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.

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PART II

ITEM 5. MARKET FOR THE 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:



	2014				2013
Quarter Ended	High		Low		High		Low
March 31	$	44.09	$	40.05	$	46.55	$	43.40
June 30	47.32		43.06		45.89		41.17
September 30	47.50		41.81		45.15		39.96
December 31	52.57		42.29		44.35		40.75

The closing price for our common stock on December 31, 2014 and 2013 were $49.90 and $42.82, respectively.

As of February 20, 2015, there were 5,929 holders of record of our common stock.

We have paid quarterly dividends on our common stock in each year since the stock first was issued to the public in 1951. Annual common dividend payments per share, adjusted for stock splits, have increased each year since 1956. Dividends per share paid during the past two years were as follows:



Payment Date	2014		2013
February 15	$	0.460	$	0.455
May 15	0.460		0.455
August 15	0.460		0.455
November 15	0.465		0.460
Total per share	$	1.845	$	1.825

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, 2014:



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
10/01/14-10/31/14	—	$	—	—	—
11/01/14-11/30/14	4,233	46.22		—	—
12/01/14-12/31/14	211	47.32		—	—
Total	4,444	$	46.28	2,124,528	$	16,732,648


⁽¹⁾	During the quarter ended December 31, 2014, 4,444 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended December 31, 2014, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

⁽²⁾

We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2015 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended December 31, 2014, no shares of our common stock were repurchased pursuant to this program. Since the program’s inception in 2000, we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

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ITEM 6. SELECTED FINANCIAL DATA



	For the year ended December 31,
In thousands, except share data	2014		2013		2012		2011		2010
Operating revenues	$	754,037	$	758,518	$	730,607	$	828,055	$	792,115
Net income	58,692		60,538		58,779		63,044		72,013

Earnings per share of common stock:
Basic	$	2.16	$	2.24	$	2.19	$	2.36	$	2.71
Diluted	2.16		2.24		2.18		2.36		2.70
Dividends paid per share of common stock	1.85		1.83		1.79		1.75		1.68

Total assets, end of period	$	3,064,945	$	2,970,911	$	2,813,120	$	2,742,718	$	2,614,172
Total equity	767,321		751,872		729,627		712,158		691,625
Long-term debt	621,700		681,700		691,700		641,700		591,700

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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, 2014, 2013, and 2012. References in this discussion to "Notes" are 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), and


•	NW Natural 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), and NNG Financial's equity investment in Kelso-Beaver Pipeline (KB Pipeline). For a further discussion of our business segments and other, see Note 4.

In addition to presenting results of operations and earnings amounts in total, certain financial measures are expressed in cents per share, which are non-GAAP financial measures. These amounts reflect factors that directly impact earnings, including income taxes. All references in this section to earnings per share (EPS) are on the basis of diluted shares. We use such non-GAAP measures in analyzing our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

EXECUTIVE SUMMARY

Our 2014 performance reflects the execution of our long-term business strategy and advancement of our initiatives. Highlights for the year include:


•	increased the annual customer growth rate in core utility for the third year in a row from 0.8% to 1.4% at December 31, 2014;


•	invested $120.1 million in our system and facilities including $30.4 million on SIP, allowing us to approach the completion of our bare steel replacement, and announced a proposed gas storage expansion at Mist;


•	received proceeds from environmental insurance settlements, bringing total insurance recoveries to $103 million in 2014 and over $150 million cumulatively;


•	launched a new online tool for customers and trade allies that enables online ordering of services, tracking progress of orders, and managing multiple projects;


•	ranked first in residential customer satisfaction for large gas utilities in the West in the 2014 J.D. Power and Associates Study, making 2014 the 13th consecutive year of top three rankings; and


•	increased the dividend, marking the 59th consecutive year of increases.

We manage our business and strategic initiatives with a long-term view on providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2015 Outlook" below for more information.

Key financial highlights include:



In millions, except per share data	2014		2013		2012
Consolidated net income	$	58.7	$	60.5	$	58.8
Consolidated EPS	2.16		2.24		2.18
Utility margin	366.1		353.9		344.5

Net income and EPS for 2014 reflected the following:


•	utility net income increased $3.7 million on utility margin growth of $12.2 million primarily due to customer growth and rate-base returns on gas reserves and other investments; and


•	gas storage net income declined $5.9 million primarily due to lower operating revenues from re-contracting certain expiring capacity at lower prices for the 2014-15 gas storage year.

See "Consolidated Earnings and Dividends" below for additional detail.

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2015 OUTLOOK

Our near-term outlook and long-term strategic goals for the business are aligned with delivering gas safely and reliably to our customers, investing for profitable growth in our core gas distribution and gas storage businesses, and creating new ideas to drive growth opportunities. Our 2015 strategy leverages our resources and our history of innovative solutions to continue meeting the needs of customers, regulators, and shareholders. We consider the following goals critical in achieving these long-term goals:



Deliver Gas		Grow Our Businesses
	Ensure Safety and Reliability		Grow Utility Customers
	Advance Regulatory Policies and Initiatives		Pursue Strategic Utility Investments
	Promote Sustainable Energy Policies		Develop Non-utility Growth Initiatives

SAFETY AND RELIABILITY. Delivering natural gas safely and reliably to customers and providing employees with a safe work environment are our top priorities. During 2015, we will continue to ensure our pipeline system and facilities are well maintained, new facility improvements are planned and well executed, and business continuity requirements are met. In addition, the removal of all bare steel pipe from our system is set to be achieved by the end of 2015.

In 2014 we filed our IRP with the OPUC and WUTC, identifying investments needed to ensure our system will continue meeting customer demands. In February 2015, the OPUC acknowledged the IRP. We will continue working on key infrastructure investments for high-growth areas of our service territory and plan for necessary maintenance of our utility and storage facilities.

REGULATION. Constructive regulation supports customers receiving quality service at a reasonable cost and the company receiving timely cost recovery and earning a reasonable return on shareholder investments. During 2015, we will implement our new Site Remediation and Recovery Mechanism (SRRM). This mechanism reflects the deep, shared commitment of the Company and its customers to the environment. In addition, we continue to work with regulators on environmental sustainability projects such as new carbon solution incentive rate mechanisms.

ENERGY POLICIES. The Pacific Northwest is committed to energy conservation, environmental sustainability, and reducing carbon emissions. Natural gas is an important clean energy resource for our region and the country. Natural gas can play an important role in supporting the integration of intermittent renewable resources into the electric power system, and therefore, complements wind and solar renewable energy options. In 2015, we will continue to play an active role in shaping energy policies and programs, which reflect the interests of our customers. We will continue to work with state legislators to build a strong energy plan for the region, and we will remain committed to working with environmental agencies to make significant progress towards remediation of our legacy environmental sites.

UTILITY CUSTOMERS. Natural gas is a preferred energy resource in our service territory as it is a low-cost, reliable, and clean energy choice. We intend to capitalize on this preference and on improvements in the residential housing and commercial markets to grow our customer base.

KEY UTILITY INVESTMENTS. We believe investing in new infrastructure, operating efficiencies, and marketing opportunities positions our core business for growth now and well into the future. During 2015, we will continue working on a number of carbon solution programs with the OPUC, such as residential oil conversions, commercial combined heat and power, and other carbon emission reduction programs.

Our recent IRP filing indicates an increase in the demand for natural gas in our region and the need for additional infrastructure investments. Our utility and gas storage operations in Oregon and SW Washington currently depend on a single bi-directional interstate transmission pipeline to transport gas supplies to customers. We will continue to work with regulators, customers, and utilities in the Pacific Northwest to advance a new, integrated, regional cross-Cascades pipeline to create supply diversity and reliability for our system. The need for gas supply flexibility increases as additional large electric generation and industrial projects are sited in the region.

A growth investment for our storage business is the planned expansion at Mist to support a gas-fired plant built by Portland General Electric (PGE) at their nearby Port Westward facility. In early 2015, we were authorized by PGE to begin permitting and land acquisition work for this project. Before construction can begin, the project is subject to several conditions, including, but not limited to, PGE's final approval of estimated costs and receipt of a notice to proceed.

NON-UTILITY INITIATIVES. Energy policies in the Pacific Northwest and California are likely to increase the value of the Company's gas storage in the long-term. In the short-term, we remain focused on maximizing the value of our storage assets by managing costs, optimizing revenue opportunities, and seeking new potential markets and customers, while recognizing the unique challenges low, stable natural gas prices bring to the storage market.

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Issues and Challenges

ECONOMY. The local, national, and global economies showed signs of improvement during 2014. We saw increased utility customer growth and business demand for natural gas. Our utility’s customer growth rate was 1.4% in 2014, compared to 1.3% in 2013 and 0.9% in 2012. NW Natural ended 2014 with 704,644 customers. The local Oregon and southwest Washington economies are showing signs of recovery as unemployment rates in the Portland and Vancouver area dropped from approximately 7% in 2013 to approximately 6% at the end of 2014. We believe our utility is well positioned for continued customer additions and increasing industrial demand because of low, stable natural gas prices, our relatively low market penetration, and our ongoing focus of converting homes and businesses to natural gas. Additional growth may also come with increased industrial load from new projects in the region and proposed legislation that favors lower carbon emissions and lower cost energy alternatives, such as natural gas. Our gas storage business is also impacted by the employment trends throughout the West Coast, as California, which was among the hardest hit areas during the recession, is reporting lower unemployment levels in 2014.

GAS PRICES AND SUPPLIES. Our gas acquisition strategy is to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so we can effectively manage costs, reduce price volatility, and maintain a competitive price advantage. With developments in drilling technologies and the abundance of shale development around the U.S. and in Canada, the current outlook for North American natural gas supply is strong and is projected to remain this way into the future. This projection is dependent upon a combination of supply outlook and demand factors as well as a regulatory environment that continues to support hydraulic fracturing and other drilling technologies.

Our utility's annual PGA mechanisms in Oregon and Washington, combined with our gas price hedging strategies, enable us to reduce earnings exposure for the Company and secure lower gas costs for our customers. Each year, we typically hedge gas prices on approximately 75% of our utility's annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2014-15 gas year (November 1, 2014 - October 31, 2015) hedged at 75% of our forecasted sales volumes, including 41% in financial swap and option contracts and 34% in physical gas supplies. For further discussion see "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" below.

In addition to the amount hedged for the current gas contract year, we are also hedged in future years at approximately 18% for the 2015-16 gas year as of December 31, 2014 and between 1% and 9% for annual requirements over the following five gas years. 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 storage inventory levels may increase or decrease based on storage expansion, changes in storage contracts with third parties, and/or storage recall by the utility.

While low and stable gas prices provide opportunities to lower costs for our utility customers, they also present challenges for our gas storage businesses by lowering the price of, and reducing the demand for, storage services. Earlier this year we re-contracted certain expiring storage customer capacity at our Gill Ranch facility for the 2014-15 gas storage year at historically low prices due to the flat natural gas price curve and generally weak market conditions, which negatively impacted our financial results. However, increases in demand for natural gas or decreases in supplies can put upward pressure on gas prices and gas price volatility, which could improve the market value for gas storage. Similarly, decreases in demand and increases in supplies can cause downward pressure on gas prices and gas price volatility. We are seeing slightly higher contract prices for the upcoming storage year, but overall prices are lower than our long-term contracts that expired during the 2013-14 gas storage year. As such, we continue to expect shorter contract lengths and prices reflecting current market trends and remain focused on lowering operating costs, finding opportunities in the market to increase revenues through enhanced services for storage customers, and capitalizing on market opportunities that fit our business-risk profile.

ENVIRONMENTAL COSTS. We accrue all material environmental loss contingencies related to environmental sites for which we are responsible. Due to numerous uncertainties surrounding the nature of environmental investigations and the approval of proposed remediation solutions by regulatory agencies, actual costs could vary significantly from our loss estimates. As a regulated utility, we have been allowed to defer certain costs pursuant to regulatory orders. In our 2012 general rate case, the OPUC approved our recovery of environmental costs from investigation and site remediation subject to certain conditions including a site remediation and recovery mechanism. In February 2015, the OPUC issued an order regarding the mechanism as noted in "Results of Operations—Regulatory Matters—Rate Mechanisms" below and Note 16.

We have received approximately $150 million cumulatively from environmental insurance policy litigation settlements to apply toward environmental costs, and will only seek recovery from customers for amounts in excess of insurance proceeds. Ultimate recovery of environmental costs from regulated utility rates depends on our ability to effectively manage these costs and demonstrate costs were prudently incurred, and the application of an annual earnings test in Oregon. Environmental cost recovery and carrying charges on amounts charged to Washington customers will be determined in a future proceeding. See "Results of Operations—Regulatory Matters—Rate Mechanisms" below and Note 16.

CLIMATE CHANGE. We recognize our business will likely be impacted by future carbon constraints. To address these possible constraints, we are seeking clean energy growth opportunities that position us for long-term success in a lower carbon energy economy and to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. A variety of federal, state, local, and international climate change initiatives, including new regulations, are underway, but we cannot determine the

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impact of these initiatives at this time. For example, an array of Environmental Protection Agency (EPA) rules impacting coal plants has driven some coal plants to shut down early although the EPA is not mandating coal plant closures. Coal plant shut downs could increase the demand for natural gas as a lower carbon emission fuel and create opportunities for us. Similarly, because natural gas has a relatively low carbon content, it is also possible future carbon constraints could create additional demand for natural gas for base load electric generation, direct use in homes and businesses, backing up intermittent renewable resources, and as a transportation fuel to displace gasoline and diesel fuels.

As required under EPA greenhouse gas regulations, we annually report our system throughput and unintended greenhouse gas releases. While our carbon dioxide equivalent emission levels are relatively small, the adoption and implementation of any regulations imposing reporting obligations, or limiting emissions of greenhouse gases associated with our operations, could result in an increase in the prices we charge our customers or a decline in the demand for natural gas.

CONSOLIDATED EARNINGS AND DIVIDENDS

Consolidated Earnings

Consolidated highlights include:



In millions, except EPS data	2014			2013			2012
Net income	$	58.7		$	60.5		$	58.8
EPS	2.16			2.24			2.18
ROE	7.7		%	8.2		%	8.2		%

2014 COMPARED TO 2013. Overall, consolidated net income decreased $1.8 million. Our net income is most significantly impacted by our utility business which had favorable results during the year, but increases at the utility were more than offset by declines from our gas storage segment. The primary factors were:


•	a $12.2 million increase in utility margin primarily due to customer growth and the rate-base return on our gas reserves and other investments;


•	a $8.9 million decrease in gas storage operating revenues as storage was negatively impacted by re-contracting certain expiring firm storage capacity at lower prices;


•	a $3.3 million increase in depreciation and amortization expenses due to additional utility capital expenditures; and


•	a $2.7 million decrease in other income and expense, net due to lower interest income on net deferred regulatory balances.

2013 COMPARED TO 2012. The most significant factors contributing to the $1.8 million increase in consolidated net income were:


•	a $9.4 million increase in utility margin primarily due to customer growth and the rate-base return on our gas reserves and other investments; and


•	a $2.7 million after-tax charge taken in 2012 from an Oregon general rate case disallowance.

Partially offsetting the above factors were:


•	a $7.1 million increase in operations and maintenance expense primarily due to increased utility payroll and system maintenance and safety program costs; and


•	a $2.9 million increase in depreciation and amortization expenses primarily due to additional utility expenditures.

Dividends

Dividend highlights include:



Per common share	2014		2013		2012
Dividends paid	$	1.85	$	1.83	$	1.79

The Board of Directors declared a quarterly dividend on our common stock of $0.465 cents per share, payable on February 13, 2015, to shareholders of record on January 30, 2015, reflecting an indicated annual dividend rate of $1.86 per share.

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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 2014, approximately 89% of our utility gas volumes and revenues were derived from Oregon customers, with the remaining 11% from Washington customers. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other proceedings in Oregon and Washington, but 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 and system of accounts. The OPUC and CPUC regulate intrastate storage services, and the FERC regulates interstate storage services. The OPUC and FERC use 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 the last regulatory filing. 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 2014, approximately 69% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 31% 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.

Open Regulatory Proceedings

The following provides a list of our significant open regulatory items:


•	Interstate Storage Sharing - A docket has been

opened to review 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. We anticipate resolution of this docket in 2015.


•	Prepaid Pension Asset - A schedule was established to resolve this docket in 2015. See "Rate Mechanisms—Pension Cost Deferral and Prepaid Pension Assets" below.


•	Gas Reserves - We filed with the OPUC in February 2015 seeking cost recovery on additional investments in gas reserves. See "Rate Mechanisms—Gas Reserves" below.

•

Integrated Resource Plan (IRP) - We filed our 2014 Oregon and Washington IRPs on August 29, 2014 and received acknowledgment from the OPUC on February 24, 2015. We expect notice from the WUTC during 2015. The IRPs included analysis of different market scenarios and corresponding resource acquisition strategies. This analysis is needed to develop supply and demand resource requirements, consider uncertainties in the planning process, and to establish a plan for providing reliable and low cost natural gas service.


•	System Integrity Program (SIP) - We filed a request to extend the SIP program in the fourth quarter of 2014. See "Rate Mechanisms—System Integrity Program (SIP)" below.

Completed Regulatory Activities

The following provides a list of our completed regulatory activities in 2014:

•

Flexible Gas Storage - We received approval from the OPUC in 2014 for two new rate schedules. One of these schedules is intended to allow us to provide no-notice gas storage service from Mist and specifically supports services associated with the proposed Mist gas storage facility expansion. The expansion would be supported by a contract with PGE to serve their gas-fired electric power generation facilities at Port Westward, which is located approximately 15 miles from Mist. In early 2015, we received authorization from PGE to begin permitting and land acquisition work. This project is subject to PGE's final approval of estimated projected costs and a notice to proceed, as well as the receipt of permits and certain land rights, among other conditions.


•	Senate Bill (SB) 844 - Final rules for gas utilities in Oregon governing the incentive rate-making mechanisms aimed at reducing greenhouse gas emissions were issued in 2014. We anticipate submitting programs developed under these rules to the OPUC in 2015. These programs include oil conversions, commercial combined heat and power, and other carbon emission reduction programs.


•	GASCO Water Treatment Station - The OPUC approved placing $19.0 million of capital costs

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associated with a water treatment station at our Gasco environmental site into rates effective November 1, 2013. During 2014, the OPUC deemed Gasco construction costs prudent and approved the application of $2.5 million of insurance proceeds plus interest to reduce the capital costs included in rates effective November 1, 2014.

•

CNG Service Approved - In 2014, we received approval from the OPUC to offer business customers a new service to install, own, and maintain gas compression equipment that enables them to fuel their vehicle fleets with CNG. NW Natural filed the tariff in June 2013 after receiving requests from businesses interested in switching or increasing the number of their fleet vehicles fueled by CNG. Costs associated with providing this service will be directly paid by business customers using the service. The OPUC will review the tariff after two years to assess the market for CNG at that time.

Rate Mechanisms

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 prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives, gas prices from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, a permanent rate adjustment for our SIP program, temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either 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. Under the Washington PGA mechanism, we defer 100% of the higher or lower actual gas costs, and those gas cost differences are normally passed on to customers through the annual PGA rate adjustment.

We filed our PGA in September 2014 and received OPUC and WUTC approval in October 2014. PGA rate changes were effective November 1, 2014, with the rate changes increasing the average monthly bills of residential customers by 1.7% and 6.0% in Oregon and Washington, respectively. The increase in Oregon reflected customers' portion of adjustments for changes in natural gas commodity costs, offset by credits related to the decoupling mechanism and other annual adjustments previously agreed to with the OPUC. Washington rates reflected the full effect of changes in natural gas commodity costs and some additional annual adjustments based on ongoing agreements with the WUTC.

Commodity cost increases were primarily related to the colder weather experienced by many parts of the United States for an extended period in late 2013 and early 2014. The extreme cold weather nationally resulted in a significant

withdrawal of gas from storage and higher gas prices compared to the 2012-13 winter. In addition, our service territory experienced a cold weather event in February 2014, increasing gas volumes purchased for that period. These past and current price and volume increases resulted in the rate changes for the 2014-15 PGA period.

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 for refund 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. We selected the 90% deferral option for the 2012-13, 2013-14 and 2014-15 PGA years. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2012, 2013, and 2014, the ROE threshold was 10.92%, 10.58%, and 10.66%, respectively. There were no refunds required for 2012 and 2013. We do not expect a refund for 2014 based on our results and anticipate filing the 2014 test in May 2015.

GAS RESERVES. In 2011 the OPUC approved the Encana gas reserve transaction to provide long-term gas price protection for our utility customers and determined the Company's costs under the agreement will be recovered, plus a rate base return on our investment, on an ongoing basis through our annual PGA mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas. Gas produced from our interests is sold by Encana at then prevailing market prices with revenues from such sales, net of associated operating and production costs, credited to our cost of gas. Annually, a forecast is established for the amounts related to revenues, costs, and production volumes expected, and any variances between forecasted and actual results are subject to our PGA incentive sharing in Oregon.

On March 28, 2014, we amended the original gas reserve agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy, LLC. Under the amendment, we ended the drilling program with Encana, but increased our assigned ownership interests in certain sections of the Jonah field and retained the right to invest in additional wells with the new owner.

In 2014 we elected to participate in some of the additional wells drilled in the Jonah field under our amended gas reserves agreement with Jonah Energy, LLC and may have the opportunity to participate in more wells in the future. We filed an application requesting regulatory deferral in Oregon for these additional investments. We filed in February 2015 seeking cost recovery for the additional wells drilled in 2014 and expect a decision on the prudence of these wells in 2015.

DECOUPLING. 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.

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The Oregon decoupling mechanism was reauthorized in the 2012 Oregon general rate case with the baseline determined in our 2012 general rate case being used in base rates. 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. Baseline consumption reflects forecasted customer consumption data used in the Oregon general rate case. In Washington, customer use is not covered by such a tariff. See "Business Segments—Local Gas Distribution Utility Operations" below.

WEATHER NORMALIZATION TARIFF. 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. This weather normalization mechanism was reauthorized in the 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, 2014, 7% 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, including terms, which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group. The 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.

SYSTEM INTEGRITY PROGRAM (SIP). Since 2002, various laws requiring minimum standards for integrity management programs and SIPs for natural gas transmission and distribution pipelines have been enacted. In January 2012 the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law and requires increased civil penalties for pipeline safety violations, improvements in prevention programs for pipelines, and additional review and analysis of various aspects of gas transmission lines. We work diligently with industry associations and federal and state regulators to ensure our compliance with the provisions of new laws.

The OPUC approved specific accounting treatment and cost recovery for our transmission pipeline integrity management program, our SIP, and for related pipeline safety rules adopted by the U.S. Department of Transportation’s PHMSA. In addition, the OPUC provided a two-year extension to November 2014 of our capital expenditure tracking mechanism to recover capital costs related to SIP. We recorded the costs related to the integrity management program as either capital expenditures or regulatory assets, accumulated the costs over each 12-month period, and recovered the revenue requirement associated with these costs, subject to audit, through rate changes effective with the Oregon annual PGA. Our SIP costs were tracked into rates annually, with rate base recovery after the first $4 million of capital costs. An annual cap for expenditures was set at $12 million, but extraordinary costs above the cap could have been approved with written consent of the OPUC staff and other interested parties and approval of the OPUC. During 2013, the Commission approved a temporary increase to the annual cap, authorizing an additional $13.7 million of expenditures above the cap over the following two years to be tracked into rates. With the increased cap, we plan to complete our bare steel replacement by the end of 2015, and as a result of this stipulation we are precluded from tracking additional bare steel replacement costs into rates after 2015. We do not have any special accounting or rate treatment for SIP costs incurred in the state of Washington.

We filed a request to extend the SIP program in the fourth quarter of 2014, with slightly modified program parameters. Specifically, we are seeking to track $8 million of SIP capital costs into rates annually, after having the first $1 million of SIP capital spend subject to regulatory lag. We expect to resolve this request during 2015.

ENVIRONMENTAL COST DEFERRAL AND SRRM. The OPUC has authorized the deferral of environmental costs associated with certain named sites and the accrual of carrying costs on amounts deferred, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the OPUC has authorized us to defer environmental costs and accrued carrying costs through January 2015, and the Company has filed a docket requesting authorization to defer costs through January 2016.

On February 20, 2015, the OPUC issued an order regarding the Site Remediation and Recovery Mechanism (SRRM) for recovering prudently incurred environmental site remediation costs through customer billings, subject to an earnings test. The OPUC order addressed a number of key issues including: (1) prudence of all but $33 thousand of costs incurred through March 31, 2014; (2) insurance settlement proceeds of approximately $150 million were deemed prudent with one-third of the proceeds applied to costs prior to December 31, 2012 and two-thirds to offset future environmental expenses; (3) in the order, the OPUC disallowed recovery of expenses totaling approximately $15 million for costs related to 2003 to 2012.

With respect to remediation expenses deferred after 2012, an aggregate of two-thirds of the environmental insurance

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receipts, plus interest will be applied ratably over 20 years and the remainder will be collected through the SRRM, and subject to an earnings test as follows: (1) The Company will recover the first $5 million of annual expense through a tariff rider from customers; (2) the Company will apply $5 million of insurance (plus interest accrued on insurance proceeds) to environmental expenses each year; and (3) any expenditures above the $10 million (plus interest) described above would be fully recoverable through the SRRM, to the extent the Company earns at or below its authorized Return on Equity (ROE). See Note 16 for additional detail regarding the earnings test and additional conditions related to these amounts.

The Company continues to evaluate the effects of the order and is required to file a compliance report with the OPUC within 30 days of the order demonstrating how it will be implemented. See Note 15 and Note 16 for additional detail.

The WUTC also authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This order was effective January 26, 2011 with cost recovery and a carrying charge to be determined in a future proceeding.

PENSION COST DEFERRAL AND PREPAID PENSION ASSETS. Effective January 1, 2011, the OPUC approved our request 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, which is currently 7.78%. 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 were $4.6 million and $9.1 million in 2014 and 2013, respectively. See "Application of Critical Accounting Policies and Estimates" below. As noted above, the Company continues to seek rate treatment for amounts invested in prepaid pension assets.

A prepaid pension asset docket was opened in 2013 to evaluate pension cost recovery for all utilities in Oregon. The utilities have requested recovery of the financing costs incurred as a result of timing differences between cash contributions made to their pension plans and the recognition of expense. A schedule was established to resolve this docket in 2015. As noted above, the Company currently recovers a portion of pension expense in rates and has requested continued recovery of these expenses in the docket.

CUSTOMER CREDITS FOR GAS STORAGE 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 from gas storage and asset management of pipeline capacity and gas storage at Mist. Generally amounts are credited to Oregon customers in June, while credits are given to customers in Washington through reductions in rates in the annual PGA filing in November.

The following table presents the credits to customers:



In millions	2014		2013		2012
Oregon utility customer credit	$	11.4	$	8.8	$	9.2
Washington utility customer credit	0.8		0.5		0.8

Business Segments - Local Gas Distribution Utility Operations

Our utility margin results are largely affected by customer growth and, to a certain extent, by changes in volume due to weather and customers’ gas usage patterns. In Oregon, we have a conservation tariff and a weather normalization tariff; both mechanisms are designed to reduce the volatility of our utility’s earnings and customer charges. See "Regulatory Matters—Rate Mechanisms" above.

Utility segment highlights include:



Dollars and therms in millions, except EPS data	2014		2013		2012
Utility net income	$	58.6	$	54.9	$	54.0
EPS - utility segment	2.15		2.03		2.01
Gas sold and delivered (in therms)	1,093		1,146		1,112
Utility margin⁽¹⁾	$	366.1	$	353.9	$	344.5

⁽¹⁾ See Utility Margin Table below for a reconciliation and additional detail.

2014 COMPARED TO 2013. The primary factors contributing to the $3.7 million or $0.12 per share increase in net income were as follows:


•	a $12.2 million net increase in utility margin primarily due to:


▪	a $16.6 million increase from customer growth in residential and commercial customers, industrial margins, and added rate-base returns on certain investments, including gas reserves; partially offset by


▪	$2.1 million increase in loss from gas cost incentive sharing mainly resulting from higher gas prices and volumes than those estimated in the PGA; and


▪	the remaining decrease was primarily due to warmer weather as measured by heating degree days, in Washington, which does not have a weather normalization mechanism in place, and the effect of warmer weather on margin for Oregon customers that opt out of weather normalization.


•	a $3.2 million increase in depreciation expense due to additional capital expenditures;


•	a $1.5 million decrease in operations and maintenance expense; and


•	a $2.1 million decrease in other income and expense, net primarily due to lower interest income on regulatory deferred account balances.

Total utility volumes sold and delivered in 2014 decreased 5% over 2013 primarily due to the impact of warmer weather on residential and commercial use.

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2013 COMPARED TO 2012. The primary factors contributing to the $0.9 million or $0.02 per share increase in net income were as follows:


•	a $9.4 million net increase in utility margin primarily due to:


▪	a $10.8 million increase related to customer growth and the rate-base return on our gas reserves and other investments, such as our pipeline integrity tracker; and

▪

a $3.9 million increase related to the timing impacts of changes in fixed monthly charges and decoupling baselines in the 2012 Oregon general rate case. As a result of changes to the decoupling baseline for average use per customer included in the 2012 rate case, the decoupling mechanism's results in 2013 were not comparable to 2012, although the overall impact on revenues was generally the same on an annualized basis.

These increases in margin were partially offset by:


▪	a $3.9 million decrease in gains from gas cost incentive sharing due to actual gas prices that were roughly equivalent to estimated PGA prices for 2013 as compared to actual gas prices that were lower than estimated PGA prices for 2012; and


▪	a $1.4 million decrease primarily related to the lower Oregon Authorized ROE of 9.5% from the 2012 general rate case.


•	a $1.5 million increase in other income and expense, net primarily due to interest on higher average regulatory account balances; and


•	a $2.7 million tax charge taken in 2012 from an Oregon general rate case disallowance. See "Application of Critical Accounting Policies and Estimates—Regulatory Accounting" below.

These factors were partially offset by:


•	a $7.4 million increase in operations and maintenance expense primarily due to increased utility payroll and system maintenance and safety program costs;


•	a $2.9 million increase in depreciation and amortization expense primarily due to a higher level of investment in utility property, plant, and equipment; and


•	a $2.4 million increase in interest expense primarily due to increases in long-term debt outstanding.

Total utility volumes sold and delivered in 2013 increased 3% over 2012 primarily due to the impact of colder

weather on residential and commercial use.

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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	2014			2013			2012			2014 vs. 2013			2013 vs. 2012
Utility volumes (therms):
Residential and commercial sales	620,903			671,906			637,885			(51,003		)	34,021
Industrial sales and transportation	472,087			474,525			473,884			(2,438		)	641
Total utility volumes sold and delivered	1,092,990			1,146,431			1,111,769			(53,441		)	34,662
Utility operating revenues:
Residential and commercial sales	$	672,440		$	673,250		$	642,337		$	(810	)	$	30,913
Industrial sales and transportation	73,992			68,880			70,020			5,112			(1,140		)
Other revenues	3,983			4,054			5,935			(71		)	(1,881		)
Less: Revenue taxes	18,837			19,002			18,430			(165		)	572
Total utility operating revenues	731,578			727,182			699,862			4,396			27,320
Less: Cost of gas	365,490			373,298			355,335			(7,808		)	17,963
Utility margin	$	366,088		$	353,884		$	344,527		$	12,204		$	9,357
Utility margin:⁽¹⁾
Residential and commercial sales	$	334,247		$	321,608		$	306,382		$	12,639		$	15,226
Industrial sales and transportation	29,982			28,335			28,586			1,647			(251		)
Miscellaneous revenues	4,329			4,308			4,452			21			(144		)
Gain (loss) from gas cost incentive sharing	(2,135		)	(41		)	3,811			(2,094		)	(3,852		)
Other margin adjustments	(335		)	(326		)	1,296			(9		)	(1,622		)
Utility margin	$	366,088		$	353,884		$	344,527		$	12,204		$	9,357
Degree Days
Average⁽²⁾	4,240			4,240			4,279			—			(39		)
Actual	3,792			4,379			4,152			(13		)%	5		%
Percent colder (warmer) than average weather⁽²⁾	(11		)%	3		%	(3		)%
Customers - end of period:
Residential customers	637,411			628,634			621,399			8,777			7,235
Commercial customers	66,304			65,321			63,619			983			1,702
Industrial customers	929			918			923			11			(5		)
Total number of customers	704,644			694,873			685,941			9,771			8,932


⁽¹⁾	Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas.

⁽²⁾

Average weather represents the 25-year average degree days, as determined in our Oregon general rate case. For 2014 and 2013, average weather represents the 25-year average degree days as set in our 2012 Oregon general rate case. For 2012, average weather represents degree days based on the 25-year average set in our 2003 Oregon general rate for the months of January through October, plus the 25-year average set in the 2012 Oregon general rate case for the months of November and December.

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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 83% 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 Tariff" above.

Residential and commercial sales highlights include:



In millions	2014		2013			2012
Volumes (therms):
Residential sales	381.5		418.6			395.5
Commercial sales	239.4		253.3			242.4
Total volumes	620.9		671.9			637.9
Operating revenues:
Residential sales	$	441.5	$	447.4		$	428.5
Commercial sales	230.9		225.9			213.8
Total operating revenues	$	672.4	$	673.3		$	642.3
Utility margin:
Residential:
Sales	$	223.6	$	234.1		$	211.6
Weather normalization	5.1		(9.0		)	(0.1		)
Decoupling	4.0		2.6			8.6
Total residential utility margin	232.7		227.7			220.1
Commercial:
Sales	91.6		92.1			84.0
Weather normalization	2.2		(4.0		)	0.2
Decoupling	7.7		5.8			2.1
Total commercial utility margin	101.5		93.9			86.3
Total utility margin	$	334.2	$	321.6		$	306.4

2014 COMPARED TO 2013. The primary factors contributing to changes in the residential and commercial markets were as follows:


•	sales volumes decreased 51.0 million therms, or 8%, primarily reflecting 13% warmer weather, which was partially offset by customer growth and a record February cold weather event;


•	operating revenues decreased $0.8 million, due to the 8% decrease in sales volumes, which was partially offset by a 4% increase in average gas rates over last year; and


•	utility margin increased $12.6 million, or 4%, primarily related to customer growth, added loads under higher commercial rate schedules, and added rate-base returns from our gas reserves and other investments, partially offset by the effect of warmer weather on our

Washington customers and Oregon customers that opted out of the weather normalization mechanism.

2013 COMPARED TO 2012. The primary factors contributing to changes in the residential and commercial markets were as follows:


•	sales volumes increased 34.0 million therms, or 5%, primarily reflecting 5% colder weather and customer growth;


•	operating revenues increased $30.9 million, or 5%, due to a 5% increase in sales volumes and $36.2 million of credits from gas cost savings which were applied to customer billings in 2012, partially offset by a 9% decrease in average gas prices, which flowed through the Company's PGA rates; and


•	utility margin increased $15.2 million, or 5%, primarily reflecting the following:


▪	a $10.8 million increase related to customer growth and the rate-base return on our gas reserves and other investments; and


▪	a $3.9 million increase related to the timing impacts of changes in fixed monthly charges and decoupling baselines in the 2012 Oregon general rate case.


▪	Partially offsetting these increases was a $1.4 million decrease primarily related to the lower Oregon Authorized ROE of 9.5% from the 2012 general rate case.

Industrial Sales and Transportation

Industrial customers have the option of purchasing sales or transportation services from the utility. Under the sales service, the customer buys the gas commodity from the utility. Under the transportation service, the customer buys the gas commodity 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 options, 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.

Industrial sales and transportation highlights include:



In millions	2014		2013		2012
Volumes (therms):
Industrial - firm sales	34.0		34.3		34.9
Industrial - firm transportation	153.6		144.5		131.2
Industrial - interruptible sales	76.4		59.5		59.6
Industrial - interruptible transportation	208.1		236.2		248.2
Total volumes	472.1		474.5		473.9
Utility margin:
Industrial - sales and transportation	$	30.0	$	28.3	$	28.6

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2014 COMPARED TO 2013. The primary factors contributing to changes in the industrial sales and transportation markets were as follows:


•	sales and transportation volumes decreased by 2.4 million therms due to lower usage by large volume interruptible transportation customers on lower margin rate schedules;


•	utility margin increased $1.6 million, or 6% primarily due to volume growth under higher margin rate schedules and other customer charges stemming from the extreme cold weather event in February 2014.

2013 COMPARED TO 2012. The primary factors contributing to changes in the industrial sales and transportation markets were as follows:


•	sales volumes remained relatively flat for 2013 compared to 2012; and


•	utility margin decreased 1%, primarily due to lower demand from customers in the pulp and paper segment. These decreases were partially offset by contributions from new customers and added load from existing customers.

Other Revenues

Other revenues include miscellaneous fee income as well as regulatory revenue adjustments, which reflect current period deferrals to and prior year amortizations from regulatory asset and liability accounts, except for gas cost deferrals which flow through cost of gas. Decoupling amortizations and other regulatory amortizations from prior year deferrals are included in revenues from residential, commercial and industrial firm customers.

Other revenue highlights include:



In millions	2014		2013		2012
Other revenues	$	4.0	$	4.1	$	5.9

2014 COMPARED TO 2013. Other revenues remained relatively flat year over year.

2013 COMPARED TO 2012. The primary factors contributing to changes in other revenues were as follows:


•	other revenues decreased $1.9 million primarily due to a positive 2012 regulatory adjustment which did not reoccur in 2013.

Cost of Gas

Cost of gas as reported by the utility includes gas purchases, gas withdrawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, gas reserve costs, and company gas use. The OPUC and WUTC generally require natural gas commodity costs to be billed to customers at the actual cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met we would not earn a profit or incur a loss on gas commodity purchases; however, in Oregon we have an incentive sharing mechanism whereby we either increase or decrease margin results based on a percentage of actual gas costs as compared to embedded gas costs in the PGA. Under this provision, our net income can be affected by differences between actual and expected gas costs, which occur

primarily because of market fluctuations and volatility affecting unhedged gas purchases in the PGA. In addition, we have a regulatory agreement where we earn a rate-base return on our investment in gas reserves, which is reflected in utility margin. See "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment and Gas Reserves" above.

We use natural gas commodity hedge contracts (derivative instruments), primarily fixed-price commodity swaps, consistent with our financial derivatives policies to help manage gas price stability. Gains and losses from these financial hedge contracts are generally included in our PGA and normally do not impact net income because the hedged prices are reflected in our annual PGA rates, subject to a regulatory prudence review. However, hedge contracts entered into after the annual PGA rates are set for Oregon customers can impact net income because we would be required to share in any gains or losses as compared to the corresponding commodity prices built into rates in the PGA. In Washington, 100% of the actual gas costs, including hedge gains and losses allocated to Washington gas sales, are passed through in customer rates. See "Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities" below, "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" above, and Note 13.

Cost of gas highlights include:



Dollars and therms in millions	2014			2013		2012
Cost of gas	$	365.5		$	373.3	$	355.3
Volumes sold (therms)	716			766		732
Average cost of gas (cents per therm)	$	0.51		$	0.49	$	0.54
Gain (loss) from gas cost incentive sharing	(2.1		)	—		3.8

2014 COMPARED TO 2013. The primary factors contributing to changes in cost of gas were as follows:


•	cost of gas decreased $7.8 million, or 2% primarily due to a 7% decrease in sales volume reflecting warmer weather during the year, partially offset by a 4% increase in average cost of gas collected through rates.

2013 COMPARED TO 2012. The primary factors contributing to changes in cost of gas were as follows:

•

cost of gas increased $18.0 million, or 5%, including the $37.7 million of credits applied to customer billings in 2012 related to the refund of gas cost savings. Excluding the customer credits, total cost of gas decreased $19.7 million, or 5%, primarily due to a 5% increase in volumes offset by a 9% decrease in average cost of gas collected through rates, reflecting lower market prices for natural gas.

During the first quarter of 2014, many parts of the United States experienced record cold weather for an extended period, while the Pacific Northwest temperatures were closer to normal averages. The extreme cold weather in early 2014 resulted in significant withdrawals of gas from storage and higher gas prices compared to 2013. In early February 2014, the Pacific Northwest had extreme cold weather for a few days that resulted in a record sendout for

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our utility. Consequently, higher volumes of gas purchases and higher gas prices during this period resulted in a margin loss of $2.1 million for 2014 under our gas cost incentive sharing mechanism. The effect on net income from our gas cost incentive sharing mechanism for 2013 was a pre-tax gain in margin of less than $0.1 million, compared to a pre-tax gain of $3.8 million for 2012. For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above.

Business Segments - Gas Storage

Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility in Oregon and our 75% ownership interest in the Gill Ranch underground storage facility in California.

At Mist, we provide gas storage services to customers in the interstate and intrastate markets primarily using storage capacity that has been developed in advance of core utility customers’ requirements. We also contract with an independent energy marketing company to provide asset management services using our utility and non-utility storage and transportation capacity, the results of which are included in the gas storage businesses segment. Pre-tax income from gas storage at Mist and asset management services using our utility's storage and transportation capacity is subject to revenue sharing with core utility customers. Under this regulatory incentive sharing mechanism, we retain 80% of pre-tax income from Mist gas storage services and asset management services when the underlying costs of the capacity being used are not included in our utility rates, and 33% of pre-tax income from such storage and asset management services when the capacity being used is included in utility rates. The remaining 20% and 67%, respectively, are credited to a deferred regulatory account for credit to our core utility customers. See "Regulatory Matters—Open Regulatory Proceedings" above for information regarding an open docket related to this incentive sharing mechanism.

Our 75% undivided ownership interest in the Gill Ranch facility is held by our wholly-owned subsidiary Gill Ranch, LLC, which is also the operator of the facility. Our portion of the facility is 15 Bcf of gas storage capacity. Gill Ranch commenced operations at the end of 2010, with the first full storage injection season beginning on April 1, 2011. We also contract with an independent energy marketing company to provide asset management services at Gill Ranch. See Note 4.

Gas storage segment highlights include:



In millions, except EPS data	2014			2013		2012
Gas storage net income	$	(0.4	)	$	5.6	$	4.5
EPS - gas storage segment	(0.01		)	0.21		0.17
Operating revenue	22.2			31.1		30.5
Operating expense	18.2			16.4		17.3

2014 COMPARED TO 2013. Our gas storage segment net income decreased $5.9 million primarily due to the following factors:


•	an $8.9 million decrease in operating revenues, primarily reflecting recontracting expiring storage

capacity at lower prices as the gas storage market prices remain at historic lows; and


•	a $1.8 million increase in operating expenses primarily due to higher repair and power costs at our Gill Ranch facility. See additional information regarding these expense trends below.

2013 COMPARED TO 2012. Our gas storage segment net income increased $1.0 million primarily due to higher revenues from asset management services and lower operating costs.

Over the past few years, market prices for natural gas storage, particularly in California, were negatively affected by the abundant supply of natural gas, low volatility of natural gas prices, and surplus gas storage capacity. In addition, storage prices were further affected by extreme cold weather this past winter, which resulted in a significant decline in storage levels, a rise in spot gas prices, and lower storage values due to a flatter forward price curve for the 2014-15 gas storage year. We re-contracted certain expiring storage capacity for the 2014-15 gas storage year with shorter-term contracts at substantially lower market prices than in previous years. These trends accounted for most of the decline in gas storage operating revenues.

We incurred an additional $2.4 million of repair and power costs at Gill Ranch during 2014 compared to 2013. The increase in power costs is primarily due to higher injections into storage during 2014 to replenish low storage levels following higher withdrawals during the 2013-14 winter. The additional repair costs were for maintenance work at the Gill Ranch facility, which has now been in operation for three annual cycles. We are continuing to evaluate potential capital improvements that may be needed to enhance the operations of the facility. See "Financial Condition—Liquidity and Capital Resources" and "Financial Condition—Cash Flows—Investing Activities" for more information below.

Our gas storage segment financial results have been negatively impacted in the short term by the decline in market conditions and higher than normal repair costs incurred this year. Despite these conditions, we continue to believe in the long-term need for gas storage in California and have recently seen a slight increase in contracting prices. In the future, we anticipate a rebound in gas storage values and an increase in the demand for natural gas driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, increase in use of alternative fuels to meet carbon reduction targets, recovery of the California economy, growth of domestic industrial manufacturing, potential exports of liquefied natural gas from the West Coast, and other favorable market conditions in and around California. These factors would likely result in higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. Refer to Note 2 for more information regarding our accounting for impairment of long-lived assets.

Other

Other primarily consists of NNG Financial's equity investment in KB Pipeline, an equity investment in TWH, which in turn has invested in the Trail West pipeline project, and other miscellaneous non-utility investments and

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business activities. See Note 4 and Note 12 for further details on other activities and our investment in TWH.

Other highlights include:



In millions, except EPS data	2014		2013		2012
Other net income	$	0.5	$	—	$	0.2
EPS - other	0.02		—		—

2014 COMPARED TO 2013. Other net income increased $0.5 million primarily due to increased merchandise sales from our natural gas appliance store.

2013 COMPARED TO 2012. Other net income remained relatively flat, as anticipated.

Consolidated Operations

Operations and Maintenance

Operations and maintenance highlights include:



In millions	2014		2013		2012
Operations and maintenance	$	137.0	$	136.6	$	129.5

2014 COMPARED TO 2013. Operations and maintenance expense increased $0.4 million, primarily due to the following factors:


•	a $2.4 million increase from additional repair and power costs at our Gill Ranch storage facility;


•	a $1.5 million increase in professional service costs related to our ongoing growth initiatives;


•	a $0.4 million increase in bad debt expense at the utility due to lower comparable amounts in 2013 driven by a decrease in our allowance for uncollectible accounts in the first quarter of 2013; and


•	Partially offsetting the above factors was a $3.9 million decrease in utility payroll and other costs.

2013 COMPARED TO 2012. Operations and maintenance expense increased $7.1 million, or 6%, primarily due to the following factors:


•	a $5.9 million increase in utility payroll expense primarily related to additional customer service positions for new programs and higher incentive compensation; and


•	a $2.7 million increase in utility expenses related to system maintenance and safety program costs.

Partially offsetting the above factors were:


•	a $0.9 million decrease in utility bad debt expense. See further discussion below.

Delinquent customer receivable balances have remained low for several years despite challenging economic conditions during the recession. This sustained, favorable trend resulted in a decrease to our allowance for uncollectible accounts in the first quarter of 2013, and bad debt expense continues to remain at historically low levels for the Company. The utility's bad debt expense as a percent of revenues was 0.1% for 2014 and has remained well below 0.5% of revenues every year since 2007.

In addition to fluctuations in operation and maintenance expense reported above, we have OPUC approval to defer certain utility pension costs in excess of what is currently recovered in customer rates. This pension cost deferral is recorded to a regulatory balancing account, which stabilizes the amount of operations and maintenance expense each year. For the year ended December 31, 2014 and 2013 we deferred pension expenses totaling $4.6 million and $9.1 million, respectively. As a result, increased pension costs had a minimal effect on operations and maintenance expense in 2014 and 2013, with the increase principally related to the costs allocated to our Washington operations, which are not covered by the pension balancing account. For further explanation of the pension balancing account, see Note 8 and “Regulatory Matters—Rate Mechanisms—Pension Cost Deferral and Prepaid Pension Assets,” above for further explanation of the pension balancing account.

Depreciation and Amortization

Depreciation and amortization highlights include:



In millions	2014		2013		2012
Depreciation and amortization	$	79.2	$	75.9	$	73.0

2014 COMPARED TO 2013. Depreciation and amortization expense increased by $3.3 million due to an increase in utility depreciation expense from system investments, resource center improvements, and gas storage facilities enhancements.

2013 COMPARED TO 2012. Depreciation and amortization expense for 2013 increased by $2.9 million compared to 2012 due to an increase in utility depreciation expense on investments in utility plant for system improvements and training facilities.

Other Income and Expense, Net

Other income and expense, net highlights include:



In millions	2014			2013			2012
Gains from company-owned life insurance	$	2.0		$	2.5		$	2.3
Interest income	0.1			0.1			0.2
Loss on sale of investments	—			—			(0.2		)
Loss from equity investments	(0.2		)	(0.1		)	—
Net interest on deferred regulatory accounts	2.4			4.5			3.0
Other non-operating	(2.4		)	(2.3		)	(2.1		)
Total other income and expense, net	$	1.9		$	4.7		$	3.2

2014 COMPARED TO 2013. Other income and expense, net decreased $2.7 million primarily due to lower interest income on net deferred regulatory balances as a result of insurance proceeds credited to regulatory balances for environmental costs. Our regulatory environmental deferred cost account subject to interest accruals changed from a net regulatory asset balance of $56 million at December 31, 2013 to a net regulatory liability balance of approximately $30 million at December 31, 2014 due to insurance proceeds received in 2014 exceeding amounts spent.

Table of Contents

2013 COMPARED TO 2012. Other income and expense, net increased $1.5 million primarily due to interest on higher average regulatory account balances.

Interest Expense, Net

Interest expense, net highlights include:



In millions	2014		2013		2012
Interest expense, net	$	44.6	$	45.2	$	43.2

2014 COMPARED TO 2013. Interest expense, net of amounts capitalized, decreased $0.6 million primarily due to the redemptions of debt in 2014 of $50 million of utility FMBs in July 2014 and $10 million in September 2014, and the retirement of $20 million of debt pursuant to Gill Ranch's amended loan agreement in June 2014.

2013 COMPARED TO 2012. Interest expense, net of amounts capitalized, increased $2.0 million primarily due to an increase of $2.3 million at the utility from the issuance of long-term debt. The utility issued $50 million of debt with a coupon rate of 3.542% in August 2013 and $50 million of debt with a coupon rate of 4.00% in October 2012. This increase was partially offset by a $0.7 million reduction in 2013 interest expense at the utility from the retirement of $40 million of long-term debt with a coupon rate of 7.13% in 2012. See Note 7 for further detail.

Income Tax Expense

Income tax expense highlights include:

In millions

2014

2013

NORTHWEST NATURAL GAS CO - FORM 10-K - February 27, 2015

Attached files