Northwest Natural Company
Annual Report 2015

Plain-text annual report

N W N A T U R A L 2 0 1 5 A N N U A L R E P O R T • B U I L D I N G W I T H F O R E S I G H T BUILDING WITH FORESIGHT 2015 ANNUAL REPORT CORPORATE PROFILE NW Natural (NYSE: NWN) is a 157-year-old natural gas distribution company headquartered in Portland, Oregon. NW Natural serves more than 714,000 utility customers in Oregon and Southwest Washington and provides natural gas storage to customers on the West Coast. In keeping with its steady growth strategy, the company has increased dividends paid to shareholders for 60 consecutive years. WASHINGTON ASTORIA MIST STORAGE VANCOUVER GASCO LNG PORTLAND THE DALLES TRAINING CENTER LINCOLN CITY NEWPORT LNG SALEM ALBANY SERVICE TERRITORY AND STORAGE FACILITIES EUGENE OREGON COOS BAY ASTORIA MIST STORAGE VANCOUVER GASCO LNG WASHINGTON PORTLAND THE DALLES TRAINING CENTER LINCOLN CITY SALEM ALBANY NEWPORT LNG EUGENE OREGON COOS BAY SAN FRANCISCO KEY NEVADA NW NATURAL SERVICE TERRITORY TRAINING CENTER REGIONAL RESOURCE CENTER LNG PLANT UNDERGROUND STORAGE HEADQUARTERS GILL RANCH STORAGE FRESNO CALIFORNIA 2015 2014 increase (decrease ) FINANCIAL OVERVIEW earnings Financial facts ($000): Operating revenues Utility margin Net income Adjusted net income* Financial ratios (%): Return on average common equity Adjusted return on average common equity* Capital structure** at year-end: Long-term debt Common stock equity **Excluding short-term debt and current long-term maturities. common stock Shareholder data (000): 723,791 371,392 53,703 62,778 754,037 366,088 58,692 58,692 6.9 8.1 42.5 57.5 7.7 7.7 44.8 55.2 Average shares outstanding – diluted Year-end shares outstanding 27,417 27,427 27,223 27,284 Per share data ($): Diluted earnings Adjusted diluted earnings* Dividends paid Book value at year-end Market value at year-end utility operating highlights 1.96 2.29 1.86 28.47 50.61 2.16 2.16 1.85 28.12 49.90 Gas sales and transportation deliveries (000 therms) 1,028,612 3,458 Degree days 714,428 Customers at year-end 1,061 Employees at year-end 1,092,990 3,792 704,644 1,084 dividends paid on common stock (per share) PAYMENT DATE February 15 May 15 August 15 November 15 Total dividends paid $ 0.4650 0.4650 0.4650 0.4675 $ 1.8625 $ 0.460 0.460 0.460 0.465 $ 1.845 (4) % 1 (9) 7 bps (80) 40 bps (230) 230 1% 1 (9)% 6 1 1 1 (6)% (9) 1 (2) diluted earnings per share (in dollars) dividends paid per share (in dollars) $2.60 $2.10 $1.60 $1.10 $0.60 $0.10 $1.90 $1.85 $1.80 $1.75 $1.70 $1.65 $1.60 $1.55 2011 2012 2013 2014 2015 2011 2012 2013 2014 2015 Diluted earnings per share were $1.96 or $2.29 adjusted for the regulatory disallowance in 2015.* Annual dividends paid per share in 2015 increased for the 60th consecutive year. The current indicated annual dividend is $1.87 per share. * Indicates non-GAAP measures based on the $15 million pre-tax or $9.1 million after-tax charge from the 2015 environmental order. After-tax amounts calculated using statutory tax rate of 39.5% and EPS uses 27.4 million diluted shares. LOS ANGELES NEVADA SAN FRANCISCO GILL RANCH STORAGE FRESNO CALIFORNIA LOS ANGELES Left: Gregg Kantor, CEO Right: David Anderson, President and COO LETTER TO SHAREHOLDERS 3 NW Natural has a long record of thinking ahead, of careful planning and disciplined execution. These attributes served us well in 2015. This past year we completed the removal of our bare steel pipe – making NW Natural’s distribution system one of the most modern in the nation. A milestone made possible due to pipe replace- ment cost trackers established three decades ago. We successfully navigated the financial impacts of a record-warm winter as a result of effective cost management and our weather normalization mechanism (WARM) put in place in 2003. We advanced a proposal to expand our storage assets in Oregon, first identified in 1979, to serve gas-fired electric generation that will back up recently built wind resources. And we began collecting revenues in November through our new environmental cost recovery mechanism. The Site Reme- 2015 HIGHLIGHTS • Reported net income of $53.7 million or $1.96 per share. Excluding the environmental charge, net income was $62.8 million or $2.29 per share, an increase of 13 cents per share compared to 2014 results.* • Continued to add new customers at an annual growth rate of 1.4 percent, bringing our customer base to more than 714,000. • Reduced residential customer rates by approximately 7 percent in Oregon and 14 percent in Washington, as a result of the lowest natural gas commodity prices in 15 years. • Earned the highest customer satisfaction score among large utilities in the West in the 2015 J.D. Power Gas Utility Resi- dential Customer Satisfaction Study. diation and Recovery Mechanism (SRRM) allows us to recover • Invested $129 million in capital expenditures for customer prudently incurred environmental cleanup costs allocated to growth and system improvements. Oregon, associated with legacy manufactured gas plants that operated until 1957. While that docket required a $15 million write-down in 2015 due to over-earning in years past, the recovery mechanism aligns our company and customers around a responsible cleanup of these legacy assets. Acting with foresight is no accident. It is part of our culture and key to a successful business in the Pacific Northwest. At NW Natural, we are proud of our ability to anticipate the needs of our customers, find innovative solutions, and successfully respond to challenges. Evidence of this can be seen in our 2015 performance: • Received key regulatory decisions from the Public Utility Commission of Oregon that resulted in cost recovery for prudently incurred environmental expenses and Jonah Field investments. • Increased common dividends paid for the 60th consecutive year, one of the longest dividend increase records of any company on the NYSE. 4 LETTER TO SHAREHOLDERS System Safety and Preparedness Removing the last few miles of all identified bare steel pipe in our system last year was a major accomplishment, but it was just one of many initiatives we’re working on to ensure our systems’ safety and reliability. In 2015, we moved forward on a five-year, $25 million infrastructure investment plan in Clark County, WA. The system upgrades planned for Clark County will include new high-pressure distribution lines and extensions to better serve customers in our service territory’s fastest-growing community. We also began to make additional improvements to our Newport LNG facility, built in 1977. Upgrades planned for this natural gas storage facility on the Oregon Coast include tank refurbishments, turbine modernization, and control room enhancements at an estimated cost of $25 million. Customer and system safety remains at the core of our operational priorities. In 2015, we once again reached our emergency response goals of answering 90 percent of emergency calls within 10 seconds, and responding on-site to damage and odor calls within 30 minutes on average. We also continued to prepare for a large-scale emergency event, such as a severe earthquake. Should our Portland headquarters be rendered unsafe, we can now transfer gas control and emergency dispatch operations to our new Business Continuity Center in Sherwood, Oregon. The facility was built to the highest structural standards for earthquake preparedness and has been outfitted to host employees crucial to core business functions during the first phases of a natural disaster. But today system safety doesn’t stop at state-of-the art pipelines and facilities. Utilities must also anticipate and mitigate cybersecurity threats. In 2015, our Information Technology team made significant strides to increase our cyber resiliency, deploying new cybersecurity technology, employee education and training on new policies and emergency response protocols company-wide. Regulatory Progress Last year, we continued to manage several important regulatory dockets at the Public Utility Commission of Oregon (OPUC). Early in 2015, we received the commission’s decision on our environmental cost recovery proceeding. In its order, the OPUC found that $114 million of environmental remediation expenses and carrying costs incurred through March of 2014 were prudent, as were the insurance settlements we executed totaling approximately $150 million. However, the OPUC disallowed recovery of $15 million of environmental costs based on the application of an earnings test for past years when the company earned above its authorized rate of return. As a result, we took an after-tax charge of $9.1 million to net income in 2015. SYSTEM SAFETY COMPLETED THE REMOVAL OF BARE STEEL AND CAST IRON PIPES CAPITAL EXPENDITURES WITH DEPRECIATION & AMORTIZATION (in millions) 2011 2012 2013 2014 2015 CAPITAL EXPENDITURES DEPRECIATION & AMORTIZATION $150 $125 $100 $75 $50 $25 $0 Total investment in capital expenditures during 2015 was $129 million, of which nearly $100 million was related to system integrity, maintenance and customer growth. Andrea Kuehnel and Scott Burg were part of the team that worked to remove the last known bare steel from NW Natural’s system. LETTER TO SHAREHOLDERS 5 In January 2016, the commission reviewed our compliance filing under their 2015 order and confirmed the company’s recovery of environmental costs allocated to Oregon rate payers under the mechanism. However, they disallowed interest earned on the original $15 million disallowance, which resulted in the company recognizing a $2 million after-tax charge in 2016. Although the charges were disappoint- ing, this was a complex docket, and we believe the mechanism provides a good path forward for all stakeholders. In September of last year, the OPUC also adopted an all-party settlement that determined how we would recover costs associated with seven wells we drilled under our amended gas WE REDUCED RESIDENTIAL CUSTOMER RATES APPROXIMATELY 7 PERCENT IN OREGON AND 14 PERCENT IN WASHINGTON reserves agreement. This $10 million additional investment provides long-term price protection for Oregon utility customers. We were pleased with this collaborative settlement and the positive conclusion to the docket. In 2016, we will be working with the commission and other utilities in Oregon on a policy docket to explore commodity hedging, including what role gas reserves could play in a balanced natural gas supply portfolio. It’s our view that today’s low prices, coupled with the expected increase in demand for natural gas to serve power generation, make long-term hedging opportunities like gas reserves an important option to help ensure future price stability for our customers. Utility and Storage Operations In November, we reduced residential customer rates approximately 7 percent in Oregon and 14 percent in Washington. With that reduction, our customers are paying less for their natural gas now than they did 15 years ago. This price decline helps our customers and improves the company’s competitive position, as consumers in our service area can save about 50 percent by switching from an electric or oil furnace to natural gas. UTILITY CUSTOMERS AT YEAR-END 720,000 700,000 680,000 660,000 640,000 620,000 600,000 580,000 560,000 2011 2012 2013 2014 2015 INDUSTRIAL COMMERCIAL RESIDENTIAL We added 9,784 new customers in 2015, and now serve 714,428 customers. 6 LETTER TO SHAREHOLDERS Our engineering team created a streamlined piping and metering design that reduces developer costs. As a result, this 10-story “Block 75” project in Portland will now include gas amenities in all 75 apartments, when it opens later in 2016. We were pleased to pair these lower rates with flexible energy resources Gill Ranch can deliver. another year of outstanding service from our As the impacts of those RPS requirements unfold, employees. For the sixth time in nine years, our priority is to pursue higher value service con- NW Natural ranked first in the annual J.D. Power tracts and tap into new market opportunities. Residential Customer Satisfaction Study for natural gas utilities in the West. This also marked the eighth time in nine years of posting among the top two highest satisfaction scores in the nation. Also in 2015, operations at our underground storage facility near Mist, Oregon performed well, providing valuable services to our core utility cus- tomers and profitably serving storage customers in the Northwest. However, our California Gill Ranch storage facility continued to operate in challenging market conditions. Excess natural gas storage capacity and limited gas price volatility have kept storage values low in California over the last several years. But new legis- lation recently signed by the Governor is likely to change the state’s energy landscape in substantial ways. California’s new Renewable Portfolio Standard (RPS) requires 50 percent of its power generation be produced from renewables by 2030, which we believe provides a strategic opportunity for the NW NATURAL RANKED FIRST in the J.D. Power Residential Customer Satisfaction Study in the West Competing for the Future Our region is attracting young, college educated households considered vital for both economic development and longer-term growth. More people were employed in 2015, with the average monthly employment in the Portland and Van- couver Metro area increasing by about 35,000 new jobs for an annual employment growth rate of 3.2 percent. This is more than one percentage point above the national average. In that same time period, the unemployment rate fell 100 basis points to 5.3 percent. Oregon’s average wage today is the highest it has been in a generation. PORTLAND AREA RENTERS prefer natural gas amenities We are also seeing strong housing growth in the Portland area with a 25 percent increase in single-family building permits in the last 12 months. NW Natural leveraged these economic improvements last year to sign up nearly 9,800 new customers, an annual growth rate of 1.4 percent. Nationally, single-family new construction has yet to rebound to pre-recession levels – and the Northwest is no exception. But there has been an upturn in the housing sector locally, particularly in multifamily apartments. Seeing this trend emerge, we created a cross-functional team to evaluate every aspect of the apartment rental market – a market typically underserved with natural gas in the Northwest and across the U.S. One of the first steps we took to assess our opportunity was to conduct renter preference research. A recent study showed 80 percent of Portland area renters paying average rent prices or above prefer gas amenities such OREGON & WASHINGTON AVERAGE RESIDENTIAL RATES (in dollars per therm) LETTER TO SHAREHOLDERS 7 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 2001 2003 2005 2007 2009 2011 2013 2015 OREGON AND WASHINGTON AVERAGE RESIDENTIAL RATES Today’s residential rates are lower than they were 15 years ago. The portal team is now working on new enhancements to leverage web analytics and cost data to identify main extension opportunities. as cooktops, water heating and fireplaces – demonstrating a clear gap between amendment to our existing Mist Site Certificate to what renters’ desire and what’s available. Armed with this data, we created a comprehensive marketing program to target apartment developers. While still early, we’ve been pleased with the level of interest from project owners. We view rental apartments as an untapped growth opportunity and a priority segment for us moving forward. Competing for growth today requires making it easier and faster to connect to gas. In 2015, the use of our industry-leading online portal grew, as consumers searched for gas availability in their area with the click of a mouse or a tap on the screen. In fact, almost 30 percent of our conversion sales used this web tool and more than 1,500 online orders were submitted by builders and con- tractors last year. Strong adoption of the portal’s functionality helps us operate more efficiently. But, as important, portal analytics allow us to strategically target new areas for growth and create customized marketing programs in 2016 and beyond. Leading with Solutions Policy makers in the Pacific Northwest are committed to shutting down coal-fired electric generation and substantially increasing the use of renewables to meet our region’s power needs. Natural gas and its supporting infrastructure are critical to helping achieve this goal. One way is by helping to back-up intermittent wind resources at a local electric utility’s gas-fired generating plants. In 2015, we submitted an application to the Oregon Energy Facility Siting Council for an 30 PERCENT of conversions used the portal allow us to provide on-demand storage services to these gas-fired generating plants. Last year, we also held an open house with the local community, obtained required permits and property rights, and worked with local agencies on the details of the project. In early 2016, the Department of Energy published a proposed order as part of the permit- ting process. If there are no challenges to that order, we could receive approval from the Oregon Energy Facility Siting Council for our permit later this spring. Concurrently, we are in the process of rebidding the engineering, procurement, and construction portion of the project. Following the approval of the permit and the rebidding process, we expect to receive a notice to proceed from the project sponsor later this year. Another way NW Natural is striving to support our region’s environmental goals is through a new Combined Heat and Power (CHP) program. The CHP program is the first proposal submitted by the company under Senate Bill 844 – the Oregon legislation designed to incent natural gas utilities to invest in projects that reduce carbon emissions. As submitted, the CHP program would provide finan- cial incentives to customers in our service territory that invest in and install CHP at their facilities. We submitted the program in June 2015, and expect a decision from the Commission in the spring of 2016. That decision will also help determine how we proceed with other potential carbon reduction programs under this legislation. 8 LETTER TO SHAREHOLDERS LIVING OUR MISSION & VALUES Leadership for the Future Over many years, NW Natural has demonstrated the careful planning essential to finding and retain- ing the talent necessary to drive future success. Detailed succession plans are an integral part of the company’s business activities, and this past year, the benefits of that work were visible. In July of 2015, the board of directors elected David H. Anderson as President, adding to his responsibilities as Chief Operating Officer. Then in December, we announced my retirement at the end of 2016 and that David would begin serving as Chief Executive Officer effective Aug. 1 this year. To help with the transition, I will be staying on as an advisor to the board until the end of December. A smooth transition at the top is critical, but as important is developing the talent for succession in key positions across the organization. That has been a long-held commitment at NW Natural, one that in my opinion is the true mark of a company with foresight. In today’s complex and rapidly changing energy landscape, foresight has never been more impor- tant. In 2016, NW Natural will remain focused on meeting today’s expectations while keeping an eye on the horizon. We will continue to safely provide our product with great customer service; provide a solid financial value to our customers and to you, our shareholders; and look toward the future – ensuring we have the expertise to drive growth and provide innovative solutions that fuel our long-term success. As I complete my last year at the company, I would like you to know it has been a great privilege to work with the talented men and women who make up NW Natural and to lead this great company on your behalf. And finally, as we continue into our 157th year, from all of us at NW Natural, we thank you for your investment and support. Gregg S. Kantor CEO OUR MISSION We provide safe, reliable and affordable energy in an environmentally responsible way to better the lives of the public we serve. OUR CORE VALUES Integrity Safety Service Ethic Caring Environmental Stewardship Produced by NW Natural’s Corporate Communications photo credits Bruce Forster - Cover: Tilikum Crossing; Page 3: Gregg Kantor and David Anderson Dale Headrick - Page 4: Andrea Kuehnel and Scott Burg; Page 5: Newport storage facility; Page 6: D.G. Graham, Block 75 project Robbie McClaran - Page 9: Board of Directors Corky Miller - Page 4: Bare steel removal, Page 6: Customer Service Rep; Page 7: Kristen Brown and Walter Cahall; Inside back cover: Nikki Sparley, Chu Lee and backpack event; Page 8: Corporate Officers printing RR Donnelley Front to back – left to right lea anne doolittle Senior Vice President and Chief Administrative Officer mardilyn saathoff Senior Vice President and General Counsel gregg s. kantor Chief Executive Officer david r. williams Vice President Utility Services david h. anderson President and Chief Operating Officer kimberly heiting Vice President Communications and Chief Marketing Officer shawn m. filippi Vice President and Corporate Secretary c. alex miller Vice President Regulation and Treasurer tom imeson Vice President Public Affairs gregory c. hazelton Senior Vice President and Chief Financial Officer grant m. yoshihara Vice President Utility Operations brody j. wilson Controller and Chief Accounting Officer CORPORATE OFFICERS 9 BOARD OF DIRECTORS timothy p. boyle Chief Executive Officer Columbia Sportswear Company martha l. “stormy” byorum Chief Executive Officer Cori Investment Advisors, LLC john d. carter Chairman of the Board Schnitzer Steel Industries, Inc. mark s. dodson Former Chief Executive Officer NW Natural c. scott gibson President Gibson Enterprises tod r. hamachek Chairman of the Board NW Natural gregg s. kantor Chief Executive Officer NW Natural jane l. peverett Former President and Chief Executive Officer British Columbia Trans- mission Corporation kenneth thrasher Chairman of the Board Compli Corporation malia wasson Former Executive Vice President of Commercial Banking, U.S. Bank 10 CORPORATE INFORMATION Notice of Annual Meeting The 2016 Annual Meeting will be held at 2 p.m., Thursday, May 26, at the company’s headquarters, One Pacific Square, 220 NW 2nd Ave., 4th floor, Portland, Oregon 97209. A meeting notice and proxy statement will be sent to all shareholders in April. If you plan to attend the annual meeting, you will need to detach and retain the admission ticket attached to your proxy card mailed to you with the notice of the annual meeting and the proxy statement. As space is limited, you may bring only one guest to the meeting. If you hold your stock through a broker, bank or other nominee, please bring a legal proxy or other evidence to the meeting showing that you owned NW Natural Common Stock as of the record date, April 7, 2016, and we will provide you with an admission ticket. A form of government-issued photograph identification will be required for both you and your guest to enter the meeting. to NW Natural Board of Directors, Request for publications Dividend reinvestment and direct stock purchase plan Participants may make an initial invest- ment in company stock and common shareholders of record may reinvest all or part of their dividends in additional shares under the company’s plan. Cash purchases may also be made. Participants in the plan bear the cost of brokerage fees and commissions for shares purchased on the open market to fulfill purchases under the plan. A prospectus will be sent upon request. c/o Corporate Secretary. Forward-looking statements The statements made in this Annual Report that are not purely historical, including statements regarding strat- egy, growth and marketing initiatives, dividends, earnings, financial value, future demand for gas, commodity costs and competitiveness, revenues, customer growth, gas supplies and reserves, hedge efficacy, capital expenditures, pipeline and storage infrastructure investments, Scheduled dividend payment dates system expansion, Mist storage expan- Subject to Board approval, the following dates are scheduled for dividend payment: February 12, 2016 May 13, 2016 August 15, 2016 November 15, 2016 Certifications The Chief Executive Officer certified to the NYSE on June 25, 2015, that, as of that date, he was not aware of any violation by the company of NYSE’s corporate governance listing standards, and the company had filed with the Securities and Exchange Commission (SEC), as exhibits 31.1 and 31.2 to its Annual Report on Form 10-K for the year ended December 31, 2014, the certificates of the Chief Executive Officer and the Chief Financial Officer of the company certifying the quality of the company’s public disclosure. For the year ended December 31, 2015, the certificates of the Chief Executive Officer and Chief Financial Officer are attached as exhibits 31.1 and 31.2 to the Form 10-K included in this Annual Report. Contact the NW Natural Board Concerns may be directed to the nonmanagement directors by writing sion project, including but not limited to cost and timelines, growth initiatives including SB844 projects, emergency preparedness, cyber resiliency and preparedness, system reliability, storage performance values, governmental policy and legislation and the effects thereof, regulatory cost recovery mechanisms, including, but not limited to, the SRRM, regulatory prudence reviews including, but not limited to, commodity hedging, regulatory proceedings and actions, economic recovery factors, customer savings, market trends and the com- petitive environment, and coal-fired and renewable energy resources, are forward-looking statements within the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. NW Natural’s actual results could differ materially from those anticipated in these forward-looking statements as a result of risks and uncertainties, including those described in the attached report on Form 10-K. For a more complete description of these risks and uncertainties, please refer to our filings with the SEC on Forms 10-K and 10-Q. The following publications may be obtained without charge by contacting the Corporate Secretary at NW Natural’s address: Annual Report; Form 10-K; Form 10-Q; Corporate Governance Standards; Director Independence Standards; Code of Ethics; and Board Committee Charters. These publications, as well as other filings made with the SEC, are also available on our website at nwnatural.com. Our SEC filings are also available by request through the SEC by mail at U.S. Securi- ties and Exchange Commission, Office of FOIA/PA Operations, 100 F Street, N.E., Washington, D.C. 20549, or online at sec.gov. You can obtain information about access to the Public Reference Room and how to access or request records by calling the SEC at 1-800-SEC-0330. comparison of five-year cumulative total return (Based on $100 invested on 12/31/2010) $250 $200 $150 $100 $50 $0 2010 2011 2012 2013 2014 2015 NWN S&P UTILITIES INDEX S&P 500 INDEX Total shareholder return (annualized) over the five years ending December 31, 2015 for NW Natural was 5.9%, compared to Standard & Poor’s (S&P) Utilities Index return of 11%, and the S&P 500 Index return of 12.5%. Form 10-K Annual Report 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, 2015 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ___________ to____________ Commission file number 1-15973 NORTHWEST NATURAL GAS COMPANY (Exact name of registrant as specified in its charter) Oregon (State or other jurisdiction of incorporation or organization) 93-0256722 (I.R.S. Employer Identification No.) 220 N.W. Second Avenue, Portland, Oregon 97209 (Address of principal executive offices) (Zip Code) Registrant’s telephone number, including area code: (503) 226-4211 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. [ X ] 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, 2015, the registrant had 27,355,642 shares of its Common Stock outstanding, of which 26,973,861 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 $1,137,757,457. At February 19, 2016, 27,435,906 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding. Portions of the Proxy Statement of the registrant, to be filed in connection with the 2016 Annual Meeting of Shareholders, are incorporated by reference in Part III. DOCUMENTS INCORPORATED BY REFERENCE NORTHWEST NATURAL GAS COMPANY Annual Report to Securities and Exchange Commission on Form 10-K For the Fiscal Year Ended December 31, 2015 TABLE OF CONTENTS PART I Glossary of Terms Forward-Looking Statements Item 1. Business Overview Business Model Local Gas Distribution Gas Storage Other Environmental Issues Employees Additions to Infrastructure Executive Officers of the Registrant Available Information Item 1A. Risk Factors Item 1B. Unresolved Staff Comments Properties Legal Proceedings Mine Safety Disclosures Item 2. Item 3. Item 4. PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Item 6. Item 7. Purchases of Equity Securities Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9B. Other Information PART III Item 10. Directors, Executive Officers and Corporate Governance Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services PART IV Item 15. Exhibits and Financial Statement Schedules SIGNATURES Page 1 4 5 5 5 5 10 12 12 13 13 13 13 14 21 21 21 21 22 23 24 46 48 86 86 86 87 88 88 89 89 90 91 GLOSSARY OF TERMS AND ABBREVIATIONS AFUDC AOCI / AOCL ASC ASU Average Weather Bcf Btu CAP CNG CO2 Allowance for Funds Used During Construction Accumulated Other Comprehensive Income (Loss) Accounting Standards Codification Accounting Standards Update as issued by the FASB The 25-year average heating degree days based on temperatures established in our last Oregon general rate case Billion cubic feet, a volumetric measure of natural gas, where one Bcf is roughly equal to 10 million therms 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 Btu's equal one therm Compliance Assurance Process with the Internal Revenue Service Compressed Natural Gas Carbon Dioxide Core Utility Customers Residential, commercial and industrial customers receiving firm service from the utility Cost of Gas CPUC Decoupling Demand Cost Dth EBITDA EE/CA Encana 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 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 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 A component in core utility customer rates representing the cost of securing firm pipeline capacity, whether the capacity is used or not Dekatherm (also decatherm) is equal to 10 therms or one million British thermal units (Btu) Earnings before interest, taxes, depreciation and amortization, a non-GAAP financial measure Engineering Evaluation / Cost Analysis Encana Oil & Gas (USA) Inc. Energy Corp Northwest Energy Corporation, a wholly-owned subsidiary of NW Natural EPA EPS FASB FERC Firm Service FMBs GAAP General Rate Case GHG Gill Ranch Gill Ranch Facility Environmental Protection Agency Earnings per share Financial Accounting Standards Board Federal Energy Regulatory Commission; the entity regulating interstate storage services offered by our Mist gas storage facility as part of our gas storage segment Natural gas service offered to customers under contracts or rate schedules that will not be disrupted to meet the needs of other customers First Mortgage Bonds Accounting principles generally accepted in the United States of America A periodic filing with state or federal regulators to establish billing rates for utility customers Greenhouse gases Gill Ranch Storage, LLC, a wholly-owned subsidiary of NWN Gas Storage Underground natural gas storage facility near Fresno, California, with 75% owned by Gill Ranch and 25% owned by PG&E 1 GTN Heating Degree Days Gas Transmission Northwest, which owns a transmission pipeline serving California and the Pacific Northwest 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 IRS KB LIBOR LNG LWG MAP-21 Moody's NAV Integrated Resource Plan United States Internal Revenue Service Kelso-Beaver Pipeline, of which 10% is owned by K-B Pipeline Company, a subsidiary of NNG Financial London Interbank Offered Rate 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 Lower Willamette Group A federal pension plan funding law called the Moving Ahead for Progress in the 21st Century Act, July 2012 Moody's Investors Service, Inc. is a credit rating agency Net Asset Value NNG Financial NNG Financial Corporation, a wholly-owned subsidiary of NW Natural NOL NRD Net Operating Loss Natural Resource Damages 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 ODEQ OPEIU OPUC PBGC PG&E PGA PGE PHMSA PRP RI/FS ROD ROE ROR S&P Department of Environmental Quality 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 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 Pension Benefit Guaranty Corporation Pacific Gas & Electric Company; is a 25% owner of the Gill Ranch Facility 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 Portland General Electric U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration Potentially Responsible Parties Remedial Investigation / Feasibility Study Record of Decision 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 Rate of Return 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 2 SIP SRRM TAIL Therm TWH TWP 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 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 TransCanada American Investments, Ltd., a 50% owner of TWH The basic unit of natural gas measurement, equal to one hundred thousand Btu’s Trail West Holdings, LLC is 50% owned by NWN Energy Trail West Pipeline, LLC, a subsidiary of TWH TransCanada TransCanada Pipelines Limited, owner of TAIL and GTN Transportation Service Service provided whereby a customer purchases natural gas directly from a supplier but pays the utility to transport the gas over its distribution system to the customer’s facility Utility Margin A financial measure consisting of utility operating revenues less the associated cost of gas, franchise tax and environmental recoveries VIE Variable Interest Entity Weather Normalization WUTC 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 mid-May of each heating season Washington Utilities and Transportation Commission, the entity that regulates our Washington utility business with respect to rates and terms of service, among other matters 3 FORWARD-LOOKING STATEMENTS plans, projections and predictions; objectives; goals; strategies; assumptions and estimates; future events or performance; trends; risks; timing and cyclicality; earnings and dividends; capital expenditures and allocation; capital structure; growth; customer rates; 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, assumes, intends, plans, seeks, believes, estimates, expects, and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following: • • • • • • • • • • • • • • • workforce succession; 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 outcomes, recovery or refunds; impacts of laws, rules and regulations; tax liabilities or refunds; levels and pricing of gas storage contracts and gas storage markets; 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; effects of new or anticipated changes in critical accounting policies; approval and adequacy of regulatory deferrals; effects and efficacy of regulatory mechanisms; and environmental, regulatory, litigation and insurance costs and recoveries, and timing thereof. • • • • • • • • • • • • • • • • • Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward- looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward- looking statements are discussed at Item 1A., "Risk Factors" of Part I and Item 7. and Item 7A., "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and "Quantitative and Qualitative Disclosures About Market Risk", respectively, of Part II of this report. Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law. 4 NORTHWEST NATURAL GAS COMPANY PART I ITEM 1. BUSINESS OVERVIEW Northwest Natural Gas Company (NW Natural or the Company) was incorporated under the laws of Oregon in 1910. Our Company and its predecessors have supplied gas service to the public since 1859, and we have been doing business as NW Natural since 1997. We maintain operations in Oregon, Washington, and California and conduct business through NW Natural and its subsidiaries. References in this discussion to "Notes" are to the Notes to the Consolidated Financial Statements in Item 8 of this report. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from storage facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other. See Note 4 to the Consolidated Financial Statements for further information on total assets and results of operations for our segments for the years ended December 31, 2013, 2014 and 2015. 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, 2015: Non-Utility(1) Utility Gas Storage(2) Other Total Assets 91.0% 8.5% 0.5% 100.0% 100.0% 0.3% 99.4% Net Income (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. 0.3% (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 714,000 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. 5 We have been allocated an exclusive service territory by the OPUC and WUTC, which includes a major portion of western Oregon, including the Portland metropolitan area, most of the Willamette Valley, the Coastal area from Astoria to Coos Bay, and portions of Washington along the Columbia River. Portland serves as one of the largest international ports on the West Coast and is a key distribution center due to its comprehensive transportation system of ocean and river shipping, transcontinental railways and highways, and an international airport. Major businesses located in our service territory include retail, manufacturing, and high-technology industries. Natural gas provides a clean, low-carbon, and affordable energy source, and supply in the United States is at an all- time high. We are committed to environmental stewardship and furthering the usage of natural gas to fuel heat, electric generation, and transportation systems in our communities. To this end, we filed our first proposal in 2015 with state regulators under a Carbon Solutions Program incentivizing industrial users to install combined heat and power systems using natural gas. See Part II, Item 7, "Results of Operations—Regulatory Matters". We also have an approved CNG tariff in place to provide customers with high- pressured gas service. Further, we have partnered with local agencies on environmental programs, and are able to allow residential and commercial customers to offset their carbon emissions by supporting carbon-reduction projects at dairies and other farms. Energy conservation is another key component of our environmental focus and competitive advantage, and we were among the first utilities in the nation to break the link between utility earnings and the quantity of natural gas sold to customers with our decoupling mechanism or conservation tariff. The decoupling mechanism 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. We will continue to further the role of natural gas in our region and country as it is an affordable, energy efficient fuel source. 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, 2015: Residential Commercial Industrial Other(1) Total Number of Customers % of Volumes % of Utility Margin (1) 646,841 66,584 1,003 N/A 34% 21% 45% N/A 63% 27% 8% 2% 714,428 100% 100% (1) Utility margin is also affected by 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 currently in approximately 60% of residential single-family dwellings in our service territory. Customer growth in our region comes from the following main sources, in both new construction and conversions: single-family housing, both new construction and conversions; multifamily housing construction; and commercial buildings, both new construction and conversions. Single family new construction has consistently been our strongest performing source of growth. We have added increasing numbers of customers in our service territory for the last four years as the economy has recovered. Continued customer growth is closely tied to the comparative pricing of natural gas to electricity and fuel oil and the health of the Portland, Oregon and Vancouver, Washington economies. We believe there is potential for continued growth as natural gas is affordable, reliable, a clean fuel choice, and a preferred energy source in our service territory. 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 utility margin if customers bypass or switch over to custom contracts with lower profit margins. Seasonality of Business Our utility business is seasonal in nature due to higher gas usage by residential and commercial customers during the cold winter heating months. 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. 6 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: Authorized Rate Structure: ROE ROR Oregon Washington 9.5% 7.8% 10.1% 8.4% Debt/Equity Ratio 50%/50% 49%/51% Key Regulatory Mechanisms: PGA Incentive Sharing Weather Normalization Tariff Decoupling SIP(1) Pension Balancing Environmental Cost Deferral SRRM X X X X X X X X X X (1) Regulatory authority for SIP expired October 31, 2014, although the bare steel replacement portion of the mechanism remained in place until the end of 2015. 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 gas reserves investments 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. 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". 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; • Reliability - ensuring gas resource portfolios are sufficient to satisfy customer requirements under extreme cold weather conditions; and • Cost Management and Recovery - 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 take advantage of price differentials. For 2015, 62% of our gas supply came from Canada, with the balance primarily coming from the U.S. Rocky Mountain region. We believe gas supplies available in the western United States and Canada are adequate to serve our core utility requirements for the foreseeable future. We continue to evaluate the long-term supply mix based on projections of gas production and pricing in the U.S. Rocky Mountain region as well as other regions in North America; however, we believe the cost of natural gas coming from western Canada and the U.S. Rocky Mountain region will continue to track with broader U.S. market pricing. Additionally, the extraction of shale gas has increased the availability of gas supplies throughout North America for the foreseeable future. We supplement our firm gas supply purchases with gas withdrawals from gas storage facilities, including underground reservoirs and LNG storage facilities. Storage facilities are generally injected with natural gas during the off-peak months in the spring and summer and the gas is withdrawn for use during peak demand months in the winter. The following table presents the storage facilities available for our utility supply: Gas Storage Facilities: Owned Facility: Mist, Oregon(1) Contracted Facilities: Jackson Prairie, Washington(2) Alberta, Canada(3) LNG Facilities: Owned Facilities: Newport, Oregon Portland, Oregon Total Maximum Daily Deliverability (therms in millions) Capacity (Bcf) 3.1 0.5 0.7 0.6 1.2 6.1 10.6 1.1 4.4 0.9 0.6 17.6 (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 3.1 million therms of daily deliverability and 10.6 Bcf of storage capacity are reserved for core utility customers. (2) The storage facility is located near Chehalis, Washington and is contracted from Northwest Pipeline, a subsidiary of The Williams Companies. (3) This resource does not add to our total peak day capacity, but mitigates price risks as it displaces equivalent volumes of heating season spot purchases. The Mist facility is used for both utility and non-utility purposes. Under our regulatory agreements with the OPUC and WUTC, non-utility gas storage at Mist can be developed in advance of core utility customer needs but is subject to recall by the utility when needed to serve utility customers as their demand increases. In May 2015, the utility recalled 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. 7 In addition, we have the ability to recall pipeline capacity and supply resources from certain customers if needed to meet high demand requirements. Diverse Contract Durations and Types We have a diverse portfolio of short-, medium-, and long- term firm gas supply contracts and a variety of contract types including firm and interruptible supplies 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 2015, we purchased a total of 669 million therms under contracts with durations outlined in the chart below: Contract Duration (primary term) Long-term (one year or longer) Short-term (more than one month, less than one year) Spot Total Percent of Purchases 33% 30 37 100% 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 2015. 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 are approximately 9.5 million therms. Of this total, we are currently capable of meeting about 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 come from gas purchases under firm gas purchase contracts and recall agreements. To supplement near-term natural gas supplies, we planned to segment transportation capacity during the 2014-2015 and 2015-2016 heating seasons 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, we 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 IRP process. The following table shows the sources of supply projected to be used to satisfy the design day sendout for the 2015-2016 winter heating season: Therms in millions Sources of utility supply: Firm supply purchases Mist underground storage (utility only) Company-owned LNG storage Off-system storage contract Pipeline segmentation capacity Recall agreements Peak day citygate deliveries(1) Therms Percent 3.3 3.1 1.8 0.5 0.4 0.4 0.2 34% 32 19 5 4 4 2 Total 100% (1) These citygate deliveries are contracted from December 2015 to February 2016 with this resource being evaluated for future heating seasons after the current winter. 9.7 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 2015, and notice from the WUTC in March 2015. We plan to file an IRP with both Commissions in 2016. 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 transport gas to our distribution system; costs paid to store gas; our gas reserves contracts; and gains or losses related to gas commodity derivative contracts. 8 We employ a number of strategies to mitigate the cost of gas sold to utility customers. Our primary strategies for managing gas commodity price risk include: • • negotiating fixed prices directly with gas suppliers; negotiating financial derivative contracts that: (1) effectively convert floating index prices in physical gas supply contracts to fixed prices (referred to as commodity price swaps); or (2) effectively set a ceiling or floor price, or both, on floating index priced physical supply contracts (referred to as commodity price options such as calls, puts, and collars). See Part II, Item 7A, "Quantitative and Qualitative Disclosures About Market Risk—Credit Risk—Credit Exposure to Financial Derivative Counterparties"; buying physical gas supplies at a set price and injecting the gas into storage for price stability and to minimize pipeline capacity demand costs; and investing in gas reserves for longer term price stability. See Note 11 for additional information about our gas reserves. • • We also contract with an independent energy marketing company to capture opportunities regarding our storage and pipeline capacity when those assets are not serving the needs of our core utility customers. Our asset management activities provide cost savings that reduce our utility customer's cost of gas and opportunities to generate incremental revenues for our shareholders from a regulatory incentive-sharing mechanism, which are included in our gas storage segment. Cost Recovery Mechanisms for gas cost recovery are designed to be fair and reasonable, with an appropriate balance between the interests of our customers and shareholders. In general, utility rates are designed to recover the costs of, but not to earn a return on, the gas commodity sold. We minimize risks associated with gas cost recovery by resetting customer rates annually through the PGA and aligning customer and shareholder interests through the use of sharing, weather normalization, and conservation mechanisms in Oregon. See Part II, Item 7, "Results of Operations—Regulatory Matters—Rate Mechanisms" and "Results of Operations—Business Segments—Local Gas Distribution Utility Operations—Cost of Gas." Transportation of Gas Supplies Our local gas distribution system is reliant on a single, bi- directional interstate transmission pipeline to bring gas supplies into our distribution system. Although we are dependent on a single pipeline, the 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 to ensure 9 gas transportation capacity is sufficient to meet our utility needs. Rates for interstate pipeline transportation services are established by FERC within the U.S. and by Canadian authorities for services on Canadian pipelines. As mentioned above, our service territory is dependent on a single pipeline for its natural gas supply. Although supply has not been disrupted in the recent past, pipeline replacement projects and long-term projected natural gas demand in our region underscore the need for pipeline transportation diversity. In addition, there are 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 our projected demand. The pipeline location is dependent on the location of the committed industrial project. We 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. 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, "2016 Outlook". Gas Distribution The primary goals of our gas distribution operations are safety and reliability of our system, which entails building and maintaining a safe pipeline distribution system. Safety and the protection of our employees, our customers, and the public at large are, and will remain, our top priorities. We construct, operate and maintain our pipeline distribution system and storage operations with the goal of ensuring natural gas is delivered and stored safely, reliably, and efficiently. NW Natural has one of the most modern distribution systems in the country with no identified cast iron pipe or bare steel main. We removed the final three miles of known bare steel from our system in 2015 and completed our cast iron pipe removal in 2000. Since the 1980s, we have taken a proactive approach to replacement programs and partnered with our Commissions on progressive regulation to further safety and reliability efforts for our distribution system. In the past, we had a cost recovery program in Oregon that encompassed the Company’s programs for bare steel replacement, transmission pipeline integrity management, and distribution pipeline integrity management. Currently, we are working with the OPUC and other Oregon natural gas utilities to evaluate guidelines for potential future safety cost-recovery tracking programs. 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 pipeline incidents involving other companies. Additional regulations from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) are currently under development with final regulations expected in 2016 and effective dates beginning in 2017. 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 of federal, state, and local rules would be recoverable in rates. GAS STORAGE Our gas storage segment includes the following: • the non-utility portion of the Mist gas storage facility near Mist, Oregon; our 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. 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) 5.4 2.1 Gill Ranch Storage(2) 15.0 (1) Approximately 5.4 Bcf of a total 16 Bcf at Mist is currently 4.9 0.8 2.4 available to our gas storage segment. The remaining 10.6 Bcf is used to provide gas storage for our local distribution business and its utility customers. 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 recalled approximately 0.3 million therms per day of deliverability and 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 initially converted to storage operations for our utility customers. Since 2001, gas storage capacity at Mist has also been made available to interstate customers by developing new incremental capacity in advance of core utility customer requirements to meet the demands for interstate storage service. These interstate storage services are offered under a limited jurisdiction blanket certificate issued by FERC. In addition, since 2005 we have offered intrastate firm storage services in Oregon under an OPUC-approved rate schedule as an optional service to eligible non-residential utility customers. CUSTOMERS. For Mist storage services, firm service agreements with customers are entered into with terms typically ranging from 2 to 10 years. Currently, our gas storage revenues from Mist are derived primarily from firm service customers who provide energy related services, including natural gas distribution, electric generation, and energy marketing. Three storage customers currently account for all of our existing contracted non-utility gas storage capacity at Mist, with the largest customer accounting for about half of the total capacity. These three customers have contracts expiring at various dates through 2019. COMPETITIVE CONDITIONS. Our Mist gas storage facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location. However, competition from other storage providers in Washington and Canada, as well as competition for interstate pipeline capacity, does exist. In the future, we could face increased competition from new or expanded gas storage facilities as well as from new natural gas pipelines, marketers, and alternative energy sources. SEASONALITY. Mist gas storage revenues generally do not follow seasonal patterns similar to those experienced by the utility because most of the storage capacity is contracted with customers for firm service, which are primarily in the form of fixed monthly reservation charges and are not affected by customer usage. However, there is seasonal variation with Mist storage capacity 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 10 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 electricity 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 long-term 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 1.2 million therms of gas per day, innovative no-notice service with uninterrupted turn capability, 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 targeted in-service date in winter of 2018-19, depending on the permitting process and construction schedule. In early 2015, we received authorization from PGE to begin permitting and land acquisition work, and a new rate schedule was approved in October 2014 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 Storage 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 near historic lows and a greater number of competitors in the area compared to the Pacific Northwest region. Prices for the 2015-16 gas year showed improvement, however prices remained low relative to the pricing in our original long-term contracts which ended primarily in the 2013-14 gas storage year. In the future, we may see an improvement 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, an increase in use of alternative fuels to meet carbon reduction targets, improvement of the California economy, growth of domestic 11 industrial manufacturing, potential exports of liquefied natural gas from the west coast, and other favorable storage market conditions in and around California. These factors, if they occur, may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. We are continuing to explore opportunities to increase revenues through enhanced services for storage customers and capitalizing on opportunities that fit our business-risk profile. 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 27 years in duration; however, the majority of the contracted capacity is shorter term in nature due to market conditions. In the near-term, we expect Gill Ranch to contract for terms ranging from one to five years. For the 2015-16 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. The Gill Ranch storage facility currently competes with a number of other storage providers, including local integrated gas companies and other independent storage providers (ISPs) in the northern California market. There are currently four ISPs authorized by the CPUC to provide storage services in California, with the Gill Ranch storage facility comprising approximately 12% of the storage capacity held by ISPs. A recent proposed acquisition, which is pending CPUC approval, will consolidate approximately 80% of the storage capacity authorized by the CPUC to ISPs in California. The effect of this dominant market share on the Gill Ranch storage facility pricing and contracting levels remains unknown and cannot be predicted at this time. In addition, in October 2015 a significant natural gas leak occurred at a southern California gas storage facility that persisted in 2016. During this time-frame, short-term storage spreads for the region improved. At this time, we do not know the long-term effects of this incident on gas storage prices. Regulatory proceedings at both the national and California state level have been opened in response to the incident, and it is likely additional regulations will result and increase short-term costs for all storage providers. The implications of the regulatory proceeding are unknown and cannot be predicted at this time until the rules are finalized. summary information for these assets and results of operations. SEASONALITY. While the majority of our Gill Ranch revenues are not subject to seasonality, and although we expect much of the storage revenue at Gill Ranch to be in the form of fixed monthly demand charges, cash flows can fluctuate due to timing of asset management and other revenues. In addition, a significant portion of operating costs at Gill Ranch are subject to fluctuations based on periods when storage customers elect to inject or withdraw. REGULATION. Gill Ranch has a tariff on file with the CPUC authorizing it to charge market-based rates for the storage services offered. 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. 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, "2016 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 12 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; variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site; and the application of environmental laws that impose joint and several liabilities on all potentially responsible parties. • • • • • • We seek recovery of environmental costs through received insurance proceeds and customer rates, and we believe recovery of these costs is probable. In Oregon, we have a mechanism to recover expenses, subject to an earnings test and allocation rules. See Part II, Item 7, "Results of Operations—Rate Matters—Rate Mechanisms— Environmental Costs", Note 2, 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 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, 2015, the utility workforce consisted of 598 members of the Office and Professional Employees International Union (OPEIU) Local No. 11, AFL-CIO, and 463 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, 2015, our subsidiaries had a combined workforce of 15 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 13 ending in 2020, 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 and excluding any potential future gas reserves investments. In addition, we are evaluating the impact of the five-year extension of bonus depreciation resulting from the enactment of the Federal Protecting Americans From Tax Hikes Act of 2016 on the mix and profile of our investments. We expect cash tax savings from bonus depreciation and are evaluating how to best take advantage of these savings during the period in which they are in effect. Our current capital expenditure range does not consider any additional capital that may be available as a result of this legislation. In 2016, utility capital expenditures are estimated to be between $155 and $175 million, and non-utility capital investments are estimated to be less than $5 million. Additional spend for gas storage and other investments during and after 2016 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 1-800- SEC-0330. The SEC website contains reports, proxy and information statements and other information we file electronically. In addition, we make available on our website (http://www.nwnatural.com), our annual report on Form 10- K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) and proxy materials filed under Section 14 of the Securities Exchange Act of 1934, as amended (Exchange Act), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We have 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. 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 mean that such risk factor is inapplicable to our other business segments. Risks Related to our Business Generally REGULATORY RISK. Regulation of our businesses, including changes in the regulatory environment, failure of regulatory authorities to approve rates which provide for timely recovery of our costs and an adequate return on invested capital, or an unfavorable outcome in regulatory proceedings may adversely impact our financial condition and results of operations. The OPUC and WUTC have general regulatory authority over our utility business in Oregon and Washington, respectively, including the rates charged to customers, authorized rates of return on rate base, including ROE, the amounts and types of securities we may issue, services we provide and the manner in which we provide them, the nature of investments we make, actions investors may take with respect to our company, and deferral and recovery of various expenses, including, but not limited to, pipeline replacement, environmental remediation costs, commodity hedging expense, transactions with affiliated interests, weather adjustment mechanisms and other matters. Similarly, in our gas storage businesses FERC has regulatory authority over interstate storage services, the CPUC has regulatory authority over our Gill Ranch storage operations, and the WUTC and OPUC have regulatory authority over our Mist storage operations. 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 February 2015 the OPUC issued an Order to the Company regarding implementation of our SRRM that 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. The OPUC issued a subsequent Order in January 2016 that, among other things, disallowed interest on the $15 million disallowance after 2012 and found only 96.68% of prudently incurred environmental remediation costs to be allowable to Oregon. 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 14 prudently incurred, and deny recovery. Additionally, while the OPUC and WUTC have established an authorized rate of return for our utility through the ratemaking process, the regulatory process does not provide assurance that we will be able to achieve the earnings level authorized. Moreover, in the normal course of business we may place assets in service or incur higher than expected levels of operating expense before rate cases can be filed to recover those costs—this is commonly referred to as regulatory lag. The failure of any regulatory commission to approve requested rate increases on a timely basis to recover increased costs or to allow an adequate return could adversely impact our financial condition and results of operations. As a regulated utility, we frequently have dockets open with our regulators. The regulatory proceedings for these dockets typically involve multiple parties, including governmental agencies, consumer advocacy groups, and other third parties. Each party has differing concerns, but all generally have the common objective of limiting amounts included in rates. We cannot predict the timing or outcome of these deferred proceedings or the effects of those outcomes on our results of operations and financial condition. ENVIRONMENTAL LIABILITY RISK. Certain of our properties and facilities may pose environmental risks requiring remediation, the costs of which are difficult to estimate and which could adversely affect our financial condition, results of operations, and cash flows. We own, or previously owned, properties that require environmental remediation or other action. We accrue all material loss contingencies relating to these properties. A regulatory asset at the utility has 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 assets 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. In addition, the OPUC ordered a review of the SRRM in 2018 or when we obtain greater certainty of environmental costs, whichever occurs first. These ongoing prudence reviews, the earnings test, or the three-year review could reduce the amounts we are allowed to recover, and could adversely affect our financial condition, results of operations and cash flows. Moreover, we may have disputes with regulators and other parties as to the severity of particular environmental matters and what remediation efforts are appropriate. We cannot predict with certainty the amount or timing of future expenditures related to environmental investigation, remediation or other action, the portions of these costs allocable to us, or disputes or litigation arising in relation thereto. Our liability estimates are based on current remediation technology, industry experience gained at similar sites, an assessment of the probable level of involvement, and the financial condition of other potentially responsible parties. However, it is difficult to estimate such costs due to uncertainties surrounding the course of environmental remediation, the preliminary nature of certain of our site investigations, and the application of environmental laws that impose joint and several liabilities on all potentially responsible parties. These uncertainties and disputes arising therefrom could lead to further adversarial administrative proceedings or litigation, with associated costs and uncertain outcomes, all of which could adversely affect our financial condition, results of operations and cash flows. ENVIRONMENTAL REGULATION COMPLIANCE RISK. We are subject to environmental regulations for our ongoing operations, compliance with which could adversely affect our operations or financial results. We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, groundwater quality and availability, plant and wildlife protection, and other aspects of environmental regulation. 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 15 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- 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 laws that could affect our ability to take, or timing of, certain tax benefits that impact the financial outcome of this transaction; inherent risks of gas production, including disruption to operations or complete shut-in of the field; and a participant in one of these business arrangements acting contrary to our interests. In addition, while the cost of the original gas reserves venture is currently included in customer rates, the occurrence of one or more of these risks, could affect our ability to recover this hedge in rates. Further, any new gas reserves arrangements have not been approved for inclusion in rates, and our regulators may ultimately determine to not include all or a portion of future transactions in rates. The realization of any of these situations could adversely impact the project as well as our financial condition, results of operations and cash flows. OPERATING RISK. Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs, some or all of which may not be fully covered by insurance, and which could adversely affect our financial condition, results of operations and cash flows. Our operations are subject to all of the risks and hazards inherent in the businesses of local gas distribution and storage, including: • earthquakes, floods, storms, landslides and other adverse weather conditions and hazards; leaks or other losses of natural gas or other chemicals or compounds as a result of the malfunction of equipment or facilities; damages from third parties, including construction, farm and utility equipment or other surface users; operator errors; negative performance by our storage reservoirs that could cause us to fail to meet expected or forecasted operational levels or contractual commitments to our customers; problems maintaining, or the malfunction of, pipelines, wellbores and related equipment and facilities that form • • • • • a part of the infrastructure that is critical to the operation of our gas distribution and storage facilities; collapse of underground storage caverns; operating costs that are substantially higher than expected; • • • • migration of natural gas through faults in the rock or to some area of the reservoir where existing wells cannot drain the gas effectively resulting in loss of the gas; blowouts (uncontrolled escapes of gas from a pipeline or well) or other accidents, fires and explosions; and risks and hazards inherent in the drilling operations associated with the development of the gas storage facilities and/or wells. • These risks could result in personal injury or loss of human life, damage to and destruction of property and equipment, pollution or other environmental damage, breaches of our contractual commitments, and may result in curtailment or suspension of our operations, which in turn could lead to significant costs and lost revenues. Further, because our pipeline, storage and distribution facilities are in or near populated areas, including residential areas, commercial business centers, and industrial sites, any loss of human life or adverse financial outcomes resulting from such events could be significant. Additionally, we may not be able to 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 16 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 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 require that we attract, train and retain skilled workers to prevent loss of institutional knowledge or skills gap. Without an appropriately skilled workforce, our ability to provide quality service and meet our regulatory requirements will be challenged and this could negatively impact our earnings. Additionally, within our utility segment a majority of our workers are represented by the OPEIU Local No.11 AFL- CIO (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 facility, 17 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 interpretations or enforcement of applicable law by a federal, state or local taxing authority, could result in substantial cost to us and negatively affect our results of operations. Tax law and its related regulations and case law are inherently complex and dynamic. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation. Our judgments may include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by taxing authorities. Changes in laws, regulations or adverse judgments may negatively affect our financial condition and results of operations. SAFETY REGULATION RISK. We may experience increased federal, state and local regulation of the safety of our systems and operations, which could adversely affect our operating costs and financial results. The safety and protection of the public, our customers and our employees is and will remain our top priority. We are committed to consistently monitoring and maintaining our distribution system and storage operations to ensure that natural gas is acquired, stored and delivered safely, reliably and efficiently. Given recent high-profile natural gas explosions, leaks and accidents in other parts of the country involving both distribution systems and storage facilities, we anticipate that the natural gas industry may be the subject of even greater federal, state and local regulatory oversight. 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 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 18 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 2015, 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 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. The recent recession slowed new construction. While construction has resumed, it has not returned to its original pace and has been heavily multi- family, which is a segment that has historically used natural gas less frequently. 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 19 conditions, technology, environmental impacts and public perception. Technological improvements in other energy sources such as heat pumps, batteries or other alternative technologies could erode our competitive advantage. If natural gas prices rise relative to other energy sources, or if the cost, environmental impact or public perception of such other energy sources improves relative to natural gas, it may negatively affect our ability to attract new customers or retain our existing residential, commercial and industrial customers, which could have a negative impact on our customer growth rate and results of operations. RELIANCE ON THIRD PARTIES TO SUPPLY NATURAL GAS RISK. We rely on third parties to supply the natural gas in our distribution segment, and limitations on our ability to obtain supplies, or failure to receive expected supplies for which we have contracted, could have an adverse impact on our financial results. Our ability to secure natural gas for current and future sales depends upon our ability to purchase and receive delivery of supplies of natural gas from third parties. We, and in some cases, our suppliers of natural gas do not have control over the availability of natural gas supplies, competition for those supplies, disruptions in those supplies, priority allocations on transmission pipelines, or pricing of those supplies. Additionally, third parties on whom we rely may fail to deliver gas for which we have contracted. If we are unable 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 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. 20 Furthermore, we rely on information technology systems in our operations of our distribution and storage operations. There are various risks associated with these systems, including, hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other inadvertent errors or deliberate human acts. In particular, cyber security attacks, terrorism or other malicious acts could damage, destroy or disrupt all of our business systems. Any failure of information technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. As these potential cyber security attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems or obtain specific insurance coverage against potential losses. Risks Related Primarily to Our Gas Storage Businesses LONG-TERM LOW OR STABILIZATION OF GAS PRICE RISK. Any significant stabilization of natural gas prices or long- term low gas prices could have a negative impact on the demand for our natural gas storage services, which could adversely affect our financial results. Storage businesses benefit from price volatility, which impacts the level of demand for services and the rates that can be charged for storage services. Largely due to the abundant supply of natural gas made available by hydraulic fracturing techniques, natural gas prices have dropped significantly to levels that are near historic lows. If prices and volatility remain low or decline further, then the demand for storage services, and the prices that we will be able to charge for those services, may decline or be depressed for a prolonged period of time. Prices below the costs to operate the storage facility could result in a decision to shut in all or a portion of the facility. A sustained decline in these prices or a shut-in of all or a portion of the facility could have an adverse impact on our financial condition, results of operations and cash flows. NATURAL GAS STORAGE COMPETITION RISK. Increasing competition in the natural gas storage business could reduce the demand for our storage services and drive prices down for storage, which could adversely affect our financial condition, results of 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. 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 eliminated all remaining known 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. IMPAIRMENT OF LONG-LIVED ASSETS RISK. If storage pricing does not improve, or higher value customers are not obtained, our Gill Ranch storage asset may be impaired, which could have a material effect on our financial condition, or results of operations. We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets might not be recoverable. The determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected cash flows depend on the future operating costs associated with the asset, storage pricing, the ability to contract with higher value customers, and the future market and price for gas storage over the remaining life of the asset. Sustained low gas storage prices, the failure to contract with higher value customers, or operating costs that are above revenues from the facility could result in an impairment of the carrying value of our Gill Ranch storage facility. Similarly, if we were to determine to sell the Gill Ranch storage facility, such determination may result in an impairment of the carrying value of the facility. Any impairment charge taken by the Company with respect to its long-lived assets, including Gill Ranch, could be material to the quarter that the charge is taken and could otherwise have a material effect on the Company’s financial condition, and results of operations. THIRD-PARTY PIPELINE RISK. Our gas storage businesses depend on third-party pipelines that connect our storage facilities to interstate pipelines, the failure or unavailability of which could adversely affect our financial condition, results of operations and cash flows. Our gas storage facilities are reliant on the continued operation of a third-party pipeline and other facilities that provide delivery options to and from our storage facilities. Because we do not own all of these pipelines, their operations are not within our control. If the third-party pipeline to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the infrastructure, lack of capacity or other reasons, our ability to operate efficiently and satisfy our customers’ needs could be compromised, thereby potentially having an adverse impact on our financial condition, results of operations and cash flows. ITEM 1B. UNRESOLVED STAFF COMMENTS We have no unresolved comments. 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 21 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is listed and trades on the New York Stock Exchange under the symbol NWN. The high and low trades for our common stock during the past two years were as follows: Quarter Ended March 31 June 30 September 30 December 31 2015 2014 High Low High Low $ 52.25 $ 43.35 $ 44.09 $ 49.77 46.74 51.85 41.32 42.00 45.03 47.32 47.50 52.57 40.05 43.06 41.81 42.29 The closing price for our common stock on December 31, 2015 and 2014 was $50.61 and $49.90, respectively. As of February 19, 2016, there were 5,697 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 February 15 May 15 August 15 November 15 Total per share 2015 2014 $ $ 0.4650 $ 0.4650 0.4650 0.4675 1.8625 $ 0.460 0.460 0.460 0.465 1.845 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, 2015: Period Balance forward 10/01/15-10/31/15 11/01/15-11/30/15 12/01/15-12/31/15 Total Issuer Purchases of Equity Securities 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) 2,124,528 $ 16,732,648 3,279 $ 26,594 1,204 31,077 47.12 46.37 48.27 46.52 — — — — — — 2,124,528 $ 16,732,648 (1) During the quarter ended December 31, 2015, 26,529 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 4,548 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, 2015, 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, 2016 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, 2015, 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. 22 ITEM 6. SELECTED FINANCIAL DATA In thousands, except share data 2015 2014 2013 2012 2011 Operating revenues Net income $ 723,791 $ 754,037 $ 758,518 $ 730,607 $ 828,055 53,703 58,692 60,538 58,779 63,044 For the year ended December 31, Earnings per share of common stock: Basic Diluted Dividends paid per share of common stock $ 1.96 $ 2.16 $ 2.24 $ 2.19 $ 1.96 1.86 2.16 1.85 2.24 1.83 2.18 1.79 2.36 2.36 1.75 Total assets, end of period $ 3,076,692 $ 3,064,945 $ 2,970,911 $ 2,813,120 $ 2,742,718 Total equity Long-term debt 780,972 576,700 767,321 621,700 751,872 681,700 729,627 691,700 712,158 641,700 23 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, 2015, 2014, and 2013. References in this discussion to "Notes" are to the Notes to Consolidated Financial Statements in Item 8 of this report. The consolidated financial statements include NW Natural and its direct and indirect wholly-owned subsidiaries including: • NW Natural Energy, LLC (NWN Energy); • NW Natural Gas Storage, LLC (NWN Gas Storage); • Gill Ranch Storage, LLC (Gill Ranch); • NNG Financial Corporation (NNG Financial); • Northwest Energy Corporation (Energy Corp); 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 the results of operations and earnings amounts in total, certain financial measures are expressed in cents per share or exclude the after-tax regulatory disallowance related to the OPUC's 2015 environmental order, which are non-GAAP financial measures. We present net income and earnings per share (EPS) excluding the regulatory disallowance along with the U.S. GAAP measures to illustrate the magnitude of this disallowance on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income and earnings per share under U.S. GAAP, we believe the amount and nature of such disallowance make period to period comparisons of operations difficult or potentially confusing. Financial measures are expressed in cents per share as these amounts reflect factors that directly impact earnings, including income taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such non-GAAP financial measures to analyze our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations. 24 EXECUTIVE SUMMARY We manage our business and strategic initiatives with a long-term view of providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2016 Outlook" below for more information. Highlights for the year include: • steady annual customer growth rate at the core utility of 1.4% at December 31, 2015; increased new meter sets installed to approximately 11,000, which is nearly 4% higher than the prior year; invested $118.3 million in our distribution system and facilities including $19.9 million on SIP, allowing us to • • • • • • complete our bare steel replacement; continued to make progress on our North Mist gas storage expansion project; decreased residential customer rates approximately 7% in Oregon and 14% in Washington with the 2015-16 PGA effective November 1, 2015; ranked first in residential customer satisfaction for large gas utilities in the West in the 2015 J.D. Power and Associates Study, making 2015 the 14th consecutive year of top three rankings; and increased our dividend, marking the 60th consecutive year of increases. Key financial highlights include: In millions, except per share data Amount Per Share Amount Per Share Amount Per Share 2015 2014 2013 Consolidated net income Adjustments: $ 53.7 $ 1.96 $ 58.7 $ 2.16 $ 60.5 $ 2.24 Regulatory environmental disallowance, net of taxes $5.9(1) 9.1 0.33 — — — — Adjusted consolidated net income(1) Utility margin Gas storage operating revenues ROE $ $ 62.8 $ 2.29 $ 58.7 $ 2.16 371.4 21.4 6.9% $ 366.1 22.2 7.7% $ $ 60.5 $ 2.24 353.9 31.1 8.2% Adjusted ROE(1) (1) Regulatory environmental disallowance of $15 million is recorded in utility operations and maintenance expense. Adjusted EPS, net 8.1% 8.2% 7.7% income, and ROE are non-GAAP financial measures based on the after-tax disallowance. EPS is calculated using the combined federal and state statutory tax rate of 39.5% and 27.4 million diluted shares for the year ended December 31, 2015. 2015 COMPARED TO 2014. Overall, consolidated net income decreased $5.0 million. The decrease was primarily due to the $9.1 million after-tax charge related to the regulatory disallowance associated with a February 2015 OPUC Order in our SRRM docket. Under the Order, we were required to forego collection of $15 million, pre-tax, out of the approximate $95 million of environmental expenditures and associated carrying costs deferred through 2012. This charge is reflected in operations and maintenance expense. Excluding the charge, net income increased $4.1 million primarily due to the following factors: • a $5.3 million increase in utility margin primarily due to customer growth and gas cost sharing, offset by the effects of warmer weather; a $0.9 million decrease in gas storage operating revenues as storage was negatively impacted by a decrease in storage prices between the 2013-14 and 2014-15 gas years; a $5.8 million increase in other income, net related to the recognition of equity earnings on deferred regulatory asset balances as a result of the OPUC SRRM Order; a $5.5 million increase in operations and maintenance expense mainly due to higher compensation and benefits expense; and a $1.7 million increase in depreciation and amortization expenses due to additional utility capital expenditures. • • • • During 2015, management implemented temporary cost saving initiatives to mitigate the effects of warm weather and the $15 million regulatory disallowance. These initiatives resulted in approximately $5 million of operations and maintenance expense savings that are not expected to be repeated in the future. 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, net due to lower interest income on net deferred regulatory balances. • • • 25 2016 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 2016 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 Ensure Safety and Reliability Grow Our Businesses 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 2016, 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. Projects planned for 2016 include infrastructure investments in high-growth areas such as Clark County, Washington, refurbishing our LNG facilities, and continuing to prepare for large-scale emergency events such as an earthquake. In addition, we will remain proactive regarding investments in computer systems and cybersecurity infrastructure. 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. In 2016, we will be evaluating our future rate case needs in Oregon and Washington, progressing open dockets from 2015, and we will also update our Integrated Resource Plan focusing on investments needed to support the growth in our region. Finally, we will work with regulators to further our shared commitment to the environment with continued efforts around the carbon solutions programs and providing gas to rural communities. 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. In 2016, we will continue to play an active role in shaping energy policies and programs, which reflect the interests of our customers, including progressing CNG transportation initiatives and working on legislation that supports making natural gas available to rural communities. In addition, we are working hard with other potentially responsible parties to make progress with the EPA on a solution to ensure the Portland Harbor Superfund Site cleanup is done in a smart, cost effective, and responsible way. UTILITY CUSTOMERS. We intend to capitalize on natural gas as a preferred energy choice in our service territory by creating a comprehensive marketing program for rental projects that further our penetration in the residential multi- family housing sector. In addition, we remain focused on supporting single-family and commercial markets to grow our customer base. 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. KEY UTILITY INVESTMENTS. Investing in new infrastructure, operating efficiencies, and marketing opportunities position our core business for growth now and well into the future. 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 2016, will be working closely with the Oregon Energy Siting Facilities Council to finalize the cost estimates and receive a notice to proceed. We expect construction to begin in 2016 with an in-service date in the winter of 2018-19. NON-UTILITY INITIATIVES. We remain focused on creating value in our non-utility gas storage business, working to identify and contract with higher value customers and position ourselves for longer-term improvement in the California storage markets. We believe the state’s renewable energy policies could strategically shift the value of gas storage in California in the future. 26 DIVIDENDS Dividend highlights include: Per common share Dividends paid 2015 2014 2013 $ 1.86 $ 1.85 $ 1.83 The Board of Directors declared a quarterly dividend on our common stock of $0.4675 cents per share, payable on February 12, 2016, to shareholders of record on January 29, 2016, reflecting an indicated annual dividend rate of $1.87 per share. 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 2015, 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. They are also affected by the local economies in Oregon and Washington, the pace of customer growth in the residential, commercial, and industrial markets, and our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs in utility plant and other regulatory assets. See "Most Recent General Rate Cases" below. GAS STORAGE. Our gas storage business is subject to regulation by the OPUC, WUTC, CPUC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities 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 2015, approximately 72% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 28% 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. Regulatory Proceeding Updates During 2015, we were involved in the regulatory activity discussed below. ENVIRONMENTAL COST DEFERRAL AND SITE REMEDIATION AND RECOVERY MECHANISM (SRRM). In February 2015, the OPUC issued an Order regarding the SRRM for recovering prudently incurred environmental site remediation costs through customer billings, subject to an earnings test. The OPUC Order found the following: (1) prudence of all but $33 thousand of costs incurred through March 31, 2014; (2) prudence of approximately $150 million of insurance settlement proceeds, with one-third of the proceeds applied to costs prior to December 31, 2012 and two-thirds to offset future environmental expenses over the next 20 years; (3) the disallowance of $15 million out of approximately $95 million of environmental remediation expenses we had deferred from 2003 to 2012 based on the OPUC’s determination of how an earnings test should have applied during that period; which resulted in a non-cash $15 million before tax expense recognized in the first quarter 2015; (4) how the SRRM recovery mechanism would allow recovery of past and future environmental costs; and (5) an OPUC review of the SRRM following its third year of operation. This Order also required us to submit a compliance filing demonstrating how we would implement the Commission’s determinations. We submitted the required compliance filing demonstrating the proposed implementation of the Order and SRRM. In September 2015, the OPUC ordered we would not be required to establish a secure account for the insurance proceeds, rather we would defer proceeds to a regulatory liability account until utilized, and we would accrue interest to rate payers' benefit at a rate equal to the five-year treasury rate plus 100 basis points. See "Rate Mechanisms —Environmental Cost Deferral and SRRM", Note 15 and Note 16. On January 27, 2016, the OPUC issued an Order addressing the remaining outstanding issues in the compliance filing. See Note 16 regarding this subsequent event. 27 GAS RESERVES. We filed with the OPUC in February 2015 seeking cost recovery on additional investments in gas reserves. In September 2015, the OPUC adopted an all- party settlement. See "Rate Mechanisms—Gas Reserves" below and Note 11. PREPAID PENSION ASSET. In August 2015, the OPUC issued the final Order related to this docket, which confirmed the use of accounting expense for recovery of pension costs, but denied the utilities' request to recover the financing costs associated with funding our pension plans in advance of expense recognition. Although we will not recover the financing costs associated with funding our plans, we will continue collecting pension expense based on the amounts set in our 2003 Oregon general rate case and will continue deferring the difference between actual pension expense and collected expense in our pension balancing account. See "Rate Mechanisms—Pension Cost Deferral and Pension Balancing Account" below. SYSTEM INTEGRITY PROGRAM (SIP). We filed a request to extend the SIP program in the fourth quarter of 2014. The OPUC considered our renewal request at a public meeting in March 2015 and suspended our filing and ordered additional process, including involvement of other gas utilities in the state, before making a final decision. See "Rate Mechanisms—System Integrity Program" below. HEDGING. In our most recent Integrated Resource Plan, we proposed to the OPUC that we engage in continued long- term gas hedging. The OPUC determined it wanted to consider long-term hedging along with a general review of overall hedging practices among all gas utilities in the state. The OPUC therefore opened a new docket to discuss broader gas hedging practices across gas utilities in Oregon. Our request for the OPUC to consider long-term hedging practices will be considered as part of this docket. The OPUC established that this docket will follow two phases. The first phase will be focused on an analytical review of hedging and hedging practices, followed by a second phase regarding potential hedging guidelines. After these phases, a status report will be submitted to the OPUC, and the remainder of the process will be determined at that time. INTERSTATE STORAGE SHARING. We received an Order from the OPUC in March 2015 on their review of the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. The Order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket. CARBON SOLUTIONS PROGRAM. Oregon Senate Bill 844 (SB 844) required the OPUC to develop rules and programs to reduce carbon emissions in Oregon. In June 2015, we submitted our first project related to Combined Heat and Power (CHP) for OPUC approval. The submitted CHP program would pay owners of new commercial- and industrial-scale CHP systems for verified carbon emission reductions. A final decision regarding CHP is expected in the first half of 2016. WEATHER NORMALIZATION MECHANISM (WARM). In Oregon, WARM is applied to residential and commercial customers' bills to adjust for temperature variances from average weather. In 2015, the OPUC initiated a review of the WARM mechanism as a result of customer complaints received this year related to surcharges applied under the WARM mechanism due to the record warm weather in our service territory during the 2014-15 winter. The OPUC review is focused on ensuring the calculations were done correctly, and to assess whether any modifications to the mechanism are necessary. Based on the scope of this proceeding established by the Commission, we do not expect this proceeding to significantly reduce the value WARM provides to us or our customers in mitigating the impact from variations in weather. Since its inception, WARM has resulted in a net benefit to customers, providing customer bill savings of approximately $9.9 million as of the end of the most recent heating season. 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, temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year. 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 2015-16 gas year (November 1, 2015 - October 31, 2016) hedged at 75% of our forecasted sales volumes, including 44% in financial swap and option contracts and 31% in physical gas supplies. For further discussion see "Regulatory Matters—Rate Mechanisms— Purchased Gas Adjustment" above. In addition to the amount hedged for the current gas contract year, we are also hedged in future years at approximately 16% for the 2016-17 gas year and between 5% and 14% for annual requirements over the following five gas years as of December 31, 2015. 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 with storage expansion, changes in storage contracts with third parties, and/or storage recall by the utility. Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year 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. For the 2014-15 and 2015-16 gas years, we selected the 90% and 80% deferral option, respectively. Under the Washington PGA mechanism, we defer 100% of the higher 28 or lower actual gas costs, and those gas cost differences are passed on to customers through the annual PGA rate adjustment. We filed our PGA in September 2015 and received OPUC and WUTC approval in October 2015. PGA rate changes were effective November 1, 2015. The rate changes decreased the average monthly bills of residential customers by approximately 7% and 14% in Oregon and Washington, respectively. The decrease in Oregon reflected customers' portion of adjustments for changes in wholesale natural gas costs, offset by adjustments related to the decoupling mechanism, environmental costs, and additional annual adjustments based on ongoing orders with the OPUC. Washington rates reflected the full effect of changes in wholesale natural gas costs and some additional annual adjustments based on ongoing orders with the WUTC. EARNINGS TEST REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE threshold. If utility earnings exceed a specific ROE level, then 33% of the amount above that level is required to be deferred or refunded to customers. Under this provision, if we select the 80% deferral gas cost option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90% deferral option for the 2013-14 and 2014-15 PGA years, and we selected the 80% deferral option for the 2015-16 PGA year. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2013, 2014, and 2015, the ROE threshold was 10.58%, 10.66%, and 10.60%, respectively. There were no refunds required for 2013 and 2014. We do not expect a refund for 2015 based on our results and anticipate filing the 2015 test in May 2016. GAS RESERVES. In 2011 the OPUC approved the Encana gas reserves transaction to provide long-term gas price protection for our utility customers and determined our costs under the agreement would be recovered, on an ongoing basis through our annual PGA mechanism. Gas produced from our interests is sold at then prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to our cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return and provides long-term price protection for our utility customers. In March 2014, we amended the original gas reserves agreement in response to Encana's sale of its interest in the Jonah field located in Wyoming to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field and we retained the right to invest in new wells with Jonah Energy. 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 and may have the 29 opportunity to participate in more wells in the future. We filed an application requesting regulatory deferral in Oregon for these additional investments, which was granted in April 2015. In September 2015, the OPUC adopted an all-party settlement, under which volumes produced under the amended agreement are included in our Oregon PGA beginning November 1, 2015 at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment. DECOUPLING. In Oregon, we have a decoupling mechanism. Decoupling is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy. The Oregon decoupling mechanism was reauthorized and the baseline expected usage per customer was set in the 2012 Oregon general rate case. This mechanism employs a use-per-customer decoupling calculation, which adjusts margin revenues to account for the difference between actual and expected customer volumes. The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the annual PGA filing. In Washington, customer use is not covered by such a tariff. 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, 2015, 9% of total customers had opted out. We do not have a weather normalization mechanism approved for residential and commercial Washington customers, which account for about 11% of total customers. See "Business Segments—Local Gas Distribution Utility Operations" below. INDUSTRIAL TARIFFS. The OPUC and WUTC have approved tariffs covering utility service to our major industrial customers, 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). In the past, we have had the approval of the OPUC for specific accounting treatment and cost recovery for our SIP, which is an integrated safety program that consolidates the bare steel replacement program, the transmission pipeline integrity management program, and the distribution integrity management program related to pipeline safety rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). We recorded these costs as capital expenditures, 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 the first $4 million of capital costs subject to regulatory lag and annual rate-base recovery capped at $12 million. Costs above the cap could also be approved with written consent of the OPUC staff and other interested parties and approval of the OPUC. During 2013, the OPUC approved a temporary two-year extension, beginning in November 2012, of our capital expenditure tracking mechanism to recover capital costs related to SIP and authorized a total increase of $13.7 million above the cap during the extension period. Regulatory authority for SIP expired October 31, 2014, although the bare steel replacement portion of the mechanism remained in place until the end of 2015. We filed a request to extend the SIP program in the fourth quarter of 2014 and upon consideration of our request in March of 2015, the OPUC ordered an additional process and evaluation with other gas utilities in the state before making a final decision. In the interim, we will recover our remaining bare steel replacement costs through the 2015-16 PGA, and we expect system integrity capital costs not tracked through our SIP mechanism would be included in rate base in our next rate case. ENVIRONMENTAL COST DEFERRAL AND SRRM. In Oregon, we have a SRRM through which we track and have the ability to recover prudently incurred past deferred and future environmental remediation costs allocable to Oregon, subject to an earnings test. The SRRM defines three classes of deferred environmental remediation expense: • Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. We anticipate the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We • • included $8.4 million of deferred remediation expense approved by the OPUC for collection during the 2015-2016 PGA year. The earnings test is an annual review of our adjusted Utility ROE compared to our authorized Utility ROE, which is currently 9.5%. To apply the earnings test first we must determine what if any costs are subject to the test through the following calculation: Annual spend Less: $5 million base rate rider(1) Prior year carry-over(2) $5 million insurance + interest on insurance Total deferred annual spend subject to earnings test Less: over-earnings adjustment, if any Add: deferred interest on annual spend(3) Total amount transferred to post-review (1) Base rate rider went into Oregon customer rates beginning November 1, 2015. (2) Prior year carry-over results when the prior year amount transferred to post-review is negative. The negative amount is carried over to offset annual spend in the following year. (3) Deferred interest is added to annual spend to the extent the spend is recoverable. If the adjusted Utility ROE is greater than the authorized Utility ROE, then we could be required to expense up to the amount that results in the Utility earning its authorized ROE. For 2015, we have performed this test, which will be submitted to the OPUC in May 2016, and have concluded that there is no earnings test adjustment for 2015. The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This Order was effective in January 2011 with cost recovery and a carrying charge to be determined in a future proceeding. PENSION COST DEFERRAL AND PENSION BALANCING ACCOUNT. 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, including interest, were $8.2 million, $4.6 million, and $9.1 million in 2015, 2014 and 2013, respectively. See "Application of Critical Accounting Policies and Estimates" below. 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 earned from Mist gas storage and asset management activities. Generally amounts are credited to Oregon customers in June, while credits are given to customers in Washington through 30 reductions in rates through the annual PGA filing in November. The following table presents the credits to customers: In millions Oregon utility customer credit Washington utility customer credit 2015 2014 2013 $ 9.6 $ 11.4 $ 0.8 0.8 8.8 0.5 Business Segments - Local Gas Distribution Utility Operations Utility margin results are primarily affected by customer growth, revenues from rate-base additions, and, to a certain extent, by changes in delivered volumes due to weather and customers’ gas usage patterns because a significant portion of our utility margin is derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff (also called the decoupling mechanism), which adjusts utility margin up or down each month through a deferred regulatory accounting adjustment designed to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, which adjusts customer bills up or down to offset changes in utility margin resulting from above- or below- average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of customer bills and our utility’s earnings. See "Regulatory Matters—Rate Mechanisms" above. Utility segment highlights include: Dollars and therms in millions, except EPS data 2015 2014 2013 Utility net income $ 53.4 $ 58.6 $ EPS - utility segment 1.95 2.15 54.9 2.03 Gas sold and delivered (in therms) Utility margin(1) 353.9 (1) See Utility Margin Table below for a reconciliation and additional 1,146 1,029 371.4 1,093 366.1 $ $ $ detail. 2015 COMPARED TO 2014. The primary factors contributing to the $5.2 million or $0.20 per share decrease in utility net income were as follows: • the $15 million pre-tax charge, or $9.1 million after-tax charge, for the regulatory disallowance associated with the February 2015 OPUC Order on the recovery of past environmental cost deferrals. This charge is reflected in operations and maintenance expense; a $5.3 million increase in utility margin primarily due to: a $4.4 million increase from customer growth; a $5.3 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; partially offset by • an approximate $4.0 million decrease due to lower customer usage from warmer weather, which impacts utility margins from our Washington customers where we do not have a weather normalization mechanism in place, and from our Oregon customers who opted out of weather normalization. a $6.6 million increase in other income, net, primarily due to the recognition of the equity earnings on deferred environmental expenditures as a result of the February order; a $7.2 million increase in operations and maintenance expense, excluding the environmental disallowance, primarily due to an increase in compensation and benefit expense; and a net $0.4 million increase in other expenses related to increased depreciation expense from additional capital investments and an increase in general taxes from higher Oregon property tax expense, offset by a decrease in interest expense due to debt redemptions made during the year. • • • Total utility volumes sold and delivered in 2015 decreased 6% over 2014 primarily due to the impact of warmer weather. 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 a $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 $3.0 million decrease in operations and maintenance expense; and a $2.1 million decrease in other income, 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. 31 UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales: In thousands, except degree day and customer data 2015 2014 2013 Utility volumes (therms): Residential and commercial sales Industrial sales and transportation 570,728 457,884 620,903 472,087 671,906 474,525 Total utility volumes sold and delivered 1,028,612 1,092,990 1,146,431 Favorable/(Unfavorable) 2015 vs. 2014 2014 vs. 2013 (50,175) (14,203) (64,378) (51,003) (2,438) (53,441) Utility operating revenues: Residential and commercial sales Industrial sales and transportation Other revenues Less: Revenue taxes Total utility operating revenues Less: Cost of gas Less: Environmental remediation expense Utility margin Utility margin:(1) Residential and commercial sales Industrial sales and transportation Miscellaneous revenues Gain (loss) from gas cost incentive sharing Other margin adjustments Utility margin Degree days Average(2) Actual Percent colder (warmer) than average weather(2) Customers - end of period: Residential customers Commercial customers Industrial customers $ 644,835 $ 672,440 $ 673,250 $ (27,605) $ (810) 71,495 3,914 18,034 702,210 327,305 3,513 73,992 3,983 18,837 731,578 365,490 — 68,880 4,054 19,002 727,182 373,298 — $ 371,392 $ 366,088 $ 353,884 $ 334,134 $ 334,247 $ 321,608 30,081 3,913 3,182 82 29,982 4,329 (2,135) (335) 28,335 4,308 (41) (326) (2,497) 5,112 (69) (803) (29,368) 38,185 (3,513) (71) (165) 4,396 7,808 — $ $ 5,304 $ 12,204 (113) $ 12,639 99 (416) 5,317 417 1,647 21 (2,094) (9) $ 371,392 $ 366,088 $ 353,884 $ 5,304 $ 12,204 4,240 3,458 4,240 3,792 4,240 4,379 — (9)% — (13)% (18)% (11)% 3% 646,841 637,411 66,584 1,003 66,304 929 628,634 65,321 918 9,430 8,777 280 74 983 11 Total number of customers 714,428 704,644 694,873 9,784 9,771 Customer growth: Residential customers Commercial customers Industrial customers Total customer growth 1.5 % 0.4 % 8.0 % 1.4 % 1.4 % 1.5 % 1.2 % 1.4 % (1) Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas and environmental remediation expense. (2) Average weather represents the 25-year average degree days, as determined in our 2012 Oregon general rate case. 32 Residential and Commercial Sales The primary factors that impact results of operations in the residential and commercial markets are customer growth, seasonal weather patterns, energy prices, competition from other energy sources, and economic conditions in our service areas. The impact of weather on margin is significantly reduced through our weather normalization mechanism in Oregon; approximately 80% of our total customers are covered under this mechanism. The remaining customers either opt out of the mechanism or are located in Washington, which does not have a similar mechanism in place. For more information on our weather mechanism, see "Regulatory Matters—Rate Mechanisms— Weather Normalization Tariff" above. Residential and commercial sales highlights include: In millions Volumes (therms): Residential sales Commercial sales Total volumes Operating revenues: 2015 2014 2013 350.9 219.8 570.7 381.5 239.4 620.9 418.6 253.3 671.9 Residential sales $ 424.6 $ 441.5 $ 447.4 Commercial sales 220.2 230.9 225.9 Total operating revenues Utility margin: Residential: Sales Weather normalization Decoupling Total residential utility margin Commercial: Sales Weather normalization Decoupling Total commercial utility margin $ 644.8 $ 672.4 $ 673.3 $ 211.6 $ 223.6 $ 234.1 14.0 7.2 5.1 4.0 (9.0) 2.6 232.8 232.7 227.7 84.8 5.8 10.7 91.6 2.2 7.7 92.1 (4.0) 5.8 101.3 101.5 93.9 Total utility margin $ 334.1 $ 334.2 $ 321.6 2015 COMPARED TO 2014. The primary factors contributing to changes in the residential and commercial markets were as follows: • sales volumes decreased 50.2 million therms, or 8%, primarily reflecting 9% warmer weather, which was partially offset by customer growth; operating revenues decreased $27.6 million, due to the 8% decrease in sales volumes, as well as a 2% decrease in average gas rates over last year; and utility margin decreased $0.1 million, due to warmer weather, almost entirely offset by increases from commercial and residential customer growth. • • 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 • 33 • • 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. 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 on November 1, 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 Volumes (therms): 2015 2014 2013 Industrial - firm sales 32.4 34.0 34.3 Industrial - firm transportation Industrial - interruptible sales Industrial - interruptible transportation Total volumes Utility margin: Industrial - sales and transportation 144.0 153.6 144.5 70.2 76.4 59.5 211.3 457.9 208.1 472.1 236.2 474.5 $ 30.1 $ 30.0 $ 28.3 2015 COMPARED TO 2014. The primary factors contributing to changes in the industrial sales and transportation markets were as follows: • sales and transportation volumes decreased by 14.2 million therms due to lower usage from warmer weather and lower demand from a few large volume transportation customers on lower margin rate schedules; utility margin increased $0.1 million, primarily due to an increase in industrial customers under higher margin rate schedules partially offset by higher fee revenue in the prior year from increased usage during the cold weather event in February 2014. 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. • 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 for 2015, 2014, and 2013 remained flat year- over-year as expected. In millions 2015 2014 2013 Other revenues $ 3.9 $ 4.0 $ 4.1 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 reserves 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 which has been described under "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" above. In addition to the PGA incentive sharing mechanism, gains and losses from hedge contracts entered into after annual PGA rates are effective for Oregon customers are also required to be shared and therefore may impact net income. Further, we also have a regulatory agreement whereby we earn a rate of return on our investment in the gas reserves acquired under the original agreement with Encana and include gas from our amended gas reserves agreement at a fixed rate of $0.4725 per therm, which are also reflected in utility margin. See "Application of Critical Accounting Policies and Estimates— Accounting for Derivative Instruments and Hedging Activities" below. Cost of gas highlights include: Dollars and therms in millions 2015 2014 2013 Cost of gas $ 327.3 $ 365.5 $ 373.3 Volumes sold (therms) 660 716 766 Average cost of gas (cents per therm) Gain (loss) from gas cost incentive sharing $ 0.50 $ 0.51 $ 0.49 3.2 (2.1) — 2015 COMPARED TO 2014. Cost of gas decreased $38.2 million, or 10% primarily due to an 8% decrease in sales volume reflecting warmer weather during the year as well as a 2% decrease in average cost of gas reflecting lower market prices for natural gas. 2014 COMPARED TO 2013. 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. During the extreme cold weather event in February 2014, we experienced a record sendout and consequently, the higher volumes of gas purchased at that time resulted in a margin loss of $2.1 million in 2014 compared to a margin gain of $3.2 million for 2015 as prices were lower due to the record warmer weather, particularly in the first quarter of 2015. The effect on net income from our gas cost incentive sharing mechanism for 2013 was a pre-tax loss in margin of less than $0.1 million. 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% undivided 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 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. 34 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 also Note 4. Gas storage segment highlights include: In millions, except EPS data Gas storage net income (loss) EPS - gas storage segment Operating revenues Operating expenses 2015 2014 2013 $ 0.2 $ (0.4) $ 5.6 0.01 21.4 16.3 (0.01) 22.2 18.2 0.21 31.1 16.4 2015 COMPARED TO 2014. Our gas storage segment net income increased $0.6 million primarily due to the following offsetting factors: • a $0.9 million decrease in operating revenues, primarily due to a decrease in storage prices between the 2013-14 and 2014-15 gas storage years; and a $1.9 million decrease in operating expenses primarily due to lower repair and power costs at our Gill Ranch facility. • 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. • Our Mist gas storage facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location. 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 during the 2013-14 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 lower market prices than in previous years. These trends accounted for most of the decline in gas storage operating revenues. Prices for the 2015-16 and 2016-17 gas years have shown improvement, however remain low relative to the pricing in our original long-term contracts, which ended primarily in the 2013-14 gas storage year. In the future, we may see an improvement in gas storage values and an increase in the 35 demand for natural gas driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, an increase in use of alternative fuels to meet carbon 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 storage market conditions in and around California. These factors, if they occur, may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. We are continuing to explore opportunities to increase revenues through enhanced services for storage customers and capitalizing on opportunities that fit our business-risk profile. Should storage values not improve in the future, this could have a negative impact on our future cash flows and could result in impairment of our Gill Ranch gas storage facility. 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 has invested in the Trail West pipeline project, and other miscellaneous non-utility investments and business activities. There were no significant changes in our other activities in 2015. See Note 4 and Note 12 for further details on other activities and our investment in TWH. Consolidated Operations Operations and Maintenance Operations and maintenance highlights include: In millions 2015 2014 2013 Operations and maintenance $ 157.5 $ 137.0 $ 136.6 2015 COMPARED TO 2014. Operations and maintenance expense increased $20.5 million, primarily due to the following factors: • the $15 million pre-tax charge for the regulatory disallowance associated with the February 2015 OPUC Order on the recovery of past environmental cost deferrals. We also expensed an additional $1 million related to the Order; and a $5.5 million increase in compensation and benefit expense, including increased employee incentive expense, retirement expense, and health care costs, as well as higher wage rates under the new union labor contract, which became effective June 1, 2014; offset by a $1.9 million decrease primarily related to 2014 repair and power costs at our Gill Ranch gas storage facility. • • During 2015, management implemented temporary cost saving initiatives to mitigate the effects of warm weather and the $15 million regulatory disallowance. These initiatives resulted in approximately $5 million of operations and maintenance expense savings that are not expected to be repeated in the future. 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. • • • Other Income, Net Other income, net highlights include: In millions 2015 2014 2013 Gains from company- owned life insurance $ Interest income Loss from equity investments Net interest income on deferred regulatory accounts Other non-operating $ 2.2 0.1 $ 2.0 0.1 2.5 0.1 (0.1) (0.2) (0.1) 8.2 (2.7) 2.4 (2.4) 4.5 (2.3) 4.7 Total other income, net $ 7.7 $ 1.9 $ Delinquent customer receivable balances continue to remain at historically low levels. The utility's bad debt expense as a percent of revenues was 0.1% for 2015 and 2014. 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 years ended December 31, 2015, 2014 and 2013 we deferred pension expenses totaling $8.2 million, $4.6 million and $9.1 million, respectively. As a result, increased pension costs had a minimal effect on operations and maintenance expense in 2015 and 2014, 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 2015 2014 2013 Depreciation and amortization $ 80.9 $ 79.2 $ 75.9 2015 COMPARED TO 2014. Depreciation and amortization expense increased by $1.7 million due to utility plant additions that included natural gas transmission and distribution system investments and computer software. 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. 2015 COMPARED TO 2014. Other income, net, increased $5.8 million primarily due to the recognition of the equity component in interest income from our deferred environmental expenses. We realized the equity earnings of these deferred regulatory asset balances as a result of the OPUC SRRM Order we received in February 2015. 2014 COMPARED TO 2013. Other income, 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. Interest Expense, Net Interest expense, net highlights include: In millions 2015 2014 2013 Interest expense, net $ 42.5 $ 44.6 $ 45.2 2015 COMPARED TO 2014. Interest expense, net of amounts capitalized, decreased $2.1 million primarily due to the redemption of $40 million of utility First Mortgage Bonds (FMBs) in June 2015, $60 million of utility FMBs in 2014, and the retirement of $20 million of Gill Ranch's debt in June 2014. This was partially offset by the early retirement of $20 million of Gill Ranch's debt in December 2015, which included a make whole interest provision. 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. 36 Income Tax Expense Income tax expense highlights include: In millions 2015 2014 2013 Income tax expense $ 35.8 $ 41.6 $ 41.7 Effective tax rate 40.0% 41.5% 40.8% 2015 COMPARED TO 2014. The decrease in the effective income tax rate reflects the benefits of depletion deductions from our gas reserves activity. 2014 COMPARED TO 2013. The increase in the effective income tax rate was primarily the result of a $0.6 million income tax charge in 2014 related to a higher statutory tax rate in Oregon, which required the revaluation of deferred tax balances. FINANCIAL CONDITION Capital Structure One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45% to 50% common stock equity and 50% to 55% long-term and short-term debt, and with a target utility capital structure of 50% common stock and 50% long-term debt. When additional capital is required, debt or equity securities are issued depending on both the target capital structure and market conditions. These sources of capital are also used to fund long-term debt retirements and short-term commercial paper maturities. See "Liquidity and Capital Resources" below and Note 7. Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and provide access to capital markets at reasonable costs. Our consolidated capital structure was as follows: Common stock equity Long-term debt Short-term debt, including current maturities of long-term debt Total December 31, 2015 2014 47.2% 46.1% 34.9 17.9 37.4 16.5 100.0% 100.0% Liquidity and Capital Resources At December 31, 2015 we had $4.2 million of cash and cash equivalents compared to $9.5 million at December 31, 2014. We did not have restricted cash at December 31, 2015 compared to $3.0 million in restricted cash at December 31, 2014 held as collateral for the long-term debt outstanding at Gill Ranch, which we redeemed in December 2015. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances and add short-term borrowing capacity. In addition, we may also pre-fund utility capital expenditures when long-term fixed rate environments are attractive. As a regulated entity, our issuance of equity securities and most forms of debt securities are subject to approval by the OPUC and WUTC. Our use of retained earnings is not subject to those same restrictions. 37 For the utility segment, the short-term borrowing requirements typically peak during colder winter months when the utility borrows money to cover the lag between natural gas purchases and bill collections from customers. Our short-term liquidity for the utility is primarily provided by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, as well as available cash from multi-year credit facilities, short-term credit facilities, company-owned life insurance policies, and the sale of long-term debt. Utility long-term debt proceeds are primarily used to finance utility capital expenditures, refinance maturing debt of the utility, and provide temporary funding for other general corporate purposes of the utility. Based on our current debt ratings (see "Credit Ratings" below), we have been able to issue commercial paper and long-term debt at attractive rates and have not needed to borrow or issue letters of credit from our back-up credit facility. In the event we are not able to issue new debt due to adverse market conditions or other reasons, we expect our near-term liquidity needs can be met using internal cash flows or, for the utility segment, drawing upon our committed credit facility. We also have a universal shelf registration statement filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions and certain regulatory approvals. As of December 31, 2015, we have Board authorization to issue up to $325 million of additional FMBs. We also have OPUC approval to issue up to $325 million of additional long-term debt for approved purposes. In the event our senior unsecured long-term debt ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit, or other forms of collateral, which could expose us to additional cash requirements and may trigger increases in short-term borrowings while we were in a net loss position. We were not near the threshold for posting collateral at December 31, 2015. However, if the credit risk-related contingent features underlying these contracts were triggered on December 31, 2015, assuming our long-term debt ratings dropped to non-investment grade levels, we could have been required to post $21.2 million of collateral to our counterparties. See "Credit Ratings" below and Note 13. Other items that may have a significant impact on our liquidity and capital resources include pension contribution requirements, expiration of bonus tax depreciation, environmental expenditures and insurance recoveries. PENSION CONTRIBUTIONS. We expect to make significant contributions to our company-sponsored defined benefit plan, which is closed to new employees, over the next several years until we are fully funded under the Pension Protection Act rules, including the new rules issued under the Moving Ahead for Progress in the 21st Century Act (MAP-21) and the Highway and Transportation Funding Act of 2014 (HATFA). See "Application of Critical Accounting Policies—Accounting for Pensions and Postretirement Benefits" below. BONUS DEPRECIATION. Regarding income tax, 50 percent bonus depreciation was available for a large portion of our capital expenditures in 2013, 2014 and 2015 for both federal and Oregon. This generated an income tax net operating loss (NOL) in 2013, and reduced taxable income in 2014 and 2015, providing cash flow benefits. The Federal Protecting Americans From Tax Hikes Act of 2015 became law on December 17, 2015 and extended federal bonus depreciation through 2019. ENVIRONMENTAL EXPENDITURES. Concerning environmental expenditures, we expect to continue using cash resources to fund our environmental liabilities. In 2015, we received an Order from the OPUC regarding our SRRM and began recovering amounts through utility rates in November 2015. These expenditures are uncertain as to the amount and timing. See Note 15, Note 16, and "Results of Operations—Regulatory Matters—Environmental Costs" above. GAS STORAGE. Short-term liquidity for the gas storage segment is supported by cash balances, internal cash flow from operations, external financing, and equity contributions from its parent company. The amount and timing of our Gill Ranch facility's cash flows from year to year are uncertain, as the majority of these storage contracts are currently short-term. We have seen slightly higher contract prices for the 2015-16 and 2016-17 storage years, but overall prices are still lower than the long- term contracts that expired at the end of the 2013-14 storage year. While we expect continuing challenges for Gill Ranch in 2016, we do not anticipate material changes in our ability to access sources of cash for short-term liquidity. In November 2011, Gill Ranch issued $40 million of senior collateralized debt, with a fixed interest rate of 7.75% on $20 million and a variable interest rate on the remaining $20 million, with an original maturity date of November 30, 2016. Under the debt agreement, Gill Ranch was subject to certain covenants and restrictions. We amended this agreement twice, which resulted in repayment of the $20 million variable-rate outstanding debt during the second quarter of 2014, suspension of the EBITDA covenant requirement through the maturity date, and maintenance of a debt reserve account, which was fixed at $4.5 million as of June 30, 2015. In addition, under the amended agreement, Gill Ranch was required to receive common equity contributions from its parent NWN Gas Storage of at least $2 million by August 31, 2015 and complied with this requirement. On December 18, 2015, Gill Ranch repaid the $20 million of fixed-rate senior secured debt using available cash and cash flows from operations, including cash from intercompany receivables. CONSOLIDATED LIQUIDITY. Based on several factors, including our current credit ratings, our commercial paper program, current cash reserves, committed credit facilities, and our expected ability to issue long-term debt in the capital markets, we believe our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations, investing, and financing activities discussed below. DIVIDEND POLICY. We have paid quarterly dividends on our common stock each year since stock was first issued to the public in 1951. Annual common stock dividend payments per share, adjusted for stock splits, have increased each year since 1956. The declarations and amount of future dividends will depend upon our earnings, cash flows, financial condition and other factors. The amount and timing of dividends payable on our common stock is at the sole discretion of our Board of Directors. OFF-BALANCE SHEET ARRANGEMENTS. Except for certain lease and purchase commitments, we have no material off- balance sheet financing arrangements. See "Contractual Obligations" below. 38 Contractual Obligations The following table shows our contractual obligations at December 31, 2015 by maturity and type of obligation: Payments Due in Years Ending December 31, In millions 2016 2017 2018 2019 2020 Thereafter Total Short-term debt maturities $ 270.0 $ — $ — $ — $ — $ — $ Long-term debt maturities Interest on long-term debt Postretirement benefit payments(1) Capital leases Operating leases Gas purchases(2) Gas pipeline capacity commitments Other purchase commitments(3) Other long-term liabilities(4) 25.0 34.2 23.6 0.6 5.4 61.5 83.2 0.1 16.5 40.0 32.1 24.1 0.1 5.4 — 79.4 — — 22.0 29.2 25.0 — 5.3 — 75.8 — — 30.0 28.6 26.1 — 5.3 — 75.7 — — 75.0 24.4 28.4 — 2.8 — 72.1 — — 409.7 177.5 145.8 — 30.5 — 340.0 — — 270.0 601.7 326.0 273.0 0.7 54.7 61.5 726.2 0.1 16.5 Total $ 520.1 $ 181.1 $ 157.3 $ 165.7 $ 202.7 $ 1,103.5 $ 2,330.4 (1) Postretirement benefit payments primarily consists of two items: (1) estimated qualified defined benefit pension plan payments, which are funded by plan assets and future cash contributions, and (2) required payments to the Western States multiemployer pension plan due to our withdrawal from the plan in December 2013. See Note 8. (2) Gas purchases include contracts which use price formulas tied to monthly index prices. The commitment amounts presented incorporate the December 2015 first of month index price for each supply basin from which gas is purchased. For a summary of gas purchase and gas pipeline capacity commitments, see Note 14. (3) Other purchase commitments primarily consist of base gas requirements and remaining balances under existing purchase orders. (4) Other long-term liabilities includes accrued vacation liabilities for management employees and deferred compensation plan liabilities for executives and directors. The timing of these payments are uncertain; however, these payments are unlikely to all occur in the next 12 months. In addition to known contractual obligations listed in the above table, we have also recognized liabilities for future environmental remediation or action. The exact timing of payments beyond 12 months with respect to those liabilities cannot be reasonably estimated due to numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of site investigations. See Note 15 for a further discussion of environmental remediation cost liabilities. At December 31, 2015, 598 of our utility employees were members of the Office and Professional Employees International Union (OPEIU) Local No. 11. In May 2014, our union employees ratified a new labor agreement (Joint Accord) that expires on November 30, 2019. The Joint Accord includes the following items: an average annualized compensation increase of 4% effective June 1, 2014, which includes a 7.9% wage increase to better reflect current market competitive wages, offset by a reduction in bonus pay opportunities for union employees; and a scheduled 3% wage increase effective December 1 each year thereafter, beginning in 2015 with the potential for up to an additional 3% per year based on wage inflation at or above 4%. The Joint Accord also maintains competitive health benefits, including a 15% to 20% premium cost sharing by employees, job flexibility, and other flexibility provisions for the Company. Short-Term Debt Our primary source of utility short-term liquidity is from the sale of commercial paper and bank loans. In addition to issuing commercial paper or bank loans to meet working capital requirements, including seasonal requirements to finance gas purchases and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper and bank loans are periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities. See “Credit Agreements” below. In the fourth quarter of 2015, we entered into a short-term credit facility loan totaling $50 million, as a short-term bridge through our peak heating season, which was repaid on February 4, 2016. At December 31, 2015 and 2014, our utility had short-term debt outstanding of $270.0 million and $234.7 million, respectively. The effective interest rate on short-term debt outstanding at December 31, 2015 and 2014 was 0.6% and 0.4%, respectively. 39 Credit Ratings Our credit ratings are a factor of our liquidity, potentially affecting our access to the capital markets including the commercial paper market. Our credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. The following table summarizes our current debt ratings from S&P and Moody’s: Commercial paper (short-term debt) Senior secured (long-term debt) Senior unsecured (long-term debt) Corporate credit rating Ratings outlook S&P Moody's A-1 AA- n/a A+ P-2 A1 A3 n/a Stable Stable The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of or reference to these credit ratings is not a recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated independently of any other rating. Maturity and Redemption of Long-Term Debt The following debentures were retired: In millions Utility First Mortgage Bonds Years Ended December 31, 2015 2014 2013 3.95% Series B due 2014 $ — $ 8.26% Series B due 2014 4.70% Series B due 2015 Subsidiary Debt Variable-rate Fixed-rate — 40 40 — 20 60 $ $ 50 10 — 60 20 — 80 $ $ — — — — — — — Credit Agreements We have a $300 million credit agreement, with a feature that allows the Company to request increases in the total commitment amount, up to a maximum of $450 million. The maturity date of the agreement is December 20, 2019. All lenders under the agreement are major financial institutions with committed balances and investment grade credit ratings as of December 31, 2015 as follows: In millions Lender rating, by category Loan Commitment AA/Aa A/A BBB/Baa Total $ $ 234 66 — 300 Based on credit market conditions, it is possible one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency; however, we do not believe this risk to be imminent due to the lenders' strong investment-grade credit ratings. Our credit agreement permits the issuance of letters of credit in an aggregate amount of up to $100 million. Any principal and unpaid interest amounts owed on borrowings under the credit agreements is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at December 31, 2015 or 2014. The credit agreement requires us to maintain a consolidated indebtedness to total capitalization ratio of 70% or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2015 and 2014, with consolidated indebtedness to total capitalization ratios of 52.8% and 53.9%, respectively. The agreement also requires us to maintain credit ratings with Standard & Poor's (S&P) and Moody's Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings or senior secured debt ratings, as applicable, by such rating agencies. A change in our debt ratings by S&P or Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. Rather, interest rates on any loans outstanding under the credit agreements are tied to debt ratings and therefore, a change in the debt rating would increase or decrease the cost of any loans under the credit agreements when ratings are changed. See "Credit Ratings" below. 40 Cash Flows Operating Activities Changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results. Operating activity highlights include: In millions 2015 2014 2013 Cash provided by operating activities $ 184.7 $ 215.7 $ 176.4 2015 COMPARED TO 2014. The significant factors contributing to the $31.0 million decrease in operating cash flows were as follows: • a decrease of $99.4 million in deferred environmental recoveries, net of expenditures, reflecting the receipt of insurance settlements during 2014; an increase of $55.0 million from changes in deferred gas costs balances, which reflected lower actual gas prices than prices embedded in the PGA compared to the prior year; an increase of $15.0 million from regulatory disallowance of prior environmental cost deferrals in 2015; a decrease of $5.3 million from a non-cash recognition of interest income on deferred environmental expenses related to our SRRM order; a net decrease of $3.6 million from changes in working capital related to receivables, inventories and accounts payable due to warmer weather in 2015 compared to 2014; and an increase of $1.8 million from changes in regulatory balances, other assets and liabilities, and accrued taxes. 2014 COMPARED TO 2013. The significant factors contributing to the $39.3 million increase in operating cash flows were as follows: • an increase of $105.5 million in deferred environmental recoveries, net of expenditures reflecting the receipt of insurance settlements during 2014; an increase of $41.0 million from changes in the accounts receivable balance, primarily due to colder weather in December 2013. a decrease of $24.1 million from changes in inventory balances due to refilling gas storage inventory after colder weather in December 2013; a decrease of $48.1 million from changes in regulatory balances, an increase in pension liabilities, and an increase in prepaids; a decrease of $21.7 million in deferred taxes due to the utilization of NOL carryforwards; and a decrease of $17.9 million from changes in deferred gas costs balances, which reflected higher actual gas prices than prices embedded in the PGA compared to the prior year. • • • • • • • • • • During the year ended December 31, 2015, we contributed $14.1 million to our utility's qualified defined benefit pension plan, compared to $10.5 million for 2014 and $9.1 million for 2013. The amounts and timing of future contributions will 41 depend on market interest rates and investment returns on the plans’ assets. See Note 8. Bonus depreciation of 50% has been available for federal and Oregon purposes in 2013, 2014 and 2015. This generated an income tax NOL in 2013, and reduced taxable income in 2014 and 2015, providing cash flow benefits. Bonus depreciation for 2014 and 2015 was not enacted until December 19, 2014 and December 17, 2015, respectively. In both cases it was extended retroactively back to January 1 of the respective year. As a result, estimated income tax payments were made throughout 2014 and 2015 without the benefit of bonus depreciation for the year. This delayed the cash flow benefit of bonus depreciation and contributed to the income tax receivable of $7.9 million and $1.0 million as of December 31, 2015 and 2014, respectively. As a result of the Federal Protecting Americans From Tax Hikes Act of 2015, bonus depreciation is now available in years 2016 through 2019. We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations. For information on cash flow requirements related to leases and other purchase commitments, see “Financial Condition—Contractual Obligations” above and Note 14. Investing Activities Investing activity highlights include: In millions 2015 2014 2013 Total cash used in investing activities Capital expenditures Utility gas reserves $ 115.3 $ 144.3 $ 182.1 118.3 1.5 120.1 26.8 138.9 54.1 2015 COMPARED TO 2014. The $29.0 million decrease in cash used in investing activities was primarily due to lower utility gas reserves investments compared to 2014; see Note 11. 2014 COMPARED TO 2013. The $37.8 million decrease in cash used in investing activities was primarily due to lower investments in capital expenditures and utility gas reserves as NW Natural ended its original drilling program with Encana in 2014; see Note 11. Over the five-year period 2016 through 2020, total utility capital expenditures are estimated to be between $850 and $950 million, including the Company's proposed investment in an expansion of our Mist gas storage facility as well as continued refurbishments of the Newport Liquefied Natural Gas (LNG) facility in Oregon over the next three years with an expected investment of approximately $25 million, and upgrading distribution infrastructure in Clark County, Washington, which could total approximately $25 million over the next five years. The estimated level of utility capital expenditures over the next five years reflects assumptions for continued customer growth, technology investments, distribution system maintenance and improvements, and gas storage facilities maintenance. Most of the required funds are expected to be internally generated over the five- year period, and any remaining funding will be obtained through a combination of long-term debt and equity security issuances, with short-term debt and bridge financing providing liquidity. In 2016, utility capital expenditures are estimated to be between $155 and $175 million, and non-utility capital investments are estimated to be less than $5 million. Gas storage segment capital expenditures in 2016 are expected to be paid from working capital and additional equity contributions from NW Natural as needed. Financing Activities Financing activity highlights include: In millions 2015 2014 2013 Total cash (used in) provided by financing activities $ (74.7) $ (71.3) $ 6.3 Change in short-term debt Change in long-term debt 35.3 (60.0) 46.5 (80.0) (2.1) 50.0 2015 COMPARED TO 2014. The $3.4 million increase in cash used in financing activities was primarily due to redeeming $20 million less debt in 2015 compared to 2014. Offsetting this, we issued $11.2 million less of net commercial paper and short-term loans in 2015 compared to 2014. 2014 COMPARED TO 2013. The $77.6 million decrease in cash provided by financing activities was primarily due to using the proceeds from our insurance settlements of $103 million to redeem $60 million of long-term utility debt. In addition, Gill Ranch retired $20 million of variable interest rate debt. Pension Cost and Funding Status of Qualified Retirement Plans Pension costs are determined in accordance with accounting standards for compensation and retirement benefits. See “Application of Critical Accounting Policies and Estimates – Accounting for Pensions and Postretirement Benefits” below. Pension expense for our qualified defined benefit plan, which is allocated between operation and maintenance expenses, capital expenditures, and the deferred regulatory balancing account, totaled $20.8 million in 2015, an increase of $6.6 million from 2014. The fair market value of pension assets in this plan decreased to $249.3 million at December 31, 2015 from $279.2 million at December 31, 2014. The decrease was due to a loss on plan assets of $9.6 million plus $14.1 million in employer contributions, offset by benefit payments of $34.3 million. We make contributions to the company-sponsored qualified defined benefit pension plan based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our qualified defined benefit pension plan was underfunded by $162.5 million at December 31, 2015. We plan to make contributions during 2016 of $14.5 million. See Note 8 for further pension disclosures. Ratios of Earnings to Fixed Charges For the years ended December 31, 2015, 2014, and 2013, our ratios of earnings to fixed charges, computed using the method outlined by the SEC, were 3.00, 3.13, and 3.16, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. See Exhibit 12 for the detailed ratio calculation. Contingent Liabilities Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. See “Application of Critical Accounting Policies and Estimates” below. At December 31, 2015, we had a net regulatory asset of $85.9 million for deferred environmental costs, which includes deferred payments and interest of $51.8 million, $125.0 million for additional costs expected to be paid in the future, and the remaining amortization to be collected in 2016 of $6.8 million, partially offset by $96.5 million of insurance recoveries and $1.2 million of a tariff rider collected in 2015 to be applied to deferred costs. If it is determined that future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made. See Note 15, Note 16, and "Results of Operations—Regulatory Matters—Rate Mechanisms— Environmental Costs" above. New Accounting Pronouncements For a description of recent accounting pronouncements that may have an impact on our financial condition, results of operations or cash flows, see Note 2. 42 APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES In preparing our financial statements in accordance with GAAP, management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for: • regulatory accounting; • revenue recognition; • derivative instruments and hedging activities; • pensions and postretirement benefits; • income taxes; • environmental contingencies; and • impairment of long-lived assets. Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 2. Regulatory Accounting Our utility is regulated by the OPUC and WUTC, which establish the rates and rules governing utility services provided to customers, and, to a certain extent, set forth special accounting treatment for certain regulatory transactions. In general, we use the same accounting principles as non-regulated companies reporting under GAAP. However, authoritative guidance for regulated operations (regulatory accounting) requires different accounting treatment for regulated companies to show the effects of such regulation. For example, we account for the cost of gas using a PGA deferral and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC. See "Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" above. There are other expenses and revenues that the OPUC or WUTC may require us to defer for recovery or refund in future periods. Regulatory accounting requires us to account for these types of deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to recover these regulatory assets from, or are required to refund regulatory liabilities to, customers, we recognize the expense or revenue on the income statement at the same time we realize the adjustment to amounts included in utility rates charged to customers. The conditions we must satisfy to adopt the accounting policies and practices of regulatory accounting include: an independent regulator sets rates; • the regulator sets the rates to cover specific costs of • delivering service; and the service territory lacks competitive pressures to reduce rates below the rates set by the regulator. • Because our utility satisfies all three conditions, we continue to apply regulatory accounting to our utility operations. Future accounting changes, regulatory changes or changes in the competitive environment could require us to discontinue the application of regulatory accounting for some or all of our regulated businesses. This would require the write-off of those regulatory assets and liabilities that would no longer be probable of recovery from or refund to customers. Based on current accounting and regulatory competitive conditions, we believe it is reasonable to expect continued application of regulatory accounting for our utility activities. Further, it is reasonable to expect the recovery or refund of our regulatory assets and liabilities at December 31, 2015 through future customer rates. If we should determine all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances against earnings in the period such determination is made. The net balance in regulatory asset and liability accounts as of December 31, 2015 and 2014 was an asset of $70.7 million and $101.2 million, respectively. See Note 2. Revenue Recognition Utility and non-utility revenues, which are derived primarily from the sale, transportation, and storage of natural gas, are recognized upon the delivery of gas commodity or services rendered to customers. Accrued Unbilled Revenue For a description of our policy regarding accrued unbilled revenue for both the utility and non-utility revenues, see Note 2. The following table presents changes in key metrics if the estimated percentage of unbilled volume at December 31 was adjusted up or down by 1%: In millions Unbilled revenue increase (decrease) Utility margin increase (decrease)(1) Net income increase (decrease) (1) Includes impact of regulatory mechanisms including decoupling mechanism. 2015 Up 1% Down 1% $ 0.5 $ (0.5) — — — — Derivative Instruments and Hedging Activities Our gas acquisition and hedging policies set forth guidelines for using financial derivative instruments to support prudent risk management strategies. These policies specifically prohibit the use of derivatives for trading or speculative purposes. We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options, and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price 43 variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts. Derivative instruments are recorded on our balance sheet at fair value. If certain regulatory conditions are met, then the derivative instrument fair value is recorded together with an offsetting entry to a regulatory asset or liability account pursuant to regulatory accounting (see Note 2, "Industry Regulation"), and no unrealized gain or loss is recognized in current income. The gain or loss from the fair value of a derivative instrument subject to regulatory deferral is included in the recovery from, or refund to, utility customers in future periods (see "Regulatory Accounting", above). If a derivative contract is not subject to regulatory deferral, then the accounting treatment for unrealized gains and losses is recorded in accordance with accounting standards for derivatives and hedging (see Note 2, "Derivatives” and "Industry Regulation") which is either in current income or in accumulated other comprehensive income or loss (AOCI or AOCL). Our derivative contracts outstanding at December 31, 2015 were measured at fair value using models or other market accepted valuation methodologies derived from observable market data. Our estimate of fair value may change significantly from period-to-period depending on market conditions and prices. These changes may have an impact on our results of operations, but the impact would largely be mitigated due to the majority of our derivative activities being subject to regulatory deferral treatment. For estimated fair value of unrealized gains and losses, see Note 13. The following table summarizes the amount of gains and losses realized from commodity price transactions for the last three years: In millions 2015 2014 2013 Net utility gain (loss) on: Commodity Swaps Options $ (37.7) $ 10.5 $ (11.0) — — — Total net gain (loss) realized $ (37.7) $ 10.5 $ (11.0) Realized gains and losses from commodity hedges shown above were recorded as decreases or increases to cost of gas, respectively, and were included in our annual PGA rates. Pensions and Postretirement Benefits We maintain a qualified non-contributory defined benefit pension plan, non-qualified supplemental pension plans for eligible executive officers and certain key employees, and other postretirement employee benefit plans covering certain non-union employees. We also have a qualified defined contribution plan (Retirement K Savings Plan) for all eligible employees. Only the qualified defined benefit pension plan and Retirement K Savings Plan have plan assets, which are held in qualified trusts to fund the respective retirement benefits. The qualified defined benefit retirement plan for union and non-union employees was closed to new participants several years ago. These plans are not available to employees at any of our subsidiary companies. Non-union and union employees hired or re- hired after December 31, 2006 and 2009, respectively, and 44 employees of NW Natural subsidiaries are provided an enhanced Retirement K Savings Plan benefit. The postretirement Welfare Benefit Plan for non-union employees was also closed to new participants several years ago. Net periodic pension and postretirement benefit costs (retirement benefit costs) and projected benefit obligations (benefit obligations) are determined using a number of key assumptions including discount rates, rate of compensation increases, retirement ages, mortality rates and an expected long-term return on plan assets. See Note 8. These key assumptions have a significant impact on the pension amounts recorded and disclosed. Retirement benefit costs consist of service costs, interest costs, the amortization of actuarial gains, losses and prior service costs, the expected returns on plan assets and, in part, on a market-related valuation of assets, if applicable. The market-related asset valuation reflects differences between expected returns and actual investment returns, which we recognize over a three- year period or less from the year in which they occur, thereby reducing year-to-year volatility in retirement benefit costs. Accounting standards also require balance sheet recognition of the overfunded or underfunded status of pension and postretirement benefit plans in AOCI or AOCL, net of tax, based on the fair value of plan assets compared to the actuarial value of future benefit obligations. However, the retirement benefit costs related to our qualified defined benefit pension and postretirement benefit plans are generally recovered in utility rates, which are set based on accounting standards for pensions and postretirement benefit expenses. We received approval from the OPUC to recognize the overfunded or underfunded status as a regulatory asset or regulatory liability based on expected rate recovery, rather than including it as AOCI or AOCL under common equity. See "Regulatory Accounting" above and Note 2, "Industry Regulation". In 2011, we received regulatory approval from the OPUC and began deferring a portion of our pension expense above or below the amount set in rates to a regulatory balancing account on the balance sheet. At December 31, 2015, the cumulative amount deferred for future pension cost recovery was $43.7 million. The regulatory balancing account includes the recognition of accrued interest on the account balance at the utility's authorized rate of return, with the equity portion of this interest being deferred until amounts are collected in rates. A number of factors, as discussed above, are considered in developing pension and postretirement benefit assumptions. For the December 31, 2015 measurement date, we reviewed and updated the following key assumptions: • our weighted-average discount rate assumptions for pensions went from 3.85% for 2014 to 4.21% for 2015, and our weighted-average discount rate assumptions for other postretirement benefits went from 3.74% for 2014 to 4.00% for 2015. The new rate assumptions were determined for each plan based on a matching of benchmark interest rates to the estimated cash flows, which reflect the timing and amount of future benefit payments. Benchmark interest rates are drawn from the Citigroup Above Median Curve, which consists of high quality bonds rated AA- or higher by S&P or Aa3 or higher by Moody’s; our expected annual rate of future compensation increases, which decreased slightly to a range of 3.25% to 4.50%; our expected long-term return on qualified defined benefit plan assets, which remained unchanged at a rate of 7.50%; our mortality rate assumptions were updated to the new Society of Actuaries Scale MP-2015, which projects a mortality detriment compared to the previous table used, thereby decreasing benefit plan liabilities; and other key assumptions, which were based on actual plan experience and actuarial recommendations. • • • • At December 31, 2015, our net pension liability (benefit obligations less market value of plan assets) for the qualified defined benefit plan decreased $9.5 million compared to 2014. The decrease in our net pension liability is primarily due to the $39.4 million decrease in our pension benefit obligation, offset by a decrease of $29.8 million in plan assets. The liability for non-qualified plans decreased $2.3 million, and the liability for other postretirement benefits decreased $1.0 million in 2015. We determine the expected long-term rate of return on plan assets by averaging the expected earnings for the target asset portfolio. In developing our expected return, we analyze historical actual performance and long-term return projections, which gives consideration to the current asset mix and our target asset allocation. As of December 31, 2015, the actual annualized returns on plan assets, net of management fees, for the past one-year, five-years, and 10- years were (3.2%), 4.7%, and 4.0%, respectively. We believe our pension assumptions to be appropriate based on plan design and an assessment of market conditions. However, the following shows the sensitivity of our retirement benefit costs and benefit obligations to changes in certain actuarial assumptions: Change in Assumption (0.25)% Impact on 2015 Retirement Benefit Costs Impact on Retirement Benefit Obligations at Dec. 31, 2015 $ 1.3 $ — 0.1 14.4 1.0 1.0 (0.25) 0.7 N/A Dollars in millions Discount rate: Qualified defined benefit plans Non-qualified plans Other postretirement benefits Expected long-term return on plan assets: Qualified defined benefit plans In July 2012, President Obama signed into law the MAP-21 Act. This legislation changed several provisions affecting pension plans, including temporary funding relief and Pension Benefit Guaranty Corporation (PBGC) premium increases, which reduces the level of minimum required contributions in the near-term but generally increases contributions in the long-run as well as increasing the 45 operational costs of running a pension plan. Prior to the MAP-21 Act, we were using interest rates based on a 24- month average yield of investment grade corporate bonds (also referred to as "segment rate") to calculate minimum contribution requirements. MAP-21 Act established a new minimum and maximum corridor for segment rates based on a 25-year average of bond yields, which is to be used in calculating contribution requirements. In August 2014, HATFA was signed and extends certain aspects of MAP-21 as well as modifies the phase-out periods for the limitations. As a result we anticipate lower contributions over the next five years with contributions increasing thereafter. Income Taxes Valuation Allowances We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider the available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. The most significant deferred tax asset currently recorded is for alternative minimum tax credits. We have determined that we are more likely than not to realize all recorded deferred tax assets as of December 31, 2015. See Note 9. Uncertain Tax Benefits The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in the jurisdictions in which we operate. A tax benefit from a material uncertain tax position will only be recognized when it is more likely than not that the position, or some portion thereof, will be sustained upon examination, including resolution of any related appeals or litigation processes, on the basis of the technical merits. The Company participates in the Compliance Assurance Process (CAP) with the Internal Revenue Service (IRS). Under the CAP program the Company works with the IRS to identify and resolve material tax matters before the federal income tax return is filed each year. No reserves for uncertain tax benefits were recorded during 2013, 2014, or 2015. See Note 9. Regulatory Matters Regulatory tax assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded to, customers in future rates. At December 31, 2015 and 2014, we have regulatory income tax assets of $47.4 million and $51.8 million, respectively, representing future rate recovery of deferred tax liabilities resulting from differences in utility plant financial statement and tax basis and utility plant removal costs. These deferred tax liabilities, and the associated regulatory income tax assets, are currently being recovered through customer rates. See Note 2. Tax Legislation When significant proposed or enacted changes in income tax rules occur we consider whether there may be a material impact to our financial position, results of operations, cash flows, or whether the changes could materially affect existing assumptions used in making estimates of tax related balances. The final tangible property regulations applicable to all taxpayers were issued on September 13, 2013 and were generally effective for taxable years beginning on or after January 1, 2014. In addition, procedural guidance related to the regulations was issued under which taxpayers may make accounting method changes to comply with the regulations. We have evaluated the regulations and do not anticipate any material impact. However, unit-of-property guidance applicable to natural gas distribution networks has not yet been issued and is expected in 2016. We will further evaluate the effect of these regulations after this guidance is issued, but believe our current method is materially consistent with the new regulations and do not expect these regulations to have a material effect on our financial statements. The Federal Protecting Americans From Tax Hikes Act of 2015 became law on December 17, 2015 and extended federal bonus depreciation through 2019. See "Financial Conditions—Cash Flows" above. Environmental Contingencies We account for environmental liabilities in accordance with accounting standards under the loss contingency guidance when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable. For a complete discussion of our environmental policy refer to Note 2. For a discussion of our current environmental sites and liabilities refer to Note 15 and "Contingent Liabilities" above. In addition, for information regarding the regulatory treatment of these costs and our regulatory recovery mechanism, see "Results of Operations—Rate Matters—Rate Mechanisms —Environmental Costs" above. Impairment of Long-Lived Assets We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets might not be recoverable. Factors that would necessitate an impairment assessment of long-lived assets include a significant adverse change in the extent or manner in which the asset is used, a significant adverse change in legal factors or business climate that could affect the value of the asset, or a significant decline in the observable market value or expected future cash flows of the asset, among others. When such factors are present, we assess the recoverability by determining whether the carrying value of the asset will be recovered through expected future cash flows. An asset is determined to be impaired when the carrying value of the asset exceeds the expected undiscounted future cash flows from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss for the difference between the carrying value and the fair value of the long-lived assets. Fair value is estimated using appropriate valuation methodologies, which may include an estimate of discounted cash flows. We determined there were no long-lived asset impairments in 2015; however our Gill Ranch Storage facility within our Gas Storage Segment was reviewed for impairment. The undiscounted cash flows are in excess of the carrying value of the asset and no impairment was indicated. The cash flows assume a recovery of storage pricing and the ability to contract with higher value customers. Accordingly, if 46 storage pricing does not improve and/or new higher value customers are not obtained, future analysis may result in an impairment of these long-lived assets. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to various forms of market risk including commodity supply risk, commodity price risk, interest rate risk, foreign currency risk, credit risk and weather risk. The following describes our exposure to these risks. Commodity Supply Risk We enter into spot, short-term, and long-term natural gas supply contracts, along with associated pipeline transportation contracts, to manage our commodity supply risk. Historically, we have arranged for physical delivery of an adequate supply of gas, including gas in our Mist storage and off-system storage facilities, to meet expected requirements of our core utility customers. Our long-term gas supply contracts are primarily index-based and subject to monthly re-pricing, a strategy that is intended to substantially mitigate credit exposure to our physical gas counterparties. Notional amounts under physical gas contracts were $7.0 million and $4.8 million as of December 31, 2015 and 2014, respectively. Commodity Price Risk Natural gas commodity prices are subject to market fluctuations due to unpredictable factors including weather, pipeline transportation congestion, drilling technologies, market speculation, and other factors that affect supply and demand. We manage commodity price risk with financial swaps and physical gas reserves from a long-term investment in working interests in gas leases operated by Jonah Energy. These financial hedge contracts and gas reserves volumes are generally included in our annual PGA filing for recovery, subject to a regulatory prudence review. Notional amounts under financial derivative contracts were $95.5 million and $108.4 million as of December 31, 2015 and 2014, respectively. The fair value of financial swaps as of December 31, 2015 was an unrealized loss of $23.2 million with future cash flows of $19.8 million in 2016, $2.7 million in 2017 and $0.7 million in 2018. Interest Rate Risk We are exposed to interest rate risk primarily associated with new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. Interest rate risk is primarily managed through the issuance of fixed-rate debt with varying maturities. We may also enter into financial derivative instruments, including interest rate swaps, options and other hedging instruments, to manage and mitigate interest rate exposure. We did not have any interest rate swaps outstanding as of December 31, 2015 or 2014. Foreign Currency Risk The costs of certain pipeline and off-system storage services purchased from Canadian suppliers are subject to changes in the value of the Canadian currency in relation to the U.S. currency. Foreign currency forward contracts are used to hedge against fluctuations in exchange rates for our commodity-related demand and reservation charges paid in Canadian dollars. Notional amounts under foreign currency forward contracts were $9.0 million and $12.2 million as of December 31, 2015 and 2014, respectively. If all of the foreign currency forward contracts had been settled on December 31, 2015, a loss of $0.4 million would have been realized. See Note 13. Credit Risk Credit Exposure to Natural Gas Suppliers Certain gas suppliers have either relatively low credit ratings or are not rated by major credit rating agencies. To manage this supply risk, we purchase gas from a number of different suppliers at liquid exchange points. We evaluate and monitor suppliers’ creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit, or surety bonds, in case a supplier defaults. In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing market prices, which may be higher or lower than the original transaction prices. We expect these costs would be subject to our PGA sharing mechanism discussed above. Since most of our commodity supply contracts are priced at the daily or monthly market index price tied to liquid exchange points, and we have adequate storage flexibility, we believe it is unlikely a supplier default would have a material adverse effect on our financial condition or results of operations. Credit Exposure to Financial Derivative Counterparties Based on estimated fair value at December 31, 2015, our overall credit exposure relating to commodity contracts is considered immaterial as it reflects amounts owed to financial derivative counterparties (see table below). However, changes in natural gas prices could result in counterparties owing us money. Therefore, our financial derivatives policy requires counterparties to have at least an investment-grade credit rating at the time the derivative instrument is entered into and specific limits on the contract amount and duration based on each counterparty’s credit rating. Due to potential changes in market conditions and credit concerns, we continue to enforce strong credit requirements. We actively monitor and manage our derivative credit exposure and place counterparties on hold for trading purposes or require cash collateral, letters of credit, or guarantees as circumstances warrant. As of December 31, 2015, we do not have any actual derivative credit risk exposure for amounts financial derivative counterparties owe to us. The following table summarizes our overall financial swap and option credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating or a middle rating if the entity is split-rated with more than one rating level difference: In most cases, we also mitigate the credit risk of financial derivatives by having master netting arrangements with our counterparties which provide for making or receiving net cash settlements. Generally, transactions of the same type in the same currency that have settlement on the same day with a single counterparty are netted and a single payment is delivered or received depending on which party is due funds. Additionally we have master contracts in place with each of our derivative counterparties that include provisions for posting or calling for collateral. Generally we can obtain cash or marketable securities as collateral with one day’s notice. We use various collateral management strategies to reduce liquidity risk. The collateral provisions vary by counterparty but are not expected to result in the significant posting of collateral, if any. We have performed stress tests on the portfolio and concluded the liquidity risk from collateral calls is not material. Our derivative credit exposure is primarily with investment grade counterparties rated AA-/ Aa3 or higher. Contracts are diversified across counterparties to reduce credit and liquidity risk. Credit Exposure to Insurance Companies Our credit exposure to insurance companies for loss or damage claims could be material. We regularly monitor the financial condition of insurance companies who provide general liability insurance policy coverage to NW Natural and its predecessors. Weather Risk We have a weather normalization mechanism in Oregon; however, we are exposed to weather risk primarily from our regulated utility business. A large percentage of our utility margin is volume driven, and current rates are based on an assumption of average weather. Our weather normalization mechanism in Oregon is for residential and commercial customers, which is intended to stabilize the recovery of our utility’s fixed costs and reduce fluctuations in customers’ bills due to colder or warmer than average weather. Customers in Oregon are allowed to opt out of the weather normalization mechanism. As of December 31, 2015, approximately 9% of our Oregon customers had opted out. In addition to the Oregon customers opting out, our Washington residential and commercial customers account for approximately 11% of our total customer base and are not covered by weather normalization. The combination of Oregon and Washington customers not covered by a weather normalization mechanism is 20% of all residential and commercial customers. See "Results of Operations— Regulatory Matters—Rate Mechanism—Weather Normalization Tariff" above. In millions AA/Aa A/A Total $ Financial Derivative Position by Credit Rating Unrealized Fair Value Loss 2015 2014 (20.0) (3.2) (23.2) $ (27.2) (3.4) (30.6) 47 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS 1. 2. 3. 4. 5. Management's Report on Internal Control Over Financial Reporting Report of Independent Registered Public Accounting Firm Consolidated Financial Statements: Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013 Consolidated Balance Sheets at December 31, 2015 and 2014 Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2015, 2014, and 2013 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013 Notes to Consolidated Financial Statements Quarterly Financial Information (Unaudited) Supplementary Data for the Years Ended December 31, 2015, 2014, and 2013: Financial Statement Schedule Schedule II – Valuation and Qualifying Accounts and Reserves Supplemental Schedules Omitted Page 49 50 51 52 54 55 56 85 85 All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements. 48 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America (GAAP). Our internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions involving company assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and the Board of Directors; and (iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements or fraud. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2015. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on our assessment and those criteria, management has concluded that we maintained effective internal control over financial reporting as of December 31, 2015. The effectiveness of internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this annual report. /s/ Gregg S. Kantor Gregg S. Kantor Chief Executive Officer /s/ Gregory C. Hazelton Gregory C. Hazelton Senior Vice President, Chief Financial Officer, and Treasurer February 26, 2016 49 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Northwest Natural Gas Company: In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and its cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLP Portland, Oregon February 26, 2016 50 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME In thousands, except per share data Operating revenues Operating expenses: Cost of gas Operations and maintenance Environmental remediation General taxes Depreciation and amortization Total operating expenses Income from operations Other income, net Interest expense, net Income before income taxes Income tax expense Net income Other comprehensive income: Change in employee benefit plan liability, net of taxes of ($988) for 2015, $2,857 for 2014, and ($1,304) for 2013 Amortization of non-qualified employee benefit plan liability, net of taxes of ($883) for 2015, ($438) for 2014, and ($608) for 2013 Comprehensive income Average common shares outstanding: Basic Diluted Earnings per share of common stock: Basic Diluted Dividends declared per share of common stock Year Ended December 31, 2015 2014 2013 $ 723,791 $ 754,037 $ 758,518 327,305 157,521 3,513 30,281 80,923 599,543 124,248 7,747 42,539 89,456 35,753 53,703 365,490 136,982 — 29,407 79,193 611,072 142,965 1,933 44,563 373,298 136,613 — 29,956 75,905 615,772 142,746 4,669 45,172 100,335 102,243 41,643 58,692 41,705 60,538 1,561 1,353 (4,364) 1,998 646 935 $ 56,617 $ 54,974 $ 63,471 27,347 27,417 27,164 27,223 26,974 27,027 $ $ 1.96 1.96 1.86 $ 2.16 2.16 1.85 2.24 2.24 1.83 See Notes to Consolidated Financial Statements 51 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS In thousands Assets: Current assets: Cash and cash equivalents Accounts receivable Accrued unbilled revenue Allowance for uncollectible accounts Regulatory assets Derivative instruments Inventories Gas reserves Income taxes receivable Deferred tax assets Other current assets Total current assets Non-current assets: Property, plant, and equipment Less: Accumulated depreciation Total property, plant, and equipment, net Gas reserves Regulatory assets Derivative instruments Other investments Restricted cash Other non-current assets Total non-current assets Total assets As of December 31, 2015 2014 $ 4,211 $ 68,228 57,987 (870) 69,178 2,719 70,868 17,094 7,900 — 34,748 332,063 9,534 69,818 57,963 (969) 68,562 243 77,832 20,020 1,000 23,785 34,772 362,560 3,089,380 2,992,560 906,717 870,967 2,182,663 2,121,593 114,552 370,711 27 68,066 — 8,610 129,280 368,908 — 68,238 3,000 11,366 2,744,629 2,702,385 $ 3,076,692 $ 3,064,945 See Notes to Consolidated Financial Statements 52 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS In thousands Liabilities and equity: Current liabilities: Short-term debt Current maturities of long-term debt Accounts payable Taxes accrued Interest accrued Regulatory liabilities Derivative instruments Other current liabilities Total current liabilities Long-term debt Deferred credits and other non-current liabilities: Deferred tax liabilities Regulatory liabilities Pension and other postretirement benefit liabilities Derivative instruments Other non-current liabilities Total deferred credits and other non-current liabilities Commitments and contingencies (see Note 14 and Note 15) Equity: Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,427 and 27,284 at December 31, 2015 and 2014, respectively Retained earnings Accumulated other comprehensive loss Total equity Total liabilities and equity See Notes to Consolidated Financial Statements As of December 31, 2015 2014 $ 270,035 $ 234,700 25,000 73,219 10,420 5,873 29,927 22,092 41,148 477,714 576,700 530,021 339,287 223,105 3,447 145,446 40,000 91,366 10,031 6,079 19,105 29,894 38,235 469,410 621,700 530,965 317,205 236,735 3,515 118,094 1,241,306 1,206,514 — — 383,144 404,990 (7,162) 780,972 375,117 402,280 (10,076) 767,321 $ 3,076,692 $ 3,064,945 53 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY In thousands Balance at December 31, 2012 Comprehensive income Dividends on common stock Tax expense from employee stock plans Stock-based compensation Issuance of common stock Balance at December 31, 2013 Comprehensive income (loss) Dividends on common stock Tax expense from employee stock plans Stock-based compensation Issuance of common stock Balance at December 31, 2014 Comprehensive income Dividends on common stock Tax expense from employee stock plans Stock-based compensation Issuance of common stock Balance at December 31, 2015 Common Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Total Equity $ 356,571 $ 382,347 $ (9,291) $ 729,627 — — (242) 2,169 6,051 364,549 — — (117) 1,646 9,039 375,117 — — (118) 3,277 4,868 60,538 (49,204) — — — 393,681 58,692 (50,093) — — — 402,280 53,703 (50,993) — — — 2,933 — — — — (6,358) (3,718) — — — — (10,076) 2,914 — — — — 63,471 (49,204) (242) 2,169 6,051 751,872 54,974 (50,093) (117) 1,646 9,039 767,321 56,617 (50,993) (118) 3,277 4,868 $ 383,144 $ 404,990 $ (7,162) $ 780,972 See Notes to Consolidated Financial Statements 54 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands Operating activities: Net income Adjustments to reconcile net income to cash provided by operations: Depreciation and amortization Regulatory amortization of gas reserves Deferred tax liabilities, net Qualified defined benefit pension plan expense Contributions to qualified defined benefit pension plans Deferred environmental (expenditures) recoveries, net Regulatory disallowance of prior environmental cost deferrals Interest income on deferred environmental expenses Amortization of environmental remediation Other Changes in assets and liabilities: Receivables, net Inventories Taxes accrued Accounts payable Interest accrued Deferred gas costs Other, net Cash provided by operating activities Investing activities: Capital expenditures Utility gas reserves Proceeds from sale of assets Restricted cash Other Cash used in investing activities Financing activities: Common stock issued, net Long-term debt issued Long-term debt retired Change in short-term debt Cash dividend payments on common stock Other Cash (used in) provided by financing activities (Decrease) increase in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period Supplemental disclosure of cash flow information: Interest paid, net of capitalization Income taxes paid, net of refunds See Notes to Consolidated Financial Statements 55 Year Ended December 31, 2015 2014 2013 $ 53,703 $ 58,692 $ 60,538 80,923 17,991 26,972 5,697 79,193 19,335 24,772 4,984 75,905 11,089 46,483 5,666 (14,120) (10,500) (11,700) (10,568) 88,849 (16,679) 15,000 (5,322) 3,513 3,709 2,373 6,964 (6,541) (17,175) (206) — — — — — — 1,853 (2,580) 14,948 (26,094) (17,163) 1,709 (2,020) (1,024) 6,933 286 7,422 1,150 31,918 (23,114) (5,245) (10,143) (24,857) 23,216 184,688 215,657 176,390 (118,320) (120,092) (138,924) (1,549) (26,798) (54,077) 410 3,000 1,161 175 1,000 1,392 8,638 — 2,231 (115,298) (144,323) (182,132) 3,875 — 8,986 — (60,000) (80,000) 5,964 50,000 — 35,335 46,500 (2,050) (49,243) (50,093) (49,204) (4,680) 3,336 (74,713) (71,271) (5,323) 9,534 63 9,471 $ 4,211 $ 9,534 $ 1,580 6,290 548 8,923 9,471 $ 39,634 $ 42,602 $ 44,022 17,306 19,445 870 2. SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes. Actual amounts could differ from those estimates, and changes would most likely be reported in future periods. Management believes the estimates and assumptions used are reasonable. Industry Regulation Our principal businesses are the distribution of natural gas, which is regulated by the OPUC and WUTC, and natural gas storage services, which are regulated by either the FERC or the CPUC, and to a certain extent by the OPUC and WUTC. Accounting records and practices of our regulated businesses conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with U.S. GAAP. Our businesses regulated by the OPUC, WUTC, and FERC earn a reasonable return on invested capital from approved cost-based rates, while our business regulated by the CPUC earns a return to the extent we are able to charge competitive prices above our costs (i.e. market-based rates). In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC, which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases. NORTHWEST NATURAL GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non- utility activities we aggregate and report as other. Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non- utility” is used to describe our gas storage businesses and other non-utility investments and business activities. Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows. 56 At December 31, the amounts deferred as regulatory assets and liabilities were as follows: In thousands Current: Regulatory Assets 2015 2014 Unrealized loss on derivatives(1) $ 22,092 $ 29,889 Gas costs Environmental costs(2) Decoupling(3) Other(4) Total current Non-current: Unrealized loss on derivatives(1) Pension balancing(5) Income taxes Pension and other postretirement benefit liabilities Environmental costs(2) Gas costs Other(4) 8,717 9,270 18,775 10,324 21,794 — 7,505 9,374 $ 69,178 $ 68,562 $ 3,447 $ 3,515 43,748 43,049 32,541 47,427 184,223 201,845 76,584 1,949 17,711 58,859 5,971 18,750 Total non-current $ 370,711 $ 368,908 In thousands Current: Gas costs Unrealized gain on derivatives(1) Other(4) Total current Non-current: Gas costs Unrealized gain on derivatives(1) Accrued asset removal costs(6) Other(4) Regulatory Liabilities 2015 2014 $ 14,157 $ 5,700 2,659 240 13,111 13,165 $ 29,927 $ 19,105 $ 8,869 $ 2,507 27 — 327,047 311,238 3,344 3,460 Total non-current $ 317,205 (1) Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement. $ 339,287 (2) Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million base rate rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. See Note 15. This deferral represents the margin adjustment resulting from differences between actual and expected volumes. (3) 57 (4) (5) These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge. The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates. (6) Estimated costs of removal on certain regulated properties are collected through rates. See "Accounting Policies—Plant, Property, and Accrued Asset Removal Costs" below. The amortization period for our regulatory assets and liabilities ranges from less than one year to an indeterminable period. Our regulatory deferrals for gas costs payable are generally amortized over 12 months beginning each November 1 following the gas contract year during which the deferred gas costs are recorded. Similarly, most of our other regulatory deferred accounts are amortized over 12 months. However, certain regulatory account balances, such as income taxes, environmental costs, pension liabilities, and accrued asset removal costs, are large and tend to be amortized over longer periods once we have agreed upon an amortization period with the respective regulatory agency. We believe all costs incurred and deferred at December 31, 2015 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances in the period such determination is made. Environmental Regulatory Accounting On February 20, 2015, the OPUC issued an Order (2015 Order) addressing outstanding implementation items related to the Site Remediation and Recovery Mechanism (SRRM). Under the Order, $15 million of $95 million in total environmental remediation expenses deferred through 2012 were disallowed. The OPUC found the $95 million to be prudent but disallowed the $15 million from rate recovery based on its determination of how an earnings test should apply to years between 2003 and 2012, with adjustments for other factors the OPUC deemed relevant. We recognized the $15 million pre-tax disallowance, or $9.1 million after-tax charge, during the first quarter of 2015. The charge was recorded in operations and maintenance expense. Also, as a result of the order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses. On January 27, 2016, the OPUC issued an Order addressing the outstanding issues. In November 2015, we began collecting revenues from customers through the SRRM. These collections are included in utility operating revenues and are offset by environmental remediation expense included in operating expense. See Note 15 and Note 16 regarding our SRRM. New Accounting Standards Recently Adopted Accounting Pronouncement PRESENTATION OF DEFERRED TAXES. On November 20, 2015, the FASB (Financial Accounting Standards Board) issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes." The ASU requires deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. The new requirements are effective for us beginning January 1, 2017 and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We have early adopted the change in accounting principle on a prospective basis, and it is reflected within our consolidated balance sheet for the period ended December 31, 2015. Prior periods were not retrospectively adjusted. Recently Issued Accounting Pronouncements BENEFIT PLAN ACCOUNTING. On July 31, 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans, Defined Contribution Pension Plans, and Health and Welfare Benefit Plans." The ASU outlines a three part update. Only part two of the update is applicable for us, which simplifies the investment disclosure requirements for employee benefit plans by allowing certain disclosures at an aggregated level, reducing the number of ways assets must be grouped and analyzed, and no longer requiring investment strategy disclosures for certain investments. The new requirements are effective for us beginning January 1, 2016, with early adoption permitted. We will be required to apply the disclosure guidance retrospectively and do not expect the ASU to materially affect our financial statements and disclosures. FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2015-07, "Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements are effective for us beginning January 1, 2016 with retrospective application to all periods presented required and early adoption permitted. We do not expect the ASU to materially affect our financial statements and disclosures. INTANGIBLES - GOODWILL AND OTHER - INTERNAL- USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements are effective for us beginning January 1, 2016. The ASU can be applied prospectively or retrospectively and early adoption is permitted. We intend to apply the guidance prospectively and do not expect the ASU to materially affect our financial statements and disclosures. DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements are 58 effective for us beginning January 1, 2016. The new guidance will be applied on a retrospective basis. We do not expect the ASU to materially affect our financial statements and disclosures. REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The model provides a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On August 12, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of January 1, 2017. We are currently assessing the effect of this standard on our financial statements and disclosures. Accounting Policies Plant, Property, and Accrued Asset Removal Costs Plant and property are stated at cost, including capitalized labor, materials and overhead. In accordance with regulatory accounting standards, the cost of acquiring and constructing long-lived plant and property generally includes an allowance for funds used during construction (AFUDC) or capitalized interest. AFUDC represents the regulatory financing cost incurred when debt and equity funds are used for construction (see “AFUDC” below). When constructed assets are subject to market-based rates rather than cost- based rates, the financing costs incurred during construction are included in capitalized interest in accordance with U.S. GAAP, not as regulatory financing costs under AFUDC. In accordance with long-standing regulatory treatment, our depreciation rates consist of three components: one based on the average service life of the asset, a second based on the estimated salvage value of the asset, and a third based on the asset’s estimated cost of removal. We collect, through rates, the estimated cost of removal on certain regulated properties through depreciation expense, with a corresponding offset to accumulated depreciation. These removal costs are non-legal obligations as defined by regulatory accounting guidance. Therefore, we have included these costs as non-current regulatory liabilities rather than as accumulated depreciation on our consolidated balance sheets. In the rate setting process, the liability for removal costs is treated as a reduction to the net rate base on which the regulated utility has the opportunity to earn its allowed rate of return. The costs of utility plant retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. Gains from the sale of regulated assets are generally deferred and refunded to customers. For non-utility assets, we record a gain or loss upon the disposal of the property, and the gain or loss is recorded in operating income in the consolidated statements of comprehensive income. Our provision for depreciation of utility property, plant, and equipment is recorded under the group method on a straight- line basis with rates computed in accordance with depreciation studies approved by regulatory authorities. The weighted-average depreciation rate for utility assets in service was approximately 2.8% for 2015, 2014, and 2013, reflecting the approximate weighted-average economic life of the property. This includes 2015 weighted-average depreciation rates for the following asset categories: 2.7% for transmission and distribution plant, 2.2% for gas storage facilities, 4.6% for general plant, and 2.7% for intangible and other fixed assets. AFUDC. Certain additions to utility plant include AFUDC, which represents the net cost of debt and equity funds used during construction. AFUDC is calculated using actual interest rates for debt and authorized rates for ROE, if applicable. If short-term debt balances are less than the total balance of construction work in progress, then a composite AFUDC rate is used to represent interest on all debt funds, shown as a reduction to interest charges, and on ROE funds, shown as other income. While cash is not immediately recognized from recording AFUDC, it is realized in future years through rate recovery resulting from the higher utility cost of service. Our composite AFUDC rate was 0.4% in 2015, and 0.3% in 2014 and 2013, respectively. IMPAIRMENT OF LONG-LIVED ASSETS. We review the carrying value of long-lived assets whenever events or changes in circumstances indicate the carrying amount of the assets may not be recoverable. Factors that would necessitate an impairment assessment of long-lived assets include a significant adverse change in the extent or manner in which the asset is used, a significant adverse change in legal factors or business climate that could affect the value of the asset, or a significant decline in the observable market value or expected future cash flows of the asset, among others. When such factors are present, we assess the recoverability by determining whether the carrying value of the asset will be recovered through expected future cash flows. An asset is determined to be impaired when the carrying value of the asset exceeds the expected undiscounted future cash flows from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss for the difference between the carrying value and the fair value of the long-lived assets. Fair value is estimated using appropriate valuation methodologies, which may include an estimate of discounted cash flows. We determined there were no long-lived asset impairments in 2015; however our Gill Ranch Storage facility within our Gas Storage Segment was reviewed for impairment. The undiscounted cash flows are in excess of the carrying value of the asset and no impairment was indicated. The cash flows assume a recovery of storage pricing and the ability to contract with higher value customers. Accordingly, if storage pricing does not improve and/or new higher value customers 59 are not obtained, future analysis may result in an impairment of these long-lived assets. Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash on hand plus highly liquid investment accounts with original maturity dates of three months or less. At December 31, 2015 and 2014, outstanding checks of approximately $2.5 million and $5.5 million, respectively, were included in accounts payable. Revenue Recognition and Accrued Unbilled Revenue Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized upon delivery of the gas commodity or service to customers. Revenues include accruals for gas delivered but not yet billed to customers based on estimates of deliveries from meter reading dates to month end (accrued unbilled revenue). Accrued unbilled revenue is dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer use by billing cycle, and weather factors. Accrued unbilled revenue is reversed the following month when actual billings occur. Our accrued unbilled revenue at December 31, 2015 and 2014 was $58.0 million. Non-utility revenues are derived primarily from the gas storage segment. At our Mist underground storage facility, revenues are primarily firm service revenues in the form of fixed monthly reservation charges. At our Gill Ranch facility, firm storage services resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. In addition, we also have asset management service revenue from an independent energy marketing company that optimizes commodity, storage, and pipeline capacity release transactions. Under this agreement, guaranteed asset management revenue is recognized using a straight- line, pro-rata methodology over the term of each contract. Revenues earned above the guaranteed amount are recognized as they are earned. Revenue Taxes Revenue-based taxes are primarily franchise taxes, which are collected from customers and remitted to taxing authorities. Revenue taxes are included in operating revenues in the statement of comprehensive income. Revenue taxes were $18.0 million, $18.8 million, and $19.0 million for 2015, 2014, and 2013, respectively. Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable consist primarily of amounts due for natural gas sales and transportation services to utility customers, plus amounts due for gas storage services. We establish an allowance for uncollectible accounts (allowance) for trade receivables, including accrued unbilled revenue, based on the aging of receivables, collection experience of past due account balances including payment plans, and historical trends of write-offs as a percent of revenues. A specific allowance is established and recorded for large individual customer receivables when amounts are identified as unlikely to be partially or fully recovered. Inactive accounts are written-off against the allowance after they are 120 days past due or when deemed uncollectible. Differences between our estimated allowance and actual write-offs will occur based on a number of factors, including changes in economic conditions, customer creditworthiness, and natural gas prices. The allowance for uncollectible accounts is adjusted quarterly, as necessary, based on information currently available. Inventories Utility gas inventories, which consist of natural gas in storage for the utility, are stated at the lower of average cost or net realizable value. The regulatory treatment of utility gas inventories provides for cost recovery in customer rates. Utility gas inventories injected into storage are priced in inventory based on actual purchase costs. Utility gas inventories withdrawn from storage are charged to cost of gas during the current period at the weighted-average inventory cost. Gas storage inventories, which primarily represent inventories at the Gill Ranch storage facility, mainly consist of natural gas received as fuel-in-kind from storage customers. Gas storage inventories are valued at the lower of average cost or net realizable value. Cushion gas is not included in our inventory balances, is recorded at original cost, and classified as a long-term plant asset. Materials and supplies inventories consist of both utility and non-utility inventories and are stated at the lower of average cost or net realizable value. Our utility and gas storage inventories totaled $59.3 million and $68.0 million at December 31, 2015 and 2014, respectively. At December 31, 2015 and 2014, our materials and supplies inventories totaled $11.6 million and $9.8 million, respectively. Gas Reserves Gas reserves are payments to acquire and produce natural gas reserves. Gas reserves are stated at cost, adjusted for regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. The current portion is calculated based on expected gas deliveries within the next fiscal year. We recognize regulatory amortization of this asset on a volumetric basis calculated using the estimated gas reserves and the estimated therms extracted and sold each month. The amortization of gas reserves is recorded to cost of gas along with gas production revenues and production costs. See Note 11. Derivatives Derivatives are measured at fair value and recognized as either assets or liabilities on the balance sheet. Changes in the fair value of the derivatives are recognized currently in earnings unless specific regulatory or hedge accounting criteria are met. Accounting for derivatives and hedges provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable. In addition, certain derivative contracts are approved by regulatory authorities for recovery or refund through customer rates. Accordingly, the changes in fair value of these approved contracts are deferred as regulatory assets or liabilities pursuant to regulatory accounting principles. Our financial derivatives generally qualify for 60 deferral under regulatory accounting. Our index-priced physical derivative contracts also qualify for regulatory deferral accounting treatment. Derivative contracts entered into for utility requirements after the annual PGA rate has been set and during the PGA year are subject to the PGA incentive sharing mechanism. In Oregon we participate in a PGA sharing mechanism under which we are required to select either an 80% or 90% deferral of higher or lower gas costs such that the impact on current earnings from the gas cost sharing is either 20% or 10% of gas cost differences compared to PGA prices, respectively. For the PGA year in Oregon beginning November 1, 2015, we selected the 80% deferral of gas cost differences, and for the PGA years in Oregon beginning November 1, 2014, and 2013, we selected a 90% deferral of gas cost differences. In Washington, 100% of the differences between the PGA prices and actual gas costs are deferred. See Note 13. Our financial derivatives policy sets forth the guidelines for using selected derivative products to support prudent risk management strategies within designated parameters. Our objective for using derivatives is to decrease the volatility of gas prices, earnings, and cash flows without speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined to exceed acceptable tolerance levels, and are determined necessary to support normal business activities. We do not enter into derivative instruments for trading purposes. Fair Value In accordance with fair value accounting, we use the following fair value hierarchy for determining inputs for our debt, pension plan assets, and our derivative fair value measurements: • Level 1: Valuation is based on quoted prices for identical instruments traded in active markets; Level 2: Valuation is based on quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market; and Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect our own estimates of assumptions market participants would use in valuing the asset or liability. • • When developing fair value measurements, it is our policy to use quoted market prices whenever available, or to maximize the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available. Fair values are primarily developed using industry- standard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market interest rates and yield curves; (g) credit spreads; and (h) other relevant economic measures. Income Taxes We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of the differences between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the enactment date period unless a regulatory Order specifies deferral of the effect of the change in tax rates over a longer period of time. Deferred income tax assets and liabilities are also recognized for temporary differences where the deferred income tax benefits or expenses have previously been flowed through in the ratemaking process of the regulated utility. Regulatory tax assets and liabilities are recorded on these deferred tax assets and liabilities to the extent the Company believes they will be recoverable from or refunded to customers in future rates. At December 31, 2015 and 2014, regulatory income tax assets of $47.4 million and $51.8 million, respectively, were recorded, a portion of which is recorded in current assets. These regulatory income tax assets primarily represent future rate recovery of deferred tax liabilities, resulting from differences in utility plant financial statement and tax bases and utility plant removal costs, which were previously flowed through for rate making purposes and to take into account the additional future taxes, which will be generated by that recovery. These deferred tax liabilities, and the associated regulatory income tax assets, are currently being recovered through customer rates. Deferred investment tax credits on utility plant additions, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant. The Company recognizes interest and penalties related to unrecognized tax benefits, if any, within income tax expense and accrued interest and penalties within the related tax liability line in the consolidated balance sheets. No accrued interest or penalties for uncertain tax benefits have been recorded. See Note 9. Environmental Contingencies Loss contingencies are recorded as liabilities when it is probable a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results. With respect to environmental liabilities and related costs, we develop estimates based on a review of information available from numerous sources, including completed studies and site specific negotiations. It is our policy to accrue the full amount of such liability when information is sufficient to reasonably estimate the amount of probable liability. When information is not available to reasonably estimate the probable liability, or when only the range of probable liabilities can be estimated and no amount within the range is more likely than another, it is our policy to accrue at the low end of the range. Accordingly, due to numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases we have disclosed the nature of the potential loss and the fact that the high end of the range cannot be reasonably estimated. See Note 15. Subsequent Events See Note 16 for information regarding the resolution of the environmental SRRM docket. 61 3. EARNINGS PER SHARE Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock awards are excluded from the calculation of diluted earnings per common share. Diluted earnings per share are calculated as follows: In thousands, except per share data Net income Average common shares outstanding - basic Additional shares for stock-based compensation plans (See Note 6) Average common shares outstanding - diluted Earnings per share of common stock - basic Earnings per share of common stock - diluted Additional information: Antidilutive shares 4. SEGMENT INFORMATION We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly- owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non- utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. Local Gas Distribution Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale, and delivery of natural gas and related services to customers in Oregon and southwest Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from producers and marketers, contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms, and conditions approved by the OPUC or WUTC. Gas distribution also includes taking customer- owned gas and transporting it from interstate pipeline connections, or city gates, to the customers’ end-use facilities for a fee, which is approved by the OPUC or WUTC. Approximately 89% of our customers are located in Oregon and 11% in Washington. On an annual basis, residential and commercial customers typically account for around 60% of our utility’s total volumes delivered and 90% of our utility’s margin. Industrial customers largely account for the remaining volumes and utility margin. A small amount of utility margin is also derived from miscellaneous 62 2015 2014 2013 $ 53,703 $ 58,692 $ 27,347 70 27,417 27,164 59 27,223 $ $ 1.96 1.96 $ $ 2.16 2.16 $ $ 60,538 26,974 53 27,027 2.24 2.24 12 18 26 services, gains or losses from an incentive gas cost sharing mechanism, and other service fees. Industrial sectors we serve include: pulp, paper, and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. No individual customer or industry group accounts for over 10% of our utility revenues or utility margins. Gas Storage Our gas storage segment includes natural gas storage services provided to customers primarily from two underground natural gas storage facilities, our Gill Ranch gas storage facility, and the non-utility portion of our Mist gas storage facility. In addition to earning revenue from customer storage contracts, we also use an independent energy marketing company to provide asset management services for utility and non-utility capacity, the results of which are included in this business segment. Mist Gas Storage Facility Earnings from non-utility assets at our Mist facility in Oregon are primarily related to firm storage capacity revenues. Earnings for the Mist facility also include revenue, net of amounts shared with utility customers, from management of utility assets at Mist and upstream capacity when not needed to serve utility customers. We retain 80% of the pre-tax income from these services when the costs of the capacity have not been included in utility rates, or 33% of the pre-tax income when the costs have been included in utility rates. The remaining 20% and 67%, respectively, are recorded to a deferred regulatory account for crediting back to utility customers. Gill Ranch Gas Storage Facility Gill Ranch has a joint project agreement with Pacific Gas and Electric Company (PG&E) to own and operate the Gill Ranch underground natural gas storage facility near Fresno, California. Gill Ranch has a 75% undivided ownership interest in the facility and is also the operator of the facility, which offers storage services to the California market at market-based rates, subject to CPUC regulation including, but not limited to, service terms and conditions and tariff regulations. Although this is a jointly owned property, each owner is independently responsible for financing its share of the Gill Ranch natural gas storage facility. Revenues are primarily related to firm storage capacity as well as asset management revenues. Other We have non-utility investments and other business activities, which are aggregated and reported as other. Other primarily consists of an equity method investment in TWH, which was formed to build and operate an interstate gas transmission pipeline in Oregon (TWP) and other pipeline assets in NNG Financial. For more information on TWP, see Note 12. Other also includes some corporate operating and non-operating revenues and expenses that cannot be allocated to utility operations. NNG Financial's assets primarily consist of an active, wholly-owned subsidiary which owns a 10% interest in an 18-mile interstate natural gas pipeline. NNG Financial’s total assets were $0.7 million and $0.8 million at December 31, 2015 and 2014, respectively. Segment Information Summary Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments: In thousands 2015 Utility Gas Storage Other Total Operating revenues $ 702,210 $ 21,356 $ 225 $ Depreciation and amortization Income from operations Net income Capital expenditures 74,410 119,215 53,391 115,272 6,513 5,032 174 3,048 — 1 138 — 723,791 80,923 124,248 53,703 118,320 Total assets at December 31, 2015 2,800,018 261,750 14,924 3,076,692 2014 Operating revenues $ 731,578 $ 22,235 $ 224 $ Depreciation and amortization Income from operations Net income (loss) Capital expenditures 72,660 138,711 58,587 117,322 6,533 3,987 (364) 2,770 — 267 469 — 754,037 79,193 142,965 58,692 120,092 Total assets at December 31, 2014 2,775,011 273,813 16,121 3,064,945 2013 Operating revenues $ 727,182 $ 31,112 $ 224 $ — 11 49 — 758,518 75,905 142,746 60,538 138,924 16,447 2,970,911 Depreciation and amortization Income from operations Net income Capital expenditures Total assets at December 31, 2013 69,420 128,066 54,920 137,466 2,644,367 6,485 14,669 5,569 1,458 310,097 63 Utility Margin Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage segment and other emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance. The following table presents additional segment information concerning utility margin: In thousands Utility margin calculation: Utility operating revenues (1) Less: Utility cost of gas Environmental remediation expense Utility margin 2015 2014 2013 $ $ 702,210 $ 731,578 $ 327,305 3,513 365,490 — 727,182 373,298 — 371,392 $ 366,088 $ 353,884 (1) Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. Summary of Changes in Common Stock The following table shows the changes in the number of shares of our common stock issued and outstanding: In thousands Balance, December 31, 2012 Sales to employees under ESPP Stock-based compensation Sales to shareholders under DRPP Balance, December 31, 2013 Sales to employees under ESPP Stock-based compensation Sales to shareholders under DRPP Balance, December 31, 2014 Sales to employees under ESPP Stock-based compensation Sales to shareholders under DRPP Balance, December 31, 2015 Shares 26,917 16 42 100 27,075 24 83 102 27,284 19 78 46 27,427 5. COMMON STOCK Common Stock As of December 31, 2015 and 2014, we had 100 million shares of common stock authorized. As of December 31, 2015, we had reserved 78,857 shares for issuance of common stock under the Employee Stock Purchase Plan (ESPP) and 297,879 shares under our Dividend Reinvestment and Direct Stock Purchase Plan (DRPP). At the Company's election, shares sold through our DRPP may be purchased in the open market or through original issuance of shares reserved for issuance under the DRPP. In July 2015 we moved DRPP to open market purchases. The Restated Stock Option Plan (SOP) was terminated with respect to new grants in 2012; however, options granted before the Restated SOP was terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. There were 352,688 options outstanding at December 31, 2015, which were granted prior to termination of the plan. Stock Repurchase Program We have a share repurchase program under which we may purchase our common shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 2016 to repurchase up to an aggregate of the greater of 2.8 million shares or $100 million. No shares of common stock were repurchased pursuant to this program during the year ended December 31, 2015. Since the plan’s inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million. 64 6. STOCK-BASED COMPENSATION Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long-Term Incentive Plan (LTIP), an ESPP, and a Restated SOP. Long-Term Incentive Plan The LTIP is intended to provide a flexible, competitive compensation program for eligible officers and key employees. Under the LTIP, shares of common stock are authorized for equity incentive grants in the form of stock, restricted stock, restricted stock units, stock options, or performance shares. An aggregate of 850,000 shares were authorized for issuance as of December 31, 2015. Shares awarded under the LTIP may be purchased on the open market or issued as original shares. Of the 850,000 shares of common stock authorized for LTIP awards at December 31, 2015, there were 186,979 shares available for issuance under any type of award and 250,000 shares available for option grants. This assumes market, performance, and service based grants currently outstanding are awarded at the target level. There were no outstanding grants of restricted stock or stock options under the LTIP at December 31, 2015 or 2014. The LTIP stock awards are compensatory awards for which compensation expense is based on the fair value of stock awards, with expense being recognized over the performance and vesting period of the outstanding awards. Performance Shares Since the LTIP’s inception in 2001, performance shares, which incorporate market, performance, and service-based factors, have been granted annually with three-year performance periods. The following table summarizes performance share expense information: Dollars in thousands Estimated award: 2013-2015 grant(3) Actual award: 2012-2014 grant 2011-2013 grant Shares(1) Expense During Award Year(2) Total Expense for Award 8,465 $ 312 $ 1,240 8,621 9,819 582 390 1,821 960 (1) In addition to common stock shares, a participant also receives a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. (2) Amount represents the expense recognized in the third year of (3) the vesting period noted above. This represents the estimated number of shares to be awarded as of December 31, 2015 as certain performance share measures had been achieved. Amounts are subject to change with final payout amounts authorized by the Board of Directors in February 2016. The aggregate number of performance shares granted and outstanding at the target and maximum levels were as follows: Dollars in thousands Performance Period Performance Share Awards Outstanding Target Maximum 2015 Expense Cumulative Expense December 31, 2015 2013-15 2014-16 2015-17 Total 34,100 39,725 43,950 117,775 68,200 $ 312 $ 79,450 87,900 235,550 $ 632 853 1,797 1,240 1,250 853 For the 2013-2015 performance period, awards will be based on total shareholder return (TSR factor) relative to a peer group of gas distribution companies over the three- year performance period and on performance results achieved relative to specific core and non-core strategies (strategic factor). In addition to the TSR and strategic factors, the 2014-2016 and 2015-2017 performance period awards also included weighting for EPS and Return on Invested Capital (ROIC) factors. Compensation expense is recognized in accordance with accounting standards for stock-based compensation and calculated based on performance levels achieved and an estimated fair value using the Monte-Carlo method. The weighted-average grant date fair value of unvested shares at December 31, 2015 and 2014 was $49.09 and $42.06 per share, respectively. The weighted-average grant date fair value of shares vested during the year was $46.64 per share and for shares granted during the year was $51.78 per share. As of December 31, 2015, there was $2.3 million of unrecognized compensation expense related to the unvested portion of performance awards expected to be recognized through 2017. Restricted Stock Units In 2012, the Company began granting RSUs under the LTIP instead of stock options under the Restated SOP. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of 4 years from the grant date. Upon vesting, the RSU holder is issued one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU. The fair value of an RSU is equal to the closing market price of the Company's common stock on the grant date. During 2015, total RSU expense was $1.3 million compared to $0.9 million in 2014. As of December 31, 2015, there was $2.6 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2019. 65 Information regarding the RSU activity is summarized as follows: Number of RSUs Weighted - Average Price Per RSU Nonvested, December 31, 2012 24,864 $ Granted Vested Forfeited Nonvested, December 31, 2013 Granted Vested Forfeited Nonvested, December 31, 2014 Granted Vested Forfeited Nonvested, December 31, 2015 25,748 (5,455) (590) 44,567 38,765 (12,060) (478) 70,794 37,264 (19,003) (468) 88,587 47.57 45.38 48.01 46.58 46.27 42.19 46.52 45.47 44.00 46.29 44.81 44.99 44.78 Restated Stock Option Plan The Restated SOP was terminated for new option grants in 2012; however, options granted before the plan terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. Any new grants of stock options would be made under the LTIP. Options under the Restated SOP were granted to officers and key employees designated by a committee of our Board of Directors. All options were granted at an option price equal to the closing market price on the date of grant and may be exercised for a period up to 10 years and seven days from the date of grant. Option holders may exchange shares they have owned for at least 6 months, valued at the current market price, to purchase shares at the option price. Information regarding the Restated SOP activity is summarized as follows: Weighted - Average Price Per Share Intrinsic Value (In millions) Option Shares Balance outstanding, December 31, 2012 529,925 $ 42.22 $ Exercised Forfeited Balance outstanding, December 31, 2013 Exercised Forfeited Balance outstanding, December 31, 2014 Exercised Forfeited Balance outstanding and exercisable, December 31, 2015 (33,800) (3,975) 492,150 (69,662) (6,400) 416,088 (62,900) (500) 32.16 43.72 42.89 39.82 43.59 43.40 39.96 45.74 352,688 44.00 1.3 0.3 n/a 0.6 0.5 n/a 2.7 0.5 n/a 2.3 During 2015, cash of $2.5 million was received for stock options exercised and $0.1 million related tax expense was recognized. During 2015, 2014, and 2013, the total fair value of options that vested was $0.2 million, $0.4 million and $0.5 million, respectively. The weighted average remaining life of options exercisable and outstanding at December 31, 2015 was 3.6 years. Employee Stock Purchase Plan The ESPP allows employees to purchase common stock at 85% of the closing price on the trading day immediately preceding the initial offering date, which is set annually. Each eligible employee may purchase up to $21,227 worth of stock through payroll deductions over a 12-month period, with shares issued at the end of the 12-month subscription period. Stock-Based Compensation Expense Stock-based compensation expense is recognized as operations and maintenance expense or is capitalized as part of construction overhead. The following table summarizes the financial statement impact of stock-based compensation under our LTIP, Restated SOP and ESPP: In thousands 2015 2014 2013 Operations and maintenance expense, for stock-based compensation $ 2,673 $ 2,309 $ 1,876 Income tax benefit (1,012) (861) (765) Net stock-based compensation effect on net income $ 1,661 $ 1,448 $ 1,111 Amounts capitalized for stock-based compensation $ 661 $ 597 $ 331 7. DEBT Short-Term Debt Our primary source of short-term funds is from the sale of commercial paper and bank loans. In addition to issuing commercial paper or bank loans to meet seasonal working capital requirements, short-term debt is used temporarily to fund capital requirements. Commercial paper and bank loans are periodically refinanced through the sale of long- term debt or equity securities. Our commercial paper program is supported by one or more committed credit facilities. In the fourth quarter of 2015, we entered into a short-term credit facility loan totaling $50 million, as a short-term bridge through our peak heating season, which was repaid on February 4, 2016. At December 31, 2015, total short-term debt outstanding was $270 million, which includes $220 million of commercial paper and a $50 million credit facility. At December 31, 2014 total short-term debt outstanding was $234.7 million, which was comprised entirely of commercial paper. The weighted average interest rate at December 31, 2015 and 2014 was 0.6% and 0.4%, respectively. 66 The carrying cost of our commercial paper approximates fair value using Level 2 inputs, due to the short-term nature of the notes. See Note 2 for a description of the fair value hierarchy. At December 31, 2015, our commercial paper had a maximum maturity of 77 days and an average maturity of 36 days. We have a $300 million credit agreement, with a feature that allows us to request increases in the total commitment amount up to a maximum amount of $450 million. The maturity of the agreement is December 20, 2019. We have a letter of credit of $100 million. Any principal and unpaid interest owed on borrowings under the agreement is due and payable on or before the expiration date. There were no outstanding balances under the agreement and no letters of credit issued or outstanding at December 31, 2015 and 2014. The credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings or senior secured debt ratings, as applicable, by such rating agencies. A change in our debt ratings is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit facility. However, interest rates on any loans outstanding under the credit facility are tied to debt ratings, which would increase or decrease the cost of any loans under the credit facility when ratings are changed. The credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70% or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2015 and 2014. Long-Term Debt The issuance of first mortgage bonds (FMBs), which includes our medium-term notes, under the Mortgage and Deed of Trust (Mortgage) is limited by eligible property, adjusted net earnings and other provisions of the Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of our utility property. Maturities and Outstanding Long-Term Debt Retirement of long-term debt for each of the 12-month periods through December 31, 2020 and thereafter are as follows: In thousands Year 2016 2017 2018 2019 2020 Thereafter $ 25,000 40,000 22,000 30,000 75,000 409,700 67 The following table presents our debt outstanding as of December 31: In thousands First Mortgage Bonds 4.70 % Series B due 2015 5.15 % Series B due 2016 7.00 % Series B due 2017 6.60 % Series B due 2018 8.31 % Series B due 2019 7.63 % Series B due 2019 5.37 % Series B due 2020 9.05 % Series A due 2021 3.176 % Series B due 2021 3.542% Series B due 2023 5.62 % Series B due 2023 7.72 % Series B due 2025 6.52 % Series B due 2025 7.05 % Series B due 2026 7.00 % Series B due 2027 6.65 % Series B due 2027 6.65 % Series B due 2028 7.74 % Series B due 2030 7.85 % Series B due 2030 5.82 % Series B due 2032 5.66 % Series B due 2033 5.25 % Series B due 2035 4.00 % due 2042 2015 2014 — 25,000 40,000 22,000 10,000 20,000 75,000 10,000 50,000 50,000 40,000 20,000 10,000 20,000 20,000 19,700 10,000 20,000 10,000 30,000 40,000 10,000 50,000 601,700 40,000 25,000 40,000 22,000 10,000 20,000 75,000 10,000 50,000 50,000 40,000 20,000 10,000 20,000 20,000 19,700 10,000 20,000 10,000 30,000 40,000 10,000 50,000 641,700 Subsidiary Senior Secured Debt Gill Ranch debt due 2016 Less: Current maturities Total long-term debt — 601,700 25,000 $ 576,700 20,000 661,700 40,000 $ 621,700 Subsidiary Senior Secured Debt On December 18, 2015, Gill Ranch repaid $20 million of fixed-rate senior secured debt outstanding with an interest rate of 7.75%, which included a make whole interest provision using available cash and cash flows from operations, including cash from intercompany receivables. Retirements of Long-Term Debt The utility redeemed $40 million of FMBs with a coupon rate of 4.70% in June 2015. Fair Value of Long-Term Debt Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2. The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date: In thousands December 31, 2015 2014 Carrying amount $ 601,700 $ Estimated fair value 667,168 661,700 756,808 8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS We maintain a qualified non-contributory defined benefit pension plan, non-qualified supplemental pension plans for eligible executive officers and other key employees, and other postretirement employee benefit plans. We also have qualified defined contribution plans (Retirement K Savings Plan) for all eligible employees. The qualified defined benefit pension plan and Retirement K Savings Plan have plan assets, which are held in qualified trusts to fund retirement benefits. Effective January 1, 2007 and 2010, the qualified defined benefit retirement plans and postretirement benefits for non-union employees and union employees, respectively, were closed to new participants. These plans were not available to employees of our non-utility subsidiaries. Non-union and union employees hired or re-hired after December 31, 2006 and 2009, respectively, and employees of NW Natural subsidiaries are provided an enhanced Retirement K Savings Plan benefit. The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for the pension and other postretirement benefit plans, excluding the Retirement K Savings Plan, and a summary of the funded status and amounts recognized in the consolidated balance sheets as of December 31: In thousands Reconciliation of change in benefit obligation: Obligation at January 1 Service cost Interest cost Plan amendments(1) Net actuarial (gain) loss Benefits paid Obligation at December 31 Reconciliation of change in plan assets: Fair value of plan assets at January 1 Actual return on plan assets Employer contributions Benefits paid Postretirement Benefit Plans Pension Benefits Other Benefits 2015 2014 2015 2014 $ 487,278 $ 391,089 $ 32,072 $ 28,754 8,267 18,360 — (32,354) (35,923) 7,213 18,198 — 90,710 (19,932) 527 1,179 (3,435) 2,724 (2,018) 483 1,252 — 3,454 (1,871) $ 445,628 $ 487,278 $ 31,049 $ 32,072 $ 279,164 $ 267,062 $ (9,599) 15,696 (35,923) 19,957 12,077 (19,932) — $ — 2,018 (2,018) — — 1,871 (1,871) — Fair value of plan assets at December 31 $ 249,338 $ 279,164 $ — $ Funded status at December 31 (32,072) (1) We amended our qualified defined benefit pension plan to establish a health retirement account (HRA) plan for participants. The HRA plan (208,114) $ (196,290) $ (31,049) $ $ permits participants to obtain reimbursement of health care expenses on a nontaxable basis, and the amendment is effective April 1, 2016. Our qualified defined benefit pension plan has an aggregate benefit obligation of $411.8 million and $451.2 million at December 31, 2015 and 2014, respectively, and fair values of plan assets of $249.3 million and $279.2 million, respectively. The following table presents amounts realized through regulatory assets or in other comprehensive loss (income) for the years ended December 31: Regulatory Assets Other Comprehensive Loss (Income) Pension Benefits Other Postretirement Benefits Pension Benefits In thousands 2015 2014 2013 2015 2014 2013 2015 2014 2013 Net actuarial loss (gain) $ 419 $ 83,027 $ (51,892) $ 2,724 $ 3,454 $ (4,283) $ (2,549) $ 7,221 $ (3,302) Amortization of: Prior service cost Actuarial loss (230) (230) (230) (16,372) (9,823) (16,744) (197) (554) (197) (221) (197) (733) — 7 7 (2,236) (1,091) (1,550) Total $ (16,183) $ 72,974 $ (68,866) $ 1,973 $ 3,036 $ (5,213) $ (4,785) $ 6,137 $ (4,845) 68 The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at December 31: In thousands Prior service cost (credit) Net actuarial loss Total Regulatory Assets AOCL Pension Benefits Other Postretirement Benefits Pension Benefits 2015 2014 2015 2014 2015 2014 $ $ 406 $ 637 $ (3,143) $ 488 $ 1 $ 176,894 192,846 10,067 7,898 11,870 177,300 $ 193,483 $ 6,924 $ 8,386 $ 11,871 $ 2 16,604 16,606 The following table presents amounts recognized in AOCL and the changes in AOCL related to our non-qualified employee benefit plans: In thousands Beginning balance Amounts reclassified to AOCL Amounts reclassified from AOCL: Amortization of prior service costs Amortization of actuarial losses Total reclassifications before tax Tax (benefit) expense Total reclassifications for the period Ending balance In 2016, an estimated $13.3 million will be amortized from regulatory assets to net periodic benefit costs, consisting of $13.5 million of actuarial losses, and $0.2 million of prior service credits. A total of $1.3 million will be amortized from AOCL to earnings related to actuarial losses in 2016. Our assumed discount rate for the pension plan and other postretirement benefit plans was determined independently based on the Citigroup Above Median Curve (discount rate curve), which uses high quality corporate bonds rated AA- or higher by S&P or Aa3 or higher by Moody’s. The discount rate curve was applied to match the estimated cash flows in each of our plans to reflect the timing and amount of expected future benefit payments for these plans. Our assumed expected long-term rate of return on plan assets for the qualified pension plan was developed using a weighted average of the expected returns for the target asset portfolio. In developing the expected long-term rate of return assumption, consideration was given to the historical performance of each asset class in which the plans’ assets are invested and the target asset allocation for plan assets. Our investment strategy and policies for qualified pension plan assets held in the retirement trust fund were approved by our retirement committee, which is composed of senior management with the assistance of an outside investment consultant. The policies set forth the guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate consideration for liquidity, portfolio risk and return expectations. All investments are expected to satisfy the prudent investments rule under the Employee Retirement Income Security Act of 1974. The approved asset classes may include cash and short-term investments, fixed income, common stock and convertible securities, absolute and real Year Ended December 31, 2015 2014 $ $ (10,076) $ 2,549 — 2,236 4,785 (1,871) 2,914 (7,162) $ (6,358) (7,221) (7) 1,091 (6,137) 2,419 (3,718) (10,076) return strategies, real estate, and investments in NW Natural securities. Plan assets may be invested in separately managed accounts or in commingled or mutual funds. Investment re-balancing takes place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target ranges. The retirement trust fund is not currently invested in NW Natural securities. The following table presents the pension plan asset target allocation at December 31, 2015: Asset Category U.S. large cap equity U.S. small/mid cap equity Non-U.S. equity Emerging markets equity Long government/credit High yield bonds Emerging market debt Real estate funds Absolute return strategy Target Allocation 18.0% 10.0 18.0 5.0 20.0 5.0 5.0 7.0 12.0 Our non-qualified supplemental defined benefit plan obligations were $33.8 million and $36.1 million at December 31, 2015 and 2014, respectively. These plans are not subject to regulatory deferral, and the changes in actuarial gains and losses, prior service costs and transition assets, or obligations are recognized in AOCL, net of tax until they are amortized as a component of net periodic benefit cost. These are unfunded, non-qualified plans with no plan assets; however, we indirectly fund a significant portion of our obligations with company- and trust-owned life insurance and other assets. 69 Our other postretirement benefit plans are unfunded plans but are subject to regulatory deferral. The actuarial gains and losses, prior service costs and transition assets or obligations for these plans are recognized as a regulatory asset. Net periodic benefit costs consist of service costs, interest costs, the amortization of actuarial gains and losses and the expected returns on plan assets, which are based in part on a market-related valuation of assets. The market- related valuation reflects differences between expected returns and actual investment returns with the differences recognized over a three-year or less period from the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility. The following table provides the components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31: In thousands Service cost Interest cost Expected return on plan assets Amortization of prior service costs Amortization of net actuarial loss Net periodic benefit cost Amount allocated to construction Amount deferred to regulatory balancing account(1) Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 $ 8,267 $ 7,213 $ 8,698 $ 527 $ 483 $ 18,360 (20,676) 231 18,609 24,791 (6,834) (8,241) 18,198 16,400 1,179 1,252 (19,496) (18,721) 223 10,914 17,052 (4,625) (4,578) 223 18,294 24,894 (6,712) (9,115) — 197 554 2,457 (808) — — 197 221 2,153 (702) — 656 1,157 — 197 734 2,744 (856) — Net amount charged to expense $ 9,716 $ 7,849 $ 9,067 $ 1,649 $ 1,451 $ 1,888 (1) The deferral of defined benefit pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2. Net periodic benefit costs are reduced by amounts capitalized to utility plant based on approximately 25% to 35% payroll overhead charge. In addition, a certain amount of net periodic benefit costs are recorded to the regulatory balancing account for pensions. Net periodic pension cost less amounts charged to capital accounts and regulatory balancing accounts are expenses recognized in earnings. The following table provides the assumptions used in measuring periodic benefit costs and benefit obligations for the years ended December 31: Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Assumptions for net periodic benefit cost: Weighted-average discount rate 3.82% 4.71% 3.84% 3.74% 4.45% 3.56% Rate of increase in compensation 3.25-5.0% 3.25-5.0% 3.25-5.0% Expected long-term rate of return 7.50% 7.50% 7.50% n/a n/a n/a n/a n/a n/a Assumptions for year-end funded status: Weighted-average discount rate 4.21% 3.85% 4.73% 4.00% 3.74% 4.45% Rate of increase in compensation 3.25-4.5% 3.25-5.0% 3.25-5.0% Expected long-term rate of return 7.50% 7.50% 7.50% n/a n/a n/a n/a n/a n/a 70 (MAP-21) legislation changed several provisions affecting pension plans, including temporary funding relief and Pension Benefit Guaranty Corporation (PBGC) premium increases, which reduces the level of minimum required contributions in the near-term but generally increases contributions in the long-run and increases the operational costs of running a pension plan. In 2014, the Highway and Transportation Funding Act (HATFA) was signed and extends certain aspects of MAP-21 as well as modifies the phase-out periods for the limitations. Our qualified defined benefit pension plan is currently underfunded by $162.5 million at December 31, 2015. Including the impacts of MAP-21 and HATFA, we made cash contributions totaling $14.1 million to our qualified defined benefit pension plan for 2015. During 2016, we expect to make contributions of approximately $14.5 million to this plan. Multiemployer Pension Plan In addition to the Company-sponsored defined benefit plans presented above, prior to 2014 we contributed to a multiemployer pension plan for our utility's union employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). The plan's employer identification number is 94-6076144. Effective December 22, 2013, we withdrew from the plan, which was a noncash transaction. Vested participants will receive all benefits accrued through the date of withdrawal. As the plan was underfunded at the time of withdrawal, we were assessed a withdrawal liability of $8.3 million, plus interest, which requires NW Natural to pay $0.6 million each year to the plan for 20 years beginning in July 2014. The cost of the withdrawal liability was deferred to a regulatory account on the balance sheet. We made payments of $0.6 million for 2015, and as of December 31, 2015 the liability balance was $7.8 million. For 2014 and 2013, contributions to the plan were $0.4 million and $0.5 million, respectively, which was approximately 4% to 5% of the total contributions to the plan by all employer participants in those years. Defined Contribution Plan The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Employer contributions totaled $3.7 million, $3.4 million, and $2.2 million for 2015, 2014, and 2013, respectively. The Retirement K Savings Plan includes an Employee Stock Ownership Plan. Deferred Compensation Plans The supplemental deferred compensation plans for eligible officers and senior managers are non-qualified plans. These plans are designed to enhance the retirement savings of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly. The assumed annual increase in health care cost trend rates used in measuring other postretirement benefits as of December 31, 2015 was 7.50% for both pre- and post-65 populations. These trend rates apply to both medical and prescription drugs. Medical costs and prescription drugs are assumed to decrease gradually each year to a rate of 4.75% by 2024. Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans; however, other postretirement benefit plans have a cap on the amount of costs reimbursable from the Company. A one percentage point change in assumed health care cost trend rates would have the following effects: In thousands 1% Increase 1% Decrease Effect on net periodic postretirement health care benefit cost Effect on the accumulated postretirement benefit obligation $ 100 $ (74) 742 (665) We review mortality assumptions annually and will update for material changes as necessary. In 2015, we adopted the Society of Actuaries Scale MP-2015, which projects a mortality detriment compared to the previous table used, thereby decreasing benefit plan liabilities. The following table provides information regarding employer contributions and benefit payments for the qualified pension plan, non-qualified pension plans and other postretirement benefit plans for the years ended December 31, and estimated future contributions and payments: In thousands Pension Benefits Other Benefits $ 12,077 $ Employer Contributions: 2014 2015 2016 (estimated) Benefit Payments: 2013 2014 2015 Estimated Future Benefit Payments: 2016 2017 2018 2019 2020 15,696 16,695 18,855 19,932 35,923 21,589 22,028 22,974 23,950 26,242 1,871 2,018 2,035 1,895 1,871 2,018 2,035 2,060 2,073 2,132 2,178 2021-2025 134,736 11,068 Employer Contributions to Company-Sponsored Defined Benefit Pension Plans We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established funding requirements for defined benefit plans. The Act establishes a 100% funding target over seven years for plan years beginning after December 31, 2008. In 2012 the Moving Ahead for Progress in the 21st Century Act 71 Fair Value Below is a description of the valuation methodologies used for assets measured at fair value. In cases where the pension plan is invested through a collective trust fund or mutual fund, our custodian uses the fund's market value. The custodian also provides the market values for investments directly owned. U.S. LARGE CAP EQUITY and U.S. SMALL/MID CAP EQUITY. These are level 1 and 2 assets. The level 1 assets consist of directly held stocks and mutual funds with a readily determinable fair value, including a published net asset value (NAV). The level 2 assets consist of mutual funds where NAV is not published but the investment can be readily disposed of at NAV or market value. Directly held stocks are valued at the closing price reported in the active market on which the individual security is traded, and mutual funds are valued at NAV. This asset class includes investments primarily in U.S. common stocks. NON-U.S. EQUITY. These are level 1 and 2 assets. The level 1 assets consist of directly held stocks, and the level 2 assets consist of a commingled trust where the NAV/unit price is not published but the investment can be readily disposed of at the NAV/unit price. Directly held stocks are valued at the closing price reported in the active market on which the individual security is traded, and the commingled trust is valued at the unit price of the trust. This asset class includes investments primarily in foreign equity common stocks. EMERGING MARKETS EQUITY. This is a level 2 asset consisting of an open-end mutual fund where the NAV price is not published but the investment can be readily disposed of at the NAV. This asset class includes investments primarily in common stocks in emerging markets. FIXED INCOME. This is a level 2 asset consisting of a mutual fund, valued at NAV, where NAV is not published, but the investment can be readily disposed of at the NAV. This asset class includes investments primarily in investment grade debt and fixed income securities. LONG GOVERNMENT/CREDIT. These are level 1 and 2 assets. The level 1 assets consist of a fixed-income mutual fund with readily determinable fair value, including a published NAV. The level 2 assets consist of a commingled trust and directly held fixed-income securities whose values are determined by closing prices if available and by matrix prices for illiquid securities. This asset class includes long duration fixed income investments primarily in U.S. treasuries, U.S. government agencies, municipal securities, mortgage-backed securities, asset-backed securities, as well as U.S. and international investment-grade corporate bonds. HIGH YIELD BONDS. This is a level 2 asset consisting of a limited partnership where valuation is not published but the investment can be readily disposed of at market value. This asset class includes investments primarily in high yield bonds. EMERGING MARKET DEBT. This is a level 1 asset consisting of a mutual fund with a readily determinable fair value, including a published NAV. This asset class includes investments primarily in emerging market debt. REAL ESTATE FUNDS. This is a level 1 asset consisting of a mutual fund with a readily determinable fair value, including a published NAV. This asset class includes investments primarily in real estate investment trust (REIT) equity securities globally. ABSOLUTE RETURN STRATEGY. This is a level 2 asset consisting of a hedge fund of funds where the valuation is not published but the investment can be readily disposed of at unit price. The hedge fund of funds is valued at the weighted average value of investments in various hedge funds, which in turn are valued at the closing price of the underlying securities. This asset class primarily includes investments in common stocks and fixed income securities. REAL RETURN STRATEGY. This is a Level 1 asset representing a mutual fund with a readily determinable fair value, including a published NAV. This asset class includes an investment in a broad range of assets primarily including fixed income, high-yield bonds and emerging market debt. CASH AND CASH EQUIVALENTS. This is a Level 2 asset representing mutual funds without published NAV's but the investment can be readily disposed of at the NAV. The mutual funds are valued at the NAV of the shares held by the plan at the valuation date. This asset class includes money market mutual funds. The preceding valuation methods may produce a fair value calculation that is not indicative of net realizable value or reflective of future fair values. Although we believe these valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. Investment securities are exposed to various financial risks including interest rate, market and credit risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the values of our investment securities will occur in the near term and such changes could materially affect our investment account balances and the amounts reported as plan assets available for benefit payments. 72 The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the retirement trust fund: In thousands Investments U.S. large cap equity U.S. small/mid cap equity Non-U.S. equity Emerging markets equity Long government/credit High yield bonds Emerging market debt Real estate funds Absolute return strategy Cash and cash equivalents Total investments Investments U.S. large cap equity U.S. small/mid cap equity Non-U.S. equity Emerging markets equity Fixed income Long government/credit High yield bonds Emerging market debt Real estate funds Absolute return strategy Real return strategy Cash and cash equivalents Total investments Receivables Accrued interest and dividend income Due from broker for securities sold Total receivables Liabilities Due to broker for securities purchased Total investment in retirement trust December 31, 2015 Level 1 Level 2 Level 3 Total $ 44,528 $ 23,495 20,725 — — — 7,746 17,261 — — — $ — 22,823 11,120 48,456 12,298 — — 36,758 4,116 — $ — — — — — — — — — 44,528 23,495 43,548 11,120 48,456 12,298 7,746 17,261 36,758 4,116 $ 113,755 $ 135,571 $ — $ 249,326 December 31, 2014 Level 1 Level 2 Level 3 Total $ 39,405 $ 122 $ — $ 27,172 16,369 — — 40,584 — 9,133 18,890 — 8,308 — 85 17,221 7,145 598 40,235 13,087 — — 37,065 — 1,720 — — — — — — — — — — — 39,527 27,257 33,590 7,145 598 80,819 13,087 9,133 18,890 37,065 8,308 1,720 $ 159,861 $ 117,278 $ — $ 277,139 December 31, 2015 2014 486 $ 88 574 $ 510 1,694 2,204 562 249,338 $ $ 179 279,164 $ $ $ $ 73 9. INCOME TAX The following table provides a reconciliation between income taxes calculated at the statutory federal tax rate and the provision for income taxes reflected in the consolidated statements of comprehensive income for December 31: Dollars in thousands 2015 2014 2013 Income taxes at federal statutory rate Increase (decrease): Current state income tax, net of federal tax benefit Amortization of investment tax credits Differences required to be flowed-through by regulatory commissions Gains on company and trust-owned life insurance Other, net Total provision for income taxes $ 31,310 $ 35,117 $ 35,785 4,195 4,666 4,674 (118) (201) (271) 2,357 2,357 2,357 (766) (1,225) (689) 393 (864) 24 $ 35,753 $ 41,643 $ 41,705 Effective tax rate 40.0% 41.5% 40.8% The decrease in the effective income tax rate for 2015 compared to 2014 was primarily due to the benefits of depletion deductions from gas reserves activity. The increase from 2014 compared to 2013 was primarily the result of a $0.6 million income tax charge in 2014 related to a higher statutory tax rate in Oregon, which required the revaluation of deferred tax balances. The provision (benefit) for current and deferred income taxes consists of the following at December 31: In thousands Current Federal State Deferred Federal State 2015 2014 2013 $ 10,558 $ 14,823 $ 61 24 10,619 14,847 (62) (11) (73) 18,729 18,635 6,405 8,161 25,134 26,796 35,109 6,669 41,778 Total provision for income taxes $ 35,753 $ 41,643 $ 41,705 The following table summarizes the total provision (benefit) for income taxes for the utility and non-utility business segments for December 31: In thousands Utility: Current Deferred Deferred investment tax credits Non-utility business segments: Current Deferred 2015 2014 2013 $ 15,890 $ 24,317 $ (73) 20,834 19,518 38,073 (118) (201) (271) 36,606 43,634 37,729 (5,271) 4,418 (853) (9,470) 7,479 (1,991) — 3,976 3,976 Total provision for income taxes $ 35,753 $ 41,643 $ 41,705 The following table summarizes the tax effect of significant items comprising our deferred income tax accounts at December 31: In thousands Deferred tax liabilities: Plant and property Regulatory income tax assets Regulatory liabilities Non-regulated deferred tax liabilities Total Deferred tax assets: Pension and postretirement obligations Alternative minimum tax credit carryforward Loss and credit carryforwards Total 2015 2014 $ 408,342 $ 386,732 47,427 46,400 49,683 51,805 55,776 48,683 $ 551,852 $ 542,996 $ 4,666 $ 6,537 16,699 514 21,879 16,788 12,657 35,982 Deferred income tax liabilities, net 529,973 507,014 Deferred investment tax credits 48 166 Deferred income taxes and investment tax credits $ 530,021 $ 507,180 Management assesses the available positive and negative evidence to estimate if sufficient taxable income will be generated to utilize the existing deferred tax assets. Based upon this assessment, we have determined we are more likely than not to realize all deferred tax assets recorded as of December 31, 2015. 74 10. PROPERTY, PLANT, AND EQUIPMENT The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation at December 31: In thousands 2015 2014 Utility plant in service $2,745,485 $2,661,097 Utility construction work in progress 39,288 24,886 Less: Accumulated depreciation 867,377 836,510 Utility plant, net Non-utility plant in service Non-utility construction work in progress Less: Accumulated depreciation 1,917,396 1,849,473 296,839 297,295 7,768 39,340 9,282 34,457 Non-utility plant, net 265,267 272,120 Total property, plant, and equipment $2,182,663 $2,121,593 Capital expenditures in accrued liabilities $ 8,985 $ 8,757 The weighted average depreciation rate was 2.8% for utility assets and 2.2% for non-utility assets in 2015, 2014, and 2013. Accumulated depreciation does not include the accumulated provision for asset removal costs of $327.0 million and $311.2 million at December 31, 2015 and 2014, respectively. These accrued asset removal costs are reflected on the balance sheet as regulatory liabilities. See Note 2. During 2014, we acquired $1.3 million of equipment under capital leases. In 2015, we did not acquire any equipment under capital leases. The Company estimates it has Oregon net operating loss (NOL) carryforwards of $3.9 million at December 31, 2015. The NOL carryforwards will be carried forward to reduce our current tax liability in future years. We anticipate that we will be able to utilize the NOL carryforwards before they begin to expire in 2028. Alternative minimum tax (AMT) credits of $16.7 million, general business credits of $0.3 million, and charitable contribution carryforwards of $2.3 million are also available. The AMT credits do not expire, and we anticipate fully using the general business credits and charitable contribution carryforwards before they begin to expire in 2033 and 2016, respectively. As a result of certain realization requirements prescribed in the accounting guidance for income taxes, the tax benefit of statutory depletion is recognized no earlier than the year in which the depletion is deductible on the Company’s federal income tax return. Income tax expense was decreased by $0.9 million in 2015 as a result of realizing deferred depletion benefit from 2013 and 2014. This benefit is included in Other in the statutory rate reconciliation table. Uncertain tax positions are accounted for in accordance with accounting standards that require management’s assessment of the anticipated settlement outcome of material uncertain tax positions taken in a prior year, or planned to be taken in the current year. Until such positions are sustained, we would not recognize the uncertain tax benefits resulting from such positions. No reserves for uncertain tax positions existed as of December 31, 2015, 2014, or 2013. The Company’s examination by the Internal Revenue Service (IRS) for tax years 2009 through 2011 was completed during the first quarter of 2014. The examination did not result in a material change to the returns as originally filed or previously adjusted for net operating loss carrybacks. The IRS Compliance Assurance Process (CAP) examinations of the 2013 and 2014 tax years were completed in the first and fourth quarters of 2015, respectively. There were no material changes to these returns as filed. The 2015 year is currently under IRS CAP examination. The Company’s 2016 CAP application has been accepted by the IRS. Under the CAP program the Company works with the IRS to identify and resolve material tax matters before the tax return is filed each year. As of December 31, 2015, tax year 2012 remains open for federal examination, and tax years 2012 through 2015 remain open for state examination. 75 11. GAS RESERVES We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of December 31, 2015. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Our investment in gas reserves provides long-term price protection for utility customers and currently incorporates two agreements: the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested. We entered into our original agreements with Encana in 2011 under which we hold working interests in certain sections of the Jonah Field. Gas produced in these sections is sold at prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to the utility's cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return. In March 2014, we amended the original gas reserves agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field. We also retained the right to invest in new wells with Jonah Energy. The amended agreements allow us to invest in additional wells on a well- by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, and may have the opportunity to participate in more wells in the future. In September 2015, the OPUC adopted an all-party settlement, under which volumes produced from the additional wells drilled in 2014 are included in our Oregon PGA beginning November 1, 2015 at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment. Gas reserves acted to hedge the cost of gas for approximately 11% and 10% of our utility's gas supplies for the years ended December 31, 2015 and 2014, respectively. The following table outlines our net gas reserves investment at December 31: In thousands 2015 2014 Gas reserves, current $ 17,094 $ 20,020 Gas reserves, non-current 170,453 167,190 Less: Accumulated amortization 55,901 37,910 Total gas reserves(1) Less: Deferred taxes on gas reserves Net investment in gas reserves(1) 131,646 149,300 27,203 18,551 $ 104,443 $ 130,749 (1) Our investment in additional wells included in total gas reserves was $8.0 million ($4.3 million net of deferred taxes) and $9.2 million ($8.4 million net of deferred taxes) at December 31, 2015 and December 31, 2014, respectively. Our investment is included on our balance sheet under gas reserves with our maximum loss exposure limited to our current investment balance. 12. INVESTMENTS Investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity method. The following table summarizes our other investments at December 31: In thousands 2015 2014 Investments in life insurance policies $ 52,308 $ 52,366 Investments in gas pipeline Other 13,866 13,962 1,892 1,910 Total other investments $ 68,066 $ 68,238 Investment in Life Insurance Policies We have invested in key person life insurance contracts to provide an indirect funding vehicle for certain long-term employee and director benefit plan liabilities. The amount in the above table is reported at cash surrender value, net of policy loans. Investments in Gas Pipeline TWP, a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly- owned subsidiary of TransCanada Corporation. 76 VIE Analysis TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate influence over it. Our investments in TWH and TWP are included in other investments on our balance sheet. If we do not develop this investment, then our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at December 31, 2015 and 2014. Impairment Analysis Our investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment at each reporting period and following updates to our corporate planning assumptions. If it is determined a loss in value is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value. Fair value is based on quoted market prices when available or on the present value of expected future cash flows. Differing assumptions could affect the timing and amount of a charge recorded in any period. In 2011, TWP withdrew its original application with the FERC for a proposed natural gas pipeline in Oregon and informed FERC that it intended to re-file an application to reflect changes in the project scope aligning the project with the region’s current and future gas infrastructure needs. TWP continues working with customers in the Pacific Northwest to further understand their gas transportation needs and determine the commercial support for a revised pipeline proposal. A new FERC certificate application is expected to be filed to reflect a revised scope based on these regional needs. Our equity investment was not impaired at December 31, 2015 as the fair value of expected cash flows from planned development exceeded our remaining equity investment of $13.4 million at December 31, 2015. However, if we learn that the project is not viable or will not go forward, then we could be required to recognize a maximum charge of up to approximately $13.4 million based on the current amount of our equity investment, net of cash and working capital at TWP. We will continue to monitor and update our impairment analysis as required. 13. DERIVATIVE INSTRUMENTS We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts. We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars. In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment. We also enter into exchange contracts related to the third- party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers. Notional Amounts The following table presents the absolute notional amounts related to open positions on our derivative instruments: In thousands Natural gas (in therms): Financial Physical Foreign exchange At December 31, 2015 2014 346,875 287,475 404,645 420,980 $ 9,025 $ 12,230 Purchased Gas Adjustment (PGA) Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. Derivative contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. In general, our commodity hedging for the current gas year is completed prior to the start of the upcoming gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. As of November 1, 2015, we reached our target hedge percentage of approximately 75% for the 2015-16 gas year. These hedge prices were included in the PGA filings and qualified for regulatory deferral. 77 Unrealized and Realized Gain/Loss The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments: In thousands Expense to cost of gas Operating revenues Less: Amounts deferred to regulatory accounts on balance sheet December 31, 2015 December 31, 2014 Natural gas commodity Foreign exchange Natural gas commodity Foreign exchange $ (22,600) $ 226 (419) $ — (32,784) $ — 22,434 419 32,782 (382) — 382 — Total gain (loss) in pre-tax earnings $ 60 $ — $ (2) $ UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability. REALIZED GAIN/LOSS. We realized net losses of $37.7 million and net gains of $10.5 million for the years ended December 31, 2015 and 2014, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year. Credit Risk Management of Financial Derivatives Instruments No collateral was posted with or by our counterparties as of December 31, 2015 or 2014. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our statement of financial position. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event. credit limits and portfolio diversification, we have not been subject to collateral calls in 2015 or 2014. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $23.2 million at December 31, 2015, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows: Credit Rating Downgrade Scenarios (Current Ratings) A+/A3 BBB+/ Baa1 BBB/ Baa2 BBB-/ Baa3 Specul- ative $ — $ — $ — $4,852 $ 21,185 — — — 4,164 15,497 In thousands With Adequate Assurance Calls Without Adequate Assurance Calls If netted by counterparty, our derivative position would result in an asset of $2.7 million and a liability of $25.5 million as of December 31, 2015. As of December 31, 2014, our derivative position would have resulted in an asset of $0.2 million and a liability of $33.4 million. We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. We utilize master netting arrangements through International Swaps and Derivatives Association contracts to minimize this risk along with collateral support agreements with counterparties based on their credit ratings. In certain cases we require guarantees or letters of credit from counterparties to meet our minimum credit requirement standards. Our financial derivatives policy requires counterparties to have a certain investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. We do not speculate with derivatives; instead, we use derivatives to hedge our exposure above risk tolerance limits. Any increase in market risk created by the use of derivatives should be offset by the exposures they modify. We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral or guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes 78 14. COMMITMENTS AND CONTINGENCIES Leases We lease land, buildings and equipment under agreements that expire in various years, including a 99-year land lease that extends through 2108. Rental expense under operating leases was $5.5 million, $5.9 million, and $5.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. The following table reflects the future minimum lease payments due under non-cancelable leases at December 31, 2015. These commitments relate principally to the lease of our office headquarters, underground gas storage facilities and computer equipment. In thousands Operating leases Capital leases $ 5,417 $ 564 $ 5,363 5,348 5,313 2,765 30,475 156 3 — — — Minimum lease payments 5,981 5,519 5,351 5,313 2,765 30,475 $ 54,681 $ 723 $ 55,404 2016 2017 2018 2019 2020 Thereafter Total Gas Purchase and Pipeline Capacity Purchase and Release Commitments We have signed agreements providing for the reservation of firm pipeline capacity under which we are required to make fixed monthly payments for contracted capacity. The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies. In addition, we have entered into long-term sale agreements to release firm pipeline capacity. We also enter into short-term and long-term gas purchase agreements. consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial condition, government actions and market news. We use a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices. The results of the model are used to establish earnings-at-risk trading limits. Our credit risk for all outstanding financial derivatives at December 31, 2015 extends to March 2018. We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss; however, we would expect such a loss to be eligible for regulatory deferral and rate recovery, subject to a prudence review. All of our existing counterparties currently have investment-grade credit ratings. Fair Value In accordance with fair value accounting, we include non- performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at December 31, 2015. As of December 31, 2015 and 2014, the net fair value was a liability of $22.8 million and a liability of $33.2 million, respectively, using significant other observable, or level 2, inputs. No level 3 inputs were used in our derivative valuations, and there were no transfers between level 1 or level 2 during the years ended December 31, 2015 and 2014. See Note 2. 79 The aggregate amounts of these agreements were as follows at December 31, 2015: In thousands 2016 2017 2018 2019 2020 Thereafter Total Less: Amount representing interest Total at present value Gas Purchase Agreements Pipeline Capacity Purchase Agreements Pipeline Capacity Release Agreements $ 61,464 $ 79,487 $ 3,739 — — — — — 61,464 79,370 75,796 75,683 72,091 340,027 722,454 — — — — — 3,739 123 110,899 11 $ 61,341 $ 611,555 $ 3,728 Our total payments for fixed charges under capacity purchase agreements were $85.2 million for 2015, $94.3 million for 2014, and $98.2 million for 2013. Included in the amounts were reductions for capacity release sales of $4.4 million for 2015, $4.8 million for 2014, and $4.5 million for 2013. In addition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements. In certain take-or-pay purchase commitments, annual deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements. Environmental Matters Refer to Note 15 for a discussion of environmental commitments and contingencies. 15. ENVIRONMENTAL MATTERS We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties (PRPs). When amounts are prudently expended related to site remediation, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding. Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After the ROD is issued, we negotiate a consent decree or consent judgment for designing and implementing the remedy. We have the ability to further refine estimates of remediation liabilities at that time. Remediation may include treatment of contaminated media such as sediment, soil and groundwater, removal and disposal of media, or institutional controls such as legal restrictions on future property use. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post- remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described above. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated where a range of potential loss is available. Unless there is an estimate within the range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations and the determination by regulators of remediation alternatives. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. As of December 31, 2015, we have not received any material NRD claims. 80 Environmental Sites The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet at December 31: In thousands Portland Harbor site: Gasco/Siltronic Sediments Other Portland Harbor Gasco Upland site Siltronic Upland site Central Service Center site Front Street site Oregon Steel Mills Total PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and the Siltronic uplands sites. We are a PRP to the Superfund site and have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/ Feasibility Study (RI/FS), which we submitted to the EPA in 2012. In August 2015, the EPA issued its own Draft Feasibility Study (Draft FS) for comment. The EPA Draft FS provides a new range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/ Siltronic Sediment site, discussed below. The range of present value costs estimated by the EPA for various remedial alternatives for the entire Portland Harbor, as provided by the EPA's Draft FS, is $791 million to $2.45 billion. The range provided in the EPA's Draft FS is based on cost alternatives the EPA estimates to have an accuracy between -30% and +50% of actual costs, depending on the scope of work. While the EPA's Draft FS provides a higher range of costs than the LWG's submission in 2012, our potential liability is still a portion of the costs of the remedy the EPA will select for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. We are participating in a non- binding allocation process in an effort to settle this potential liability. The new EPA Draft FS does not provide any additional clarification around allocation of costs. We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects. Current Liabilities Non-Current Liabilities 2015 2014 2015 2014 $ 2,229 $ 1,767 $ 42,641 $ 38,019 1,972 10,599 951 25 1,155 — 1,934 9,535 957 171 1,020 — 5,073 52,117 337 — 7,748 179 4,338 37,117 348 — 122 179 $ 16,931 $ 15,384 $ 108,095 $ 80,123 Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up range from $44.9 million to $350 million. We have recorded a liability of $44.9 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. Other Portland Harbor. NW Natural incurs costs related to its membership in the LWG. NW Natural also incurs costs related to natural resource damages from these sites. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have recorded a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor or noted above. 81 GASCO UPLANDS SITE. A predecessor of NW Natural owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action. We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time. In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the initial testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure. Beginning November 1, 2013, capital asset costs of $19.0 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base. A portion of these proceeds was noncash in 2014. OTHER SITES. In addition to those sites above, we have environmental exposures at four other sites: Siltronic, Central Service Center, Front Street and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the remediation and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time. Siltronic Upland. A portion of the Siltronic property adjacent to the Gasco site was formerly owned by Portland Gas and Coke, NW Natural's predecessor. We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ. Central Service Center site. We are currently performing an environmental investigation of the property under the ODEQ's Independent Cleanup Pathway. This site is on 82 ODEQ's list of sites with confirmed releases of hazardous substances, and cleanup is necessary. Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.3 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design. Oregon Steel Mills site. Refer to the “Legal Proceedings,” below. Site Remediation and Recovery Mechanism We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test. REGULATORY ACTIVITIES. An Order from the OPUC in February 2015 deemed certain environmental remediation expenses and associated carrying costs deferred through March 31, 2014 prudent. Our settlement with insurance carriers resulting in insurance proceeds received was also deemed prudent in the Order. Under the Order, we were required to forgo the collection of $15 million out of approximately $95 million of environmental remediation expenses and associated carrying costs we had deferred through 2012. The OPUC disallowed this amount from rate recovery based on its determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. See Note 2 for information regarding the regulatory disallowance of past deferred costs under the Order received from the OPUC in February 2015. We submitted the required compliance filing demonstrating the proposed implementation of the Order and SRRM in March 2015. In September 2015, as a result of discussions with the parties, we withdrew our original compliance filing and submitted a revised filing. The parties raised three issues with our proposed implementation of the Order. First, the parties asserted that interest on the $15 million charge should be separately disallowed, in addition to the specified $15 million. This interest would total approximately $2.8 million. Second, the parties raised issues with how the state allocation rates from the Order are applied to our environmental remediation sites. Third, a customer group disagreed with our treatment of expenses put into the SRRM amortization account. In addition, we requested clarification from the OPUC regarding the amount of Oregon-allocated insurance proceeds to be held in a secured account. In September 2015, the OPUC resolved the issue by adopting an all-party settlement, which provided that we did not need to obtain a secured account. Instead, under the order, insurance proceeds used to offset future environmental expenses will accrue interest at a rate equal to the five-year treasury rate plus 100 basis points. Currently, Oregon-allocated insurance proceeds total approximately $93 million on a pre-tax basis. On January 27, 2016, the OPUC issued an Order addressing the outstanding issues. See Note 16 regarding this subsequent event. COLLECTIONS FROM CUSTOMERS. The SRRM provides us with the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test. The SRRM created three classes of deferred environmental remediation expense: • Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. • Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. • Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We included $8.4 million of deferred remediation expense approved by the OPUC for collection during the 2015-2016 PGA year. In addition to the collection amount noted above, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize our deferred regulatory asset balance through operating expense. We received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012, and the remaining two-thirds will be applied to costs over the next 20 years. Annually, the Order provided for the application of $5 million of insurance proceeds against deferred remediation expense deemed prudent in the same annual period; annual amounts not utilized are carried forward to apply against future prudently incurred costs. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of December 31, 2015, we have applied $53.2 million of insurance proceeds to prudently incurred remediation costs. 83 The following table presents information regarding the total amount of cash paid for environmental sites and the total regulatory asset deferred as of December 31: In thousands Cash paid Total regulatory asset deferral(1) Current regulatory assets(2) 2015 2014 $ 124,325 $ 113,740 85,854 9,270 76,584 58,859 — 58,859 Long-term regulatory assets (1) Includes cash paid, remaining liability and interest, net of insurance reimbursement, amounts collected from customers, and amounts reclassified to utility plant for the water treatment station. (2) Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million base rate rider. The Oregon amounts are recoverable through utility rates, subject to an earnings test. ENVIRONMENTAL EARNINGS TEST. The Order directed us to implement an annual environmental earnings test for our prudently incurred remediation expense. Prudently incurred Oregon allocated annual remediation expense and interest in excess of the $5 million tariff rider and $5 million insurance proceeds application plus interest on the insurance proceeds are recoverable through the SRRM, to the extent the utility earns at or below our authorized Return On Equity (ROE). To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE. Under the Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if the Company gains greater certainty about its future remediation costs, to consider whether adjustments to the mechanism may be appropriate. WASHINGTON DEFERRAL. In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Annually, we review all regulatory assets for recoverability or more often if circumstances warrant. If we should determine all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings in the period such a determination is made. Legal Proceedings NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part I, Item 3, “Legal Proceedings.” OREGON STEEL MILLS SITE. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows. For additional information regarding other commitments and contingencies, see Note 14. 16. SUBSEQUENT EVENT On January 27, 2016, the Public Utility Commission of Oregon (OPUC) issued an Order (2016 OPUC Order) deciding the three issues raised as a result of our required Site Remediation Recovery Mechanism (SRRM) compliance filing. The OPUC ordered: (1) the disallowance of $2.8 million of interest earned on the previously disallowed environmental expenditures amounts; (2) the allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. Under a prior OPUC order we were required to forgo collection of $15 million out of approximately $95 million of environmental remediation expenses and associated carrying costs that the Company had deferred through 2012 based on the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. We recognized interest of approximately $2.8 million on the $15 million charge after that time. This interest is shown as a regulatory asset in our financial statements, and the disallowance will result in a $2.8 million pre-tax charge in the first quarter of 2016. Consistent with our accounting policy for recognition of regulatory actions, we recognize the financial impacts in the period in which the order was received. With respect to allocation of 96.68% of environmental remediation costs to Oregon, we currently have a deferral order in Washington to defer environmental costs and insurance proceeds; however, recovery of those costs has not yet been determined. We have deferred costs for certain sites that only served Oregon customers and have, as a result of this order, determined it appropriate to reserve against 3.32% of these deferrals until resolution of recovery in Washington can be determined. The total reserve amount is approximately $0.5 million and will be recorded in the first quarter of 2016 in accordance with the Company’s policy. Consistent with our compliance filing filed in September 2015, the OPUC also ordered the same allocation factors should be applied to insurance proceeds, resulting in the application of 96.68% of the Company’s recovered insurance proceeds to Oregon. With respect to a third issue raised in the proceeding by a customer group that the Company should not be allowed to apply and recover portions of the SRRM amounts in 2013, 2014, and 2015 because that would constitute retroactive ratemaking, the OPUC ordered in the Company’s favor. The OPUC ordered our treatment of $13.8 million of expenses put into the SRRM amortization account, to be amortized over five years, was correct and complied with the original order. For more information regarding our SRRM, see Note 15. 84 NORTHWEST NATURAL GAS COMPANY QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Quarter ended In thousands, except share data March 31 June 30 September 30 December 31 2015 Operating revenues Net income (loss) Basic earnings (loss) per share(1) Diluted earnings (loss) per share(1) 2014 Operating revenues Net income (loss) Basic earnings (loss) per share(1) Diluted earnings (loss) per share(1) $ 261,665 $ 138,280 $ 93,128 $ 28,486 1.04 1.04 2,197 0.08 0.08 (6,685) (0.24) (0.24) $ 293,386 $ 133,169 $ 87,199 $ 37,884 1.40 1.40 1,071 0.04 0.04 (8,733) (0.32) (0.32) 230,718 29,705 1.08 1.08 240,283 28,470 1.05 1.04 (1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business. NORTHWEST NATURAL GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES COLUMN A COLUMN B COLUMN C Additions COLUMN D COLUMN E Deductions In thousands (year ended December 31) 2015 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts 2014 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts 2013 Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $ $ $ Balance at beginning of period Charged to costs and expenses Charged to other accounts Net write-offs Balance at end of period 969 $ 760 $ — $ 859 $ 870 1,656 $ 599 $ — $ 1,286 $ 969 2,518 $ 199 $ — $ 1,061 $ 1,656 85 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)). Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (SEC) rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. (b) Changes in Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f). There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 9(a). ITEM 9B. OTHER INFORMATION On February 24, 2016, the Organization and Executive Compensation Committee of the Company’s Board of Directors approved, and the Company entered into, an amendment to the Long Term Incentive Award Agreement dated February 25, 2015 between the Company and Gregg S. Kantor, Chief Executive Officer of the Company. The amendment changes the minimum age to qualify for a pro- rated payment on retirement under the agreement from 60 to 55. The Company has previously announced that Mr. Kantor intends to retire as an employee of the Company on December 31, 2016, which is four months before his 60th birthday. Accordingly, the effect of the amendment will be to make Mr. Kantor eligible for a pro rata payout of his 2015-2017 performance share award upon his planned retirement. Assuming retirement on December 31, 2016, the pro-rated target number of shares of Company common stock under this award will be 9,500 shares, and the award can payout between 0% and 200% of target based on Company performance. The same change was made in the agreement for Mr. Kantor’s 2016-2018 performance share award granted on February 24, 2016. Assuming retirement on December 31, 2016, the pro-rated target number of shares of Company common stock under this award will be 2,525 shares, and this award also can payout between 0% and 200% of target based on Company performance. 86 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The "Information Concerning Nominees and Continuing Directors", "Corporate Governance", and "Section 16(a) Beneficial Ownership Reporting Compliance" contained in our definitive Proxy Statement for the May 26, 2016 Annual Meeting of Shareholders is hereby incorporated by reference. Name Gregg S. Kantor Age at Dec. 31, 2015 58 David H. Anderson Gregory C. Hazelton Lea Anne Doolittle MardiLyn Saathoff David R. Williams Grant M. Yoshihara C. Alex Miller Ngoni Murandu Shawn M. Filippi Kimberly A. Heiting Thomas J. Imeson Margaret D. Kirkpatrick Brody J. Wilson David A. Weber 54 51 60 59 62 60 58 41 43 46 65 60 36 56 Positions held during last five years Chief Executive Officer (2009- ); President (2009-2015); President and Chief Operating Officer (2007-2008); Executive Vice President (2006-2007); Senior Vice President, Public and Regulatory Affairs (2003-2006). President and Chief Operating Officer (2016- ); Executive Vice President and Chief Operating Officer (2014-2015); Executive Vice President Operations and Regulation (2013-2014); Senior Vice President and Chief Financial Officer (2004-2013). Senior Vice President, Chief Financial Officer and Treasurer (2016- ); Senior Vice President and Chief Financial Officer (2015-2016); Vice President of Finance, Treasurer and Controller, Hawaiian Electric Industries, Inc. (2013-2015); Managing Director, UBS Investment Bank, Global Power and Utilities Group; Associate Director, UBS Investment Bank, Global Power and Utilities Group (2011-2013); Executive Director, UBS Investment Bank, Global Power and Utilities Group (2008-2011). Senior Vice President and Chief Administrative Officer (2013- ); Senior Vice President (2008-2013); Vice President, Human Resources (2000-2007). Senior Vice President, General Counsel and Regulation (2016- )Senior Vice President and General Counsel (2015-2016); Vice President Legal, Risk and Compliance (2013-2014); Deputy General Counsel (2010-2013); Chief Governance Officer and Corporate Secretary (2008-2014). Vice President, Utility Services (2007- ); Director of Utility Operations, Districts and Managed Labor Relations (2004-2006). Vice President, Utility Operations (2007- ); Managing Director, Utility Services (2005-2006); Director, Utility Services (2004-2005). Vice President Regulation and Treasurer (2013-2016); Vice President, Finance and Regulation (2009-2013); Assistant Treasurer (2008-2013); General Manager of Rates and Regulatory Affairs (2002-2009). Vice President and Chief Information Officer (2016- ); Chief Information Officer (2014-2016); Vice President and Chief Information Officer, NANA Development Corporation (2010-2014). Vice President, Chief Compliance Officer and Corporate Secretary (2016- ); Vice President and Corporate Secretary (2015-2016); Senior Legal Counsel (2011-2014); Assistant Corporate Secretary (2010-2014); Associate Legal Counsel (2005-2010). Vice President, Communications and Chief Marketing Officer (2015- ); Chief Marketing & Communications Officer (2013-2014); Chief Corporate Communications Officer (2011-2013); Communications Director (2005-2011). Vice President of Public Affairs (2014- ); Director of Public Affairs, Port of Portland (2006-2014). Senior Vice President, Environmental Policy and Affairs (2015); Senior Vice President and General Counsel (2013-2014); Vice President and General Counsel (2005-2013). Chief Accounting Officer, Controller and Assistant Treasurer (2016- ); Controller (2013-2015); Acting Controller (2013); Accounting Director (2012-2013); Senior Manager, PriceWaterhouseCoopers LLP (2009-2012); Manager, PriceWaterhouseCoopers LLP (2007-2009). President and Chief Executive Officer, NW Natural Gas Storage, LLC and Gill Ranch Storage, LLC (2012- ); Interim President and Chief Executive Officer, NW Natural Gas Storage LLC, and Gill Ranch Storage, LLC (2011-2012); Chief Operating Officer NW Natural Gas Storage, LLC and Gill Ranch Storage LLC (November 2010 - January 2011); Managing Director of Information Services and Chief Information Officer (2005 - 2011); Director of Information Services and Chief Information Officer (2001-2005). Each executive officer serves successive annual terms; present terms end on May 26, 2016. There are no family relationships among our executive officers, directors or any person chosen to become one of our officers or directors. NW Natural has adopted a Code of Ethics (Code) applicable to all employees and officers that is available on our website at www.nwnatural.com. We intend to disclose on our website at www.nwnatural.com any amendments to the Code or waivers of the Code for executive officers. 87 ITEM 11. EXECUTIVE COMPENSATION The information concerning "Executive Compensation", "Report of the Organization and Executive Compensation Committee", and "Compensation Committee Interlocks and Insider Participation" contained in our definitive Proxy Statement for the May 26, 2016 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of December 31, 2015 is reflected in Part III, Item 10, above. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The following table sets forth information regarding compensation plans under which equity securities of NW Natural are authorized for issuance as of December 31, 2015 (see Note 6 to the Consolidated Financial Statements): Plan Category Equity compensation plans approved by security holders: LTIP Performance Share Awards (Target Award)(1)(2) LTIP Restricted Stock Units (Target Award)(1)(2) LTIP Stock Options(3) Restated Stock Option Plan Employee Stock Purchase Plan Equity compensation plans not approved by security holders: Executive Deferred Compensation Plan (EDCP)(4) Directors Deferred Compensation Plan (DDCP)(4) Deferred Compensation Plan for Directors and Executives (DCP)(5) Total (a) (b) (c) Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) 117,775 88,587 — 352,688 $ 20,726 1,251 48,370 149,485 778,882 n/a n/a — 44.00 40.51 n/a n/a n/a 393,210 393,210 643,210 — 58,131 n/a n/a n/a 701,341 (1) Shares issued pursuant to Performance Share Awards and Restricted Stock Units under the LTIP do not include an exercise price, but are payable when the award criteria are satisfied. If the maximum awards were paid pursuant to the Performance Share Awards outstanding at December 31, 2015, the number of shares shown in column (a) would increase by 117,775 shares and the number of shares shown in column (c) would decrease by the same amount of shares. The aggregate 393,210 shares are available for future issuance under the LTIP as Restricted Stock Units, Performance Share Awards, or stock options. An additional 250,000 shares are available for LTIP Stock Option Issuance at December 31, 2015, but those additional shares are not available for issuance of LTIP Restricted Stock Units or Performance Share Awards. (2) (3) Shares balance includes 393,210 shares available for future issuance under the LTIP as Restricted Stock Units, Performance Share Awards, or stock options; and an additional 250,000 shares available for LTIP Stock Option Issuance only at December 31, 2015, and are not available for issuance of LTIP Restricted Stock Units or Performance Share Awards. (4) Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.” If deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock based on the purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase Plan, and such accounts were credited with additional shares based on the deemed reinvestment of dividends. Cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points, subject to a 6% minimum rate. At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a combination of lump sum and installments. Amounts credited to stock accounts are payable solely in shares of common stock and cash for fractional shares, and amounts in the above table represent the aggregate number of shares credited to participant's stock accounts. We have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of shares of common stock equal to the number of shares credited to all participants’ stock accounts. (5) Effective January 1, 2005, the EDCP and DDCP were closed to new participants and replaced with the DCP. The DCP continues the basic provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or a “stock account.” Stock accounts represent a right to receive shares of NW Natural common stock on a deferred basis, and such accounts are credited with additional shares based on the deemed reinvestment of dividends. Effective January 1, 2007, cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield. Our obligation to pay deferred compensation in accordance with the terms of the DCP will generally become due on retirement, death, or other termination of service, and will be paid in a lump sum or in installments of five, 10, or 15 years as elected by the participant in accordance with the terms of the DCP. Amounts credited to stock accounts are payable solely in shares of common stock and cash for fractional shares, and amounts in the above table represent the aggregate number of shares credited to participant's stock accounts. We have contributed common stock to the trustee of the Supplemental Trust such that this trust holds approximately the number of common shares equal to the number of shares credited to all participants' stock accounts. The right of each participant in the DCP is that of a general, unsecured creditor of the Company. 88 The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” and "Security Ownership of Common Stock of Certain Beneficial Owners" contained in our definitive Proxy Statement for the May 26, 2016 Annual Meeting of Shareholders is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information captioned "Transactions with Related Persons" and "Corporate Governance" in the Company’s definitive Proxy Statement for the May 26, 2016 Annual Meeting of Shareholders is hereby incorporated by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information captioned "2015 and 2014 Audit Firm Fees" in the Company’s definitive Proxy Statement for the May 26, 2016 Annual Meeting of Shareholders is hereby incorporated by reference. 89 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) The following documents are filed as part of this report: PART IV 1. A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8. 2. List of Exhibits filed: Reference is made to the Exhibit Index commencing on page 92. 90 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NORTHWEST NATURAL GAS COMPANY By: /s/ Gregg S. Kantor Gregg S. Kantor Chief Executive Officer Date: February 26, 2016 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. Signature Title Date /s/ Gregg S. Kantor Gregg S. Kantor Chief Executive Officer /s/ Gregory C. Hazelton Gregory C. Hazelton Senior Vice President, Chief Financial Officer and Treasurer /s/ Brody J. Wilson Brody J. Wilson Chief Accounting Officer, Controller and Assistant Treasurer Principal Executive Officer and Director February 26, 2016 Principal Financial Officer February 26, 2016 Principal Accounting Officer February 26, 2016 /s/ Timothy P. Boyle Timothy P. Boyle /s/ Martha L. Byorum Martha L. Byorum /s/ John D. Carter John D. Carter /s/ Mark S. Dodson Mark S. Dodson /s/ C. Scott Gibson C. Scott Gibson /s/ Tod R. Hamachek Tod R. Hamachek /s/ Jane L. Peverett Jane L. Peverett /s/ Kenneth Thrasher Kenneth Thrasher /s/ Malia H. Wasson Malia H. Wasson Director Director Director Director Director Director Director Director Director 91 ) ) ) ) ) ) ) ) ) ) ) February 26, 2016 ) ) ) ) ) ) ) ) ) ) ) ) ) NORTHWEST NATURAL GAS COMPANY Exhibit Index to Annual Report on Form 10-K For the Fiscal Year Ended December 31, 2015 Exhibit Number Document *3a. *3b. *4a. *4b. *4c. *4d. *4e. *4f. *4g. *4h. *4i. *4j. Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended June 3, 2008 (incorporated herein by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2008, File No. 1-15973). Bylaws as amended May 22, 2014 (incorporated herein by reference to Exhibit 3.1 to Form 8-K dated May 22, 2014, File No. 1-15973). Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as of June 1, 1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966, December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1, 1985 (incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit 4(c) in File No. 33-24168); Supplemental Indentures Nos. 16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988, October 1, 1989 and July 1, 1990 (incorporated herein by reference to Exhibit 4(c) in File No. 33-40482); Supplemental Indenture No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by reference to Exhibit 4(c) in File No. 33-64014); and Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File No. 33-53795). Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating to the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No. 33-64014). Officers’ Certificate dated June 12, 1991 creating Series A of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994). Officers’ Certificate dated June 18, 1993 creating Series B of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994). Officers’ Certificate dated January 17, 2003 relating to Series B of the Company’s Unsecured Medium-Term Notes and supplementing the Officers’ Certificate dated June 18, 1993 (incorporated herein by reference to Exhibit 4f.(1) to Form 10-K for 2002, File No. 1-15973). Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 4, 2004, File No. 1-15973). Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated October 4, 2004, File No. 1-15973). Twenty-First Supplemental Indenture, providing, among other things, for First Mortgage Bonds, 4.00% Series Due 2042, dated as of October 15, 2012, by and between Northwest Natural Gas Company, Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), and Stanley Burg (Successor to R.G. Page and J.C. Kennedy) (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 26, 2012, File No.1-15973). Form of Credit Agreement among Northwest Natural Gas Company and the parties thereto, with JPMorgan Chase Bank, N.A. as administrative agent and U.S. Bank, N.A. and Wells Fargo Bank, N.A. as co-syndication agents, dated as of December 20, 2012 (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated December 20, 2012, File No.1-15973). Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the maturity date of the Credit Agreement between Northwest Natural Gas Company and each financial institution, effective as of December 20, 2013 (incorporated herein by reference to Exhibit 4k to Form 10-K for 2013, File No. 1-15973). 92 *4k. *4l. *10a Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the maturity date of the Credit Agreement between Northwest Natural Gas Company and each financial institution, effective as of December 20, 2014 (incorporated herein by reference to Exhibit 4m to Form 10-K for 2014, File No. 1-15973). First Amendment to Credit Agreement, between the Company JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, dated as of December 20, 2014 (incorporated herein by reference to Exhibit 4n to Form 10-K for 2014, File No. 1-15973). Carry and Earning Agreement by and between Encana Oil & Gas (USA) Inc. and Northwest Natural Gas Company, dated effective as of May 1, 2011, and First Amendment to Carry and Earning Agreement dated March 11, 2011 (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2011, File No. 1-15973). † *10b Second Amendment to Carry and Earning Agreement by and between Encana Oil and Gas (USA) Inc. and NWN Gas Reserves, LLC., dated as of March 7, 2014 (incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended March 31, 2014, File No. 1-15973). 12 21 23 Statement re computation of ratios of earnings to fixed charges. Subsidiaries of Northwest Natural Gas Company. Consent of PricewaterhouseCoopers LLP. 31.1 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002. Executive Compensation Plans and Arrangements: *10c. Executive Supplemental Retirement Income Plan 2010 Restatement (incorporated herein by reference to Exhibit 10b. to Form 10-K for 2009, File No. 1-15973). *10d. Supplemental Executive Retirement Plan, 2011 Restatement (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973). *10e. Northwest Natural Gas Company Supplemental Trust, effective January 1, 2005, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.7 to Form 8-K dated December 16, 2005, File No. 1-15973). *10f. Northwest Natural Gas Company Umbrella Trust for Directors, effective January 1, 1991, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated December 16, 2005, File No. 1-15973). *10g. Northwest Natural Gas Company Umbrella Trust for Executives, effective January 1, 1988, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.6 to Form 8-K dated December 16, 2005, File No. 1-15973). *10h. Restated Stock Option Plan, as amended effective December 14, 2006 (incorporated herein by reference to Exhibit 10c. to Form 10-K for 2006, File No. 1-15973). 93 *10i. Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10h. to Form 10-K for 2009, File No. 1-15973). *10j. Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of February 26, 2009 (incorporated herein by reference to Exhibit 10e. to Form 10-K for 2008, File No. 1-15973). *10k. Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2009 (incorporated herein by reference to Exhibit 10f. to Form 10-K for 2008, File No. 1-15973). *10l. Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated as of September 24, 2015 (incorporated herein by reference to Exhibit 10a to Form 10-Q for the quarter ended September 30, 2015). *10m. Form of Indemnity Agreement as entered into between the Company and each director and certain executive officers (incorporated herein by reference to Exhibit 10l. to Form 10-K for 2009, File No. 1-15973). *10n. Form of Indemnity Agreement as entered into between the Company and certain executive officers (incorporated herein by reference to Exhibit 10l.(1) to Form 10-K for 2009, File No. 1-15973). *10o. Non-Employee Directors Stock Compensation Plan, as amended effective December 15, 2005 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated December 16, 2005, File No. 1-15973). 10p. Executive Annual Incentive Plan, effective February 23, 2012, as amended effective January 1, 2016. *10q. Form of Change in Control Severance Agreement between the Company and each executive officer (incorporated herein by reference to Exhibit 10o. to Form 10-K for 2008, File No. 1-15973). *10r. Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective May 24, 2012 (incorporated herein by reference to Exhibit 10r to Form 10-K for 2012, File No. 1-15973). *10s. Severance Agreement between Northwest Natural Gas Company and an executive officer, dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated June 24, 2015). *10t. Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2013-2015) (incorporated herein by reference to Exhibit 10v. to Form 10K for 2012, File No. 1-15973). *10u. Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2014-2016) (incorporated herein by reference to Exhibit 10v. to Form 10-K for 2013, File No. 1-15973). *10v. Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2015-2017) (incorporated by reference to Exhibit 10w to Form 10-K for 2014, File No. 1-15973). 10w. Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan (2016-2018). 10x. 10y. *10z. Form of Long-Term Incentive Award Agreement under the Long Term Incentive Plan between the Company and an Executive Officer (2016-2018). Agreement to Amend the Long-Term Incentive Award Agreement, under the Long-Term Incentive Plan dated February 25, 2016 by and between the Company and an executive officer. Form of Consent dated December 14, 2006 entered into by each executive officer with respect to amendments to the Executive Supplemental Retirement Income Plan, the Supplemental Executive Retirement Plan and certain change in control severance agreements (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 19, 2006, File No. 1-15973). 94 *10aa. Consent to Amendment of Deferred Compensation Plan for Directors and Executives, dated February 28, 2008 entered into by each executive officer (incorporated herein by reference to Exhibit 10bb to Form 10-K for 2007, File No. 1-15973). 10bb. Form of Restricted Stock Unit Award Agreement under Long-Term Incentive Plan (2016). *10cc. Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2013) (incorporated herein by reference to Exhibit 10aa. to Form 10-K for 2012, File No. 1-15978). *10dd. Form of Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan (2012) (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 20, 2011, File No. 1-15973). *10ee. Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan between the Company and an executive officer (incorporated herein by reference to Exhibit 10cc. to Form 10-Q for the period ending September 30, 2013, File No. 1-15973). *10ff. Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan between the Company and an executive officer. (incorporated herein by reference to Form 10-Q for the quarter ended March 31, 2014, File No. 1-15973). *10gg. Form of Special Retention Restricted Stock Unit Award Agreement between the Company and an executive officer, dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated June 24, 2015). *10hh. Hire-On Bonus Agreement between the Company and an executive officer, dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.3 to Form 8-K dated June 24, 2015). 10ii. Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2016. 10jj. Long-Term Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2016. 101. The following materials from Northwest Natural Gas Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, formatted in Extensible Business Reporting Language (XBRL): (i) Consolidated Statements of Income; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; and (iv) Related notes. *Incorporated herein by reference as indicated † Certain portions of the exhibit have been omitted based upon a request for confidential treatment filed by us with the Securities and Exchange Commission. The omitted portions of the exhibit have been separately filed by us with the Securities and Exchange Commission. 95 NORTHWEST NATURAL GAS COMPANY Ratios of Earnings to Fixed Charges (Unaudited) EXHIBIT 12 In thousands, except share data Fixed Charges, as defined: Interest on Long-Term Debt Other Interest Amortization of Debt Discount and Expense Interest Portion of Rentals Total Fixed Charges, as defined Earnings, as defined: Net Income Taxes on Income Fixed Charges, as above Total Earnings, as defined Ratios of Earnings to Fixed Charges Year Ended December 31, 2015 2014 2013 2012 2011 $ $ 37,918 3,173 1,760 1,976 44,827 $ 40,066 2,718 1,963 2,302 47,049 $ 40,825 2,709 1,877 1,910 47,321 $ 39,175 2,314 1,848 1,864 45,201 37,515 2,976 1,729 2,213 44,433 53,703 35,753 44,827 $ 134,283 3.00 58,692 41,643 47,049 $ 147,384 3.13 60,538 41,705 47,321 $ 149,564 3.16 58,779 43,403 45,201 $ 147,383 3.26 63,044 42,825 44,433 $ 150,302 3.38 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM EXHIBIT 23 We hereby consent to the incorporation by reference in the Registration Statement on Form 333-120955, 333-134973, 333-139819, 333-180350 and 333-187005) and in the Registration Statement on Form S-3 (No. 333-192641) of Northwest Natural Gas Company of our report dated February 26, 2016 relating to the consolidated financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form (Nos. 333-70218, 333-100885, /s/ PricewaterhouseCoopers LLP Portland, Oregon February 26, 2016 CERTIFICATION I, Gregg S. Kantor, certify that: EXHIBIT 31.1 1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: February 26, 2016 /s/ Gregg S. Kantor Gregg S. Kantor Chief Executive Officer CERTIFICATION I, Gregory C. Hazelton, certify that: EXHIBIT 31.2 1. I have reviewed this annual report on Form 10-K for Northwest Natural Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: February 26, 2016 /s/ Gregory C. Hazelton Gregory C. Hazelton Senior Vice President, Chief Financial Officer, and Treasurer NORTHWEST NATURAL GAS COMPANY Certificate Pursuant to Section 906 of Sarbanes – Oxley Act of 2002 EXHIBIT 32.1 Each of the undersigned, GREGG S. KANTOR, Chief Executive Officer, and GREGORY C. HAZELTON, the Senior Vice President, Chief Financial Officer, and Treasurer of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that: 1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (the Report) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 26th day of February 2016. /s/ Gregg S. Kantor Gregg S. Kantor Chief Executive Officer /s/ Gregory C. Hazelton Gregory C. Hazelton Senior Vice President, Chief Financial Officer, and Treasurer A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. INVESTOR AND SHAREHOLDER INFORMATION CORPORATE INFORMATION Nikki Sparley Director, Investor Relations Toll free (800) 422-4012, Ext. 2530 Direct (503) 721-2530 nikki.sparley@nwnatural.com Chu Lee Manager, Shareholder Services Toll free (800) 422-4012, Ext. 2402 Direct (503) 220-2402 chu.lee@nwnatural.com Stock transfer agent and registrar For common stock: American Stock Transfer & Trust Company 6201 15th Avenue Brooklyn, NY 11219 (888) 777-0321 web: amstock.com email: info@amstock.com Trustee and bond paying agent For bond issues: Deutsche Bank Trust Company Americas 60 Wall Street New York, NY 10005 (800) 735-7777 COMMUNITY & SUSTAINABILITY REPORT Learn more about NW Natural’s community involvement and philanthropic contributions, environmental stewardship, employee safety efforts and other company initiatives. View the Community & Sustainability Annual Report at nwnatural.com/aboutnwnatural/community. LOW-INCOME PROGRAMS NW Natural helps low-income customers manage their bills through a variety of programs. Shareholders and customers support the Gas Assistance Program (GAP), which supplements the federal and state assistance programs. In addition, the Oregon Low-Income Gas Assistance Program (OLGA) uses public purpose fees to help low-income customers pay their utility bills. The Oregon Low-Income Energy Efficiency Program (OLIEE), also paid for by public purpose charges, helps customers in need acquire high-efficiency equipment and weatherization. View the Low-Income Programs at nwnatural.com/residential. ENERGY-EFFICIENCY PROGRAMS NW Natural partners with Energy Trust of Oregon to offer our Oregon and Washington customers energy-efficiency programs and services. Learn more about the results of these programs and the benefits to our customers. View the Energy Trust of Oregon Annual Report at nwnatural.com/residential. 220 nw second avenue portland, oregon 97209 nwnatural.com nyse: nwn N W N A T U R A L 2 0 1 5 A N N U A L R E P O R T • B U I L D I N G W I T H F O R E S I G H T 

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